AgEagle Aerial Systems 424B3 Prospectus supplement

Filed Pursuant to Rule 424(b)(3)

Registration No. 333-156115

PROSPECTUS SUPPLEMENT NO. 2 TO

PROSPECTUS DATED DECEMBER 24, 2008

ENERJEX RESOURCES, INC.

1,000,000 SHARES OF COMMON STOCK

(par value $0.001 per share)

_______________________________________

This Prospectus Supplement relates to the resale of up to 1,000,000 shares of Common Stock, par value $0.001 per share, of EnerJex Resources, Inc. (“EnerJex”). These shares may be offered or sold by the selling stockholder identified on page 77 of the Prospectus dated December 24, 2008 (the “Base Prospectus”) in the manner provided in the Base Prospectus. See “Plan of Distribution” in the Base Prospectus. EnerJex will not receive any proceeds from such transactions.

See “Risk Factors” on page 11 of the Base Prospectus for certain considerations relevant to an investment in the Common Stock.

_______________________________________

NEITHER THE SECURITIES AND EXCHANGE COMMISSION NOR ANY STATE SECURITIES COMMISSION HAS APPROVED OR DISAPPROVED OF THESE SECURITIES OR DETERMINED IF THIS PROSPECTUS SUPPLEMENT OR THE PROSPECTUS IS TRUTHFUL OR COMPLETE. ANY REPRESENTATION TO THE CONTRARY IS A CRIMINAL OFFENSE.

_______________________________________

This Prospectus Supplement should be read in conjunction with, and may not be delivered or utilized without, the Prospectus dated December 24, 2008 as supplemented by the Prospectus Supplement dated January 16, 2009 (collectively, the “Prospectus”). EnerJex has agreed to indemnify the selling stockholder against certain liabilities, including liabilities under the Securities Act of 1933. Capitalized terms used in this Prospectus Supplement and not otherwise defined have the same meanings as in the Prospectus.

The date of this Prospectus Supplement is February 24, 2009.

RECENT DEVELOPMENTS

Operating Results. Attached hereto is EnerJex’s Quarterly Report on Form 10-Q for the fiscal quarter ended December 31, 2008.

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended December 31, 2008

¨ 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)

7300 W. 110th, 7th Floor
Overland Park, Kansas		66210
(Former address of principal executive offices)		(Zip 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 x No ¨

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

Large accelerated filer ¨		Accelerated filer ¨

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

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ¨ No x

The number of shares of Common Stock, $0.001 par value, outstanding on February 20, 2008 was 4,443,483 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	10
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	11
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	22
Item 4T.	Controls and Procedures	22

PART II	OTHER INFORMATION
Item 1.	Legal Proceedings	23
Item 1A.	Risk Factors	23
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	39
Item 3.	Defaults Upon Senior Securities	39
Item 4.	Submission of Matters to a Vote of Security Holders	39
Item 5.	Other Information	39
Item 6.	Exhibits	41

SIGNATURES		42

PART 1 – FINANCIAL INFORMATION

Item 1. Financial Statements

EnerJex Resources, Inc. and Subsidiaries

Condensed Consolidated Balance Sheets

	December 31, 2008			March 31, 2008
	(Unaudited)			(Audited)
Assets
Current assets:
Cash	$	188,346			$	951,004
Accounts receivable		371,915				227,055
Prepaid debt issue costs		45,928				157,191
Deferred and prepaid expenses		1,213,666				176,345
Total current assets		1,819,855				1,511,595

Fixed assets		332,619				185,299
Less: Accumulated depreciation		46,046				30,982
Total fixed assets		286,573				154,317

Other assets:
Prepaid debt issue costs		11,325				157,191
Oil and gas properties using full cost accounting:
Properties not subject to amortization		3,200				62,216
Properties subject to amortization		5,883,829				8,982,510
Total other assets		5,898,354				9,201,917
Total assets	$	8,004,782			$	10,867,829
Liabilities and Stockholders' Equity (Deficit)
Current liabilities:
Accounts payable	$	1,040,595			$	416,834
Accrued liabilities		60,640				70,461
Notes payable		-				965,000
Deferred payments from Euramerica development		-				251,951
Long term debt, current		22,815				412,930
Total current liabilities		1,124,050				2,117,176

Asset retirement obligation		775,670				459,689

Convertible note payable		25,000				25,000
Long-term debt, net of discount		9,497,848				6,831,972
Total liabilities		11,422,568				9,433,837
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 – 4,443,483 at December 31, 2008 and 4,440,651 at March 31, 2008		4,443				4,441
Paid-in capital		8,932,911				8,853,457
Retained (deficit)		(12,355,140	)			(7,423,906	)
Total stockholders’ equity (deficit)		(3,417,786	)			1,433,992

Total liabilities and stockholders’ equity	$	8,004,782			$	10,867,829

See Notes to Condensed Consolidated Financial Statements.

EnerJex Resources, Inc. and Subsidiaries

Condensed Consolidated Statements of Operations

	For the Three Months Ended						For the Nine Months Ended
	December 31,						December 31,
	2008			2007			2008			2007

Revenue
Oil and gas activities	$	1,184,547		$	1,498,202		$	4,652,289		$	1,982,119

Expenses:
Direct operating costs		562,693			722,540			2,093,994			1,104,272
Depreciation, depletion and amortization		277,020			387,408			995,069			532,665
Impairment of oil and gas properties		4,777,723			-			4,777,723			-
Professional fees		106,032			100,770			400,816			1,112,832
Salaries		200,547			212,088			694,973			1,416,150
Administrative expense		227,150			227,025			808,180			506,547
Total expenses		6,151,165			1,649,831			9,770,755			4,672,466

Loss from operations		(4,966,618	)		(151,629	)		(5,118,466	)		(2,690,347	)

Other income (expense):
Interest expense		(205,327	)		(224,273	)		(743,372	)		(507,640	)
Loan fee expense		(11,576	)		(39,298	)		(257,128	)		(113,155	)
Loan interest accretion		(119,512	)		(304,317	)		(2,686,892	)		(766,800	)
Gain on liquidation of hedging instrument		3,879,050			-			3,879,050			-
Loss on sale of vehicle		-			-			(4,421	)		-

Total other income (expense)		3,542,635			(567,888	)		187,237			(1,387,595	)


Net income (loss)	$	(1,423,983	)	$	(719,517	)	$	(4,931,229	)	$	(4,077,942	)

Weighted average number of
common shares outstanding - basic		4,443,483			4,440,651			4,442,467			4,138,338

Net income (loss) per share - basic	$	(0.32	)	$	(0.16	)	$	(1.11	)	$	(0.99	)

See Notes to Condensed Consolidated Financial Statements.

EnerJex Resources, Inc. and Subsidiaries

Condensed Consolidated Statements of Cash Flows

	For the Nine Months Ended
	December 31,
	2008			2007
Cash flows (used in) / provided from operating activities

Net (loss)	$	(4,931,229	)	$	(4,077,942	)
Impairment of oil and gas properties		4,777,723			-
Depreciation, depletion and amortization		1,034,013			532,665
Accretion of asset retirement obligation		46,928			13,567
Stock, warrants and options issued for services		79,455			1,862,795
Loan costs and accretion of interest		2,832,758			879,955
Adjustments to reconcile net (loss) to cash
used in operating activities:
Accounts and notes receivable		(144,860	)		(362,871	)
Prepaid expenses		(926,058	)		(4,124	)
Accounts payable		623,761			322,456
Accrued liabilities		(9,821	)		31,091
Deferred payments from Euramerica for development		(251,951	)		51,925
Net cash (used in) / provided from operating activities		3,130,719			(750,483	)

Cash flows (used in) / provided from investing activities
Purchase of fixed assets		(171,200	)		(113,575	)
Additions to oil and gas properties		(2,346,041	)		(8,936,628	)
Net cash (used in) / provided from investing activities		(2,517,241	)		(9,050,203	)

Cash flows (used in) / provided from financing activities
Proceeds from sale of common stock		-			4,313,757
Notes payable, net		(965,000	)		-
Payments received on notes receivable		-			23,100
Proceeds from long term debt		11,274,842			6,765,141
Payments on notes payable		(11,685,978	)		(443,328	)
Net cash (used in) / provided from financing activities		(1,376,136	)		10,658,670

Net increase (decrease) in cash		(762,658	)		857,984
Cash - beginning		951,004			99,493
Cash - ending	$	188,346		$	957,477

Supplemental disclosures:
Interest paid	$	688,602		$	75,935
Income taxes paid		-			-

Non-cash transactions
Stock, warrants and options issued for services	$	79,455		$	1,862,795
Asset retirement obligation		776,906			352,000
Loan costs		2,944,020			879,955
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, 2008.

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 - Common Stock

Effective July 25, 2008, we implemented a one-for-five reverse stock split of our issued and outstanding common stock. The number of authorized shares of common stock and preferred stock was not affected and remains at 100,000,000 and 10,000,000, respectively, but the number of shares of common stock outstanding was reduced from 22,214,166 to 4,443,467. An additional 634 shares were issued in lieu of issuing fractional shares. The aggregate par value of the issued common stock was reduced by reclassifying a portion of the par value amount of the outstanding common shares from common stock to additional paid-in capital for all periods presented. In addition, all per share and share amounts, including stock options and warrants have been retroactively restated in the accompanying consolidated financial statements and notes to consolidated financial statements for all periods presented to reflect the reverse stock split.

Stock transactions in fiscal 2009:

On May 15, 2008, we issued 2,182 shares of common stock to a Director and chairman of our Audit Committee for services. For the nine month period ended December 31, 2008, we recorded director compensation in the amount of $13,000.

Option and Warrant transactions in fiscal 2009:

On July 2, 2008, we granted 122,000 options to purchase shares of our common stock to our non-employee directors as compensation for their service as directors in fiscal 2009. On August 1, 2008, we granted C. Stephen Cochennet, our chief executive officer, an option to purchase 75,000 shares of our common stock at 6.25 per share and we granted Dierdre P. Jones, our chief financial officer, an option to purchase 40,000 shares of our common stock at $6.25 per share. These options were rescinded in November 2008 at the request of the board’s compensation committee and the approval of each option holder. Shares subject to these options were returned to the plan and are available for future issuance.

A summary of stock options and warrants is as follows:

	Options			Weighted Ave. Exercise Price			Warrants		Weighted Ave. Exercise Price
Outstanding March 31, 2008		458,500		$	6.30			75,000	$	3.00
Cancelled		(4,170	)	$	(6.25	)		-		-
Exercised		-			-			-		-
Outstanding December 31, 2008		454,330		$	6.30			75,000	$	3.00

Note 3 - Asset Retirement Obligation

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, 2008	$	459,689
Liabilities incurred during the period		269,053
Liabilities settled during the period		-
Accretion		46,928
Asset retirement obligations, December 31, 2008	$	775,670

Note 4 - Long-Term Debt

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.

The Debentures have a three-year term, maturing on March 31, 2010, and bear interest at a rate equal to 10% per annum. Interest is payable quarterly in arrears on the first day of each succeeding quarter. We may pay interest in either cash or registered shares of our common stock. The Debentures 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.

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 for each item. 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, 2008 was $2,686,892 and for the nine month period ended December 31, 2007 was $766,800. Of the $2,686,892 interest accreted during the period ended December 31, 2008, $2,112,267 relates to the redemption of $6.3 million of the Debentures. The remaining amount of interest to accrete in future periods is $723,310 as of December 31, 2008.

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, 2008 was $257,128. Of this amount, $195,559 was expensed upon the redemption of $6.3 million of the Debentures. The remaining debt issue costs will be expensed in the following fiscal years: March 31, 2009 - $45,928 and March 31, 2010 - $11,325.

Effective July 7, 2008, we redeemed an aggregate principal amount of $6.3 million of the Debentures and amended the $2.7 million of aggregate principal amount of the remaining Debentures to, among other things, permit the indebtedness under our new Credit Facility, subordinate the security interests of the debentures to the new 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.

Pursuant to the terms of the Registration Rights Agreement, as amended, between us and one of the Buyers, we were obligated to register 1,000,000 of the shares issued under the Financing Agreements. These shares were registered effective December 24, 2008.

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 first redetermination commenced October 1, 2008. The initial borrowing base was set at $10.75 million and was reduced to $7.428 million following the liquidation of the BP hedging instrument. The borrowing base is currently under review by Texas Capital Bank. 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 $7.428 million of our available borrowing base as of December 31, 2008.

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 new 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. 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 extensionon. We may select Eurodollar loans of one, two, three and six months. 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, 2008.

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. We were able to obtain a waiver of default from Texas Capital Bank on these two technical covenants at September 30, 2008 and believe we are in compliance with these covenants at December 31, 2008. 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 $3.3 million with proceeds from liquidating in November of 2008 a costless collar we entered into on July 3, 2008 and the reduction of our operating and general expenses.

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.

We financed the purchase of vehicles through a bank. The notes are for seven years and the weighted average interest is 6.99% per annum. Vehicles collateralize these notes.

Long-term debt consists of the following at December 31, 2008

Long-term debentures	$	2,700,000
Unaccreted discount		(723,311	)
Net long-term debentures		1,976,689
Credit Facility		7,428,000
Vehicle notes payable		115,974
Total long-term debt		9,520,663
Less current portion		22,815
Long-term debt	$	9,497,848

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 5 - 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. We have until June 1, 2009 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.

In August of 2007, we entered into a development agreement with Euramerica Energy, Inc., or Euramerica, to further the development and expansion of the Gas City Project, which included 6,600 acres, whereby Euramerica contributed $524,000 in capital toward the project. Euramerica was granted an option to purchase this project for $1.2 million with a requirement to invest an additional $2.0 million for project development by August 31, 2008. We are the operator of the project at a cost plus 17.5% basis. We have received $600,000 of the $1.2 million purchase price and $500,000 of the $2.0 million development funds.

On October 15, 2008, we again amended the agreement with Euramerica for the purchase of the Gas City Project to include the following material changes to the Euramerica agreement, as amended, extended and supplemented:

Euramerica was granted an extension until January 15, 2009 (with no further grace periods) to pay the remaining $600,000 of the purchase price for its option to purchase an approximately 6,600 acre portion of the Gas City Project and $1.5 million in previously due development funds for the Gas City Project;

If Euramerica fails to fully fund both the purchase price and these development funds by January 15, 2009, Euramerica will lose all rights to the Gas City Project and assets and there will be no payout from the revenue of the wells on this project;

The oil zones and production from such oil zones in two oil wells (which approximated 8 barrels of oil per day of gross production for the month of December 2008) are now 100% owned by EnerJex;

We may deduct from the development funds all amounts owed to us prior to applying the funds to any actual development;

Euramerica specifically recognized that we can shut in or stop the development of the project if the project is not producing in paying quantities or if the project is operating at a loss. The decision to shut in the project and cease all operations was made on October 15, 2008; and

If Euramerica funds the remaining portion of the purchase price for its option and the development funds in the Gas City Project on or before January 15, 2009, “Payout” as used in the Assignment and other documents is now based on “drilling and completion costs on a well-by-well basis.”

Subsequently, Euramerica failed to fully fund by January 15, 2009 both the balance of the purchase price and the remaining development capital owed under the Amended and Restated Well Development Agreement and Option for “Gas City Property” between us and Euramerica. Therefore, Euramerica has forfeited all of its interest in the property, including all interests in any wells, improvements or assets, and all of Euramerica's interest in the property reverts back to us. In addition, all operating agreements between us and Euramerica relating to the Gas City Project are null and void. See Note 7.

We recorded a non-cash impairment of $4,777,723 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.

Note 6 - Commitments and Contingencies

On March 6, 2008, we entered into an agreement with Shell Trading US Company (Shell) whereby we agreed to an 18-month fixed-price delivery contract with Shell for 130 BOPD at a fixed price per barrel of $96.90, less transportation costs. This contract is for the physical delivery of oil under our normal sales. This represented approximately 60% of our total oil production on a net revenue basis at that time. In addition, we agreed to sell all of our remaining oil production at current spot market pricing beginning April 1, 2008 through September 30, 2009 to Shell.

As of July 3, 2008, we entered into an ISDA master agreement and a costless collar with BP Corporation North America Inc. (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 have reduced the debt outstanding under our Credit Facility by approximately $3.3 million and used the remainder for general operating purposes. In February 2009, we entered into a fixed price swap transaction with BP for $57.30 per barrel for the period of October 1, 2009 until December 31, 2013. From October 1, 2009 through December 31, 2010-3,000 gross barrels per month; January 1, 2011 through December 31, 2011-2,750 gross barrels per month; Januray 1, 2012 through December 31, 2012-2,500 gross barrels per month; January 1, 2013 through December 31, 2013-1,000 gross barrels per month. See Note 7.

On August 1, 2008, we entered into three year employment agreements with C. Stephen Cochennet, our chief executive officer, and Dierdre P. Jones, our chief financial officer. Our future commitments under these agreements are as follows:

Base Salary

Year	Cochennet		Jones*
2009	$	200,000	$	140,000
2010		200,000		140,000
2011		200,000		140,000
Total	$	600,000	$	420,000

* Jones’ base salary to adjust annually by not less than the year-over-year increase in the U.S. Consumer Price Index.

On August 8, 2008, we entered into a five year lease for corporate office space beginning September 1, 2008 at a monthly base rent of $5,858.

Note 7 - Subsequent Events

Euramerica failed to fully fund by January 15, 2009 both the balance of the purchase price and the remaining development capital owed under the Amended and Restated Well Development Agreement and Option for “Gas City Property” between us and Euramerica. Therefore, Euramerica has forfeited all of its interest in the property, including all interests in any wells, improvements or assets, and all of Euramerica's interest in the property reverts back to us. In addition, all operating agreements between us and Euramerica relating to the Gas City Project are null and void.

On February 17, 2009, we entered into a fixed price swap transaction under the terms of our ISDA master agreement with BP for a total of 120,000 gross barrels at a price of $57.30 per barrel for the period beginning October 1, 2009 and ending on December 31, 2013. From October 1, 2009 through December 31, 2010-3,000 gross barrels per month; January 1, 2011 through December 31, 2011-2,750 gross barrels per month; Januray 1, 2012 through December 31, 2012-2,500 gross barrels per month; January 1, 2013 through December 31, 2013-1,000 gross barrels per month.

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,” “should” or “will” 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, 2008.

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.

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, we 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.

During fiscal 2008 and the first nine months of fiscal 2009, we deployed approximately $12 million in capital resources to acquire and develop five operating projects and drill 177 new wells (109 producing wells, 65 water injection wells, and 3 dry holes). For the month of December 2008, our production was approximately 243 gross barrels of oil per day (BOPD).

We are continually evaluating oil and natural gas opportunities in Eastern Kansas and are also in various stages of discussions with potential joint venture (“JV”) partners who would contribute capital to develop leases we currently own or would acquire for the JV. This economic strategy will 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.

We began generating revenues from the sale of oil during the fiscal year ended March 31, 2008. Subject to availability of capital, we expect our production to continue to increase, both through development of wells and through our acquisition strategy. Our future financial results will continue to depend on: (i) our ability to source and screen potential projects; (ii) our ability to discover commercial quantities of natural gas and oil; (iii) the market price for oil and natural gas; and (iv) our ability to fully implement our exploration, work-over and development program, which is in part dependent on the availability of capital resources. 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. The board of directors has implemented a crude oil and natural gas hedging strategy that will allow management to hedge up to 80% of our net production to mitigate a majority of our exposure to changing oil prices in the intermediate term.

Material Developments

Texas Capital Credit Facility

On July 3, 2008, we entered into a new three-year $50 million Senior Secured Credit Facility with Texas Capital Bank, N. A. with an initial borrowing base of $10.75 million based on our current proved oil and natural gas reserves. We used our initial borrowing under this facility of $10.75 million to redeem an aggregate principal amount of $6.3 million of our 10% debentures, assign approximately $2.0 million of our existing indebtedness with another bank to this facility, repay $965,000 of seller-financed notes, pay the transaction costs, fees and expenses of this new facility and expand our current development projects. We have reduced principal of approximately $3.3 million with proceeds from liquidating a costless collar in November 2008. We have borrowed all $7.428 million of our available borrowing base as of December 31, 2008.

BP ISDA

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 have reduced the debt outstanding under our Credit Facility by approximately $3.3 million and used the remainder for general operating purposes.

In February 2009, we entered into a fixed price swap transaction under the terms of this BP ISDA for a total of 120,000 gross barrels at a price of $57.30 per barrel for the period beginning October 1, 2009 and ending on December 31, 2013.

Debenture Amendment

On July 7, 2008, we amended the $2.7 million of aggregate principal amount of our 10% debentures that remain outstanding to, among other things, permit the indebtedness under our new Credit Facility, subordinate the security interests of the debentures to the new 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.

Employment Agreements

On August 1, 2008, we executed three-year employment agreements with C. Stephen Cochennet, our chief executive officer, and Dierdre P. Jones, our chief financial officer. Mr. Cochennet and Ms. Jones have agreed to amend their employment agreements to reflect options rescinded in November 2008. See Note 2 to our Condensed Consolidated Financial Statements in this report.

Euramerica Amendments

On September 15, 2008, we entered into an amendment to the Amended and Restated Well Development Agreement and Option for "Gas City Property" with Euramerica Energy Inc., or Euramerica. The Amendment extended the date on which Euramerica must make its third and fourth quarterly installment payments of the purchase price for the purchase of its interest in our Gas City Project until October 15, 2008. The amendment also extended the date on which Euramerica must fund the remaining $1.5 million in development funds for the Gas City Project until November 15, 2008.

On October 15, 2008, we again amended the agreement with Euramerica for the purchase of the Gas City Project to include the following:

If Euramerica fails to fully fund both this purchase price and these development funds by January 15, 2009, Euramerica will lose all rights to the Gas City Project and assets and there will be no payout from the revenue of the wells on this project;

The oil zones and production from such oil zones in two oil wells (which approximated 8 barrels of oil per day of gross production for the month of December 2008) are now 100% owned by EnerJex;

We may deduct from the development funds all amounts owed to us prior to applying the funds to any actual development;

If Euramerica funds the remaining portion of the purchase price for its option and the development funds in the Gas City Project on or before January 15, 2009, “Payout” as used in the Assignment and other documents will be based on “drilling and completion costs on a well-by-well basis.”

Results of Operations for the Three Months and Nine Months Ended December 31, 2008 and 2007 compared.

Income:

	Three Months Ended				Increase /			Nine Months Ended				Increase /
	December 31,				(Decrease)			December 31,				(Decrease)
	2008		2007		$			2008		2007		$
Oil and natural gas revenues	$	1,184,547	$	1,498,202	$	(313,655	)	$	4,652,289	$	1,982,119	$	2,670,170

Revenues

Oil and natural gas revenues for the three months ended December 31, 2008 were $1,184,547 compared to revenues of $1,498,202 in the three months ended December 31, 2007. The decrease in the three month revenues is due to the low price of oil and natural gas during the quarter ended December 31, 2008 as compared to December 31, 2007 despite higher sales volumes. Oil and natural gas revenues for the nine months ended December 31, 2008 were $4,652,289 and $1,982,119 in the nine months ended December 31, 2007. The increase in the nine month revenues is due to both higher average oil prices and sales volumes in the current year over the prior year. The average price per barrel of oil, net of transportation costs, sold during the three months ended December 31, 2008 was $71.91 compared to $83.89 during the three months ended December 31, 2007 and was $89.97 for the nine months ended December 31, 2008 compared to $77.97 for the nine months ended December 31, 2007. The average price per Mcf for natural gas sales during the three months ended December 31, 2008 was $3.71, compared to $5.61 during the three months ended December 31, 2007 and was $7.34 for the nine months ended December 31, 2008 compared to $4.99 for the nine months ended December 31, 2007.

Expenses:

	Three Months Ended						Increase /			Nine Months Ended						Increase /
	December 31,						(Decrease)			December 31,						(Decrease)
	2008			2007			$			2008			2007			$
Production expenses:
Direct operating costs	$	562,693		$	722,540		$	(159,847	)	$	2,093,994		$	1,104,272		$	989,722
Depreciation, depletion and amortization		277,020			387,408			(110,388	)		995,069			532,665			462,404
Impairment of oil and gas properties		4,777,723			-			4,777,723			4,777,723			-			4,777,723
Total production expenses		5,617,436			1,109,948			4,507,488			7,866,786			1,636,937			6,229,849

General expenses:
Professional fees		106,032			100,770			5,262			400,816			1,112,832			(712,016	)
Salaries		200,547			212,088			(11,541	)		694,973			1,416,150			(721,177	)
Administrative expense		227,150			227,025			125			808,180			506,547			301,633
Total general expenses		533,729			539,883			(6,154	)		1,903,969			3,035,529			(1,131,560	)
Total production and general expenses		6,151,165			1,649,831			3,576,249			9,770,755			4,672,466			5,098,289

Other income (expense)
Interest expense		(205,327	)		(224,273	)		(18,946	)		(743,372	)		(507,640	)		235,732
Loan fee expense		(11,576	)		(39,298	)		(27,722	)		(257,128	)		(113,155	)		143,973
Loan interest accretion		(119,512	)		(304,317	)		(184,805	)		(2,686,892	)		(766,800	)		1,920,092
Gain on liquidation of hedging instrument		3,879,050			-			(3,879,050	)		3,879,050			-			(3,879,050	)
Loss on Sale of Vehicle		-			-			-			(4,421	)		-			4,421
Total other income (expense)		3,542,635			(567,888	)		4,110,523			187,237			(1,387,595	)		(1,574,832	)

Net income (loss)	$	(1,423,983	)	$	(719,517	)	$	704,466		$	(4,931,229	)		(4,077,942	)	$	853,287

Direct Operating Costs

Direct operating costs for the three months ended December 31, 2008 were $562,693 compared to $722,540 for the three months ended December 31, 2007 and $2,093,994 compared to $1,104,272 for each of the nine months ended December 31, 2008 and 2007, respectively. The decrease in the current three month period over the prior three month period 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, 2008 was $277,020 and $995,069, respectively, compared to $387,408 and $532,665 for the three and nine months ended December 31, 2007. During the quarter ended December 31, 2008, we recorded an impairment to our oil and gas properties based upon changes in our reserve estimates. The calculation of DD&A for the three and nine months ended December 31, 2008 is based on these updated estimates. The decrease in the three months ended December 31, 2008 over the three months ended December 31, 2007 is primarily attributable to the reduced amortizable base. The increase in the nine months ended December 31, 2008 over the nine months ended December 31, 2007 results from more properties included in the amortizable base which were acquired in September 2007.

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.

As previously announced, in December 2008, the Securities and Exchange Commission (“SEC”) issued new regulations for oil and gas reserve reporting which go into effect effective for fiscal years ending on or after December 31, 2009. One of the key elements of the new regulations relate to the commodity prices which are used to calculate reserves and their present value. The new regulations provide for disclosure of oil and gas reserves evaluated using annual average prices based on the prices in effect on the first day of each month rather than the current regulations which utilize commodity prices on the last day of the year. If the new regulations had been in effect at December 31, 2008, EnerJex would not have recorded a ceiling test impairment. Prior to the new regulations taking effect, if commodity prices continue to decline during 2009, we may be subject to further ceiling-test impairments. Without the effect of the above items, our net loss for the nine months ended December 31, 2008 would have been $254,679. The ceiling test impairment charge is a non-cash item.

Professional Fees

Professional fees for the three months ended December 31, 2008 were $106,032 compared to $100,770 for the three months ended December 31, 2007, reflecting little change. This compares to professional fees of $400,816 for the nine months ended December 31, 2008 and $1,112,832 for the same period in 2007. The decrease in professional fees for the nine month ended December 31 was largely the result of $773,659 in non-cash equity-based payments made by issuing stock options to directors and an outside consultant in the prior year.

Salaries

Salaries for the three months ended December 31, 2008 were $200,547 compared to $212,088 for the three months ended December 31, 2007. Though there were fewer employees at December 31, 2007 versus December 31, 2008, the lower salaries were offset by $70,000 of bonuses accrued in December 2007 and paid in January 2008. Additionally, salaries for the nine month periods ended December 31, 2008 and 2007 were $694,973 and $1,416,150, respectively. Non-cash equity-based payments made by issuing stock options to our management in the prior nine months ended December 31, 2007 were $1,039,714 as compared to $0 in the current nine month period ended December 31, 2008, resulting in a decrease.

Administrative Expense

Administrative expense for the three and nine months ended December 31, 2008 were $227,150 and $808,180, compared to $227,025 in the three months ended December 31, 2007 and $506,547 in the nine months ended December 31, 2007. The administrative expense increased as a result of the addition of employees, office space, and corporate activity related to growth in operations.

Interest expense

Interest expense for the three and nine months ended December 31, 2008 was $205,327 and $743,372, whereas interest expense for the three and nine months ended December 31, 2007 was $224,273 and $507,640. Interest expense was primarily related to our debentures and our Credit Facility. See Note 4 to our Condensed Consolidated Financial Statements in this report.

Loan Costs

Loan costs for the three and nine months ended December 31, 2008 were $131,088 and $2,944,020, as compared to $343,615 and $879,955 for the three and nine months ended December 31, 2007. 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 the $6.3 of the $9.0 million debentures, accounting for the increase in the nine month period ended December 31, 2008 as compared to December 31, 2007. The lower costs in the three month period ended December 31, 2008 as compared to December 31, 2007 results from interest on a lower amount of debentures remaining outstanding at December 31, 2008, or $2.7 million.

Gain on Liquidation of Hedging Instrument

Net Income (Loss)

Net loss for the three months ended December 31, 2008 was $1,423,983 and $4,931,229 for the nine months ended December 31, 2008 as compared to a net loss of $719,517 in the three months ended December 31, 2007 and $4,077,942 in the nine months ended December 31, 2007. The gain on the liquidation of the hedging instrument accounted for $3,879,050 of income in the quarter ended December 31, 2008. Non-cash expenses such as depreciation and depletion, impairment on oil and gas properties, loan costs and accretions are significant factors contributing to the net loss in the three and nine months ended December 31, 2008. For the nine month period ended December 31, 2008, these expenses totaled over $8.7 million. These expenses do not affect our cash flows. Upon maturity or redemption of the remaining $2.7 million debentures which are outstanding at December 31, 2008, all remaining non-cash loan costs will be expensed.

Liquidity and Capital Resources

Liquidity is a measure of a company’s ability to meet potential cash requirements. We have historically met our capital requirements through debt financing, revenues from operations and the issuance of equity securities. We have been able to provide some of the necessary liquidity we need by the revenues generated from our net interests in our oil and natural gas production, and sales of reserves in our existing properties. If we do not generate sufficient sales revenues we will need to continue to finance our operations through equity and/or debt financings.

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.

We entered into a costless collar with BP beginning October 1, 2009 through March 31, 2011 to set minimum and maximum prices on a financially settled collar on a set number of barrels of oil per day. In response to the declining economic conditions which have negatively impacted our business, we liquidated this costless collar with BP and received approximately $3.9 million. We have reduced the debt outstanding under our Credit Facility by approximately $3.3 million and used the remainder for general operating purposes. We have also utilized a price swap contracts with Shell and BP for a portion of our production through December 2013, and agreed to sell Shell the remainder of our current oil production at current spot market pricing, beginning April 1, 2008 through September of 2009. The key risks associated with these contracts are summarized in “Item 1A. Risk Factors”.

The following table summarizes total current assets, total current liabilities and working capital at December 31, 2008 as compared to March 31, 2008.

	December 31,		March 31,			Increase / (Decrease)
	2008		2008			$

Current Assets	$	1,819,855	$	1,511,595			308,260

Current Liabilities	$	1,124,050	$	2,117,176			(993,126	)

Working Capital (deficit)	$	695,805	$	(605,581	)		1,301,386

New 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 first redetermination commenced October 1, 2008. The initial borrowing base was set at $10.75 million and was reduced to $7.428 million following the liquidation of the BP hedging instrument in November 2008. The borrowing base is currently under review by Texas Capital Bank. 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 $7.428 million of our available borrowing base as of December 31, 2008.

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 minimum current assets to current liabilities ratio, a minimum ratio of EBITDA (earnings before interest, taxes, depreciation and amortization) to interest expense, and to maintain a minimum ratio of EBITDA to senior funded debt. We were able to obtain a waiver of default from Texas Capital Bank on these two technical covenants at September 30, 2008 and are in compliance with these covenants at December 31, 2008. 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 $3.3 million with proceeds from liquidating a costless collar we entered into on July 3, 2008 and the reduction of our operating and general expenses. See Note 6 to our Condensed Consolidated Financial Statements in this report.

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.

The debentures mature on March 31, 2010, absent earlier redemption by us, and carry an interest rate of 10%. Interest on the debentures began accruing on April 11, 2007 and is payable quarterly in arrears on the first day of each succeeding quarter during the term of the debentures, beginning on or about May 11, 2007 and ending on the maturity date of March 31, 2010. We may, under certain conditions specified in the debentures, pay interest payments in shares of our registered common stock. Additionally, on the maturity date, we are required to pay the amount equal to the principal, as well as all accrued but unpaid interest.

In connection with the Credit Facility, we entered into an agreement amending the Securities Purchase Agreement, Registration Rights Agreement, the Pledge and Security Agreement and the Senior Secured Debentures issued on June 21, 2007 (the “Debenture Agreements”), with the holders (the “Buyers”) of the debentures issued on June 21, 2007 (the “June Debentures”). Pursuant to this agreement, we, among other things, (i) redeemed the April Debentures, (ii) agreed to use the net proceeds from our next debt or equity offering to redeem the June Debentures, (iii) agreed to update the registration statement to sell our common stock owned by one of the Buyers, (iv) amended certain terms of the Debenture Agreements in recognition of the indebtedness under the new Credit Facility, and (v) amended the Securities Purchase Agreement and Registration Rights Agreement to remove the covenant to issue and register additional shares of common stock in the event that our oil production does not meet certain thresholds over time.

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. While our operations are generating sufficient cash revenues to meet our monthly expenses, we have limited working capital. In the event we cannot obtain additional capital to pursue our strategic plan, our ability to continue our growth would be materially impacted. There is no assurance we will be able to obtain such financing on commercially reasonable terms, if at all.

Subject to availability of capital, we intend to implement and execute our business and marketing strategy, continue to develop and upgrade technology and products, respond to competitive developments, and attract, retain and motivate qualified personnel. There can be no assurance that we will be successful in addressing such risks, and the 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 until such time as we can raise adequate working capital to sustain our operations.

Expected purchase or sale of any significant equipment

Subject to availability of capital, 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, 2008, we had 15 full time employees, an increase from 9 full time employees at our fiscal year ended March 31, 2008. We hired a number of former independent field contractors to help secure a more stable work base. In November 2008, we reduced personnel levels by 4 full time employees and 1 independent contractor 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 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.

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.

We review the carrying value of our gas and oil properties under the full-cost accounting rules of the SEC on a quarterly basis. This quarterly review is referred to as a ceiling test. Under the ceiling test, capitalized costs, less accumulated amortization and related deferred income taxes, may not exceed an amount equal to the sum of the present value of estimated future net revenues (adjusted for cash flow hedges) less estimated future expenditures to be incurred in developing and producing the proved reserves, less any related income tax effects. In calculating future net revenues, current 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.

All reserve estimates are prepared based upon a review of production histories and other geologic, economic, ownership and engineering data.

Asset Retirement Obligations:

The asset retirement obligation relates to the plug and abandonment costs when our wells are no longer useful. We determine the value of the liability by obtaining quotes for this service and estimate the increase we will face in the future. We then discount the future value based on an intrinsic interest rate that is appropriate for us. If costs rise more than what we have expected there could be additional charges in the future, however, we monitor the costs of the abandoned wells and we will adjust this liability if necessary.

Share-Based Payments:

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

Recent Accounting Pronouncements

In May 2008, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 163, “Accounting for Financial Guarantee Insurance Contracts – An interpretation of FASB Statement No. 60”. SFAS No. 163 requires that an insurance enterprise recognize a claim liability prior to an event of default when there is evidence that credit deterioration has occurred in an insured financial obligation. It also clarifies how Statement 60 applies to financial guarantee insurance contracts, including the recognition and measurement to be used to account for premium revenue and claim liabilities, and requires expanded disclosures about financial guarantee insurance contracts. It is effective for financial statements issued for fiscal years beginning after December 15, 2008, except for some disclosures about the insurance enterprise’s risk-management activities. SFAS No. 163 requires that disclosures about the risk-management activities of the insurance enterprise be effective for the first period beginning after issuance. Except for those disclosures, earlier application is not permitted. The adoption of this statement is not expected to have a material effect on the Company’s financial statements.

In May 2008, the FASB issued SFAS No. 162, “The Hierarchy of Generally Accepted Accounting Principles”. SFAS No. 162 identifies the sources of accounting principles and the framework for selecting the principles to be used in the preparation of financial statements of nongovernmental entities that are presented in conformity with generally accepted accounting principles in the United States. It is effective 60 days following the SEC’s approval of the Public Company Accounting Oversight Board amendments to AU Section 411, “The Meaning of Present Fairly in Conformity With Generally Accepted Accounting Principles”. The adoption of this statement is not expected to have a material effect on the Company’s financial statements.

In March 2008, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities – an amendment to FASB Statement No. 133”. SFAS No. 161 is intended to improve financial standards for derivative instruments and hedging activities by requiring enhanced disclosures to enable investors to better understand their effects on an entity's financial position, financial performance, and cash flows. Entities are required to provide enhanced disclosures about: (a) how and why an entity uses derivative instruments; (b) how derivative instruments and related hedged items are accounted for under Statement 133 and its related interpretations; and (c) how derivative instruments and related hedged items affect an entity’s financial position, financial performance, and cash flows. It is effective for financial statements issued for fiscal years beginning after November 15, 2008, with early adoption encouraged. The Company is currently evaluating the impact of SFAS No. 161 on its financial statements, and the adoption of this statement is not expected to have a material effect on the Company’s financial statements.

In December 2007, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 141 (revised 2007), “Business Combinations”. This statement replaces SFAS No. 141 and defines the acquirer in a business combination as the entity that obtains control of one or more businesses in a business combination and establishes the acquisition date as the date that the acquirer achieves control. SFAS 141 (revised 2007) requires an acquirer to recognize the assets acquired, the liabilities assumed, and any non-controlling interest in the acquired at the acquisition date, measured at their fair values as of that date. SFAS 141 (revised 2007) also requires the acquirer to recognize contingent consideration at the acquisition date, measured at its fair value at that date. This statement is effective for fiscal years, and interim periods within those fiscal years, beginning on or after December 15, 2008. Earlier adoption is prohibited. The adoption of this statement is not expected to have a material effect on the Company's financial statements.

In December 2007, the FASB issued SFAS No. 160, “Non-controlling Interests in Consolidated Financial Statements Liabilities –an Amendment of ARB No. 51”. This statement amends ARB 51 to establish accounting and reporting standards for the Non-controlling interest in a subsidiary and for the deconsolidation of a subsidiary. This statement is effective for fiscal years, and interim periods within those fiscal years, beginning on or after December 15, 2008. Earlier adoption is prohibited. The adoption of this statement is not expected to have a material effect on the Company's 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 have recently been impacted by such material reductions in oil prices that we have significantly cut back our drilling and completion activities and have lowered our operating expenses by reducing personnel levels, use of contractors, and eliminating all reasonable and feasible discretionary expenses. We anticipate we will continue to operate in this fashion in the near term.

Item 3. Quantitative and Qualitative Disclosures About Market Risk.

Not applicable.

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.

Risks Associated with Our Business

Declining economic conditions could negatively impact our business

Our operations are affected by local, national and worldwide economic conditions. Markets in the United States and elsewhere have been experiencing extreme volatility and disruption for more than 12 months, due in part to the financial stresses affecting the liquidity of the banking system and the financial markets generally. In recent weeks, this volatility and disruption has reached unprecedented levels. The consequences of a potential or prolonged recession may include a lower level of economic activity and uncertainty regarding energy prices and the capital and commodity markets. While the ultimate outcome and impact of the current economic conditions cannot be predicted, a lower level of economic activity might result in a decline in energy consumption, which may adversely affect the price of oil, our revenues, liquidity and future growth. Instability in the financial markets, as a result of recession or otherwise, also may affect the cost of capital and our ability to raise capital.

We have sustained losses, which raises doubt as to our ability to successfully develop profitable business operations.

Our prospects must be considered in light of the risks, expenses and difficulties frequently encountered in establishing and maintaining a business in the oil and natural gas industries. There is nothing conclusive at this time on which to base an assumption that our business operations will prove to be successful or that we will be able to operate profitably. Our future operating results will depend on many factors, including:

the future prices of natural gas and oil;

our ability to raise adequate working capital;

success of our development and exploration efforts;

demand for natural gas and oil;

the level of our competition;

our ability to attract and maintain key management, employees and operators;

transportation and processing fees on our facilities;

fuel conservation measures;

alternate fuel requirements;

government regulation and taxation;

technical advances in fuel economy and energy generation devices; and

our ability to efficiently explore, develop and produce sufficient quantities of marketable natural gas or oil in a highly competitive and speculative environment while maintaining quality and controlling costs.

To achieve profitable operations, we must, alone or with others, successfully execute on the factors stated above, along with continually developing ways to enhance our production efforts. Despite our best efforts, we may not be successful in our development efforts or obtain required regulatory approvals. There is a possibility that some of our wells may never produce natural gas or oil in sustainable or economic quantities.

We will need additional capital in the future to finance our planned growth, which we may not be able to raise or may only be available on terms unfavorable to us or our stockholders, which may result in our inability to fund our working capital requirements and harm our operational results.

We have and expect to continue to have substantial capital expenditure and working capital needs. We will need to rely on cash flow from operations and borrowings under our Credit Facility or raise additional cash to fund our operations, pay outstanding long-term debt, fund our anticipated reserve replacement needs and implement our growth strategy, or respond to competitive pressures and/or perceived opportunities, such as investment, acquisition, exploration, work-over and development activities.

If low natural gas and oil prices, operating difficulties or other factors, many of which are beyond our control, cause our revenues or cash flows from operations to decrease, we may be limited in our ability to spend the capital necessary to complete our development, production exploitation and exploration programs. If our resources or cash flows do not satisfy our operational needs, we will require additional financing, in addition to anticipated cash generated from our operations, to fund our planned growth. Additional financing might not be available on terms favorable to us, or at all. If adequate funds were not available or were not available on acceptable terms, our ability to fund our operations, take advantage of unanticipated opportunities, develop or enhance our business or otherwise respond to competitive pressures would be significantly limited. In such a capital restricted situation, we may curtail our acquisition, drilling, development, and exploration activities or be forced to sell some of our assets on an untimely or unfavorable basis. Our current plans to address lower crude and natural gas prices are primarily to reduce both capital and operating expenditures to a level equal to or below cash flow from operations. However, our plans may not be successful in improving our results of operations and liquidity.

If we raise additional funds through the issuance of equity or convertible debt securities, the percentage ownership of our stockholders would be reduced, and these newly issued securities might have rights, preferences or privileges senior to those of existing stockholders.

Natural gas and oil prices are volatile. This volatility may occur in the future, causing negative change in cash flows which may result in our inability to cover our operating or capital expenditures.

Our future revenues, profitability, future growth and the carrying value of our properties is anticipated to depend substantially on the prices we may realize for our natural gas and oil production. Our realized prices may also affect the amount of cash flow available for operating or capital expenditures and our ability to borrow and raise additional capital.

Natural gas and oil prices are subject to wide fluctuations in response to relatively minor changes in or perceptions regarding supply and demand. Historically, the markets for natural gas and oil have been volatile, and they are likely to continue to be volatile in the future. Among the factors that can cause this volatility are:

local, national and worldwide economic conditions;

worldwide or regional demand for energy, which is affected by economic conditions;

the domestic and foreign supply of natural gas and oil;

weather conditions;

natural disasters;

acts of terrorism;

domestic and foreign governmental regulations and taxation;

political and economic conditions in oil and natural gas producing countries, including those in the Middle East and South America;

impact of the U.S. dollar exchange rates on oil and natural gas prices;

the availability of refining capacity;

actions of the Organization of Petroleum Exporting Countries, or OPEC, and other state controlled oil companies relating to oil price and production controls; and

the price and availability of other fuels.

It is impossible to predict natural gas and oil price movements with certainty. Lower natural gas and oil prices may not only decrease our future revenues on a per unit basis but also may reduce the amount of natural gas and oil that we can produce economically. A substantial or extended decline in natural gas and oil prices may materially and adversely affect our future business enough to force us to cease our business operations. In addition, our reserves, financial condition, results of operations, liquidity and ability to finance and execute planned capital expenditures will also suffer in such a price decline. Further, natural gas and oil prices do not necessarily move together.

Approximately 54% of our total proved reserves as of March 31, 2008 consist of undeveloped and developed non-producing reserves, and those reserves may not ultimately be developed or produced.

As of March 31, 2008, approximately 36% of our total proved reserves were undeveloped and approximately 18% were developed non-producing. We plan to develop and produce all of our proved reserves, but ultimately some of these reserves may not be developed or produced. Furthermore, not all of our undeveloped or developed non-producing reserves may be ultimately produced in the time periods we have planned, at the costs we have budgeted, or at all.

Because we face uncertainties in estimating proven recoverable reserves, you should not place undue reliance on such reserve information.

Our reserve estimates and the future net cash flows attributable to those reserves are prepared by McCune Engineering, our independent petroleum and geological engineer. There are numerous uncertainties inherent in estimating quantities of proved reserves and cash flows from such reserves, including factors beyond our control and the control of McCune Engineering. Reserve engineering is a subjective process of estimating underground accumulations of natural gas and oil that can be economically extracted, which cannot be measured in an exact manner. The accuracy of an estimate of quantities of reserves, or of cash flows attributable to these reserves, is a function of the available data, assumptions regarding future natural gas and oil prices, expenditures for future development and exploitation activities, and engineering and geological interpretation and judgment. Reserves and future cash flows may also be subject to material downward or upward revisions based upon production history, development and exploitation activities and natural gas and oil prices. Actual future production, revenue, taxes, development expenditures, operating expenses, quantities of recoverable reserves and value of cash flows from those reserves may vary significantly from the assumptions and estimates in our reserve reports. Any significant variance from these assumptions to actual figures could greatly affect our estimates of reserves, the economically recoverable quantities of natural gas and oil attributable to any particular group of properties, the classification of reserves based on risk of recovery, and estimates of the future net cash flows. In addition, reserve engineers may make different estimates of reserves and cash flows based on the same available data. The estimated quantities of proved reserves and the discounted present value of future net cash flows attributable to those reserves included in this report were prepared by McCune Engineering in accordance with rules of the Securities and Exchange Commission, or SEC, and are not intended to represent the fair market value of such reserves.

The present value of future net cash flows from our proved reserves is not necessarily the same as the current market value of our estimated reserves. We base the estimated discounted future net cash flows from our proved reserves on prices and costs. However, actual future net cash flows from our natural gas and oil properties also will be affected by factors such as:

geological conditions;

assumptions governing future oil and natural gas prices;

amount and timing of actual production;

availability of funds;

future operating and development costs;

actual prices we receive for natural gas and oil;

supply and demand for our natural gas and oil;

changes in government regulations and taxation; and

capital costs of drilling new wells.

The timing of both our production and our incurrence of expenses in connection with the development and production of our properties will affect the timing of actual future net cash flows from proved reserves, and thus their actual present value. In addition, the 10% discount factor we use when calculating discounted future net cash flows may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with our business or the natural gas and oil industry in general.

Currently, The SEC permits natural gas and oil companies, in their public filings, to disclose only proved reserves that a company has demonstrated by actual production or conclusive formation tests to be economically and legally producible under existing economic and operating conditions. These current SEC guidelines strictly prohibit us from including “probable reserves” and “possible reserves” in such filings. We also caution you that the SEC has, in the past, viewed such “probable” and “possible” reserve estimates as inherently unreliable and these estimates may be seen as misleading to investors unless the reader is an expert in the natural gas and oil industry. Unless you have such expertise, you should not place undue reliance on these estimates. Potential investors should also be aware that such “probable” and “possible” reserve estimates will not be contained in any “resale” or other registration statement filed by us that offers or sells shares on behalf of purchasers of our common stock and may have an impact on the valuation of the resale of the shares. Effective January 1, 2010, the Commission is adopting revisions to its oil and gas reporting disclosures which are intended to provide investors with a more meaningful and comprehensive understanding of oil and gas reserves, which should help investors evaluate the relative value of oil and gas companies. Except as required by applicable law, we undertake no duty to update this information and do not intend to update this information.

The differential between the New York Mercantile Exchange, or NYMEX, or other benchmark price of oil and natural gas and the wellhead price we receive could have a material adverse effect on our results of operations, financial condition and cash flows.

The prices that we receive for our oil and natural gas production sometimes trade at a discount to the relevant benchmark prices, such as NYMEX, that are used for calculating hedge positions. The difference between the benchmark price and the price we receive is called a differential. We cannot accurately predict oil and natural gas differentials. In recent years for example, production increases from competing Canadian and Rocky Mountain producers, in conjunction with limited refining and pipeline capacity from the Rocky Mountain area, have gradually widened this differential. Increases in the differential between the benchmark price for oil and natural gas and the wellhead price we receive could have a material adverse effect on our results of operations, financial condition and cash flows by decreasing the proceeds we receive for our oil and natural gas production in comparison to what we would receive if not for the differential.

The natural gas and oil business involves numerous uncertainties and operating risks that can prevent us from realizing profits and can cause substantial losses.

Our development, exploitation and exploration activities may be unsuccessful for many reasons, including weather, cost overruns, equipment shortages and mechanical difficulties. Moreover, the successful drilling of a natural gas and oil well does not ensure a profit on investment. A variety of factors, both geological and market-related, can cause a well to become uneconomical or only marginally economical. In addition to their cost, unsuccessful wells can hurt our efforts to replace reserves.

The natural gas and oil business involves a variety of operating risks, including:

unexpected operational events and/or conditions;

unusual or unexpected geological formations;

reductions in natural gas and oil prices;

limitations in the market for oil and natural gas;

adverse weather conditions;

facility or equipment malfunctions;

title problems;

natural gas and oil quality issues;

pipe, casing, cement or pipeline failures;

natural disasters;

fires, explosions, blowouts, surface cratering, pollution and other risks or accidents;

environmental hazards, such as natural gas leaks, oil spills, pipeline ruptures and discharges of toxic gases;

compliance with environmental and other governmental requirements; and

uncontrollable flows of oil, natural gas or well fluids.

If we experience any of these problems, it could affect well bores, gathering systems and processing facilities, which could adversely affect our ability to conduct operations. We could also incur substantial losses as a result of:

injury or loss of life;

severe damage to and destruction of property, natural resources and equipment;

pollution and other environmental damage;

clean-up responsibilities;

regulatory investigation and penalties;

suspension of our operations; and

repairs to resume operations.

Because we use third-party drilling contractors to drill our wells, we may not realize the full benefit of worker compensation laws in dealing with their employees. Our insurance does not protect us against all operational risks. We do not carry business interruption insurance at levels that would provide enough funds for us to continue operating without access to other funds. For some risks, we may not obtain insurance if we believe the cost of available insurance is excessive relative to the risks presented. In addition, pollution and environmental risks generally are not fully insurable. If a significant accident or other event occurs and is not fully covered by insurance, it could impact our operations enough to force us to cease our operations.

Drilling wells is speculative, often involving significant costs that may be more than our estimates, and may not result in any addition to our production or reserves. Any material inaccuracies in drilling costs, estimates or underlying assumptions will materially affect our business.

Developing and exploring for natural gas and oil involves a high degree of operational and financial risk, which precludes definitive statements as to the time required and costs involved in reaching certain objectives. The budgeted costs of drilling, completing and operating wells are often exceeded and can increase significantly when drilling costs rise due to a tightening in the supply of various types of oilfield equipment and related services. Drilling may be unsuccessful for many reasons, including geological conditions, weather, cost overruns, equipment shortages and mechanical difficulties. Moreover, the successful drilling of a natural gas or oil well does not ensure a profit on investment. Exploratory wells bear a much greater risk of loss than development wells. Substantially all of our wells drilled through December 31, 2008 have been development wells. A variety of factors, both geological and market-related, can cause a well to become uneconomical or only marginally economic. Our initial drilling and development sites, and any potential additional sites that may be developed, require significant additional exploration and development, regulatory approval and commitments of resources prior to commercial development. If our actual drilling and development costs are significantly more than our estimated costs, we may not be able to continue our business operations as proposed and would be forced to modify our plan of operation.

Development of our reserves, when established, may not occur as scheduled and the actual results may not be as anticipated. Drilling activity and access to capital may result in downward adjustments in reserves or higher than anticipated costs. Our estimates will be based on various assumptions, including assumptions over which we have control and assumptions required by the SEC relating to natural gas and oil prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. We have control over our operations that affect, among other things, acquisitions and dispositions of properties, availability of funds, use of applicable technologies, hydrocarbon recovery efficiency, drainage volume and production decline rates that are part of these estimates and assumptions and any variance in our operations that affects these items within our control may have a material effect on reserves. The process of estimating our natural gas and oil reserves is anticipated to be extremely complex, and will require significant decisions and assumptions in the evaluation of available geological, geophysical, engineering and economic data for each reservoir. Our estimates may not be reliable enough to allow us to be successful in our intended business operations. Our actual production, revenues, taxes, development expenditures and operating expenses will likely vary from those anticipated. These variances may be material.

Unless we replace our oil and natural gas reserves, our reserves and production will decline, which would adversely affect our cash flows and income.

Unless we conduct successful development, exploitation and exploration activities or acquire properties containing proved reserves, our proved reserves will decline as those reserves are produced. Producing oil and natural gas reservoirs generally are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Our future oil and natural gas reserves and production, and, therefore our cash flow and income, are highly dependent on our success in efficiently developing and exploiting our current reserves and economically finding or acquiring additional recoverable reserves. We may be unable to make such acquisitions because we are:

unable to identify attractive acquisition candidates or negotiate acceptable purchase contracts with them;

unable to obtain financing for these acquisitions on economically acceptable terms; or

outbid by competitors.

If we are unable to develop, exploit, find or acquire additional reserves to replace our current and future production, our cash flow and income will decline as production declines, until our existing properties would be incapable of sustaining commercial production.

A significant portion of our potential future reserves and our business plan depend upon secondary recovery techniques to establish production. There are significant risks associated with such techniques.

We anticipate that a significant portion of our future reserves and our business plan will be associated with secondary recovery projects that are either in the initial stage of implementation or are scheduled for implementation. We anticipate that secondary recovery will affect our reserves and our business plan, and the exact project initiation dates and, by the very nature of waterflood operations, the exact completion dates of such projects are uncertain. In addition, the reserves and our business plan associated with these secondary recovery projects, as with any reserves, are estimates only, as the success of any development project, including these waterflood projects, cannot be ascertained in advance. If we are not successful in developing a significant portion of our reserves associated with secondary recovery methods, then the project may be uneconomic or generate less cash flow and reserves than we had estimated prior to investing the capital. Risks associated with secondary recovery techniques include, but are not limited to, the following:

higher than projected operating costs;

lower-than-expected production;

longer response times;

higher costs associated with obtaining capital;

unusual or unexpected geological formations;

fluctuations in natural gas and oil prices;

regulatory changes;

shortages of equipment; and

lack of technical expertise.

If any of these risks occur, it could adversely affect our financial condition or results of operations.

Any acquisitions we complete are subject to considerable risk.

Even when we make acquisitions that we believe are good for our business, any acquisition involves potential risks, including, among other things:

the validity of our assumptions about reserves, future production, revenues and costs, including synergies;

an inability to integrate successfully the businesses we acquire;

a decrease in our liquidity by using our available cash or borrowing capacity to finance acquisitions;

a significant increase in our interest expense or financial leverage if we incur additional debt to finance acquisitions;

the assumption of unknown liabilities, losses or costs for which we are not indemnified or for which our indemnity is inadequate;

the diversion of management’s attention from other business concerns;

an inability to hire, train or retain qualified personnel to manage the acquired properties or assets;

the incurrence of other significant charges, such as impairment of goodwill or other intangible assets, asset devaluation or restructuring charges;

unforeseen difficulties encountered in operating in new geographic or geological areas; and

customer or key employee losses at the acquired businesses.

Our decision to acquire a property will depend in part on the evaluation of data obtained from production reports and engineering studies, geophysical and geological analyses and seismic and other information, the results of which are often incomplete or inconclusive.

Our reviews of acquired properties can be inherently incomplete because it is not always feasible to perform an in-depth review of the individual properties involved in each acquisition. Even a detailed review of records and properties may not necessarily reveal existing or potential problems, nor will it permit a buyer to become sufficiently familiar with the properties to assess fully their deficiencies and potential. Inspections may not always be performed on every well, and environmental problems, such as ground water contamination, plugging or orphaned well liability are not necessarily observable even when an inspection is undertaken.

We must obtain governmental permits and approvals for drilling operations, which can result in delays in our operations, be a costly and time consuming process, and result in restrictions on our operations.

Regulatory authorities exercise considerable discretion in the timing and scope of permit issuances in the region in which we operate. Compliance with the requirements imposed by these authorities can be costly and time consuming and may result in delays in the commencement or continuation of our exploration or production operations and/or fines. Regulatory or legal actions in the future may materially interfere with our operations or otherwise have a material adverse effect on us. In addition, we are often required to prepare and present to federal, state or local authorities data pertaining to the effect or impact that a proposed project may have on the environment, threatened and endangered species, and cultural and archaeological artifacts. Accordingly, the permits we need may not be issued, or if issued, may not be issued in a timely fashion, or may involve requirements that restrict our ability to conduct our operations or to do so profitably.

Due to our lack of geographic diversification, adverse developments in our operating areas would materially affect our business.

We currently only lease and operate oil and natural gas properties located in Eastern Kansas. As a result of this concentration, we may be disproportionately exposed to the impact of delays or interruptions of production from these properties caused by significant governmental regulation, transportation capacity constraints, curtailment of production, natural disasters, adverse weather conditions or other events which impact this area.

We depend on a small number of customers for all, or a substantial amount of our sales. If these customers reduce the volumes of oil and natural gas they purchase from us, our revenue and cash available for distribution will decline to the extent we are not able to find new customers for our production.

We have contracted with Shell for the sale of all of our oil through September 2009 and will likely contract for the sale of our natural gas with one, or a small number, of buyers. It is not likely that there will be a large pool of available purchasers. If a key purchaser were to reduce the volume of oil or natural gas it purchases from us, our revenue and cash available for operations will decline to the extent we are not able to find new customers to purchase our production at equivalent prices.

We are not the operator of some of our properties and we have limited control over the activities on those properties.

We are not the operator on our Black Oaks Project. We have only limited ability to influence or control the operation or future development of the Black Oaks Project or the amount of capital expenditures that we can fund with respect to it. In the case of the Black Oaks Project, our dependence on the operator, Haas Petroleum, limits our ability to influence or control the operation or future development of the project. Such limitations could materially adversely affect the realization of our targeted returns on capital related to exploration, drilling or production activities and lead to unexpected future costs.

We may suffer losses or incur liability for events for which we or the operator of a property have chosen not to obtain insurance.

Our operations are subject to hazards and risks inherent in producing and transporting natural gas and oil, such as fires, natural disasters, explosions, pipeline ruptures, spills, and acts of terrorism, all of which can result in the loss of hydrocarbons, environmental pollution, personal injury claims and other damage to our and others’ properties. As protection against operating hazards, we maintain insurance coverage against some, but not all, potential losses. In addition, pollution and environmental risks generally are not fully insurable. As a result of market conditions, existing insurance policies may not be renewed and other desirable insurance may not be available on commercially reasonable terms, if at all. The occurrence of an event that is not covered, or not fully covered, by insurance could have a material adverse effect on our business, financial condition and results of operations.

Our hedging activities could result in financial losses or could reduce our available funds or income and therefore adversely affect our financial position.

To achieve more predictable cash flow and to reduce our exposure to adverse fluctuations in the prices of oil and natural gas, we have entered into derivative arrangements from April 1, 2008 until December 31, 2013 for between 30 and 130 barrels of oil per day that could result in both realized and unrealized hedging losses. As of December 31, 2008 we had not incurred any such losses. The extent of our commodity price exposure is related largely to the effectiveness and scope of our derivative activities. For example, the derivative instruments we may utilize may be based on posted market prices, which may differ significantly from the actual crude oil, natural gas and NGL prices we realize in our operations.

Our actual future production may be significantly higher or lower than we estimate at the time we enter into derivative transactions for such period. If the actual amount is higher than we estimate, we will have greater commodity price exposure than we intended. If the actual amount is lower than the nominal amount that is subject to our derivative financial instruments, we might be forced to satisfy all or a portion of our derivative transactions without the benefit of the cash flow from our sale or purchase of the underlying physical commodity, resulting in a substantial diminution of our liquidity. As a result of these factors, our derivative activities may not be as effective as we intend in reducing the volatility of our cash flows, and in certain circumstances may actually increase the volatility of our cash flows. In addition, while we believe our existing derivative activities are with creditworthy counterparties (Shell and BP), continued deterioration in the credit markets may cause a counterparty not to perform its obligation under the applicable derivative instrument or impact their willingness to enter into future transactions with us.

Our business depends in part on gathering and transportation facilities owned by others. Any limitation in the availability of those facilities could interfere with our ability to market our oil and natural gas production and could harm our business.

The marketability of our oil and natural gas production will depend in a very large part on the availability, proximity and capacity of pipelines, oil and natural gas gathering systems and processing facilities. The amount of oil and natural gas that can be produced and sold is subject to curtailment in certain circumstances, such as pipeline interruptions due to scheduled and unscheduled maintenance, excessive pressure, physical damage or lack of available capacity on such systems. The curtailments arising from these and similar circumstances may last from a few days to several months. In many cases, we will be provided only with limited, if any, notice as to when these circumstances will arise and their duration. Any significant curtailment in gathering system or pipeline capacity could significantly reduce our ability to market our oil and natural gas production and harm our business.

The high cost of drilling rigs, equipment, supplies, personnel and other services could adversely affect our ability to execute on a timely basis our development, exploitation and exploration plans within our budget.

Shortages or an increase in cost of drilling rigs, equipment, supplies or personnel could delay or interrupt our operations, which could impact our financial condition and results of operations. Drilling activity in the geographic areas in which we conduct drilling activities may increase, which would lead to increases in associated costs, including those related to drilling rigs, equipment, supplies and personnel and the services and products of other vendors to the industry. Increased drilling activity in these areas may also decrease the availability of rigs. Although Haas Petroleum has agreed to provide up to two drilling rigs to the Black Oaks Project, we do not have any contracts for drilling rigs and drilling rigs may not be readily available when we need them. Drilling and other costs may increase further and necessary equipment and services may not be available to us at economical prices.

Our exposure to possible leasehold defects and potential title failure could materially adversely impact our ability to conduct drilling operations.

We obtain the right and access to properties for drilling by obtaining oil and natural gas leases either directly from the hydrocarbon owner, or through a third party that owns the lease. The leases may be taken or assigned to us without title insurance. There is a risk of title failure with respect to such leases, and such title failures could materially adversely impact our business by causing us to be unable to access properties to conduct drilling operations.

Our reserves are subject to the risk of depletion because many of our leases are in mature fields that have produced large quantities of oil and natural gas to date.

Our operations are located in established fields in Eastern Kansas. As a result, many of our leases are in, or directly offset, areas that have produced large quantities of oil and natural gas to date. The degree of depletion for each of our projects ranges from approximately 0% to 78%. As such, our reserves may be partially or completely depleted by offsetting wells or previously drilled wells, which could significantly harm our business.

Our lease ownership may be diluted due to financing strategies we may employ in the future due to our lack of capital.

To accelerate our development efforts we plan to take on working interest partners who will contribute to the costs of drilling and completion and then share in revenues derived from production. In addition, we may in the future, due to a lack of capital or other strategic reasons, establish joint venture partnerships or farm out all or part of our development efforts. These economic strategies may have a dilutive effect on our lease ownership and could significantly reduce our operating revenues.

We are subject to complex laws and regulations, including environmental regulations, which can adversely affect the cost, manner or feasibility of doing business.

Development, production and sale of natural gas and oil in the United States are subject to extensive laws and regulations, including environmental laws and regulations. We may be required to make large expenditures to comply with environmental and other governmental regulations. Matters subject to regulation include, but are not limited to:

location and density of wells;

the handling of drilling fluids and obtaining discharge permits for drilling operations;

accounting for and payment of royalties on production from state, federal and Indian lands;

bonds for ownership, development and production of natural gas and oil properties;

transportation of natural gas and oil by pipelines;

operation of wells and reports concerning operations; and

taxation.

Under these laws and regulations, we could be liable for personal injuries, property damage, oil spills, discharge of hazardous materials, remediation and clean-up costs and other environmental damages. Failure to comply with these laws and regulations also may result in the suspension or termination of our operations and subject us to administrative, civil and criminal penalties. Moreover, these laws and regulations could change in ways that substantially increase our costs. Accordingly, any of these liabilities, penalties, suspensions, terminations or regulatory changes could materially adversely affect our financial condition and results of operations enough to possibly force us to cease our business operations.

Our operations may expose us to significant costs and liabilities with respect to environmental, operational safety and other matters.

We may incur significant costs and liabilities as a result of environmental and safety requirements applicable to our oil and natural gas exploration and production activities. We may also be exposed to the risk of costs associated with Kansas Corporation Commission requirements to plug orphaned and abandoned wells on our oil and natural gas leases from wells previously drilled by third parties. In addition, we may indemnify sellers or lessors of oil and natural gas properties for environmental liabilities they or their predecessors may have created. These costs and liabilities could arise under a wide range of federal, state and local environmental and safety laws and regulations, including regulations and enforcement policies, which have tended to become increasingly strict over time. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, imposition of cleanup and site restoration costs, liens and to a lesser extent, issuance of injunctions to limit or cease operations. In addition, claims for damages to persons or property may result from environmental and other impacts of our operations.

Strict, joint and several liability may be imposed under certain environmental laws, which could cause us to become liable for the conduct of others or for consequences of our own actions that were in compliance with all applicable laws at the time those actions were taken. New laws, regulations or enforcement policies could be more stringent and impose unforeseen liabilities or significantly increase compliance costs. If we are not able to recover the resulting costs through insurance or increased revenues, our ability to operate effectively could be adversely affected.

Our facilities and activities could be subject to regulation by the Federal Energy Regulatory Commission or the Department of Transportation, which could take actions that could result in a material adverse effect on our financial condition.

Although it is anticipated that our natural gas gathering systems will be exempt from FERC and DOT regulation, any revisions to this understanding may affect our rights, liabilities, and access to midstream or interstate natural gas transportation, which could have a material adverse effect on our operations and financial condition. In addition, the cost of compliance with any revisions to FERC or DOT rules, regulations or requirements could be substantial and could adversely affect our ability to operate in an economic manner. Additional FERC and DOT rules and legislation pertaining to matters that could affect our operations are considered and adopted from time to time. We cannot predict what effect, if any, such regulatory changes and legislation might have on our operations, but we could be required to incur additional capital expenditures and increased costs.

Although our natural gas sales activities are not currently projected to be subject to rate regulation by FERC, if FERC finds that in connection with making sales in the future, we (i) failed to comply with any applicable FERC administered statutes, rules, regulations or orders, (ii) engaged in certain fraudulent acts, or (iii) engaged in market manipulation, we could be subject to substantial penalties and fines of up to $1.0 million per day per violation.

We operate in a highly competitive environment and our competitors may have greater resources than us.

The natural gas and oil industry is intensely competitive and we compete with other companies, many of which are larger and have greater financial, technological, human and other resources. Many of these companies not only explore for and produce crude oil and natural gas but also carry on refining operations and market petroleum and other products on a regional, national or worldwide basis. Such companies may be able to pay more for productive natural gas and oil properties and exploratory prospects or define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. In addition, such companies may have a greater ability to continue exploration activities during periods of low oil and natural gas market prices. Our ability to acquire additional properties and to discover reserves in the future will be dependent upon our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. If we are unable to compete, our operating results and financial position may be adversely affected.

We may incur substantial write-downs of the carrying value of our natural gas and oil properties, which would adversely impact our earnings.

We review the carrying value of our natural gas and oil properties under the full-cost accounting rules of the SEC on a quarterly basis. This quarterly review is referred to as a ceiling test. Under the ceiling test, capitalized costs, less accumulated amortization and related deferred income taxes, may not exceed an amount equal to the sum of the present value of estimated future net revenues (adjusted for cash flow hedges) less estimated future expenditures to be incurred in developing and producing the proved reserves, less any related income tax effects. In calculating future net revenues, current prices and costs used are those as of the end of the appropriate quarterly period. Such prices are utilized except where different prices are fixed and determinable from applicable contracts for the remaining term of those contracts, including the effects of derivatives qualifying as cash flow hedges. Two primary factors impacting this test are reserve levels and current prices, and their associated impact on the present value of estimated future net revenues. Revisions to estimates of natural 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, natural 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.

We have recorded a total of $742,040 in impairments on our oil and natural gas properties based on the ceiling test under the full-cost method in the years ended March 31, 2007 and 2006. There was no impairment for the fiscal year ended March 31, 2008. We recorded an impairment of $4,777,723 in the nine months ended December 31, 2008.

Our success depends on our key management and professional personnel, including C. Stephen Cochennet, the loss of whom would harm our ability to execute our business plan.

Our success depends heavily upon the continued contributions of C. Stephen Cochennet, whose knowledge, leadership and technical expertise would be difficult to replace, and on our ability to retain and attract experienced engineers, geoscientists and other technical and professional staff. We have entered into an employment agreement with Mr. Cochennet, and we maintain $1.0 million in key person insurance on Mr. Cochennet. However, if we were to lose his services, our ability to execute our business plan would be harmed and we may be forced to significantly alter our operations until such time as we could hire a suitable replacement for Mr. Cochennet.

Risks Associated with our Debt Financing

Significant and prolonged declines in commodity prices may negatively impact our borrowing base and our ability to borrow overall.

It is possible that our borrowing base, which is based on our oil and gas reserves and is subject to review and adjustment on a semi-annual basis and other interim adjustments, may be reduced when it is reviewed. A reduction in our base could result in a “loan excess” which would be required to be eliminated through payment of a portion of the loan and/or cash collateralization of Letters of Credit obligations; or adding properties to the borrowing base sufficient to offset the “loan excess”. A reduction in our ability to borrow under our Credit Facility, combined with a reduction in cash flow from operations resulting from a decline in oil prices, may require us to reduce our capital expenditures and our operating activities.

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, 2008, $2.7 million in debentures and approximately $8.5 million of bank loans and letters of credit were outstanding. In the event that we default 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.

Our substantial indebtedness could make it more difficult for us to fulfill our obligations under our new 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, 2008, we had total indebtedness of $10.2 million, including $7.428 million of borrowings under the Credit Facility and $2.7 million of remaining debentures. In addition, we had an outstanding letter of credit under the new facility totaling $1.0 million at December 31, 2008. This letter of credit expired on January 3, 2009 and was not renewed. 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;

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 new Credit Facility and debentures impose significant operating and financial restrictions on us.

The new 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;

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 new Credit Facility and our debentures also contain various affirmative covenants with which we are required to comply. We were able to obtain a waiver of default from Texas Capital Bank on two technical covenants at September 30, 2008 and are in compliance with these covenants at December 31, 2008. 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 $3.3 million with proceeds from liquidating a costless collar we entered into on July 3, 2008 and the reduction of our operating and general expenses. See Note 6 to our Condensed Consolidated Financial Statements in this report .We may be unable to comply with some or all of them 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

Our common stock is traded on an illiquid market, making it difficult for investors to sell their shares.

Our common stock trades on the Over-the-Counter Bulletin Board under the symbol “ENRJ,” but trading has been minimal. Therefore, the market for our common stock is limited. The trading price of our common stock could be subject to wide fluctuations. Investors may not be able to purchase additional shares or sell their shares within the time frame or at a price they desire.

The price of our common stock may be volatile and you may not be able to resell your shares at a favorable price.

Regardless of whether an active trading market for our common stock develops, the market price of our common stock may be volatile and you may not be able to resell your shares at or above the price you paid for such shares. The following factors could affect our stock price:

our operating and financial performance and prospects;

quarterly variations in the rate of growth of our financial indicators, such as net income per share, net income and revenues;

changes in revenue or earnings estimates or publication of research reports by analysts about us or the exploration and production industry;

potentially limited liquidity;

actual or anticipated variations in our reserve estimates and quarterly operating results;

changes in natural gas and oil prices;

sales of our common stock by significant stockholders and future issuances of our common stock;

increases in our cost of capital;

changes in applicable laws or regulations, court rulings and enforcement and legal actions;

commencement of or involvement in litigation;

changes in market valuations of similar companies;

additions or departures of key management personnel;

general market conditions, including fluctuations in and the occurrence of events or trends affecting the price of natural gas and oil; and

domestic and international economic, legal and regulatory factors unrelated to our performance.

Our articles of incorporation, bylaws and Nevada Law contain provisions that could discourage an acquisition or change of control of us.

Our articles of incorporation authorize our board of directors to issue preferred stock and common stock without stockholder approval. If our board of directors elects to issue preferred stock, it could be more difficult for a third party to acquire control of us. In addition, provisions of the articles of incorporation and bylaws could also make it more difficult for a third party to acquire control of us. In addition, Nevada’s “Combination with Interested Stockholders’ Statute” and its “Control Share Acquisition Statute” may have the effect in the future of delaying or making it more difficult to effect a change in control of us.

These statutory anti-takeover measures may have certain negative consequences, including an effect on the ability of our stockholders or other individuals to (i) change the composition of the incumbent board of directors; (ii) benefit from certain transactions which are opposed by the incumbent board of directors; and (iii) make a tender offer or attempt to gain control of us, even if such attempt were beneficial to us and our stockholders. Since such measures may also discourage the accumulations of large blocks of our common stock by purchasers whose objective is to seek control of us or have such common stock repurchased by us or other persons at a premium, these measures could also depress the market price of our common stock. Accordingly, our stockholders may be deprived of certain opportunities to realize the “control premium” associated with take-over attempts.

We have no plans to pay dividends on our common stock. You may not receive funds without selling your stock.

We do not anticipate paying any cash dividends on our common stock in the foreseeable future. We currently intend to retain future earnings, if any, to finance the expansion of our business. Our future dividend policy is within the discretion of our board of directors and will depend upon various factors, including our business, financial condition, results of operations, capital requirements, investment opportunities and restrictions imposed by our debentures and Credit Facility.

We may issue shares of preferred stock with greater rights than our common stock.

Although we have no current plans, arrangements, understandings or agreements to issue any preferred stock, our articles of incorporation authorizes our board of directors to issue one or more series of preferred stock and set the terms of the preferred stock without seeking any further approval from our stockholders. Any preferred stock that is issued may rank ahead of our common stock, with respect to dividends, liquidation rights and voting rights, among other things.

We have derivative securities currently outstanding. Exercise of these derivatives will cause dilution to existing and new stockholders.

As of December 31, 2008, we had options and warrants to purchase approximately 454,330 shares of common stock outstanding in addition to 2,500 shares issuable upon conversion of a convertible note. The exercise of our outstanding options and warrants, and the conversion of the note, will cause additional shares of common stock to be issued, resulting in dilution to our existing common stockholders.

Because our common stock may be deemed a low-priced “Penny” stock, an investment in our common stock should be considered high risk and subject to marketability restrictions.

Our common stock may be deemed to be a penny stock, as defined in Rule 3a51-1 under the Securities Exchange Act, which may make it more difficult for investors to liquidate their investment even if and when a market develops for the common stock. Until the trading price of the common stock consistently trades above $5.00 per share, if ever, trading in the common stock may be subject to the penny stock rules of the Securities Exchange Act specified in rules 15g-1 through 15g-10. Those rules require broker-dealers, before effecting transactions in any penny stock, to:

Deliver to the customer, and obtain a written receipt for, a disclosure document;

Disclose certain price information about the stock;

Disclose the amount of compensation received by the broker-dealer or any associated person of the broker-dealer;

Send monthly statements to customers with market and price information about the penny stock; and

In some circumstances, approve the purchaser’s account under certain standards and deliver written statements to the customer with information specified in the rules.

Consequently, the penny stock rules may restrict the ability or willingness of broker-dealers to sell the common stock and may affect the ability of holders to sell their common stock in the secondary market and the price at which such holders can sell any such securities. These additional procedures could also limit our ability to raise additional capital in the future.

If we fail to remain current on our reporting requirements, we could be removed from the OTC Bulletin Board, which would limit the ability of broker-dealers to sell our securities and the ability of stockholders to sell their securities in the secondary market.

Companies trading on the OTC Bulletin Board, such as us, must be reporting issuers under Section 12 of the Securities Exchange Act of 1934, as amended, and must be current in their reports under Section 13, in order to maintain price quotation privileges on the OTC Bulletin Board. More specifically, FINRA has enacted Rule 6530, which determines eligibility of issuers quoted on the OTC Bulletin Board by requiring an issuer to be current in its filings with the Commission. Pursuant to Rule 6530(e), if we file our reports late with the Commission three times in a two-year period or our securities are removed from the OTC Bulletin Board for failure to timely file twice in a two-year period then we will be ineligible for quotation on the OTC Bulletin Board. As a result, the market liquidity for our securities could be severely adversely affected by limiting the ability of broker-dealers to sell our securities and the ability of stockholders to sell their securities in the secondary market.

FINRA sales practice requirements may limit a stockholder's ability to buy and sell our stock.

In addition to the “penny stock” rules described above, FINRA has adopted rules that require that in recommending an investment to a customer, a broker-dealer must have reasonable grounds for believing that the investment is suitable for that customer. Prior to recommending speculative low priced securities to their non-institutional customers, broker-dealers must make reasonable efforts to obtain information about the customer's financial status, tax status, investment objectives and other information. Under interpretations of these rules, the FINRA believes that there is a high probability that speculative low priced securities will not be suitable for at least some customers. The FINRA requirements make it more difficult for broker-dealers to recommend that their customers buy our common stock, which may limit your ability to buy and sell our stock and have an adverse effect on the market for our shares.

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

We did not issue, sell, or repurchase any equity securities during the quarter ended December 31, 2008.

Item 3. Defaults Upon Senior Securities.

There were no defaults upon Senior Securities during the quarter ended December 31, 2008.

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, 2008.

Item 5. Other Information.

On November 6, 2008 we entered into a third amendment to the “Joint Exploration Agreement” with MorMeg, LLC, to further extend the “Additional Capital Deadline” for development of the Black Oaks Project. We have until June 1, 2009 to contribute additional capital towards the development of Black Oaks, and within a reasonable length of time thereafter, secure and contribute additional funding so as not to cause more than thirty (30) days delay of project activities due to lack of funding to complete the project. In the event we are not successful in obtaining additional funding, or all funding, to complete the Black Oaks development, MorMeg may cancel and declare the JEA of no force and effect from the point of cancellation forward.

On November 17, 2008, options to purchase shares of our common stock, which were granted to our non-employee directors as compensation for their service as directors in fiscal 2009 and to our chief executive officer our chief financial officer, were rescinded at the request of the board’s compensation committee and the approval of each option holder. Both the chief executive officer the chief financial officer have agreed to amend their employment agreements to reflect this rescission. The shares subject to these options were returned to the plan and are available for future issuance. This action was taken in an effort to reduce compensation and professional fees expenses which, though non-cash, would have had a substantial negative impact on our financial statements and results of operations for the nine months ended December 31, 2008.

On November 18, 2008, in response to the declining economic conditions which have negatively impacted our business, we liquidated a costless collar with BP. Both EnerJex and BP have executed confirmations of this transaction and BP will pay us approximately $3.9 million. We have reduced to reduce the debt outstanding under our Credit Facility by approximately $3.3 million and used the remainder for general operating purposes.

On November 19, 2008, we were able to obtain a waiver of default from Texas Capital Bank on technical covenants at September 30, 2008 and believe we are in compliance with these covenants at December 31, 2008. 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 $3.3 million with proceeds from liquidating a costless collar we entered into on July 3, 2008 and the reduction of our operating and general expenses.

Item 6.

Exhibits.

Exhibit No.
		Description
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)
5.1		Opinion of Husch Blackwell Sanders LLP (incorporated by reference to Exhibit 5.1 to the S-1 filed on December 12, 2008)
10.1(a)		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)
10.1(b)		Waiver from Texas Capital Bank, N.A. dated November 19, 2008 (incorporated by reference to Exhibit 10.1(b) to the Form 10Q filed on November 19, 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(a)		Letter Agreement with Debenture Holders dated July 3, 2008 (incorporated by reference to Exhibit 10.37 to the Form 10-K filed on July 10, 2008)
10.6†		C. Stephen Cochennet Employment Agreement dated August 1, 2008 (incorporated by reference to Exhibit 10.1 to the Form 8-K filed on August 1, 2008)
10.7†		Dierdre P. Jones Employment Agreement dated August 1, 2008 (incorporated by reference to Exhibit 10.2 to the Form 8-K filed on August 1, 2008)
10.8†		Amended and Restated EnerJex Resources, Inc. Stock Incentive Plan (incorporated by reference to Exhibit 10.1 to the Form 8-K filed on October 16, 2008)
10.9		Form of Officer and Director Indemnification Agreement (incorporated by reference to Exhibit 10.2 to the Form 8-K filed on October 16, 2008)
10.10		Euramerica Letter Agreement Amendment dated September 15, 2008 (incorporated by reference to Exhibit 10.10 to the Form 8-K filed on September 18, 2008)
10.11		Euramerica Letter Agreement Amendment dated October 15, 2008 (incorporated by reference to Exhibit 10.11 to the Form 8-K filed on October 21, 2008)
10.12		Amendment 3 to Joint Exploration Agreement effective as of November 6, 2008 between MorMeg, LLC and EnerJex Resources, Inc. (incorporated by reference to Exhibit 10.12 to the Form 10-Q filed on November 19, 2008)
10.13(a) †		C. Stephen Cochennet Rescission of Option Grant Agreement dated November 17, 2008
10.13(b) †		Dierdre P. Jones Rescission of Option Grant Agreement dated November 17, 2008
10.13(c)		Daran G. Dammeyer Rescission of Option Grant Agreement dated November 17, 2008
10.13(d)		Darrel G. Palmer Rescission of Option Grant Agreement dated November 17, 2008
10.13(e)		Dr. James W. Rector Rescission of Option Grant Agreement dated November 17, 2008
10.13(f)		Robert G. Wonish Rescission of Option Grant Agreement dated November 17, 2008
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 23, 2009

AgEagle Aerial Systems (UAVS) 424B3Prospectus supplement