AgEagle Aerial Systems 424B3 Prospectus supplement

Filed pursuant to Rule 424(b)(3)

Registration No. 333-163611

PROSPECTUS

1,390,000 Shares of Common Stock

(par value $0.001 per share)

This prospectus relates to the resale of 1,390,000 shares of the common stock, par value $0.001 per share, of EnerJex Resources, Inc. by the selling stockholder identified on page 74 of this prospectus, Paladin Capital Management, S.A. (“Paladin” or the “Selling Stockholder”). We may from time to time issue shares of our common stock to Paladin at between 85% and 95% of the market price at the time of such issuance determined in accordance with the terms of our Standby Equity Distribution Agreement, dated as of December 3, 2009, or SEDA, with Paladin. Paladin may from time to time sell shares in transactions on any stock exchange, market or facility on which our shares are traded, in privately negotiated transactions or otherwise at market prices prevailing at the time of sale, at prices related to such market prices or at negotiated prices. We have no basis for estimating either the number of shares of our common stock that will ultimately be issued to or sold by the Selling Stockholder or the prices at which such shares will be sold. We will bear all expenses of registration incurred in connection with this offering, including filing fees, printing fees, and expenses of our legal counsel and other experts, but all selling and other expenses incurred by the Selling Stockholder will be borne by the Selling Stockholder. For additional information on the methods of sale that may be used by Paladin, see the section entitled “Plan of Distribution” on page 75. We will not receive any of the proceeds from the sale of these shares. However, we will receive proceeds from Paladin from the initial sale to such stockholder of these shares.

Our common stock is included for quotation on the over-the-counter bulletin board (“OTC:BB”) under the symbol “ENRJ.OB.” The closing price of our common stock on March 3, 2009 was $ 1.03.

This investment involves a high degree of risk. We urge you to carefully read the “Risk Factors” section beginning on page 9 of this prospectus.

We may amend or supplement this prospectus from time to time by filing amendments or supplements as required. You should read this prospectus and any prospectus supplement carefully before you decide to invest. You should not assume that the information in this prospectus is accurate as of any date other than the date on the front of this document.

With the exception of Paladin, which has informed us it is an “underwriter” within the meaning of the Securities Act of 1933, as amended or the Securities Act, to the best of our knowledge, no other underwriter or person has been engaged to facilitate the sale of shares of our stock in this offering. The Securities and Exchange Commission may take the view that, under certain circumstances, any broker-dealers or agents that participate with Paladin in the distribution of the shares may be deemed to be “underwriters” within the meaning of the Securities Act. Commissions, discounts or concessions received by any such broker-dealer or agent may be deemed to be underwriting commissions under the Securities Act.

Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of these securities or determined if this prospectus is truthful or complete. Any representation to the contrary is a criminal offense.

The date of this prospectus is March 24, 2010

TABLE OF CONTENTS

SUMMARY		1
THE OFFERING		6
SUMMARY FINANCIAL DATA		7
RISK FACTORS		9
SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS		25
USE OF PROCEEDS		25
DIVIDEND POLICY		26
CAPITALIZATION		26
PRICE RANGE OF COMMON STOCK		27
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS		28
BUSINESS AND PROPERTIES		45
MANAGEMENT		61
NON-EMPLOYEE DIRECTOR COMPENSATION		63
EXECUTIVE COMPENSATION		64
CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS		69
PRINCIPAL STOCKHOLDERS		69
DESCRIPTION OF CAPITAL STOCK		71
SELLING STOCKHOLDER		74
PLAN OF DISTRIBUTION		75
LEGAL MATTERS		76
EXPERTS		76
INDEPENDENT PETROLEUM ENGINEERS		77
WHERE YOU CAN FIND MORE INFORMATION		77
GLOSSARY		78
INDEX TO FINANCIAL STATEMENTS		81

You should rely only on the information contained in this prospectus. The selling stockholders have not, authorized any person to provide you with different information. This prospectus is not an offer to sell, nor is it an offer to buy, these securities in any jurisdiction where the offer or sale is not permitted. The information in this prospectus is complete and accurate only as of the date of this prospectus regardless of the time of delivery of this prospectus or any sale of our common stock. Our business, financial condition, prospects and other information may have changed since this date.

No action is being taken in any jurisdiction outside the United States to permit a public offering of the common stock or possession or distribution of this prospectus in that jurisdiction. Persons who come into possession of this prospectus in jurisdictions outside the United States are required to inform themselves about, and to observe any restrictions as to, this offering and the distribution of this prospectus applicable to those jurisdictions.

Industry and Market Data

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

Non-GAAP Financial Measures

The body of accounting principles generally accepted in the United States is commonly referred to as “GAAP.” A non-GAAP financial measure is generally defined by the Securities and Exchange Commission, or SEC, as one that purports to measure historical or future financial performance, financial position or cash flows, but excludes or includes amounts that would not be so adjusted in the most comparable GAAP measures. Any non-GAAP measures are described herein.

SUMMARY

The items in the following summary are described in more detail later in this prospectus. Because this section is a summary, it does not contain all the information that may be important to you or that you should consider before investing in our common stock. For a more complete understanding, you should carefully read the more detailed information set out in this prospectus, especially the risks of investing in our common stock that we discuss under the “Risk Factors” section, as well as the financial statements and the related notes to those statements included elsewhere in this prospectus.

All references in this prospectus 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. We have provided definitions for the oil and natural gas industry terms used in this prospectus in the “Glossary” beginning on page 78 of this prospectus.

Our Business

EnerJex, formerly known as Millennium Plastics Corporation, is an oil and natural gas acquisition, exploration and development company. In August 2006, Millennium Plastics Corporation, following a reverse merger by and among us, Millennium Acquisition Sub (our wholly-owned subsidiary) and Midwest Energy, Inc., a Nevada corporation, or Midwest Energy, changed the focus of its business plan from the development of biodegradable plastic materials and entered into the oil and natural gas industry. In conjunction with the change, the company was renamed EnerJex Resources, Inc.

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 strive to implement an accelerated development program utilizing capital resources, a regional operating focus, an experienced management and technical team, and enhanced recovery technologies to attempt to increase production and increase returns for our stockholders. Our oil and natural gas acquisition and development activities are currently focused in Eastern Kansas.

The total proved PV10 (present value) of our reserves (“PV10”) as of March 31, 2009 was $10.63 million, based on an estimated oil price of $42.65 per barrel. PV10 means the estimated future gross revenue to be generated from the production of proved reserves, net of estimated production and future development and abandonment costs, using prices and costs in effect at the determination date, before income taxes, and without giving effect to non-property related expenses, discounted to a present value using an annual discount rate of 10% in accordance with the guidelines of the SEC. PV10 is a non-GAAP financial measure and generally differs from the standardized measure of discounted future net cash flows, the most directly comparable GAAP financial measure, because it does not include the effects of income taxes on future net revenues. See “Glossary” on page 78 for our definition of PV10 and see “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Reserves” on page 33 for a reconciliation to the comparable GAAP financial measure.

The following table sets forth a summary of our estimated proved reserves attributable to our properties as of March 31, 2009:

Proved Reserves Category	Gross STB(1)		Net STB(2)		Gross MCF(3)		Net MCF(4)		PV10(5) (before tax)
Proved, Developed Producing		722,590		429,420		-		-	$	6,691,550
Proved, Developed Non-Producing		146,620		95,560		-		-		1,459,280
Proved, Undeveloped		1,440,760		811,650		-		-		2,478,510
Total Proved		2,309,970		1,336,630		-		-	$	10,629,340

(1)

STB = one stock-tank barrel.

(2)

Net STB is based upon our net revenue interest, including any applicable reversionary interest.

(3)

MCF = thousand cubic feet of natural gas. There were no natural gas reserves at March 31, 2009.

(4)

Net MCF is based upon our net revenue interest. There were no natural gas reserves at March 31, 2009.

(5)

See “Glossary” on page 78 for our definition of PV10 and “Management’s Discussion and Analysis of Financial Condition and Results of Operations-Reserves” page 33, for a reconciliation to the comparable GAAP financial measure.

The Opportunity in Kansas

According to the Kansas Geological Survey, the State of Kansas has historically been one of the top 10 domestic oil producing regions in the United States. For the years ended December 31, 2008 and 2007, 39.6 million barrels and 36.6 million barrels of oil were produced in Kansas. Of the total barrels produced in Kansas in the calendar year ended December 2007, 15 companies accounted for approximately 29% of the total production, with the remaining 71% produced by over 1,750 active producers.

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

Traditional Roll-Up Strategy. We are seeking to employ a traditional roll-up strategy utilizing a combination of capital resources, operational and management expertise, technology, and our strategic partnership with Haas Petroleum, which has experience operating in the region for nearly 70 years.

Numerous Acquisition Opportunities. There are many small producers and owners of mineral rights in the region, which afford us numerous opportunities to pursue negotiated lease transactions instead of having to competitively bid on fundamentally sound assets.

Fragmented Ownership Structure. There are numerous opportunities to acquire producing properties at attractive prices, because of the currently inefficient and fragmented ownership structure.

Our Properties

Black Oaks Project. The Black Oaks Project is currently a 2,400 acre project in Woodson and Greenwood Counties of Kansas where we are aggressively implementing a primary and secondary recovery waterflood program to increase oil production. We originally acquired an option to purchase and participate in the Black Oaks Project from MorMeg, LLC, or MorMeg, which is controlled by Mark Haas, a principal of Haas Petroleum, for $500,000 of cash and stock. In addition, we established a joint operating account with MorMeg and funded it with $4.0 million for the initial development of the project. We have a 95% working interest in the project and MorMeg has a 5% carried working interest in the project, which will convert to a 30% working interest upon payout. Our gross production at Black Oaks for the month of January 2010 was approximately 89 BOEPD.

DD Energy Project. In September 2007, we acquired a 100% working interest in seven oil and natural gas leases stretching across approximately 1,700 acres in Johnson, Anderson and Linn Counties of Kansas for $2.7 million. Our gross production at DD Energy for the month of January 2010 was approximately 48 BOEPD.

Tri-County Project. We hold a nearly 100% working interest in, and are the operator of, approximately 1,300 acres of oil and natural gas leases in Miami, Johnson and Franklin Counties of Kansas that make up the Tri-County Project. We completed this purchase in September 2007 for $800,000 in cash. Our gross production for the month of January 2010 at Tri-County was approximately 35 BOEPD.

Thoren Project. We acquired the Thoren Project from MorMeg in April 2007 for $400,000. The lease currently encompasses approximately 747 acres in Douglas County, Kansas. We hold a 100% working interest in the Thoren Project. Our gross production for the month of January 2010 at Thoren was approximately 26 BOEPD.

Gas City Project. The Gas City Project, currently located on approximately 5,313 acres in Allen County, Kansas, was acquired for $750,000 in February of 2006 and was our first property acquisition. In August 2007, we entered into a Development Agreement with Euramerica Energy, Inc., or Euramerica, whereby Euramerica initially invested $524,000 in capital toward 6,600 acres of the project. Euramerica was granted an option to purchase this 6,600 acre portion of the project for $1.2 million with a requirement to invest an additional $2.0 million for project development. Euramerica paid us $600,000 of the $1.2 million purchase price and $500,000 of the $2.0 million development funds. On October 15, 2008, the decision was made to shut in the project and cease all operations until Euramerica provided the funds that were due by January 15, 2009. Euramerica failed to fully fund by January 15, 2009 both the balance of the purchase price and the remaining development capital owed under the agreements between us and Euramerica. Therefore, Euramerica 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 reverted back to us. We drilled 22 wells on behalf of Euramerica under the development agreement. We are currently exploring options to sell or further develop the Gas City Project through joint venture partnerships or other opportunities. The gas project remains shut in and certain leases approximating 1,300 acres were not renewed upon expiration. The gross production for the month of January 2010 at Gas City was approximately 6 BOEPD from the oil wells now 100% owned by us.

Our Business Strategy

Our goal is to increase stockholder value by finding and developing oil and natural gas reserves at costs that provide an attractive rate of return on our investments. The principal elements of our business strategy are:

Develop Our Existing Properties. We intend to create reserve and production growth from over 400 additional drilling locations we have identified on our properties. We have identified an additional 193 drillable producer locations and 213 drillable injector locations. The structure and the continuous oil accumulation in Eastern Kansas, and the expected long-life production and reserves of our properties, are anticipated to enhance our opportunities for long-term profitability.

Maximize Operational Control. We seek to operate our properties and maintain a substantial working interest. We believe the ability to control our drilling inventory will provide us with the opportunity to more efficiently allocate capital, manage resources, control operating and development costs, and utilize our experience and knowledge of oilfield technologies.

Pursue Selective Acquisitions and Joint Ventures. Due to our local presence in Eastern Kansas and strategic partnership with Haas Petroleum, we believe we are well-positioned to pursue selected acquisitions, subject to availability of capital, from the fragmented and capital-constrained owners of mineral rights throughout Eastern Kansas.

Reduce Unit Costs Through Economies of Scale and Efficient Operations. As we increase our oil production and develop our existing properties, we expect that our unit cost structure will benefit from economies of scale. In particular, we anticipate reducing unit costs by greater utilization of our existing infrastructure over a larger number of wells.

Our Competitive Strengths

We have a number of strengths that we believe will help us successfully execute our strategy:

Acquisition and Development Strategy. We have what we believe to be a relatively low-risk acquisition and development strategy compared to some of our competitors. We generally buy properties that have proven current production, with a projected pay-back within a relatively short period of time, and with potential growth and upside in terms of development, enhancement and efficiency. We also plan to minimize the risk of natural gas and oil price volatility by developing a sales portfolio of pricing for our production as it expands and as market conditions permit.

Significant Production Growth Opportunities. We have acquired an attractive acreage position with favorable lease terms in a region with historical hydrocarbon production. Based on drilling success we have had within our acreage position and subject to availability of capital, we expect to increase our reserves, production and cash flow.

Experienced Management Team and Strategic Partner with Strong Technical Capability. Our CEO has over 20 years of experience in the energy industry, primarily related to gas/electric utilities, but including experience related to energy trading and production, and members of our board of directors have considerable industry experience and technical expertise in engineering, horizontal drilling, geoscience and field operations. In addition, our strategic partner, Haas Petroleum, has over 70 years of experience in Eastern Kansas, including completion and secondary recovery techniques and technologies. Our board of directors and Mark Haas of Haas Petroleum work closely with management during the initial phases of any major project to ensure its feasibility and to consider the appropriate recovery techniques to be utilized.

Incentivized Management Ownership. The equity ownership of our directors and executive officers is strongly aligned with that of our stockholders. As of February 22, 2010, our directors and executive officers owned approximately 14% of our outstanding common stock.

Company History

Prior to the reverse merger with Midwest Energy in August of 2006, we operated under the name Millennium Plastics Corporation and focused on the development of biodegradable plastic materials. This business plan was ultimately abandoned following its unsuccessful implementation. Following the merger, we assumed the business plan of Midwest Energy and entered into the oil and natural gas industry. Concurrent with the effectiveness of the merger, we changed our name to “EnerJex Resources, Inc.” The result of the merger was that the former stockholders of Midwest Energy controlled approximately 98% of our outstanding shares of common stock. In addition, Midwest Energy was deemed to be the acquiring company for financial reporting purposes and the merger was accounted for as a reverse merger.

Initially, all of our oil and natural gas operations were conducted through Midwest Energy. In November 2007, Midwest Energy changed its name to EnerJex Kansas, Inc., or EnerJex Kansas. In August 2007, we incorporated DD Energy, Inc., or DD Energy, as a wholly-owned operating subsidiary. All of our current operations are conducted through EnerJex Kansas and DD Energy, our wholly-owned subsidiaries.

Risks Associated with Our Business

Our business is subject to numerous risks, as discussed more fully in the section entitled “Risk Factors” beginning on page 9 of this prospectus. Some of these risks include:

Volatility in natural gas and oil prices, which could negatively impact our revenues and our ability to cover our operating or capital expenditures.

The concentration of our properties in Eastern Kansas, which disproportionately exposes us to adverse events occurring in this geographic area.

Our ability to achieve and maintain profitable business operations. Although we recently achieved positive income from operations for the first time in our history, we have a history of losses since our inception and we may never be able to maintain profitability.

Our ability to obtain 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.

Our ability to effectively compete with large companies that may have greater resources than us.

Our ability to accurately estimate proven recoverable reserves.

Our ability to successfully complete future acquisitions and to integrate acquired businesses.

Our ability to comply with complex laws and regulations, including environmental regulations, which can adversely affect the cost, manner or feasibility of doing business.

December 2009 Standby Equity Distribution Agreement

On December 3, 2009, we and Paladin entered into a Standby Equity Distribution Agreement, or SEDA, pursuant to which, for a two-year period, we have the right to sell up to 1,300,000 shares of our common stock to Paladin at any time. These shares are being registered with this registration statement, even though Paladin does not own them yet. On December 3, 2009, we authorized the issuance of 90,000 shares of our common stock to Paladin as a commitment fee. As of December 9, 2009, we had not sold any shares of common stock to Paladin under the SEDA.

For each share of common stock purchased under the SEDA, Paladin will pay a percentage of the lowest daily volume weighted average closing price during the five consecutive trading days after we provide notice to Paladin based on the following:

85% of the market price for the initial two advances,

90% of the market price to the extent the Common Stock is trading below $1.00 per share during the pricing period,

92% of the market price to the extent the Common Stock is trading at or above $1.00 per share during the pricing period, or

95% of the market price to the extent the Common Stock is trading at or above $2.00 per share during the pricing period.

Each such advance may be for an amount that is the greater of $40,000 or 20% the average daily trading volume of our common stock for the five consecutive trading days prior to the notice date. However, our initial two advances under the SEDA may be for up to $55,000. In addition, in no event shall the number of shares of common stock issuable to Paladin pursuant to an advance cause the aggregate number of shares of common stock beneficially owned by Paladin and its affiliates to exceed 4.99%.

Our right to deliver an advance notice and the obligations of Paladin thereunder with respect to an advance is subject to our satisfaction of a number of conditions, including that our common stock is trading, and we believe will continue for the foreseeable future to trade, on a principal market, that we have not received any notice threatening the continued listing of our common stock on the principal market and that a registration statement is effective.

In addition, without the written consent of Paladin, we may not, directly or indirectly, offer to sell, sell, contract to sell, grant any option to sell or otherwise dispose of any shares of common stock (other than the shares offered pursuant to the provisions of the agreement) or securities convertible into or exchangeable for common stock, warrants or any rights to purchase or acquire, common stock during the period beginning on the 5th trading day immediately prior to an advance notice date and ending on the 5th trading day immediately following the settlement date.

We may terminate the SEDA upon fifteen trading days of prior notice to Paladin, as long as there are no advances outstanding and we have paid to Paladin all amounts then due. A copy of the SEDA is attached hereto as an exhibit.

Corporate Information

EnerJex Resources, Inc. is a Nevada corporation. Our principal executive office is located at 27 Corporate Woods, Suite 350, 10975 Grandview Drive, Overland Park, Kansas 66210, and our phone number is (913) 754-7754. We also maintain a website at www.enerjexresources.com. The information on our website is not incorporated by reference into this prospectus.

THE OFFERING

We have agreed to register 1,390,000 shares of our common stock already issued to or subject to issuance to the Selling Stockholder named in this prospectus for resale pursuant to this prospectus. The named selling stockholder may offer shares of our common stock through public or private transactions.

Common stock offered by the Selling Stockholder	1,390,000 shares

Use of proceeds	We will not receive any of the proceeds from the sale of shares of our common stock in this offering. We will receive proceeds from any sale of shares of common stock to Paladin pursuant to the SEDA and proceeds received under the SEDA will be utilized for working capital and general corporate purposes.See “Use of Proceeds” on page 25 of this prospectus.

Current OTC:BB symbol	ENRJ.OB

Dividend policy	We do not expect to pay dividends in the foreseeable future.

Risk factors	Investing in our common stock involves certain risks. See the risk factors described under the heading “Risk Factors” beginning on page 9 of this prospectus and the other information included in this prospectus for a discussion of factors you should carefully consider before deciding to invest in shares of our common stock.

SUMMARY FINANCIAL DATA

The following tables set forth a summary of the historical financial data of EnerJex Resources, Inc. for, and as of the end of, each of the periods indicated. The statements of operations, statements of cash flows and other financial data for the period from (i) inception (December 30, 2005) to March 31, 2006, (ii) the fiscal years ended March 31, 2007, 2008 and 2009, and (iii) our balance sheets as of March 31, 2007, March 31, 2008 and March 31, 2009 are derived from our audited financial statements included elsewhere in this prospectus. Our balance sheet as of December 31, 2009 and the statements of operations, statements of cash flows and other financial data for the nine months ended December 31, 2009 and 2008 are derived from our unaudited financial statements included elsewhere in this prospectus. We have prepared the unaudited financial statements on the same basis as our audited financial statements and, in our opinion, have included all adjustments, which include only normal recurring adjustments, necessary to present fairly our financial position and results of our operations for each of the periods mentioned.

The inception date for the financial statements presented in this prospectus is that of EnerJex Kansas. As a result of a reverse merger between Millennium Plastics Corporation (now EnerJex Resources, Inc.) and EnerJex Kansas (formerly Midwest Energy), EnerJex Kansas was deemed to be the acquiring company for financial reporting purposes and the transaction has been accounted for as a reverse merger.

Our historical results are not necessarily indicative of the results to be expected for any future periods and the results for the nine months ended December 31, 2009 should not be considered indicative of results expected for the full fiscal year. You should read the following financial information together with the information under “Management’s Discussion and Analysis of Results of Operations and Financial Condition” and our financial statements and related notes included elsewhere in this prospectus.

	Nine Months Ended December 31,						Year Ended March 31,			Year Ended March 31,			Year Ended March 31,			From Inception (December 30, 2005) through March 31,
	2009			2008			2009			2008			2007			2006
	(Unaudited)			(Unaudited)			(Audited)			(Audited)			(Audited)			(Audited)
Statement of Operations:
Revenue
Oil and natural gas activities	$	3,703,724		$	4,652,289		$	6,436,805		$	3,602,798		$	90,800		$	2,142
Expenses
Direct operating costs		1,313,518			2,093,994			2,637,333			1,795,188			172,417			14,599
Repairs on oil and natural gas equipment		—			—			—			—			165,603			40,436
Depreciation, depletion and amortization		577,288			995,069			911,293			935,330			23,978			825
Professional fees		479,710			400,816			1,320,332			1,226,998			302,071			50,490
Salaries		706,011			694,973			849,340			1,703,099			288,016			—
Administrative expense		789,827			1,065,308			1,392,645			887,872			182,773			21,700
Impairment of oil and natural gas
Properties		—			4,777,723			4,777,723			—			273,959			468,081
Impairment of goodwill		—			—			—			—			677,000			—
Total expenses		3,866,354			10,027,883			11,888,666			6,548,487			2,085,817			596,131

Income (loss) from operations		(162,630	)		(5,375,594	)		(5,451,861	)		(2,945,689	)		(1,995,017	)		(593,989	)

Other income (expense):
Interest expense		(542,939	)		(743,372	)		(882,426	)		(792,448	)		(8,434	)		(38	)
Loan interest accretion		(432,864	)		(2,686,892	)		(2,814,095	)		(1,089,798	)		—			—
Management fee revenue		99,234			—			—			—			—			—
Gain on repurchase of debentures		406,500			—			—			—			—			—
Loss on disposal of vehicles		(20,695	)		(4,421	)		—			—			—			—
Unrealized gain (loss) on derivative instruments		(2,485,706	)		—			—			—			—			—
Gain on liquidation of hedging instrument		—			3,879,050			3,879,050			—			—			—
Other gain (loss)		—			—			(37,736	)		—			348			1,159
Total other income (expense)		(2,976,470	)		444,365			144,793			(1,882,246	)		(8,086	)		1,121

Net income (loss)	$	(3,139,100	)	$	(4,931,229	)	$	(5,307,068	)	$	(4,827,935	)	$	(2,003,103	)	$	(592,868	)

Weighted average number of common shares outstanding – basic and fully diluted		4,647,879			4,442,467			4,443,249			4,284,144			2,448,318			1,712,609

Net income (loss) per share – basic	$	(0.68	)	$	(1.11	)	$	(1.19	)	$	(1.13	)	$	(0.82	)	$	(0.35	)

	Nine Months Ended December 31,						Year Ended March 31,			Year Ended March 31,			Year Ended March 31,			From Inception (December 30, 2005) through March 31,
	2009			2008			2009			2008			2007			2006
	(Unaudited)			(Unaudited)			(Audited)			(Audited)			(Audited)			(Audited)
Statement of Cash Flows:
Cash provided by (used in) operating activities	$	1,675,890		$	3,130,719		$	3,686,582		$	(408,494	)	$	(1,435,559	)	$	(60,786	)
Cash (used in) investing activities		(173,793	)		(2,517,241	)		(3,027,203	)		(9,357,020	)		(151,180	)		(767,550	)
Cash provided by (used in) financing activities		(1,217,312	)		(1,376,136	)		(1,482,798	)		10,617,025			1,095,800			1,418,768

Increase (decrease) in cash and cash equivalents		284,785			(762,658	)		(823,419	)		851,511			(490,939	)		590,432
Cash and cash equivalents, beginning		127,585			951,004			951,004			99,493			590,432			—
Cash and cash equivalents, end	$	412,370		$	188,346		$	127,585		$	951,004		$	99,493		$	590,432

Supplemental disclosures:
Interest paid	$	209,681		$	688,062		$	768,053		$	733,972		$	5,407		$	38
Income tax paid	$	—		$	—		$	—		$	—		$	—		$	—

Non-cash transactions:
Share- based payments issued for compensation and services	$	603,750			79,455			—			280,591			558,000			33,000
Share-based payments issued for oil and gas properties	$	—		$	—		$	—		$	—		$	200,000		$	—
Principal increase on debentures	$	294,250		$	—		$	—		$	—		$	—		$	—
Shares issued for interest on debentures	$	7,355		$	—		$	—		$	—		$	—		$	—
Asset retirement obligation	$	4,281		$	246,871		$	—		$	—		$	—		$	—

	At December 31,			At March 31,			At March 31,		At March 31,			At March 31,
	2009			2009			2008		2007			2006
	(Unaudited)			(Audited)			(Audited)		(Audited)			(Audited)

Total Assets	$	7,336,967		$	7,680,178		$	10,867,829	$	492,507		$	922,486
Total Liabilities		13,658,584			11,473,802			9,433,837		537,097			71,586
Stockholders’ Equity (deficit)	$	(6,321,617	)	$	(3,793,624	)	$	1,433,992	$	(44,590	)	$	850,900

RISK FACTORS

Investing in our common stock involves a high degree of risk. You should carefully consider the following risk factors, as well as the other information in this prospectus, before deciding whether to invest in shares of our common stock. If any of the following risks actually occur, our business, financial condition, operating results and prospects would suffer. In that case, the trading price of our common stock would likely decline and you might lose all or part of your investment in our common stock. The risks described below are not the only ones we face. Additional risks that we currently do not know about or that we currently believe to be immaterial may also impair our operations and business results.

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 months, 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 materially 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 or advancements;

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, constrained capital sources 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 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.

Our auditor’s report reflects the fact that without realization of additional capital, it would be unlikely for us to continue as a going concern.

As a result of our deficiency in working capital at March 31, 2009 and other factors, our auditors have included a paragraph in their audit report regarding substantial doubt about our ability to continue as a going concern. Our plans in this regard are to increase production, seek strategic alternatives and to seek additional capital through future equity private placements or debt facilities.

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 68% of our total proved reserves as of March 31, 2009 consist of undeveloped and developed non-producing reserves, and those reserves may not ultimately be developed or produced.

Our estimated total proved PV 10 (present value) before tax of reserves as of March 31, 2009 was $10.63 million, versus $39.6 million as of March 31, 2008. The decline in PV10 is primarily due to the estimated average price of oil at March 31, 2009 of $42.65 versus $94.53 at March 31, 2008. We held total proved reserves of 1.3 million barrels of oil equivalent, or BOE, as of March 31, 2009. Of the 1.3 million BOE of total proved reserves, approximately 39% are proved developed and approximately 61% are proved undeveloped. The proved developed reserves consist of 82% proved developed producing reserves and 18% proved developed non-producing reserves. See “Glossary” on page 78 for our definition of PV10.

As of March 31, 2009, approximately 61% of our total proved reserves were undeveloped and approximately 7% 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 estimate and the future net cash flows attributable to those reserves at March 31, 2009 was prepared by Miller and Lents, Ltd., an independent petroleum consultant. Prior to this fiscal year, our reserves were evaluated and estimates were prepared by McCune Engineering, an 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 these independent consultants and engineers. 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 Miller and Lents, Ltd. 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. Effective January 1, 2010, however, the SEC 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. Oil and gas companies will be permitted, but not required, to disclose probable reserves (i.e., reserves less likely to be recovered than proved reserves, but as likely as not to be recovered) and possible reserves (i.e., reserves less certain to be recovered than probable reserves).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 filing with the SEC, 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 until permitted by SEC rules. Except as required by applicable law, we undertake no duty 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 typically 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. While we have fixed this differential under the terms of our agreement with Coffeyville Resources Refining and Marketing, LLC (“Coffeyville”) through March 31, 2011 and may continue on a month to month basis after that date, we cannot accurately predict future 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. Recent economic conditions, including volatility in the price of oil and natural gas, have resulted in both increases and decreases in the differential between the benchmark price for oil and natural gas and the wellhead price we receive. These fluctuations 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, 2009 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 lack of access to economically acceptable 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 extremely complex, and requires 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 early 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 Coffeyville for the sale of all of our oil through March 2011 and will likely contract for the sale of our natural gas with one, or a small number, of buyers if and when we resume operations on the Gas City Project. 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 approximately 30 and 165 barrels of oil per day that could result in both realized and unrealized hedging losses. As of December 31, 2009 we have realized losses of $165,116 and have unrealized losses of $2,485,706. 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 (Coffeyville 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.

Cost and availability 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.

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 when needed, subject to availability of capital, 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. 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 may 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.

As previously announced, in December 2008, the 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.

There was no impairment for the fiscal year ended March 31, 2008. We recorded an impairment of $4,777,723 during the fiscal year ended March 31, 2009 primarily attributable to lower prices for both oil and natural gas at 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, 2009, $2.39 million in debentures and approximately $6.75 million of bank loans were outstanding. Under a default situation with respect to the debentures or other secured debt, the lenders may enforce their rights as a secured party and we may lose all or a portion of our assets or be forced to materially reduce our business activities. An event of default under the Credit Facility permits Texas Capital to accelerate repayment of all amounts due and to terminate the commitments thereunder. Any event of default which results in such acceleration under the Credit Facility would also result in an event of default under our Debentures. We do not have sufficient cash resources to repay these amounts if Texas Capital accelerates its obligations under the Credit Facility. If we are unable to successfully negotiate a forbearance agreement or waiver with Texas Capital, or if Texas Capital accelerates its obligations under the Credit Facility, we may be forced to voluntarily seek bankruptcy protection.

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

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

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

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

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

increasing our vulnerability to general adverse economic and industry conditions;

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

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

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

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

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

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

incur additional indebtedness and provide additional guarantees;

pay dividends and make other restricted payments;

create or permit certain liens;

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

use the proceeds from the unwinding of certain financial hedges;

engage in certain transactions with affiliates; and

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

The Credit Facility and our debentures also contain various affirmative covenants with which we are required to comply. We obtained a waiver of default from Texas Capital Bank on two technical covenants at March 31, 2009 and one at June 30, 2009. We were not in compliance with working capital ratio covenant at December 31, 2009; however, we were able to obtain a waiver of default from TCB. A copy of this waiver is incorporated by reference in this document and is filed as Exibit 10.18 to the Form 10-Q filed on February 16, 2010. We are taking steps in an effort to comply with these same covenants in future quarters, including but not limited to, a reduction in principal of approximately $4 million since November 2008, and the reduction of our operating and general expenses. We may be unable to comply with some or all of these covenants in the future as well. If we do not comply with these covenants and are unable to obtain waivers from our lenders, we would be unable to make additional borrowings under these facilities, our indebtedness under these agreements would be in default and could be accelerated by our lenders. In addition, it could cause a cross-default under our other indebtedness, including our debentures. If our indebtedness is accelerated, we may not be able to repay our indebtedness or borrow sufficient funds to refinance it. In addition, if we incur additional indebtedness in the future, we may be subject to additional covenants, which may be more restrictive than those to which we are currently subject.

Risks Associated with our Common Stock and the Offering

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

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

There are substantial risks associated with the Standby Equity Distribution Agreement with Paladin, which could contribute to the decline of our stock price and have a dilutive impact on our existing stockholders.

The sale of shares of our common stock pursuant to the SEDA will have a dilutive impact on our stockholders. Paladin may re-sell all of the shares we issue to them under the SEDA and such sales could cause the market price of our common stock to decline significantly with advances under the SEDA. To the extent of any such decline, any subsequent advances would require us to issue a greater number of shares of common stock to Paladin in exchange for each dollar of the advance. Under these circumstances, our existing stockholders would experience greater dilution. If we were to fully draw down the commitment amount under the SEDA, we would have to issue approximately 26.1% of our currently outstanding shares. Although Paladin is precluded from short sales, the sale of our common stock under the SEDA could encourage short sales by third parties, which could contribute to the further decline of our stock price.

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.OB,” 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.

Future sales of our common stock may result in a decrease in the market price of our common stock, even if our business is doing well.

The market price of our common stock could drop due to sales of a large number of shares of our common stock in the market or the perception that such sales could occur. This could make it more difficult to raise funds through future offerings of common stock.

As of February 22, 2010, we have outstanding 4,979,928 shares of our common stock. This does not include the 1,390,000 shares being sold by the Selling Stockholder in this offering, which may be resold from time to time in the public market following an advance notice by us. The 77,500 shares of our common stock that are subject to outstanding warrants and convertible securities as of August 31, 2009 will be eligible for sale in the public market to the extent permitted by the provisions of applicable securities laws. If these additional shares are sold, or it is perceived they will be sold, the trading price of our common stock could decline. These sales also might make it more difficult for us to sell equity or equity-related securities in the future at a time and price that we deem reasonable or appropriate.

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

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.

SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS

This prospectus 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 prospectus, including statements regarding future events, our future financial performance, business strategy and plans and objectives of management for future operations, are forward-looking statements. We have attempted to identify forward-looking statements by terminology including “anticipates,” “believes,” “can,” “continue,” “could,” “estimates,” “expects,” “intends,” “may,” “plans,” “potential,” “predicts” or & #8220;should” or the negative of these terms or other comparable terminology. Although we do not make forward-looking statements unless we believe we have a reasonable basis for doing so, we cannot guarantee their accuracy. These statements are only predictions and involve known and unknown risks, uncertainties and other factors, including the risks outlined under “Risk Factors” or elsewhere in this prospectus, 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;

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 prospectus. Before you invest in our common stock, you should be aware that the occurrence of the events described in the section entitled “Risk Factors” and elsewhere in this prospectus could negatively affect our business, operating results, financial condition and stock price. 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 prospectus to conform our statements to actual results or changed expectations.

USE OF PROCEEDS

Paladin is selling all of the shares of our common stock covered by this prospectus for its own account. Accordingly, we will not receive any proceeds from the sale of shares by Paladin. All net proceeds from the sale of the common stock covered by this prospectus will go to Paladin. We will bear all expenses of registration incurred in connection with this offering, including filing fees, printing fees, and expenses of our legal counsel and other experts, but all selling and other expenses incurred by the Selling Stockholder will be borne by the Selling Stockholder. However, we will receive proceeds from any sale of shares of common stock to Paladin pursuant to the SEDA.

85% of the market price for the initial two advances,

90% of the market price to the extent the Common Stock is trading below $1.00 per share during the pricing period,

92% of the market price to the extent the Common Stock is trading at or above $1.00 per share during the pricing period, or

95% of the market price to the extent the Common Stock is trading at or above $2.00 per share during the pricing period.

We anticipate, and have represented to Paladin in the SEDA, that the proceeds received under the SEDA will be utilized for working capital and general corporate purposes.

DIVIDEND POLICY

We have never paid or declared any cash dividends on our common stock. We currently intend to retain any future earnings to finance the growth and development of our business and we do not expect to pay any cash dividends on our common stock in the foreseeable future. In addition, we are contractually prohibited by the terms of our outstanding debt from paying cash dividends on our common stock. Payment of future dividends, if any, will be at the discretion of our board of directors and will depend on our financial condition, results of operations, capital requirements, restrictions contained in current or future financing instruments, including the consent of debt holders, if applicable at such time, and other factors our board of directors deems relevant.

CAPITALIZATION

You should read this capitalization table in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our financial statements and related notes included elsewhere in this prospectus.

The following table sets forth our capitalization as of December 31, 2009.

	As of December 31, 2009
	Actual
	(Unaudited)

Stockholders’ equity:
Common stock; $0.001 par value, 100,000,000 shares authorized, 4,910,660 issued and outstanding		4,911
Common stock owed but not issued		186
Additional paid-in capital		9,543,360
Retained (deficit)		(15,870,074	)

Total stockholders’ equity (deficit)		(6,321,617	)

Total capitalization		(6,321,617	)

The information in the table above excludes:

2,500 shares issuable upon conversion of an unsecured $25,000 6% convertible note due August 2, 2010, which is convertible into shares of our common stock at $10.00 per share; and

75,000 shares of our common stock issuable upon the exercise of outstanding warrants, at an exercise price of $3.00 per share, that were issued to the placement agent in connection with the private placement of $9.0 million of debentures in April 2007.

PRICE RANGE OF COMMON STOCK

Prior to completion of the reverse merger with Midwest Energy in August 2006, our common stock was sporadically traded in the inter-dealer markets of the OTC:BB, “pink sheets” and “gray sheets” under the symbol “MPCO.” As of March 23, 2007, our common stock commenced trading on the OTC:BB under the symbol “EJXR.OB.” On July 28, 2008, in conjunction with the implementation of the 1-for-5 reverse stock split of all of our common stock, our trading symbol on the OTC:BB changed to ENRJ.OB. Our common stock has traded infrequently on the OTC:BB, which limits our ability to locate accurate high and low bid prices for each quarter within the last two fiscal years. Therefore, the following table lists the quotations for the high and low bid prices as reported by a Quarterly Trade and Quote Summary Report of the OTC Bulletin Board and Yahoo! Finance for fiscal years 2008 and 2009, the first, second and third quarters of fiscal year 2010. The quotations reflect inter-dealer prices without retail mark-up, markdown, or commissions and may not represent actual transactions.

	Low		High
Fiscal 2008
Quarter ended June 30, 2007	$	5.00	$	6.25
Quarter ended September 30, 2007	$	3.75	$	6.75
Quarter ended December 31, 2007	$	3.50	$	6.00
Quarter ended March 31, 2008	$	4.05	$	6.00
Fiscal 2009
Quarter ended June 30, 2008	$	4.80	$	5.90
Quarter ended September 30, 2008	$	4.00	$	5.10
Quarter ended December 31, 2008	$	0.45	$	3.16
Quarter ended March 31, 2009	$	0.25	$	1.88
Fiscal 2010
Quarter ended June 30, 2009	$	0.15	$	1.34
Quarter ending September 30, 2009	$	0.15	$	1.85
Quarter ending December 31, 2009	$	0.41	$	1.00

The last reported sale price of our common stock on the OTC:BB was $1.03 per share on March 3 , 2010. As of February 22, 2009, there were approximately 1,135 holders of record of our common stock.

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 prospectus. 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 “Risk Factors” and elsewhere in this prospectus.

Overview

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

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

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

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

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

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.

Recent Developments

We entered into an agreement with Shell Trading (US) Company, or Shell, whereby we agreed to an 18-month fixed-price swap with Shell for 130 BOPD at a fixed price per barrel of $96.90, before transportation costs from April 1, 2008 through September 30, 2009. This represented approximately 60% of our total oil production on a net revenue basis at that time and locked in approximately $6.8 million in gross revenue before transportation costs over the 18 month period. 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. Through September 30, 2009, the positive impact on our net revenue from the fixed-price swap was approximately $787,000.

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 and interim adjustments. 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 was most recently reviewed by Texas Capital Bank in January 2010 and it was determined that it should be reduced by $55,000 per month beginning February 2010. The Credit Facility is secured by a lien on substantially all assets of the Company and its subsidiaries. The Credit Facility has a term of three years, and all unpaid principal and 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 had borrowings $7.328 million outstanding at March 31, 2009 and $6.746 million at December 31, 2009.

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

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 Credit Facility, subordinate the security interests of the debentures to the Credit Facility, provide for the redemption of the remaining debentures with the net proceeds from any next debt or equity offering, eliminate the covenant to maintain certain production thresholds and waive all known defaults. Subsequent to year-end, we again amended the debentures to extend the maturity date to September 30, 2010, and allow us to pay interest in either cash or payment-in-kind interest (an increase in the amount of principal due) or pay interest through the issuance of shares of common stock, and add a provision for the conversion of the debentures into shares of our common stock. Further, in November of 2009, we amended the debentures to amend the company redemption section of the debentures to allow for the retirement of shares of our common stock held by the debenture holders if we meet certain redemption payment schedules and to amend the debenture holders’ rights to participate in certain future debt or equity offerings made by us. We repurchased $450,000 of the Debentures during the nine months ended December 31, 2009 at a gain of $406,500. We also redeemed an additional $150,000 of the Debentures during the quarter ended December 31, 2009 for $150,000 in cash. No gain or loss resulted from this $150,000 redemption. Subsequent to the quarter ended December 31, 2009, we further amended the Debentures to extend the scheduled due dates for the January and February 2010 redemption payments to March 10, 2010.

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.

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.

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

On March 3, 2009, we withdrew our Form S-1 Registration Statement after deciding to terminate the registered public offering. As global economic conditions deteriorated and the commodity prices of oil and natural gas experienced significant declines, the availability of equity capital became severely constrained. While we intend to return to the equity market when conditions improve and are conducive to raising capital, there can be no assurance that we will be successful in doing so.

We recorded a non-cash impairment of $4,777,723 to the carrying value of our proved oil and gas properties during the fiscal year ended March 31, 2009. 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.

In April and May of 2009, we repurchased a total of $450,000 of the subordinated debentures. The principal balance remaining as of December 31, 2009 is approximately $2.39 million. These debentures mature on September 30, 2010.

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

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

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

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

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

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

Effective January 13, 2010 the Credit Facility with Texas Capital Bank was amended to modify the senior funded debt to EBITDA ratio on a quarterly basis beginning with the quarter ending December 31, 2009 and to modify the annualization of the interest coverage ratio, also beginning with the quarter ending December 31, 2009. See Note 8 to our December 31, 2009 Unaudited Condensed Consolidated Financial Statements in this report.

Results of Operations for the Fiscal Years Ended March 31, 2009 and 2008 compared.

We began acquiring oil properties with existing production in April of 2007, the first month of our fiscal year ended March 31, 2008. These acquisitions included the Black Oaks and Thoren Projects. We acquired both the DD Energy and the Tri-County Projects in November of 2007, or about mid-year of that same fiscal year. We owned these projects throughout the entire fiscal year ended March 31, 2009. Comparisons between the fiscal years, then, will reflect a full year of revenues and expenses for all projects for the fiscal year ended March 31, 2009 and a partial year of revenues and expenses for the two of the four projects for the fiscal year ended March 31, 2008.

Income:

	Fiscal Year Ended March 31,
	2009		2008		Increase / (Decrease)
	Amount		Amount		$
Oil and natural gas revenues	$	6,436,805	$	3,602,798	$	2,834,007

Revenues

Oil and natural gas revenues for the fiscal year ended March 31, 2009 were $6,436,805 compared to revenues of $3,602,798 in the fiscal year ended March 31, 2008. The increase in revenues is primarily the result of the greater oil production levels as well as a higher average price per barrel of oil. The average price per barrel we received for oil sold during the twelve months ended March 31, 2009 was $85.67 compared to $79.71 for the twelve months ended March 31, 2008. Natural gas sales accounted for less than 1% of the total revenues. The average price per Mcf for natural gas sales during the fiscal year ended March 31, 2009 was $5.57, compared to $6.20 during the fiscal year ended March 31, 2008.

Expenses:

	Fiscal Year Ended March 31,
	2009		2008		Increase / (Decrease)
	Amount		Amount		$
Expenses:
Direct operating costs	$	2,637,333	$	1,795,188	$	842,145
Depreciation, depletion and amortization		872,230		913,224		(40,994	)
Total production expenses		3,509,563		2,708,412		801,151

Professional fees		1,320,332		1,226,998		93,334
Salaries		849,340		1,703,099		(853,759	)
Depreciation on other fixed assets		39,063		22,106		16,957
Administrative expenses		1,392,645		887,872		504,773
Impairment of oil & gas properties		4,777,723		-		4,777,723
Total expenses	$	11,888,666	$	6,548,487	$	5,340,179

Direct Operating Costs

Direct operating costs for the fiscal year ended March 31, 2009 were $2,637,333 compared to $1,795,188 for the fiscal year ended March 31, 2008. The increase over the prior period results from the operating costs on a greater number of wells on our existing and acquired oil leases during the fiscal year ended March 31, 2009. Direct operating costs include pumping, gauging, pulling, repairs, certain contract labor costs, and other non-capitalized expenses.

Depreciation, Depletion and Amortization

Depreciation, depletion and amortization for the fiscal year ended March 31, 2009 was $872,230, compared to $913,224 for the fiscal year ended March 31, 2008. The decrease was primarily a result of the lower cost per barrel of depletion of oil reserves. The rate of depletion was $12.02 per barrel for the fiscal year ended March 31, 2009 as compared to $19.57 per barrel for the fiscal year ended March 31, 2008.

Professional Fees

Professional fees for the fiscal year ended March 31, 2009 were $1,320,332 compared to $1,226,998 for the fiscal year ended March 31, 2008. Payments for services rendered in connection with acquisition and financing activities, our audit, legal, and consulting fees are recorded as professional fees and remained relatively constant over the two fiscal years.

Salaries

Salaries for the fiscal year ended March 31, 2009 were $849,340 compared to $1,703,099 for the fiscal year ended March 31, 2008. There were expenses totaling $1,204,102 during the prior fiscal year related to non-cash equity based payments made by issuing stock options to our management. No such issuances were made in the current fiscal year. In addition, the number of full-time employees increased from 9 at March 31, 2008 to 19 at one point during the fiscal year ended March 31, 2009, then settled at 14 on March 31, 2009. As a result, cash based salary expense increased by approximately $500,000 during the current fiscal year.

Depreciation on Other Fixed Assets

Depreciation on other fixed assets fiscal year ended March 31, 2009 was $39,063 compared to $22,106 for the fiscal year ended March 31, 2008. The increase was primarily due to depreciation on fixed assets acquired during the period.

Administrative Expenses

Administrative expenses for the fiscal year ended March 31, 2009 were $1,392,645 compared to $887,872 in the fiscal year ended March 31, 2008. The administrative expenses increased in relation to the addition of employees, office space, and corporate activity related to growth in operations.

Impairment of Oil & Gas Properties

The impairment of oil and natural gas properties in the year ended March 31, 2009 of $4,777,723 represented an impairment through applying the full-cost ceiling test method. This ceiling test was applied to all of the cost of our oil and natural gas properties accounted for under the full-cost method that were subject to amortization at March 31, 2009. We took this impairment based on the ceiling test results during the quarter ended December 31, 2008, and was primarily due to depressed commodity prices at the time.

Reserves

Our estimated total proved PV 10 (present value) of reserves as of March 31, 2009 decreased to $10.63 million from $39.6 million as of March 31, 2008. Though total proved reserves were comparable at March 31, 2009 and 2008; 1.3 million and 1.4 million barrels of oil equivalent (BOE), respectively, the PV10 declined dramatically due to the estimated average price of oil at March 31, 2009 of $42.65 versus $94.53 at March 31, 2008. Of the 1.3 million BOE at March 31, 2009 approximately 39% are proved developed and approximately 61% are proved undeveloped. The proved developed reserves consist of proved developed producing (82%) and proved developed non-producing (18%).

The following table presents summary information regarding our estimated net proved reserves as of March 31, 2009. All calculations of estimated net proved reserves have been made in accordance with the rules and regulations of the SEC, and, except as otherwise indicated, give no effect to federal or state income taxes. The estimates of net proved reserves are based on the reserve reports prepared by Miller and Lents, Ltd., our independent petroleum consultants. For additional information regarding our reserves, please see Note 11 to our audited financial statements as of and for the fiscal year ended March 31, 2009.

Summary of Proved Oil and Natural Gas Reserves

as of March 31, 2009

Proved Reserves Category	Gross		Net		PV10 (before tax)(1)

Proved, Developed Producing
Oil (stock-tank barrels)		722,590		429,420	$	6,691,550
Natural Gas (mcf)(2)		-		-		-
Proved, Developed Non-Producing
Oil (stock-tank barrels)		146,620		95,560	$	1,459,280
Natural Gas (mcf) (2)		-		-		-
Proved, Undeveloped
Oil (stock-tank barrels)		1,440,760		811,650	$	2,478,510
Natural Gas (mcf) (2)		-		-		-
Total Proved Reserves
Oil (stock-tank barrels)		2,309,970		1,136,630	$	10,629,340
Natural Gas (mcf) (2)		-		-		-

(1)

The following table shows our reconciliation of our PV10 to our standardized measure of discounted future net cash flows (the most direct comparable measure calculated and presented in accordance with GAAP). PV10 is our estimate of the present value of future net revenues from estimated proved natural gas reserves after deducting estimated production and ad valorem taxes, future capital costs and operating expenses, but before deducting any estimates of future income taxes. The estimated future net revenues are discounted at an annual rate of 10% to determine their “present value.” We believe PV10 to be an important measure for evaluating the relative significance of our oil and natural gas properties and that the presentation of the non-GAAP financial measure of PV10 provides useful information to investors because it is widely used by professional analysts and sophisticated investors in evaluating oil and gas companies. Because there are many unique factors that can impact an individual company when estimating the amount of future income taxes to be paid, we believe the use of a pre-tax measure is valuable for evaluating our company. We believe that most other companies in the oil and gas industry calculate PV10 on the same basis. PV10 should not be considered as an alternative to the standardized measure of discounted future net cash flows as computed under GAAP.

	As of March 31, 2009

PV10 (before tax)	$	10,629,340
Future income taxes, net of 10% discount		-
Standardized measure of discounted future net cash flows	$	10,629,340

(2)

There were no natural gas reserves at March 31, 2009.

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

Income:

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

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

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

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

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

Revenues

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

Expenses:

Direct Operating Costs

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

Depreciation, Depletion and Amortization

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

Impairment of Oil and Gas Properties

We recorded a non-cash impairment of $4,777,723 million to the carrying value of our proved oil and gas properties as of December 31, 2008. The impairment is primarily attributable to lower prices for both oil and natural gas at December 31, 2008. The charge results from the application of the “ceiling test” under the full cost method of accounting. Under full cost accounting requirements, the carrying value may not exceed an amount equal to the sum of the present value of estimated future net revenues (adjusted for cash flow hedges) less estimated future expenditures to be incurred in developing and producing the proved reserves, less any related income tax effects. In calculating future net revenues, current prices and costs used are those as of the end of the appropriate quarterly period. Such prices are utilized except where different prices are fixed and determinable from applicable contracts for the remaining term of those contracts, including the effects of derivatives qualifying as cash flow hedges. A ceiling test charge occurs when the carrying value of the oil and gas properties exceeds the full cost ceiling.

Professional Fees

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

Salaries

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

Administrative Expense

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

Interest Expense

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

Loan Interest Accretion

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

Gain on Liquidation of Hedging Instrument

Unrealized Gain (loss) on Derivative Instruments

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

Gain on Repurchase of Debentures

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

Management Fee Revenue

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

Net Income (Loss)

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

Liquidity and Capital Resources

Liquidity is a measure of a company’s ability to meet potential cash requirements. We have historically met our capital requirements through debt financing, revenues from operations and the issuance of equity securities. Based upon the monthly commitment notices we have received to date, we have estimated and classified $330,000 of the borrowings outstanding under our Credit Facility as a current liability. As we may be unable to provide the necessary liquidity we need by the revenues generated from our net interests in our oil and natural gas production at current commodity prices, we are exploring various strategic initiatives and JV partnerships, as well as sales of reserves in our existing properties to finance our operations and to service our debt obligations.

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

The following table summarizes total current assets, total current liabilities and working capital at December 31, 2009 as compared to March 31, 2009.

	December 31, 2009			March 31, 2009			Increase / (Decrease) $

Current Assets	$	977,561		$	898,941			78,620

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

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

Senior Secured Credit Facility

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

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

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

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

Debenture Financing

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

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

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

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.

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 Buyers’ registration statement to sell our common stock owned by the Buyers, (iv) amended certain terms of the Debenture Agreements in recognition of the indebtedness under the Credit Facility, (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, and (vi) the Buyers agreed to waive all known events of default. In June 2009, we again amended the debentures to extend the maturity date to September 30, 2010, and allow us to pay interest in either cash or payment-in-kind interest (an increase in the amount of principal due) or payment-in-kind shares (issuance of shares of common stock), and add a provision for the conversion of the debentures into shares of EnerJex’s common stock. Further, in November 2009, we amended the debentures to amend the company redemption section of the debentures to allow for the retirement of shares of our common stock held by the debenture holders if we meet certain redemption payment schedules and to amend the debenture holders’ rights to participate in certain future debt or equity offerings made by us.

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

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

Standby Equity Distribution Agreement with Paladin

On December 3, 2009, we and Paladin entered into a Standby Equity Distribution Agreement, or SEDA, pursuant to which, for a two-year period, we have the right to sell up to 1,300,000 shares of our common stock to Paladin at any time. These shares are being registered with this registration statement, even though Paladin does not own them yet. On December 3, 009, we authorized the issuance of 90,000 shares of our common stock to Paladin as a commitment fee. As of December 9, 2009, we had not sold any shares of common stock to Paladin under the SEDA.

85% of the market price for the initial two advances,

90% of the market price to the extent the Common Stock is trading below $1.00 per share during the pricing period,

92% of the market price to the extent the Common Stock is trading at or above $1.00 per share during the pricing period, or

95% of the market price to the extent the Common Stock is trading at or above $2.00 per share during the pricing period.

Satisfaction of our cash obligations for the next 12 months

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

Going Concern

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

Summary of product research and development

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

Expected purchase or sale of any significant equipment

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

Significant changes in the number of employees

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

Off-Balance Sheet Arrangements

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

Critical Accounting Policies and Estimates

Our critical accounting estimates include the value our oil and gas properties, asset retirement obligations, current portion of long-term debt, and share-based payments.

Oil and Gas Properties:

The accounting for our business is subject to special accounting rules that are unique to the gas and oil industry. There are two allowable methods of accounting for oil and gas business activities: the successful efforts method and the full-cost method. We follow the full-cost method of accounting under which all costs associated with property acquisition, exploration and development activities are capitalized. We also capitalize internal costs that can be directly identified with our acquisition, exploration and development activities and do not include any costs related to production, general corporate overhead or similar activities.

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

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

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

Asset Retirement Obligations:

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

Current Portion of Long-term Debt:

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

Derivative Instruments:

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

Share-Based Payments:

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

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

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

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

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

Recent Accounting Pronouncement Issued But Not in Effect

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

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

Effects of Inflation and Pricing

The oil and natural gas industry is very cyclical and the demand for goods and services of oil field companies, suppliers and others associated with the industry puts extreme pressure on the economic stability and pricing structure within the industry. Material changes in prices impact revenue stream, estimates of future reserves, borrowing base calculations of bank loans and value of properties in purchase and sale transactions. Material changes in prices can impact the value of oil and natural gas companies and their ability to raise capital, borrow money and retain personnel. We anticipate business costs and the demand for services related to production and exploration will fluctuate while the commodity prices for oil and natural gas, both remain volatile.

BUSINESS AND PROPERTIES

Our Business

EnerJex, formerly known as Millennium Plastics Corporation, is an oil and natural gas acquisition, exploration and development company. Midwest Energy, Inc. was incorporated in the State of Nevada on December 30, 2005. In August of 2006, Millennium Plastics Corporation, following a reverse merger by and among us, Millennium Acquisition Sub (our wholly-owned subsidiary) and Midwest Energy, changed the focus of its business plan from the development of biodegradable plastic materials and entered into the oil and natural gas industry. In conjunction with the change, the company was renamed EnerJex Resources, Inc.

Since the beginning of fiscal 2008, we deployed approximately $12 million in capital resources to acquire and develop five operating projects and drill 179 new wells (111 producing wells and 65 water injection wells and 3 dry holes). As a result, our estimated total net proved oil reserves increased from zero at March 31, 2007 to 1.3 million barrels of oil equivalent, or BOE, as of March 31, 2009. Of the 1.3 million BOE of total proved reserves, approximately 39% are proved developed and approximately 61% are proved undeveloped. The proved developed reserves consist of 82% proved developed producing reserves and 18% proved developed non-producing reserves.

The total proved PV10 (present value) of our reserves (“PV10”) as of March 31, 2009 was $10.63 million, based on an estimated oil price of $42.65 per barrel. PV10 means the estimated future gross revenue to be generated from the production of proved reserves, net of estimated production and future development and abandonment costs, using prices and costs in effect at the determination date, before income taxes, and without giving effect to non-property related expenses, discounted to a present value using an annual discount rate of 10% in accordance with the guidelines of the SEC. PV10 is a non-GAAP financial measure and generally differs from the standardized measure of discounted future net cash flows, the most directly comparable GAAP financial measure, because it does not include the effects of income taxes on future net revenues. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations-Reserves” page 33, for a reconciliation to the comparable GAAP financial measure.

In response to economic conditions and capital market constraints, we have recently begun to explore and evaluate various strategic initiatives that would allow us to continue our plans to grow production and reserves in the mid-continent region of the United States. Initiatives include creating joint ventures to further develop current leases, restructuring current debt, as well as evaluating other options ranging from capital formation to some type of business combination. Though there can be no assurance that any particular outcome will result from this process, we believe there are significant opportunities to increase our growth rates given current market conditions. We believe this process may create options that will allow us to better position EnerJex to take advantage of these opportunities.

The Opportunity in Kansas

Fragmented Ownership Structure. There are numerous opportunities to acquire producing properties at attractive prices, because of the currently inefficient and fragmented ownership structure.

Our Properties

The table below summarizes our acreage by project name as of March 31, 2009.

Project Name	Developed Acreage				Undeveloped Acreage				Total Acreage
	Gross		Net(1)		Gross		Net(1)		Gross		Net(1)
Black Oaks Project		550		522		1,850		1,758		2,400		2,280
Thoren Project		135		135		591		591		726		726
DD Energy Project		400		400		1,370		1,370		1,770		1,770
Tri-County Project		610		606		652		651		1,262		1,257
Gas City Project		600		600		4,713		4,713		5,313		5,313
Total		2,295		2,263		9,176		9,083		11,471		11,346

(1)

Net acreage is based on our net working interest as of March 31, 2009.

Black Oaks Project

On April 9, 2007, we entered into a “Joint Exploration Agreement” with a shareholder, MorMeg, LLC, (MorMeg) 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. The Black Oaks Project encompasses approximately 2,400 gross acres in Woodson and Greenwood Counties, Kansas, which at the time of acquisition had approximately 35 oil wells producing an average of approximately 32 barrels of oil per day, or BOPD.

The Black Oaks Project is a primary and enhanced secondary recovery project between us and MorMeg. Phase I of the Black Oaks Project development plan commenced shortly after closing with the drilling of 44 in-fill wells. During fiscal 2008, we began injecting water into the first five water injection wells at an average rate of approximately 50 barrels of water per day per well. This pilot program was expanded so that by June 2008, we were injecting approximately 200 barrels of water per day (bbls water/day) per well in the initial 5 injection wells. Adjacent oil wells showed increased production from an average of approximately 5 BOPD to 25 BOPD. As of March 31, 2009, we are maintaining the 200 bbls water/day average on the injection wells in the pilot program area. We have seen no additional response on this area as of yet. We are also injecting an average of 100 bbls water/day per well in 4 injection wells adjacent to the pilot program area and are closely monitoring data and activities for any resulting increase in production. Based upon the results of our testing, we expect to continue the development plan, subject to availability of capital. Phase II of the plan contemplates drilling over 25 additional water injection wells and drilling over 20 additional producer wells. Project-wide production was an average of approximately 96 BOPD as of March 31, 2009.

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. Through an additional extension, we have until December 31, 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 extension will have no force and effect, however, upon a material default by EnerJex under the Credit Facility. 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.

As of March 31, 2009, based on an estimated oil price of $42.65 per barrel, we had proved oil reserves on Phase I of this project of:

	Gross STB(1)		Net STB(2)		PV10(3) (before tax)
Proved, Developed Producing		420,080		197,640	$	3,781,690
Proved, Developed Non-Producing		50,440		30,450	$	650,430
Proved, Undeveloped		875,300		352,370	$	944,100
Total Proved		1,345,820		580,460	$	5,376,220

(1)

STB = one stock-tank barrel.

(2)

Net STB is based upon our net revenue interest, including any applicable reversionary interest.

(3)

Thoren Project

On April 27, 2007, we acquired a 100% working interest in the Thoren Project for $400,000 from MorMeg. This project, at the time of acquisition, contained 240 acres in Douglas County, Kansas, with 12 oil wells producing an average of approximately 10 BOPD, 4 water injection wells, and one water supply well. We have leased an additional 486 acres increasing the total acreage of this project to 726 acres.

Through March 31, 2009, we have invested approximately $800,000 for the development of this project and as of March 31, 2009, we had 32 oil wells producing an average of approximately 38 BOPD; along with 16 water injection wells and one water supply well.

As of March 31, 2009, based on an estimated oil price of $42.65 per barrel, we had proved oil reserves on this project of:

	Gross STB(1)		Net STB(2)		PV10(3) (before tax)
Proved, Developed Producing		48,030		24,600	$	539,510
Proved, Developed Non-Producing		24,920		7,690	$	146,490
Proved, Undeveloped		43,020		37,640	$	85,970
Total Proved		115,970		69,930	$	771,970

(1)

STB = one stock-tank barrel.

(2)

Net STB is based upon our net revenue interest, including any applicable reversionary interest.

(3)

We will maintain our 100% working interest until “payout” and our working interest will become 75%, at which time the MorMeg working interest will be converted to a 25% working interest. Payout for this project occurs at that point in time when the total cumulative revenue from production equals the total amount of the purchase price, all costs and expenses incurred by us in the development and operation, and loan and interest costs incurred in the finance and funding of the purchase.

We have identified an additional 7 drillable producer locations and 8 drillable injector locations on this project.

DD Energy Project

Effective September 1, 2007, we acquired a 100% working interest in the DD Energy Project for $2.7 million, which consisted of approximately 1,500 acres in Johnson, Anderson and Linn Counties, Kansas. At the time of acquisition, this project was producing an average of approximately 45 BOPD.

In addition, we have acquired additional leases bringing the total acreage for this project to approximately 1,700 acres. As of March 31, 2009, we had 110 oil wells, 41 water injection wells and 2 water supply wells on this project with production averaging approximately 61 BOPD. Through March 31, 2009, we have invested an additional $2.4 million in this project and have drilled 41 water injection wells and 34 producing wells. We have seen some indication of an initial response from 5 of the injectors and are closely monitoring data and activities for any resulting increase in production.

As of March 31, 2009, based on an estimated oil price of $42.65 per barrel, we had proved oil reserves on this project of:

	Gross STB(1)		Net STB(2)		PV10(3) (before tax)
Proved, Developed Producing		75,510		64,700	$	972,220
Proved, Developed Non-Producing		23,070		19,470	$	183,090
Proved, Undeveloped		39,390		31,840	$	85,030
Total Proved		137,970		116,010	$	1,240,340

(1)

STB = one stock-tank barrel.

(2)

Net STB is based upon our net revenue interest, including any applicable reversionary interest.

(3)

We have identified an additional 88 drillable producer locations and 86 drillable injector locations on this project.

Tri-County Project

On September 14, 2007, we acquired nearly a 100% working interest in the Tri-County Project for $800,000, which consisted of approximately 1,100 acres in Miami, Johnson and Franklin Counties, Kansas. At the time of acquisition, this project was producing an average of approximately 25 BOPD.

Through March 31, 2009, we have invested approximately $700,000 towards the development of this project. Funds have been used to drill four producer wells, make infrastructure upgrades, and perform work-overs on approximately 20 wells in this project. We have also acquired additional leases, bringing the total project to approximately 1,300 acres.

As of March 31, 2009, the Tri-County Project consisted of 166 producing wells and 59 water injection wells with production averaging approximately 49 BOPD.

As of March 31, 2009, based on an estimated oil price of $42.65 per barrel, we had proved oil reserves on this project of:

	Gross STB(1)		Net STB(2)		PV10(3) (before tax)
Proved, Developed Producing		177,560		141,330	$	1,369,700
Proved, Developed Non-Producing		48,190		37,940	$	479,270
Proved, Undeveloped		474,210		380,030	$	1,361,430
Total Proved		699,960		559,300	$	3,210,400

(1)

STB = one stock-tank barrel.

(2)

Net STB is based upon our net revenue interest, including any applicable reversionary interest.

(3)

We have identified an additional 83 drillable producer locations and 90 drillable injector locations on this project.

Gas City Project

On September 15, 2008, we amended the well development agreement to extend the date on which Euramerica was required to make its third and fourth quarterly installment payments of the purchase price to October 15, 2008. The amendment also extended until November 15, 2008 the requirement to fund the remaining $1.5 million in development capital.

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 then became 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.

We drilled 22 wells on behalf of Euramerica under the development agreement. We are currently exploring options to sell or further develop the Gas City Project through joint venture partnerships or other opportunities. The gas project remains shut in and certain leases approximating 1,300 acres were not renewed upon expiration. As of March 31, 2009 we were producing an average of approximately 10 BOPD from the two oil wells now 100% owned by us.

As of March 31, 2009, based on an estimated oil price of $42.65 per barrel, we had proved oil and natural gas reserves on this project of:

	Gross STB(1)		Net STB(2)		Gross MCF(3)		Net MCF(4)		PV10(5) (before tax)
Proved, Developed Producing		1,400		1,150		-		-	$	28,430
Proved, Developed Non-Producing		-		-		-		-	$	-
Proved, Undeveloped		11,850		9,780		-		-	$	1,970
Total Proved		13,250		10,930		-		-	$	30,400

(1)

STB = one stock-tank barrel.

(2)

Net STB is based upon our net revenue interest, including any applicable reversionary interest.

(3)

MCF = thousand cubic feet of natural gas. There were no natural gas reserves at March 31, 2009.

(4)

Net MCF is based upon our net revenue interest. There were no natural gas reserves at March 31, 2009.

(5)

See “Glossary” on page 78 for our definition of PV10 and “Management’s Discussion and Analysis of Financial Condition and Results of Operations-Reserves” page 33, for reconciliation to the comparable GAAP financial measure.

Brownrigg Project

Our Business Strategy

Our principal strategy has been to focus on the acquisition of oil and natural gas mineral leases that have existing production and cash flow. Once acquired, subject to availability of capital, we strive to implement an accelerated development program utilizing capital resources, a regional operating focus, an experienced management and technical team, and enhanced recovery technologies to attempt to increase production and increase returns for our stockholders. Our oil and natural gas acquisition and development activities are currently focused in Eastern Kansas. Depending on availability of capital, and other restraints, our goal is to increase stockholder value by finding and developing oil and natural gas reserves at costs that provide an attractive rate of return on our investments. The principal elements of our business strategy are:

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. Subsequent to year-end (in June 2009), we entered into one such opportunity on the Brownrigg lease in Linn County, Kansas, as discussed above. This economic strategy is anticipated to 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, through our acquisition strategy, and other strategic initiatives. 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. For a detailed description of these and other factors that could materially impact actual results, please see “Risk Factors” in this document.

Our Competitive Strengths

We have a number of strengths that we believe will help us successfully execute our strategy:

Incentivized Management Ownership. The equity ownership of our directors and executive officers is strongly aligned with that of our stockholders. As of November 16, 2009, our directors and executive officers owned approximately 12.1% of our outstanding common stock.

Company History

Midwest Energy, Inc. was incorporated in the State of Nevada on December 30, 2005. Prior to the reverse merger with Midwest Energy in August of 2006, we operated under the name Millennium Plastics Corporation and focused on the development of biodegradable plastic materials. This business plan was ultimately abandoned following its unsuccessful implementation. Following the merger, we assumed the business plan of Midwest Energy and entered into the oil and natural gas industry. Concurrent with the effectiveness of the merger, we changed our name to “EnerJex Resources, Inc.” The result of the merger was that the former stockholders of Midwest Energy controlled approximately 98% of our outstanding shares of common stock. In addition, Midwest Energy was deemed to be the acquiring company for financial reporting purposes and the merger was accounted for as a reverse merger. In November 2007 Midwest Energy changed its name to EnerJex Kansas. All of our current operations are conducted through EnerJex Kansas and DD Energy, our wholly-owned subsidiaries.

Significant Developments in Fiscal 2009 and 2010

The following is a brief description of our most significant corporate developments that occurred in fiscal 2009:

On March 6, 2008 we entered into an agreement with Shell Trading (US) Company, or Shell, whereby we agreed to an 18-month fixed-price swap with Shell for 130 BOPD at a fixed price per barrel of $96.90, before transportation costs from April 1, 2008 through September 30, 2009. This represented approximately 60% of our total oil production on a net revenue basis at that time and locked in approximately $6.8 million in gross revenue before transportation costs over the 18 month period. 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. Through September 30, 2009, the positive impact on our net revenue from the fixed-price swap was approximately $787,000.

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 and other interim adjustments. 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 was reviewed by Texas Capital Bank in February 2009 and it was determined that it shall be reduced by $200,000 per month beginning April 2009 with the expectation that this monthly reduction would continue through December 2009. We had borrowings $7.328 million outstanding at March 31, 2009. Subsequent to year-end, we have made an additional $582,000 of payments to reduce the borrowing base to $6.746 million at December 31, 2009. 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 matures 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.

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 Credit Facility, subordinate the security interests of the debentures to the Credit Facility, provide for the redemption of the remaining debentures with the net proceeds from any next debt or equity offering, eliminate the covenant to maintain certain production thresholds and waive all known defaults. Subsequent to year-end, we again amended the debentures to extend the maturity date to September 30, 2010, to allow us to pay interest in either cash or payment-in-kind interest (an increase in the amount of principal due) or payment of interest through the issuance of shares of common stock, and add a provision for the conversion of the debentures into shares of our common stock. Through May 31, 2010 the conversion price per share equals $3.00. From June 1, 2010 through the Maturity Date, assuming the debenture has not been redeemed, the conversion price per share equals that price which shall be computed as 100.0% of the arithmetic average of the Weighted Average Price of the Common Stock on each of the thirty (30) consecutive Trading Days immediately preceding the Conversion Date, and considering adjustments, if any, as specified in the amendment. Further, in November of 2009, we amended the debentures to amend the company redemption section of the debentures to allow for the retirement of shares of our common stock held by the debenture holders if we meet certain redemption payment schedules and to amend the debenture holders’ rights to participate in certain future debt or equity offerings made by us. We repurchased $450,000 of the Debentures during the nine months ended December 31, 2009 at a gain of $406,500. We also redeemed an additional $150,000 of the Debentures during the quarter ended December 31, 2009 for $150,000 in cash. No gain or loss resulted from this $150,000 redemption. Subsequent to the quarter ended December 31, 2009, we further amended the Debentures to extend the scheduled due dates for the January and February 2010 redemption payments to March 10, 2010.

We recorded a non-cash impairment of $4,777,723 to the carrying value of our proved oil and gas properties during the fiscal year ended March 31, 2009. The impairment is primarily attributable to lower prices for both oil and natural gas. The charge results from the application of the “ceiling test” under the full cost method of accounting at December 31, 2008. 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.

In April and May of 2009, we repurchased a total of $450,000 of the subordinated debentures. The principal balance remaining as of December 31, 2009 is approximately $2.46 million. These debentures mature on September 30, 2010.

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

Relationship with Haas Petroleum

In April of 2007, we entered into a consulting agreement with Mark Haas, President of Haas Petroleum and managing member of MorMeg. This agreement provides that Mr. Haas will consult with us at an executive level regarding field development, acquisition evaluation, identification of additional acquisition opportunities and overall business strategy. Haas Petroleum has been in the oil exploration and production business for over 70 years and Mark Haas has been in the business for over 30 years.

We believe that this relationship provides us with a competitive advantage when evaluating and sourcing acquisition opportunities. As a long-term producer and oil field service provider, Haas Petroleum has existing relationships with numerous oil and natural gas producers in Eastern Kansas and is generally aware of existing opportunities to enhance many of these properties through the deployment of capital, and application of enhanced drilling and production technologies. We believe that we will be able to leverage the experience and relationships of Mr. Haas to compliment our business strategy. To date, Mr. Haas has helped us identify and evaluate all of our property acquisitions, and has been instrumental in the creation and implementation of our development plans of these properties.

One of our fundamental goals with respect to the consulting arrangement is to align the interests of Mr. Haas with those of ours as much as possible. As a result, the consulting agreement provides that we will pay him five thousand dollars per month. Finally, we have utilized our common stock, in part, for the purchase of assets owned by MorMeg, which we believe will further align our business interests with those of Mr. Haas.

Drilling Activity

The following table sets forth the results of our drilling activities during the 2007, 2008 and 2009 fiscal years.

Drilling Activity
	Gross Wells						Net Wells(1)
Fiscal Year	Total		Producing		Dry		Total		Producing		Dry

2007 Exploratory		-0-		-0-		-0-		-0-		-0-		-0-
2008 Exploratory		10		10		-0-		10		10		-0-
2009 Exploratory(2)		12		12		-0-		12		12		-0-

2007 Development		-0-		-0-		-0-		-0-		-0-		-0-
2008 Development		59		57		2		58		56		2
2009 Development		96		95		1		96		95		1

(1)

Net wells are based on our net working interest as of March 31, 2009.

(2)

We incurred some exploration costs related to exploratory wells drilled on behalf of Euramerica.

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

The table below sets forth our net oil and natural gas production (net of all royalties, overriding royalties and production due to others) for the fiscal years ended March 31, 2009 and 2008 and 2007, the average sales prices, average production costs and direct lifting costs per unit of production.

	Fiscal Year Ended March 31, 2009		Fiscal Year Ended March 31, 2008		Fiscal Year Ended March 31,2007
Net Production
Oil (Bbl)		74,289		43,697		-0-
Natural gas (Mcf)		12,275		17,762		19,254

Average Sales Prices
Oil (per Bbl)	$	85.67	$	79.71	$	-0-
Natural gas (per Mcf)	$	5.57	$	6.20	$	4.72

Average Production Cost (1)
Per Bbl of oil	$	45.01	$	56.65	$	-0-
Per Mcf of natural gas	$	15.11	$	13.12	$	9.55

Average Lifting Costs (2)
Per Bbl of oil	$	33.01	$	37.08	$	-0-
Per Mcf of natural gas	$	15.11	$	9.86	$	8.95

(1)

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

(2)

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

Results of Oil and Natural Gas Producing Activities

The following table shows the results of operations from our oil and natural gas producing activities from fiscal years ended March 31, 2007 through March 31, 2009. Results of operations from these activities have been determined using historical revenues, production costs, depreciation, depletion and amortization of the capitalized costs subject to amortization. General and administrative expenses and interest expense have been excluded from this determination.

	For the Fiscal Year Ended March 31, 2009			For the Fiscal Year Ended March 31, 2008			For the Fiscal Year Ended March 31, 2007
Production revenues	$	6,436,805		$	3,602,798		$	90,800
Production costs		(2,637,333	)		(1,795,188	)		(172,417	)
Depreciation, depletion and amortization		(872,230	)		(913,224	)		(11,477	)
Results of operations for producing activities	$	2,972,242		$	894,386		$	(93,094	)

Producing Wells

The following table sets forth the number of productive oil and natural gas wells in which we owned an interest as of March 31, 2009.

	Producing
Project	Gross Oil		Net Oil(1)		Gross Natural Gas		Net Natural Gas(1)

Black Oaks Project		62		59		-0-		-0-
Thoren Project		33		33		-0-		-0-
DD Energy Project		114		114		-0-		-0-
Tri-County Project		170		170		-0-		-0-
Gas City Project		-0-		-0-		22		22
Total		379		376		22		22

(1)

Net wells are based on our net working interest as of March 31, 2009.

Reserves

Our estimated total proved PV10 (present value) before tax of reserves as of March 31, 2009 was $10.63 million, versus $39.6 million as of March 31, 2008. Though total proved reserves were comparable at March 31, 2009 and 2008; 1.3 million and 1.4 million barrels of oil equivalent (BOE), respectively, the PV10 declined dramatically due to the estimated average price of oil at March 31, 2009 of $42.65 versus $94.53 at March 31, 2008. Of the 1.3 million BOE at March 31, 2009 approximately 39% are proved developed and approximately 61% are proved undeveloped. The proved developed reserves consist of proved developed producing (82%) and proved developed non-producing (18%). See “Glossary” on page 78 for our definition of PV10.

Based on an estimated oil price of $42.65 as of March 31, 2009, and applying an annual discount rate of 10% of the future net cash flow, the estimated PV10 of the 1.3 million BOE, before tax, is calculated as set forth in the following table:

Summary of Oil and Natural Gas Reserves

as of March 31, 2009

Proved Reserves Category	Gross STB(1)		Net STB(2)		Gross MCF(3)		Net MCF(4)		PV10(5) (before tax)
Proved, Developed Producing		722,590		429,420		-		-	$	6,691,550
Proved, Developed Non-Producing		146,620		95,560		-		-		1,459,280
Proved, Undeveloped		1,440,760		811,650		-		-		2,478,510
Total Proved		2,309,970		1,336,630		-		-	$	10,629,340

(6)

STB = one stock-tank barrel.

(7)

Net STB is based upon our net revenue interest, including any applicable reversionary interest.

(8)

MCF = thousand cubic feet of natural gas. There were no natural gas reserves at March 31, 2009.

(9)

Net MCF is based upon our net revenue interest. There were no natural gas reserves at March 31, 2009.

(10)

Oil and Natural Gas Reserves Reported to Other Agencies

We did not file any estimates of total proved net oil or natural gas reserves with, or include such information in reports to, any federal authority or agency, other than the SEC, during the fiscal year ended March 31, 2009.

Title to Properties

Our properties are subject to customary royalty interests, liens under indebtedness, liens incident to operating agreements and liens for current taxes and other burdens, including mineral encumbrances and restrictions. Further, our debt is secured by first and second liens substantially on all of our assets. These burdens have not materially interfered with the use of our properties in the operation of our business to date, though there can be no assurance that such burdens will not materially impact our operations in the future.

We believe that we have satisfactory title to or rights in all of our producing properties. As is customary in the natural gas and oil industry, minimal investigation of title is made at the time of acquisition of undeveloped properties. In most cases, we investigate title and obtain title opinions from counsel or have title reviewed by professional landmen only when we acquire producing properties or before we begin drilling operations. However, any acquisition of producing properties without obtaining title opinions are subject to a greater risk of title defects.

Sale of Natural Gas and Oil

We do not intend to refine our natural gas or oil production. We expect to sell all or most of our production to a small number of purchasers in a manner consistent with industry practices at prevailing rates by means of long-term and short-term sales contracts, some of which may have fixed price components. We have an ISDA master agreement and two fixed price swaps with BP beginning October 1, 2009 through December 31, 2013. Under current conditions, we should be able to find other purchasers, if needed. All of our produced oil is held in tank batteries and then each respective purchaser transports the oil by truck to the refinery. In addition, our 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 in an effort to mitigate a majority of our exposure to changing oil prices in the intermediate term.

Secondary Recovery and Other Production Enhancement Strategies

When an oil field is first produced, the oil typically is recovered as a result of natural pressure within the producing formation, often assisted by pumps of various types. The only natural force present to move the crude oil to the wellbore is the pressure differential between the higher pressure in the formation and the lower pressure in the wellbore. At the same time, there are many factors that act to impede the flow of crude oil, depending on the nature of the formation and fluid properties, such as pressure, permeability, viscosity and water saturation. This stage of production is referred to as “primary production,” which in Eastern Kansas normally only recovers up to 15% of the crude oil originally in place in a producing formation.

Many, but not all, oil fields are amenable to assistance from a waterflood, a form of “secondary recovery,” which is used to maintain or increase reservoir pressure and to help sweep oil to the wellbore. In a waterflood, certain wells are used to inject water into the reservoir while other wells are used to recover the oil in place. We utilize waterflooding as a secondary recovery technique for the majority of our oil field projects.

As the waterflood matures, the fluid produced contains increasing amounts of water and decreasing amounts of oil. Surface equipment is used to separate the oil from the water, with the oil going to holding tanks for sale and the water being recycled to the injection facilities. In the Black Oaks Project, we realized an initial increase of approximately 20 barrels per day in oil production as a result of the waterflood pilot program.

In addition, we may utilize 3-D seismic analysis, horizontal drilling, and other technologies and production techniques to improve drilling results and ultimately enhance our production and returns. We also believe use of such technologies and production techniques in exploring for, developing and exploiting oil and natural gas properties will help us reduce drilling risks, lower finding costs and provide for more efficient production of oil and natural gas from our properties.

Markets and Marketing

The natural gas and oil industry has experienced dramatic price volatility in recent years, and especially in recent months. As a commodity, global natural gas and oil prices respond to macro-economic factors affecting supply and demand. In particular, world oil prices have risen and fallen in response to political unrest and supply uncertainty in the United States, Iraq, Venezuela, Nigeria, Russia and Iran, and changing demand for energy in rapidly growing economies, notably India and China. North American prospects have become more attractive as efforts to stimulate the US economy and reduce dependence on foreign oil increase. Escalating conflicts in the Middle East and the ability of OPEC to control supply and pricing are some of the factors impacting the availability of global supply. The costs of steel and other products used to construct drilling rigs and pipeline infrastructure, as well as drilling and well-servicing rig rates, are impacted by the commodity price volatility.

Our market is affected by many factors beyond our control, such as the availability of other domestic production, commodity prices, the proximity and capacity of natural gas and oil pipelines, and general fluctuations of global and domestic supply and demand. We have entered into two sales contracts (with Coffeyville and BP) at this time, and we do not anticipate difficulty in finding additional sales opportunities, as and when needed.

Natural gas and oil sales prices are negotiated based on factors such as the spot price for natural gas or posted price for oil, price regulations, regional price variations, hydrocarbon quality, distances from wells to pipelines, well pressure, and estimated reserves. Many of these factors are outside our control. Natural gas and oil prices have historically experienced high volatility, related in part to ever-changing perceptions within the industry of future supply and demand.

Competition

The natural gas and oil industry is intensely competitive and we must compete against larger companies that may have greater financial and technical resources than we do and substantially more experience in our industry. These competitive advantages may better enable our competitors to sustain the impact of higher exploration and production costs, natural gas and oil price volatility, productivity variances between properties, overall industry cycles and other factors related to our industry. Their advantage may also negatively impact our ability to acquire prospective properties, develop reserves, attract and retain quality personnel and raise capital.

Research and Development Activities

We have not spent any material amount of time in the last two fiscal years on research and development activities.

Governmental Regulations

Regulation of Oil and Natural Gas Production. Our oil and natural gas exploration, production and related operations, when developed, are subject to extensive rules and regulations promulgated by federal, state, tribal and local authorities and agencies. For example, some states in which we may operate, including Kansas, require permits for drilling operations, drilling bonds and reports concerning operations and impose other requirements relating to the exploration and production of oil and natural gas. Such states may also have statutes or regulations addressing conservation matters, including provisions for the unitization or pooling of oil and natural gas properties, the establishment of maximum rates of production from wells, and the regulation of spacing, plugging and abandonment of such wells. Failure to comply with any such rules and regulations can result in substantial penalties. Moreover, such states may place burdens from previous operations on current lease owners, and the burdens could be significant. The regulatory burden on the oil and natural gas industry will most likely increase our cost of doing business and may affect our profitability. Although we believe we are currently in substantial compliance with all applicable laws and regulations, because such rules and regulations are frequently amended or reinterpreted, we are unable to predict the future cost or impact of complying with such laws. Significant expenditures may be required to comply with governmental laws and regulations and may have a material adverse effect on our financial condition and results of operations.

Federal Regulation of Natural Gas. The Federal Energy Regulatory Commission (“FERC”) regulates interstate natural gas transportation rates and service conditions, which may affect the marketing of natural gas produced by us, as well as the revenues that may be received by us for sales of such production. Since the mid-1980’s, FERC has issued a series of orders, culminating in Order Nos. 636, 636-A and 636-B (“Order 636”), that have significantly altered the marketing and transportation of natural gas. Order 636 mandated a fundamental restructuring of interstate pipeline sales and transportation service, including the unbundling by interstate pipelines of the sale, transportation, storage and other components of the city-gate sales services such pipelines previously performed. One of FERC’s purposes in issuing the order was to increase competition within all phases of the natural gas industry. The United States Court of Appeals for the District of Columbia Circuit largely upheld Order 636 and the Supreme Court has declined to hear the appeal from that decision. Generally, Order 636 has eliminated or substantially reduced the interstate pipelines’ traditional role as wholesalers of natural gas in favor of providing only storage and transportation service, and has substantially increased competition and volatility in natural gas markets.

The price we may receive from the sale of oil and natural gas liquids will be affected by the cost of transporting products to markets. Effective January 1, 1995, FERC implemented regulations establishing an indexing system for transportation rates for oil pipelines, which, generally, would index such rates to inflation, subject to certain conditions and limitations. We are not able to predict with certainty the effect, if any, of these regulations on our intended operations. However, the regulations may increase transportation costs or reduce well head prices for oil and natural gas liquids.

Environmental Matters

Our operations and properties are subject to extensive and changing federal, state and local laws and regulations relating to environmental protection, including the generation, storage, handling, emission, transportation and discharge of materials into the environment, and relating to safety and health. The recent trend in environmental legislation and regulation generally is toward stricter standards, and this trend will likely continue.

These laws and regulations may:

require the acquisition of a permit or other authorization before construction or drilling commences and for certain other activities;

limit or prohibit construction, drilling and other activities on certain lands lying within wilderness and other protected areas; and

impose substantial liabilities for pollution resulting from its operations, or due to previous operations conducted on any leased lands.

The permits required for our operations may be subject to revocation, modification and renewal by issuing authorities. Governmental authorities have the power to enforce their regulations, and violations are subject to fines or injunctions, or both. In the opinion of management, we are in substantial compliance with current applicable environmental laws and regulations, and have no material commitments for capital expenditures to comply with existing environmental requirements. Nevertheless, changes in existing environmental laws and regulations or in interpretations thereof could have a significant impact on us, as well as the oil and natural gas industry in general.

The Comprehensive Environmental, Response, Compensation, and Liability Act, as amended (“CERCLA”), and comparable state statutes impose strict, joint and several liability on owners and operators of sites and on persons who disposed of or arranged for the disposal of “hazardous substances” found at such sites. It is not uncommon for the neighboring land owners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. The Federal Resource Conservation and Recovery Act, as amended (“RCRA”), and comparable state statutes govern the disposal of “solid waste” and “hazardous waste” and authorize the imposition of substantial fines and penalties for noncompliance. Although CERCLA currently excludes petroleum from its definition of “hazardous substance,” state laws affecting our operations may impose clean-up liability relating to petroleum and petroleum related products. In addition, although RCRA classifies certain oil field wastes as “non-hazardous,” such exploration and production wastes could be reclassified as hazardous wastes thereby making such wastes subject to more stringent handling and disposal requirements.

The Federal Water Pollution Control Act of 1972, as amended (“Clean Water Act”), and analogous state laws impose restrictions and controls on the discharge of pollutants into federal and state waters. These laws also regulate the discharge of storm water in process areas. Pursuant to these laws and regulations, we are required to obtain and maintain approvals or permits for the discharge of wastewater and storm water and develop and implement spill prevention, control and countermeasure plans, also referred to as “SPCC plans,” in connection with on-site storage of greater than threshold quantities of oil. The EPA issued revised SPCC rules in July 2002 whereby SPCC plans are subject to more rigorous review and certification procedures. We believe that our operations are in substantial compliance with applicable Clean Water Act and analogous state requirements, including those relating to wastewater and storm water discharges and SPCC plans.

The Endangered Species Act, as amended (“ESA”), seeks to ensure that activities do not jeopardize endangered or threatened animal, fish and plant species, nor destroy or modify the critical habitat of such species. Under ESA, exploration and production operations, as well as actions by federal agencies, may not significantly impair or jeopardize the species or its habitat. ESA provides for criminal penalties for willful violations of the Act. Other statutes that provide protection to animal and plant species and that may apply to our operations include, but are not necessarily limited to, the Fish and Wildlife Coordination Act, the Fishery Conservation and Management Act, the Migratory Bird Treaty Act and the National Historic Preservation Act. Although we believe that our operations will be in substantial compliance with such statutes, any change in these statutes or any reclassification of a species as endangered could subject us to significant expenses to modify our operations or could force us to discontinue certain operations altogether.

Personnel

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

Facilities

We currently maintain an office at 27 Corporate Woods, Suite 350, 10975 Grandview Drive, Overland Park, Kansas 66210. This space is leased pursuant to a five year lease that expires in August 2013.

MANAGEMENT

The following table sets forth certain information regarding our current directors and executive officers. Our executive officers serve one-year terms.

Name	Age	Position	Board Committee(s)(1)
C. Stephen Cochennet	53	President, Chief Executive Officer, and Chairman	None
Dierdre P. Jones	45	Chief Financial Officer	None
Robert G. Wonish	56	Director	GCNC (Chairman) and Audit
Daran G. Dammeyer	48	Director	Audit (Chairman) and GCNC
Darrel G. Palmer	51	Director	GCNC
Dr. James W. Rector	48	Director	None

(1)

“GCNC” means the Governance, Compensation and Nominating Committee of the Board of Directors. “Audit” means the Audit Committee of the Board of Directors.

C. Stephen Cochennet, has been our President, Chief Executive Officer and Chairman since August 15, 2006. Prior to joining EnerJex, Mr. Cochennet was President of CSC Group, LLC. Mr. Cochennet formed the CSC Group, LLC through which he supported a number of clients that included Fortune 500 corporations, international companies, natural gas/electric utilities, outsource service providers, as well as various start up organizations. The services provided included strategic planning, capital formation, corporate development, executive networking and transaction structuring. From 1985 to 2002, he held several executive positions with UtiliCorp United Inc. (Aquila) in Kansas City. His responsibilities included finance, administration, operations, human resources, corporate development, natural gas/energy marketing, and managing several new start up operations. Prior to his experience at UtiliCorp United Inc., Mr. Cochennet served 6 years with the Federal Reserve System. Mr. Cochennet graduated from the University of Nebraska with a B.A. in Finance and Economics.

Dierdre P. Jones was promoted to Chief Financial Officer on July 23, 2008. Ms. Jones was our Director of Finance and Accounting from August 2007 through July 2008. From May 2007 through August 2007, Ms. Jones provided independent consulting services for the company, primarily in the testing and implementation of financial accounting and reporting software. From May 2002 through May 2007, Ms. Jones was sole proprietor of These Faux Walls, a specialty design company. She holds the professional designations of Certified Public Accountant and Certified Internal Auditor. Prior to joining EnerJex, Ms. Jones held management positions with UtiliCorp United Inc. (Aquila), and served three years in public accounting with Arthur Andersen & Co. Ms. Jones graduated with distinction from the University of Kansas with a B.S. in Accounting and Business Administration.

Robert G. Wonish has served as a member of our board of directors since May 2007. Effective April 7, 2009, Mr. Wonish was appointed President and Chief Operating Officer of Petrodome Energy, LLC, a privately held firm. From December 2004 to June 30, 2007, Mr. Wonish was Vice President of Petroleum Engineers Inc., a subsidiary of The CYMRI Corporation, now CYMRI, L.L.C., which is a wholly-owned subsidiary of Stratum Holdings, Inc. On July 1, 2007, Mr. Wonish was appointed President and Chief Operating Officer of Petroleum Engineers Inc. Mr. Wonish was also President of CYMRI, L.L.C. After the sale of Petroleum Engineers Inc. in March of 2008, Mr. Wonish resigned all positions in Petroleum Engineers Inc. and CYMRI, L.L.C. as well as resigning as a member of the Stratum Holdings, Inc. board of directors. Mr. Wonish held the position of President & Chief Operating Officer of Striker Oil & Gas, Inc. prior to his engagement with Petrodome Energy, LLC.. He previously achieved positions of increasing responsibility with PANACO, Inc., a public oil and natural gas company, ultimately serving as that company’s President and Chief Operating Officer. He began his engineering career at Amoco in 1975 and joined Panaco’s engineering staff in 1992. Mr. Wonish serves as EnerJex’s chairman of the Governance, Compensation and Nominating committee and is a member of the company’s audit committee. Mr. Wonish received his Mechanical Engineering degree from the University of Missouri-Rolla.

Daran G. Dammeyer, has served as a member of our board of directors since May 2007. Since July 1999, Mr. Dammeyer has served as President of D-Two Solutions through which he supports clients by primarily providing merger and acquisition support, strategic planning, budgeting and forecasting process development and implementation. From March 1999 through July 1999, Mr. Dammeyer was a Director of International Financial Management for UtiliCorp United Inc. (Aquila), a multinational energy solutions provider in Kansas City, Missouri. From November 1995 through March 1999, Mr. Dammeyer served as the Chief Financial Controller of United Energy Limited in Melbourne, Australia. Mr. Dammeyer also served in numerous management positions at Michigan Energy Resources Company, including Director of Internal Audit. Mr. Dammeyer earned his Bachelor of Business Administration degree, with dual majors in Accounting and Corporate Financial Management from The University of Toledo, Ohio.

Darrel G. Palmer, has served as a member of our board of directors since May of 2007. Since January 1997, Mr. Palmer has been President of Energy Management Resources, an energy process management firm serving industrial and large commercial companies throughout the U. S. and Canada. Mr. Palmer has 25 years of expertise in the natural gas arena. His experiences encompass a wide area of the natural gas industry and include working for natural gas marketing companies, local distribution companies, and FERC regulated pipelines. Prior to becoming an independent energy consultant in 1997, Mr. Palmer’s last position was Vice President/National Account Sales at UtiliCorp United Inc. (Aquila) of Kansas City, Missouri. Over the years Mr. Palmer has worked in many civic organizations including United Way and has been a President of the local Kiwanis Club. Junior Achievement of Minnesota awarded him the Bronze Leadership Award for his accomplishments which included being an advisor, program manager, holding various Board positions, and ultimately being Board President.

Dr. James W. Rector, has served as a member of our board of directors since March 19, 2008. Dr. Rector is the author of numerous technical papers along with a number of patents on seismic technology. He was a co-founder of two seismic technology startups that were later sold to NYSE-listed companies, and he regularly consults for many of the major oil companies including Chevron and BP. In 1998, he founded Berkeley GeoImaging LLC, which has completed five equity private placements for oil and natural gas exploration and development projects. Dr. Rector is a tenured professor of Geophysics at the University of California at Berkeley and a faculty staff scientist at the Lawrence Berkeley National Laboratory. He has been the Editor-in-Chief of the Journal of Applied Geophysics and has also served on the Society of Exploration Geophysicists Executive Committee. He received his Masters and Ph.D. degrees in Geophysics from Stanford University.

Board of Directors

Our board of directors currently consists of five members. Our directors serve one-year terms. Our board of directors has affirmatively determined that Messrs. Wonish, Dammeyer, Palmer and Dr. Rector are independent directors, as defined by Section 803 of the American Stock Exchange Company Guide.

Committees of the Board of Directors

Our board of directors has two standing committees: an audit committee and a governance, compensation and nominating committee. Each of those committees has the composition and responsibilities set forth below.

Audit Committee

On May 4, 2007, we established and appointed initial members to the audit committee of our board of directors. Mr. Dammeyer is the chairman and Mr. Wonish serves as the other member of the committee. Currently, none of the members of the audit committee are, or have been, our officers or employees, and each member qualifies as an independent director as defined by Section 803 of the American Stock Exchange Company Guide and Section 10A(m) of the Securities Exchange Act of 1934, and Rule 10A-3 thereunder. The Board of Directors has determined that Mr. Dammeyer is an “audit committee financial expert” as that term is used in Item 401(h) of Regulation S-K promulgated under the Securities Exchange Act. The audit committee held five meetings during fiscal 2009.

The audit committee has the sole authority to appoint and, when deemed appropriate, replace our independent registered public accounting firm, and has established a policy of pre-approving all audit and permissible non-audit services provided by our independent registered public accounting firm. The audit committee has, among other things, the responsibility to evaluate the qualifications and independence of our independent registered public accounting firm; to review and approve the scope and results of the annual audit; to review and discuss with management and the independent registered public accounting firm the content of our financial statements prior to the filing of our quarterly reports and annual reports; to review the content and clarity of our proposed communications with investors regarding our operating results and other financial matters; to review significant changes in our accounting policies; to establish procedures for receiving, retaining, and investigating reports of illegal acts involving us or complaints or concerns regarding questionable accounting or auditing matters, and supervise the investigation of any such reports, complaints or concerns; to establish procedures for the confidential, anonymous submission by our employees of concerns or complaints regarding questionable accounting or auditing matters; and to provide sufficient opportunity for the independent auditors to meet with the committee without management present.

Governance, Compensation and Nominating Committee

The governance, compensation and nominating committee is comprised of Messrs. Wonish, Dammeyer and Palmer. Mr. Wonish serves as the chairman of the governance, compensation and nominating committee. The governance, compensation and nominating committee is responsible for, among other things; identifying, reviewing, and evaluating individuals qualified to become members of the Board, setting the compensation of the Chief Executive Officer and performing other compensation oversight, reviewing and recommending the nomination of Board members, and administering our equity compensation plans. The governance, compensation and nominating committee held five meetings during fiscal 2009.

NON-EMPLOYEE DIRECTOR COMPENSATION

The following table sets forth summary compensation information for the fiscal year ended March 31, 2009 for each of our non-employee directors.

Name	Fees Earned or Paid in Cash $		Stock Awards $			Option Awards (2) $		All Other Compensation $			Total $
Daran G. Dammeyer	$	58,000	$	12,000	(1)	$	-0-	$	-0-		$	70,000

Darrel G. Palmer	$	26,500	$	-0-		$	-0-	$	20,000	(3)	$	46,500

Robert G. Wonish	$	49,000	$	-0-		$	-0-	$	-0-		$	49,000

Dr. James W. Rector	$	22,500	$	-0-		$	-0-	$	-0-		$	22,500

(1)

Amount represents the estimated total fair market value of 2,182 shares of common stock issued to Mr. Dammeyer for services as audit committee chairman under SFAS 123(R), as discussed in Note 3 to our audited financial statements for the year ended March 31, 2009 included elsewhere in this prospectus.

(2)

In July, 2008, 28,000 stock options were granted to each of Messrs. Dammeyer, Palmer and Wonish and 38,000 stock options were granted to Dr. Rector under SFAS 123(R), as discussed in Note 3 to our financial statements for the year ended March 31, 2009 included elsewhere in this prospectus. These total 122,000 options granted to Messrs. Dammeyer, Palmer and Wonish and to Dr. Rector were rescinded in November 2008.

(3)

Mr. Palmer was paid $20,000 for assisting in the establishment and development of the audit committee and for his involvement and assistance to the chief executive officer in finalizing the hedging instrument with BP.

Board compensation was set for fiscal 2009 upon the recommendation of an independent compensation consultant and the governance, compensation and nominating committee of the board of directors. The annual retainer for non-employee directors is $20,000 with a meeting fee of $1,500 for those in attendance and $750 for those who participate by telephone. The chairman of the audit committee will be paid an annual retainer of $42,000, payable with $2,500 per month in cash and $12,000 worth of common stock. Members of the audit committee will be paid an annual cash retainer of $15,000 and $375 per meeting attended. The chairman of the governance, compensation and nominating committee will be paid an annual cash retainer of $8,000, payable quarterly, while members of that committee will be paid an annual cash retainer of $2,000, payable quarterly, and $375 per meeting attended. In addition, the directors are reimbursed for expenses incurred in connection with board and committee membership.

On August 3, 2009, in an effort for us to preserve cash in light of deteriorated global economic conditions and the significant declines in commodity prices of oil and natural gas, each of our non-employee directors agreed to convert their board/committee retainers for the period from July 1, 2009 through September 30, 2009 into 32,000 shares of our restricted common stock.

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

EXECUTIVE COMPENSATION

The following table sets forth summary compensation information for the fiscal years ended March 31, 2009 and 2008 for our chief executive officer and chief financial officer. We did not have any other executive officers as of the end of fiscal 2009 whose total compensation exceeded $100,000. We refer to these persons as our named executive officers elsewhere in this prospectus.

Summary Compensation Table

Name and Principal Position	Fiscal Year	Salary ($)			Bonus ($)			Option Awards ($)			All Other Compen- sation ($)			Total ($)

C. Stephen Cochennet	2009	$	186,525		$	50,000		$	-	(2)	$	-		$	236,525
President, Chief Executive Officer	2008	$	156,000			-			859,622	(1)		-		$	1,015,622
Dierdre P. Jones	2009	$	128,808		$	10,000			-	(2)		-		$	138,808
Chief Financial Officer	2008		-	(3)		-	(3)		-	(3)		-	(3)		-	(3)

(1)

Amount represents the estimated total fair value of stock options granted to Mr. Cochennet under SFAS 123(R). These options were exchanged for shares of restricted common stock in August of 2009.

(2)

In August, 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, and option to purchase 40,000 shares of our common stock at $6.25 per share under SFAS 123(R) as discussed in Note 3 to our financial statements for the year ended March 31, 2009 included elsewhere in this prospectus. These options were rescinded in November 2008 at the request of the board’s compensation committee and the approval of each option holder.

(3)

Ms. Jones was promoted to chief financial officer during fiscal 2009 and was not a named executive officer in fiscal 2008.

Outstanding Equity Awards at Fiscal Year-End

The following table lists the outstanding equity incentive awards held by our named executive officers as of March 31, 2009.

		Option Awards
	Fiscal Year	Number of Securities Underlying Unexercised Options Exercisable (#)			Number of Securities Underlying Unexercised Options Unexercisable (#)		Number of Securities Underlying Unexercised Unearned Options (#)		Option Exercise Price ($)		Option Expiration Date

C. Stephen Cochennet	2009		200,000	(1)		-		-	$	6.25	05/03/2011
Dierdre P. Jones	2009		20,000	(2)		-		-	$	6.30	07/31/2011

(1)

These options were exchanged for 50,000 shares of restricted common stock in August of 2009.

(2)

These options were exchanged for 5,000 shares of restricted common stock in August of 2009.

Potential Payments Upon Termination or Change in Control

We entered into employment agreements with both of our named executive officers which could result in payments to such officers because of their resignation, incapacity or disability, or other termination of employment with us or our subsidiaries, or a change in control, or a change in the person’s responsibilities following a change in control.

Option Exercises for fiscal 2009

There were no options exercised by our named executive officers in fiscal 2009.

2000/2001 Stock Option Plan

The board of directors approved the 2000/2001 Stock Option Plan and our stockholders ratified the plan on September 25, 2000. The total number of options that can be granted under the plan is 200,000 shares and all such shares were previously granted to Mr. Cochennet. On August 3, 2009, we exchanged these outstanding options for 50,000 shares of our restricted common stock. Therefore, all 200,000 shares reserved for issuance under this plan are again available for issuance.

Stock Incentive Plan

The board of directors approved the EnerJex Resources, Inc. Stock Option Plan on August 1, 2002 (the “2002-2003 Stock Option Plan”). Originally, the total number of options that could be granted under the 2002-2003 Stock Option Plan was not to exceed 400,000 shares. In September 2007 our stockholders approved a proposal to amend and restate the 2002-2003 Stock Option Plan to increase the number of shares issuable to 1,000,000. On October 14, 2008 our stockholders approved a proposal to amend and restate the 2002-2003 Stock Option Plan to (i) rename it the EnerJex Resources, Inc. Stock Incentive Plan (the “Stock Incentive Plan”), (ii) increase the maximum number of shares of our common stock that may be issued under the Stock Incentive Plan from 1,000,000 to 1,250,000, and (iii) add restricted stock as an eligible award that can be granted under the Stock Incentive Plan.

We had previously granted 238,500 options under this plan. On August 3, 2009, we exchanged all 238,500 outstanding options for 59,700 shares of our restricted common stock. In addition, we granted 151,750 shares of restricted common stock under the Stock Incentive Plan to employees for fiscal 2009 bonuses and 59,300 shares to our officers and directors for the prior rescission of stock options in fiscal 2008.

General Terms of Plans

Officers (including officers who are members of the board of directors), directors, and other employees and consultants and our subsidiaries (if established) will be eligible to receive awards under the 2000/2001 Stock Option Plan and the Stock Incentive Plan. A committee of the board of directors will administer the plans and will determine those persons to whom awards will be granted, the number of and type of awards to be granted, the provisions applicable to each grant and the time periods during which the awards may be exercised. No awards may be granted more than ten years after the date of the adoption of the plans.

Non-qualified stock options will be granted by the committee with an option price equal to the fair market value of the shares of common stock to which the non-qualified stock option relates on the date of grant. The committee may, in its discretion, determine to price the non-qualified option at a different price. In no event may the option price with respect to an incentive stock option granted under the plans be less than the fair market value of such common stock to which the incentive stock option relates on the date the incentive stock option is granted. However the price of an incentive stock option will not be less than 110% of the fair market value per share on the date of the grant in the case of an individual then owning more than 10% of the total combined voting power of all classes of stock of the corporation.

Each option granted under the plans will be exercisable for a term of not more than ten years after the date of grant. Certain other restrictions will apply in connection with the plans when some awards may be exercised.

Restricted stock will have full dividend, voting and other ownership rights, unless otherwise indicated in the applicable award agreement pursuant to which it is granted. If any dividends or distributions are paid in shares of common stock during the restricted period, the applicable award agreement may provide that such shares will be subject to the same restrictions as the restricted stock with respect to which they were paid.

These plans are intended to encourage directors, officers, employees and consultants to acquire ownership of common stock. The opportunity so provided is intended to foster in participants a strong incentive to put forth maximum effort for our continued success and growth, to aid in retaining individuals who put forth such effort, and to assist in attracting the best available individuals in the future.

Limitation of Liability of Directors

Pursuant to the Nevada General Corporation Law, our articles of incorporation exclude personal liability for our directors for monetary damages based upon any violation of their fiduciary duties as directors, except as to liability for any breach of the duty of loyalty, acts or omissions not in good faith or which involve intentional misconduct or a knowing violation of law, or any transaction from which a director receives an improper personal benefit. This exclusion of liability does not limit any right which a director may have to be indemnified and does not affect any director’s liability under federal or applicable state securities laws. We have agreed to indemnify our directors against expenses, judgments, and amounts paid in settlement in connection with any claim against a director if he acted in good faith and in a manner he believed to be in our best interests.

Employment Agreements

C. Stephen Cochennet – Chief Executive Officer

On August 1, 2008, we entered into an employment agreement with C. Stephen Cochennet, our president and chief executive officer. Mr. Cochennet’s employment agreement was approved by the governance, compensation and nominating committee of our board of directors.

In general, Mr. Cochennet’s employment agreement contains provisions concerning terms of employment, voluntary and involuntary termination, indemnification, severance payments, and other termination benefits, in addition to a non-compete clause and certain other perquisites, such as long-term disability insurance, director and officer insurance, and an automobile allowance. The original term of Mr. Cochennet’s employment agreement runs from August 1, 2008 until July 31, 2011. The term of the employment agreement is automatically extended for additional one year terms unless otherwise terminated in accordance with its terms.

Mr. Cochennet’s employment agreement provides for an initial annual base salary of $200,000, which may be adjusted by the governance, compensation and nominating committee or our board of directors.

In addition, Mr. Cochennet is eligible to receive an annual bonus of up to 100% of his applicable base salary in cash or shares of restricted stock (if approved by stockholders) subject to our obtaining certain business objectives established by our board of directors. In addition Mr. Cochennet is eligible to receive long-term incentives of up to 135,000 options to purchase shares of our common stock based upon our achievement of specified performance targets. Additional information regarding these options is set forth in the following table.

	Potential	Maximum #		Option
Fiscal Year	Grant Date	of Options	Strike Price of Options	Expiration Date*
2009	7/01/2009	30,000	Fair market value on grant date	6/30/2012
2010	7/01/2010	45,000	Fair market value on grant date	6/30/2013
2011	7/01/2011	60,000	Fair market value on grant date	6/30/2014

__________________

The options shall be immediately vested and exercisable from the grant date through the option expiration date.

The number of stock options granted each fiscal year shall be based upon a schedule set forth in Mr. Cochennet’s employment agreement and will be prorated if actual performance does not equal or exceed 100% of the targeted performance conditions. Mr. Cochennet must be employed by us on the grant date to receive the stock options.

The maximum number of options available to be earned by Mr. Cochennet each year is subject to a “catch-up” provision, such that if an element in any year is missed, it may be “caught-up” in a subsequent year, so long as the cumulative goal is met. For example, if the 2009 share price element of $11.00 is not met by March 31, 2009, Mr. Cochennet would still be able to earn the available options for this element if our share price is at least $16.85 on March 31, 2010, or $22.55 on March 31, 2011. Any caught-up options would be granted at the then current stock price. The cumulative goal for Mr. Cochennet’s long-term incentive compensation is comprised of three factors; a 35% year over year net reserve growth (40% of the goal), a 35% year over year net production increase (30% of the goal), and the previously stated share price increases (30% of the goal).

As consideration for his efforts during fiscal 2008 we also agreed to pay Mr. Cochennet a $50,000 cash bonus and grant him 75,000 options to purchase shares of our common stock at $6.25 per share; 30,000 vested immediately upon grant and the remaining 45,000 were to vest over a three year period. These options were rescinded in November 2008 at the request of the board’s compensation committee and with the approval of Mr. Cochennet in an effort to reduce compensation expense which, through non-cash, would have had a substantial negative impact on our financial statements and results of operations for the quarter ended September 30, 2008. Shares subject to these options were returned to the plan and are available for future issuance. On August 3, 2009, we issued Mr. Cochennet 18,800 shares of twelve month restricted stock in consideration for the prior rescission of the options discussed above.

In the event of a termination of employment with us by Mr. Cochennet for “good reason”, which includes by reason of a “change of control”, or by us without “cause” (each as defined in the employment agreement), Mr. Cochennet would receive: (i) a lump sum payment equal to all earned but unpaid base salary through the date of termination of employment; (ii) a lump sum payment equal to the annual incentive amount (assuming achievement at 100% of target) that Mr. Cochennet would have earned if he had remained employed through June 30th following the last day of the current fiscal year; (iii) a lump sum payment equal to an amount equal to the lesser of (a) 12-months base salary or (b) the base salary Mr. Cochennet would have received had he remained in employment through the end of the then-existing term of the agreement; and (iv) immediate vesting of all equity awards (including but not limited to stock options and restricted shares).

In the event of a termination of Mr. Cochennet’s employment with us by reason of incapacity, disability or death, Mr. Cochennet, or his estate, would receive: (i) a lump sum payment equal to all earned but unpaid base salary through the date of termination of employment or death; (ii) a lump sum payment equal to the annual incentive amount (assuming achievement at 100% of target) that Mr. Cochennet would have earned if he had remained employed through June 30th following the last day of the current fiscal year; and (iii) a lump sum payment equal to an amount equal to six-months base salary.

In the event of a termination of Mr. Cochennet’s employment by us for “cause” (as defined in the employment agreement), Mr. Cochennet would receive all earned but unpaid base salary through the date of termination of employment. However, if a dispute arises between us and Mr. Cochennet that is not resolved within 60 days and neither party initiates arbitration proceedings pursuant to the terms of the employment agreement, we will have the option to pay Mr. Cochennet a lump sum payment equal to six-months base salary in lieu of any and all other amounts or payments to which Mr. Cochennet may be entitled relating to his employment.

Dierdre P. Jones – Chief Financial Officer

On July 23, 2008, Dierdre P. Jones, our former director of finance and accounting, was appointed our chief financial officer. On August 1, 2008, we entered into an employment agreement with Ms. Jones. The employment agreement was approved by the governance, compensation and nominating committee of our board of directors.

In general, Ms. Jones’ employment agreement contains provisions concerning terms of employment, voluntary and involuntary termination, indemnification, severance payments, and other termination benefits, in addition to certain other perquisites. The original term of the employment agreement runs from August 1, 2008 until July 31, 2011.

Ms. Jones’ employment agreement provides for an initial annual base salary of $140,000, which may be adjusted by the governance, compensation and nominating committee or our board of directors.

In addition, Ms. Jones is eligible to receive an annual bonus up to 30% of her applicable base salary and is also eligible to participate in other incentive programs established by us.

We granted Ms. Jones 40,000 options to purchase shares of our common stock at $6.25 per share for a period of three years, which vested immediately upon grant. These options were rescinded in November 2008 at the request of the board’s compensation committee and with the approval of Ms. Jones in an effort to reduce compensation expense which, through non-cash, would have had a substantial negative impact on our financial statements and results of operations for the quarter ended September 30, 2008. Shares subject to these options were returned to the plan and are available for future issuance. On August 3, 2009, we issued Ms. Jones 10,000 shares of twelve month restricted stock in consideration for the prior rescission of the options discussed above.

In the event of a termination of employment by Jones for “good reason” prior to a “change of control” or by us without “cause” prior to a “change of control” (each as defined in the employment agreement), Ms. Jones would receive: (i) a lump sum payment equal to 12 months of her salary; plus (ii) a lump sum payment equal to the prorated portion of her bonus through the date of termination; plus (iii) all unvested stock or options held by Jones shall immediately vest and become exercisable for the full term set forth in such stock option or equity award agreements; plus (iv) health insurance premiums for a period of 12 months.

In the event of the termination of Ms. Jones’ employment by us in connection with a “change of control” (as defined in the employment agreement), without cause within 12 months of a “change of control”, or by Ms. Jones for “good reason” within 12 months of a “change of control,” Ms. Jones shall be entitled to: (i) a lump sum payment equal to 12 months of her salary; plus (ii) a lump sum payment equal to 100% of her prior year’s bonus; plus (iii) all unvested stock or options held by Jones shall immediately vest and become exercisable for the full term set forth in such stock option or equity award agreements; plus (iv) health insurance premiums for a period of 12 months.

CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

We describe below transactions and series of similar transactions that have occurred during fiscal 2009 and during the fiscal years ended March 31, 2008, 2007 and 2006 to which we were a party or will be a party in which:

•

The amounts involved exceeds the lesser of $120,000 or one percent of the average of our total assets at year end for the last two completed fiscal years; and

•

A director, executive officer, holder of more than 5% of our common stock or any member of their immediate family had or will have a direct or indirect material interest.

On March 14, 2006 and July 21, 2006, we paid consulting fees totaling $121,000 in connection with financing activities to Goran Blagojevic, a stockholder.

Our board of directors has affirmatively determined that Messrs. Wonish, Dammeyer, Palmer and Dr. Rector are independent directors, as defined by Section 803 of the American Stock Exchange Company Guide. Mr. Palmer is not eligible to serve on our Audit Committee pursuant to Section 10A(m)(3) of the Securities Exchange Act of 1934, as amended.

PRINCIPAL STOCKHOLDERS

The following table presents information, to the best of EnerJex’s knowledge, about the ownership of EnerJex’s common stock on February 22, 2010 relating to those persons known to beneficially own more than 5% of EnerJex’s capital stock and by EnerJex’s directors and executive officers. The percentage of beneficial ownership for the following table is based on 4,979,928 shares of common stock outstanding.

Beneficial ownership is determined in accordance with the rules of the Securities and Exchange Commission and does not necessarily indicate beneficial ownership for any other purpose. Under these rules, beneficial ownership includes those shares of common stock over which the stockholder has sole or shared voting or investment power. It also includes shares of common stock that the stockholder has a right to acquire within 60 days after February 22, 2010 pursuant to options, warrants, conversion privileges or other right. The percentage ownership of the outstanding common stock, however, is based on the assumption, expressly required by the rules of the Securities and Exchange Commission, that only the person or entity whose ownership is being reported has converted options or warrants into shares of EnerJex’s common stock.

Name and Address of Beneficial Owner, Officer or Director(1)	Number of Shares			Percent of Outstanding Shares of Common Stock(2)

C. Stephen Cochennet, President & Chief Executive Officer(3)		542,061	(4)		10.9	%
Dierdre P. Jones, Chief Financial Officer(3)		15,000	(5)		*
Robert (Bob) G. Wonish, Director(3)		32,000			*
Darrel G. Palmer, Director(3)		32,000			*
Daran G. Dammeyer, Director(3)		48,102			*
Dr. James W. Rector, Director(3)		24,500			*

Directors and Officers as a Group		693,663			13.9	%

West Coast Opportunity Fund LLC(6)		1,486,153			29.8	%
West Coast Asset Management, Inc.
Paul Orfalea, Lance Helfert & R. Atticus Lowe
2151 Alessandro Drive, #100
Ventura, CA 93001

Enable Growth Partners L.P.(7)		286,270			5.7	%
Enable Capital Management, LLC
Mitchell S. Levine
One Ferry Building, Suite 225
San Francisco, CA 94111

Represents beneficial ownership of less than 1%

(1)

As used in this table, “beneficial ownership” means the sole or shared power to vote, or to direct the voting of, a security, or the sole or shared investment power with respect to a security (i.e., the power to dispose of, or to direct the disposition of, a security).

(2)

Figures are rounded to the nearest tenth of a percent.

(3)

The address of each person is care of EnerJex Resources: Corporate Woods 27, Suite 350, 10975 Grandview Drive, Overland Park, Kansas 66210.

(4)

Does not include 75,000 shares of restricted stock that could be issued on August 4, 2010 if Mr. Cochennet remains an employee of EnerJex through August 3, 2010.

(5)

Does not include 20,000 shares of restricted stock that could be issued on August 4, 2010 if Ms. Jones remains an employee of EnerJex through August 3, 2010.

(6)

Based on a Schedule 13D/A filed with the SEC on February 16, 2010, the investment manager of West Coast Opportunity Fund, LLC (“WCOF”) is West Coast Asset Management (“WCAM”). WCAM has the authority to take any and all actions on behalf of WCOF, including voting any shares held by WCOF. Paul Orfalea, Lance Helfert and R. Atticus Lowe constitute the Investment Committee of WCOF. Messrs. Orfalea, Helfert and Lowe disclaim beneficial ownership of the shares. Includes 500,000 shares of common stock underlying the potential conversion of a $1,500,000 debenture currently held by WCOF.

(7)

Based on a Schedule 13G/A filed with the SEC on February 11, 2010, Enable Capital Management, LLC, as general and investment manager of Enable Growth Partners L.P. and other clients, may be deemed to have the power to direct the voting or disposition of shares of common stock held by Enable Growth Partners L.P. and other clients. Therefore, Energy Capital Management, LLC, as Enable Growth Partners L.P.’s and those other accounts’ general partner and investment manager, and Mitchell S. Levine, as managing member and majority owner of Enable Capital Management, LLC, may be deemed to beneficially own the shares of common stock owned by Enable Growth Partners L.P. and such other accounts.

DESCRIPTION OF CAPITAL STOCK

Common Stock

Our articles of incorporation authorize the issuance of 100,000,000 shares of common stock, $0.001 par value per share, of which 4,979,928 shares were outstanding as of February 22, 2010. Holders of common stock have no cumulative voting rights. Holders of shares of common stock are entitled to share ratably in dividends, if any, as may be declared, from time to time by the board of directors in its discretion, from funds legally available to be distributed. In the event of a liquidation, dissolution or winding up of us, the holders of shares of common stock are entitled to share pro rata all assets remaining after payment in full of all liabilities. Holders of common stock have no preemptive rights to purchase our common stock. There are no conversion rights or redemption or sinking fund provisions with respect to the common stock. All of the outstanding shares of common stock are validly issued, fully paid and non-assessable.

Preferred Stock

Our articles of incorporation authorizes the issuance of 10,000,000 shares of preferred stock, $0.001 par value per share, of which no shares were outstanding as of the date of this prospectus. The preferred stock may be issued from time to time by the board of directors as shares of one or more classes or series. Our board of directors, subject to the provisions of our articles of incorporation and limitations imposed by law, is authorized to:

• adopt resolutions;

• issue the shares;

• fix the number of shares;

• change the number of shares constituting any series; and

• provide for or change the following:

• the voting powers;

• designations;

• preferences; and

• relative, participating, optional or other special rights, qualifications, limitations or restrictions, including the following:

• dividend rights, including whether dividends are cumulative;

• dividend rates;

• terms of redemption, including sinking fund provisions;

• redemption prices;

• conversion rights; and

• liquidation preferences of the shares constituting any class or series of the preferred stock.

In each of the listed cases, we will not need any further action or vote by the stockholders.

One of the effects of undesignated preferred stock may be to enable the board of directors to render more difficult or to discourage an attempt to obtain control of us by means of a tender offer, proxy contest, merger or otherwise, and thereby to protect the continuity of our management. The issuance of shares of preferred stock pursuant to the board of director’s authority described above may adversely affect the rights of holders of common stock. For example, preferred stock issued by us may rank prior to the common stock as to dividend rights, liquidation preference or both, may have full or limited voting rights and may be convertible into shares of common stock. Accordingly, the issuance of shares of preferred stock may discourage bids for the common stock at a premium or may otherwise adversely affect the market price of the common stock.

Debenture Financing

On April 11, 2007, we entered into financing agreements for $9.0 million of senior secured debentures. The debentures mature on September 30, 2010 and bear an interest rate equal to 10% per annum. In accordance with the terms of the debentures, we received $6.3 million (before expenses and placement fees) at the first closing on April 13, 2007 and an additional $2.7 million on June 21, 2007. Net proceeds from the debentures were approximately $8.3 million, after approximately $700,000 in fees and expenses to our placement agent, C. K. Cooper & Company, attorney’s fees and post-closing fees and expenses. On July 7, 2008, we redeemed debentures with an aggregate principal amount of $6.3 million with proceeds from our new senior secured credit facility. We also amended the remaining $2.7 million of aggregate principal Debentures to, among other things, permit the indebtedness under our Credit Facility, subordinate the security interests of the debentures to the Credit Facility, provide for the redemption of the remaining Debentures with the net proceeds from any next debt or equity offering and eliminate the covenant to maintain certain production thresholds. Further, in June 2009 we amended the Debentures to allow us to pay interest in either cash or payment-in-kind interest (an increase in the amount of principal due) or payment-in-kind shares (issuance of shares of common stock), and add a provision for the conversion of the debentures into shares of our common stock. Further, in November 2009, we amended the debentures to amend the company redemption section of the debentures to allow for the retirement of shares of our common stock held by the debenture holders if we meet certain redemption payment schedules and to amend the debenture holders’ rights to participate in certain future debt or equity offerings made by us. In January 2010, we further amended the Debentures to extend the scheduled due dates for the January and February 2010 redemption payments to March 10, 2010.

In connection with the sale of the debentures, we issued the debenture holders 1,800,000 shares of common stock (1,260,000 shares of common stock were issued on April 13, 2007 and 540,000 shares of common stock were issued on June 21, 2007).

Right to Redeem Debenture. So long as a registration statement covering all of the registrable securities is effective, we have the option of prepaying the principal, in whole but not in part by paying the amount equal to 100% of the principal, together with accrued and unpaid interest by giving six (6) business days prior notice of redemption to the lenders. During the quarter ended June 30, 2009, we repurchased $450,000 of the Debentures. In November of 2009 we amended the debentures to allow for the retirement of shares of our common stock held by the debenture holders on a 0.5 share for each $1.00 redeemed if we meet certain redemption payment schedules.

Interest. Interest is payable quarterly in arrears on the first day of each succeeding quarter. The interest rate is 10% per annum for cash interest payments. The payment-in-kind interest rate is equal to 12.5% per annum. If interest payments are made through payment-in-kind interest, we must issue common stock equal to and additional 2.5% of the quarterly interest payment due.

Registration Rights. Pursuant to the terms of the Registration Rights Agreement, as amended, we are obligated to register 1,000,000 shares of common stock issuable under the debentures.

If we fail to obtain and maintain the effectiveness of this registration statement through a date which the lender may sell all of its shares of common stock without restriction under Rule 144 of the Securities Act or the date on which the debenture holders shall have sold all of its shares of common required to be covered by this registration statement, we will be obligated to pay cash to this debenture holders equal to 1.5% of the aggregate purchase price allocable to such lender’s registrable securities included in such registration statement for each 30 day period following such effectiveness failure or maintenance failure. These payments are capped at 10% of the lender’s original purchase price as defined in the registration rights agreement.

Conversion Rights. The conversion price on or before May 31, 2010 is equal to $3.00 per share. From June 1, 2010 through the maturity date, assuming the Debentures have not been redeemed, the conversion price per share shall be computed as 100.0% of the arithmetic average of the weighted average price of the common stock on each of the thirty (30) consecutive Trading Days immediately preceding the conversion date.

Preemptive Rights. So long as any debenture is outstanding, the debenture holders have the right to participate in any subsequent issuance of equity or equity equivalent securities up to each holder’s pro rata portion, based on the holder’s ownership of shares of common stock compared to the then-outstanding shares of common stock. At least five days before the closing of a subsequent issuance, we must give each debenture holder written notice of the issuance and each debenture holder may request specified additional information and may elect to participate in the issuance.

The preemptive rights do not apply to specified issuances, including: (1) options issued pursuant to an employee benefit plan for up to 1,000,000 options on specified terms; (2) securities issued in a bona fide underwritten public offering; and (3) issuances for services performed, at a value not less than $3.00 per share.

Additional Restrictions and Operational Covenants. In addition to standard covenants and conditions such as us maintaining our reporting status with the SEC pursuant to the Exchange Act, the debentures contain certain restrictions regarding our operations, including limitations on our ability to incur liens or additional debt, pay dividends, redeem our stock, make specified investments and engage in merger, consolidation or asset sale transactions, among other restrictions.

Nevada Anti-Takeover Law and Charter and By-law Provisions

Depending on the number of residents in the state of Nevada who own our shares, we could be subject to the provisions of Sections 78.378 et seq. of the Nevada Revised Statutes which, unless otherwise provided in a company’s articles of incorporation or by-laws, restricts the ability of an acquiring person to obtain a controlling interest of 20% or more of our voting shares. Our articles of incorporation and by-laws do not contain any provision which would currently keep the change of control restrictions of Section 78.378 from applying to us.

We are subject to the provisions of Sections 78.411 et seq. of the Nevada Revised Statutes. In general, this statute prohibits a publicly held Nevada corporation from engaging in a “combination” with an “interested stockholder” for a period of three years after the date of the transaction in which the person became an interested stockholder, unless the combination or the transaction by which the person became an interested stockholder is approved by the corporation’s board of directors before the person becomes an interested stockholder. After the expiration of the three-year period, the corporation may engage in a combination with an interested stockholder under certain circumstances, including if the combination is approved by the board of directors and/or stockholders in a prescribed manner, or if specified requirements are met regarding consideration. The term “combination” includes mergers, asset sales and other transactions resulting in a financial benefit to the interested stockholder. Subject to certain exceptions, an “interested stockholder” is a person who, together with affiliates and associates, owns, or within three years did own, 10% or more of the corporation’s voting stock. A Nevada corporation may “opt out” from the application of Section 78.411 et seq. through a provision in its articles of incorporation or by-laws. We have not “opted out” from the application of this section.

Apart from Nevada law, however, our articles of incorporation and by-laws do not contain any provisions which are sometimes associated with inhibiting a change of control from occurring (i.e., we do not provide for a staggered board, or for “super-majority” votes on major corporate issues). However, we do have 10,000,000 shares of authorized “blank check” preferred stock, which could be used to inhibit a change in control.

Liability and Indemnification of Officers and Directors

Our articles of incorporation and by-laws provide that our directors and officers shall not be personally liable to us or our stockholders for damages for breach of fiduciary duty as a director or officer, except for liability for (a) acts of omissions which involve intentional or reckless conduct, fraud or a knowing violation of law, or (b) the payment of distributions in violation of Section 78.300 of the Nevada Revised Statutes.

In addition, on October 14, 2008, we entered into identical indemnification agreements with each member of our board of directors and each of our executive officers (the “Indemnification Agreements”). The Indemnification Agreements provide that we will indemnify each such director or executive officer to the fullest extent permitted by Nevada law if he or she becomes a party to or is threatened with any action, suit or proceeding arising out of his or her service as a director or executive officer. The Indemnification Agreements also provide that we will advance, if requested by an indemnified person, any and all expenses incurred in connection with any such proceeding, subject to reimbursement by the indemnified person should a final judicial determination be made that indemnification is not available under applicable law. The Indemnification Agreements further provide that if we maintain directors’ and officers’ liability coverage, each indemnified person shall be included in such coverage to the maximum extent of the coverage available for our directors or executive officers.

Transfer Agent

The transfer agent for our common stock is Standard Registrar & Transfer Company Inc., 12528 South 1840 East, Draper, Utah 84020.

SELLING STOCKHOLDER

The Selling Stockholder named in the table below is offering for resale up to 1,390,000 shares of our common stock. We are registering the shares covered hereby to permit the Selling Stockholder to offer the shares for resale from time to time. Other than the ownership of our shares of common stock, the Selling Stockholder has not within the past three years held a position or office, had any other material relationship with, or otherwise been affiliated with, us or any of our predecessors or affiliates. Based on information provided to us, the Selling Stockholder is not affiliated, nor has it been affiliated, with any broker-dealer in the United States.

The named Selling Stockholder may resell the shares of common stock covered by this prospectus as provided under the section entitled “Plan of Distribution” and in any applicable prospectus supplement.

The following table sets forth the number of shares of our common stock beneficially owned and the percentage of ownership by the Selling Stockholder as of the date hereof, the number of shares offered hereby, the number of shares of common stock that will be beneficially owned and the percentage of ownership of the Selling Stockholder after the completion of this offering, assuming the sale of all shares offered and no other changes in beneficial ownership. The Selling Stockholder may sell all, some or none of its shares in this offering. See “Plan of Distribution.” The information set forth below is based on information provided to us by or on behalf of the Selling Stockholder.

Shares Beneficially Owned

Prior To The Offering

Maximum

Number Of

Shares Being

Offered

Shares Beneficially Owned

After The Offering

Name

Number

Percent(1)

Number

Percent

Paladin Capital Management, S.A. (1)

90,000

(2)

1.8

1,390,000

(1)

Applicable percentage ownership is based on 4,979,928 shares of our common stock outstanding as of February 22, 2010.

(2)

Paladin is the investor under the SEDA. Ms. Lidia Matos, the portfolio manager of Paladin, makes the investment decisision on its behalf. Paladin acquired, or will acquire, all shares being registered in this offering in financing transactions with us.

(3)

This number represents the shares currently held by the Selling Stockholder and does not include any additional shares which may be sold to the Selling Stockholder pursuant to the terms of the SEDA. On December 3, 2009, we authorized the issuance of 90,000 shares of common stock to Paladin for the payment of a commitment fee.

PLAN OF DISTRIBUTION

We are registering these shares of our common stock to permit the resale of these shares by the Selling Stockholder from time to time after the date of this prospectus. We will not receive any of the proceeds from the sale by the Selling Stockholder of these shares. We will bear all fees and expenses incident to the registration of these shares.

The Selling Stockholder may sell all or a portion of these shares from time to time directly or through one or more underwriters, broker-dealers or agents. If these shares are sold through underwriters or broker-dealers, the Selling Stockholder will be responsible for underwriting discounts and commissions and brokers’ or agents’ commissions or selling commissions. These shares may be sold in one or more transactions at fixed prices, at prevailing market prices at the time of the sale, at varying prices determined at the time of sale, or at negotiated prices. These sales may be effected in transactions, which may involve crosses or block transactions,

on any national securities exchange or quotation service on which the securities may be listed or quoted at the time of sale;

in the over-the-counter market;

in transactions otherwise than on these exchanges or systems or in the over-the-counter market;

through the writing of options, whether such options are listed on an options exchange or otherwise;

ordinary brokerage transactions and transactions in which the broker-dealer solicits purchasers;

block trades in which the broker-dealer will attempt to sell the shares as agent but may position and resell a portion of the block as principal to facilitate the transaction;

purchases by a broker-dealer as principal and resale by the broker-dealer for its account;

an exchange distribution in accordance with the rules of the applicable exchange;

privately negotiated transactions;

short sales entered into after the effective date of the registration statement of which this prospectus is a part;

sales pursuant to Rule 144;

broker-dealers may agree with the Selling Stockholder to sell a specified number of such shares at a stipulated price per share;

a combination of any such methods of sale; and

any other method permitted pursuant to applicable law.

If the Selling Stockholder effects such transactions by selling shares to or through underwriters, broker-dealers or agents, such underwriters, broker-dealers or agents may receive commissions in the form of discounts, concessions or commissions from the Selling Stockholder or commissions from purchasers of the shares for whom they may act as agent or to whom they may sell as principal (which discounts, concessions or commissions as to particular underwriters, broker-dealers or agents may be in excess of those customary in the types of transactions involved). No such broker-dealer will receive compensation in excess of that permitted by FINRA Rule 2440 and IM-2440. In no event will any broker-dealer receive total compensation in excess of 8%.

The Selling Stockholder and any broker-dealer participating in the distribution of these shares are “underwriters” within the meaning of the Securities Act, and any commission paid, or any discounts or concessions allowed to, any such broker-dealer may be deemed to be underwriting commissions or discounts under the Securities Act. At the time a particular offering of these shares is made, a prospectus supplement, if required, will be distributed which will set forth the aggregate amount of shares being offered and the terms of the offering, including the name or names of any broker-dealers or agents, any discounts, commissions and other terms constituting compensation from the Selling Stockholder and any discounts, commissions or concessions allowed or reallowed or paid to broker-dealers.

Under the securities laws of some states, the shares of our common stock may be sold in such states only through registered or licensed brokers or dealers. In addition, in some states the shares of our common stock may not be sold unless such shares have been registered or qualified for sale in such state or an exemption from registration or qualification is available and is complied with.

There can be no assurance that the Selling Stockholder will sell any or all of the shares of our common stock registered pursuant to the registration statement of which this prospectus forms a part.

The Selling Stockholder and any other person participating in such distribution will be subject to applicable provisions of the Securities Exchange Act of 1934, as amended, and the rules and regulations thereunder, including, without limitation, Regulation M of the Exchange Act, which may limit the timing of purchases and sales of any of the shares of our common stock by the Selling Stockholder and any other participating person. Regulation M may also restrict the ability of any person engaged in the distribution of the shares of our common stock to engage in market-making activities with respect to such shares. All of the foregoing may affect the marketability of the shares of our common stock and the ability of any person or entity to engage in market-making activities with respect to our common stock.

We will pay all expenses of the registration of these shares, including, without limitation, Securities and Exchange Commission filing fees and expenses of compliance with state securities or “blue sky” laws; provided, however, that the Selling Stockholder will pay all underwriting discounts, commissions and concessions and brokers’ or agents’ commissions and concessions or selling commissions and concessions, if any. We have agreed to indemnify the Selling Stockholder against liabilities, including some liabilities under the Securities Act, or the Selling Stockholder will be entitled to contribution. We may be indemnified by the Selling Stockholder against civil liabilities, including liabilities under the Securities Act, that may arise from any written information furnished to us by the Selling Stockholder specifically for use in this prospectusor we may be entitled to contribution.

LEGAL MATTERS

The validity of the issuance of the shares of common stock offered hereby will be passed upon for us by the DeMint Law, PLLC, Las Vegas, Nevada.

EXPERTS

Weaver & Martin, LLC, independent registered public accounting firm, has audited our financial statements at March 31, 2008 and March 31, 2009, as set forth in their reports. We have included our financial statements in the prospectus and elsewhere in the registration statement in reliance on Weaver & Martin, LLC’s report, given on their authority as experts in accounting and auditing.

INDEPENDENT PETROLEUM ENGINEERS

Certain information incorporated herein regarding estimated quantities of oil and natural gas reserves and their present value is based on estimates of the reserves and present values prepared by or derived from estimates prepared by Miller and Lents, Ltd., independent petroleum engineers and geologists. The reserve information is incorporated herein in reliance upon the authority of said firm as an expert with respect to such report.

WHERE YOU CAN FIND MORE INFORMATION

We have filed a registration statement on Form S-1 under the Securities Act with the SEC with respect to the common stock offered by this prospectus. This prospectus does not include all of the information contained in the registration statement or the exhibits and schedules filed therewith. You should refer to the registration statement and its exhibits for additional information. Whenever we make reference in this prospectus to any of our contracts, agreements or other documents, the references are not necessarily complete and you should refer to the exhibits attached to the registration statement for copies of the actual contract, agreement or other document.

We file annual, quarterly and special reports and other information with the SEC. You can read these SEC filings and reports, including the registration statement, over the Internet at the SEC’s website at www.sec.gov or on our website at www.enerjexresources.com. You can also obtain copies of the documents at prescribed rates by writing to the Public Reference Section of the SEC at 100 F Street, NE, Washington, DC 20549 on official business days between the hours of 10:00 am and 3:00 pm. Please call the SEC at (800) SEC-0330 for further information on the operations of the public reference facilities. We will provide a copy of our annual report to security holders, including audited financial statements, at no charge upon receipt of your written request to us at EnerJex Resources, Inc., 27 Corporate Woods, Suite 350, 10975 Grandview Drive, Overland Park, Kansas 66210.

GLOSSARY

Term		Definition

Barrel (bbl)		The standard unit of measurement of liquids in the petroleum industry, it contains 42 U.S. standard gallons. Abbreviated to “bbl”.
Basin		A depression in the crust of the Earth, caused by plate tectonic activity and subsidence, in which sediments accumulate. Sedimentary basins vary from bowl-shaped to elongated troughs. Basins can be bounded by faults. Rift basins are commonly symmetrical; basins along continental margins tend to be asymmetrical. If rich hydrocarbon source rocks occur in combination with appropriate depth and duration of burial, then a petroleum system can develop within the basin.
BOE		One barrel of oil equivalent, determined using a ratio of six Mcf of natural gas to one barrel of crude oil.
BOEPD		BOE per day.
BOPD		Abbreviation for barrels of oil per day, a common unit of measurement for volume of crude oil. The volume of a barrel is equivalent to 42 U.S. standard gallons.
Carried Working Interest		The owner of this type of working interest in the drilling of a well incurs no capital contribution requirement for drilling or completion costs associated with a well and, if specified in the particular contract, may not incur capital contribution requirements beyond the completion of the well.
Completion / Completing		A well made ready to produce oil or natural gas.
Costless Collar		When viewed against an appropriate index, the parties agree to a maximum price (call option) and a minimum price (put option), through a financially-settled collar. If the average monthly prices are within the collar range there will be no monthly settlement. However, if average monthly prices fluctuate outside the collar, the parties settle the difference in cash.
Development		The phase in which a proven oil or natural gas field is brought into production by drilling development wells.
Development Drilling		Wells drilled during the Development phase.
Division order		A directive signed by the royalty owners verifying to the purchaser or operator of a well the decimal interest of production owned by the royalty owner. The Division Order generally includes the decimal interest, a legal description of the property, the operator’s name, and several legal agreements associated with the process. Completion of this step generally precedes placing the royalty owner on pay status to begin receiving revenue payments.
Drilling		Act of boring a hole through which oil and/or natural gas may be produced.
Dry Wells		A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes.
Exploration		The phase of operations which covers the search for oil or natural gas generally in unproven or semi-proven territory.
Exploratory Drilling		Drilling of a relatively high percentage of properties which are unproven.
Farm out		An arrangement whereby the owner of a lease assigns all or some portion of the lease or licenses to another company for undertaking exploration or development activity.
Field		An area consisting of a single reservoir or multiple reservoirs all grouped on, or related to, the same individual geological structural feature or stratigraphic condition. The field name refers to the surface area, although it may refer to both the surface and the underground productive formations.
Fixed price swap		A derivative instrument that exchanges or “swaps” the “floating” or daily price of a specified volume of natural gas, oil or NGL, over a specified period, for a fixed price for the specified volume over the same period (typically three months or longer).

Term		Definition

Gathering line / system		Pipelines and other facilities that transport oil or natural gas from wells and bring it by separate and individual lines to a central delivery point for delivery into a transmission line or mainline.
Gross acre		The number of acres in which the Company owns any working interest.
Gross Producing Well		A well in which a working interest is owned and is producing oil or natural gas or other liquids or hydrocarbons. The number of gross producing wells is the total number of wells producing oil or natural gas or other liquids or hydrocarbons in which a working interest is owned.
Gross well		A well in which a working interest is owned. The number of gross wells is the total number of wells in which a working interest is owned.
Held-By-Production (HBP)		Refers to an oil and natural gas property under lease, in which the lease continues to be in force, because of production from the property.
Horizontal drilling		A drilling technique used in certain formations where a well is drilled vertically to a certain depth and then turned and drilled horizontally. Horizontal drilling allows the wellbore to follow the desired formation.
In-fill wells		In-fill wells refers to wells drilled between established producing wells; a drilling program to reduce the spacing between wells in order to increase production and recovery of in-place hydrocarbons.
Oil and Natural Gas Lease		A legal instrument executed by a mineral owner granting the right to another to explore, drill, and produce subsurface oil and natural gas. An oil and natural gas lease embodies the legal rights, privileges and duties pertaining to the lessor and lessee.
Lifting Costs		The expenses of producing oil from a well. Lifting costs are the operating costs of the wells including the gathering and separating equipment. Lifting costs do not include the costs of drilling and completing the wells or transporting the oil.
Mcf		Thousand cubic feet.
Mmcf		Million cubic feet.
Net acres		Determined by multiplying gross acres by the working interest that the Company owns in such acres.
Net Producing Wells		The number of producing wells multiplied by the working interest in such wells.
Net Revenue Interest		A share of production revenues after all royalties, overriding royalties and other nonoperating interests have been taken out of production for a well(s).
Operator		A person, acting for itself, or as an agent for others, designated to conduct the operations on its or the joint interest owners’ behalf.
Overriding Royalty		Ownership in a percentage of production or production revenues, free of the cost of production, created by the lessee, company and/or working interest owner and paid by the lessee, company and/or working interest owner out of revenue from the well.
Pooled Unit		A term frequently used interchangeably with “Unitization” but more properly used to denominate the bringing together of small tracts sufficient for the granting of a well permit under applicable spacing rules.
Proved Developed Reserves		Proved reserves that can be expected to be recovered from existing wells with existing equipment and operating methods. This definition of proved developed reserves has been abbreviated from the applicable definitions contained in Rule 4-10(a)(2-4) of Regulation S-X.
Proved Developed Non-Producing		Proved developed reserves expected to be recovered from zones behind casings in existing wells.
Proved Undeveloped Reserves		Proved undeveloped reserves are the portion of proved reserves which can be expected to be recovered from new wells on undrilled proved acreage, or from existing wells where a relatively major expenditure is required for completion. This definition of proved undeveloped reserves has been abbreviated from the applicable definitions contained in Rule 4-10(a)(2-4) of Regulation S-X.

Term		Definition

PV10		PV10 means the estimated future gross revenue to be generated from the production of proved reserves, net of estimated production and future development and abandonment costs, using prices and costs in effect at the determination date, before income taxes, and without giving effect to non-property related expenses, discounted to a present value using an annual discount rate of 10% in accordance with the guidelines of the SEC. PV10 is a non-GAAP financial measure. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Reserves” on page 33 for a reconciliation to the comparable GAAP financial measure.
Re-completion		Completion of an existing well for production from one formation or reservoir to another formation or reservoir that exists behind casing of the same well.
Reservoir		The underground rock formation where oil and natural gas has accumulated. It consists of a porous rock to hold the oil or natural gas, and a cap rock that prevents its escape.
Reservoir Pressure		The pressure at the face of the producing formation when the well is shut-in. It equals the shut-in pressure at the wellhead plus the weight of the column of oil and natural gas in the well.
Roll-Up Strategy		A “roll-up strategy” is a common business term used to describe a business plan whereby a company accumulates multiple small operators in a particular business sector with a goal to generate synergies, stimulate growth and optimize the value of the individual pieces.
Secondary Recovery		The stage of hydrocarbon production during which an external fluid such as water or natural gas is injected into the reservoir through injection wells located in rock that has fluid communication with production wells. The purpose of secondary recovery is to maintain reservoir pressure and to displace hydrocarbons toward the wellbore.
		The most common secondary recovery techniques are natural gas injection and waterflooding. Normally, natural gas is injected into the natural gas cap and water is injected into the production zone to sweep oil from the reservoir. A pressure-maintenance program can begin during the primary recovery stage, but it is a form of enhanced recovery.
Shut-in well		A well which is capable of producing but is not presently producing. Reasons for a well being shut-in may be lack of equipment, market or other.
Stock Tank Barrel or STB		A stock tank barrel of oil is the equivalent of 42 U.S. gallons at 60 degrees fahrenheit.
Undeveloped acreage		Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas regardless of whether such acreage contains proved reserves.
Unitize, Unitization		When owners of oil and/or natural gas reservoir pool their individual interests in return for an interest in the overall unit.
Waterflood		The injection of water into an oil reservoir to “push” additional oil out of the reservoir rock and into the wellbores of producing wells. Typically a secondary recovery process.
Water Injection Wells		A well in which fluids are injected rather than produced, the primary objective typically being to maintain or increase reservoir pressure, often pursuant to a waterflood.
Water Supply Wells		A well in which fluids are being produced for use in a Water Injection Well.
Wellbore		A borehole; the hole drilled by the bit. A wellbore may have casing in it or it may be open (uncased); or part of it may be cased, and part of it may be open. Also called a borehole or hole.
Working Interest		An interest in an oil and natural gas lease entitling the owner to receive a specified percentage of the proceeds of the sale of oil and natural gas production or a percentage of the production, but requiring the owner of the working interest to bear the cost to explore for, develop and produce such oil and natural gas.

INDEX TO FINANCIAL STATEMENTS

	Page
Index to Financial Statements	81
Report of Independent Registered Public Accounting Firm	F-1
Consolidated Balance Sheets at March 31, 2009 and 2008	F-2
Consolidated Statements of Operations for the Fiscal Years Ended March 31, 2009 and 2008	F-3
Consolidated Statement of Stockholders’ Equity(Deficit) for the Fiscal Years Ended March 31, 2009 and 2008	F-4
Consolidated Statement of Cash Flows for the Fiscal Years Ended March 31, 2009 and 2008	F-5
Notes to Consolidated Financial Statements	F-6

Report of Independent Registered Public Accounting Firm

Stockholders and Directors

EnerJex Resources, Inc.

Overland Park, Kansas

We have audited the accompanying consolidated balance sheet of EnerJex Resources, Inc. as of March 31, 2009 and 2008 and the related consolidated statements of operations, stockholders’ equity (deficit), and cash flows for each of the years in the two-year period ended March 31, 2009. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatements. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of EnerJex Resources, Inc. as of March 31, 2009 and 2008 and the consolidated results of its operations and cash flows for each of the years in the two–year period ended March 31, 2009 in conformity with accounting principles generally accepted in the United States of America.

The accompanying financial statements have been prepared assuming that the Company will continue as a going concern. As discussed in Note 2 to the financial statements, the Company has suffered recurring losses and had negative cash flows that raise substantial doubt about the Company's ability to continue as a going concern. Management's plans in regard to these matters are described in the Note 2. The financial statements do not include any adjustments that might result from the outcome of this uncertainty.

/S/ Weaver & Martin, LLC

Weaver & Martin, LLC

Kansas City, Missouri

July 9, 2009

F-1

EnerJex Resources, Inc. and Subsidiaries

Consolidated Balance Sheets

	March 31,
	2009			2008

Assets
Current assets:
Cash	$	127,585			$	951,004
Accounts receivable		462,044				227,055
Prepaid debt issue costs		45,929				157,191
Deposits and prepaid expenses		263,383				176,345
Total current assets		898,941				1,511,595

Fixed assets		365,019				185,299
Less: Accumulated depreciation		63,988				30,982
Total fixed assets		301,031				154,317

Other assets:
Prepaid debt issue costs		-				157,191
Oil and gas properties using full-cost accounting:
Properties not subject to amortization		31,183				62,216
Properties subject to amortization		6,449,023				8,982,510
Total other assets		6,480,206				9,201,917
Total assets	$	7,680,178			$	10,867,829

Liabilities and Stockholders’ Equity (Deficit)
Current liabilities:
Accounts payable	$	1,016,168			$	416,834
Accrued liabilities		87,811				70,461
Notes payable		-				965,000
Deferred payments from Euramerica development		-				251,951
Long-term debt, current		1,723,036				412,930
Total current liabilities		2,827,015				2,117,176

Asset retirement obligation		803,624				459,689
Convertible note payable		25,000				25,000
Long-term debt, net of discount of $596,108		7,818,163				6,831,972
Total liabilities		11,473,802				9,433,837
Contingencies and commitments
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 –4,443,512 at March 31, 2009
and 4,440,651 at March 31, 2008		4,444				4,441
Paid in capital		8,932,906				8,853,457
Retained (deficit)		(12,730,974	)			(7,423,906	)
Total stockholders’ equity (deficit)		(3,793,624	)			1,433,992

Total liabilities and stockholders’ equity (deficit)	$	7,680,178			$	10,867,829

See Notes to Consolidated Financial Statements.

F-2

EnerJex Resources, Inc. and Subsidiaries

Consolidated Statements of Operations

	For the Fiscal Years Ended
	March 31,
	2009			2008

Oil and natural gas revenues	$	6,436,805			$	3,602,798

Expenses:
Direct operating costs		2,637,333				1,795,188
Depreciation, depletion and amortization		911,293				935,330
Impairment of oil and gas properties		4,777,723				-
Professional fees		1,320,332				1,226,998
Salaries		849,340				1,703,099
Administrative expense		1,392,645				887,872
Total expenses		11,888,666				6,548,487

Loss from operations		(5,451,861	)			(2,945,689	)

Other income (expense):
Interest expense		(882,426	)			(792,448	)
Loan interest accretion		(2,814,095	)			(1,089,798	)
Gain on liquidation of hedging instrument		3,879,050				-
Other Gain/(Loss)		(37,736	)			-

Total other income (expense)		144,793				(1,882,246	)

Net income - (loss)	$	(5,307,068	)		$	(4,827,935	)

Weighted average shares outstanding - basic		4,443,249				4,284,144

Net income (loss) per share - basic	$	(1.19	)		$	(1.13	)

See Notes to Consolidated Financial Statements.

F-3

EnerJex Resources, Inc. and Subsidiaries

Consolidated Statements of Stockholders’ Equity (Deficit)

	Common Stock
	Shares		Par Value		Owed but not issued			Paid in Capital			Retained Deficit			Total Stockholders’ Equity (Deficit)

Balance, April 1, 2007		2,635,731	$	2,636	$	3		$	2,548,742		$	( 2,595,971	)	$	(44,590	)

Stock sold		1,800,000		1,800		-			4,311,956			-			4,313,756
Stock issued for services		1,920		2		-			14,998			-			15,000
Previously authorized but unissued stock		3,000		3		(3	)		-			-			-
Stock options issued for services		-		-		-			1,977,761			-			1,977,761
Net (loss) for the year		-		-		-			-			(4,827,935	)		(4,827,935	)
Balance, March 31, 2008		4,440,651		4,441		-			8,853,457			(7,423,906	)		1,433,992

Stock options issued for services		-		-		-			67,452			-			67,452
Stock issued for services		2,182		2		-			11,998			-			12,000
Stock issued in reverse stock split		679		1		-			(1	)		-			-
Net loss for the year		-		-		-			-		$	(5,307,068	)		(5,307,068	)
Balance, March 31, 2009		4,443,512	$	4,444	$	-		$	8,932,906		$	( 12,730,974	)	$	(3,793,624	)

See Notes to Consolidated Financial Statements.

F-4

EnerJex Resources, Inc. and Subsidiaries

Consolidated Statements of Cash Flows

	For the Fiscal Years Ended
	March 31,
	2009			2008
Cash flows from operating activities
Net (loss)	$	(5,307,068	)	$	(4,827,935	)
Depreciation and depletion		950,357			935,330
Debt issue cost amortization		157,191			152,453
Stock and options issued for services		79,452			1,992,761
Accretion of interest on long-term debt discount		2,814,095			1,089,798
Accretion of asset retirement obligation		60,864			30,331
Impairment of oil & gas properties		4,777,723			-
Adjustments to reconcile net (loss) to cash
used in operating activities:
Accounts receivable		(234,989	)		(222,917	)
Notes and interest receivable		-			10,300
Deposits and prepaid expenses		24,224			(169,672	)
Accounts payable		599,334			374,535
Accrued liabilities		17,350			(25,429	)
Deferred payment from Euramerica for development		(251,951	)		251,951
Cash used in operating activities		3,686,582			(408,494	)

Cash flows from investing activities
Purchase of fixed assets		(204,200	)		(149,799	)
Additions to oil & gas properties		(3,123,003	)		(9,530,321	)
Sale of oil & gas properties		300,000			300,000
Note and interest receivable from officer		-			23,100
Proceeds from sale of vehicle					-
Cash used in investing activities		(3,027,203	)		(9,357,020	)

Cash flows from financing activities
Proceeds from (repayment of) note payable, net		(965,000	)		615,000
Proceeds from sales of common stock		-			4,313,756
Debt issue costs					(466,835	)
Borrowings on long-term debt		11,274,843			6,344,816
Payments on long-term debt		(11,792,641	)		(189,712	)
Cash provided from financing activities		(1,482,798	)		10,617,025

Increase (decrease) in cash and cash equivalents		(823,419	)		851,511
Cash and cash equivalents, beginning		951,004			99,493
Cash and cash equivalents, end	$	127,585		$	951,004

Supplemental disclosures:
Interest paid	$	768,053		$	733,972
Income taxes paid	$	-		$	-

Non-cash transactions:
Share-based payments issued for services	$	-		$	280,591

See Notes to Consolidated Financial Statements.

F-5

EnerJex Resources, Inc.

Notes to Consolidated Financial Statements

Note 1 – Summary of Accounting Policies

Nature of Business

We are an independent energy company engaged in the business of producing and selling crude oil and natural gas. This crude oil and natural gas is obtained primarily by the acquisition and subsequent exploration and development of mineral leases. Development and exploration may include drilling new exploratory or development wells on these leases. These operations are conducted primarily in Eastern Kansas.

Principles of Consolidation

Our consolidated financial statements include the accounts of our wholly-owned subsidiaries, EnerJex Kansas, Inc., DD Energy, Inc.

Use of Estimates

The preparation of these financial statements requires the use of estimates by management in determining our assets, liabilities, revenues, expenses and related disclosures. Actual amounts could differ from those estimates.

Trade Accounts Receivable

Trade accounts receivable are recorded at the invoiced amount and do not bear any interest. We regularly review receivables to insure that the amounts will be collected and establish or adjust an allowance for uncollectible amounts as necessary using the specific identification method. Account balances are charged off against the allowance after all means of collection have been exhausted and the potential for recovery is considered remote. There were no reserves for uncollectible amounts in the periods presented.

Share-Based Payments

Income Taxes

We account for income taxes under the Statement of Financial Accounting Standards “SFAS” Statement 109, “Accounting for Income Taxes”. The asset and liability approach requires the recognition of deferred tax liabilities and assets for the expected future tax consequences of temporary differences between the carrying amounts and the tax basis of assets and liabilities. The provision for income taxes differs from the amount currently payable because of temporary differences in the recognition of certain income and expense items for financial reporting and tax reporting purposes.

We adopted the Financial Accounting Standards Board “FASB” Interpretation No. 48, “Accounting for Uncertainty in Income Taxes – an interpretation of FASB Statement No. 109” (“FIN 48”) as of April 1, 2007. FIN 48 clarifies the accounting for uncertainty in income taxes recognized in companies’ financial statements in accordance with FASB Statement No. 109, “Accounting for Income Taxes”. As a result, we apply a more-likely-than-not recognition threshold for all tax uncertainties. FIN 48 only allows the recognition of those tax benefits that have a greater than fifty percent likelihood of being sustained upon examination by the taxing authorities. As a result of implementing FIN 48, we have reviewed our tax positions and determined there were no outstanding or retroactive tax positions with less than a 50% likelihood of being sustained upon examination by the taxing authorities, therefore the implementation of this standard has not had a material effect on the Company.

F-6

EnerJex Resources, Inc.

Notes to Consolidated Financial Statements – (Continued)

We classify tax-related penalties and net interest on income taxes as income tax expense. As of March 31, 2009 and 2008, no income tax expense had been incurred.

Fair Value of Financial Instruments

Our financial instruments consist of accounts receivable and notes payable. Interest rates currently available to us for debt with similar terms and remaining maturities are used to estimate fair value of such financial instruments. Accordingly the carrying amounts are a reasonable estimate of fair value.

Earnings Per Share

SFAS No. 128, “Earnings Per Share”, requires dual presentation of basic and diluted earnings per share on the face of the income statement for all entities with complex capital structures and requires a reconciliation of the numerator and denominator of the diluted income or loss per share computation.

For the year ended March 31, 2009 and 2008, there were 513,500 and 533,500, respectively, of potentially issuable shares of common stock pursuant to outstanding stock options and warrants. These have been excluded from the denominator of the diluted earnings per share computation, as their effect would be anti-dilutive.

Cash and Cash Equivalents

We consider all highly liquid investment instruments purchased with original maturities of three months or less to be cash equivalents for purposes of the consolidated statements of cash flows and other statements. We maintain cash on deposit, which, at times, exceed federally insured limits. We have not experienced any losses on such accounts and believe we are not exposed to any significant credit risk on cash and equivalents.

Revenue Recognition and Imbalances

Oil and gas revenues are recognized net of royalties when production is sold to a purchaser at a fixed or determinable price, when delivery has occurred and title has transferred, and if collection of the revenue is probable. Cash received relating to future revenues is deferred and recognized when all revenue recognition criteria are met.

We use the sales method of accounting for gas production imbalances. The volumes of gas sold may differ from the volumes to which we are entitled based on our interests in the properties. These differences create imbalances that are recognized as a liability only when the properties’ estimated remaining reserves net to us will not be sufficient to enable the under-produced owner to recoup its entitled share through production. No receivables are recorded for those wells where we have taken less than our share of production. Gas imbalances are reflected as adjustments to estimates of proved gas reserves and future cash flows in the supplemental oil and gas disclosures. There was no imbalance at March 31, 2009 and 2008.

Goodwill

Goodwill represents the excess of the purchase price of an entity over the estimated fair value of the assets acquired and liabilities assumed. We assess the carrying amount of goodwill by testing the goodwill for impairment annually and when impairment indicators arise. The impairment test requires allocating goodwill and all other assets and liabilities to assigned reporting units. The fair value of each unit is determined and compared to the book value of the reporting unit. If the fair value of the reporting unit is less than the book value, including goodwill, then the goodwill is written down to the implied fair value of the goodwill through a charge to expense.

F-7

EnerJex Resources, Inc.

Notes to Consolidated Financial Statements – (Continued)

Property and Equipment

Property and equipment are recorded at cost. Depreciation is on a straight-line method using the estimated lives of the assets. (3-15 years). Expenditures for maintenance and repairs are charged to expense.

Debt Issue Costs

Debt issuance costs incurred are capitalized and subsequently amortized over the term of the related debt on the straight-line method of amortization over the estimated life of the debt.

Oil and Gas Properties

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.

F-8

EnerJex Resources, Inc.

Notes to Consolidated Financial Statements – (Continued)

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.

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

Long-Lived Assets

Impairment of long-lived assets is recorded when indicators of impairment are present and the undiscounted cash flows estimated to be generated by those assets are less than the assets’ carrying value. The carrying value of the assets is then reduced to their estimated fair value that is usually measured based on an estimate of future discounted cash flows.

Asset Retirement Obligations

Major Purchasers

For the years ended March 31, 2009 and 2008 we sold all of our natural gas production to one purchaser. We sold all of our oil production to one purchaser during fiscal 2009 and to a single, but different purchaser in fiscal 2008.

Recent Issued Accounting Standards

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.

F-9

EnerJex Resources, Inc.

Notes to Consolidated Financial Statements – (Continued)

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.

Reclassifications

Certain reclassifications have been made to prior periods to conform to current presentation.

Note 2 – Going Concern

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

Note 3 – Stock Transactions

Stock transactions in fiscal 2009:

We issued 2,182 shares of common stock to a Director and chairman of our Audit Committee for services over the next year. For the year ended March 31, 2009, we recorded director compensation in the amount $13,000.

Option and Warrant transactions:

Officers (including officers who are members of the board of directors), directors, employees and consultants are eligible to receive options under our stock option plans. We administer the stock option plans and we determine those persons to whom options will be granted, the number of options to be granted, the provisions applicable to each grant and the time periods during which the options may be exercised. No options may be granted more than ten years after the date of the adoption of the stock option plans.

F-10

EnerJex Resources, Inc.

Notes to Consolidated Financial Statements – (Continued)

Each option granted under the stock option plans will be exercisable for a term of not more than ten years after the date of grant. Certain other restrictions will apply in connection with the plans when some awards may be exercised. In the event of a change of control (as defined in the stock option plans), the vesting date on which all options outstanding under the stock option plans may first be exercised will be accelerated. Generally, all options terminate 90 days after a change of control.

2000-2001 Stock Option Plan

The Board of Directors approved a stock option plan and our stockholders ratified the plan on September 25, 2000. The total number of options that can be granted under the plan is 200,000 shares. At March 31, 2009, we had granted 200,000 non-qualified options under this plan.

Stock Option Plan

On May 4, 2007, we amended and restated the EnerJex Resources, Inc. Stock Option Plan to rename the plan and to increase the number of shares issuable under the plan to 1,000,000. Our stockholders approved this plan in September of 2007. At March 31, 2009, we had granted 238,500 non-qualified options under this plan.

Option transactions in fiscal 2008:

The unvested option issued in the year ended March 31, 2007, was unexercised and cancelled in accordance with a separation agreement. We recognized the remaining expense ($61,187) relating to the options in the year ended March 31, 2008.

We granted 458,500 options in the year ended March 31, 2008. 30,000 of the options were for services earned over a one-year period. We measured the compensation cost of the options based on the vesting and the market value as determined by the Black-Scholes pricing model.

For the year ended March 31, 2008, we included as expense $1,977,761 relating to the value of vested options.

The fair value of each option award was estimated on the date of grant using the assumptions noted in the following table. Volatility is based on the historical volatility of stock trading, expected term was the estimated exercise period, risk free rate was the rate of a U.S. Treasury instrument of the time period in which the options would be outstanding, and dividend rate was estimated to be zero as we cannot assume that there will be any future dividends.

Weighted average expected volatility	101	%
Weighted average expected term (in years)	3.95
Weighted average expected dividends	0	%
Weighted average risk free rate	4.42	%

The weighted average grant date fair value of the options granted in the year ended March 31, 2009 was $4.35.

In the year ended March 31, 2008, we granted warrants to purchase 75,000 shares of our common stock as partial payment for services rendered in connection with our financing activities. The warrants have an exercise price of $3.00 and expire on April 11, 2010. The fair value of the warrants based on the Black-Scholes pricing model totaled $280,591 (approximately $3.75 per warrant). The following assumptions were used in the valuation: stock price-$1.00; exercise price-$0.60; life- 3 years; volatility- 106%; yield-4.66%. We have included the value of the warrants with the loan and equity transaction costs (See Note 5).

F-11

EnerJex Resources, Inc.

Notes to Consolidated Financial Statements – (Continued)

Option transactions in fiscal 2009:

We cancelled 20,000 options in accordance with the provisions regarding terminations in Stock Option Plan.

At March 31, 2009, we included as expense $66,456 relating to the options that were for services earned over a one-year period.

A summary of stock options and warrants is as follows:

	Options			Weighted Ave. Exercise Price			Warrants		Weighted Ave. Exercise Price
Outstanding April 1, 2007		60,000		$	6.25			-		-
Granted		458,500			6.30			75,000	$	3.00
Cancelled		(60,000	)		(6.25	)		-		-
Exercised		-			-			-		-
Outstanding March 31, 2008		458,500		$	6.30			75,000	$	3.00
Granted		-			-			-		-
Cancelled		(20,000	)		(6.25	)		-		-
Exercised		-			-			-		-
Outstanding March 31, 2009		438,500		$	6.30			75,000	$	3.00

Note 4 – 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 at April 1, 2007	$	23,908
Liabilities incurred during the period		405,450
Liabilities settled during the period		-
Accretion		30,331
Asset retirement obligations, March 31, 2008		459,689
Liabilities incurred during the period		283,071
Liabilities settled during the period		-
Accretion		60,864
Asset retirement obligations, March 31, 2009	$	803,624

Note 5 - Long-Term Debt

Senior Secured Credit Facility

On July 3, 2008, EnerJex, EnerJex Kansas, and DD Energy entered into a three-year $50 million Senior Secured Credit Facility (the “Credit Facility”) with Texas Capital Bank, N.A. 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 and interim adjustments. 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 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 had borrowings $7.328 million outstanding at March 31, 2009.

F-12

EnerJex Resources, Inc.

Notes to Consolidated Financial Statements – (Continued)

Debentures

The Debentures originally had 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 fiscal year ended March 31, 2009 was $2,814,095 and $1,089,798 for the fiscal year ended March 31, 2008. Of the $2,814,095 interest accreted during the period ended March 31, 2009, $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 $596,108 as of March 31, 2009.

We incurred debt issue costs totaling $466,835. The debt issue costs are initially recorded as assets and are amortized to expense on a straight-line basis over the life of the loan. The amount expensed in the twelve month period ended March 31, 2009 was $268,453. Of this amount, $195,559 was expensed upon the redemption of $6.3 million of the Debentures. The remaining debt issue costs totaling $45,929 will be expensed in the fiscal year ended March 31, 2010.

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.

F-13

EnerJex Resources, Inc.

Notes to Consolidated Financial Statements – (Continued)

Convertible and Other Long-Term Debt

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.

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 March 31, 2009:

Credit Facility	$	7,328,000

Debentures		2,700,000
Unaccreted discount		(596,108	)
Debentures, net of unaccreted discount		2,103,892

Vehicle notes payable		109,307
Total long-term debt		9,541,199
Less current portion		(1,723,036	)
Long-term debt	$	7,818,163

Principal amounts are due on long-term and convertible debt as follows: Year ended March 31, 2010 -$1,723,036, March 31, 2011 -$8,377,636, March 31, 2012 -$25,243, March 31, 2013 -$16,044, March 31, 2014 -$13,171 and thereafter-$7,177.

Note 6 – 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. Through an additional extension, we have until December 31, 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 extension will have no force and effect, however, upon a material default by EnerJex under the Credit Facility. 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.

F-14

EnerJex Resources, Inc.

Notes to Consolidated Financial Statements – (Continued)

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 were the operator of the project at a cost plus 17.5% basis. We received $600,000 of the $1.2 million purchase price and $500,000 of the $2.0 million development funds. We have recorded a reduction of $600,000 to our oil & gas properties using full-cost accounting subject to amortization as of the year ended March 31, 2009. In January 2009, Euramerica failed to fully fund both the balance of the purchase price and the remaining development capital owed under the agreements 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. We drilled 22 wells on behalf of Euramerica under the development agreement. We are currently exploring options to sell or further develop the Gas City Project through joint venture partnerships or other opportunities. The gas project remains shut in.

Note 7 – Related party transactions

In August 2008, we paid $20,000 to a non-employee director and former member of the audit committee for assisting in the establishment and development of the audit committee and for his involvement and assistance to the chief executive officer in finalizing the hedging instrument with BP.

Note 8 – Commitments and Contingencies

We have a lease agreement that expires in September 30, 2013. Future minimum payments are $71,180 for the year ending March 31, 2010.

Note 9 – Income Taxes

Deferred income taxes are determined based on the tax effect of items subject to different treatment between book and tax bases. At March 31, 2009, there is approximately $8,100,000 of net operating loss carry-forwards expiring in 2021-2023. The net deferred tax is as follows:

	March 31, 2009			March 31, 2008
Non-current deferred tax asset:
Impaired oil & gas costs and long-lived assets	$	1,864,700		$	312,800
Net operating loss carry-forward		2,754,600			2,429,900
Valuation allowance		(4,619,300	)		(2,742,700	)
Total deferred tax net	$	-		$	-

F-15

EnerJex Resources, Inc.

Notes to Consolidated Financial Statements – (Continued)

A reconciliation of the provision for income taxes to the statutory federal rate for continuing operations is as follows:

	March 31, 2009			March 31, 2008
Statutory tax rate		34	%		34	%
Equity based compensation		(1	)%		(15	)%
Oil & gas costs and long-lived assets		(29	)%		1	%
Change in valuation allowance		(4	)%		(20	)%
Effective tax rate		0	%		0	%

Note 10 – Subsequent Events

In April and May of 2009, we retired $450,000 of the $2.7 million Debentures that were outstanding at March 31, 2009, leaving a remaining balance of $2.25 million as of the date of this prospectus.

Subsequent to year-end, we amended the Debentures to extend the maturity date to September 30, 2010, to allow us to pay interest in either cash or payment-in-kind interest (an increase in the amount of principal due) or payment-in-kind shares (issuance of shares of common stock), and add a provision for the conversion of the debentures into shares of EnerJex’s common stock. See Note 5.

Subsequent to year-end, we have made Borrowing Base Reduction payments of $200,000 on our Credit Facility.

Note 11 – Supplemental Oil and Natural Gas Reserve Information (Unaudited)

Results of operations from oil and natural gas producing activities

The following table shows the results of operations from the Company’s oil and gas producing activities. Results of operations from these activities are determined using historical revenues, production costs and depreciation, depletion and amortization of the capitalized costs subject to amortization. General and administrative expenses, professional, investor relations and interest expense is excluded from this determination.

	March 31, 2009			March 31, 2008
Production revenues	$	6,436,805		$	3,602,798
Production costs		(2,637,333	)		(1,795,188	)
Depletion and depreciation		(892,871	)		(913,224	)
Results of operations for producing activities	$	2,906,601		$	894,386

Capitalized costs of oil and natural gas producing properties

The Company’s aggregate capitalized costs related to oil and natural gas producing activities are as follows:

	March 31, 2009			March 31, 2008
Proved	$	8,566,979		$	10,207,596
Unevaluated and unproved		31,183			62,216
Accumulated depreciation and depletion		(1,817,956	)		(925,086	)
Sale of properties		(300,000	)		(300,000	)
Net capitalized costs	$	6,480,206		$	9,044,726

Unproved and unevaluated properties are not included in the full-cost pool and are therefore not subject to depletion or depreciation. These assets consist primarily of leases that have not been evaluated. We will continue to evaluate our unproved and unevaluated properties; however, the timing of such evaluation has not been determined.

F-16

EnerJex Resources, Inc.

Notes to Consolidated Financial Statements – (Continued)

Capitalized costs incurred for oil and natural gas producing activities

Costs incurred in oil and natural gas property acquisition, exploration and development activities that have been capitalized are summarized below:

	March 31, 2009		March 31, 2008
Acquisition of proved and unproved properties	$	123,040	$	4,352,040
Development costs		2,999,963		5,178,281
Exploration costs		-		-
Total	$	3,123,003	$	9,530,321

Gas and oil Reserve Quantities

Our ownership interests in estimated quantities of proved oil and gas reserves and changes in net proved reserves all of which are located in the United States are summarized below. Proved reserves are estimated quantities of natural gas and oil that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed reserves are those that are expected to be recovered through existing wells with existing equipment and operating methods. Reserves are stated in thousand cubic feet (mcf) of natural gas and barrels (stb) of oil. Geological and engineering estimates of proved natural gas and oil reserves at one point in time are highly interpretive, inherently imprecise and subject to ongoing revisions that may be substantial in amount. Although every reasonable effort is made to ensure that the reserve estimates are accurate, by their nature reserve estimates are generally less precise than other estimates presented in connection with financial statement disclosures.

	March 31, 2009						March 31, 2008
	Gas-mcf			Oil-stb			Gas-mcf			Oil-stb
Proved reserves:
Revisions of previous estimates		(394,732	)		(14,575	)		-			-
Purchase of minerals in place		-			53,280			418,959			347,228
Extensions and discoveries		-						-			1,068,683
Production		(6,465	)		(74,289	)		(17,762	)		(43,697	)
Total		-			1,336,630			401,197			1,372,214

Proved developed reserves at the end of the period:

Gas- mcf	Oil – stb
March 31, 2009	March 31, 2009
-		524,980

Gas- mcf	Oil stb
March 31, 2008	March 31, 2008
401,197		861,240

F-17

EnerJex Resources, Inc.

Notes to Consolidated Financial Statements – (Continued)

Standardized measure of discounted future net cash flows

The standardized measure of discounted future net cash flows from our proved reserves for the periods presented in the financial statements is summarized below. The standardized measure of future cash flows as of March 31, 2009 and 2008 is calculated using a price per Mcf of gas of $0 and $7.479, respectively and a price for oil of $42.65 and $94.53, respectively. The resulting estimated future cash inflows are reduced by estimated future costs to develop and produce the estimated proved reserves. These costs are based on year-end cost levels. Future income taxes are based on year-end statutory rates. The future net cash flows are reduced to present value by applying a 10% discount rate. The standardized measure of discounted future cash flows is not intended to represent the replacement cost or fair market value of the Company’s oil and gas properties.

	March 31, 2009			March 31, 2008
Future production revenue	$	57,007,970		$	132,457,459
Future production costs		(24,732,440	)		(39,629,625	)
Future development costs		(9,584,500	)		(18,827,013	)
Future cash flows before income taxes		22,691,030			74,000,821
Future income taxes		-			(19,241,954	)
Future net cash flows		22,691,030			54,758,867
10% annual discount for estimating of future cash flows		(12,061,690	)		(26,558,364	)
Standardized measure of discounted net cash flows	$	10,629,340		$	28,200,503

Changes in Standardized Measure of Discounted Future Net Cash Flows

	March 31, 2009			March 31, 2008
Balance beginning of year	$	28,200,503		$	-
Sales, net of production costs		(5,697,410	)		(1,777,278	)
Net change in pricing and production costs		(31,927,063	)		-
Net change in future estimated development costs		9,220,510			-
Purchase of minerals in place		136,190			8,124,394
Extensions and discoveries		518,297			21,853,387
Revisions		(1,089,039	)		-
Accretion of discount		(143,477	)		-
Change in income tax		11,410,829			-
Balance end of year	$	10,629,340		$	28,200,503

F-18

EnerJex Resources, Inc. and Subsidiaries

Condensed Consolidated Balance Sheets

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

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

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

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

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

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

See Notes to Condensed Consolidated Financial Statements.

F-19

EnerJex Resources, Inc. and Subsidiaries

Condensed Consolidated Statements of Operations

(Unaudited)

	For the Three Months Ended						For the Nine Months Ended
	December 31,						December 31,
	2009			2008			2009			2008

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

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

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

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

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

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

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

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

See Notes to Condensed Consolidated Financial Statements.

F-20

EnerJex Resources, Inc. and Subsidiaries

Condensed Consolidated Statements of Cash Flows

(Unaudited)

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

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

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

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

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

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

See Notes to Condensed Consolidated Financial Statements.

F-21

EnerJex Resources, Inc. and Subsidiaries

Notes to Condensed Consolidated Financial Statements

Note 1- Basis of Presentation

The unaudited consolidated financial statements have been prepared in accordance with United States generally accepted accounting principles for interim financial information and with the instructions to Form 10-Q and reflect all adjustments which, in the opinion of management, are necessary for a fair presentation. All such adjustments are of a normal recurring nature. The results of operations for the interim period are not necessarily indicative of the results to be expected for a full year. Certain amounts in the prior year statements have been reclassified to conform to the current year presentations. The statements should be read in conjunction with the financial statements and footnotes thereto included in our Form 10-K for the fiscal year ended March 31, 2009.

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

Note 2 – Going Concern

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

Note 3 - Stock Options and Warrants

A summary of stock options and warrants is as follows:

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

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

Note 4 – Fair Value Measurements

The Company holds certain financial assets which are required to be measured at fair value on a recurring basis in accordance with the Statement of Financial Accounting Standard No. 157, “Fair Value Measurements” (“ASC Topic 820-10”).. ASC Topic 820-10 establishes a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurements) and the lowest priority to unobservable inputs (Level 3 measurements). ASC Topic 820-10 defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants on the measurement date. A fair value measurement assumes that the transaction to sell the asset or transfer the liability occurs in the principal market for the asset or liability. The three levels of the fair value hierarchy under ASC Topic 820-10 are described below:

F-22

Level 1. Valuations based on quoted prices in active markets for identical assets or liabilities that an entity has the ability to access. The Company’s Level 1 assets include cash.

Level 2. Valuations based on quoted prices for similar assets or liabilities, quoted prices for identical assets or liabilities in markets that are not active, or other inputs that are observable or can be corroborated by observable data for substantially the full term of the assets or liabilities. The Company’s Level 2 assets and liabilities consist of accounts receivable, notes and convertible notes payable, and derivative liability. Due to the short term nature of its accounts receivable, notes and convertible notes payable, the Company estimates the fair value of these assets and liabilities at their current basis. The Company determines the fair value of its derivative liability utilizing various inputs, including NYMEX price quotations and contract terms.

Level 3. Valuations based on inputs that are supported by little or no market activity and that are significant to the fair value of the assets or liabilities. The Company has no level 3 assets or liabilities.

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

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

Note 5 - Asset Retirement Obligations

The following shows the changes in asset retirement obligations:

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

Note 6 – Derivative Instruments

We have entered into certain derivative or physical arrangements with respect to portions of our crude oil production to reduce our sensitivity to volatile commodity prices and/or to meet hedging requirements under our Credit Facility. See Note 7. None of our derivative instruments are designated as cash flow hedges. We believe that these derivative arrangements, although not free of risk, allow us to achieve a more predictable cash flow and to reduce exposure to commodity price fluctuations. However, derivative arrangements limit the benefit of increases in the prices of crude oil. Moreover, our derivative arrangements apply only to a portion of our production.

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

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

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

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

Note 7 - Long-Term Debt and Convertible Debt

Senior Secured Credit Facility

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

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

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

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

Debentures

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

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

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

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

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

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

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

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

Convertible and Other Long-Term Debt

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

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

Credit Facility	$	6,746,000

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

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

Note 8 - Oil & Gas Properties

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

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

Note 9 - Subsequent Events

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

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

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

On January 4, 2010, the Company issued to MorMeg, LLC 45,000 shares of restricted common stock for payment of consulting fees accrued from July 2009 through March 31, 2010 and 65,000 shares of restricted common stock as payment for granting an extension on the date required to provide additional development funding on the Black Oaks project.

On January 5, 2010, in an effort for the Company to preserve cash in light of deteriorated global economic conditions and the significant declines in commodity prices of oil and natural gas, Steve Cochennet, our CEO/President, agreed to convert his salary for the months of January and February 2010 into 73,261 shares of the Company’s restricted common stock.

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

On January 12, 2010, we issued the Debenture holders an additional 45 shares of our common stock in lieu of interest payments for the quarter ended September 30, 2009 and 4,223 shares of our common stock in lieu of interest payments for the quarter ended December 31, 2009.

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

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1,390,000 Shares

Common Stock

PROSPECTUS

March 24, 2010

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AgEagle Aerial Systems (UAVS) 424B3Prospectus supplement