Unassociated Document

10-Q 1 v174653_10q.htm 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 December 31, 2009

¨ 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.)

27 Corporate Woods, Suite 350
10975 Grandview Drive
Overland Park, Kansas		66210
(Address of principal executive offices)		(Zip Code)

(913) 754-7754

(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 o

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 o No þ

The number of shares of Common Stock, $0.001 par value, outstanding on February 12, 2010 was 4,653,668 shares.

ENERJEX RESOURCES, INC.

FORM 10-Q

TABLE OF CONTENTS

		Page
PART I	FINANCIAL STATEMENTS
Item 1.	Financial Statements	1
	Condensed Consolidated Balance Sheets	1
	Condensed Consolidated Statements of Operations	2
	Condensed Consolidated Statements of Cash Flows	3
	Notes to Condensed Consolidated Financial Statements	4
	Forward-Looking Statements	11
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	12
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	24
Item 4T.	Controls and Procedures	25

PART II	OTHER INFORMATION
Item 1.	Legal Proceedings	25
Item 1A.	Risk Factors	25
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	27
Item 3.	Defaults Upon Senior Securities	28
Item 4.	Submission of Matters to a Vote of Security Holders	29
Item 5.	Other Information	29
Item 6.	Exhibits	30

SIGNATURES		32

PART 1 – FINANCIAL INFORMATION

Item 1. Financial Statements

EnerJex Resources, Inc. and Subsidiaries

Condensed Consolidated Balance Sheets

	December 31, 2009			March 31, 2009
	(Unaudited)			(Audited)
Assets
Current assets:
Cash	$	412,370		$	127,585
Accounts receivable		363,247			462,044
Prepaid debt issue costs		11,325			45,929
Deferred and prepaid expenses		190,619			263,383
Total current assets		977,561			898,941

Fixed assets		382,747			365,019
Less: Accumulated depreciation		106,795			63,988
Total fixed assets		275,952			301,031

Other assets:
Oil and gas properties using full cost accounting:
Properties not subject to amortization		6,351			31,183
Properties subject to amortization		6,077,103			6,449,023
Total other assets		6,083,454			6,480,206
Total assets	$	7,336,967		$	7,680,178

Liabilities and Stockholders' Equity (Deficit)
Current liabilities:
Accounts payable	$	865,874		$	1,016,168
Accrued liabilities		28,892			87,811
Deferred payments - development		337,451			-
Long-term debt, current		353,634			1,723,036
Convertible note payable		25,000			-
Derivative liability		647,480			-
Total current liabilities		2,258,331			2,827,015

Asset retirement obligation		864,659			803,624
Convertible note payable		-			25,000
Long-term debt, net of discount of $163,244 and $596,108		8,697,368			7,818,163
Derivative liability		1,838,226			-
Total liabilities		13,658,584			11,473,802
Commitments and contingencies
Stockholders' Equity (Deficit):
Preferred stock, $0.001 par value, 10,000,000
shares authorized, no shares issued and outstanding		-			-
Common stock, $0.001 par value, 100,000,000 shares authorized
shares issued and outstanding – 4,910,660 at December 31, 2009 and 4,443,512 at March 31, 2009		4,911			4,444
Common stock owed but not issued		186			-
Paid-in capital		9,543,360			8,932,906
Retained (deficit)		(15,870,074	)		(12,730,974	)
Total stockholders’ equity (deficit)		(6,321,617	)		(3,793,624	)

Total liabilities and stockholders’ equity	$	7,336,967		$	7,680,178

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
	December 31,						December 31,
	2009			2008			2009			2008

Revenue
Oil and gas activities	$	914,545		$	1,184,547		$	3,703,724		$	4,652,289

Expenses:
Direct operating costs		448,684			562,693			1,313,518			2,093,994
Depreciation, depletion and amortization		131,394			277,020			577,288			995,069
Impairment of oil and gas properties		-			4,777,723			-			4,777,723
Professional fees		60,571			106,032			479,710			400,816
Salaries		153,022			200,547			706,011			694,973
Administrative expense		334,512			238,726			789,827			1,065,308
Total expenses		1,128,183			6,162,741			3,866,354			10,027,883

Income (loss) from operations		(213,638	)		(4,978,194	)		(162,630	)		(5,375,594	)

Other income (expense):
Interest expense		(189,374	)		(205,327	)		(542,939	)		(743,372	)
Loan interest accretion		(153,374	)		(119,512	)		(432,864	)		(2,686,892	)
Gain on liquidation of hedging instrument		-			3,879,050			-			3,879,050
Unrealized gain (loss) on derivative instruments		(2,485,706	)		-			(2,485,706	)		-
Gain on repurchase of debentures		-			-			406,500			-
Management fee revenue		23,944			-			99,234			-
Loss on disposal of vehicles		(20,695	)		-			(20,695	)		(4,421	)

Total other income (expense)		(2,825,205	)		3,554,211			(2,976,470	)		444,365

Net income (loss)	$	(3,038,843	)	$	(1,423,983	)	$	(3,139,100	)	$	(4,931,229	)

Weighted average shares outstanding
Common shares outstanding basic and diluted		4,827,137			4,443,483			4,647,879			4,442,467

Net income (loss) per share - basic	$	(0.63	)	$	(0.32	)	$	(0.68	)	$	(1.11	)

See Notes to Condensed Consolidated Financial Statements.

EnerJex Resources, Inc. and Subsidiaries

Condensed Consolidated Statements of Cash Flows

(Unaudited)

	For the Nine Months Ended
	December 31,
	2009			2008
Cash flows (used in) / provided from operating activities
Net income (loss)	$	(3,139,100	)	$	(4,931,229	)
Impairment of oil and gas properties		-			4,777,723
Depreciation and depletion		599,908			1,034,013
Accretion of asset retirement obligation		56,754			46,928
Principal increase on debentures		294,250			-
Shares issued for interest on debentures		7,355			-
Share-based payments issued for compensation and services		603,750			79,455
Loan costs and accretion of interest		432,864			2,832,758
Unrealized (gain) loss on derivative instruments		2,485,706			-
Adjustments to reconcile net income (loss) to cash
used in operating activities:
Accounts receivable		98,797			(144,860	)
Prepaid expenses		107,368			(926,058	)
Accounts payable		(150,294	)		623,761
Accrued liabilities		(58,919	)		(9,821	)
Deferred payment - development		337,451			(251,951	)
Net cash (used in) / provided from operating activities		1,675,890			3,130,719

Cash flows (used in) / provided from investing activities
Purchase of fixed assets		(14,738	)		(171,200	)
Loss on disposal of vehicles		(20,695	)		-
Additions to oil and gas properties		(138,360	)		(2,346,041	)
Net cash (used in) / provided from investing activities		(173,793	)		(2,517,241	)

Cash flows (used in) / provided from financing activities
Notes payable, net		-			(965,000	)
Borrowings on long-term debt		38,480			11,274,842
Notes payable, net		(1,255,792	)		(11,685,978	)
Net cash (used in) / provided from financing activities		(1,217,312	)		(1,376,136	)

Net increase (decrease) in cash		284,785			(762,658	)
Cash - beginning		127,585			951,004
Cash - ending	$	412,370		$	188,346

Supplemental disclosures:
Interest paid	$	209,681		$	688,602
Income taxes paid		-			-

Non-cash transactions
Shares issued for interest on debentures	$	7,355		$	-
Share-based payments issued for compensation and services		603,750			79,455
Asset retirement obligation		4,281			776,906
Unrealized (gain) loss on derivative instruments		2,485,706			-
Impairment of oil and gas properties	$	-		$	4,777,723

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 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 Form 10-K for the fiscal year ended March 31, 2009.

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

Note 2 – Going Concern

The accompanying condensed consolidated financial statements have been prepared assuming that we will continue as a going concern. Our ability to continue as a going concern is dependent upon attaining profitable operations based on the development of resources that can be sold. We intend to use borrowings, equity and asset sales, and other strategic initiatives to mitigate the effects of our cash position, however, no assurance can be given that debt or equity financing, if and when required, will be available. The financial statements do not include any adjustments relating to the recoverability and classification of recorded assets and classification of liabilities that might be necessary should we be unable to continue in existence.

Note 3 - Stock Options and Warrants

A summary of stock options and warrants is as follows:

	Options			Weighted Ave. Exercise Price			Warrants		Weighted Ave. Exercise Price
Outstanding March 31, 2009		438,500		$	6.30			75,000	$	3.00
Cancelled		(438,500	)	$	(6.30	)		-		-
Exercised		-			-			-		-
Outstanding December 31, 2009		-			-			75,000	$	3.00

On August 3, 2009, upon advice and recommendation by the governing, compensation and nominating committee (“GCNC”) of the Board of Directors, we exchanged all of the 438,500 outstanding stock options for 109,700 shares of twelve-month restricted common stock valued at $109,700 based upon the fair market value of the stock on the date of exchange.

Note 4 – Fair Value Measurements

The Company holds 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. The Company’s Level 1 assets include cash.

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. The Company’s Level 2 assets and liabilities consist of accounts receivable, notes and convertible notes payable, and derivative liability. Due to the short term nature of its accounts receivable, notes and convertible notes payable, the Company estimates the fair value of these assets and liabilities at their current basis. The Company determines the fair value of its 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. The Company has no level 3 assets or liabilities.

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

				Fair Value Measurement
	Total Amount			Level 1		Level 2			Level 3
Crude oil swaps	$	(2,485,706	)	$	-	$	(2,485,706	)	$	-

Note 5 - Asset Retirement Obligations

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

The following shows the changes in asset retirement obligations:

Asset retirement obligation, April 1, 2009	$	803,624
Liabilities incurred during the period		4,281
Liabilities settled during the period		-
Accretion		56,754
Asset retirement obligations, December 31, 2009	$	864,659

Note 6 – 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. See Note 7. None of our derivative instruments are designated as cash flow hedges. 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. (“TCB”), which allows TCB 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.

The following derivative contracts were in place at December 31, 2009:

	Term	Contract Volumes	Price per Bbl		Fair Value
Crude oil swap	Oct. 2009 – Dec. 2013	120,000 Bbls	$	57.30	$	(2,497,608	)
Crude oil swap	Oct. 2009 – Mar. 2011	20,250 Bbls	$	77.05	$	11,902
					$	(2,485,706	)

The total fair value is shown as a derivative instrument in both the current and non-current liabilities on the balance sheet. We recorded an unrealized loss of $2,485,706 in the quarter ended December 31, 2009. We realized a loss of $165,116 in the quarter ended December 31, 2009, the effect of which is recorded in operating revenue in the Condensed Consolidated Statement of Operations.

Note 7 - Long-Term Debt and Convertible Debt

Senior Secured Credit Facility

On July 3, 2008, EnerJex, EnerJex Kansas, and DD Energy entered into a three-year $50 million Senior Secured Credit Facility (the “Credit Facility”) with Texas Capital Bank, N.A (“TCB”). Borrowings under the Credit Facility will be subject to a borrowing base limitation based on our current proved oil and gas reserves and will be subject to semi-annual redeterminations. A borrowing base redetermination was completed by Texas Capital Bank effective January 1, 2010. The borrowing base was determined to be $6,746,000 and called for $55,000 Monthly Borrowing Base Reductions (“MBBR”) beginning February 1, 2010.

The Credit Facility is secured by a lien on substantially all assets of the Company and its subsidiaries. The Credit Facility has a term of three years, and all principal amounts, together with all accrued and unpaid interest, will be due and payable in full on July 3, 2011. The Credit Facility also provides for the issuance of letters-of-credit up to a $750,000 sub-limit under the borrowing base and up to an additional $2.25 million limit not subject to the borrowing base to support our hedging program. We have borrowed all of our available borrowing base as of December 31, 2009.

Advances under the Credit Facility will be in the form of either base rate loans or Eurodollar loans. The interest rate on the base rate loans fluctuates based upon the higher of (1) the lender’s “prime rate” and (2) the Federal Funds rate plus 0.50%, plus, in either case, a margin of between 0.0% and 0.5% depending on the percent of the borrowing base utilized at the time of the credit extension, but in no event shall be less than five percent (5.0%). The interest rate on the Eurodollar loans fluctuates based upon the applicable LIBOR rate, plus a margin of 2.25% to 2.75% depending on the percent of the borrowing base utilized at the time of the credit extension, but in no event shall be less than five percent (5.0%). Eurodollar loans may be based upon one, two, three and six month LIBOR options, except that beginning March 30, 2009 and continuing through the date of this report, TCB has suspended all LIBOR based funding with maturities less than 90 days due to the extreme volatility in the interest rate market and the unprecedented spread between the 90 day LIBOR and the shorter term LIBOR options. A commitment fee of 0.375% on the unused portion of the borrowing base will accrue, and be payable quarterly in arrears. There was no commitment fee due at December 31, 2009.

The Credit Facility was amended August 18, 2009 to implement a minimum interest rate of five (5.0%) and establish minimum volumes to be hedged of not less than seventy-five percent (75%) of the proved developed producing reserves attributable to our interest in the borrowing base oil and gas properties projected to be produced. The Credit Facility was further amended January 13, 2010 to modify the senior funded debt to EBITDA ratio on a quarterly basis beginning with the quarter ended December 31, 2009 and to modify the annualization of the interest coverage ratio, also beginning with the quarter ended December 31, 2009. See Note 9. The senior funded debt to EBITDA ratio allowed is 6.25:1.00 at December 31, 2009; 5.75:1.00 at March 31, 2010; 5.25:1.00 at June 30, 2010; and 4.75:1.00 at September 30, 2010; and 4.25:1.00 for all quarters ending after September 30, 2010. We were not in compliance with the working capital ratio covenant at December 31, 2009; however, we were able to obtain a waiver of default from TCB. A copy of this waiver is attached hereto as Exhibit 10.18.

Additionally, TCB and the holders of the debentures entered into a Subordination Agreement whereby the debentures issued on June 21, 2007 are subordinated to the Credit Facility.

Debentures

On April 11, 2007, we entered into a Securities Purchase Agreement, Registration Rights Agreements, Senior Secured Debentures, a Pledge and Security Agreement, a Secured Guaranty, and other related agreements (the “Financing Agreements”) with the “Buyers” of a new series of senior secured debentures (the “Debentures”). Under the terms of the Financing Agreements, we agreed to sell Debentures for a total purchase price of $9.0 million. In connection with the purchase, we agreed to issue to the Buyers a total of 1,800,000 shares. The first closing occurred on April 12, 2007 with a total of $6.3 million in Debentures being sold and the remaining $2.7 million closing on June 21, 2007. Effective July 7, 2008, we redeemed an aggregate principal amount of $6.3 million of the Debentures. We also amended the remaining $2.7 million of aggregate principal Debentures to, among other things, permit the indebtedness under our Credit Facility, subordinate the security interests of the debentures to the Credit Facility, provide for the redemption of the remaining Debentures with the net proceeds from any next debt or equity offering and eliminate the covenant to maintain certain production thresholds.

The proceeds from the Debentures were allocated to the long-term debt and the stock issued based on the fair market value of each item that we calculated to be $9.0 million. Since each of the instruments had a value equal to 50% of the total, we allocated $4.5 million to stock and $4.5 million to the note. The loan discount costs of $4.5 million will accrete as interest based on the interest method over the period of issue to maturity or redemption. The amount of interest accreted for the nine month period ended December 31, 2009 was $432,864. The remaining amount of interest to accrete in future periods is $163,244 as of December 31, 2009.

We incurred debt issue costs totaling $466,835. The debt issue costs are initially recorded as assets and are amortized to expense on a straight-line basis over the life of the loan. The amount expensed in the nine month period ended December 31, 2009 was $34,604. The remaining debt issue costs totaling $11,325 will be expensed in the fiscal year ended March 31, 2010.

The Debentures originally had a three-year term, maturing on March 31, 2010, and an interest rate equal to 10% per annum. We further amended the Debentures in June 2009 to extend the maturity date to September 30, 2010, to allow us to pay interest in either cash or payment-in-kind interest (an increase in the amount of principal due) or payment-in-kind shares (issuance of shares of common stock), and add a provision for the conversion of the debentures into shares of our common stock. The conversion price on or before May 31, 2010 is equal to $3.00 per share. From June 1, 2010 through the maturity date, assuming the Debentures have not been redeemed, the conversion price per share shall be computed as 100.0% of the arithmetic average of the weighted average price of the common stock on each of the thirty (30) consecutive Trading Days immediately preceding the conversion date.

Interest is payable quarterly in arrears on the first day of each succeeding quarter. The interest rate remains 10% per annum for cash interest payments. The payment-in-kind interest rate is equal to 12.5% per annum. If interest payments are made through payment-in-kind interest, we must issue common stock equal to an additional 2.5% of the quarterly interest payment due. As of December 31, 2009, we have recorded additional principal on the Debentures of $294,250 and common stock of $7,355.

We again amended the Debentures on November 16, 2009 to provide for the tender and cancellation of shares by the Buyers upon retirement of a portion of the Debentures in accordance with an agreed upon schedule. We redeemed $150,000 of the Debentures for $150,000 in cash in accordance with this amendment during the quarter ended December 31, 2009. As a result, 75,000 shares have been or will be tendered and cancelled.

We have no prepayment penalty so long as we maintain an effective registration statement with the Securities Exchange Commission and provided we give six (6) business days prior notice of redemption to the Buyers. During the nine months ended December 31, 2009, we also repurchased $450,000 of the Debentures at a gain of $406,500.

Subsequent to the quarter ended December 31, 2009, we further amended the Debentures to extend the scheduled due dates for the January and February 2010 redemption payments to March 10, 2010.

Convertible and Other Long-Term Debt

We financed the purchase of vehicles through a bank. The notes are for six years and the weighted average interest is 7.1% per annum. Vehicles collateralize these notes.

Long-term debt consists of the following at December 31, 2009:

Credit Facility	$	6,746,000

Debentures		2,394,250
Unaccreted discount		(163,244	)
Debentures, net of unaccreted discount		2,231,006

Convertible note payable		25,000
Vehicle notes payable		73,996
Total long-term debt		9,076,002
Less current portion, long-term debt		353,634
Less current portion, convertible note payable		25,000
Long-term debt	$	8,697,368

On August 3, 2006, we sold a $25,000 convertible note that has an interest rate of 6% and matures August 2, 2010. The note is convertible at any time at the option of the note holder into shares of our common stock at a conversion rate of $10.00 per share.

Note 8 - Oil & Gas Properties

On April 9, 2007, we entered into a “Joint Exploration Agreement” with a shareholder, MorMeg, LLC, whereby we agreed to advance $4.0 million to a joint operating account for further development of MorMeg’s Black Oaks leaseholds in exchange for a 95% working interest in the Black Oaks Project. We will maintain our 95% working interest until payout, at which time the MorMeg 5% carried working interest will be converted to a 30% working interest and our working interest becomes 70%. Payout is generally the point in time when the total cumulative revenue from the project equals all of the project’s development expenditures and costs associated with funding. Pursuant to amendments to the Joint Exploration Agreement, we have until March 31, 2010 to contribute additional capital toward the Black Oaks Project development. If we elect not to contribute further capital to the Black Oaks Project prior to the project’s full development while it is economically viable to do so, or if there is more than a thirty day delay in project activities due to lack of capital, MorMeg has the option to cease further joint development and we will receive an undivided interest in the Black Oaks Project. The undivided interest will be the proportionate amount equal to the amount that our investment bears to our investment plus $2.0 million, with MorMeg receiving an undivided interest in what remains.

Subsequent to the quarter ended December 31, 2009, we have listed assets for sale encompassing five leases in Johnson County, Kansas. Proceeds from the sale of these assets would, primarily, be used to meet scheduled Debenture redemptions. See Note 7. These five leases approximate $1.3 million of the value of our borrowing base. We would be required to pay this approximate $1.3 million to Texas Capital Bank upon the sale of these assets.

Note 9 - Subsequent Events

Effective January 13, 2010 the Credit Facility was amended to modify the senior funded debt to EBITDA ratio on a quarterly basis beginning with the quarter ending December 31, 2009 and to modify the annualization of the interest coverage ratio, also beginning with the quarter ending December 31, 2009. The senior funded debt to EBITDA ratio allowed is 6.25:1.00 at December 31, 2009; 5.75:1.00 at March 31, 2010; 5.25:1.00 at June 30, 2010; and 4.75:1.00 at September 30, 2010; and 4.25:1.00 for all quarters ending after September 30, 2010. We were not in compliance with the working capital ratio covenant at December 31, 2009; however, we were able to obtain a waiver of default from TCB. A copy of this waiver is attached hereto as Exhibit 10.18.

We have listed assets for sale encompassing five leases in Johnson County, Kansas. Proceeds from the sale of these assets would, primarily, be used to meet scheduled Debenture redemptions. See Note 7. These five leases approximate $1.3 million of the value of our borrowing base. We would be required to pay this approximate $1.3 million to Texas Capital Bank upon the sale of these assets.

Subsequent to the quarter ended December 31, 2009, we further amended the Debentures to extend the scheduled due dates for the January and February 2010 redemption payments to March 10, 2010. See Note 7.

On January 5, 2010, we issued to Tom Nelson of Ten Associates, LLC 5,000 share of restricted common stock for payment of professional services to be rendered beginning in January 2010.

Pursuant to FAS 165, which is now incorporated into ASC Topic No. 855, management has evaluated all events and transactions that have occurred subsequent to the balance sheet date and has determined that there are no additional material events which have occurred as of February 16, 2010, that would be deemed significant or require recognition or additional disclosure.

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;

potential default under our secured obligations or material debt agreements;

estimated quantities and quality of oil and natural gas reserves;

declining local, national and worldwide economic conditions;

fluctuations in the price of oil and natural gas;

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) 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 year ended March 31, 2009.

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. and DD Energy, Inc., unless the context requires otherwise. We report our financial information on the basis of a March 31 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., 27 Corporate Woods, Suite 350, 10975 Grandview Drive, Overland Park, Kansas 66210.

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 focus on the acquisition of oil and natural gas mineral leases that have existing production and cash flow. Once acquired, subject to availability of capital, we strive to implement an accelerated development program utilizing capital resources, a regional operating focus, an experienced management and technical team, and enhanced recovery technologies to attempt to increase production and increase returns for our stockholders. Our oil and natural gas acquisition and development activities are currently focused in Eastern Kansas.

Since the beginning of fiscal 2008, we have deployed approximately $12 million in capital resources to acquire and develop five operating projects and drill 179 new wells (111 producing wells, 65 water injection wells, and 3 dry holes). Our estimated total proved PV 10 (present value) of reserves as of March 31, 2009 was $10.63 million, versus $39.6 million as of March 31, 2008. We developed estimated total proved reserves to 1.3 million barrels of oil equivalent, or BOE, as of March 31, 2009. Though total estimated proved reserves were comparable at March 31, 2009 and 2008; 1.3 million and 1.4 million BOE, respectively, the PV10 declined dramatically due to the estimated average price of oil at March 31, 2009 of $42.65 versus $94.53 at March 31, 2008. Of the 1.3 million BOE of total estimated proved reserves, approximately 39% are proved developed and approximately 61% are proved undeveloped. The proved developed reserves consist of 82% proved developed producing reserves and 18% proved developed non-producing reserves.

PV10 means the estimated future gross revenue to be generated from the production of proved reserves, net of estimated production and future development and abandonment costs, using prices and costs in effect at the determination date, before income taxes, and without giving effect to non-property related expenses, discounted to a present value using an annual discount rate of 10% in accordance with the guidelines of the SEC. PV10 is a non-GAAP financial measure and generally differs from the standardized measure of discounted future net cash flows, the most directly comparable GAAP financial measure, because it does not include the effects of income taxes on future net revenues.

In response to economic conditions and capital market constraints, we are exploring and evaluating various strategic initiatives that would allow us to continue our plans to grow production and reserves in the mid-continent region of the United States. Initiatives include creating joint ventures to further develop current leases, restructuring current debt, pursuing the sale of certain assets, as well as evaluating other options ranging from capital formation via additional debt or equity raising, to some type of business combination. We are continually evaluating oil and natural gas opportunities in Eastern Kansas and anticipate that this economic strategy would allow us to utilize our own financial assets toward the growth of our leased acreage holdings, pursue the acquisition of strategic oil and natural gas producing properties or companies and generally expand our existing operations while further diversifying risk. Subject to availability of capital, we plan to continue to bring potential acquisition and JV opportunities to various financial partners for evaluation and funding options. It is our vision to grow the business in a disciplined and well-planned manner. However, there can be no assurance that we will be successful in any of these respects, that the prices of oil and natural gas prevailing at the time of production will be at a level allowing for profitable production, or that we will be able to obtain additional funding at terms favorable to us to increase our currently limited capital resources.

We entered into a joint venture in June 2009 on the Brownrigg (“Brownrigg”) lease in Linn County, Kansas with Pharyn Impact Growth Fund, LP (“Pharyn”). The initial development funding on this lease was completed as of January 1, 2010. We have resumed development and completion activities on Brownrigg and anticipate production to begin in the quarter ending March 31, 2010.

Recent Developments

In April and May of 2009, we repurchased a total of $450,000 of the subordinated debentures and in December 2009, we redeemed $150,000 of the subordinated debentures for $150,000 in cash. In accordance with the terms of the amended Debentures, 75,000 shares have been or will be tendered to us and cancelled for the $150,000 redemption. The principal balance remaining as of December 31, 2009 is approximately $2.39 million. These debentures mature on September 30, 2010.

On August 3, 2009, upon advice and recommendation by the GCNC of EnerJex, we exchanged all of the 438,500 outstanding options to purchase shares of our common stock for shares of twelve-month restricted common stock to be issued pursuant to the terms of the EnerJex Resources, Inc. Stock Incentive Plan. All of the stock options outstanding on August 3, 2009 were exchanged for 109,700 shares of restricted common stock valued at $109,700 based upon the fair market value of the stock on the date of exchange.

Also on August 3, 2009, we awarded 211,050 shares of twelve-month restricted common stock, valued at $211,500 to be issued pursuant to the terms of the EnerJex Resources, Inc. Stock Incentive Plan for the following: 151,750 shares to employees as incentive compensation (with such shares being issued on August 4, 2010 assuming each employee remains employed by us through such date); and 59,300 shares to our named executives and independent directors as compensation related to options rescinded in the prior fiscal year.

In addition, on August 3, 2009, we issued 150,000 shares of restricted common stock (valued at $150,000) to vendors in satisfaction of certain outstanding balances payable to them and 32,000 shares of restricted common stock (valued at $32,000) to the four non-employee directors in lieu of cash compensation for board retainers for the period from July 1, 2009 through September 30, 2009.

Effective August 18, 2009, the Credit Facility with Texas Capital Bank was amended to implement a minimum interest rate of five percent (5.0%); establish minimum volumes to be hedged by September 15, 2009 of not less than seventy-five percent (75%) of the proved developed producing reserves attributable to our interest in the borrowing base oil and gas properties projected to be produced; and reduce the borrowing base to $6,986,500. Additionally, the borrowing base was reduced by $100,000 on the first day of each month by a Monthly Borrowing Base Reduction (MBBR) beginning September 1, 2009 and continuing through the January 1, 2010 redetermination.

On August 25, 2009 we entered into a fixed price swap transaction under the terms of the BP ISDA for a total of 20,250 gross barrels at a price of $77.05 per barrel before transportation costs for the period beginning October 1, 2009 and ending on March 31, 2011. This transaction allowed us to comply with the minimum hedge volumes required by Texas Capital Bank and increased the weighted average price for hedged volumes to between $64.958 and $61.963 from October 1, 2009 through March 2011.

Also on August 25, 2009, we entered into an agreement with Coffeyville Resources Refining and Marketing, LLC (“Coffeyville”) to sell all our crude oil production beginning October 1, 2009 through March 31, 2011 to Coffeyville. All physical production will be sold to Coffeyville at current market prices defined as the average of the daily settlement price for light sweet crude oil reported by NYMEX for any given delivery month. All prices received are before location basis differential and oil quality adjustments.

On November 16, 2009, we amended the Debentures to provide for the tender and cancellation of shares by the Buyers upon retirement of a portion of the Debentures in accordance with an agreed upon schedule. On December 21, 2009, we redeemed $150,000 of the Debentures for $150,000 in cash in accordance with the amendment. As a result, 75,000 shares will be tendered and cancelled.

On December 3, 2009 we entered into a Stock Equity Distribution Agreement (“SEDA”) with Paladin Capital Management, S.A. (“Paladin”). The SEDA provides that we may issue and sell to Paladin up to 1,300,000 shares (subject to adjustment as provided therein) of our common stock. We issued 90,000 shares to Paladin as a commitment fee under the terms of the SEDA. The price we receive shall be set at (i) 95% of the Market Price to the extent the Common Stock is trading at or above $2.00 per share during the Pricing Period, (ii) 92% of the Market Price to the extent the Common Stock is trading at or above $1.00 per share during the Pricing Period, (iii) 90% of the Market Price to the extent the Common Stock is trading below $1.00 per share during the Pricing Period, or (iv) 85% of the Market Price for the initial two advances. In December of 2009 we filed a registration statement on Form S-1 to register the 1,390,000 shares included in the SEDA. This registration statement is not yet effective.

Effective January 13, 2010 the Credit Facility with Texas Capital Bank was amended to modify the senior funded debt to EBITDA ratio on a quarterly basis beginning with the quarter ending December 31, 2009 and to modify the annualization of the interest coverage ratio, also beginning with the quarter ending December 31, 2009. See Note 8 to our Condensed Consolidated Financial Statements in this report. The senior funded debt to EBITDA ratio allowed is 6.25:1.00 at December 31, 2009; 5.75:1.00 at March 31, 2010; 5.25:1.00 at June 30, 2010; and 4.75:1.00 at September 30, 2010; and 4.25:1.00 for all quarters ending after September 30, 2010. We were not in compliance with the working capital ratio covenant at December 31, 2009; however, we were able to obtain a waiver of default from TCB. A copy of this waiver is attached hereto as Exhibit 10.18.

Results of Operations for the Three Months and Nine Months Ended December 31, 2009 and 2008 compared.

Income:

	Three Months Ended				Increase /			Nine Months Ended				Increase /
	December 31,				(Decrease)			December 31,				(Decrease)
	2009		2008		$			2009		2008		$
Oil and natural gas revenues	$	914,545	$	1,184,547	$	(270,002	)	$	3,703,724	$	4,652,289	$	(948,565	)

Revenues

Oil and natural gas revenues for the three months ended December 31, 2009 were $914,454 compared to revenues of $1,184,547 in the three months ended December 31, 2008. The decrease in the three month revenues is due to the lower price of oil and to lower sales volumes during the quarter ended December 31, 2009 as compared to December 31, 2008. Oil and natural gas revenues for the nine months ended December 31, 2009 were $3,703,724 and $4,652,289 in the nine months ended December 31, 2008. The decrease in the nine month revenues is due to both lower average oil prices and sales volumes in the current year as compared to the prior year. The average price per barrel of oil, net of transportation costs, sold during the three months ended December 31, 2009 was $69.34 compared to $71.91 during the three months ended December 31, 2008 and was $76.64 for the nine months ended December 31, 2009 compared to $89.97 for the nine months ended December 31, 2008.

Expenses:

	Three Months Ended						Increase /			Nine Months Ended						Increase /
	December 31,						(Decrease)			December 31,						(Decrease)
	2009			2008			$			2009			2008			$
Production expenses:
Direct operating costs	$	448,684		$	562,693		$	(114,009	)	$	1,313,518		$	2,093,994		$	(780,476	)
Depreciation, depletion and amortization		131,394			277,020			(145,626	)		577,288			995,069			(417,781	)
Impairment of oil and gas properties		-			4,777,723			(4,777,723	)		-			4,777,723			(4,777,723	)
Total production expenses		580,078			5,617,436			(5,037,358	)		1,890,806			7,866,786			(5,975,980	)

General expenses:
Professional fees		60,571			106,032			(45,461	)		479,710			400,816			78,894
Salaries		153,022			200,547			(47,525	)		706,011			694,973			11,038
Administrative expense		334,512			238,726			95,786			789,827			1,065,308			(275,481	)
Total general expenses		548,105			545,305			2,800			1,975,548			2,161,097			(185,549	)
Total production and general expenses		1,128,183			6,162,741			(5,034,558	)		3,866,354			10,027,883			(6,161,529	)

Other income (expense)
Interest expense		(189,374	)		(205,327	)		15,953			(542,939	)		(743,372	)		200,433
Loan interest accretion		(153,374	)		(119,512	)		(33,862	)		(432,864	)		(2,686,892	)		2,254,028
Gain on liquidation of hedging instrument		-			3,879,050			(3,879,050	)		-			3,879,050			(3,879,050	)
Unrealized gain (loss) on derivative instruments		(2,485,706	)		-			(2,485,706	)		(2,485,706	)		-			(2,485,706	)
Loan fee expense
Gain on repurchase of debentures		-			-						406,500			-			406,500
Management fee revenue		23,944			-			23,944			99,234			-			99,234
Loss on disposal of vehicle		(20,695	)		-			(20,695	)		(20,695	)		(4,421	)		(16,274	)
Total other income (expense)		(2,825,205	)		3,554,211			(6,379,416	)		(2,976,470	)		444,365			3,420,835

Net income (loss)	$	(3,038,843	)	$	(1,423,983	)	$	1,614,860		$	(3,139,100	)		(4,931,229	)	$	1,792,129

Direct Operating Costs

Direct operating costs for the three months ended December 31, 2009 were $448,684 compared to $562,693 for the three months ended December 31, 2008 and $1,313,518 compared to $2,093,994 for each of the nine months ended December 31, 2009 and 2008, respectively. The decrease in the current periods over the prior periods results from personnel and cost reductions implemented to offset declining oil and natural gas prices. Direct operating costs include pumping, gauging, pulling, certain contract labor costs, and other non-capitalized expenses.

Depreciation, Depletion and Amortization

Depreciation, depletion and amortization (DD&A) for the three and nine months ended December 31, 2009 was $131,394 and $577,288, respectively, compared to $277,020 and $995,069 for the three and nine months ended December 31, 2008. The decreases were primarily a result of lower production in the quarter and year to date periods ended December 31, 2009 versus the comparable periods ended December 31, 2008. Costs of depletion per barrel of oil reserves were also lower in 2009 than in 2008. The rate of depletion was $12.10 per barrel for the nine months ended December 31, 2009 as compared to $17.09 per barrel for the nine months ended December 31, 2008. The per barrel rate of depletion is equal to the total book value of oil and gas properties plus future development costs associated with reserves divided by the net number of barrels of such reserves. The decline in the rate is directly attributed to the lower book value of the oil and gas properties at December 31, 2009 as compared to December 31, 2008 following an impairment charge of nearly $4.8 million in December of 2008.

Impairment of Oil and Gas Properties

We recorded a non-cash impairment of $4,777,723 million to the carrying value of our proved oil and gas properties as of December 31, 2008. The impairment is primarily attributable to lower prices for both oil and natural gas at December 31, 2008. The charge results from the application of the “ceiling test” under the full cost method of accounting. Under full cost accounting requirements, the carrying value 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. A ceiling test charge occurs when the carrying value of the oil and gas properties exceeds the full cost ceiling.

Professional Fees

Professional fees for the three months ended December 31, 2009 were $60,571 compared to $106,032 for the three months ended December 31, 2008, reflecting little change. This compares to professional fees of $479,710 for the nine months ended December 31, 2009 and $400,816 for the same period in 2008. The decrease in professional fees in the three months ended December 31, 2009 versus December 31, 2008 results from cost reductions implemented to offset declining oil and natural gas prices. The increase in professional fees in the nine months ended December 31, 2009 over December 31, 2008 is due to both higher costs incurred in connection with the fiscal year end reserve evaluations performed by a new independent reserve engineer, as well as non-cash charges for restricted stock issued to non-employees for options cancelled in August 2009.

Salaries

Salaries for the three months ended December 31, 2009 were $153,022 compared to $200,547 for the three months ended December 31, 2008. There were fewer employees at December 31, 2009 versus December 31, 2008, which is primarily the cause of the decline. Additionally, salaries for the nine month periods ended December 31, 2009 and 2008 were $706,011 and $694,973, respectively. The effect of the decrease in the number of employees referred to above is offset by non-cash charges for restricted stock issued to employees for both options cancelled, and accrued, but un-paid employee incentives in August 2009.

Administrative Expense

Administrative expense for the three and nine months ended December 31, 2009 was $334,512 and $789,827, compared to $238,726 in the three months ended December 31, 2008 and $1,065,308 in the nine months ended December 31, 2008. The administrative expense increased in the quarter ended December 31, 2009 over the quarter ended December 31, 2008 due to (a) printing expenses totaling $60,000 which were paid in October 2009; (b) approximately $27,000 of bank fees associated with the Credit Facility; and (c) increases in auto expenses, depreciation on office equipment, and insurance. The administrative expense in the prior period ended December 31, 2008 contained significant public and investor relations expenses as well as travel related costs incurred in connection with the road show for a public offering that was subsequently cancelled, explaining the decrease in the nine month period ended December 31, 2009.

Interest expense

Interest expense for the three and nine months ended December 31, 2009 was $189,374 and $542,939, whereas interest expense for the three and nine months ended December 31, 2008 was $205,327 and $743,372. Interest expense was primarily related to our debentures and our Credit Facility. See Note 7 to our Condensed Consolidated Financial Statements in this report.

Loan Interest Accretion

Loan Interest Accretion for the three and nine months ended December 31, 2009 was $153,374 and $432,864, whereas loan interest accretion for the three and nine months ended December 31, 2008 was $119,512 and $2,686,892. The amount of interest accreted is based on the interest method over the period of issue to maturity or redemption. A proportionate share of the loan costs were expensed upon redemption of $6.3 of the $9.0 million debentures in July of 2008, accounting for the significantly higher amount in the nine month period ended December 31, 2008 as compared to December 31, 2009. See note 7 to our Condensed Consolidated Financial Statements in this report.

Gain on Liquidation of Hedging Instrument

As of July 3, 2008, we entered into an ISDA master agreement and a costless collar with BP Corporation North America Inc., or BP, for 130 barrels of oil per day with a price floor of $132.50 per barrel and a price ceiling of $155.70 per barrel for NYMEX West Texas Intermediate for the period of October 1, 2009 until March 31, 2011. We liquidated this costless collar in November 2008 and received proceeds of approximately $3.9 million from BP. We reduced the debt outstanding under our Credit Facility by approximately $3.3 million and used the remainder for general operating purposes.

Unrealized Gain (loss) on Derivative Instruments

Unrealized gain or loss on derivative instruments is the mark-to-market exposure under our commodity swaps. This non-cash unrealized loss for the quarter ended December 31, 2009 was $2,485,706. Unrealized gain or loss will fluctuate from period to period when commodities are hedged, and will be a function of the instruments in place and the forward curve pricing for the commodities.

Gain on Repurchase of Debentures

We repurchased $450,000 of the Debentures during the nine months ended December 31, 2009 at a gain of $406,500. We also redeemed an additional $150,000 of the Debentures during the quarter ended December 31, 2009 for $150,000 in cash. No gain or loss resulted from this $150,000 redemption.

Management Fee Revenue

Management fee revenue for the three and nine months ended December 31, 2009 was $23,944 and $99,234, respectively, and represents revenues earned as operator on the Brownrigg joint venture project, in accordance with the terms of the joint operating agreement.

Net Income (Loss)

Net loss for the three months ended December 31, 2009 was $3,038,843 and $3,139,100 for the nine months ended December 31, 2009 as compared to a net loss of $1,423,983 in the three months ended December 31, 2008 and $4,931,229 in the nine months ended December 31, 2008. The primary component of the net loss is the non-cash unrealized loss of $2,485,706 recorded in the quarter ended December 31, 2009. Loan interest accretion, also a non-cash expense further contributes to the net loss recorded in both the three and nine months ended December 31, 2009 and 2008.

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. Based upon the monthly commitment notices we have received to date, we have estimated and classified $330,000 of the borrowings outstanding under our Credit Facility as a current liability. As we may be unable to provide the necessary liquidity we need by the revenues generated from our net interests in our oil and natural gas production at current commodity prices, we are exploring various strategic initiatives and JV partnerships, as well as sales of reserves in our existing properties to finance our operations and to service our debt obligations.

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 at December 31, 2009 as compared to March 31, 2009.

	December 31, 2009			March 31, 2009			Increase / (Decrease) $
Current Assets	$	977,561		$	898,941			78,620

Current Liabilities	$	2,258,331		$	2,827,015			568,684

Working Capital (deficit)	$	(1,280,770	)	$	(1,928,074	)		647,304

Senior Secured Credit Facility

On July 3, 2008, EnerJex, EnerJex Kansas, and DD Energy entered into a three-year $50 million Senior Secured Credit Facility (the “Credit Facility”) with Texas Capital Bank, N.A. Borrowings under the Credit Facility will be subject to a borrowing base limitation based on our current proved oil and gas reserves and will be subject to semi-annual redeterminations. The Credit Facility is secured by a lien on substantially all assets of the Company and its subsidiaries. The Credit Facility has a term of three years, and all principal amounts, together with all accrued and unpaid interest, will be due and payable in full on July 3, 2011. The Credit Facility also provides for the issuance of letters-of-credit up to a $750,000 sub-limit under the borrowing base and up to an additional $2.25 million limit not subject to the borrowing base to support our hedging program.

Proceeds from the initial extension of credit under the Credit Facility were used: (1) to redeem our 10% debentures in an aggregate principal amount of $6.3 million plus accrued interest (the “April Debentures”), (2) for Texas Capital Bank’s acquisition of our approximately $2.0 million indebtedness to Cornerstone Bank, (3) for complete repayment of promissory notes issued to the sellers in connection with our purchase of the DD Energy project in an aggregate principal amount of $965,000 plus accrued interest, (4) to pay transaction costs, fees and expenses related to the Credit Facility, and (5) to expand our current development projects. Future borrowings may be used for the acquisition, development and exploration of oil and gas properties, capital expenditures and general corporate purposes.

Advances under the Credit Facility will be in the form of either base rate loans or Eurodollar loans. The interest rate on the base rate loans fluctuates based upon the higher of (1) the lender’s “prime rate” and (2) the Federal Funds rate plus 0.50%, plus, in either case, a margin of between 0.0% and 0.5% depending on the percent of the borrowing base utilized at the time of the credit extension, but in no event shall be less than five percent (5.0%). The interest rate on the Eurodollar loans fluctuates based upon the applicable LIBOR rate, plus a margin of 2.25% to 2.75% depending on the percent of the borrowing base utilized at the time of the credit extension, but in no event shall be less than five percent (5.0%). Eurodollar loans may be based upon one, two, three and six month LIBOR options, except that beginning March 30, 2009 and continuing through the date of this report, the Texas Capital Bank has suspended all LIBOR based funding with maturities less than 90 days due to the extreme volatility in the interest rate market and the unprecedented spread between the 90 day LIBOR and the shorter term LIBOR options. A commitment fee of 0.375% on the unused portion of the borrowing base will accrue, and be payable quarterly in arrears. There was no commitment fee due at December 31, 2009.

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 also requires that we, at the end of each fiscal quarter beginning with the quarter ending September 30, 2008, maintain a minimum current assets to current liabilities ratio and a minimum ratio of EBITDA (earnings before interest, taxes, depreciation and amortization) to interest expense and at the end of each fiscal quarter beginning with the quarter ended September 30, 2008 to maintain a minimum ratio of EBITDA to senior funded debt. The Credit Facility was amended August 18, 2009 to implement a minimum interest rate of five (5.0%) and establish minimum volumes to be hedged of not less than seventy-five percent (75%) of the proved developed producing reserves attributable to our interest in the borrowing base oil and gas properties projected to be produced. The Credit Facility was further amended January 13, 2010 to modify the senior funded debt to EBITDA ratio on a quarterly basis beginning with the quarter ending December 31, 2009 and to modify the annualization of the interest coverage ratio, also beginning with the quarter ending December 31, 2009. See Note 8 to our Condensed Consolidated Financial Statements in this report. A copy of the January 13, 2010 amendment is attached hereto as Exhibit 10.16. The senior funded debt to EBITDA ratio allowed is 6.25:1.00 at December 31, 2009; 5.75:1.00 at March 31, 2010; 5.25:1.00 at June 30, 2010; and 4.75:1.00 at September 30, 2010; and 4.25:1.00 for all quarters ending after September 30, 2010. We were not in compliance with the working capital ratio covenant at December 31, 2009; however, we were able to obtain a waiver of default from TCB. A copy of this waiver is attached hereto as Exhibit 10.18.

Additionally, Texas Capital Bank, N.A. and the holders of the debentures entered into a Subordination Agreement whereby the debentures issued on June 21, 2007 will be subordinated to the Credit Facility.

Debenture Financing

On April 11, 2007, we completed a $9.0 million private placement of senior secured debentures. In accordance with the terms of the debentures, we received $6.3 million (before expenses and placement fees) at the first closing and an additional $2.7 million (before closing fees and expenses) at the second closing on June 21, 2007. In connection with the sale of the debentures, we issued the lenders 1,800,000 shares of common stock. On July 7, 2008, we redeemed $6.3 million aggregate principal amount of our debentures. Effective July 7, 2008, we redeemed an aggregate principal amount of $6.3 million of the Debentures. We also amended the $2.7 million of aggregate principal amount of the remaining Debentures to, among other things, permit the indebtedness under our Credit Facility, subordinate the security interests of the debentures to the Credit Facility, provide for the redemption of the remaining Debentures with the net proceeds from our next debt or equity offering and eliminate the covenant to maintain certain production thresholds.

The Debentures originally had a three-year term, maturing on March 31, 2010, and an interest rate equal to 10% per annum. We further amended the Debentures in June 2009 to extend the maturity date to September 30, 2010, to allow us to pay interest in either cash or payment-in-kind interest (an increase in the amount of principal due) or payment-in-kind shares (issuance of shares of common stock), and add a provision for the conversion of the debentures into shares of EnerJex’s common stock. Interest is payable quarterly in arrears on the first day of each succeeding quarter. The interest rate remains 10% per annum for cash interest payments. The payment-in-kind interest rate is equal to 12.5% per annum. If interest payments are made through payment-in-kind interest, we must issue common stock equal to and additional 2.5% of the quarterly interest payment due.

We have no prepayment penalty so long as we maintain an effective registration statement with the Securities Exchange Commission and provided we give six (6) business days prior notice of redemption to the Buyers. In April and May of 2009, we redeemed $450,000 of the Debentures for $43,500 in cash.

We again amended the Debentures on November 16, 2009 to provide for the tender and cancellation of shares by the Buyers upon retirement of a portion of the Debentures in accordance with an agreed up schedule. We redeemed $150,000 of the Debentures for $150,000 in cash in accordance with this amendment during the quarter ended December 31, 2009. As a result, 75,000 shares will be tendered and cancelled.

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. During fiscal 2009, we were in the midst of a public equity offering when global economic conditions deteriorated and the commodity prices of oil and natural gas experienced significant declines. Our cash revenues from operations have been significantly impacted as has our ability to meet our monthly operating expenses and service our debt obligations. We are actively seeking opportunities to raise funds through a debt or equity offering and through the sale of certain assets. In the event we cannot obtain additional capital through other means to allow us to pursue our strategic plan, this would materially impact not only our ability to continue our desired growth and execute our business strategy, but also to continue as a going concern. There is no assurance we would be able to obtain such financing on commercially reasonable terms, if at all. Failure to do so can have a material adverse effect on our business prospects, financial condition and results of operations

Summary of product research and development

We do not anticipate performing any significant product research and development under our plan of operation until such time as we can raise adequate working capital to sustain our operations.

Expected purchase or sale of any significant equipment

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

Significant changes in the number of employees

At December 31, 2009, we had 14 full time employees, equal to the number of full time employees at our fiscal year ended March 31, 2009. Since November 2008, we have reduced personnel levels by 5 full time employees and 2 independent contractors in response to declining economic conditions and in an effort to reduce our operating and general expenses and cash outlay. As drilling and production activities increase or decrease, we may have to adjust our technical, operational and administrative personnel as appropriate. We are using and will continue to use the services of independent consultants and contractors to perform various professional services, particularly in the area of land services, reservoir engineering, drilling, water hauling, pipeline construction, well design, well-site monitoring and surveillance, permitting and environmental assessment when it is prudent and necessary to do so. 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, current portion of long-term debt, derivative instruments, and share-based payments.

Oil and Gas Properties:

The accounting for our business is subject to special accounting rules that are unique to the gas and oil industry. There are two allowable methods of accounting for oil and gas 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 gas and 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.

On a regular basis, we evaluate the carrying value of our gas and oil properties considering the full-cost accounting methodology. 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. This sum which may not be exceeded is referred to as the “ceiling”. In calculating future net revenues, current SEC regulations require us to utilize prices at 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 gas and 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, gas and 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 gas and 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.

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.

Current Portion of Long-term Debt:

We have classified a portion of the borrowings outstanding under our Credit Facility as a current liability based upon monthly commitment reduction notices that we have received in connection with borrowing base reviews by Texas Capital Bank. Our future estimates may change as a result of, among other factors, the semi-annual borrowing base redeterminations required under the Credit Facility.

Derivative Instruments:

The Company determines the fair value of its derivative instruments utilizing various inputs, including NYMEX price quotations and contract terms. The mark-to-market exposure under our derivative instruments is recorded as an unrealized gain or loss. This exposure will vary from period to period with fluctuations in commodity prices, which have been and may continue to be volatile.

Share-Based Payments:

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

Recent Accounting Pronouncements

In June 2009, the FASB adopted Codification Topic Statement No. 105 “The FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles”. ASC 105 is the single source of authoritative nongovernmental U.S. generally accepted accounting principles (“GAAP”), superseding existing FASB, American Institute of Certified Public Accounts (“AICPA”), Emerging Issues Task Force (“EITF”), and related accounting literature. ASC 105 reorganized the thousands of GAAP pronouncements into roughly 90 accounting topics and displays them using a consistent structure. Also included is relevant Securities and Exchange Commission guidance organized using the same topical structure in separate sections. ASC 105 will be effective for financial statements issued for reporting periods that end after September 15, 2009. There was no impact upon adoption.

In May 2009, the FASB adopted Codification Topic 855,” Subsequent Event’s, which requires entities to disclose the date through which they have evaluated subsequent events and whether the date corresponds with the release of its financial statements. The statement established general standards of accounting for and disclosure of events that occur after the balance sheet date but before financial statements are issued or are available to be issued. ASC 855 is effective for interim or annual financial periods ending after June 15, 2009, and shall be applied prospectively. The adoption ASC 855 did not have a material impact on the Company’s financial statements.

In April 2009, the Financial Accounting Standards Board (FASB) issued FASB Staff Position (FSP) Financial Accounting Standard (FAS) 157-4, “Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly” (Codification Topic 820). Based on the guidance, if an entity determines that the level of activity for an asset or liability has significantly decreased and that a transaction is not orderly, further analysis of transactions or quoted prices is needed, and a significant adjustment to the transaction or quoted prices may be necessary to estimate fair value in accordance with Statement of Financial Accounting Standards (SFAS) No. 157 Fair Value Measurements. This FSP is to be applied prospectively and is effective for interim and annual periods ending after June 15, 2009 with early adoption permitted for periods ending after March 15, 2009.

In April 2009, the FASB issued FSP FAS 115-2 and FAS 124-2, Recognition and Presentation of Other-Than-Temporary Impairments (Codification Topic 320). The guidance applies to investments in debt securities for which other-than-temporary impairments may be recorded. If an entity’s management asserts that it does not have the intent to sell a debt security and it is more likely than not that it will not have to sell the security before recovery of its cost basis, then an entity may separate other-than-temporary impairments into two components: 1) the amount related to credit losses (recorded in earnings), and 2) all other amounts (recorded in other comprehensive income). This FSP is to be applied prospectively and is effective for interim and annual periods ending after June 15, 2009 with early adoption permitted for periods ending after March 15, 2009.

FSP FAS 107-1 and APB 28-1 - In April 2009, the FASB issued FSP FAS 107-1 and Accounting Principles Board (APB) 28-1, Interim Disclosures about Fair Value of Financial Instruments (ACS Topic 825). The FSP amends SFAS No. 107 Disclosures about Fair Value of Financial Instruments to require an entity to provide disclosures about fair value of financial instruments in interim financial information. This FSP is to be applied prospectively and is effective for interim and annual periods ending after June 15, 2009 with early adoption permitted for periods ending after March 15, 2009.

Recent Accounting Pronouncement Issued But Not in Effect

In June 2009, the FASB adopted SFAS 166,” Accounting for Transfers of Financial Assets (“ACS Topic 860”) Statement 166 is a revision to FASB Statement No. 140, Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities, and will require more information about transfers of financial assets, including securitization transactions, and where entities have continuing exposure to the risks related to transferred financial assets. It eliminates the concept of a “qualifying special-purpose entity,” changes the requirements for derecognizing financial assets, and requires additional disclosures. SFAS 166 enhances information reported to users of financial statements by providing greater transparency about transfers of financial assets and an entity’s continuing involvement in transferred financial assets. SFAS 166 will be effective at the start of a reporting entity’s first fiscal year beginning after November 15, 2009. Early application is not permitted. The Company does not anticipate the adoption of SFAS 166 will have an impact on its consolidated results of operations or consolidated financial position.

In June 2009, the FASB issued SFAS No. 167, Amendments to FASB Interpretation No. 46(R) (“ACS Topic 810). Statement 167 is a revision to FASB Interpretation No. 46 (Revised December 2003), Consolidation of Variable Interest Entities, and changes how a reporting entity determines when an entity that is insufficiently capitalized or is not controlled through voting (or similar rights) should be consolidated. The determination of whether a reporting entity is required to consolidate another entity is based on, among other things, the other entity’s purpose and design and the reporting entity’s ability to direct the activities of the other entity that most significantly impact the other entity’s economic performance. SFAS 167 will require a reporting entity to provide additional disclosures about its involvement with variable interest entities and any significant changes in risk exposure due to that involvement. A reporting entity will be required to disclose how its involvement with a variable interest entity affects the reporting entity’s financial statements. SFAS 167 will be effective at the start of a reporting entity’s first fiscal year beginning after November 15, 2009. Early application is not permitted. The Company is currently evaluating the impact, if any, of adoption of SFAS 167 on its financial statements.

Effects of Inflation and Pricing

The oil and natural gas 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 and natural gas companies and their ability to raise capital, borrow money and retain personnel. We anticipate business costs and the demand for services related to production and exploration will fluctuate while the commodity prices for oil and natural gas both remain 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.

Item 4T. Controls and Procedures.

Our Chief Executive Officer, C. Stephen Cochennet, and Chief Financial Officer, Dierdre P. Jones, 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. Cochennet and Ms. Jones concluded that our disclosure controls and procedures are effective in timely alerting them 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 1A. Risk Factors.

Information regarding risk factors appears in Part I, “Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations” under the captions “Overview”, “Recent Developments” and “Cautionary Note Regarding Forward-Looking Statements” contained in this Quarterly Report on Form 10-Q and in “Item 1A. RISK FACTORS” of our Annual Report on Form 10-K for the year ended March 31, 2009. Other than as set forth below, there have been no material changes from the risk factors previously disclosed in our Annual Report on Form 10-K for the year ended March 31, 2009.

Risks Associated with Our Business

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

On December 31, 2009, $2.39 million in debentures and approximately $6.75 million of bank loans were outstanding. Under a default situation with respect to the debentures or other secured debt, the lenders may enforce their rights as a secured party and we may lose all or a portion of our assets or be forced to materially reduce our business activities. An event of default under the Credit Facility permits Texas Capital to accelerate repayment of all amounts due and to terminate the commitments thereunder. Any event of default which results in such acceleration under the Credit Facility would also result in an event of default under our Debentures. We do not have sufficient cash resources to repay these amounts if Texas Capital accelerates its obligations under the Credit Facility. If we are unable to successfully negotiate a forbearance agreement or waiver with Texas Capital, or if Texas Capital accelerates its obligations under the Credit Facility, we may be forced to voluntarily seek bankruptcy protection.

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

On July 3, 2008, we entered into a three-year, Senior Secured Credit Facility providing for aggregate borrowings of up to $50 million. As of December 31, 2009, we had total indebtedness of $9.2 million, including $6.75 million of borrowings under the Credit Facility and $2.39 million of remaining debentures, as well as other notes payable totaling approximately $75,000. We had no outstanding letters of credit under the facility on December 31, 2009. Our substantial indebtedness, and the related interest expense, could have important consequences to us, including:

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

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

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

increasing our vulnerability to general adverse economic and industry conditions;

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

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

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

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

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

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

incur additional indebtedness and provide additional guarantees;

pay dividends and make other restricted payments;

create or permit certain liens;

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

use the proceeds from the unwinding of certain financial hedges;

engage in certain transactions with affiliates; and

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

The Credit Facility and our debentures also contain various affirmative covenants with which we are required to comply. We obtained a waiver of default from Texas Capital Bank on two technical covenants at March 31, 2009 and one at June 30, 2009. We were not in compliance with the working capital ratio covenant at December 31, 2009; however, we were able to obtain a waiver of default from TCB. A copy of this waiver is attached hereto as Exhibit 10.18. We are taking steps in an effort to comply with these same covenants in future quarters, including but not limited to, a reduction in principal of approximately $4 million since November 2008, and the reduction of our operating and general expenses. We may be unable to comply with some or all of these covenants in the future as well. If we do not comply with these covenants and are unable to obtain waivers from our lenders, we would be unable to make additional borrowings under these facilities, our indebtedness under these agreements would be in default and could be accelerated by our lenders. In addition, it could cause a cross-default under our other indebtedness, including our debentures. If our indebtedness is accelerated, we may not be able to repay our indebtedness or borrow sufficient funds to refinance it. In addition, if we incur additional indebtedness in the future, we may be subject to additional covenants, which may be more restrictive than those to which we are currently subject.

Risks Associated with our Common Stock

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

The exercise of our outstanding warrants, and the conversion of a convertible note, will cause additional shares of common stock to be issued, resulting in dilution to our existing and future common stockholders.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds.

On August 20, 2009, we issued the Debenture holders 2,330 shares of our common stock in lieu of interest payments for the quarter ended March 31, 2009 and 2,394 shares of our common stock in lieu of interest payments for the quarter ended June 30, 2009. We believe that the issuance of the shares was exempt from the registration and prospectus delivery requirements of the Securities Act of 1933 by virtue of Section 4(2) thereof.

On October 8, 2009, we issued the Debenture holders 1,424 shares of our common stock in lieu of interest payments for the quarter ended September 30, 2009. We believe that the issuance of the shares was exempt from the registration and prospectus delivery requirements of the Securities Act of 1933 by virtue of Section 4(2) thereof.

On December 3, 2009, we authorized the issuance of 90,000 shares of our common stock to Paladin as a commitment fee under the SEDA. We believe that the issuance of the shares was exempt from the registration and prospectus delivery requirements of the Securities Act of 1933 by virtue of Section 4(2) thereof.

On December 22, 2009, in an effort for the Company to preserve cash in light of deteriorated global economic conditions and the significant declines in commodity prices of oil and natural gas, each of the Company’s non-employee directors agreed to convert their board/committee retainers for the period from October 1, 2009 through December 31, 2009 into 20,000 shares of the Company’s restricted common stock. The Company believes that the issuance of the shares was exempt from the registration and prospectus delivery requirements of the Securities Act of 1933 by virtue of Section 4(2) thereof.

On January 4, 2010, the Company issued to MorMeg, LLC 45,000 shares of restricted common stock for payment of consulting fees accrued from July 2009 through March 31, 2010 and 65,000 shares of restricted common stock as payment for granting an extension on the date required to provide additional development funding on the Black Oaks project. The Company believes that the issuance of the shares was exempt from the registration and prospectus delivery requirements of the Securities Act of 1933 by virtue of Section 4(2) thereof.

On January 5, 2010, in an effort for the Company to preserve cash in light of deteriorated global economic conditions and the significant declines in commodity prices of oil and natural gas, Steve Cochennet, our CEO/President, agreed to convert his salary for the months of January and February 2010 into 73,261 shares of the Company’s restricted common stock. The Company believes that the issuance of the shares was exempt from the registration and prospectus delivery requirements of the Securities Act of 1933 by virtue of Section 4(2) thereof.

On January 5, 2010, we issued to Tom Nelson of Ten Associates, LLC 5,000 share of restricted common stock for payment of professional services to be rendered beginning in January 2010. The Company believes that the issuance of the shares was exempt from the registration and prospectus delivery requirements of the Securities Act of 1933 by virtue of Section 4(2) thereof.

On January 12, 2010, we issued the Debenture holders an additional 45 shares of our common stock in lieu of interest payments for the quarter ended September 30, 2009 and 4,223 shares of our common stock in lieu of interest payments for the quarter ended December 31, 2009. We believe that the issuance of the shares was exempt from the registration and prospectus delivery requirements of the Securities Act of 1933 by virtue of Section 4(2) thereof.

Item 3. Defaults Upon Senior Securities.

Credit Facility

On July 3, 2008, we entered into a three-year $50 million Senior Secured Credit Facility (the “Credit Facility”) with Texas Capital Bank, N.A. Borrowings under the Credit Facility are subject to a borrowing base limitation based on our current proved oil and gas reserves and are subject to semi-annual redeterminations.

The Credit Facility also requires that we, at the end of each fiscal quarter beginning with the quarter ending September 30, 2008, maintain a minimum current assets to current liabilities ratio and a minimum ratio of EBITDA (earnings before interest, taxes, depreciation and amortization) to interest expense and at the end of each fiscal quarter and to maintain a minimum ratio of EBITDA to senior funded debt. We obtained a waiver of default from Texas Capital Bank on two technical covenants at March 31, 2009 and one at June 30, 2009. We were not in compliance with the working capital ratio covenant at December 31, 2009; however, we were able to obtain a waiver of default from TCB. A copy of this waiver is attached hereto as Exhibit 10.18.

During the nine months ended December 31, 2009, we received Monthly Commitment Reduction notices from Texas Capital requiring $900,000to be repaid to the bank under the Credit Facility through monthly installments. We paid $582,000 to reduce the borrowing base during that same period.. Following receipt of the notices, we commenced discussions with Texas Capital regarding a possible forbearance agreement or waiver, pursuant to which the bank would waive, postpone or delay the requirement to repay some or all of the anticipated Monthly Commitment Reductions, in order to afford us additional time to raise equity capital, increase production or consummate alternative financing transactions. The discussions are currently ongoing, although there is no assurance that we will be able to negotiate successfully a forbearance agreement or obtain any other waiver of compliance from the bank.

Although we anticipate the ability to make monthly payments of $55,000 beginning February 1, 2010 following the most recent borrowing base review, which will be applied towards the borrowing base reduction; if we are unable to successfully negotiate a forbearance agreement, obtain a waiver of compliance or cure a borrowing base deficiency, an event of default under the Credit Facility will occur. An event of default under the Credit Facility permits Texas Capital to accelerate repayment of all amounts due and to terminate the commitments thereunder. We currently have approximately $6.75 million drawn under the Credit Facility. Any event of default which results in such acceleration under the Credit Facility would also result in an event of default under our Debentures, described above. We do not have sufficient cash resources to repay these amounts if Texas Capital accelerates its obligations under the Credit Facility. If we are unable to successfully negotiate a forbearance agreement or waiver with Texas Capital, or if Texas Capital accelerates its obligations under the Credit Facility, we may be forced to voluntarily seek bankruptcy protection.

The terms of the Credit Facility (including a full description of the rights and remedies of Texas Capital upon an event of default), and copies of the Texas Capital agreements related to the Credit Facility can be found in our prior filings with the SEC, including the Current Reports on Forms 8-K filed with the SEC on July 10, 2008 and November 19, 2008, which are incorporated herein by reference and in the First Amendment to the Credit Agreement included in exhibit 10.12 and in the Second Amendment to the Credit Agreement included in exhibit 10.16.

Item 4. Submission of Matters to a Vote of Security Holders.

There were no matters submitted to Security Holders for Vote during the quarter ended December 31, 2009.

Item 5. Other Information.

In December of 2009, we amended the JEA with MorMeg to extend the date for the provision of additional development funds for the Black Oaks project to March 31, 2010. We issued MorMeg 65,000 shares of our common stock as consideration for the amendment. A copy of the amendment to the JEA is attached hereto as Exhibit 10.15.

Subsequent to the quarter ended December 31, 2009, we have listed assets for sale encompassing five leases in Johnson County, Kansas. Proceeds from the sale of these assets would, primarily, be used to meet scheduled Debenture redemptions. These five leases approximate $1.3 million of the value of our borrowing base. We would be required to pay this approximate $1.3 million to Texas Capital Bank upon the sale of these assets.

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)
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		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)
10.9		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)
10.10		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)
10.11		Waiver from Texas Capital Bank, N.A. dated July 14, 2009 (incorporated by reference to the Exhibit 10.16 to the Form 10-K filed July 14, 2009)
10.12		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)
10.13		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)
10.14		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)
10.15		Amendment 5 to Joint Exploration Agreement effective as of December 31, 2009 between MorMeg LLC and EnerJex Resources, Inc.
10.16		Second Amendment to Credit Agreement dated January 13, 2010
10.17		Debenture Holder Amendment Letter dated January 27, 2010
10.18		Waiver from Texas Capital Bank, N.A. dated February 10, 2009
31.1		Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
31.2		Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
32.1		Certification of Chief Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
32.2		Certification of Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

† 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/ Dierdre P. Jones
	Dierdre P. Jones, Chief Financial Officer
	(Principal Financial Officer)

Date: February 16, 2010