S-1/A 1 a38274a1sv1za.htm AMENDEMNT TO FORM S-1
As filed with the Securities and Exchange Commission on May 27, 2008
Registration No. 333-150164
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Amendment No. 1
to
Form S-1
REGISTRATION STATEMENT
UNDER
THE SECURITIES ACT OF 1933
ENERJEX RESOURCES, INC.
(Exact name of registrant as specified in its charter)

Nevada |  | 1311 |  | 88-0422242
(State or other jurisdiction of incorporation or organization) |  | (Primary Standard Industrial Classification Code Number) |  | (I.R.S. Employer Identification No.)

7300 W. 110th, 7th Floor
Overland Park, Kansas 66210
(913) 693-4600
(Address, including zip code, and telephone number,
including area code, of registrant’s principal executive offices)
C. Stephen Cochennet
President and Chief Executive Officer
EnerJex Resources, Inc.
7300 W. 110th, 7th Floor
Overland Park, Kansas 66210
(913) 693-4600
(Name, address, including zip code, and telephone number,
including area code, of agent for service)
Copies to:

Jeffrey T. Haughey, Esq. Husch Blackwell Sanders LLP 4801 Main Street, Suite 1000 Kansas City, Missouri 64112 (816) 983-8146 |  | Michael A. Hedge, Esq. Ryan C. Wilkins, Esq. Stradling Yocca Carlson & Rauth 660 Newport Center Drive, Suite 1600 Newport Beach, California 92660 (949) 725-4000

Approximate date of commencement of proposed sale to the public: As soon as practicable after this Registration Statement becomes effective.
If any of the securities being registered on this Form are to be offered on a delayed or continuous basis pursuant to Rule 415 under the Securities Act of 1933, check the following box. o
If this Form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, please check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. o
If this Form is a post-effective amendment filed pursuant to Rule 462(c) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. o
If this Form is a post-effective amendment filed pursuant to Rule 462(d) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer o |  | Accelerated filer o |  | Non-accelerated filer o (Do not check if a smaller reporting company) |  | Smaller reporting company þ

The Registrant hereby amends this Registration Statement on such date or dates as may be necessary to delay its effective date until the Registrant shall file a further amendment which specifically states that this Registration Statement shall thereafter become effective in accordance with Section 8(a) of the Securities Act of 1933 or until the Registration Statement shall become effective on such date as the Commission, acting pursuant to said Section 8(a), may determine.

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The information in this prospectus is not complete and may be changed. We may not sell these securities until the registration statement filed with the Securities and Exchange Commission is effective. This prospectus is not an offer to sell these securities and it is not soliciting an offer to buy these securities in any state where the offer or sale is not permitted.

SUBJECT TO COMPLETION, DATED MAY 27, 2008
Shares
Common Stock
We are offering shares of our common stock. Our common stock is included for quotation on the over-the-counter bulletin board (“OTC:BB”) under the symbol “EJXR.” The closing price of our common stock on , 2008 on the OTC:BB was $ . We have applied for listing of our common stock on the American Stock Exchange under the proposed symbol “JEX.”
This investment involves a high degree of risk. We urge you to carefully read the “Risk Factors” section beginning on page 10 of this prospectus.

|  | Per Share |  | Total
Public Offering Price |  | $ |  |  |  | $ |  |
Underwriting Discount |  | $ |  |  |  | $ |  |
Proceeds, Before Expenses, to EnerJex Resources, Inc.(1) |  | $ |  |  |  | $ |  |

(1) |  | The aggregate expenses of the offering are estimated to be $ , which represents $ per share.

We have granted the underwriters a 30-day option to purchase from us, at a price equal to the public offering price less the underwriting discount, up to an additional 15% of the total number of shares sold in this offering. In addition, the underwriters will have the right to purchase from us, at a nominal price, warrants to purchase up to 10% of the total number of shares sold in this offering at an exercise price equal to 140% of the public offering price.
The underwriters expect to deliver the shares of common stock to investors on or about , 2008.
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 , 2008

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PROPERTIES FOCUSED IN EASTERN KANSAS
MISSISSIPPI OIL RESERVOIR
NW Woodson County, Kansas

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TABLE OF CONTENTS

SUMMARY |  |  | 1 |
RISK FACTORS |  |  | 10 |
SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS |  |  | 24 |
USE OF PROCEEDS |  |  | 25 |
DIVIDEND POLICY |  |  | 25 |
CAPITALIZATION |  |  | 26 |
DILUTION |  |  | 27 |
PRICE RANGE OF COMMON STOCK |  |  | 28 |
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS |  |  | 29 |
BUSINESS AND PROPERTIES |  |  | 40 |
MANAGEMENT |  |  | 55 |
DIRECTOR COMPENSATION |  |  | 57 |
EXECUTIVE COMPENSATION |  |  | 57 |
CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS |  |  | 61 |
PRINCIPAL STOCKHOLDERS |  |  | 62 |
DESCRIPTION OF CAPITAL STOCK |  |  | 64 |
MATERIAL U.S. FEDERAL INCOME TAX CONSEQUENCES FOR NON-U.S. HOLDERS |  |  | 67 |
UNDERWRITING |  |  | 70 |
LEGAL MATTERS |  |  | 73 |
EXPERTS |  |  | 73 |
INDEPENDENT PETROLEUM ENGINEERS |  |  | 73 |
WHERE YOU CAN FIND MORE INFORMATION |  |  | 73 |
GLOSSARY |  |  | 74 |
INDEX TO FINANCIAL STATEMENTS |  |  | F-1 |

You should rely only on the information contained in this prospectus. We have not, and the underwriters have not, authorized anyone to provide you with different information. We are not making offers to sell or seeking offers to buy these securities in any jurisdiction where the offer or sale is not permitted. You should assume that the information contained in this prospectus is accurate as of the date on the front of this prospectus only, regardless of the time of delivery of this prospectus or any sale of our common stock. Our business, financial condition, operating results and prospects may have changed since that 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. Although we believe these third-party sources are reliable, we have not independently verified the information. In addition, some data are based on our good faith estimates.

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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 74 of this prospectus.
Unless stated otherwise, all information in this prospectus (other than in the financial statements) gives effect to a 1-for-5 reverse stock split of our outstanding shares of common stock, which will be effected prior to the consummation of this offering (and assumes no fractional shares will remain outstanding thereafter).
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 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.
Between March 31, 2007 and December 31, 2007, we deployed nearly $9.0 million in capital resources to acquire four major operating projects and drill 90 new wells. As a result, our estimated total proved oil reserves increased from zero as of March 31, 2007 to 1.2 million barrels of oil equivalent, or BOE, as of December 31, 2007. Of the 1.2 million BOE of total proved reserves, approximately 75% are proved developed and approximately 25% are proved undeveloped. The proved developed reserves consist of 40% proved developed producing reserves and 35% proved developed non-producing reserves.
The total proved PV10 (present value) before tax of our reserves as of December 31, 2007 was $30.9 million. 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” page 74 for our definition of PV10 and see “Business and Properties — Reserves” on page 49 for a reconciliation to the comparable GAAP financial measure.

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The following table sets forth a summary of our estimated proved reserves attributable to our properties as of December 31, 2007:

|  |  |  |  |  |  |  | PV10(2) |
Proved Reserves Category |  | Gross BOE(1) |  |  | Net BOE(1) |  |  | (Before Tax) |
Proved, Developed Producing |  |  | 643,573 |  |  |  | 488,897 |  |  | $ | 12,156,907 |
Proved, Developed Non-Producing |  |  | 606,133 |  |  |  | 432,875 |  |  | $ | 12,424,172 |
Proved, Undeveloped |  |  | 406,750 |  |  |  | 304,526 |  |  | $ | 6,329,438 |
Total Proved |  |  | 1,656,456 |  |  |  | 1,226,298 |  |  | $ | 30,910,517 |

(1) |  | BOE = barrels of oil equivalent (with 6 mcf of natural gas = 1 barrel of oil).

(2) |  | See “Glossary” on page 74 for our definition of PV10 and see “Business and Properties-Reserves” on page 49 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 year-ended December 31, 2006, 35.7 million barrels of oil were produced in Kansas. Of the total barrels produced in Kansas in 2006, 15 companies accounted for 30% of this production, with the remaining 70% produced by over 1,800 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 thousands of 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 a 1,980 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, as part of the agreement we established a joint operating account with MorMeg and funded it with $4.0 million for the initial development of the project. We hold a 95% working interest in the project and MorMeg retained a 5% carried working interest in the project, which will convert to a 30% working interest upon payout. As of December 31, 2007, production from the approximate 60 net wells on the Black Oaks Project averaged approximately 101 barrels of oil per day, or BOPD. We plan to invest at least $5 million from the proceeds of this offering to further develop this project.

| • | DD Energy Project. In September of 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. As of December 31, 2007, production from the 112 oil wells on this project averaged approximately 40 BOPD. We expect to continue to develop this project with approximately $4.0 million from the proceeds of this offering.

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| • | 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 of 2007 for $800,000 in cash. Subsequent to this acquisition, we purchased two additional 80 acre leases for a total of $50,000, which we incorporated into the project. As of December 31, 2007, production from the 191 oil wells on this project averaged approximately 45 BOPD. We plan to further develop this project with approximately $3.0 million from the proceeds of this offering.

| • | Thoren Project. We acquired the Thoren Project from MorMeg in April of 2007 for $400,000. The lease encompasses approximately 240 acres in Douglas County, Kansas. We hold a 100% working interest in the Thoren Project. As of December 31, 2007, production from the 31 oil wells on this lease averaged approximately 50 BOPD. We have completed our originally planned $600,000 development of the project. We intend to further develop this lease with approximately $500,000 from the proceeds of this offering.

| • | Gas City Project. The Gas City Project, located on approximately 4,400 acres in Allen County, Kansas, was acquired for $750,000 in February of 2006 and was our first property acquisition. Subsequent to acquisition, we invested an additional $650,000 in capital improvement and development of this project. In August of 2007, we entered into a Development Agreement with Euramerica Energy, Inc., or Euramerica, whereby Euramerica initially invested $524,000 in funds for development of the project. In February of 2008, Euramerica made its first quarterly payment related to the exercise of its option to purchase this property by paying the initial installment payment of $300,000 towards the full purchase price of $1.2 million by October 31, 2008. In addition, Euramerica has funded $500,000 of a required $2.0 million to be invested by August 31, 2008, which will be used for development of the Gas City Project. Production on this project as of December 31, 2007 from 15 wells was approximately 200,000 cubic feet per day. We are the operator of the project at a cost plus 17.5% basis. Until Euramerica has completed all payments related to the option exercise, we will retain a 100% working interest in the project. Following Euramerica’s February 29, 2008 payment toward the full purchase price, Euramerica receives revenues equal to a 95% net revenue interest and we receive a management fee equal to a 5% net revenue interest in the project until Euramerica has completed the full payment of its option exercise at which time this 5% net revenue interest management fee will be converted to a 5% carried working interest and Euramerica will receive assignment of its before payout 95% working interest in the project. When the project reaches payout our 5% carried working interest will increase to a 25% working interest and Euramerica will have a 75% working interest.

| • | Nickel Town Project. The option granted to us in connection with the Black Oaks Project would allow us to participate in another approximately 2,100 acre development and secondary recovery project with MorMeg, in the same area as the Black Oaks Project. Should we elect to participate in the Nickel Town Project, which requires us to complete development of the Black Oaks Project, we will have the option of negotiating new operating agreements with MorMeg. As of December 31, 2007, production on this project averaged approximately 25 BOPD.

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 near-term reserve and production growth from over 400 additional drilling locations identified on our properties. The structure and the continuous oil accumulation in Eastern Kansas and the mid-continent region of the United States, and the expected long-life production and reserves of our properties, are anticipated to enhance our opportunities for long-term profitability. As of December 31, 2007, our Black Oaks Project, DD Energy Project, Tri-County Project and Thoren Project have projected lives of 41 years, 33 years, 23 years and 21 years, respectively.

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| • | 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 Kansas and strategic partnership with Haas Petroleum, we believe we are well-positioned to pursue selected acquisitions 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 continue to 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 portfolio of pricing for our production as we continue to expand 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 continued drilling success within our acreage position, 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 May 20, 2008, our directors and executive officers owned approximately 9.1% of our outstanding common stock, with options that upon exercise would increase their ownership of our outstanding common stock to 16.7%. In addition, the compensation arrangements for our directors and executive officers are weighted toward future performance based equity payments rather than cash.

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.

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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 of 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 10 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 speculative nature of drilling wells, which often involves significant costs that may be more than our estimates, and may not result in any addition to our production or reserves.

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

| • | Our ability to achieve profitable business operations. We have a history of losses since our inception and we may never be profitable.

| • | 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.

Recent Developments
A number of recent developments have occurred which may significantly impact our business prospects and results. Some of the developments that we believe to be most important to our business are summarized below. However, you are encouraged to read the more thorough description of these and other recent developments in the “Business and Properties” section beginning on page 40 of this prospectus

| • | As of December 31, 2007, our estimated total proved reserves were 1.2 million BOE with a total proved PV10, before tax, of reserves of $30.9 million. See “Glossary” on page 74 for our definition of PV10 and see “Business and Properties-Reserves” on page 49 for a reconciliation to the comparable GAAP financial measure.

| • | On February 29, 2008, we received our first quarterly payment of $300,000 from Euramerica related to its option exercise contained in the amended and restated well development agreement with Euramerica executed on August 10, 2007. Further, Euramerica funded $500,000 of a required $2.0 million to be invested by August 31, 2008, which will be used for development of the Gas City Project.

| • | 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. This represents approximately 60% of our total current oil production on a net revenue basis and locks in approximately $6.8 million in gross revenue 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.

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| • | On March 13, 2008, we disclosed an operations update regarding our Black Oaks Project, which we acquired in April of 2007. Since January 15, 2008, our in-fill drilling and waterflood enhanced recovery techniques at the Black Oaks Project has increased oil production to an average of approximately 117 BOPD from a level of 32 BOPD per day when the project was originally acquired. As of December 31, 2007, the Black Oaks Project had 61 active production wells and 5 active water injection wells, an increase of 26 production wells and 5 water injection wells since the project was originally acquired. Water production from the Black Oaks Project as of December 31, 2007 was approximately 2,100 barrels of water per day, or BWPD. Based upon these results, we anticipate commencing Phase II of the development plan, which contemplates drilling 28 additional water injection wells and completing 23 additional producer wells.

Corporate Information
EnerJex Resources, Inc. is a Nevada corporation. Our principal executive office is located at 7300 W. 110th Street, 7th Floor, Overland Park, KS 66210, and our phone number is (913) 693-4600. We also maintain a website at www.enerjexresources.com. The information on our website is not incorporated by reference into this prospectus.

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The Offering

Common stock offered by us |  | shares
Common stock to be outstanding after this offering |  | shares
Public offering price |  | $ per share

Use of proceeds |  | We intend to use the net proceeds of this offering for debt repayment, development of our properties, working capital and other general corporate purposes. See the more detailed description of our expected use of the proceeds from this offering under the heading “Use of Proceeds” on page 25 of this prospectus.

Current OTC:BB symbol |  | EJXR
Proposed American Stock Exchange symbol |  | JEX
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 10 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.

The number of shares of our common stock that will be outstanding after this offering is based on 4,442,834 shares of our common stock outstanding as of May 20, 2008, and excludes:

| • | 458,500 shares of our common stock issuable upon exercise of outstanding options under our existing 2000 Stock Option and Incentive Plan and 2002/2003 Stock Option Plan, at a weighted average exercise price of $6.30 per share;

| • | 2,500 shares issuable upon conversion of a $25,000 unsecured, 6% convertible note due August 2, 2010, which is convertible into shares of our common stock at $10.00 per share;
| • | 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 of 2007; and

| • | shares of our common stock issuable upon the exercise of warrants to be issued to the underwriters in connection with this offering at an exercise price equal to 140% of the offering price.

In addition, unless specifically stated otherwise, all information in this prospectus assumes no exercise of the underwriters’ overallotment option to purchase additional shares.

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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 year ended March 31, 2007, (iii) the nine months ended December 31, 2007, and (iv) our balance sheets as of March 31, 2006, March 31, 2007 and December 31, 2007 are derived from our audited financial statements included elsewhere in this prospectus. The statements of operations, statements of cash flows and other financial data for the nine months ended December 31, 2006, are derived from our unaudited financial statements included elsewhere in this prospectus.
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 that may be expected for any future period. The following data should be read in conjunction with “Management’s Discussion and Analysis of Results of Operations and Financial Condition” and our financial statements and related notes included elsewhere in this prospectus.

|  |  |  |  |  |  |  |  |  |  | From Inception |
|  |  |  |  |  |  |  |  |  |  | (December 30, |
|  | Nine Months Ended |  |  | Year Ended |  |  | 2005) through |
|  | December 31, |  |  | March 31, |  |  | March 31, |
|  | 2007 |  |  | 2006 |  |  | 2007 |  |  | 2006 |
|  | (Audited) |  |  | (Unaudited) |  |  | (Audited) |  |  | (Audited) |
Statement of Operations: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Revenue |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Oil and natural gas activities |  | $ | 1,982,119 |  |  | $ | 76,314 |  |  | $ | 90,800 |  |  | $ | 2,142 |
Expenses |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Direct costs |  |  | 1,104,272 |  |  |  | 279,619 |  |  |  | 172,417 |  |  |  | 14,599 |
Repairs on oil and natural gas equipment |  |  | — |  |  |  | — |  |  |  | 165,603 |  |  |  | 40,436 |
Professional fees |  |  | 1,112,832 |  |  |  | 287,478 |  |  |  | 302,071 |  |  |  | 50,490 |
Investor relations fees |  |  | 164,435 |  |  |  | — |  |  |  | — |  |  |  | — |
General and administrative expenses |  |  | 1,758,262 |  |  |  | 319,366 |  |  |  | 470,789 |  |  |  | 21,700 |
Depreciation, depletion and amortization |  |  | 532,665 |  |  |  | 23,359 |  |  |  | 23,978 |  |  |  | 825 |
Impairment of goodwill |  |  | — |  |  |  | 677,000 |  |  |  | 677,000 |  |  |  | — |
Impairment of oil and natural gas properties subject to amortization |  |  | — |  |  |  | — |  |  |  | 273,959 |  |  |  | 468,081 |
Total expenses |  |  | 4,672,466 |  |  |  | 1,586,822 |  |  |  | 2,085,817 |  |  |  | 596,131 |
Net operating income (loss) |  |  | (2,690,347 | ) |  |  | (1,510,508 | ) |  |  | (1,995,017 | ) |  |  | (593,989 | )
Other income (expense): |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Interest expense |  |  | (507,640 | ) |  |  | (4,239 | ) |  |  | (8,434 | ) |  |  | (38 | )
Loan fees |  |  | (113,155 | ) |  |  | — |  |  |  | — |  |  |  | — |
Loan interest accretion |  |  | (766,800 | ) |  |  | — |  |  |  | — |  |  |  | — |
Interest income |  |  | — |  |  |  | 3,495 |  |  |  | 4,202 |  |  |  | 1,159 |
Gain (loss) on sale of asset |  |  | — |  |  |  | (3,854 | ) |  |  | (3,854 | ) |  |  | — |
Total other income (expense) |  |  | (1,317,595 | ) |  |  | (4,598 | ) |  |  | (8,086 | ) |  |  | 1,121 |
Net income (loss) |  | $ | (4,077,942 | ) |  | $ | (1,515,106 | ) |  | $ | (2,003,103 | ) |  | $ | (592,868 | )
Weighted average number of common shares outstanding — basic and fully diluted(1) |  |  | 20,691,689 |  |  |  | 12,142,498 |  |  |  | 12,241,589 |  |  |  | 8,563,044 |
Net income (loss) per share — basic and fully diluted |  | $ | (0.20 | ) |  | $ | (0.12 | ) |  | $ | (0.16 | ) |  | $ | (0.07 | )

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(1) |  | This information does not give effect to a 1-for-5 reverse stock split of our common stock, which will be effected prior to consummation of this offering.

|  |  |  |  |  |  |  |  |  |  | From Inception |
|  | Nine Months |  |  | Nine Months |  |  |  |  |  | (12/30/05) |
|  | Ended |  |  | Ended |  |  | Year Ended |  |  | through |
|  | December 31, |  |  | December 31, |  |  | March 31, |  |  | March 31, |
|  | 2007 |  |  | 2006 |  |  | 2007 |  |  | 2006 |
|  | (Audited) |  |  | (Unaudited) |  |  | (Audited) |  |  | (Audited) |
Statements of Cash Flows: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Cash used in operating activities |  | $ | (750,483 | ) |  | $ | (1,268,081 | ) |  | $ | (1,435,559 | ) |  | $ | (60,786 | )
Cash used in investing activities |  |  | (9,050,203 | ) |  |  | (160,379 | ) |  |  | (151,180 | ) |  |  | (767,550 | )
Cash provided from financing activities |  |  | 10,658,670 |  |  |  | 845,800 |  |  |  | 1,095,800 |  |  |  | 1,418,768 |
Increase (decrease) in cash and cash equivalents |  |  | 857,984 |  |  |  | (582,660 | ) |  |  | (490,939 | ) |  |  | 590,432 |
Cash and cash equivalents, beginning |  |  | 99,493 |  |  |  | 590,432 |  |  |  | 590,432 |  |  |  | — |
Cash and cash equivalents, end |  | $ | 957,477 |  |  | $ | 7,772 |  |  | $ | 99,493 |  |  | $ | 590,432 |
Supplemental disclosures: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Interest paid |  | $ | 75,935 |  |  | $ | 2,313 |  |  | $ | 5,407 |  |  | $ | 38 |
Income tax paid |  | $ | — |  |  | $ | — |  |  | $ | — |  |  | $ | — |
Non-cash transactions: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Stock, warrants and options issued for services |  | $ | 1,862,795 |  |  | $ | 644,000 |  |  | $ | 252,000 |  |  | $ | 33,000 |
Stock issued for properties not subject to amortization |  |  | — |  |  |  | — |  |  |  | 200,000 |  |  |  | — |
Stock issued for payment of liabilities net of asset in reverse merger |  |  | — |  |  |  | — |  |  |  | 306,000 |  |  |  | — |
Asset retirement obligation |  |  | 352,000 |  |  |  | — |  |  |  | — |  |  |  | — |
Loan costs |  |  | 879,955 |  |  |  | — |  |  |  | — |  |  |  | — |

|  | At |  |  |  |  |  |  |  |  |  |
|  | December 31, 2007 |  |  | At |  |  | At |  |  | At |
|  | Pro Forma |  |  | December 31, |  |  | March 31, |  |  | March 31, |
|  | As Adjusted(1) |  |  | 2007 |  |  | 2007 |  |  | 2006 |
|  |  |  |  | (Audited) |  |  | (Audited) |  |  | (Audited) |
Total Assets |  | $ |  |  |  | $ | 10,563,926 |  |  | $ | 492,507 |  |  | $ | 922,486 |
Total Liabilities |  |  |  |  |  |  | 8,509,906 |  |  |  | 537,097 |  |  |  | 71,586 |
Stockholders’ Equity (deficit) |  | $ |  |  |  | $ | 2,054,020 |  |  | $ | (44,590 | ) |  | $ | 850,900 |

(1) |  | The pro forma as adjusted column gives effect to the sale of shares of our common stock in this offering at the public offering price of $ per share, after deducting estimated underwriting discounts and commissions and estimated offering costs payable by us.

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

| • | the future prices of natural gas and oil;
| • | our ability to raise adequate working capital;
| • | success of our development and exploration efforts;
| • | demand for natural gas and oil;
| • | the level of our competition;
| • | our ability to attract and maintain key management, employees and operators;
| • | transportation and processing fees on our facilities;
| • | fuel conservation measures;
| • | alternate fuel requirements;
| • | government regulation and taxation;
| • | technical advances in fuel economy and energy generation devices; and
| • | our ability to efficiently explore, develop and produce sufficient quantities of marketable natural gas or oil in a highly competitive and speculative environment while maintaining quality and controlling costs.

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

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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:

| • | 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 60% of our total proved reserves as of December 31, 2007 consist of undeveloped and developed non-producing reserves, and those reserves may not ultimately be developed or produced.
As of December 31, 2007, approximately 25% of our total proved reserves were undeveloped and approximately 35% were developed non-producing. We plan to develop and produce all of our proved reserves, but ultimately some of these reserves may not be developed or produced. Furthermore, not all of our undeveloped or developed non-producing reserves may be ultimately produced in the time periods we have planned, at the costs we have budgeted, or at all.
Because we face uncertainties in estimating proven recoverable reserves, you should not place undue reliance on such reserve information.
Our reserve estimates and the future net cash flows attributable to those reserves are prepared by McCune Engineering, our independent petroleum and geological engineer. There are numerous uncertainties inherent in estimating quantities of proved reserves and cash flows from such reserves, including factors beyond our control and the control of McCune Engineering. Reserve engineering is a subjective process of estimating underground accumulations of natural gas and oil that can be economically extracted, which cannot be measured in an exact manner. The accuracy of an estimate of quantities of reserves, or of cash flows attributable to these reserves, is a function of the available data, assumptions regarding future natural gas and oil prices, expenditures for future development and exploitation activities, and engineering and geological interpretation and judgment. Reserves and future cash flows may also be subject to material downward or upward revisions based upon production history, development and exploitation activities and natural gas and oil prices. Actual future production, revenue, taxes, development expenditures, operating expenses, quantities of recoverable reserves and value of cash flows from those reserves may vary significantly from the

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assumptions and estimates in our reserve reports. Any significant variance from these assumptions to actual figures could greatly affect our estimates of reserves, the economically recoverable quantities of natural gas and oil attributable to any particular group of properties, the classification of reserves based on risk of recovery, and estimates of the future net cash flows. In addition, reserve engineers may make different estimates of reserves and cash flows based on the same available data. The estimated quantities of proved reserves and the discounted present value of future net cash flows attributable to those reserves included in this report were prepared by McCune Engineering in accordance with rules of the Securities and Exchange Commission, or SEC, and are not intended to represent the fair market value of such reserves.
The present value of future net cash flows from our proved reserves is not necessarily the same as the current market value of our estimated reserves. We base the estimated discounted future net cash flows from our proved reserves on prices and costs. However, actual future net cash flows from our natural gas and oil properties also will be affected by factors such as:

| • | Geological conditions;
| • | Assumptions governing future oil and natural gas prices;
| • | Amount and timing of actual production;
| • | Availability of funds;
| • | Future operating and development costs;
| • | Actual prices we receive for natural gas and oil;
| • | Supply and demand for our natural gas and oil;
| • | Changes in government regulations and taxation; and
| • | Capital costs of drilling new wells.

The timing of both our production and our incurrence of expenses in connection with the development and production of our properties will affect the timing of actual future net cash flows from proved reserves, and thus their actual present value. In addition, the 10% discount factor we use when calculating discounted future net cash flows may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with our business or the natural gas and oil industry in general.
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. The SEC’s guidelines strictly prohibit us from including “probable reserves” and “possible reserves” in such filings. We also caution you that the SEC views such “probable” and “possible” reserve estimates as inherently unreliable and these estimates may be seen as misleading to investors unless the reader is an expert in the natural gas and oil industry. Unless you have such expertise, you should not place undue reliance on these estimates. Potential investors should also be aware that such “probable” and “possible” reserve estimates will not be contained in any “resale” or other registration statement filed by us that offers or sells shares on behalf of purchasers of our common stock and may have an impact on the valuation of the resale of the shares. Except as required by applicable law, we undertake no duty to update this information and do not intend to update this information.
The differential between the New York Mercantile Exchange, or NYMEX, or other benchmark price of oil and natural gas and the wellhead price we receive could have a material adverse effect on our results of operations, financial condition and cash flows.
The prices that we receive for our oil and natural gas production sometimes trade at a discount to the relevant benchmark prices, such as NYMEX, that are used for calculating hedge positions. The difference between the benchmark price and the price we receive is called a differential. We cannot accurately predict oil and natural gas differentials. In recent years for example, production increases from competing Canadian and Rocky Mountain producers, in conjunction with limited refining and pipeline capacity from the Rocky

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Mountain area, have gradually widened this differential. Increases in the differential between the benchmark price for oil and natural gas and the wellhead price we receive could have a material adverse effect on our results of operations, financial condition and cash flows by decreasing the proceeds we receive for our oil and natural gas production in comparison to what we would receive if not for the differential.
The natural gas and oil business involves numerous uncertainties and operating risks that can prevent us from realizing profits and can cause substantial losses.
Our development, exploitation and exploration activities may be unsuccessful for many reasons, including weather, cost overruns, equipment shortages and mechanical difficulties. Moreover, the successful drilling of a natural gas and oil well does not ensure a profit on investment. A variety of factors, both geological and market-related, can cause a well to become uneconomical or only marginally economical. In addition to their cost, unsuccessful wells can hurt our efforts to replace reserves.
The natural gas and oil business involves a variety of operating risks, including:

| • | unexpected operational events and/or conditions;
| • | unusual or unexpected geological formations;
| • | reductions in natural gas and oil prices;
| • | limitations in the market for oil and natural gas;
| • | adverse weather conditions;
| • | facility or equipment malfunctions;
| • | title problems;
| • | natural gas and oil quality issues;
| • | pipe, casing, cement or pipeline failures;
| • | natural disasters;
| • | fires, explosions, blowouts, surface cratering, pollution and other risks or accidents;
| • | environmental hazards, such as natural gas leaks, oil spills, pipeline ruptures and discharges of toxic gases;
| • | compliance with environmental and other governmental requirements; and
| • | uncontrollable flows of oil, natural gas or well fluids.

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

| • | injury or loss of life;
| • | severe damage to and destruction of property, natural resources and equipment;
| • | pollution and other environmental damage;
| • | clean-up responsibilities;
| • | regulatory investigation and penalties;
| • | suspension of our operations; and
| • | repairs to resume operations.

Because we use third-party drilling contractors to drill our wells, we may not realize the full benefit of worker compensation laws in dealing with their employees. Our insurance does not protect us against all

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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. However, over 90% of our wells drilled through December 31, 2007 have been development wells. A variety of factors, both geological and market-related, can cause a well to become uneconomical or only marginally economic. Our initial drilling and development sites, and any potential additional sites that may be developed, require significant additional exploration and development, regulatory approval and commitments of resources prior to commercial development. If our actual drilling and development costs are significantly more than our estimated costs, we may not be able to continue our business operations as proposed and would be forced to modify our plan of operation.
Development of our reserves, when established, may not occur as scheduled and the actual results may not be as anticipated. Drilling activity and access to capital may result in downward adjustments in reserves or higher than anticipated costs. Our estimates will be based on various assumptions, including assumptions over which we have control and assumptions required by the SEC relating to natural gas and oil prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. The process of estimating our natural gas and oil reserves is anticipated to be extremely complex, and will require significant decisions and assumptions in the evaluation of available geological, geophysical, engineering and economic data for each reservoir. Our estimates may not be reliable enough to allow us to be successful in our intended business operations. Our actual production, revenues, taxes, development expenditures and operating expenses will likely vary from those anticipated. These variances may be material.
Unless we replace our oil and natural gas reserves, our reserves and production will decline, which would adversely affect our cash flows and income.
Unless we conduct successful development, exploitation and exploration activities or acquire properties containing proved reserves, our proved reserves will decline as those reserves are produced. Producing oil and natural gas reservoirs generally are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Our future oil and natural gas reserves and production, and, therefore our cash flow and income, are highly dependent on our success in efficiently developing and exploiting our current reserves and economically finding or acquiring additional recoverable reserves. We may be unable to make such acquisitions because we are:

| • | unable to identify attractive acquisition candidates or negotiate acceptable purchase contracts with them;
| • | unable to obtain financing for these acquisitions on economically acceptable terms; or
| • | outbid by competitors.

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If we are unable to develop, exploit, find or acquire additional reserves to replace our current and future production, our cash flow and income will decline as production declines, until our existing properties would be incapable of sustaining commercial production.
A significant portion of our potential future reserves and our business plan depend upon secondary recovery techniques to establish production. There are significant risks associated with such techniques.
We anticipate that a significant portion of our future reserves and our business plan will be associated with secondary recovery projects that are either in the initial stage of implementation or are scheduled for implementation. We anticipate that secondary recovery will affect our reserves and our business plan, and the exact project initiation dates and, by the very nature of waterflood operations, the exact completion dates of such projects are uncertain. In addition, the reserves and our business plan associated with these secondary recovery projects, as with any reserves, are estimates only, as the success of any development project, including these waterflood projects, cannot be ascertained in advance. If we are not successful in developing a significant portion of our reserves associated with secondary recovery methods, then the project may be uneconomic or generate less cash flow and reserves than we had estimated prior to investing the capital. Risks associated with secondary recovery techniques include, but are not limited to, the following:

| • | higher than projected operating costs;
| • | lower-than-expected production;
| • | longer response times;
| • | higher costs associated with obtaining capital;
| • | unusual or unexpected geological formations;
| • | fluctuations in natural gas and oil prices;
| • | regulatory changes;
| • | shortages of equipment; and
| • | lack of technical expertise.

If any of these risks occur, it could adversely affect our financial condition or results of operations.
Any acquisitions we complete are subject to considerable risk.
Even when we make acquisitions that we believe are good for our business, any acquisition involves potential risks, including, among other things:

| • | the validity of our assumptions about reserves, future production, revenues and costs, including synergies;
| • | an inability to integrate successfully the businesses we acquire;
| • | a decrease in our liquidity by using our available cash or borrowing capacity to finance acquisitions;
| • | a significant increase in our interest expense or financial leverage if we incur additional debt to finance acquisitions;
| • | the assumption of unknown liabilities, losses or costs for which we are not indemnified or for which our indemnity is inadequate;
| • | the diversion of management’s attention from other business concerns;
| • | an inability to hire, train or retain qualified personnel to manage the acquired properties or assets;
| • | the incurrence of other significant charges, such as impairment of goodwill or other intangible assets, asset devaluation or restructuring charges;

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| • | unforeseen difficulties encountered in operating in new geographic or geological areas; and
| • | customer or key employee losses at the acquired businesses.

Our decision to acquire a property will depend in part on the evaluation of data obtained from production reports and engineering studies, geophysical and geological analyses and seismic and other information, the results of which are often incomplete or inconclusive.
Our reviews of acquired properties can be inherently incomplete because it is not always feasible to perform an in-depth review of the individual properties involved in each acquisition. Even a detailed review of records and properties may not necessarily reveal existing or potential problems, nor will it permit a buyer to become sufficiently familiar with the properties to assess fully their deficiencies and potential. Inspections may not always be performed on every well, and environmental problems, such as ground water contamination, plugging or orphaned well liability are not necessarily observable even when an inspection is undertaken.
We must obtain governmental permits and approvals for drilling operations, which can result in delays in our operations, be a costly and time consuming process, and result in restrictions on our operations.
Regulatory authorities exercise considerable discretion in the timing and scope of permit issuances in the region in which we operate. Compliance with the requirements imposed by these authorities can be costly and time consuming and may result in delays in the commencement or continuation of our exploration or production operations and/or fines. Regulatory or legal actions in the future may materially interfere with our operations or otherwise have a material adverse effect on us. In addition, we are often required to prepare and present to federal, state or local authorities data pertaining to the effect or impact that a proposed project may have on the environment, threatened and endangered species, and cultural and archaeological artifacts. Accordingly, the permits we need may not be issued, or if issued, may not be issued in a timely fashion, or may involve requirements that restrict our ability to conduct our operations or to do so profitably.
Due to our lack of geographic diversification, adverse developments in our operating areas would materially affect our business.
We currently only lease and operate oil and natural gas properties located in Eastern Kansas. As a result of this concentration, we may be disproportionately exposed to the impact of delays or interruptions of production from these properties caused by significant governmental regulation, transportation capacity constraints, curtailment of production, natural disasters, adverse weather conditions or other events which impact this area.
We depend on a small number of customers for all, or a substantial amount of our sales. If these customers reduce the volumes of oil and natural gas they purchase from us, our revenue and cash available for distribution will decline to the extent we are not able to find new customers for our production.
We have contracted with Shell for the sale of all of our oil and will likely contract for the sale of our natural gas with one, or a small number, of buyers, and it is not likely that there will be a large pool of available purchasers. If a key purchaser, such as Shell, 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.

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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 income and therefore 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 intend to enter into additional derivative arrangements, similar to the 18-month fixed price contract with Shell for production beginning on April 1, 2008, for up to 80% of our oil and natural gas production that could result in both realized and unrealized hedging losses. As of December 31, 2007 we had not incurred any such losses. The extent of our commodity price exposure is related largely to the effectiveness and scope of our derivative activities. For example, the derivative instruments we may utilize may be based on posted market prices, which may differ significantly from the actual crude oil, natural gas and NGL prices we realize in our operations.
Our actual future production may be significantly higher or lower than we estimate at the time we enter into derivative transactions for such period. If the actual amount is higher than we estimate, we will have greater commodity price exposure than we intended. If the actual amount is lower than the nominal amount that is subject to our derivative financial instruments, we might be forced to satisfy all or a portion of our derivative transactions without the benefit of the cash flow from our sale or purchase of the underlying physical commodity, resulting in a substantial diminution of our liquidity. As a result of these factors, our derivative activities may not be as effective as we intend in reducing the volatility of our cash flows, and in certain circumstances may actually increase the volatility of our cash flows. In addition, our derivative activities are subject to the risks that a counterparty, such as Shell, may not perform its obligation under the applicable derivative instrument.
Our business depends in part on gathering and transportation facilities owned by others. Any limitation in the availability of those facilities could interfere with our ability to market our oil and natural gas production and could harm our business.
The marketability of our oil and natural gas production will depend in a very large part on the availability, proximity and capacity of pipelines, oil and natural gas gathering systems and processing facilities. The amount of oil and natural gas that can be produced and sold is subject to curtailment in certain circumstances, such as pipeline interruptions due to scheduled and unscheduled maintenance, excessive pressure, physical damage or lack of available capacity on such systems. The curtailments arising from these and similar circumstances may last from a few days to several months. In many cases, we will be provided only with limited, if any, notice as to when these circumstances will arise and their duration. Any significant curtailment in gathering system or pipeline capacity could significantly reduce our ability to market our oil and natural gas production and harm our business.
The high cost of drilling rigs, equipment, supplies, personnel and other services could adversely affect our ability to execute on a timely basis our development, exploitation and exploration plans within our budget.
Shortages or an increase in cost of drilling rigs, equipment, supplies or personnel could delay or interrupt our operations, which could impact our financial condition and results of operations. Drilling activity in the geographic areas in which we conduct drilling activities may increase, which would lead to increases in associated costs, including those related to drilling rigs, equipment, supplies and personnel and the services

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and products of other vendors to the industry. Increased drilling activity in these areas may also decrease the availability of rigs. Although Haas Petroleum is currently providing two drilling rigs to the Black Oaks Project, we do not have any contracts for drilling rigs and drilling rigs may not be readily available when we need them. Drilling and other costs may increase further and necessary equipment and services may not be available to us at economical prices.
Our exposure to risks associated with possible leasehold defects could materially adversely impact our business.
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.
Our reserves are subject to risks associated with the fact that 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 plan to take on working interest partners who will contribute to the costs of drilling and completion and then share in revenues derived from production. In addition, we may in the future, due to a lack of capital or other strategic reasons, establish joint venture partnerships or farm out all or part of our development efforts. These economic strategies may have a dilutive effect on our lease ownership and could significantly reduce our operating revenues.
We are subject to complex laws and regulations, including environmental regulations, which can adversely affect the cost, manner or feasibility of doing business.
Development, production and sale of natural gas and oil in the United States are subject to extensive laws and regulations, including environmental laws and regulations. We may be required to make large expenditures to comply with environmental and other governmental regulations. Matters subject to regulation include, but are not limited to:

| • | location and density of wells;
| • | the handling of drilling fluids and obtaining discharge permits for drilling operations;
| • | accounting for and payment of royalties on production from state, federal and Indian lands;
| • | bonds for ownership, development and production of natural gas and oil properties;
| • | transportation of natural gas and oil by pipelines;
| • | operation of wells and reports concerning operations; and
| • | taxation.

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

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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 $1,000,000 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.

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We may incur substantial write-downs of the carrying value of our natural gas and oil properties, which would adversely impact our earnings.
We review the carrying value of our natural gas and oil properties under the full-cost accounting rules of the SEC on a quarterly basis. This quarterly review is referred to as a ceiling test. Under the ceiling test, capitalized costs, less accumulated amortization and related deferred income taxes, may not exceed an amount equal to the sum of the present value of estimated future net revenues (adjusted for cash flow hedges) less estimated future expenditures to be incurred in developing and producing the proved reserves, less any related income tax effects. In calculating future net revenues, current prices and costs used are those as of the end of the appropriate quarterly period. Such prices are utilized except where different prices are fixed and determinable from applicable contracts for the remaining term of those contracts, including the effects of derivatives qualifying as cash flow hedges. Two primary factors impacting this test are reserve levels and current prices, and their associated impact on the present value of estimated future net revenues. Revisions to estimates of natural gas and oil reserves and/or an increase or decrease in prices can have a material impact on the present value of estimated future net revenues. Any excess of the net book value, less deferred income taxes, is generally written off as an expense. Under SEC regulations, the excess above the ceiling is not expensed (or is reduced) if, subsequent to the end of the period, but prior to the release of the financial statements, natural gas and oil prices increase sufficiently such that an excess above the ceiling would have been eliminated (or reduced) if the increased prices were used in the calculations.
We have recorded a total of $742,040 impairment on our oil and natural gas properties. There was no impairment of assets during the 9 months ended December 31, 2007. We recorded $273,959 impairment in the fiscal year ended March 31, 2007 and $468,068 during the period from inception (December 20, 2005) through March 31, 2006.
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 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, workover and development activities.
If low natural gas and oil prices, operating difficulties or other factors, many of which are beyond our control, cause our revenues or cash flows from operations to decrease, we may be limited in our ability to spend the capital necessary to complete our development, production exploitation and exploration programs. If our resources or cash flows do not satisfy our operational needs, we will require additional financing, in addition to anticipated cash generated from our operations, to fund our planned growth. Additional financing might not be available on terms favorable to us, or at all. If adequate funds were not available or were not available on acceptable terms, our ability to fund our operations, take advantage of unanticipated opportunities, develop or enhance our business or otherwise respond to competitive pressures would be significantly limited. In such a capital restricted situation, we may curtail our acquisition, drilling, development, and exploration activities or be forced to sell some of our assets on an untimely or unfavorable basis.
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 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 not entered into

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an employment agreement with Mr. Cochennet, nor do we maintain key person insurance on Mr. Cochennet. 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
Although we plan to repay our outstanding debt from proceeds of this offering, until we repay the full amount of the $9.0 million debentures, outstanding bank loans and promissory notes, we may continue to have substantial indebtedness, which is secured by all of our assets.
On April 11, 2007, we sold $9.0 million in debentures to certain lenders pursuant to a securities purchase agreement and certain related agreements. Further, in fiscal 2008 we have incurred approximately $3.2 million in additional debt. While we intend to pay off the full amount of the debentures and other debt with proceeds from the offering, in the event that we default with respect to the debentures or other secured debt, the lenders may enforce their rights as a secured party and we may lose all or a portion of our assets or be forced to materially reduce our business activities.
We may be required to issue additional shares of common stock to our debenture holders, which would cause immediate and substantial dilution to our existing stockholders.
We are contractually obligated to meet 30-day average production thresholds while the debentures are outstanding. We must achieve production of the equivalent of an average of 182 barrels of oil equivalent per day (BOPDE) as of June 30, 2008, 170 BOPDE as of December 31, 2008 and 206 BOPDE as of June 30, 2009. Our production at December 31, 2007 was 252 BOPD. If we do not meet the stated production thresholds on any of these dates, we will be required to issue an additional 600,000 shares of our common stock to the debenture holders for each date we fail to meet the thresholds (the ’Production Shares”). In addition, we are obligated to register the Production Shares with the SEC so that they may be freely transferable. Furthermore, we are obligated to register any shares that are issued in lieu of cash interest payments due to the debenture holders (the “Interest Shares”). The issuance of any Production Shares or Interest Shares would cause immediate dilution to the interests of other stockholders. However, we plan to repay the full amount of the debentures from funds received in this offering, which will eliminate the potential for us to issue any Production Shares or Interest Shares or to register any such shares with the SEC.
Risks Associated with our Common Stock and the Offering
Our common stock is traded on an illiquid market, making it difficult for investors to sell their shares.
As of March 23, 2007, our common stock commenced trading on the Over-the-Counter Bulletin Board under the symbol “EJXR,” 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. Although we expect our common stock to be listed on AMEX, we may not be able to obtain a listing for our common stock on AMEX or a liquid market may not develop.
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;

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| • | 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.

Due to our low book value, investors in this offering will incur substantial immediate dilution of up to $ per share.
Investors who purchase shares of common stock in this offering will pay a per share price that substantially exceeds the value of our assets after subtracting liabilities. Accordingly, the offering price is substantially higher than the book value per share of our outstanding common stock. As a result, an investor who acquires shares of common stock in this offering will incur immediate substantial dilution of approximately $ per share. For a more detailed description of how new stockholders will incur dilution, see the “Dilution” section beginning on page 26 of this prospectus.
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 after the offering or the perception that such sales could occur. This could make it more difficult to raise funds through future offerings of common stock.
On completion of this offering, we will have outstanding shares of our common stock. This includes the shares we are selling in this offering, all of which may be resold in the public market immediately. Our executive officers and directors own 404,102 shares and also hold currently exercisable options to acquire an additional 340,000 shares after the closing of this offering. In addition our debenture holders currently hold an aggregate of shares. The shares held by our executive officers and directors are subject to lock-up agreements that prohibit their sale until at least 180 days after the date of this prospectus. Our debenture holders have agreed to subject their shares to lock-up agreements that prohibit the sale of their shares until at least 60 days after the date of this prospectus. Each of these lock-up periods can be extended for up to an additional 34 days under certain circumstances. Our underwriters, in their sole discretion, may permit our executive officers, directors, or debenture holders to sell their shares prior to the expiration of their respective lock-up agreements. After the lock-up agreements expire, all of the shares of our common stock held by our executive officers, directors and debenture holders will be eligible for sale in the public market. In addition, the 533,500 shares of our common stock that are subject to outstanding options and warrants as of March 31, 2008 will be eligible for sale in the public market to the extent permitted by the provisions of the various vesting arrangements, the lock-up agreements and Rule 144 under the Securities Act. If these additional shares are sold, or it is perceived they will be sold, the trading price of our common stock

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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.
We have substantial discretion to use the proceeds from this offering for business activities that may not be successful, which could adversely affect the trading price of our common stock.
Other than with respect to the repayment of the debentures, our management has broad discretion as to how to spend the proceeds from this offering and may spend these proceeds in ways with which our stockholders may not agree or on business activities or acquisitions which may not be successful. If we choose to invest some or all of the proceeds from this offering, that investment may not yield a favorable return, if any. If our management fails to effectively use the proceeds from this offering, our business and results of operations could be adversely affected.
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 and investment opportunities.
We may issue shares of preferred stock with greater rights than our common stock.
Although we have no current plans, arrangements, understandings or agreements to issue any preferred stock, our articles of incorporation authorizes our board of directors to issue one or more series of preferred stock and set the terms of the preferred stock without seeking any further approval from our stockholders. Any preferred stock that is issued may rank ahead of our common stock, with respect to dividends, liquidation rights and voting rights, among other things.
We have derivative securities currently outstanding. Exercise of these derivatives will cause dilution to existing and new stockholders.
As of March 31, 2008, we had options and warrants to purchase approximately 533,500 shares of common stock outstanding in addition to 2,500 shares issuable upon conversion of a convertible note. The exercise of our outstanding options and warrants, and the conversion of the note, will cause additional shares of common stock to be issued, resulting in dilution to our existing common stockholders.

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SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS
This prospectus contains forward-looking statements intended to qualify for the safe harbors from liability established by the Private Securities Litigation Reform Act of 1995, Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. 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,” “should” or “will” or the negative of these terms or other comparable terminology. Although we do not make forward-looking statements unless we believe we have a reasonable basis for doing so, we cannot guarantee their accuracy. These statements are only predictions and involve known and unknown risks, uncertainties and other factors, including the risks outlined under “Risk Factors” or elsewhere in this 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:

| • | estimated quantities and quality of oil and natural gas reserves;
| • | fluctuations in the price of oil and natural gas;
| • | inability to efficiently manage our operations;
| • | the inability of management to effectively implement our strategies and business plans;
| • | potential default under our secured obligations or material debt agreements;
| • | approval of certain parts of our operations by state regulators;
| • | inability to hire or retain sufficient qualified operating field personnel;
| • | inability to attract and obtain additional development capital;
| • | increases in interest rates or our cost of borrowing;
| • | deterioration in general or regional (especially Eastern Kansas) economic conditions;
| • | adverse state or federal legislation or regulation that increases the costs of compliance, or adverse findings by a regulator with respect to existing operations;
| • | the occurrence of natural disasters, unforeseen weather conditions, or other events or circumstances that could impact our operations or could impact the operations of companies or contractors we depend upon in our operations;
| • | inability to acquire mineral leases at a favorable economic value that will allow us to expand our development efforts;
| • | inability to achieve future sales levels or other operating results;
| • | 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.

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USE OF PROCEEDS
We estimate the net proceeds to us from the sale of shares of common stock that we are selling in this offering will be approximately $ million, after deducting the underwriting discounts and commissions and estimated offering expenses payable by us. If the underwriters’ option to purchase additional shares is exercised in full, we estimate we will receive net proceeds of approximately $ million.
Of the net proceeds from this offering, we expect to use approximately:

| • | $9.0 million, plus accrued interest, for the repayment of our 10% debentures, which are due in March of 2010. We used the $9.0 million in proceeds from the debentures for development of our Black Oaks Project, the Thoren Project acquisition, other lease acquisitions and general working capital;

| • | $965,000, plus accrued interest, for the repayment of our 5% promissory notes, which are due in September of 2008. These notes were incurred as part of a $2.7 million DD Energy acquisition completed in September 2007, whereby the sellers of the leaseholds agreed to carry a portion of the purchase price;

| • | $1,549,000, plus accrued interest, for the repayment of our 8.5% promissory note, which is due in September of 2011. We issued this note to Cornerstone Bank in connection with the purchase of the DD Energy Project; and

| • | Approximately $12.5 million for the continued development of our existing projects.

We intend to use the remainder of the net proceeds from this offering for capital expenditures, working capital and general corporate purposes. The amounts actually spent for these purposes may vary significantly and will depend on a number of factors, including our operating costs and other factors described under “Risk Factors.” While we have no present understandings, commitments or agreements to enter into any material acquisitions, we may also use a portion of the net proceeds to acquire property or equipment that complements our business. Accordingly, management will retain broad discretion as to the allocation of the net proceeds of this offering.
Pending the uses described above, we will invest the net proceeds of this offering in short-term, interest-bearing, investment-grade securities. We cannot predict whether the proceeds will yield a favorable return.
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 debentures from paying cash dividends on our common stock, without written consent from our debenture holders. 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 and other factors our board of directors deems relevant.

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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, 2007 on:

| • | an actual consolidated historical basis; and
| • | on a pro forma basis to reflect the sale of shares of our common stock in this offering at an assumed offering price of $ per share, after deducting estimated underwriting discounts and commissions and estimate offering costs payable by us, and the use of proceeds therefrom.

|  | As of December 31, 2007 |
|  |  |  |  | Pro Forma |
|  | Actual |  |  | As Adjusted |
|  | (Audited) |  |  | (Unaudited) |
Long-term debt |  | $ | 6,173,452 |  |  | $ |  |
Stockholders’ equity: |  |  |  |  |  |  |  |
Common stock; $0.001 par value, 100,000,000 shares authorized, 22,203,256 issued and outstanding, actual(1); issued and outstanding, pro forma as adjusted |  |  | 22,203 |  |  |  |  |
Additional paid-in capital |  |  | 8,705,730 |  |  |  |  |
Accumulated (deficit) |  |  | (6,673,913 | ) |  |  |  |
Total stockholders’ equity |  |  | 2,054,020 |  |  |  |  |
Total capitalization |  | $ | 8,227,472 |  |  | $ |  |

(1) |  | This information does not give effect to a 1-for-5 reverse stock split of our common stock, which will be effected prior to consummation of this offering.

The information in the table above excludes:

| • | 458,500 shares of our common stock issuable upon exercise of outstanding options under our existing 2000 Stock Option and Incentive Plan and 2002/2003 Stock Option Plan, at a weighted average exercise price of $6.30 per share;

| • | 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;

| • | 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; and

| • | shares of our common stock issuable upon the exercise of warrants to be issued to the underwriters in connection with this offering at an exercise price equal to 140% of the offering price.

The information in the table above:

| • | Assumes no exercise of the underwriters’ option to purchase additional shares: and
| • | The Pro Forma as Adjusted column gives effect to a 1-for-5 reverse stock split of our outstanding shares of common stock, which will be effected prior to the consummation of this offering (and assumes no fractional shares will remain outstanding thereafter).

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DILUTION
If you purchase our shares of common stock in this offering, you will experience immediate and substantial dilution to the extent of the difference between the public offering price per share and the net tangible book value per share of our common stock after this offering. We calculate net tangible book value per share by dividing the net tangible book value, tangible assets less total liabilities, by the number of outstanding shares of our common stock.
Our net tangible book value (unaudited) at , 2008, was approximately $ or $ per share, based on shares of our common stock outstanding as of , . After giving effect to the sale of shares of common stock by us at a public offering price of $ per share, less our estimated offering expenses, our net tangible book value (unaudited) at , 2008, would have been approximately $ , or $ per share. This represents an immediate increase in the net tangible book value of $ per share to existing stockholders and an immediate dilution of $ per share to investors in this offering. The following table illustrates this per share dilution:

Assumed public offering price per share |  | $ |  |
Net tangible book value per share as of , 2008 (unaudited) |  |  |  |
Increase in net tangible book value per share after the offering |  |  |  |
As adjusted net tangible book value per share after this offering |  |  |  |
Dilution in as adjusted net tangible book value per share to new investors |  | $ |  |

The following table summarizes, on an as adjusted basis set forth above as of , 2008, the total number of shares of common stock owned by existing stockholders and to be owned by new investors, the total consideration paid, and the average price per share paid by our existing stockholders and to be paid by new investors in this offering at $ , calculated before deduction of estimated underwriting discounts and commissions.

|  | Shares Purchased |  |  | Total Consideration |  |  | Average Price |
|  | Number |  |  | Percent |  |  | Amount |  |  | Percent |  |  | per Share |
|  | (In thousands) |
Existing Stockholders |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
New Public Investors |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Total |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |

If the over-allotment option is exercised in full, the number of shares of common stock held by existing stockholders will be reduced to , or approximately % of the total number of shares of common stock outstanding after this offering. Sales of common stock by us and by the selling stockholders, if the over-allotment is exercised in full, will increase the number of shares of common stock held by new investors to , or approximately % of the total number of shares of common stock outstanding after this offering.
As of , 2008, there were shares of our common stock outstanding held by approximately stockholders of record and approximately beneficial owners.

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PRICE RANGE OF COMMON STOCK
Prior to completion of the reverse merger with Midwest Energy in August of 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.” 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 2007 and 2008 and the relevant portion of the first quarter of fiscal year 2009. The quotations reflect inter-dealer prices without retail mark-up, markdown, or commissions and may not represent actual transactions.

|  | Low |  |  | High |
Fiscal 2007 |  |  |  |  |  |  |  |
Quarter ended June 30, 2006 |  | $ | 0.50 |  |  | $ | 6.25 |
Quarter ended September 30, 2006 |  | $ | 4.50 |  |  | $ | 7.50 |
Quarter ended December 31, 2006 |  | $ | 3.75 |  |  | $ | 6.00 |
Quarter ended March 31, 2007 |  | $ | 0.50 |  |  | $ | 0.60 |
Fiscal 2008 |  |  |  |  |  |  |  |
Quarter ended June 30, 2007 |  | $ | 0.50 |  |  | $ | 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 (through , 2008) |  | $ |  |  |  | $ |  |

The last reported sale price of our common stock on the OTC:BB was $ per share on , 2008. As of , 2008, there were holders of record of our common stock.

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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, we implement an accelerated development program utilizing capital resources, a regional operating focus, an experienced management and technical team, and enhanced recovery technologies to attempt to increase production and increase returns for our stockholders. Our oil and natural gas acquisition and development activities are currently focused in Eastern Kansas.
Between March 31, 2007 and December 31, 2007, we deployed nearly $9.0 million in capital resources to acquire four major operating projects and drill 90 new wells including 25 injector wells. As a result, our estimated total proved oil reserves increased from zero as of March 31, 2007 to a net 1.2 million barrels of oil equivalent, or BOE, as of December 31, 2007. Of the 1.2 million BOE of total proved reserves, approximately 75% are proved developed and approximately 25% are proved undeveloped. The proved developed reserves consist of 40% proved developed producing reserves and 35% proved developed non-producing reserves.
The total proved PV10 (present value) before tax of our reserves as of December 31, 2007 was $30.9 million. 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 74 for our definition of PV10 and “Business and Properties — Reserves” on page 49 for a reconciliation to the comparable GAAP financial measure.
Recent Developments
On February 29, 2008, we received our first quarterly payment of $300,000 from Euramerica related to its option exercise contained in the amended and restated well development agreement with Euramerica executed on August 10, 2007. Further, through April of 2008, Euramerica has funded $500,000, of a required $2.0 million to be invested by August 31, 2008, which will be used for development of the Gas City Project.
As of December 31, 2007, our production was 252 BOPD.
On March 6, 2008, we entered into an agreement with 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. This represents approximately 60% of our total current oil production on a net revenue basis and locks in approximately $6.8 million in gross revenue 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.
On March 13, 2008, we disclosed an operations update regarding our Black Oaks Project, which we acquired in April of 2007. Since January 15, 2008 our in-fill drilling and waterflood enhanced recovery techniques at the Black Oaks Project has increased oil production to an average of approximately 117 BOPD from a level of an average of approximately 32 BOPD per day when the project was originally acquired. As of December 31, 2007, the Black Oaks Project had 61 active production wells and 5 active water injection wells, an increase of 26 production wells and 5 water injection wells since the project was originally acquired. Water production from the Black Oaks Project as of December 31, 2007 was approximately 2,100 BWPD. Based upon these results, we anticipate commencing Phase II of the development plan, which contemplates drilling 28 additional water injection wells and completing 23 additional producer wells.

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Results of Operations for the Fiscal Year Ended March 31, 2007.
As of March 31, 2007, we were in the early stage of developing properties in Kansas and had minimal production or revenues from those properties. Our operations as of March 31, 2007 were limited to technical evaluation of these properties, the design of development plans to exploit the oil and natural gas resources on those properties, as well as seeking financing opportunities to acquire additional oil and natural gas properties.
Oil and natural gas revenues for the fiscal year ended March 31, 2007 were $90,800 compared to $2,142 for the period from inception (December 30, 2005) through March 31, 2006 and, primarily, relate to natural gas production revenues.
Our expenses for the fiscal year ended March 31, 2007 consisted principally of direct and repair costs associated with the Gas City Project, professional and administrative costs associated with evaluating potential acquisitions, general and administrative costs associated with the business start-up (including hiring employees), and expenses associated with raising capital. Such costs totaled $1,110,880 in the fiscal year ended March 31, 2007. By comparison, these same costs totaled $127,225 for the period from inception (December 30, 2005) through March 31, 2006.
In connection with the reverse merger transaction, we recorded goodwill of $687,000 for liabilities of that amount assumed and for a patent we received that had no book value. The goodwill was impaired and recorded as an expense at September 30, 2006. We have sold the patent for $10,000 and reduced the impairment expense by $10,000 in October 2006.
Total cost and operating expenses for the fiscal years ended March 31, 2007 and 2006, respectively, were $2,085,817 and $596,131. Total other expense for the fiscal year ended March 31, 2007 was $8,086 and included interest expense and a loss on the sale of a vehicle. Total other income for the fiscal year ended March 31, 2006 was $1,121, primarily from interest income.
Total expenses for the fiscal year ended March 31, 2007 were $2,093,903. We had a net loss for the same period of $2,003,103 or $0.16 per share. Because our operating expenses as of March 31, 2007 exceeded our revenues, we did not attribute any reserves to our properties for the year ended March 31, 2007.
Results of Operations for the Nine Months Ended December 31, 2007 and 2006.
Income:

|  | Nine Months Ended |  |
|  | December 31, |  |
|  | 2007 |  | 2006 |  |
|  | (Audited) |  | (Unaudited) |  | Increase/(Decrease)
|  | Amount |  | Amount |  | $
Oil and natural gas revenues |  | $ | 1,982,119 |  |  | $ | 76,314 |  |  | $ | 1,905,805 |

Revenues
Oil and natural gas revenues for the nine months ended December 31, 2007 were $1,982,119 compared to revenues of $76,314 in the nine months ended December 31, 2006. The increase in revenues is primarily the result of the sale of oil from leases acquired beginning in April of 2007 and developed during the period. There were no oil sales revenues in the prior period as we did not own any producing oil leases. The average price per barrel of oil sold during the nine months ended December 31, 2007 was $74.78. The average price per Mcf for natural gas sales during the nine month period ended December 31, 2007 was $5.25.

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Expenses:

|  | Nine Months Ended |  |  |  |
|  | December 31, |  |  |  |
|  | 2007 |  |  | 2006 |  |  |  |
|  | (Audited) |  |  | (Unaudited) |  |  | Increase / (Decrease) |
|  | Amount |  |  | Amount |  |  | $ |
Expenses: |  |  |  |  |  |  |  |  |  |  |  |
Direct costs |  | $ | 1,104,272 |  |  | $ | 279,619 |  |  | $ | 824,653 |
Professional fees |  |  | 1,112,832 |  |  |  | 287,478 |  |  |  | 825,354 |
Investor relations fees |  |  | 164,435 |  |  |  | — |  |  |  | 164,435 |
General and administrative expenses |  |  | 1,758,262 |  |  |  | 319,366 |  |  |  | 1,438,896 |
Depreciation, depletion and amortization |  |  | 532,665 |  |  |  | 23,359 |  |  |  | 509,306 |
Impairment of goodwill |  |  | — |  |  |  | 677,000 |  |  |  | (677,000 | )
Total expenses |  |  | 4,672,466 |  |  |  | 1,586,822 |  |  |  | 3,085,644 |
Net operating (loss) |  |  | (2,690,347 | ) |  |  | (1,510,508 | ) |  |  | 1,179,839 |
Other income (expense): |  |  |  |  |  |  |  |  |  |  |  |
Interest expense |  |  | (507,640 | ) |  |  | (4,239 | ) |  |  | 503,401 |
Loan fee expense |  |  | (113,155 | ) |  |  | — |  |  |  | 113,155 |
Loan interest accretion |  |  | (766,800 | ) |  |  | — |  |  |  | 766,800 |
Interest income |  |  | — |  |  |  | 3,495 |  |  |  | 3,495 |
Loss on sale of asset |  |  | — |  |  |  | (3,854 | ) |  |  | (3,854 | )
Total other income (expense) |  |  | (1,387,595 | ) |  |  | (4,598 | ) |  |  | 1,382,997 |
Net income (loss) |  | $ | (4,077,942 | ) |  | $ | (1,515,106 | ) |  | $ | 2,562,836 |

Direct Costs
Direct costs for the nine months ended December 31, 2007 were $1,104,272 compared to $279,619 for the nine months ended December 31, 2006. The increase over the prior period reflects the operating costs on the oil leases acquired during the period beginning in April 2007. Direct costs include pumping, gauging, pulling, repair and maintenance, certain contract labor costs, and other non-capitalized expenses.
Professional Fees
Professional fees for the nine months ended December 31, 2007 were $1,112,832 compared to $287,478 for the nine months ended December 31, 2006. The increase in professional fees was a result of non-cash charges related to options awarded to Board members and an outside consultant, together with payment for services rendered in connection with acquisition and financing activities.
Investor Relations Fees
Investor relations fees for the nine months ended December 31, 2007 were $164,435 compared to zero for the nine months ended December 31, 2006. The increase in public and investor relations expenses in the current period was a result of costs associated with our annual meeting of stockholders in September 2007 and with development and implementation of our public and investor relations strategy designed to establish a clear corporate identity, create and communicate high quality materials for the investment community.
General and Administrative
General and administrative expenses for the nine months ended December 31, 2007 were $1,758,262 compared to $319,366 in the nine months ended December 31, 2006. The increase is primarily due to non-cash option transactions and incentives recorded as employee compensation in the period. The Black-Scholes

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pricing model was used to determine the fair value of options granted and these values were expensed. The remaining general and administrative expenses increased in relation to the addition of employees, office space, and corporate activity related to growth in operations.
Depreciation, Depletion and Amortization
Depreciation, depletion and amortization for the nine months ended December 31, 2007 was $532,665 compared to $23,359 for the nine months ended December 31, 2006. The increase was primarily a result of the depletion of oil reserves commensurate with our increase in production.
Impairment of Goodwill
Impairment of goodwill for the nine months ended December 31, 2007 was zero as compared to $677,000 for the nine months ended December 31, 2006, the period during which the goodwill was fully impaired based upon reserve reports and management’s evaluation in the prior year of the Gas City Project acquisition, which determined that the purchase price paid for the project exceeded the asset value. Therefore the goodwill recorded at acquisition was considered to be impaired and was expensed.
Net Operating Income (Loss)
Net operating loss for the nine months ended December 31, 2007 was $2,690,347 compared to net operating loss of $1,510,508 for the nine months ended December 31, 2006. Direct costs increased from $279,619 to $1,104,272 as a result of the oil leases acquired during the period beginning in April 2007. For this same reason, depreciation, depletion and amortization increased from $23,359 for the nine months ended December 31, 2006 to $532,665 for the nine months ended December 31, 2007. Employee compensation accounted for $1,282,337 of the increased net operating loss and included non-cash options transactions and incentives as well as salary and wages paid to employees added during the nine months ended December 31, 2007. Similarly, general and administrative expenses for office space and corporate activity related to growth in operations also increased by $156,559 from the nine months ended December 31, 2006 to the nine months ended December 31, 2007. Professional fees increased $825,354 between the two periods, largely resulting from non-cash charges related to options awarded to board members and an outside consultant, together with payment for services rendered in connection with acquisition and financing activities.
Other Income (Expense):
Interest expense
Interest expense for the nine months ended December 31, 2007 was $507,640 compared to $4,239 for the nine months ended December 31, 2006. The increase in interest expense is primarily the result of increased debt from the debenture financing completed in April and June of 2007.
Loan Fee Expense
Loan fee expense for the nine months ended December 31, 2007 was $113,155 compared to zero for the nine months ended December 31, 2006. The increase in loan fee expense was a result of costs associated with the $9.0 million in debentures we sold in April and June of 2007.
Loan Interest Accretion
Loan interest accretion for the nine months ended December 31, 2007 was $766,800 compared to zero for the nine months ended December 31, 2006. The increase in loan interest accretion was a result of non-cash costs associated with the debentures.

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Interest Income
Interest income for the nine months ended December 31, 2007 was zero compared to $3,495 for the nine months ended December 31, 2006. Any interest earned in the current period on proceeds from financing was offset against the related interest expense.
Loss on Sale of Asset
Loss on sale of asset for the nine months ended December 31, 2007 was zero compared to $3,854 for the nine months ended December 31, 2006. The loss was a result of the sale of a vehicle in the prior year.
Net Income (Loss)
Our net loss for the nine months ended December 31, 2007 was $4,077,942 compared to $1,515,106 for the nine months ended December 31, 2006. The increase in net loss is primarily the result of direct costs on producing assets, professional and general costs we incurred as a start-up, and depletion recorded during the period as explained above.
Reserves
Our estimated total proved PV 10 (present value) of reserves as of December 31, 2007 increased to $30.9 million from zero as of March 31, 2007 and from $24.6 million as of September 30, 2007 reflecting an approximately 25% improvement in the three month period. We increased total proved reserves to 1.2 million barrels of oil equivalent (BOE). Of the 1.2 million BOE, approximately 75% are proved developed and approximately 25% are proved undeveloped. The proved developed reserves consist of proved developed producing (40%) and proved developed non-producing (35%).
Based on an assumed oil price of $84.25 per barrel and $5.657 per Mcf for natural gas as of December 31, 2007, and applying a 10% discount rate to the future net cash flow, the estimated PV10 of the 1.2 million BOE, before tax, is calculated as set forth in the following table:
Summary of Oil and Natural Gas Reserves
as of December 31, 2007

|  |  |  |  |  |  |  | PV10(2) |
Proved Reserves Category |  | Gross BOE(1) |  |  | Net BOE(1) |  |  | (Before Tax) |
Proved, Developed Producing |  |  | 643,573 |  |  |  | 488,897 |  |  | $ | 12,156,907 |
Proved, Developed Non-Producing |  |  | 606,133 |  |  |  | 432,875 |  |  | $ | 12,424,172 |
Proved, Undeveloped |  |  | 406,750 |  |  |  | 304,526, |  |  | $ | 6,329,438 |
Total Proved |  |  | 1,656,456 |  |  |  | 1,226,298 |  |  | $ | 30,910,517 |

(1) |  | BOE = barrels of oil equivalent (with 6 mcf of natural gas = 1 barrel of oil).

(2) |  | See “Glossary” on page 74 for our definition of PV10 and see “Business and Properties-Reserves” on page 49 for a reconciliation to the comparable GAAP financial measure.

Operation Plan
Our plan is to continue to acquire oil and natural gas assets primarily in the mid-continent region of the United States. However, over time we may expand our area of operations as opportunities become available. Once these assets are acquired we plan to continue to focus our efforts on increasing production of oil and natural gas, cash flows, and enhancing our net asset value.
We expect to achieve these results by:

| • | Investing additional capital in development drilling and in secondary and tertiary recovery of oil as well as natural gas;

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| • | Using the latest technologies available to the oil and natural gas industry in our operations; and
| • | Finding additional oil and natural gas reserves on the properties we acquire.

In the past 12 months, we have taken significant steps towards achieving these results, including:

| • | On April 12, 2007, we completed a private placement of senior secured debentures for $9.0 million (before fees and expenses) that has allowed us to implement our business plan.
| • | In April of 2007, we funded $4.0 million towards the development of the Black Oaks Project.
| • | On September 14, 2007, we completed the purchase of nine leases in Eastern Kansas for $800,000 in cash. As part of this acquisition, we acquired a nearly 100% working interest in 1,300 gross acres of leaseholds located in Miami, Johnson and Franklin counties in Eastern Kansas.
| • | On September 27, 2007, DD Energy entered into a purchase and sale agreement with an effective date of September 1, 2007, whereby DD Energy acquired seven oil leases and a 100% working interest in 1,700 gross acres of leaseholds for $2.7 million, of which $1,735,000 was in cash delivered at the time of closing and $965,000 was in the form of one year 5% promissory notes, secured by a second mortgage on the leaseholds. The $1,735,000 amount was borrowed from Cornerstone Bank pursuant to a 8.5% promissory note due September 27, 2011. The seven leases are in Johnson, Anderson and Linn counties in Eastern Kansas.

| • | As of December 31, 2007, our estimated total proved reserves were 1.2 million BOE with a total proved PV10 of reserves of $30.9 million, before tax. See “Glossary” on page 74 for our definition of PV10 and see “Business and Properties-Reserves” on page 49 for a reconciliation to the comparable GAAP financial measure.

| • | On February 29, 2008, we received our first quarterly payment of $300,000 from Euramerica related to its option exercise contained in the amended and restated well development agreement with Euramerica. Further, through April of 2008, Euramerica funded $500,000 of a required $2.0 million to be invested by August 31, 2008, which will be used for development of the Gas City Project.
| • | On March 6, 2008, we entered into the Shell agreement 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. This represents approximately 60% of our total current oil production on a net revenue basis and locks in approximately $6.8 million in gross revenue 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.

| • | On March 13, 2008, we disclosed an operations update regarding our Black Oaks Project, which was acquired in April 2007. Since January 15, 2008, our in-fill drilling and enhanced primary and secondary recovery waterflood techniques at the Black Oaks Project has increased oil production to an average of approximately 117 BOPD from a level of an average of approximately 32 BOPD per day when the project was originally acquired. As of December 31, 2007, the Black Oaks Project had 61 active production wells and 5 active water injection wells, an increase of 26 production wells and 5 water injection wells since the project was originally acquired. Water production from the Black Oaks Project as of December 31, 2007 was approximately 2,100 BWPD. Based upon these results, we anticipate commencing Phase II of the development plan.

We have several other projects that are in various stages of discussions and we are continually evaluating oil and natural gas opportunities in the mid-continent region. We plan to continue to bring multiple potential acquisitions to various financial partners for evaluation and funding options. It is our vision to grow the business in a disciplined and well planned manner.
In addition to raising additional capital, we may take on working interest participants that will contribute to the capital costs of drilling and completion and then share in revenues derived from production. This economic strategy will allow us to utilize our own financial assets toward the growth of our leased acreage holdings, pursue the acquisition of strategic oil and natural gas producing properties or companies and generally expand our existing operations while further diversifying risk.

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We began generating revenues from the sale of oil, primarily during the fiscal year ended March 31, 2008. We expect our production to continue to increase, both through development of wells and through our acquisition strategy. Our future financial results will continue to depend on: (i) our ability to source and screen potential projects; (ii) our ability to discover commercial quantities of natural gas and oil; (iii) the market price for oil and natural gas; and (iv) our ability to fully implement our exploration, workover and development program, which is in part dependent on the availability of capital resources. There can be no assurance that we will be successful in any of these respects, that the prices of oil and natural gas prevailing at the time of production will be at a level allowing for profitable production, or that we will be able to obtain additional funding at terms favorable to us to increase our currently limited capital resources. The board of directors has implemented a crude oil and natural gas hedging strategy that will allow management to hedge up to 80% of our net production to mitigate a majority of our exposure to changing oil prices in the intermediate term. In March of 2008 we entered into the Shell agreement whereby we hedged 130 BOPD of our production for an eighteen month period.
Liquidity and Capital Resources
Liquidity is a measure of a company’s ability to meet potential cash requirements. We have historically met our capital requirements through debt financing, revenues from operations and the issuance of equity securities. In the future we anticipate we will be able to provide some of the necessary liquidity we need by the revenues generated from our net interests in our oil and natural gas production, and sales of reserves in our existing properties, however, if we do not generate sufficient sales revenues we will continue to finance our operations through equity and/or debt financings.
The following table summarizes total current assets, total current liabilities and working capital at December 31, 2007 as compared to March 31, 2007.

|  | December 31, |  |  | March 31, |  |  | Increase/(Decrease) |
|  | 2007 |  |  | 2007 |  |  | $ |
Current Assets |  | $ | 1,345,583 |  |  | $ | 120,604 |  |  |  | 1,224,979 |
Current Liabilities |  | $ | 1,946,979 |  |  | $ | 488,189 |  |  |  | 1,458,790 |
Working Capital (deficit) |  | $ | (601,396 | ) |  | $ | (367,585 | ) |  |  | (233,811 | )

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 agreed to issue the lenders 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 26, 2007). In addition, we are required to issue the lenders up to an additional 1,800,000 shares of common stock or warrants in the event we fail to meet certain production thresholds over the term of the debentures. To avoid issuing these additional shares, we must have 30 day average production of the equivalent of 182 BOPDE at June 30, 2008, 170 BOPDE at December 31, 2008 and 206 BOPDE at June 30, 2009. We believe that we should be able to meet the production threshold levels for the future periods, as our production at December 31, 2007 was 243 BOPDE.
The debentures mature on March 31, 2010, absent earlier redemption by us, and carry an interest rate of 10%. Interest on the debentures began accruing on April 11, 2007 and is payable quarterly in arrears on the first day of each succeeding quarter during the term of the debentures, beginning on or about May 11, 2007 and ending on the maturity date of March 31, 2010. We may, under certain conditions specified in the debentures, pay interest payments in shares of our registered common stock. Additionally, on the maturity date, we are required to pay the amount equal to the principal, as well as all accrued but unpaid interest.

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Satisfaction of our cash obligations for the next 12 months.
A critical component of our operating plan is the ability to obtain additional capital through additional equity and/or debt financing and working interest participants. We are currently generating sufficient revenues to meet operating needs. In the event we cannot obtain additional capital to pursue our strategic plan, however, this would materially impact our ability to continue our aggressive growth.
Since inception, we have financed cash flow requirements through debt financing and issuance of common stock for cash and services. As we have expanded operational activities, we are no longer experiencing cash flow deficiencies from operations. If we again experience cash flow deficiencies we would be required to obtain additional financing to fund operations through common stock offerings and debt borrowings to the extent necessary to provide working capital. However, there is no assurance we would be able to obtain such financing on commercially reasonable terms, if at all.
We intend to implement and successfully execute our business and marketing strategy, continue to develop and upgrade technology and products, respond to competitive developments, and attract, retain and motivate qualified personnel. There can be no assurance that we will be successful in addressing such risks, and the failure to do so can have a material adverse effect on our business prospects, financial condition and results of operations.
Summary of product research and development that we will perform for the term of our plan.
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. We estimate this amount to be approximately $3.0 million.
Significant changes in the number of employees.
As of December 31, 2007, we had 8 full time employees and employ the services of several independent contractors. As drilling and production activities increase, we intend to hire additional technical, operational and administrative personnel as appropriate. We do not expect a significant change in the number of full time employees over the next 12 months. 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. We believe that this use of third-party service providers may enhance our ability to contain general and administrative expenses.
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 our oil and natural gas properties, the asset retirement obligation and the value of the options and warrants that we issue. Our trade receivables have been fully collectible since inception and we only have sales to a small base of customers. We believe that all of our receivables are collectible.

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Gas and Oil 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.
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 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 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.
As of December 31, 2007, approximately 100% of our proved reserves were evaluated by an independent petroleum engineer. All reserve estimates are prepared based upon a review of production histories and other geologic, economic, ownership and engineering data.
In addition, the prices of gas and oil are volatile and change from period to period. Price changes directly impact the estimated revenues from our properties and the associated present value of future net revenues. Such changes also impact the economic life of our properties and thereby affect the quantity of reserves that can be assigned to a property.

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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.
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 the volatility of our stock. We believe our estimate of volatility is reasonable and we review the assumptions used to determine this whenever we have an equity instrument that needs a fair market value. Although the offset to the valuation is in paid in capital were we to have an incorrect material volatility assumption our expenses could be understated or overstated.
The preparation of our financial statements requires us to make assumptions and estimates that affect the reported amounts of assets, liabilities, revenues and expenses as well as the disclosure of contingent assets and liabilities. We base our assumptions and estimates on historical experience and other sources that we believe to be reasonable at the time. Actual results may vary from our estimates due to changes in circumstances, weather, politics, global economics, mechanical problems, general business conditions and other factors.
Recent Accounting Pronouncements
In December 2007, the FASB issued SFAS No. 141R (revised 2007), “Business Combinations.” Although this statement amends and replaces SFAS No. 141, it retains the fundamental requirements in SFAS No. 141 that (i) the purchase method of accounting be used for all business combinations; and (ii) an acquirer be identified for each business combination. SFAS No. 141R defines the acquirer as the entity that obtains control of one or more businesses in the business combination and establishes the acquisition date as the date that the acquirer achieves control. This Statement applies to all transactions or other events in which an entity (the acquirer) obtains control of one or more businesses (the acquiree), including combinations achieved without the transfer of consideration; however, this Statement does not apply to a combination between entities or businesses under common control. Significant provisions of SFAS No. 141R concern principles and requirements for how an acquirer (i) recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed, and any noncontrolling interest in the acquiree; (ii) recognizes and measures the goodwill acquired in the business combination or a gain from a bargain purchase; and (iii) determines what information to disclose to enable users of the financial statements to evaluate the nature and financial effects of the business combination. This Statement applies prospectively to business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2008 with early adoption not permitted. Management is assessing the impact of the adoption of SFAS No. 141R.
In December 2007, the FASB issued SFAS No. 141I, “Business Combinations”. This Statement replaces SFAS No. 141, Business Combinations. This Statement retains the fundamental requirements in Statement 141 that the acquisition method of accounting (which Statement 141 called the purchase method) be used for all business combinations and for an acquirer to be identified for each business combination. This Statement also establishes principles and requirements for how the acquirer: a) recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed, and any non-controlling interest in the acquiree; b) recognizes and measures the goodwill acquired in the business combination or a gain from a bargain purchase and c) determines what information to disclose to enable users of the financial statements to evaluate the nature and financial effects of the business combination. SFAS No. 141I will apply prospectively to business combinations for which the acquisition date is on or after a Company’s fiscal year beginning November 1, 2009.
In December 2007, the FASB issued SFAS No. 160, “Non-controlling Interests in Consolidated Financial Statements”. This Statement amends ARB 51 to establish accounting and reporting standards for the non-controlling (minority) interest in a subsidiary and for the deconsolidation of a subsidiary. It clarifies that a non-controlling interest in a subsidiary is an ownership interest in the consolidated entity that should be

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reported as equity in the consolidated financial statements. We have not yet determined the impact, if any, that SFAS No. 160 will have on our 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 the increased business costs will continue while the commodity prices for oil and natural gas, and the demand for services related to production and exploration, both remain high (from a historical context) in the near term.

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BUSINESS AND PROPERTIES
Our Business
EnerJex, formerly known as Millennium Plastics Corporation, is an oil and natural gas acquisition, exploration and development company. 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.
Our principal strategy is to focus on the acquisition of oil and natural gas mineral leases that have existing production and cash flow. Once acquired, we implement an accelerated development program utilizing capital resources, a regional operating focus, an experienced management and technical team, and enhanced recovery technologies to attempt to increase production and increase returns for our stockholders. Our oil and natural gas acquisition and development activities are currently focused in Eastern Kansas.
Between March 31, 2007 and December 31, 2007, we deployed nearly $9.0 million in capital resources to acquire four major operating projects and drill 90 new wells. As a result, our estimated total proved oil reserves increased from zero as of March 31, 2007 to 1.2 million barrels of oil equivalent, or BOE, as of December 31, 2007. Of the 1.2 million BOE of total proved reserves, approximately 75% are proved developed and approximately 25% are proved undeveloped. The proved developed reserves consist of 40% proved developed producing reserves and 35% proved developed non-producing reserves.
The total proved PV10 (present value) before tax of our reserves as of December 31, 2007 was $30.9 million. 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 74 for our definition of PV10 and see “Business and Properties — Reserves” on page 49 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 year-ended December 31, 2006, 35.7 million barrels of oil were produced in Kansas. Of the total barrels produced in Kansas in 2006, 15 companies accounted for 30% of this production, with the remaining 70% produced by over 1,800 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 thousands of 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.

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Our Properties
The table below summarizes our acreage by project name as of December 31, 2007.

|  | Developed Acreage |  |  | Undeveloped Acreage |  |  | Total Acreage |
Project Name |  | Gross |  |  | Net(1) |  |  | Gross |  |  | Net(1) |  |  | Gross |  |  | Net(1) |
Black Oaks Project(2) |  |  | 530 |  |  |  | 504 |  |  |  | 1,450 |  |  |  | 1,377 |  |  |  | 1,980 |  |  |  | 1,881 |
DD Energy Project |  |  | 380 |  |  |  | 380 |  |  |  | 1,340 |  |  |  | 1,340 |  |  |  | 1,720 |  |  |  | 1,720 |
Tri-County Project |  |  | 610 |  |  |  | 606 |  |  |  | 652 |  |  |  | 651 |  |  |  | 1,262 |  |  |  | 1,257 |
Thoren Project |  |  | 100 |  |  |  | 100 |  |  |  | 140 |  |  |  | 140 |  |  |  | 240 |  |  |  | 240 |
Gas City Project |  |  | 560 |  |  |  | 560 |  |  |  | 3,849 |  |  |  | 3,849 |  |  |  | 4,409 |  |  |  | 4,409 |
Total |  |  | 2,180 |  |  |  | 2,150 |  |  |  | 7,431 |  |  |  | 7,357 |  |  |  | 9,611 |  |  |  | 9,507 |

(1) |  | Net acreage is based on our net working interest as of December 31, 2007.

(2) |  | Following completion of the Black Oaks Project, or upon mutual agreement with MorMeg, we will have the option to develop the approximate 2,100 acre “Nickel Town Project.”

Black Oaks and Nickel Town Projects
In September of 2006, we acquired an option to purchase the Black Oaks Project from MorMeg for $500,000 in a combination of stock and cash. In addition, as part of the purchase agreement we established a joint operating account and funded it with $4.0 million in April of 2007 specifically for the Phase I development plan of this project. We have a 95% working interest and MorMeg retained a 5% carried working interest in the project. The Black Oaks Project encompasses approximately 1,980 acres in Woodson and Greenwood Counties, Kansas, which at the time of acquisition had approximately 35 oil wells producing an average of approximately 32 BOPD.
The Black Oaks Project is a joint development at 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 the period ended December 31, 2007, 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 March 31, 2008, we were injecting approximately 200 barrels of water per day per well in the initial 5 injection wells. In addition, five adjacent oil wells have increased production from an average of approximately 5 BOPD to 18 BOPD since January 15, 2008. Project-wide production has increased to an average of approximately 117 BOPD as of December 31, 2007. Based upon these results, we plan to invest a minimum of $5.0 million from the proceeds of this offering in the project and commence Phase II of the development plan. Phase II contemplates drilling 28 additional water injection wells, targeting water injection rates that will eventually increase to 300 barrels of water per day per well, and drilling and completing 23 additional producer wells.
As of December 31, 2007, we had proved oil reserves on this project of:

|  |  |  |  |  |  |  | PV10(2) |
|  | Gross STB(1) |  |  | Net STB(1) |  |  | (Before Tax) |
Proved, Developed Producing |  |  | 243,256 |  |  |  | 158,539 |  |  | $ | 2,010,023 |
Proved, Developed Non-Producing |  |  | 335,000 |  |  |  | 208,798 |  |  | $ | 4,405,805 |
Proved, Undeveloped |  |  | 120,000 |  |  |  | 66,961 |  |  | $ | 1,166,409 |
Total Proved |  |  | 698,256 |  |  |  | 434,298 |  |  | $ | 7,582,237 |

(1) |  | STB = one stock-tank barrel

(2) |  | See “Glossary” on page 74 for our definition of PV10 and see “Business and Properties-Reserves” on page 49 for a reconciliation to the comparable GAAP financial measure.

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We will maintain our 95% working interest until payout of the project’s total expenses, at which time the MorMeg 5% carried working interest will be converted to a 30% working interest, which is generally the point in time when the total cumulative revenue from the project equals all of the project’s development expenditures and costs associated with funding.
We have until November 30, 2008 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, the joint development of the project 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.
Once the parties agree that the project has been fully developed or it is no longer economically viable to fund further development, we will have earned the right to exercise our option to participate in the Nickel Town Project and will have nine-months from that time to exercise this option. Should we elect to participate in the Nickel Town Project, we will have the option of negotiating new operating and other governing agreements with MorMeg. The Nickel Town Project contains approximately 2,100 acres and current production averaged approximately 25 BOPD for the period ended December 31, 2007.
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 acquired additional leases bringing the total acreage for this project to approximately 1,700 acres. As of December 31, 2007, we had 112 oil wells, 33 water injection wells and 2 water supply wells on this project with production averaging approximately 45 BOPD. Through March 31, 2008, we have invested an additional $300,000 in this project and have drilled seven water injection wells and four producing wells which are just now coming on line.
As of December 31, 2007, we had proved oil reserves on this project of:

|  |  |  |  |  |  |  | PV10(2) |
|  | Gross STB(1) |  |  | Net STB(1) |  |  | (Before Tax) |
Proved, Developed Producing |  |  | 128,208 |  |  |  | 108,221 |  |  | $ | 3,444,668 |
Proved, Developed Non-Producing |  |  | 183,200 |  |  |  | 153,849 |  |  | $ | 6,348,604 |
Proved, Undeveloped |  |  | 202,750 |  |  |  | 169,521 |  |  | $ | 3,940,437 |
Total Proved |  |  | 514,158 |  |  |  | 431,591 |  |  | $ | 13,733,709 |

(1) |  | STB = one stock-tank barrel

(2) |  | See “Glossary” on page 74 for our definition of PV10 and see “Business and Properties-Reserves” on page 49 for a reconciliation to the comparable GAAP financial measure.

Upon completion of this offering we plan to invest approximately $4.0 million into the DD Energy Project and drill approximately 100 wells.
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, 2008, we have invested approximately $400,000 in this project. Proceeds have been used to drill four wells, fund infrastructure upgrades, and perform work-overs on approximately 20 wells in this project. We also acquired additional leases, bringing the total project to approximately 1,300 acres.

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As of December 31, 2007, the Tri-County Project consisted of 191 oil wells and 57 water injection wells with production averaging approximately 45 BOPD.
As of December 31, 2007, we had proved oil reserves on this project of:

|  |  |  |  |  |  |  | PV10(2) |
|  | Gross STB(1) |  |  | Net STB(1) |  |  | (Before Tax) |
Proved, Developed Producing |  |  | 129,969 |  |  |  | 102,753 |  |  | $ | 2,175,567 |
Proved, Developed Non-Producing |  |  | 54,600 |  |  |  | 42,728 |  |  | $ | 1,242,725 |
Proved, Undeveloped |  |  | 60,000 |  |  |  | 47,700 |  |  | $ | 691,684 |
Total Proved |  |  | 244,569 |  |  |  | 193,181 |  |  | $ | 4,109,976 |

(1) |  | STB = one stock-tank barrel

(2) |  | See “Glossary” on page 74 for our definition of PV10 and see “Business and Properties-Reserves” on page 49 for a reconciliation to the comparable GAAP financial measure.

Upon completion of this offering we plan to invest up to $3.0 million and drill up to 70 injection and production wells.
Thoren Project
On April 27, 2007, we acquired the Thoren Project for $400,000 from MorMeg. This project contains 240 acres in Douglas County, Kansas. At the time of acquisition, this project had 12 oil wells producing an average of approximately 10 BOPD, 4 water injection wells, and one water supply well.
Through March 31, 2008, we have invested approximately $600,000 for the development of this project and as of December 31, 2007, we had 31 oil wells producing an average of approximately 50 BOPD, 11 water injection wells and one water supply well.
As of December 31, 2007, we had proved oil reserves on this project of:

|  |  |  |  |  |  |  | PV10(2) |
|  | Gross STB(1) |  |  | Net STB(1) |  |  | (Before Tax) |
Proved, Developed Producing |  |  | 109,189 |  |  |  | 92,555 |  |  | $ | 3,992,648 |
Proved, Developed Non-Producing |  |  | -0- |  |  |  | -0- |  |  | $ | -0- |
Proved, Undeveloped |  |  | 24,000 |  |  |  | 20,344 |  |  | $ | 530,908 |
Total Proved |  |  | 133,189 |  |  |  | 112,898 |  |  | $ | 4,523,556 |

(1) |  | STB = one stock-tank barrel

(2) |  | See “Glossary” on page 74 for our definition of PV10 and see “Business and Properties-Reserves” on page 49 for a reconciliation to the comparable GAAP financial measure.

We will maintain our 100% working interest until payout of the project’s total expenses, at which time the MorMeg 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 interests costs incurred in the finance and funding of the purchase.
Based on the results of production and economics to date, we intend to allocate up to $500,000 in additional development drilling for this project from the proceeds of this offering.
Gas City Project
Effective February 1, 2006, we acquired the Gas City Project for $750,000, which at that time encompassed approximately 8,800 acres in Allen County, Kansas. When we originally acquired this project, we acquired 10 natural gas wells, a natural gas gathering system, an interstate pipeline tap and a salt water

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disposal system for the project. Subsequent to acquisition, we invested an additional $650,000 in capital improvement and development of this project. Since the time of the acquisition, we have had certain leases expire or have elected to not renew certain leases in an attempt to centralize the acreage.
In August of 2007, we entered into a development agreement with 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. We are the operator of the project at a cost plus 17.5% basis. Until Euramerica has completed all payments related to the option exercise, we will retain a 100% working interest in the project. Following Euramerica’s February 29, 2008 payment toward the full purchase price, Euramerica receives revenues equal to a 95% net revenue interest and we receive a management fee equal to a 5% net revenue interest in the project until Euramerica has completed the full payment of its option exercise at which time this 5% net revenue interest management fee will be converted to a 5% carried working interest and Euramerica will receive assignment of its before payout 95% working interest in the project. When the project reaches payout our 5% carried working interest will increase to a 25% working interest and Euramerica will have a 75% working interest.
As of December 31, 2007, the project contained approximately 4,400 acres and we had expended approximately $475,000 in drilling and completing 10 wells. Production on this project as of December 31, 2007 was approximately 200,000 cubic feet per day.
We are negotiating operating agreements with Euramerica for the Gas City Project and for joint working interest participation in other mineral leases and acreage near the Gas City Project.
The following table sets forth the Company’s working interest and revenue interest levels in the Gas City Project.

|  | Gas City Project |
|  |  |  |  | Company |
|  | Company |  |  | Net |
|  | Working |  |  | Revenue |
|  | Interest |  |  | Interest(1) |
Before Euramerica first Purchase Price Payment on February 29, 2008 |  |  | 100 | %(2) |  |  | 10 | %
After First Purchase Price payment but Before Full Purchase Price Paid by Euramerica |  |  | 100 | %(2) |  |  | 5 | %
After Full Purchase Price Paid, Before Payout |  |  | 5 | %(2) |  |  | 5 | %
After Payout |  |  | 25 | % |  |  | 25 | %

(1) |  | For purposes of this table, net revenue interest is the Company’s revenue interest of the working interest owners’ proceeds from the sale of production.

(2) |  | These working interests are carried working interests.

As of December 31, 2007, we had proved natural gas reserves on this project of:

|  |  |  |  |  |  |  | PV10(2) |
|  | Gross MCF(1) |  |  | Net MCF(1) |  |  | (Before Tax) |
Proved, Developed Producing |  |  | 197,704 |  |  |  | 160,976 |  |  | $ | 534,001 |
Proved, Developed Non-Producing |  |  | 200,000 |  |  |  | 165,000 |  |  | $ | 427,038 |
Proved, Undeveloped |  |  | -0- |  |  |  | -0- |  |  | $ | -0- |
Total Proved |  |  | 397,704 |  |  |  | 325,976 |  |  | $ | 961,039 |

(1) |  | MCF = thousand cubic feet of natural gas

(2) |  | See “Glossary” on page 74 for our definition of PV10 and see “Business and Properties-Reserves” on page 49 for a reconciliation to the comparable GAAP financial measure.

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On February 29, 2008, Euramerica exercised the option to purchase this property by paying the initial installment payment of $300,000 towards the full purchase price of $1.2 million. In addition, Euramerica has funded $500,000 of a required $2.0 million to be invested by August 31, 2008. These proceeds will be used for development of the Gas City Project.
Between April 1 and June 1, 2008, we intend to drill approximately 10 exploration wells on behalf of Euramerica and complete as many of these wells as possible with the remaining funds available. Beyond June 1, 2008, development of this project will be dependent on additional capital contributed by Euramerica.
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 near-term reserve and production growth from over 400 additional drilling locations identified on our properties. The structure and the continuous oil accumulation in Eastern Kansas and the mid-continent region of the United States, and the expected long-life production and reserves of our properties, are anticipated to enhance our opportunities for long-term profitability. As of December 31, 2007, our Black Oaks Project, DD Energy Project, Tri-County Project and Thoren Project have projected lives of 41 years, 33 years, 23 years and 21 years, respectively.

| • | 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 Kansas and strategic partnership with Haas Petroleum, we believe we are well-positioned to pursue selected acquisitions 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 continue to 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 portfolio of pricing for our production as we continue to expand and as market conditions permit.
| • | Significant Production Growth Opportunities. We have acquired an attractive acreage position with very favorable lease terms in a region with historical hydrocarbon production. Based on continued drilling success within our acreage position, 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

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|  | 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 December 31, 2007, our directors and executive officers owned approximately 9.1% of our outstanding common stock, with options that upon exercise would increase their ownership of our outstanding common stock to 16.7%. In addition, the compensation arrangements for our directors and executive officers are weighted toward future performance based equity payments rather than cash.

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. 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 2008
The following is a brief description of our most significant corporate developments that have occurred in fiscal 2008 to date:

| • | In April of 2007, we completed a debt financing in which we issued debentures and received $6.3 million (before expenses and placement fees) at the first closing and an additional $2.7 million in June 2007.
| • | In April of 2007, concurrent with the receipt of funds from the debentures, we acquired all of the rights, title and interest to the Black Oaks Project for $4.0 million, with the commitment to spend additional funds to fully complete the development of the Black Oaks Project.
| • | In April of 2007, Phase I of the Black Oaks Project development plan commenced with the drilling of 44 in-fill wells. In the period ended December 31, 2007, we began injecting water into the first five water injection wells at a rate averaging approximately 50 barrels of water per day per well, which was expanded in March 2008 to an average of approximately 200 barrels of water per day per well. Project-wide production has increased to an average of approximately 117 BOPD from a level of approximately 32 BOPD per day when the project was originally acquired.
| • | In April of 2007, we entered into an agreement with MorMeg to acquire the 240 acre Thoren Project in Douglas County, Kansas for $400,000.
| • | In August of 2007, we entered into the Development Agreement with Euramerica, pursuant to which we granted to Euramerica the right to purchase the Gas City Project for $1.2 million.
| • | In September of 2007, we acquired the 1,700 acre DD Energy Project, located in Johnson, Anderson and Linn Counties of Kansas, for $2.7 million.
| • | In September of 2007, we acquired the 1,300 acre Tri-County Project, located in Miami, Johnson and Franklin Counties, Kansas, for $800,000.

| • | Our estimated total proved oil reserves increased from zero as of March 31, 2007 to 1.2 million BOE as of December 31, 2007.

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| • | According to a reserve report prepared by McCune Engineering P.E., our independent reserve engineer, the total proved PV 10 (present value) of reserves before tax as of December 31, 2007 was $30.9 million. See “Glossary” on page 74 for our definition of PV10 and see “Business and Properties-Reserves” on page 49 for a reconciliation to the comparable GAAP financial measure.

| • | In February of 2008, we received our first quarterly payment of $300,000 from Euramerica related to its option exercise contained in the amended and restated well development agreement with Euramerica executed on August 10, 2007. Further, through April 3, 2008, Euramerica funded $500,000, of a required $2.0 million to be invested by August 31, 2008, which will be used for development of the Gas City Project.
| • | In March of 2008, we entered into the Shell agreement 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. This represents approximately 60% of our total current oil production on a net revenue basis and locks in approximately $6.8 million in gross revenue 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.

| • | On March 13, 2008, we disclosed an operations update regarding our Black Oaks Project, which we acquired in April of 2007. Since January 15, 2008, our in-fill drilling and waterflood enhanced recovery techniques at the Black Oaks Project has increased oil production to an average of approximately 117 BOPD from a level of 32 BOPD per day when the project was originally acquired. As of December 31, 2007, the Black Oaks Project had 61 active production wells and 5 active water injection wells, an increase of 26 production wells and 5 water injection wells since the project was originally acquired. Water production from the Black Oaks Project as of December 31, 2007 was approximately 2,100 BWPD. Based upon these results, we anticipate commencing Phase II of the development plan, which contemplates drilling 28 additional water injection wells and completing 23 additional producer wells.

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. In addition, we have granted Mr. Haas options to purchase 60,000 shares of our common stock at an exercise price of $6.25 per share, expiring on May 3, 2011. 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.

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Drilling Activity
The following table sets forth the results of our drilling activities during the 2006, 2007 and 2008 fiscal years, Our fiscal year ends on March 31 and fiscal 2008 results are for the nine-months ended December 31, 2007.

|  | Drilling Activity |
|  | Gross Wells |  |  | Net Wells(1) |
Fiscal Year |  | Total |  |  | Producing |  |  | Dry |  |  | Total |  |  | Producing |  |  | Dry |
2006 Exploratory |  |  | -0- |  |  |  | -0- |  |  |  | -0- |  |  |  | -0- |  |  |  | -0- |  |  |  | -0- |
2007 Exploratory |  |  | -0- |  |  |  | -0- |  |  |  | -0- |  |  |  | -0- |  |  |  | -0- |  |  |  | -0- |
2008 Exploratory(2) |  |  | 10 |  |  |  | 10 |  |  |  | -0- |  |  |  | 10 |  |  |  | 10 |  |  |  | -0- |
2006 Development |  |  | -0- |  |  |  | -0- |  |  |  | -0- |  |  |  | -0- |  |  |  | -0- |  |  |  | -0- |
2007 Development |  |  | -0- |  |  |  | -0- |  |  |  | -0- |  |  |  | -0- |  |  |  | -0- |  |  |  | -0- |
2008 Development(2) |  |  | 55 |  |  |  | 53 |  |  |  | 2 |  |  |  | 52 |  |  |  | 50 |  |  |  | 2 |

(1) |  | Net wells are based on our net working interest as of December 31, 2007.

(2) |  | Fiscal 2008 drilling activities are for the nine months ended December 31, 2007. We incurred no exploration costs related to exploratory wells in which we held carried working interest.

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 nine months ended December 31, 2007, the fiscal year ended March 31, 2007 and the period from inception (December 30, 2005) through March 31, 2006, the average sales prices, average production costs and direct lifting costs per unit of production.

|  |  |  |  |  |  |  | Period From |
|  |  |  |  |  |  |  | Inception (December 30, |
|  | Nine Months Ended |  |  | Year Ended |  |  | 2005) through |
|  | December 31, |  |  | March 31, |  |  | March 31, |
|  | 2007 |  |  | 2007 |  |  | 2006 |
Net Production |  |  |  |  |  |  |  |  |  |  |  |
Oil (Bbls) |  |  | 25,674 |  |  |  | -0- |  |  |  | -0- |
Natural gas (Mcf) |  |  | 11,840 |  |  |  | 19,254 |  |  |  | -0- |
Average Sales Prices |  |  |  |  |  |  |  |  |  |  |  |
Oil (per Bbl) |  | $ | 76.45 |  |  | $ | -0- |  |  | $ | -0- |
Natural gas (per Mcf) |  | $ | 5.25 |  |  | $ | 4.72 |  |  | $ | -0- |
Average Production Cost(1) |  |  |  |  |  |  |  |  |  |  |  |
Per equivalent (Bbl of oil) |  | $ | 59.24 |  |  | $ | 57.31 |  |  | $ | -0- |
Average Lifting Costs(2) |  |  |  |  |  |  |  |  |  |  |  |
Per equivalent (Bbl of oil) |  | $ | 39.94 |  |  | $ | 53.73 |  |  | $ | -0- |

(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 inception (December 30, 2005) through December 31, 2007. Results of operations from these activities have been determined using historical revenues, production costs, depreciation, depletion and amortization of the

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capitalized costs subject to amortization. General and administrative expenses and interest expense have been excluded from this determination.

|  |  |  |  |  |  |  | From Inception |
|  |  |  |  |  |  |  | (December 30, |
|  | For the Nine |  |  | For the Year |  |  | 2005) |
|  | Months Ended |  |  | Ended |  |  | through |
|  | December 31, |  |  | March 31, |  |  | March 31, |
|  | 2007 |  |  | 2007 |  |  | 2006 |
Production revenues |  | $ | 1,982,119 |  |  | $ | 90,800 |  |  | $ | 2,142 |
Production costs |  |  | (1,104,272 | ) |  |  | (172,417 | ) |  |  | (14,599 | )
Depreciation, depletion and amortization |  |  | (532,665 | ) |  |  | (11,477 | ) |  |  | (385 | )
Income tax |  |  | -0- |  |  |  | -0- |  |  |  | -0- |
Results of operations for producing activities |  | $ | 345,182 |  |  | $ | $(93,094 | ) |  | $ | (12,842 | )

Producing Wells
The following table sets forth the number of productive oil and natural gas wells in which we owned an interest as of December 31, 2007.

|  | Producing |
|  |  |  |  |  |  |  | Gross |  |  | Net |
Project |  | Gross Oil |  |  | Net Oil(1) |  |  | Natural Gas |  |  | Natural Gas(1) |
Black Oaks Project(2) |  |  | 63 |  |  |  | 60 |  |  |  | -0- |  |  |  | -0- |
DD Energy Project |  |  | 112 |  |  |  | 112 |  |  |  | -0- |  |  |  | -0- |
Tri-County Project |  |  | 191 |  |  |  | 190 |  |  |  | -0- |  |  |  | -0- |
Thoren Project |  |  | 31 |  |  |  | 31 |  |  |  | -0- |  |  |  | -0- |
Gas City Project |  |  | -0- |  |  |  | -0- |  |  |  | 15 |  |  |  | 15 |
Total |  |  | 444 |  |  |  | 440 |  |  |  | 15 |  |  |  | 15 |

(1) |  | Net wells are based on our net working interest as of December 31, 2007

(2) |  | Following completion of the Black Oaks Project, or upon mutual agreement with MorMeg, we will have the option to develop the approximate 2,100 acre “Nickel Town Project.”

Reserves
Our estimated total proved PV 10 (present value) of reserves as of December 31, 2007 increased to $30.9 million from zero as of March 31, 2007 and $24.6 million as of September 30, 2007, reflecting a 25% improvement in the three month period. We increased total proved reserves to 1.2 million barrels of oil equivalent (BOE). Of the 1.2 million BOE, approximately 75% are proved developed and approximately 25% are proved undeveloped. The proved developed reserves consist of proved developed producing (40%) and proved developed non-producing (35%). See “Glossary” on page 74 for our definition of PV10 and see “Business and Properties-Reserves” on page 49 for a reconciliation to the comparable GAAP financial measure.

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The following table presents summary information regarding our estimated net proved reserves as of and for the nine months ended December 31, 2007. 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 McCune Engineering P.E., our independent petroleum consultants. For additional information regarding our reserves, please see Note 11 to our audited financial statements as of and for the period ended December 31, 2007.
Summary of Proved Oil and Natural Gas Reserves as of December 31, 2007

|  |  |  |  | PV10 |
Proved Reserves Category |  | Net |  |  | (Before Tax)(1) |
Proved, Developed Producing |  |  |  |  |  |  |  |
Oil (stock-tank barrels) |  |  | 462,068 |  |  |  |  |
Natural Gas (mcf) |  |  | 160,976 |  |  |  |  |
Total Developed Producing |  |  |  |  |  | $ | 12,156,907 |
Proved, Developed Non-Producing |  |  |  |  |  |  |  |
Oil (stock-tank barrels) |  |  | 405,375 |  |  |  |  |
Natural Gas (mcf) |  |  | 165,000 |  |  |  |  |
Total Developed Non-Producing |  |  |  |  |  | $ | 12,424,172 |
Proved, Undeveloped |  |  |  |  |  |  |  |
Oil (stock-tank barrels) |  |  | 304,526 |  |  |  |  |
Natural Gas (mcf) |  |  | -0- |  |  |  |  |
Total Undeveloped |  |  |  |  |  | $ | 6,329,438 |
Total Proved Reserves |  |  |  |  |  |  |  |
Oil (stock-tank barrels) |  |  | 1,171,969 |  |  |  |  |
Natural Gas (mcf) |  |  | 325,976 |  |  |  |  |
Total |  |  |  |  |  | $ | 30,910,517 |

(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 |
|  | December 31, |
|  | 2007 |
PV10 |  | $ | 30,910,517 |
Future income taxes, discounted at 10% |  |  | (5,034,403 | )
Standardized measure of discounted future net cash flows |  | $ | 25,876,114 |

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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, since the beginning of the fiscal year ended March 31, 2007.
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, the debentures are also secured by a first lien on all of our assets. We do not believe that any of these burdens materially interferes with the use of our properties in the operation of our business.
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 one long-term purchase contract with Shell to sell all of our current oil production through September of 2009 and under current conditions 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 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 are employing a waterflood for the Black Oaks Project as well as on our remaining shallow oil leases. We anticipate waterflooding to be our 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 pipelines or holding tanks for sale and the water being recycled to the injection facilities. In the Black Oaks Project, through March 31, 2008 we have realized an increase of 4 barrels a day to 18 barrels a day in oil production on 4 wells as a result of the waterflood.
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

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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 rising and volatile prices in recent years. 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 in response to political unrest and supply uncertainty in Iraq, Venezuela, Nigeria and Iran, and increasing demand for energy in rapidly growing economies, notably India and China. Due to rising world prices and the consequential impact on supply, North American prospects have become more attractive. Escalating conflicts in the Middle East and the ability of OPEC to control supply and pricing are some of the factors negatively impacting the availability of global supply. In contrast, increased costs of steel and other products used to construct drilling rigs and pipeline infrastructure, as well as higher drilling and well-servicing rig rates, negatively impact domestic supply.
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. Although we have entered into one sales contract with Shell at this time, 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, as an early-stage company, 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.
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.

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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 (“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 (“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

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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 (“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
As of December 31, 2007, we had 8 full-time employees and employ the services of several contract personnel. As drilling production activities increase, we intend to hire additional 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, geology drilling, water hauling, pipeline construction, well design, well-site monitoring and surveillance, permitting and environmental assessment. We believe that this use of third-party service providers may enhance our ability to contain general and administrative expenses.
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 7300 W. 110th Street, 7th floor, Overland Park, Kansas 66210. This space is leased pursuant to a one year agreement, which expires on July 31, 2008. Our current office space is adequate for our immediate needs; however, as our operations expand, we may need to locate and secure additional office space.

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MANAGEMENT
The following table sets forth certain information regarding our current directors and executive officers:

Name |  | Age |  | Position
C. Stephen Cochennet |  |  | 51 |  |  | President, Chief Executive Officer, Principal Financial and Accounting Officer and Chairman
Dierdre P. Jones |  |  | 43 |  |  | Director of Finance and Accounting
Robert G. Wonish |  |  | 54 |  |  | Director
Daran G. Dammeyer |  |  | 47 |  |  | Director
Darrel G. Palmer |  |  | 50 |  |  | Director
Dr. James W. Rector |  |  | 46 |  |  | Director

C. Stephen Cochennet, has been our President, Chief Executive Officer and Chairman since August 15, 2006. From July 2002 to present, Mr. Cochennet has been President of CSC Group, LLC. Mr. Cochennet formed the CSC Group, LLC through which he supports a number of clients that include Fortune 500 corporations, international companies, natural gas/electric utilities, outsource service providers, as well as various start up organizations. The services provided include strategic planning, capital formation, corporate development, executive networking and transaction structuring. Mr. Cochennet currently spends less than 10 hours a month on activities associated with CSC Group, LLC. 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, has been our Director of Finance and Accounting since August 2007. 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 1, 2008, Mr. Wonish was appointed as Chief Operating Officer of Ecco Energy Corp. (OTC:BB ECCE). 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. 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 also serves on the board of directors of Striker Oil, Inc., (OTC:BB UCPI), which is an oil and natural gas exploration and production company.
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.

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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 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 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

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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.
Director Compensation
The following table sets forth summary compensation information for the fiscal year ended March 31, 2007 for each of our directors. We did not pay any director compensation for the fiscal year ended March 31, 2007. Mr. Dammeyer was issued 1,920 shares of our common stock on June 1, 2007 for services through March 31, 2008.
DIRECTOR COMPENSATION

|  | Fees |  |  |  |  |  |  |  |  |  |  |  | Nonqualified |  |  |  |  |  |  |
|  | Earned |  |  |  |  |  |  |  |  | Non-Equity |  |  | Deferred |  |  |  |  |  |  |
|  | or Paid |  |  | Stock |  |  | Option |  |  | Incentive Plan |  |  | Compensation |  |  | All Other |  |  |  |
|  | in Cash |  |  | Awards |  |  | Awards |  |  | Compensation |  |  | Earnings |  |  | Compensation |  |  | Total |
Name |  | ($) |  |  | ($) |  |  | ($) |  |  | ($) |  |  | ($) |  |  | ($) |  |  | ($) |
Darran G. Dammeyer |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |
Darrel G. Palmer |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |
Dr. James W. Rector(1) |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |
Robert G. Wonish |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |

(1) |  | Mr. Rector was appointed to the board of directors on March 19, 2008.

EXECUTIVE COMPENSATION
The following table sets forth summary compensation information for the year ended March 31, 2007 for our chief executive officer and former chief financial officer. We did not have any other executive officers as of the end of fiscal 2007 whose total compensation exceeded $100,000 and no compensation was paid in fiscal 2006. We refer to these persons as our named executive officers elsewhere in this prospectus.
Summary Compensation Table

|  |  |  |  |  |  |  |  |  |  | Option |  |  | All Other |  |  |  |
|  | Fiscal |  |  | Salary |  |  | Bonus |  |  | Awards |  |  | Compensation |  |  | Total |
Name and Principal Position |  | Year |  |  | ($) |  |  | ($) |  |  | ($) |  |  | ($) |  |  | ($) |
C. Stephen Cochennet |  |  | 2007 |  |  | $ | 110,500 | (1) |  |  | — |  |  |  | — |  |  | $ | 9,500 | (2) |  | $ | 120,000 |
President, Chief Executive Officer and Principal Financial and Accounting Officer |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Todd Bart |  |  | 2007 |  |  | $ | 106,875 | (3) |  | $ | 8,306 | (4) |  | $ | 37,813 | (5) |  | $ | 8,775 | (6) |  | $ | 161,769 |
Former Chief Financial Officer |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |

(1) |  | Mr. Cochennet began receiving compensation as of August 1, 2006; therefore the amounts listed for fiscal 2007 represents compensation for only a portion of the year. We agreed to pay Mr. Cochennet a monthly

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|  | salary of $13,000. Mr. Cochennet received $26,000 as compensation for August 1, 2006 through October 1, 2006. As of October 15, 2006, Mr. Cochennet agreed to defer his salary until financing was secured. As of March 31, 2007, we accrued $84,500 of Mr. Cochennet’s salary. Subsequent to March 31, 2007, Mr. Cochennet’s accrued salary was paid and Mr. Cochennet is no longer accruing salary.
(2) |  | Represents automobile maintenance and related costs.
(3) |  | Mr. Bart began receiving compensation as of June 15, 2006. We agreed to pay Mr. Bart a monthly salary of $11,250. Mr. Bart resigned as our Chief Financial Officer on June 29, 2007.
(4) |  | Represents a discretionary moving bonus of $8,306.
(5) |  | Amount represents the estimated total fair market value of stock options granted to Mr. Bart under SFAS 123(R), as discussed in Note 3 to our audited financial statements for the year ended March 31, 2007 included elsewhere in this prospectus.
(6) |  | Represents reimbursement of Mr. Bart’s moving expenses.

Grants of Plan-Based Awards in Fiscal 2007
The following table lists grants of plan-based awards made to our named executive officers for the fiscal year ended March 31, 2007 and related fair value for fiscal 2007.

|  |  |  |  |  |  |  | Possible |  |  |  |  |  |  |  |  |  |
|  |  |  |  |  |  |  | Future |  |  | All Other |  |  |  |  |  | Grant |
|  |  |  |  |  |  |  | Payouts |  |  | Awards: |  |  | Exercise |  |  | Date Fair |
|  |  |  |  |  |  |  | Under Non- |  |  | Number of |  |  | or Base |  |  | Value of |
|  |  |  |  |  |  |  | Equity |  |  | Securities |  |  | Price of |  |  | Stock and |
|  | Fiscal |  |  | Grant |  |  | Incentive |  |  | Underlying |  |  | Option |  |  | Option |
Name |  | Year |  |  | Date |  |  | Plan Awards |  |  | Options |  |  | Awards |  |  | Awards |
C. Stephen Cochennet(1) |  |  | 2007 |  |  |  | N/A |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |
Todd Bart(2) |  |  | 2007 |  |  |  | 08/16/2006 |  |  |  | — |  |  |  | 60,000 |  |  | $ | 5.00 |  |  | $ | 99,000 | (3)

(1) |  | Mr. Cochennet did not receive any plan based awards in fiscal 2007.
(2) |  | Mr. Bart resigned as our Chief Financial Officer on June 29, 2007.

(3) |  | Amount represents the estimated total fair value of stock options granted to Mr. Bart under SFAS 123(R).

Outstanding Equity Awards at 2007 Fiscal Year-End
The following table lists the outstanding equity incentive awards held by our named executive officers as of March 31, 2007.

|  |  |  |  | Option Awards |
|  |  |  |  | Number of |  |  | Number of |  |  |  |  |  |  |
|  |  |  |  | Securities |  |  | Securities |  |  |  |  |  |  |
|  |  |  |  | Underlying |  |  | Underlying |  |  |  |  |  |  |
|  |  |  |  | Unexercised |  |  | Unexercised |  |  | Option |  |  |  |
|  |  |  |  | Options |  |  | Options |  |  | Exercise |  |  | Option |
|  | Fiscal Year |  |  | Exercisable |  |  | Unexercisable |  |  | Price |  |  | Expiration Date |
C. Stephen Cochennet(1) |  |  | 2007 |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |
Todd Bart |  |  | 2007 |  |  |  | 20,000 |  |  |  | 40,000 |  |  | $ | 5.00 |  |  |  | 09/13/07 | (2)

(1) |  | Mr. Cochennet did not receive any equity incentive awards in fiscal 2007.
(2) |  | On June 29, 2007, we entered into a separation agreement with Mr. Bart, pursuant to which the 60,000 options were fully vested with a right to exercise any time prior to September 13, 2007. The options were not exercised and have been cancelled.

Option Exercises for 2007
There were no options exercised by our named executive officers in fiscal 2007.

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Potential Payments Upon Termination or Change in Control
We have not entered into any compensatory plans or arrangements with respect to any of our named executive officers, which would in any way result in payments to any such officers because of their resignation, retirement, or other termination of employment with us or our subsidiaries, or any change in control of, or a change in the person’s responsibilities following a change in control.
2000 Stock Option and Incentive Plan
The board of directors approved the 2000 Stock Option and Incentive 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. On May 4, 2007, we granted a non-qualified option to C. Stephen Cochennet for all 200,000 options available under this plan. The options are exercisable for a term of four years at a per share price of $6.25.
2002-2003 Stock Option Plan
The board of directors approved the 2002-2003 Stock Option and Incentive Plan on August 1, 2002. Originally, the total number of options that could be granted under the plan was not to exceed 400,000 shares. On May 4, 2007, the Governance, Compensation, and Nominating Committee amended and restated the stock option plan to rename the plan and to increase the number of shares issuable to 1,000,000. Our stockholders approved this plan in September of 2007.
As of December 31, 2007, we have granted 235,000 non-qualified options under this plan at prices ranging from $6.25 to $7.50 per share. In addition, in January 2008, we granted an additional 23,500 non-qualified options under this plan at a per share price of $6.25.
General Terms of Stock Option 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 options under the stock option plans. The committee will administer the stock option plans and will 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.
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 stock option 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 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 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.
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.

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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.

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CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS
We describe below transactions and series of similar transactions that have occurred during this fiscal year 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 April 1, 2006, we acquired a vehicle from C. Stephen Cochennet, our President and CEO, for $35,500, an amount that approximated its fair market value at the time of purchase.
On August 1, 2006, EnerJex Kansas entered an agreement wherein we advanced funds to Todd Bart, our former Chief Financial Officer. The note was unsecured and totaled $22,000. Interest was at 7.5%, and we recorded interest of $1,100 for the year ended March 31, 2007. The note was repaid upon Mr. Bart’s termination in June 2007.
One of our directors, Darrel G. Palmer, is an officer and stockholder of Energy Management Resources, or EMR. We pay EMR a monthly fee for both crude oil and natural gas marketing services plus a fee for each Mcf of natural gas or barrel of oil sold. We paid EMR $12,905 during the fiscal year ended March 31, 2007 and $27,075 during the nine months ended December 31, 2007.

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PRINCIPAL STOCKHOLDERS
The following table presents information, to the best of our knowledge, about the ownership of our common stock on May 20, 2008 relating to those persons known to beneficially own more than 5% of our capital stock and by our directors and executive officers. The percentage of beneficial ownership for the following table is based on 4,442,834 shares of our common stock outstanding.
Beneficial ownership is determined in accordance with the rules of the SEC 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 May 20, 2008 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 SEC, that only the person or entity whose ownership is being reported has converted options or warrants into shares of our common stock.

|  |  |  |  | Percent of Outstanding |  |  | Percent of Outstanding |
|  |  |  |  | Shares of Common |  |  | Shares of Common |
|  | Number |  |  | Stock |  |  | Stock |
Name of Beneficial Owner, Officer or Director(1) |  | of Shares |  |  | before Offering(2) |  |  | after Offering(2) |
C. Stephen Cochennet, President & Chief Executive Officer(3) |  |  | 600,000 | (4) |  |  | 13.5 | % |  |  |  | %
Robert G. Wonish, Director(3) |  |  | 40,000 | (5) |  |  | * |  |  |  |  | *
Darrel G. Palmer, Director(3) |  |  | 40,000 | (5) |  |  | * |  |  |  |  | *
Daran G. Dammeyer, Director(3) |  |  | 44,102 | (5) |  |  | * |  |  |  |  | *
Dr. James W. Rector, Director(3) |  |  | -0- |  |  |  | * |  |  |  |  | *
Directors and Executive Officers as a Group |  |  | 744,102 |  |  |  | 16.7 | % |  |  |  | %
West Coast Opportunity Fund LLC(7) |  |  | 1,000,000 |  |  |  | 22.5 | % |  |  |  | %
West Coast Asset Management, Inc. Paul Orfalea, Lance Helfert & R. Atticus Lowe 2151 Alessandro Drive, #100 Ventura, CA 93001 |  |  |  |  |  |  |  |  |  |  |  |
Enable Growth Partners L.P.(8) |  |  | 385,980 |  |  |  | 8.7 | % |  |  |  | %
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: 7300 W. 110th Street, 7th Floor, Overland Park, Kansas 66210.
(4) |  | Includes 200,000 options, exercisable at $6.25 per share through May 3, 2011.

(5) |  | Includes 40,000 options, exercisable at $6.25 per share through May 3, 2011.

(7) |  | Based on a Schedule 13G/A filed with the SEC on February 9, 2008. 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

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|  | Orfalea, Lance Helfert and R. Atticus Lowe constitute the Investment Committee of the WCOF. Messrs. Orfalea, Helfert and Lowe disclaim beneficial ownership of the shares.

(8) |  | Based on a Schedule 13G/A filed with the SEC on February 20, 2008. Enable Capital Management, 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. (277,040 shares of common stock) and other clients (108,940 shares of common stock). 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.

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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 4,442,834 shares were outstanding as of May 20, 2008. 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 filing. 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.

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Debenture Financing
On April 11, 2007, we entered into financing agreements for $9.0 million of senior secured debentures. The debentures have a three-year term 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.
In connection with the sale of the debentures, we agreed to issue 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). In addition, we may be required to issue the holders up to an additional 1,800,000 shares of common stock (originally 2,400,000 shares) or warrants, determined solely at the discretion of the holders, in the event we fail to meet certain production thresholds over the term of the debentures. Such warrants would have an exercise price of $0.05 per share and would be exercisable for a four year term.
Production Thresholds. So long as any debenture is outstanding, we are required to produce a minimum average daily quantity of oil and natural gas over 30 days of no less than the following on each of the following dates (each a “Measurement Date”):
We easily exceeded the first production threshold as of December 31, 2007.

|  | 06/30/08 |  |  | 12/31/08 |  |  | 06/30/09 |
BOPDE Production |  |  | 182 |  |  |  | 170 |  |  |  | 206 | (1)

(1) |  | Notwithstanding the above, for the Measurement Date of June 30, 2009, if BOPDE production is (i) equal to or greater than 136 BOPDE but less than 206 BOPDE, we are only obligated to issue 200,000 shares of common stock instead of 600,000 shares of common stock, and (ii) equal to or greater than 69 BOPDE but less than 136 BOPDE, we are only obligated to issue 400,000 shares of common stock instead of 600,000 shares of common stock.

In the event that for any Measurement Date specified above, we do not meet the production thresholds applicable to such Measurement Date, then we must issue to the lenders an aggregate of 600,000 shares of common stock for each such date. Each lender may elect to receive common stock purchase warrants in lieu of its allocation of shares of common stock. Such warrants would have an exercise price of $0.05 per share and would be exercisable for a four year term.
Right to Redeem Debenture. So long as a registration statement covering all of the registrable securities is effective (we currently have two effective registration statements covering 1,200,000 shares of the registrable securities), 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. Pursuant to a Consent and Waiver Agreement dated April 9, 2008 all of the debenture holders consented to the redemption of their debentures were redeemed with the proceeds of this offering without further notice.
Registration Rights. Pursuant to the terms of the Registration Rights Agreement, as amended, we are obligated to file at least three registration statements registering the 1,800,000 shares of common stock, 600,000 interest shares issuable under the debentures, and up to 1,800,000 production shares which may be issued pursuant to the Securities Purchase Agreement. The first two registration statements (effective on August 14, 2007 and January 11, 2008, respectively) each registered 600,000 shares of common stock. The third registration statement (required to be filed on or before November 20, 2008) will register the remaining 600,000 shares of common stock, and the interest shares issuable pursuant to the terms of the debentures, if necessary. In addition, we are required to file a registration statement within 30 days of the issuance of any production shares.
If we fail to obtain and maintain the effectiveness of these registration statements through a date which the lenders may sell all of their respective shares of common stock without restriction under Rule 144 of the

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1933 Act or the date on which the lenders shall have sold all of their respective shares of common required to be covered by these registration statements, we will be obligated to pay cash to each lender equal to: (i) 0.5% of the aggregate purchase price allocable to such lender’s registrable securities included in such registration statement for the first 30 day period following such effectiveness failure or maintenance failure, (ii) 0.75% of the aggregate purchase price allocable to such lender’s registrable securities in such registration statement for the following thirty day period; and (iii) 1% of the aggregate purchase price allocable to such Buyer’s registrable securities included in the registration statement for every thirty day period thereafter. These payments are capped at 10% of the Buyer’s original purchase price under the debentures.
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 Securities Exchange Act of 1934, as amended, the Financing Agreements 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.
Transfer Agent
The transfer agent for our common stock is Standard Registrar & Transfer Company Inc., 12528 South 1840 East, Draper, Utah 84020.

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MATERIAL U.S. FEDERAL INCOME TAX CONSEQUENCES FOR NON-U.S. HOLDERS
The following summary discusses material United States federal income tax consequences, and certain United States federal estate tax consequences, of the purchase, ownership and disposition of our common stock by a Non-U.S. Holder, as defined below. This summary deals only with common stock held as a capital asset within the meaning of Section 1221 of the Internal Revenue Code of 1986, as amended, or the Code, and is applicable only to Non-U.S. Holders who purchase common stock pursuant to this offering. This summary does not address specific tax consequences that may be relevant to you if you are a Non-U.S. Holder subject to special tax treatment (including pass-through entities, banks and insurance companies, dealers in securities, persons holding our common stock as part of a “straddle,” “hedge,” “conversion transaction” or other risk-reduction transaction, controlled foreign corporations, passive foreign investment companies, companies that accumulate earnings to avoid United States federal income tax, foreign tax-exempt organizations, former U.S. citizens or residents and persons who hold or receive common stock as compensation or pursuant to the exercise of compensatory options), and does not address alternative minimum tax consequences, if any, or any state, local, or foreign tax consequences.
This summary is based upon the provisions of the Code and United States Treasury regulations, rulings and judicial decisions as of the date hereof, all of which are subject to change, possibly with retroactive effect.
If you are considering the purchase of common stock, you should consult your own tax advisors regarding the United States federal income tax consequences to you of the purchase, ownership, and disposition of common stock, as well as any consequences arising under the laws of any other taxing jurisdiction.
For purposes of this summary, you are a Non-U.S. Holder if you are a beneficial owner of common stock who is not a U.S. person or a partnership (or other entity treated as a partnership) for United States federal income tax purposes. A U.S. person is (i) a citizen or resident alien individual of the United States; (ii) a corporation, or other entity treated as a corporation for United States federal income tax purposes, created or organized in or under the laws of the United States, any state thereof, or the District of Columbia; (iii) an estate, the income of which is subject to United States federal income taxation regardless of its source; or (iv) a trust (a) whose administration is subject to the primary supervision of a court within the United States and one or more U.S. persons have the authority to control all substantial decisions of the trust, or (b) if it has a valid election in effect under applicable United States Treasury regulations to be treated as a U.S. person.
U.S. Trade or Business Income
For purposes of this discussion, dividend income and gain on the sale or other taxable disposition of our common stock will be considered to be “U.S. trade or business income” if such income or gain is (i) effectively connected with the conduct by a Non-U.S. Holder of a trade or business within the United States, or (ii) in the case of a Non-U.S. Holder that is eligible for the benefits of an income tax treaty with the United States, attributable to a permanent establishment (or, for an individual, a fixed base) maintained by the Non-U.S. Holder in the United States. Generally, U.S. trade or business income is not subject to United States federal withholding tax (provided the Non-U.S. Holder complies with applicable certification and disclosure requirements). Instead, U.S. trade or business income is subject to United States federal income tax on a net income basis at regular United States federal income tax rates in the same manner as a U.S. person, unless an applicable income tax treaty provides otherwise. Any U.S. trade or business income received by a corporate Non-U.S. Holder may be subject to an additional “branch profits tax” at a 30% rate or such lower rate as may be specified by an applicable income tax treaty.
Distributions
Provided the dividend income is not considered to be U.S. trade or business income, distributions of cash or property that we pay will generally constitute dividends for United States federal income tax purposes to the extent paid from our current or accumulated earnings and profits (as determined under United States federal income tax principles). A Non-U.S. Holder generally will be subject to withholding of United States federal income tax at a 30% rate on any dividends received in respect of our stock, or at a lower rate provided

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by an applicable income tax treaty. If the amount of a distribution exceeds our current and accumulated earnings and profits, such excess first will be treated as a tax-free return of capital to the extent of the Non-U.S. Holder’s tax basis in our common stock (with a corresponding reduction in such Non-U.S. Holder’s tax basis in our common stock), and thereafter will be treated as gain realized on the sale or other disposition of the common stock and will be treated as described under “— Sale or Other Disposition of Our Common Stock” below. In order to obtain a reduced rate of United States federal withholding tax under an applicable income tax treaty, a Non-U.S. Holder, who is otherwise entitled to benefits under an income tax treaty, will be required to provide a properly executed IRS Form W-8BEN certifying under penalties of perjury its entitlement to benefits under the treaty. Special certification requirements and other requirements apply to certain Non-U.S. Holders that are entities rather than individuals.
If you are eligible for a reduced rate of United States withholding tax pursuant to an applicable income tax treaty, you may obtain a refund or credit of any excess amounts withheld by timely filing an appropriate claim for refund with the United States Internal Revenue Service, or IRS. A Non-U.S. Holder should consult its own tax advisor regarding its possible entitlement to benefits under an income tax treaty and the filing of a United States tax return for claiming a refund of United States federal withholding tax.
The United States federal withholding tax does not apply to dividends that are U.S. trade or business income, as defined above, of a Non-U.S. Holder who provides a properly executed IRS Form W-8ECI, certifying that the dividends are effectively connected with the Non-U.S. Holder’s conduct of a trade or business within the United States.
Sale or Other Disposition of Our Common Stock
Any gain that a Non-U.S. Holder realizes upon the sale or other disposition of a share of common stock generally will not be subject to United States federal income or withholding tax unless:

| • | The gain is U.S. trade or business income, as defined and discussed above;
| • | The Non-U.S. Holder is an individual who is present in the United States for 183 days or more in the taxable year of the disposition, and certain other conditions are met; or
| • | Our common stock constitutes a “United States Real Property interest” by reason of our status as a United States real property holding corporation, or a USRPHC, under Section 897 of the Code at any time during the shorter of the five-year period ending on the date of disposition and the Non-U.S. Holder’s holding period for our common stock.

In general, a corporation is a USRPHC if the fair market value of its “United States real property interests” (as defined in the Code and applicable United States Treasury regulations) equals or exceeds 50% of the sum of the fair market value of its worldwide real property interests and its other assets used or held for use in a trade or business. If we are determined to be a USRPHC, the United States federal income and withholding taxes relating to interests in USRPHCs nevertheless will not apply to gains derived from the sale or other disposition of our common stock by a Non-U.S. Holder whose shareholdings, actual and constructive, at all times during the applicable period, amount to 5% or less of our common stock, provided that our common stock is regularly traded on an established securities market. We do not believe we currently are, and do not anticipate becoming, a USRPHC. However, no assurance can be given that we will not be a USRPHC, or that our common stock will be considered regularly traded, when a Non-U.S. Holder sells its shares of our common stock.
Gain described in the second bullet point above will be subject to United States federal income tax at a flat 30% rate (or such lower rate as may be specified by an applicable income tax treaty), but may be offset by United States source capital losses (even though the individual is not considered a resident of the United States).

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U.S. Federal Estate Tax
If you are an individual Non-U.S. Holder, common stock that you hold at the time of death will be included in your gross estate for United States federal estate tax purposes, and may be subject to United States federal estate tax, unless an applicable estate tax treaty provides otherwise.
Information Reporting and Backup Withholding
We must report annually to the IRS and to you the amount of dividends paid to you on your shares of common stock and the tax withheld with respect to such dividends, regardless of whether withholding was required. Copies of the information returns reporting such dividends and withholding may also be made available to the tax authorities in the country in which you reside under the provisions of an applicable income tax treaty or exchange of information treaty.
The United States imposes a backup withholding tax on dividends and certain other types of payments to U.S. persons. The backup withholding rate is currently 28%. You will not be subject to backup withholding on dividends you receive on your shares of common stock if you provide proper certification (usually on an IRS Form W-8BEN) of your status of a Non-U.S. Holder or otherwise establishes an exemption, provided that the payor does not have actual knowledge or reason to know that you are a U.S. person or that the conditions of any other exemption are not, in fact, satisfied.
Information reporting and, depending on the circumstances, backup withholding, generally will apply to the proceeds of a sale of common stock within the United States or conducted through the United States office of any broker, United States or foreign, unless you certify under penalties of perjury that you are a Non-U.S. Holder or otherwise establish an exemption, provided that the broker does not have actual knowledge or reason to know that you are a U.S. person or that the conditions of any other exemption are not, in fact, satisfied. The payment of the proceeds from the disposition of our common stock to or through a non-U.S. office of a non-U.S. broker generally will not be subject to information reporting or backup withholding unless the non-U.S. broker has certain types of relationships with the United States, or a U.S. related person. In the case of the payment of the proceeds from the disposition of our common stock to or through a non-U.S. office of a broker that is either a U.S. person or a U.S. related person, the United States Treasury regulations generally require information reporting (but not backup withholding) on the payment unless the broker has documentary evidence that the holder is a Non-U.S. Holder and the broker has no knowledge to the contrary. Non-U.S. Holders should consult their own tax advisors on the application of information reporting and backup withholding to them in their particular circumstances (including upon their disposition of our common stock).
Backup withholding is not an additional tax. Any amounts withheld under the backup withholding rules from a payment to a Non-U.S. Holder may be allowed as a refund or a credit against your United States federal income tax liability, if any, provided that you furnish the required information to the IRS in a timely manner.

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UNDERWRITING
Subject to the terms and conditions described in an underwriting agreement among us, C. K. Cooper & Company, as representative and book-running manager, we have agreed to sell to the underwriters, and the underwriters have severally agreed to purchase from us, the following number of shares of common stock at the offering price less the underwriting discount set forth on the cover page of this prospectus.

Underwriter |  | Number of Shares |
C. K. Cooper & Company, Inc. |  |  |  |
Total |  |  |  |

The underwriters have agreed to purchase all of the shares sold under the underwriting agreement if any of the shares are purchased, other than shares covered by the over-allotment option described below. The underwriting agreement provides that the underwriters’ obligation to purchase shares of common stock depends on the satisfaction of the conditions contained in the underwriting agreement including:

| • | the obligation to purchase all of the shares of common stock offered hereby (other than those shares of common stock covered by their option to purchase additional shares as described below), if any of the shares are purchased;
| • | the representations and warranties made by us to the underwriters are true;
| • | there is no material change in our business or the financial markets; and
| • | we deliver customary closing documents to the underwriters.

We have granted the underwriters an option exercisable for 30 days from the date of the underwriting agreement to purchase a total of up to additional shares at the public offering price less the underwriting discount. The underwriters may exercise this option solely to cover any over-allotments, if any, made in connection with this offering. To the extent the underwriters exercise this option in whole or in part, each will be obligated, subject to conditions contained in the underwriting agreement, to purchase a number of additional shares approximately proportionate to that underwriter’s initial commitment amount reflected in the above table.
The underwriters have advised us that they propose initially to offer the shares to the public at the public offering price on the cover page of this prospectus and to dealers at that price less a concession not in excess of $ per share. After the offering, the offering price and other selling terms may be changed.
The following table shows the per share and total underwriting discounts and commissions to be paid to the underwriters by EnerJex. The information assumes either no exercise or full exercise by the underwriters of their over-allotment option.

|  | Without Option |  |  | With Option |
Per Share |  | $ |  |  |  | $ |  |
Total |  | $ |  |  |  | $ |  |

The expenses of this offering that are payable by us, excluding the underwriting discount and commissions and related fees, are estimated at approximately $ million. We have agreed to reimburse C. K. Cooper & Company for its out of pocket expenses in connection with this offering.
In connection with this offering, we have agreed to issue to the underwriters warrants entitling the underwriters, or their assigns, to purchase up to an aggregate of 10% of the total number of shares sold in this offering at a price equal to 140% of the public offering price per share. The underwriter warrants will be exercisable for three years from the closing date of the offering and will contain cashless exercise provisions and customary anti-dilution provisions.
The underwriter warrants are deemed compensation by the Financial Industry Regulatory Authority, Inc., and may not be sold, transferred, pledged, hypothecated or assigned for a period of 180-days following the effective date of the offering pursuant to Rule 2710(g)(1) of the NASD Conduct Rules.

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We have agreed to indemnify the underwriters against certain liabilities, including liabilities under the Securities Act, or to contribute to payments the underwriters may be required to make in respect of those liabilities. We (subject to certain exceptions in the event of a change of control), all of our executive officers, directors, and holders of our debentures have agreed that, without the prior written consent of each of C. K. Cooper & Company, neither we nor they will directly or indirectly, (1) offer for sale, sell, pledge, or otherwise dispose of (or enter into any transaction or device that is designed to, or could be expected to, result in the disposition by any person at any time in the future of) any shares of common stock (including, without limitation, shares of common stock that may be deemed to be beneficially owned by us or them in accordance with the rules and regulations of the SEC and shares of common stock that may be issued upon exercise of any options or warrants) or securities convertible into or exercisable or exchangeable for common stock, (2) enter into any swap or other derivatives transaction that transfers to another, in whole or in part, any of the economic consequences of ownership of the common stock, (3) make any demand for or exercise any right or file or cause to be filed a registration statement, including any amendments thereto, with respect to the registration of any shares of common stock or securities convertible, exercisable or exchangeable into common stock or any of our other securities, or (4) publicly disclose the intention to do any of the foregoing for, in the case of holders of our debentures, a period of 60 days after the date of the prospectus and, in the case of our executive officers and directors, a period of 180 days after the date of this prospectus.
The 60-day or 180-day restricted periods described in the preceding paragraph will be extended if:

| • | during the last 17 days of the 60-day or 180-day restricted periods we issue an earnings release or material news or a material event relating to us occurs; or
| • | prior to the expiration of the 60-day or 180-day restricted periods, we announce that we will release earnings results during the 16-day period beginning on the last day of the 60-day or 180-day periods,

in which case the restrictions described in the preceding paragraph will continue to apply until the expiration of the 18-day period beginning on the issuance of the earnings release or the announcement of the material news or occurrence of a material event, unless such extension is waived in writing by C. K. Cooper & Company.
C. K. Cooper & Company, in its sole discretion, may release the common stock and other securities subject to the lock-up agreements described above in whole or in part at any time with or without notice. When determining whether or not to release common stock and other securities from lock-up agreements, C. K. Cooper & Company will consider, among other factors, the holder’s reasons for requesting the release, the number of shares of common stock and other securities for which the release is being requested and market conditions at the time. C. K. Cooper & Company does not have any present intention to release any of these lock-up agreements prior to their termination.
We have applied to list our common stock on the American Stock Exchange under the symbol “JEX.”
A prospectus in electronic format may be made available on the Internet sites or through other online services maintained by one or more of the underwriters of this offering, or by their affiliates. Other than any prospectus made available in electronic format in this manner, the information on any web site containing the prospectus is not part of this prospectus or the registration statement of which this prospectus forms a part, has not been approved or endorsed by us or any underwriter in such capacity and should not be relied on by prospective investors.
In connection with this offering, some participants in the offering may purchase and sell shares of common stock in the open market. These transactions may include short sales, syndicate covering transactions and stabilizing transactions. Short sales involve sales by the underwriters of common stock in excess of the number of shares required to be purchased by the underwriters in the offering, which creates a syndicate short position. “Covered” short sales are sales of shares made in an amount up to the number of shares represented by the underwriters’ over-allotment option. Transactions to close out the covered syndicate short involve either purchases of the common stock in the open market after the distribution has been completed or the exercise of the over-allotment option. In determining the source of shares to close out the covered syndicate short position, the underwriters will consider, among other things, the price of shares available for purchase in the open

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market as compared to the price at which they may purchase shares through the over-allotment option. The underwriters may also make “naked” short sales, or sales in excess of the over-allotment option. The underwriters must close out any naked short position by purchasing shares of common stock in the open market. A naked short position is more likely to be created if the underwriters are concerned that there may be downward pressure on the price of the shares in the open market after pricing that could adversely affect investors who purchase in the offering. Stabilizing transactions consist of bids for or purchases of shares in the open market while the offering is in progress.
The underwriters also may impose a penalty bid. Penalty bids permit the underwriters to reclaim a selling concession from an underwriter or syndicate member when the underwriters repurchase shares originally sold by that underwriter or syndicate member in order to cover syndicate short positions or make stabilizing purchases. Any of these activities may have the effect of raising or maintaining the market price of the common stock or preventing or retarding a decline in the market price of the common stock. As a result, the price of the common stock may be higher than the price that might otherwise exist in the open market. The underwriters may conduct these transactions on The American Stock Exchange or otherwise. If the underwriters commence any of these transactions, they may discontinue them at any time.
C. K. Cooper & Company acted as placement agent in our private placement of debentures in April 2006. The underwriters may in the future perform investment banking and advisory services for us from time to time for which they may in the future receive customary fees and expenses.

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LEGAL MATTERS
The validity of the issuance of the shares of common stock offered hereby will be passed upon for us by Husch Blackwell Sanders LLP, Kansas City, Missouri. Certain legal matters will be passed upon for the underwriter by Stradling Yocca Carlson & Rauth, a Professional Corporation, Newport Beach, California.
EXPERTS
Weaver & Martin, LLC, independent registered public accounting firm, has audited our financial statements at March 31, 2006, March 31, 2007 and December 31, 2007, and for the periods from inception (December 30, 2005) to March 31, 2006, the fiscal year ended March 31, 2007 and the nine-months ended December 31, 2007, 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 McCune Engineering P.E., independent reserve engineer. 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., 7300 W. 110th, 7th Floor, Overland Park, Kansas 66210.

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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.
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.
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).
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.

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Term |  | Definition
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 or 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. This definition of proved developed non-producing reserves has been abbreviated from the applicable definitions contained in Rule 4-10(a)(2-4) of Regulation S-X.

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Term |  | Definition
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.
PV10 Value |  | PV10 value 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 “Business and Properties-Reserves” on page 49 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.

76

#####

Term |  | Definition
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.

77

#####

INDEX TO FINANCIAL STATEMENTS

|  | Page |
Index to Financial Statements |  |  | F-1 |
Report of Independent Registered Public Accounting Firm |  |  | F-2 |
Consolidated Balance Sheet at March 31, 2007 and 2006 |  |  | F-3 |
Consolidated Statement of Operations for the Year Ended March 31, 2007 and period of inception (December 30, 2005) to March 31, 2006 |  |  | F-4 |
Consolidated Statement of Stockholders’ Equity for the Year Ended March 31, 2007 and period of inception (December 30, 2005) to March 31, 2006 |  |  | F-5 |
Consolidated Statement of Cash Flows for the Year Ended March 31, 2007 and period of inception (December 30, 2005) to March 31, 2006 |  |  | F-6 |
Notes to Consolidated Financial Statements |  |  | F-7 |
Report of Independent Registered Public Accounting Firm |  |  | G-1 |
Consolidated Balance Sheet at December 31, 2007 |  |  | G-2 |
Consolidated Statement of Operations for the Nine Months Ended December 31, 2007 (audited) and 2006 |  |  | G-3 |
Consolidated Statement of Stockholders Equity (Deficit) for the Nine Months Ended December 31, 2007 (audited) and 2006 |  |  | G-4 |
Consolidated Statement of Cash Flows for the Nine Months Ended December 31, 2007 (audited) and 2006 |  |  | G-5 |
Notes to Consolidated Financial Statements |  |  | G-6 |

The share information presented in the accompanying financial statements does not reflect the proposed 1-for-5 reverse stock split of our outstanding shares of common stock, which will be effected prior to the consummation of this offering.

F-1

#####

Report of Independent Registered Public Accounting Firm
To the Board of Directors and Stockholders
EnerJex Resources, Inc. and Subsidiary,
We have audited the accompanying consolidated balance sheets of EnerJex Resources, Inc. and Subsidiary as of March 31, 2007 and 2006, and the related statements of operations, changes in stockholders’ equity and cash flows for the year ended March 31, 2007 and the period from inception (December 30, 2005) through March 31, 2006. 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 audit.
We conducted our audit in accordance with auditing 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 misstatement. 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 financial position of EnerJex Resources, Inc. and Subsidiary as of March 31, 2007 and 2006, and the results of their operations and their cash flows for the year ended March 31, 2007 and for the period from inception (December 30, 2005) through March 31, 2006 in conformity with accounting principles generally accepted in the United States.
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 losses and had negative cash flows from operations that raise substantial doubt about the Company’s ability to continue as a going concern. Management’s plans in regard to these matters are also 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
June 12, 2007

F-2

#####

EnerJex Resources, Inc. and Subsidiary
Consolidated Balance Sheet

|  | March 31, |  |  | March 31, |
|  | 2007 |  |  | 2006 |
ASSETS
Current assets: |  |  |  |  |  |  |  |
Cash |  | $ | 99,493 |  |  | $ | 590,432 |
Accounts receivable |  |  | 4,138 |  |  |  | 2,549 |
Notes and interest receivable |  |  | 10,300 |  |  |  | — |
Deposits and prepaid expenses |  |  | 6,673 |  |  |  | 8,861 |
Total current assets |  |  | 120,604 |  |  |  | 601,842 |
Fixed assets |  |  | 35,500 |  |  |  | 17,550 |
Accumulated depreciation |  |  | 8,875 |  |  |  | 440 |
Total fixed assets |  |  | 26,625 |  |  |  | 17,110 |
Other assets: |  |  |  |  |  |  |  |
Note receivable-officer |  |  | 23,100 |  |  |  | — |
Oil and gas properties using full cost accounting: |  |  |  |  |  |  |  |
Properties not subject to amortization |  |  | 322,178 |  |  |  | 59,582 |
Properties subject to amortization |  |  | — |  |  |  | 243,952 |
Total other assets |  |  | 345,278 |  |  |  | 303,534 |
Total assets |  | $ | 492,507 |  |  | $ | 922,486 |
LIABILITIES AND STOCKHOLDERS’ EQUITY (DEFICIT)
Current liabilities: |  |  |  |  |  |  |  |
Accounts payable |  | $ | 42,299 |  |  | $ | 49,045 |
Notes payable |  |  | 350,000 |  |  |  | — |
Accrued liabilities |  |  | 95,890 |  |  |  | 503 |
Total current liabilities |  |  | 488,189 |  |  |  | 49,548 |
Asset retirement obligation |  |  | 23,908 |  |  |  | 22,038 |
Convertible note payable |  |  | 25,000 |  |  |  | — |
Contingencies and commitments |  |  |  |  |  |  |  |
Stockholders’ equity (deficit): |  |  |  |  |  |  |  |
Preferred stock, $001 par value, 10,000,000 shares authorized, no shares issued and outstanding |  |  | — |  |  |  | — |
Common stock $.001 par value, 100,000,000 shares authorized; 13,178,656 shares issued and outstanding at 3/31/07 and 11,050,000 at 3/31/06 |  |  | 13,179 |  |  |  | 11,050 |
Common stock owed but not issued 15,000 shares |  |  | 15 |  |  |  | — |
Paid in capital |  |  | 2,603,374 |  |  |  | 1,432,718 |
Unamortized cost of options issued for service |  |  | (61,187 | ) |  |  | — |
Unamortized cost of stock issued for service |  |  | (4,000 | ) |  |  | — |
Retained deficit |  |  | (2,595,971 | ) |  |  | (592,868 | )
Total stockholders’ equity (deficit) |  |  | (44,590 | ) |  |  | 850,900 |
Total liabilities and stockholders’ equity (deficit) |  | $ | 492,507 |  |  | $ | 922,486 |

See notes to consolidated financial statements.

F-3

#####

EnerJex Resources, Inc. and Subsidiary
Consolidated Statement of Operations

|  |  |  |  | From Inception |
|  |  |  |  | (12/30/05) |
|  | Year Ended |  |  | through |
|  | March 31, |  |  | March 31, |
|  | 2007 |  |  | 2006 |
Oil and gas revenues |  | $ | 90,800 |  |  | $ | 2,142 |
Costs and operating expenses |  |  |  |  |  |  |  |
Direct operating costs |  |  | 172,417 |  |  |  | 14,599 |
Repairs on oil & gas equipment |  |  | 165,603 |  |  |  | 40,436 |
Professional fees |  |  | 302,071 |  |  |  | 50,490 |
Administrative expense |  |  | 470,789 |  |  |  | 21,700 |
Depreciation, depletion and amortization |  |  | 23,978 |  |  |  | 825 |
Impairment of oil & gas properties subject to amortization |  |  | 273,959 |  |  |  | 468,081 |
Goodwill on acquisition |  |  | 677,000 |  |  |  | — |
Total cost and operating expenses |  |  | 2,085,817 |  |  |  | 596,131 |
Loss from operations |  |  | (1,995,017 | ) |  |  | (593,989 | )
Other income (expense): |  |  |  |  |  |  |  |
Interest expense |  |  | (8,434 | ) |  |  | (38 | )
Loss on sale of vehicle |  |  | (3,854 | ) |  |  | — |
Interest income |  |  | 4,202 |  |  |  | 1,159 |
Total other income (expense) |  |  | (8,086 | ) |  |  | 1,121 |
Net loss |  | $ | (2,003,103 | ) |  | $ | (592,868 | )
Net loss per share of common stock-basic and diluted |  | $ | (0.16 | ) |  | $ | (0.07 | )
Weighted average shares outstanding |  |  | 12,241,589 |  |  |  | 8,563,044 |

See notes to consolidated financial statements.

F-4

#####

EnerJex Resources, Inc. and Subsidiary
Consolidated Statement of Stockholders’ Equity (Deficit)

|  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | Unamortized |  |  | Unamortized |  |  |  |  |  |  |
|  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | Cost of |  |  | Cost of |  |  |  |  |  | Total |
|  | Common Stock |  |  | Options |  |  | Stock |  |  |  |  |  | Stockholders’ |
|  | Per |  |  |  |  |  |  |  |  | Owned But |  |  | Paid in |  |  | Issued for |  |  | Issued for |  |  | Retained |  |  | Equity |
|  | Share |  |  | Shares |  |  | Amount |  |  | Not Issued |  |  | Capital |  |  | Service |  |  | Service |  |  | Deficit |  |  | (Deficit) |
Stock issued to founders |  | $ | 0.001 |  |  |  | 8,000,000 |  |  | $ | 8,000 |  |  | $ | — |  |  | $ | (8,000 | ) |  | $ | — |  |  | $ | — |  |  | $ | — |  |  | $ | — |
Stock sold |  |  | 0.500 |  |  |  | 3,000,000 |  |  |  | 3,000 |  |  |  | — |  |  |  | 1,415,768 |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | 1,418,768 |
Stock issued for services |  |  | 0.500 |  |  |  | 50,000 |  |  |  | 50 |  |  |  | — |  |  |  | 24,950 |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | 25,000 |
Net loss for the period |  |  |  |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | (592,868 | ) |  |  | (592,868 | )
Balance March 31, 2006 |  |  |  |  |  |  | 11,050,000 |  |  |  | 11,050 |  |  |  | — |  |  |  | 1,432,718 |  |  |  | — |  |  |  | — |  |  |  | (592,868 | ) |  |  | 850,900 |
Stock sold |  |  | 0.540 |  |  |  | 768,000 |  |  |  | 768 |  |  |  | — |  |  |  | 414,032 |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | 414,800 |
Stock issued for services |  |  | 0.600 |  |  |  | 230,000 |  |  |  | 230 |  |  |  | — |  |  |  | 137,770 |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | 138,000 |
Stock issued for services |  |  | 1.000 |  |  |  | — |  |  |  | — |  |  |  | 15 |  |  |  | 14,985 |  |  |  | — |  |  |  | (15,000 | ) |  |  | — |  |  |  | — |
Stock issued to satisfy liabilities |  |  | 0.600 |  |  |  | 510,000 |  |  |  | 510 |  |  |  | — |  |  |  | 305,490 |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | 306,000 |
Stock issued to stockholders |  |  |  |  |  |  | 300,656 |  |  |  | 301 |  |  |  | — |  |  |  | (301 | ) |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |
Stock issued for contract extension |  |  | 0.625 |  |  |  | 320,000 |  |  |  | 320 |  |  |  | — |  |  |  | 199,680 |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | 200,000 |
Options issued for services |  |  |  |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | 99,000 |  |  |  | (99,000 | ) |  |  | — |  |  |  | — |  |  |  | — |
Amortization of stock and options for services |  |  |  |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | 37,813 |  |  |  | 11,000 |  |  |  | — |  |  |  | 48,813 |
Net loss for the period |  |  |  |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | (2,003,103 | ) |  |  | (2,003,103 | )
Balance March 31, 2007 |  |  |  |  |  |  | 13,178,656 |  |  | $ | 13,179 |  |  | $ | 15 |  |  | $ | 2,603,374 |  |  | $ | (61,187 | ) |  | $ | (4,000 | ) |  | $ | (2,595,971 | ) |  | $ | (44,590 | )

See notes to consolidated financial statements.

F-5

#####

EnerJex Resources, Inc. and Subsidiary
Consolidated Statement of Cash Flows

|  |  |  |  | From Inception |
|  |  |  |  | (12/30/05) |
|  | Year Ended |  |  | through |
|  | March 31, |  |  | March 31, |
|  | 2007 |  |  | 2006 |
Cash flows from operating activities: |  |  |  |  |  |  |  |
Net loss |  | $ | (2,003,103 | ) |  | $ | (592,868 | )
Depreciation and depletion |  |  | 22,108 |  |  |  | 863 |
Amortization of stock and options for services |  |  | 186,813 |  |  |  | 25,000 |
Accretion of asset retirement obligation |  |  | 1,870 |  |  |  | — |
Impairment of oil & gas properties subject to amortization |  |  | 273,959 |  |  |  | 468,081 |
Loss on sale of vehicle |  |  | 3,854 |  |  |  | — |
Adjustments to reconcile net (loss) to cash used in operating activities: |  |  |  |  |  |  |  |
Accounts receivable |  |  | (1,589 | ) |  |  | (2,549 | )
Notes and interest receivable |  |  | (10,300 | ) |  |  | — |
Deposits and prepaid expenses |  |  | 2,188 |  |  |  | (8,861 | )
Accounts payable |  |  | (6,746 | ) |  |  | 49,045 |
Accrued liabilities |  |  | 95,387 |  |  |  | 503 |
Cash used in operating activities |  |  | (1,435,559 | ) |  |  | (60,786 | )
Cash flows from investing activities: |  |  |  |  |  |  |  |
Purchase of equipment |  |  | (35,500 | ) |  |  | (17,550 | )
Additions to oil & gas properties not subject to amortization |  |  | (104,080 | ) |  |  | (750,000 | )
Note and interest receivable from officer |  |  | (23,100 | ) |  |  | — |
Proceeds from sale of vehicle |  |  | 11,500 |  |  |  | — |
Cash used in investing activities |  |  | (151,180 | ) |  |  | (767,550 | )
Cash flows from financing activities: |  |  |  |  |  |  |  |
Proceeds from note payable |  |  | 350,000 |  |  |  | — |
Proceeds from sales of common stock |  |  | 414,800 |  |  |  | 1,418,768 |
Stock issued to pay liabilities |  |  | 306,000 |  |  |  | — |
Proceeds from convertible note |  |  | 25,000 |  |  |  | — |
Cash provided from financing activities |  |  | 1,095,800 |  |  |  | 1,418,768 |
Increase in cash & cash equivalents |  |  | (490,939 | ) |  |  | 590,432 |
Cash and cash equivalents, beginning |  |  | 590,432 |  |  |  | — |
Cash and cash equivalents, end |  | $ | 99,493 |  |  | $ | 590,432 |
Interest paid |  | $ | 5,407 |  |  | $ | 38 |
Income tax paid |  | $ | — |  |  | $ | — |
Non cash transactions: |  |  |  |  |  |  |  |
Stock and options issued for services |  | $ | 252,000 |  |  | $ | 33,000 |
Stock issued for properties not subject to amortization |  | $ | 200,000 |  |  | $ | — |
Stock issued for payment of liabilities net of asset in reverse merger |  | $ | 306,000 |  |  | $ | — |

See notes to consolidated financial Statements.

F-6

#####

EnerJex Resources, Inc. and Subsidiary
Notes to Consolidated Financial Statements

Note 1 — | Significant Accounting Policies

Nature of Business
We are an independent energy company engaged in the business of producing and selling oil and natural gas. This 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 the central United States, also referred to as the mid-continent region.
Basis of Presentation
The Company was formed on December 30, 2005 (“Inception”) and incorporated in the state of Nevada as Midwest Energy, Inc (“Midwest”). In February 2006 we acquired our first oil and natural gas assets, located in Allen County, Kansas.
On July 31, 2006, Millennium Plastics Corporation (“MPCO”) agreed to acquire Midwest, pursuant to an agreement and plan of merger. The agreement and plan of merger provided that, effective on August 15, 2006, Millennium Acquisition Sub merged with and into Midwest, with Midwest as the surviving corporation and wholly-owned subsidiary of MPCO. 11,833,000 shares of MPCO common stock were issued in exchange for 100% of the outstanding shares of Midwest. Further, concurrent with the effective time of the merger and prior to the issuance of the shares to the Midwest stockholders, there was a 1 for 253.45 reverse split of MPCO outstanding shares of common stock. Upon closing of the merger, the former stockholders of Midwest controlled approximately 98% of outstanding shares of common stock.
Midwest was considered the acquiring enterprise for financial reporting purposes. The merger was accounted for as a reverse acquisition with Midwest as the accounting acquirer and MPCO as the surviving company for legal purposes. Accordingly, the financial statements include the historical results of operations of Midwest, the accounting acquirer.
MPCO changed its name to EnerJex Resources, Inc. on August 15, 2006.
Principles of Consolidation
Our consolidated financial statements include the accounts of our wholly-owned subsidiary Midwest 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 collectability 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.

F-7

#####

EnerJex Resources, Inc. and Subsidiary
Notes to Consolidated Financial Statements — (Continued)
Stock-based Compensation
Common stock, warrants and options issued for services are accounted for based on the fair market value at the date the services are performed. If the awards are based on a vesting period the fair market value of the awards is determined as vesting is earned. If the services are to be performed over a period of time the value is amortized over the life of the period that services are performed.
Income Taxes
We account for income taxes under SFAS 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 differ from the amounts currently payable because of temporary differences in the recognition of certain income and expense items for financial reporting and tax reporting purposes.
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, since interest rates on substantially all of our debt are variable, market based rates, the carrying amounts are a reasonable estimate of fair value.
Earnings Per Share
SFAS No. 128, Earnings Per Share. This standard 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 loss per share computation. Potentially issuable shares of common stock pursuant to outstanding stock options and warrants are excluded from the diluted computation, as their effect would be anti-dilutive.
Cash and Cash Equivalents
We consider all highly liquid investment instruments purchased with remaining 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
It is our policy to recognize revenue when title passes to our customers based on the contractual point of delivery.
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. At March 31, 2007 our fixed assets were vehicles.
Debt issue costs
Debt issuance costs incurred are capitalized and subsequently amortized over the term of the related debt on an interest method of accretion over the estimated life of the debt.

F-8

#####

EnerJex Resources, Inc. and Subsidiary
Notes to Consolidated Financial Statements — (Continued)
Oil and Gas Properties
We follow the full cost method of accounting for oil and natural gas properties. Accordingly, all costs associated with the acquisition, exploration, and development are capitalized.
All costs included in properties subject to amortization, are amortized on the unit-of-production method using estimates of proved reserves. Investments in unproved properties and major development projects are not amortized until proved reserves associated with the projects can be determined or until impairment occurs. If the results of an assessment indicate that the properties are impaired, the amount of the impairment is added to the capitalized costs to be amortized. Abandonment of oil and natural gas properties are charged to the full cost pool and amortized.
Under the full cost method, the net book value of oil and natural gas properties are subject to a “ceiling” amount. The ceiling is the estimated after-tax future net cash flows from proved oil and natural gas properties, discounted at 10% per annum plus the lower of cost or fair market value of unevaluated properties. In calculating future net revenues, prices and costs in effect at the time of the calculation are held constant for the lives of the oil and natural gas reserves, except for changes that are fixed and determinable by existing contracts. The excess, if any, of the net book value above this ceiling is charged to expense.
Sales of proved and unproved properties are accounted for as adjustments of capitalized costs with no gain or loss recognized, unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves of oil and gas, in which case the gain or loss is recognized as income.
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
We accrue for the future plugging and abandonment of oil and natural gas assets in the period in which the obligation is incurred. We accrue costs at estimated fair value. When the related liability is initially recorded, we capitalize the cost by increasing the carrying amount of properties subject to amortization. Over time, the liability is accreted to its settlement value and the capitalized cost is depleted over the life of the related asset. Upon settlement of the liability, we recognize a gain or loss for any difference between the settlement amount and the liability recorded.
Major Purchasers
From inception through March 31, 2007, we sold all of our natural gas production to one purchaser.
Recent Issued Accounting Standards
In September 2006, the Securities and Exchange Commission staff (“SEC”) issued SAB 108. SAB 108 was issued to provide consistency to how companies quantify financial statement misstatements. SAB 108 establishes an approach that requires companies to quantify misstatements in financial statements based on effects of the misstatement on both the consolidated balance sheet and statement of operations and the related financial statement disclosures. Additionally, companies must evaluate the cumulative effect of errors existing in prior years that previously had been considered immaterial. We adopted SAB 108 in connection with the preparation of our annual financial statements for the year ended March 31, 2007 and found no adjustments necessary.

F-9

#####

EnerJex Resources, Inc. and Subsidiary
Notes to Consolidated Financial Statements — (Continued)
In September 2006, the FASB issued SFAS No. 157, Fair Value Measurements (“SFAS No. 157”). SFAS No. 157 defines fair value, establishes a framework for measuring fair value in generally accepted accounting principles and expands disclosures about fair value measurements. SFAS No. 157 does not require any new fair value measurements, rather, its application will be made pursuant to other accounting pronouncements that require or permit fair value measurements. SFAS No. 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those years. The provisions of SFAS No. 157 are to be applied prospectively upon adoption, except for limited specified exceptions. We are evaluating the requirements of SFAS No. 157 and do not expect the adoption to have a material impact on our consolidated balance sheet or statement of operations.
In June 2006, the Financial Accounting Standards Board (“FASB”) issued Interpretation No. 48, Accounting for Uncertainty in Income Taxes-an interpretation of FASB Statement No. 109 (“FIN 48”). FIN 48 clarifies the accounting for uncertainty in income taxes recognized in a company’s financial statements in accordance with FASB Statement No. 109, Accounting for Income Taxes. It prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. FIN 48 also provides guidance on de-recognition, classification, interest and penalties, accounting in interim periods, disclosure and transition. FIN 48 is effective for fiscal years beginning after December 15, 2006 and will be adopted by us on April 1, 2007. We do not expect the adoption of FIN 48 to have a material impact on our consolidated balance sheet or statement of operations.
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 and security sales 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 2006:
At inception on December 30, 2005, 8 million shares of common stock were issued at no cost to our founders.
On March 15, 2006, we completed an offering of 3 million shares of common stock at a price of $0.50 per share. Fees of $81,232 in connection with the offering were offset to paid in capital.
On March 16, 2006, we issued 40,000 shares of common stock for services rendered in connection with an acquisition of an oil and natural gas property. The value assigned to the transaction was equivalent to $.50 per share as that was the most recent sales price. The cost was recorded as a professional fee expense.
On March 16, 2006, we issued 10,000 shares of common stock for consulting services. The value assigned to the transaction was equivalent to $.50 per share as that was the most recent sales price. The cost was recorded as a professional fee expense.

F-10

#####

EnerJex Resources, Inc. and Subsidiary
Notes to Consolidated Financial Statements — (Continued)
Stock transactions in fiscal 2007:
On April 28, 2006, we entered into a consulting agreement with Nunneley Oil and Gas Management to provide evaluations of oil & gas leases and technical data. Fees for the services were 15,000 shares of our common stock. The value of the stock was $9,000 based on our last sale price on the day the stock was earned. We recorded $9,000 as professional fee expense.
On July 31, 2006, pursuant to the reverse merger with Millennium Plastics Corporation the stockholders of Millennium Plastics Corporation retained 300,656 shares of our stock.
On August 16, 2006, we agreed to issue 200,000 shares of our common stock to Stoecklein Law Group for professional legal services provided to us. The shares were valued at a price of $.60 per share that was the price we most recently sold shares for and we expensed $120,000 as professional fees in the transaction.
On August 16, 2006, we issued 510,000 shares of our common stock to pay for liabilities assumed from Millennium Plastics Company. The value of the stock was based on our last sales price on the day the stock was earned ($.60 per share) and totaled $306,000.
On September 10, 2006, we entered into a consulting agreement with Bill Stoeckinger to assist in the assessment of well data and geology. Fees for the services were 15,000 shares of our common stock. The value of the stock was based on our last sales price on the day the stock was earned ($.60 per share) and totaled $9,000. We recorded $9,000 as professional fee expense.
During the year ended March 31, 2007, we sold 768,000 shares of our common stock at $.60 per share. Pursuant to the sale we paid a fee of $46,000 to an individual that assisted us in obtaining capital. The fee was offset to the paid in capital recorded in the transaction.
On December 15, 2006, we amended a joint exploration agreement with an entity that holds leases on properties and issued 320,000 of our shares in lieu of cash. The common stock was valued at $200,000 and we recorded this in the oil & gas properties not subject to amortization.
On January 10, 2007, we agreed to issue 15,000 shares of our common stock valued at $15,000 for oil field services. On March 31, 2007, the shares were unissued and we have recorded $15 as stock owed not issued which represents the par value of the stock. The services cover a period that expends beyond March 31, 2007 and we recorded the value of the services through March 31, 2007 ($11,000) as direct operating cost. The remaining value of the services ($4,000) will be amortized in the first quarter of fiscal 2008.
Option transactions in fiscal 2007:
Pursuant to an employment agreement we issued 300,000 stock options to our Chief Financial Officer Todd Bart on August 16, 2006. The options vest at 100,000 per year on the anniversary of the agreement. The options have an exercise price of $1.00 per share of our common stock and they expire on August 15, 2011. The value of the options was based on the Black-Scholes pricing model and totaled $99,000 based on the following assumptions stock price-$.60; exercise price-$1.00; life 5 years; volatility 76%; yield-4.81%. Initially we recorded the value as unamortized costs of options issued for services and we will amortize this over the vesting period of the agreement as additional compensation. We will recalculate the value of the options each quarter. For the year ended March 31, 2007 we recorded $37,813 as compensation expense and the unamortized balance was $61,187. We had no other options outstanding at March 31, 2007.

Note 4 — | Impairment of oil and gas properties

In fiscal 2006, we acquired a 100% working interest in certain oil and natural gas assets located in Allen County, Kansas known as the Gas City Project. The assets included producing wells, approximately 10,000 acres of leasehold and a gathering system with a connection to an Oneok natural gas pipeline. The

F-11

#####

EnerJex Resources, Inc. and Subsidiary
Notes to Consolidated Financial Statements — (Continued)
purchase price for the assets was $750,000. We also recorded a $22,000 liability for the asset retirement obligation associated with the plugging and abandonment of the wells acquired. Based upon reserve reports and management’s evaluation of the acquisition, $468,081 of the purchase price was considered to be impaired and was expensed. In fiscal 2007 there was further impairment of these assets totaling $273,959 based on reserve studies of the present value of the discounted cash flows.

Note 5 — | Income Taxes

Deferred income taxes are determined based on the tax effect of items subject to different treatment between book and tax bases. There is approximately $2,596,000 of net operating loss carry-forwards which expire in 2021-2022. The net deferred tax is as follows:

|  | March 31, |  |  | March 31, |
|  | 2007 |  |  | 2006 |
Non-current deferred tax asset (liabilities): |  |  |  |  |  |  |  |
Net operating loss carry-forward |  | $ | 908,000 |  |  | $ | 180,000 |
Valuation allowance |  |  | (908,000 | ) |  |  | (180,000 | )
Total deferred tax net |  | $ | — |  |  | $ | — |

A reconciliation of the provision for income taxes to the statutory federal rate for continuing operations for the year ended March 31, 2007 and the period from inception through March 31, 2006 is as follows:

|  | March 31, |  |  | March 31, |
|  | 2007 |  |  | 2006 |
Statutory tax rate |  |  | 34.0 | % |  |  | 34.0 | %
Change in valuation allowance |  |  | (34.0 | )% |  |  | (34.0 | )%
Effective tax rate |  |  | 0.0 | % |  |  | 0.0 | %

Note 6 — | Asset Retirement Obligations

Our asset retirement obligations relate to the abandonment of oil and natural gas wells. The amounts recognized are based on numerous estimates and assumptions, including future retirement costs, inflation rates and credit adjusted risk-free interest rates. The following shows the changes in asset retirement obligations for the financial statements presented. Accretion of the liability was recorded as interest expense.

|  | March 31, |  |  | March 31, |
|  | 2007 |  |  | 2006 |
Asset retirement obligation, beginning of period |  | $ | 22,038 |  |  | $ | — |
Liabilities incurred during the period |  |  | — |  |  |  | 22,000 |
Liabilities settled during the period |  |  | — |  |  |  | — |
Accretion |  |  | 1,870 |  |  |  | 38 |
Asset retirement obligations, end of period |  | $ | 23,908 |  |  | $ | 22,038 |

Note 7 — | Convertible Note

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 $2.00 per share.

F-12

#####

EnerJex Resources, Inc. and Subsidiary
Notes to Consolidated Financial Statements — (Continued)

Note 8 — | Goodwill From Reverse Merger

Pursuant to the reverse merger with Millennium Plastics Corporation we assumed liabilities totaling $687,000 and received a patent that had a no book value. We issued stock and cash to pay the liabilities and have sold the patent for $10,000. We had an expense of $677,000 for goodwill resulting from the reverse merger.

Note 9 — | Related Party Transactions

We acquired a vehicle from our President for $35,500 that approximated the fair market value at the time of purchase.
We entered an agreement where we advanced funds to our Chief Financial Officer on August 1, 2006. The note is unsecured and totaled $22,000. Interest is at 7.5% and we recorded interest of $1,100 for the year ended March 31, 2007. The note is due July 31, 2009.
On October 30, 2006, we entered into an agreement with a stockholder to sell the patent we received in the reverse merger. In exchange for the patent, we received a note for $10,000 payable on December 31, 2006. The note is in default but we believe the note will be paid in fiscal 2008.
Our Chief Executive Officer, Steve Cochennet, has agreed to accrue his salary. As of March 31, 2007, $84,500 has been accrued and has been recorded as accrued salary payable to Officer. Subsequent to March 31, 2007 the accrued salary has been paid.
On September 26, 2006, we entered into a letter agreement with MorMeg, LLC, a stockholder, and secured an option to participate in a joint exploration agreement. The cost of the option was $100,000. On December 15, 2006 pursuant to amendment No. 1 to the Letter Agreement we issued 320,000 shares of our stock (valued at $200,000) to extend our option to enter into the joint exploration agreement for an additional 120 days. See subsequent events for the payment of a fee in connection with the joint exploration agreement.
On March 14, and July 21, 2006, we paid consulting fees totaling $121,000 in connection with our financing activities to a stockholder of the Company.

Note 10 — | Commitments and Contingencies

Effective August 7, 2006, we entered into a lease for office space through July 31, 2007. Payments for rent were $21,682 during the year ended March 31, 2007. On April 1, 2007, we leased additional space through March 31, 2008. Commitments for lease payments total $17,192 under these lease agreements for the year ending March 31, 2008.

Note 11 — | Note Payable

On November 15, 2006, we entered into a note payable with a bank in the amount of $100,000. The note was subsequently increased to $350,000. The note had an interest rate of 9% and was secured by substantially all of our assets. The principal and interest was paid off on April 18, 2007.

Note 12 — | Cost of Oil and Natural Gas Properties

General
The following is information related to the Company’s oil and gas development and producing activities in accordance with SFAS No. 69, “Disclosures about Oil and Gas Producing Activities”. The information is for the period from inception (December 30, 2005) through March 31, 2006 and for the year ended March 31, 2007.

F-13

#####

EnerJex Resources, Inc. and Subsidiary
Notes to Consolidated Financial Statements — (Continued)
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 and interest expense is excluded from this determination.

|  | March 31, |  |  | March 31, |
|  | 2007 |  |  | 2006 |
Production revenues |  | $ | 90,800 |  |  | $ | 2,142 |
Production costs |  |  | (172,417 | ) |  |  | (14,599 | )
Depletion and depreciation |  |  | (11,477 | ) |  |  | (385 | )
Income taxes |  |  | — |  |  |  | — |
Results of operations for producing activities |  | $ | (93,094 | ) |  | $ | (12,842 | )

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, |  |  | March 31, |
|  | 2007 |  |  | 2006 |
Proved |  | $ | 11,862 |  |  | $ | 244,337 |
Unevaluated and unproved |  |  | 322,178 |  |  |  | 59,582 |
Accumulated depreciation and depletion |  |  | (11,862 | ) |  |  | (385 | )
Net capitalized costs |  | $ | 322,178 |  |  | $ | 303,534 |

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.
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, |  |  | March 31, |
|  | 2007 |  |  | 2006 |
Acquisition of proved and unproved properties |  | $ | 304,080 |  |  | $ | 772,000 |
Development costs |  |  | — |  |  |  | — |
Exploration costs |  |  | — |  |  |  | — |
Total |  | $ | 304,080 |  |  | $ | 772,000 |

Note 13 — | Subsequent Events

On April 11, 2007 we sold 6,300,000 shares of our stock and $6,300,000 senior secured debentures. Proceeds from the sale net of costs were $5,657,964. The debentures pay interest at 10% per annum and mature March 31, 2010. The allocation of sale proceeds is based on the ratable fair market value of the stock and debentures on the date of sale. The transaction costs of $642,035 will be amortized over the term of the

F-14

#####

EnerJex Resources, Inc. and Subsidiary
Notes to Consolidated Financial Statements — (Continued)
debentures. We have the option to pay interest on the debentures in cash or in shares of our stock based on a price equal to 85% of the weighted average price of our stock over a 30-day period preceding the interest date. We have to meet production thresholds during the period the debentures are outstanding. We must have production of the equivalent of 180 Barrel of Oil Equivalent Per Day (BOPDE) by December 31, 2007; 182 BOPDE by June 30, 2008; 170 BOPDE by December 31, 2008 and 206 BOPDE by June 30, 2009. If we do not meet those thresholds on any of the days we will be required to issue an additional 3,000,000 shares to the debenture holders for each period we fail to meet the thresholds. We are required to register the shares that were issued in this transaction and if we are unable to meet certain registration deadlines we may have to pay a penalty, ranging from .005% to 10%, to the debenture holders. On June 8, 2007 we are committed to sell an additional 2,700,000 of our shares and issue $2,700,000 of secured debentures with terms identical to the April 11th sale.
On April 18, 2007, we acquired the working interests of certain producing properties for $400,000 from a stockholder. We obtained an independent valuation of the properties that determined the fair market value exceeded the amount paid.
We entered into a joint operating agreement with a stockholder, MorMeg, LLC and advanced $4,000,000 that will be used for acquisition and development. We also completed an obligation with MorMeg, LLC by payment of $200,000.
On May 4, 2007, the Governance, Compensation and Nominating Committee of the Board of Directors established compensation for board and committee members. The three non-employee Directors received one-fourth ($2,500) of their annual retainer of $10,000, during the month of May, 2007. Additionally, the Audit Committee Chairman, Mr. Dammeyer, received 9,600 shares of common stock, representing the stock portion of his compensation for Audit Committee Chairman. Mr. Dammeyer also received $5,000 for the cash portion of his compensation for Audit Committee Chairman through June, 2007. We granted 200,000 options to each of our three non-employee Directors, 1,000,000 options to our CEO Mr. Steve Cochennet, 300,000 options to Mr. Mark Haas, a principal with MorMeg, LLC, and a total of 125,000 options to two of our employees. All of the options had a strike price of $1.25 per share (approximate market price of our stock on the date of grant) for a period of 4 years.
On May 4, 2007, we increased the number of issuable shares under our 2002/2003 option plan to 5,000,000 shares.

Note 14 — | Supplemental Oil and Natural Gas Reserve Information (Unaudited)

(a) | General

Our estimated net proved oil and gas reserves and the present value of estimated cash flows from those reserves are summarized below. The reserves were estimated by McCune Engineering, independent petroleum engineers, using market prices at the end of each of the periods presented in the financial statements. Those prices were held constant over the estimated life of the reserves. There are numerous uncertainties inherent in estimating quantities and values of proved oil and gas reserves and in projecting future rates of production and the timing of development expenditures, including factors involving reservoir engineering, pricing and both operating and regulatory constraints. All reserves estimates are to some degree speculative, and various classifications of reserves only constitute attempts to define the degree of speculation involved. Accordingly, oil and gas reserve information represents estimates only and should not be construed as being exact. The information is for the period from inception (December 30, 2005) through March 31, 2006 and for the year ended March 31, 2007.

F-15

#####

EnerJex Resources, Inc. and Subsidiary
Notes to Consolidated Financial Statements — (Continued)

(b) | Estimated Oil and Gas Reserve Quantities

Our ownership interests in estimated quantities of proved gas reserves and changes in net proved reserves, all of which are located in the United States, are summarized below.

|  | Gas-mcf |
Proved reserves: |  |  |  |
Balance at inception (December 30, 2005) |  |  | — |
Purchase of reserves-in-place |  |  | 229,912 |
Production |  |  | (395 | )
Balance March 31, 2006 |  |  | 229,517 |

There were no revisions of previous estimates of reserves or extensions and discoveries during the period from inception (December 30, 2005) through March 31, 2006.

|  | Gas-mcf |
Proved reserves: |  |  |  |
Balance March 31, 2006 |  |  | 229,517 |
Revisions of previous estimates |  |  | (212,077 | )
Production |  |  | (17,440 | )
Balance March 31, 2007 |  |  | — |

There were no extensions and discoveries or purchases of reserves-in-place during the year ended March 31, 2007.
Proved developed reserves at the end of the period:

|  | Gas-mcf |  |  | Gas-mcf |  |  |  |
|  | March 31, |  |  | March 31, |  |  |  |
|  | 2007 |  |  | 2006 |  |  |  |
|  |  | — |  |  |  | 229,517 |  |  |  |  |

(c) | Standardized measure of discounted future 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. There were no proved reserves at inception. The standardized measure of future cash flows as of March 31, 2007 and 2006 is calculated using a price per Mcf of natural gas of $5.37 and $5.05, respectively. The gas price was the Williams/Southern Star Central spot gas price (inside FERC index) at the end of the period. 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.

F-16

#####

EnerJex Resources, Inc. and Subsidiary
Notes to Consolidated Financial Statements — (Continued)
There were no proved reserves at inception (December 30, 2005).

|  | March 31, |  |  | March 31, |
|  | 2007 |  |  | 2006 |
Future production revenue |  | $ | 240,000 |  |  | $ | 1,103,000 |
Future production costs |  |  | (240,000 | ) |  |  | (775,000 | )
Future development costs |  |  | — |  |  |  | — |
Future cash flows before income taxes |  |  | — |  |  |  | 328,000 |
Future income taxes |  |  | — |  |  |  | — |
Future net cash flows |  |  | — |  |  |  | 328,000 |
10% annual discount for estimating of future cash flows |  |  | — |  |  |  | (84,000 | )
Standardized measure of discounted net cash flows |  | $ | — |  |  | $ | 244,000 |

(d) | Changes in Standardized Measure of Discounted Future Net Cash Flows

At March 31, 2007, the future production costs exceeded the production revenue.

Balance December 30, 2005 (inception)(1) |  | $ | — |
Sales, net of production costs |  |  | — |
Acquisition of gas in place |  |  | 244,000 |
Balance March 31, 2006 |  |  | 244,000 |
Sales, net of production costs |  |  | (18,000 | )
Net change in pricing and production costs(1) |  |  | (60,000 | )
Net change in future estimated development costs |  |  | (90,000 | )
Extensions and discoveries |  |  | — |
Revisions |  |  | (77,000 | )
Accretion of discount |  |  | 1,000 |
Change in income tax |  |  | — |
Balance March 31, 2007 |  | $ | — |

Production costs exceeded sales in fiscal 2006 and 2007.

F-17

#####

Report of Independent Registered Public Accounting Firm
To the Board of Directors and Stockholders
EnerJex Resources, Inc. and Subsidiary,
We have audited the accompanying consolidated balance sheets of EnerJex Resources, Inc. and Subsidiary as of December 31, 2007 and the related statements of operations, changes in shareholders’ equity and cash flows for the nine month period ended December 31, 2007. 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 audit.
We conducted our audit in accordance with auditing 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 misstatement. 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 financial position of EnerJex Resources, Inc. and Subsidiary as of December 31, 2007 and the results of their operations and their cash flows for the nine month period ended December 31, 2007 in conformity with accounting principles generally accepted in the United States.
/s/ Weaver & Martin
Weaver & Martin, LLC
Kansas City, Missouri
February 21, 2008

G-1

#####

EnerJex Resources, Inc. and subsidiaries
Consolidated Balance Sheet

|  | December 31, |
|  | 2007 |
ASSETS
Current assets: |  |  |  |
Cash |  | $ | 957,477 |
Accounts receivable |  |  | 57,788 |
Sales revenue receivable |  |  | 319,521 |
Prepaid expenses |  |  | 10,797 |
Total current assets |  |  | 1,345,583 |
Fixed assets, net of accumulated depreciation of $21,140 |  |  | 127,400 |
Other assets: |  |  |  |
Oil and gas properties using full cost accounting: |  |  |  |
Properties not subject to amortization |  |  | 74,777 |
Properties subject to amortization |  |  | 9,016,166 |
Total other assets |  |  | 9,090,943 |
|  | $ | 10,563,926 |
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities: |  |  |  |
Accounts payable |  | $ | 364,755 |
Accrued liabilities |  |  | 126,981 |
Deferred payments from Euramerica for development |  |  | 51,925 |
Promissory notes payable |  |  | 965,000 |
Current portion of long term debt |  |  | 438,318 |
Total current liabilities |  |  | 1,946,979 |
Asset retirement obligation |  |  | 389,475 |
Long term liabilities: |  |  |  |
Convertible note payable |  |  | 25,000 |
Long-term debt, less current portion |  |  | 6,148,452 |
|  |  | 6,173,452 |
Commitments and contingencies |  |  | — |
Stockholders’ Equity: |  |  |  |
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 22,203,256 shares issued and outstanding |  |  | 22,203 |
Additional paid-in capital |  |  | 8,705,730 |
Accumulated (deficit) |  |  | (6,673,913 | )
|  |  | 2,054,020 |
|  | $ | 10,563,926 |

See notes to consolidated financial statements.

G-2

#####

EnerJex Resources, Inc. and subsidiaries
Consolidated Statement of Operations

|  | Nine Months Ended |  |  | Nine Months Ended |
|  | December 31, |  |  | December 31, |
|  | 2007 |  |  | 2006 |
|  | (Audited) |  |  | (Unaudited) |
Revenue |  |  |  |  |  |  |  |
Oil and gas activities |  | $ | 1,982,119 |  |  | $ | 76,314 |
Expenses: |  |  |  |  |  |  |  |
Direct costs |  |  | 1,104,272 |  |  |  | 279,619 |
Professional fees |  |  | 1,112,832 |  |  |  | 287,478 |
Investor relations fees |  |  | 164,435 |  |  |  | — |
General and administrative expenses |  |  | 1,758,262 |  |  |  | 319,366 |
Depreciation, depletion and amortization |  |  | 532,665 |  |  |  | 23,359 |
Impairment of goodwill |  |  | — |  |  |  | 677,000 |
Total expenses |  |  | 4,672,466 |  |  |  | 1,586,822 |
Net operating (loss) |  |  | (2,690,347 | ) |  |  | (1,510,508 | )
Other income (expense): |  |  |  |  |  |  |  |
Interest expense |  |  | (507,640 | ) |  |  | (4,239 | )
Loan fees |  |  | (113,155 | ) |  |  | — |
Loan interest accretion |  |  | (766,800 | ) |  |  | — |
Interest income |  |  | — |  |  |  | 3,495 |
Loss on sale of asset |  |  | — |  |  |  | (3,854 | )
Total other income (expense) |  |  | (1,317,595 | ) |  |  | (4,598 | )
Net income (loss) |  | $ | (4,077,942 | ) |  | $ | (1,515,106 | )
Weighted average number of Common shares outstanding — basic |  |  | 20,691,689 |  |  |  | 12,142,498 |
Net income (loss) per share — basic |  | $ | (0.20 | ) |  | $ | (0.12 | )

See notes to consolidated financial statements.

G-3

#####

EnerJex Resources, Inc. and subsidiaries
Consolidated Statement of Stockholders’ Equity

|  | Common Stock |  |  |  |  |  |  |  |  |  |
|  |  |  |  | Owned But |  |  | Paid in |  |  | Retained |  |  | Stockholders’ |
|  | Amount |  |  | Not Issued |  |  | Capital |  |  | Deficit |  |  | Equity |
Balance March 31, 2007 |  | $ | 13,179 |  |  | $ | 15 |  |  | $ | 2,538,187 |  |  | $ | (2,595,971 | ) |  | $ | (44,590 | )
Stock sold |  |  | 9,000 |  |  |  | — |  |  |  | 4,024,167 |  |  |  | — |  |  |  | 4,033,167 |
Stock issued for services |  |  | 9 |  |  |  | — |  |  |  | 11,990 |  |  |  | — |  |  |  | 11,999 |
Previously authorized but unissued stock |  |  | 15 |  |  |  | (15 | ) |  |  | — |  |  |  | — |  |  |  | — |
Warrants issued for services |  |  | — |  |  |  | — |  |  |  | 280,591 |  |  |  | — |  |  |  | 280,591 |
Options issued for services |  |  | — |  |  |  | — |  |  |  | 1,850,795 |  |  |  | — |  |  |  | 1,850,795 |
Net loss for the period |  |  | — |  |  |  | — |  |  |  | — |  |  |  | (4,077,942 | ) |  |  | (4.077,942 | )
Balance December 31, 2007 |  | $ | 22,203 |  |  | $ | — |  |  | $ | 8,705,730 |  |  | $ | (6,673,913 | ) |  | $ | 2,054,020 |

See notes to consolidated financial statements.

G-4

#####

EnerJex Resources, Inc. and subsidiaries
Consolidated Statement of Cash Flows

|  | Nine Months Ended |  |  | Nine Months Ended |
|  | December 31, |  |  | December 31, |
|  | 2007 |  |  | 2006 |
|  | (Audited) |  |  | (Unaudited) |
Cash flows from operating activities |  |  |  |  |  |  |  |
Net (loss) |  | $ | (4,077,942 | ) |  | $ | (1,515,106 | )
Depreciation, depletion and amortization |  |  | 532,665 |  |  |  | 46,047 |
Accretion of asset retirement obligation |  |  | 13,567 |  |  |  | 1,440 |
Stock, warrants and options issued for services |  |  | 1,862,795 |  |  |  | 138,000 |
Loan costs |  |  | 879,955 |  |  |  | — |
Loss on sale of asset |  |  | — |  |  |  | 3,854 |
Adjustments to reconcile net (loss) to cash used in operating activities: |  |  |  |  |  |  |  |
Accounts and notes receivable |  |  | (362,871 | ) |  |  | (18,028 | )
Prepaid expenses |  |  | (4,124 | ) |  |  | 8,443 |
Accounts payable |  |  | 322,456 |  |  |  | 28,832 |
Accrued liabilities |  |  | 31,091 |  |  |  | 38,437 |
Deferred payments from Euramerica for development |  |  | 51,925 |  |  |  | — |
Net cash used in operating activities |  |  | (750,483 | ) |  |  | (1,268,081 | )
Cash flows from investing activities |  |  |  |  |  |  |  |
Purchase of fixed assets |  |  | (113,575 | ) |  |  | (35,500 | )
Proceeds from sale of assets |  |  | — |  |  |  | 11,500 |
Payments received on notes receivable |  |  | — |  |  |  | (32,275 | )
Additions to oil and gas properties |  |  | (8,936,628 | ) |  |  | (100,000 | )
Additions to oil and gas properties not subject to amortization |  |  | — |  |  |  | (4,104 | )
Net cash used in investing activities |  |  | (9,050,203 | ) |  |  | (160,379 | )
Cash flows from financing activities |  |  |  |  |  |  |  |
Proceeds from sale of common stock |  |  | 4,313,757 |  |  |  | 414,800 |
Stock issued for liabilities |  |  | — |  |  |  | 306,000 |
Payments received on notes receivable |  |  | 23,100 |  |  |  | — |
Proceeds from long term debt |  |  | 6,765,141 |  |  |  | 100,000 |
Payments on notes payable |  |  | (443,328 | ) |  |  | — |
Proceeds from convertible note |  |  | — |  |  |  | 25,000 |
Net cash provided from financing activities |  |  | 10,658,670 |  |  |  | 845,800 |
Net increase (decrease) in cash |  |  | 857,984 |  |  |  | (582,660 | )
Cash — beginning |  |  | 99,493 |  |  |  | 590,432 |
Cash — ending |  | $ | 957,477 |  |  | $ | 7,772 |
Supplemental disclosures: |  |  |  |  |  |  |  |
Interest paid |  | $ | 75,935 |  |  | $ | 2,313 |
Income taxes paid |  |  | — |  |  |  | — |
Non-cash transactions: |  |  |  |  |  |  |  |
Stock, warrants and options issued for services |  | $ | 1,862,795 |  |  | $ | 644,000 |
Asset retirement obligation |  |  | 352,000 |  |  |  | — |
Loan costs |  |  | 879,955 |  |  |  | — |

See notes to consolidated financial statements.

G-5

#####

EnerJex Resources, Inc.
Notes to Consolidated Financial Statements

Note 1 — | Significant Accounting Policies

Nature of Business
We are an independent energy company engaged in the business of producing and selling oil and natural gas. This 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 the central United States, also referred to as the mid-continent region.
Principles of Consolidation
Our consolidated financial statements include the accounts of our wholly-owned subsidiaries, EnerJex Kansas, Inc. and 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 collectability 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.
Stock-based Compensation
Common stock, warrants and options issued for services are accounted for based on the fair market value at the date the services are performed. If the awards are based on a vesting period the fair market value of the awards is determined as vesting is earned. If the services are to be performed over a period of time the value is amortized over the life of the period that services are performed.
Income Taxes
We account for income taxes under SFAS 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 differ from the amounts currently payable because of temporary differences in the recognition of certain income and expense items for financial reporting and tax reporting purposes.
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, since interest rates on substantially all of our debt are variable, market based rates, the carrying amounts are a reasonable estimate of fair value.

G-6

#####

EnerJex Resources, Inc.
Notes to Consolidated Financial Statements — (Continued)
Earnings Per Share
SFAS No. 128, Earnings Per Share. This standard 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 loss per share computation. For the period ended December 31, 2007 the potentially issuable shares of common stock pursuant to outstanding stock options and warrants have been excluded from the diluted 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 natural gas revenues are recognized when production is sold to a purchaser at a fixed or determinable price, when delivery has occurred and title has transferred, and if collectibility 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 natural 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 underproduced 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 unaudited supplemental oil and gas disclosures. There was no imbalance at December 31, 2007.
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.
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. At December 31, 2007 our fixed assets were primarily vehicles.
Debt Issue Costs
Debt issuance costs incurred are capitalized and subsequently amortized over the term of the related debt on an interest method of accretion over the estimated life of the debt.

G-7

#####

EnerJex Resources, Inc.
Notes to Consolidated Financial Statements — (Continued)
Oil and Gas Properties
We follow the full cost method of accounting for oil and natural gas properties. Accordingly, all costs associated with acquisition, exploration, and development are capitalized.
All costs included in properties subject to amortization, are amortized on the unit-of-production method using estimates of proved reserves. Investments in unproved properties and major development projects are not amortized until proved reserves associated with the projects can be determined or until impairment occurs. If the results of an assessment indicate that the properties are impaired, the amount of the impairment is added to the capitalized costs to be amortized. Abandonment of oil and natural gas properties are charged to the full cost pool and amortized.
Under the full cost method, the net book value of oil and natural gas properties are subject to a “ceiling” amount. The ceiling is the estimated after-tax future net cash flows from proved oil and natural gas properties, discounted at 10% per annum plus the lower of cost or fair market value of unevaluated properties. In calculating future net revenues, prices and costs in effect at the time of the calculation are held constant for the lives of the oil and natural gas reserves, except for changes that are fixed and determinable by existing contracts. The excess, if any, of the net book value above this ceiling is charged to expense.
Sales of proved and unproved properties are accounted for as adjustments of capitalized costs with no gain or loss recognized, unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves of oil and gas, in which case the gain or loss is recognized as income.
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
We accrue for the future plugging and abandonment of oil and natural gas assets in the period in which the obligation is incurred. We accrue costs at estimated fair value. When the related liability is initially recorded, we capitalize the cost by increasing the carrying amount of properties subject to amortization. Over time, the liability is accreted to its settlement value and the capitalized cost is depleted over the life of the related asset. Upon settlement of the liability, we recognize a gain or loss for any difference between the settlement amount and the liability recorded.
Major Purchasers
Through December 31, 2007, we sold all of our natural gas production to a sole purchaser and all of our oil production to a sole purchaser.
Recent Issued Accounting Standards
In July 2006, the FASB issued Interpretation No. 48, “Accounting for Uncertainty in Income Taxes” (“FIN 48”). FIN 48 clarifies the accounting for uncertainty in income taxes recognized in enterprises’ financial statements in accordance with SFAS No. 109, “Accounting for Income Taxes”. FIN 48 prescribes a recognition threshold and measurement attributable for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. FIN 48 also provides guidance on derecognizing, classification, interest and penalties, accounting in interim periods, disclosures and transitions. FIN 48 is

G-8

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EnerJex Resources, Inc.
Notes to Consolidated Financial Statements — (Continued)
effective for fiscal years beginning after December 15, 2006. We believe we have no uncertainties in income taxes.
In September 2006, the FASB issued SFAS No. 157, “Fair Value Measures” (“SFAS No. 157”). SFAS No. 157 defines fair value, establishes a framework for measuring fair value in generally accepted accounting principles (“GAAP”), expands disclosures about fair value measurements, and applies under other accounting pronouncements that require or permit fair value measurements. SFAS No. 157 does not require any new fair value measurements, however the FASB anticipates that for some entities, the application of SFAS No. 157 will change current practice. SFAS No. 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007. We are currently reviewing the effect, if any, SFAS 157 will have on our financial statements.
In February 2007, the FASB issued SFAS No. 159 (“SFAS 159”) — the fair value option for financial assets and liabilities including in amendment of SFAS 115. This Statement permits entities to choose to measure many financial instruments and certain other items at fair value. The objective is to improve financial reporting by providing entities with the opportunity to mitigate volatility in reported earnings caused by measuring related assets and liabilities differently without having to apply complex hedge accounting provisions. This Statement is expected to expand the use of fair value measurement objectives for accounting for financial instruments. This Statement is effective as of the beginning of an entity’s first fiscal year that begins after November15, 2007, and interim periods within those fiscal years. Early adoption is permitted as of the beginning of a fiscal year that begins on or before November 15, 2007, provided the entity also elects to apply the provisions of FASB Statement No. 157, Fair value measurements. We are currently evaluating the impact of SFAS No. 159 on our financial statements.
In December 2007, the FASB issued SFAS No. 141R (revised 2007), “Business Combinations.” Although this statement amends and replaces SFAS No. 141, it retains the fundamental requirements in SFAS No. 141 that (i) the purchase method of accounting be used for all business combinations; and (ii) an acquirer be identified for each business combination. SFAS No. 141R defines the acquirer as the entity that obtains control of one or more businesses in the business combination and establishes the acquisition date as the date that the acquirer achieves control. This Statement applies to all transactions or other events in which an entity (the acquirer) obtains control of one or more businesses (the acquiree), including combinations achieved without the transfer of consideration; however, this Statement does not apply to a combination between entities or businesses under common control. Significant provisions of SFAS No. 141R concern principles and requirements for how an acquirer (i) recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed, and any noncontrolling interest in the acquiree; (ii) recognizes and measures the goodwill acquired in the business combination or a gain from a bargain purchase; and (iii) determines what information to disclose to enable users of the financial statements to evaluate the nature and financial effects of the business combination. This Statement applies prospectively to business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2008 with early adoption not permitted. Management is assessing the impact of the adoption of SFAS No. 141R.
In December 2007, the FASB issued SFAS No. 160, “Non-controlling Interests in Consolidated Financial Statements”. This Statement amends ARB 51 to establish accounting and reporting standards for the non-controlling (minority) interest in a subsidiary and for the deconsolidation of a subsidiary. It clarifies that a non-controlling interest in a subsidiary is an ownership interest in the consolidated entity that should be reported as equity in the consolidated financial statements. We have not yet determined the impact, if any, that SFAS No. 160 will have on our financial statements.
Reclassifications
Certain reclassifications have been made to prior periods to conform to current presentation.

G-9

#####

EnerJex Resources, Inc.
Notes to Consolidated Financial Statements — (Continued)

Note 2 — | Stock Transactions

Stock transactions in fiscal 2008:
On May 4, 2007, we issued 9,600 shares of common stock to a Director and chairman of our Audit Committee for services over the next year. For the nine month period ended December 31, 2007, we recorded director compensation in the amount of $8,000.
On May 22, 2007, we issued 15,000 shares of common stock previously authorized and un-issued.
During the nine months ended December 31, 2007 we issued 9,000,000 shares of our common stock pursuant to our “Mortgage Security Agreements” entered into on April 12, 2007 and June 8, 2007. We allocated $4,500,000 of the $9,000,000 to the equity portion of the transaction. The transaction costs of the equity sale were $466,835 resulting in $4,033,165 in net proceeds.
Option and Warrant transactions in fiscal 2008:
Officers (including officers who are members of the board of directors), directors, employees and consultants will be eligible to receive options under the stock option plans. We will administer the stock option plans and we will 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.
Non-qualified stock options will be granted 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. In no event may the option price with respect to an incentive stock option granted under the stock option 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.
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 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 Stock Option and Incentive 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 1,000,000 shares. At December 31, 2007 we have granted 1,000,000 non-qualified options, which constitutes all options available under this plan.
2002-2003 Stock Option Plan
On May 4, 2007, we amended and restated the 2002-2003 Stock Option Plan to rename the plan and to increase the number of shares issuable to 5,000,000. Our stockholders approved this plan in September of 2007. At December 31, 2007, we have granted 1,175,000 non-qualified options under this plan.
Compensation cost for options issued to employees is measured based on the vesting of the option and the market value as determined by the Black-Scholes pricing model of the option. For the period ended December 31, 2007, we included as compensation expense $1,592,908 relating to the value of vested options. We had $125,392 at December 31, 2007 in charges to future compensation expense relating to the unamortized cost of options that were issued in accordance with contracts that covered a period of one year. This will all be expensed in fiscal 2008. We had $257,887 in option value that is included in oil and natural gas

G-10

#####

EnerJex Resources, Inc.
Notes to Consolidated Financial Statements — (Continued)
properties under the full cost method subject to amortization for services rendered relating directly to our drilling activities.
On June 14, 2007, we entered into a “Separation Agreement” with our former Chief Financial Officer. Pursuant to the agreement, 300,000 options were fully vested with a right to exercise any time prior to September 13, 2007. The options were not exercised and have been cancelled.
The fair value of each option award is estimated on the date of grant using the Black-Scholes pricing model that uses the assumptions noted in the following table. Volatility is based on the historical volatility of stock trading, expected term used the life of the option, risk free rate used 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 can not assume that there will be any future dividends.

Weighted average expected volatility |  |  | 101 | %
Weighted average expected term (in years) |  |  | 4 |
Weighted average expected dividends |  |  | 0 | %
Weighted average risk free rate |  |  | 4.5 | %

The weighted average grant date fair value of the options granted in the period ended December 31, 2007 was $0.88.
In the period ended December 31, 2007, we granted warrants to purchase 375,000 shares of our common stock to C.K. Cooper & Company as partial payment for services render in connection with our financing activities. The warrants have an exercise price of $0.60 and expire on April 11, 2010. The fair value of the warrants based on the Black-Scholes pricing model totaled $280,591. 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.
A summary of stock options and warrants is as follows:

|  |  |  |  | Weighted Ave |  |  |  |  |  | Weighted Ave |
|  | Options |  |  | Exercise Price |  |  | Warrants |  |  | Exercise Price |
Outstanding 03/31/07 |  |  | 300,000 |  |  | $ | 1.00 |  |  |  | — |  |  | $ | — |
Granted |  |  | 2,175,000 |  |  |  | 1.26 |  |  |  | 375,000 |  |  |  | 0.60 |
Cancelled |  |  | (300,000 | ) |  |  | 1.00 |  |  |  | — |  |  |  | — |
Exercised |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |
Outstanding and exercisable 12/31/07 |  |  | 2,175,000 |  |  | $ | 1.26 |  |  |  | 375,000 |  |  | $ | 0.60 |

There were no non-vested options or warrants at April 1, 2007. During the period ended December 31, 2007, 300,000 options became vested when we entered into a “Separation Agreement” with our former Chief Financial Officer. Pursuant to the agreement, 300,000 options became fully vested with a right to exercise any time prior to September 13, 2007. The options were not exercised and have been cancelled. There are no non-vested options or warrants at December 31, 2007.

G-11

#####

EnerJex Resources, Inc.
Notes to Consolidated Financial Statements — (Continued)

Note 3 — | Asset Retirement Obligation

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

|  | December 31, |
|  | 2007 |
Asset retirement obligation, beginning of period |  | $ | 23,908 |
Liabilities incurred during the period |  |  | 352,000 |
Liabilities settled during the period |  |  | — |
Accretion |  |  | 13,567 |
Asset retirement obligations, end of period |  | $ | 389,475 |

Note 4 — | Long-Term Debt and Convertible Debt

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 DKR Soundshore Oasis Holding Fund Ltd., West Coast Opportunity Fund, LLC, Enable Growth Partners LP, Enable Opportunity Partners LP, Glacier Partners LP, and Frey Living Trust (the “Buyers”). Pursuant to the Financing Agreements, we authorized 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 $9,000,000. In connection with the purchase, we agreed to issue to each of the Buyers one share of our common stock for each dollar purchased for a total issuance of 9,000,000 shares. The first closing occurred on April 12, 2007 with a total of $6,300,000 in debentures being sold and the remaining $2,700,000 closing on June 21, 2007.
The proceeds from the debentures were allocated to the note payable and the stock issued based on the fair market value of each item that we calculated to be $9,000,000 for each item. Since each of the instruments had a value equal to 50% of the total, we allocated $4,500,000 to stock and $4,500,000 to the note. We have recorded the maturity value of the note at $9,000,000 and in the equity section we recorded the loan costs of $4,500,000 that will accrete as interest based on the interest method over the period of issue to maturity. The amount of interest accreted for the period ended December 31, 2007 was $766,800.
The Debentures have a three-year term, maturing on March 31, 2010, and bear interest at a rate equal to 10% per annum. Interest is payable quarterly in arrears on the first day of each succeeding quarter. We may pay interest in either cash or registered shares of our common stock. The Debenture has 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 Debentures are guaranteed, pursuant to the “Secured Guaranty” and “Pledge and Security Agreement” by us and secured by a security interest in all of our assets and assignments of production.
Pursuant to the agreements, during the term of the debentures, we are required to produce a minimum average daily quantity of oil and natural gas. The production thresholds will be measured at six month intervals beginning December 31, 2007 and ending on September 30, 2009. In the event that for any Measurement Date specified above, we do not meet the production thresholds applicable to such Measurement Date, then we shall issue to the Buyers an aggregate 3,000,000 shares of common stock for each threshold date (up to 12,000,000 shares total). Each Buyer may elect to receive common stock purchase warrants in lieu of its allocation of shares of common stock. Such warrants shall have an exercise price of $0.01 per share and be exercisable for a four year term. As of December 31, 2007, we have met our initial production threshold and we believe our future production levels will be sufficient to meet the subsequent required threshold levels.

G-12

#####

EnerJex Resources, Inc.
Notes to Consolidated Financial Statements — (Continued)
Pursuant to the terms of the Registration Rights Agreement between us and the Buyers, we are obligated to file a minimum of three registration statements registering the 9,000,000 shares of common stock or shares of common stock underlying the common stock purchase warrants, 3,000,000 interest shares potentially due under the Debentures, and up to 12,000,000 production threshold shares. If we fail to obtain and maintain effectiveness of a registration statement, we will be obligated to pay cash to each Buyer equal to: (i) 0.5% of the aggregate purchase price allocable to such Buyer’s registrable securities included in such registration statement for the first 30 day period following such effectiveness failure or maintenance failure, (ii) 0.75% of the aggregate Purchase price allocable to such Buyer’s registrable securities in such registration statement for the following thirty day period; and (iii) 1% of the aggregate purchase price allocable to such Buyer’s registrable securities included in the registration statement for every thirty day period thereafter. These payments are capped at 10% of the Buyer’s original purchase price under the Debentures. The first registration statement, registering 3,000,000 shares of common stock, became effective on August 14, 2007 and the second became effective January 11, 2008.
We obtained a note payable to a bank of $1,735,000 maturing in October 2011 with an interest rate of 8.5% that is collateralized by our oil leases related to the DD Energy project.
On September 28, 2007, we financed the purchase of vehicles totaling $31,976 through GE Money Bank. This note is for seven years and bears interest at 6.99% per annum and is collateralized by the vehicle.
Long-Term debt consist of the following:

|  | December 31, |
|  | 2007 |
Long term debentures |  | $ | 9,000,000 |
Unaccreted discount |  |  | (4,086,880 | )
Total |  |  | 4,913,120 |
Note payable to bank |  |  | 1,642,990 |
Vehicle note payable |  |  | 30,660 |
Total Long-Term Debt |  |  | 6,586,770 |
Less current portion |  |  | 438,318 |
Long-term debt |  | $ | 6,148,452 |

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 $2.00 per share.
The aggregate principal payments on long-term and convertible debt are as follows: Year ended March 31, 2009: $438,318, March 31, 2010: $9,460,744, March 31, 2011: $474,746, March 31, 2012: $311,877, March 31, 2013: $4,995 and thereafter-$7,970.

Note 5 — | Oil & Gas Properties

On April 9, 2007, we entered into a “Joint Exploration Agreement” with a shareholder, MorMeg, LLC, whereby we agreed to advance $4,000,000 to a joint operating account for further development of MorMeg’s Black Oaks leaseholds in exchange for a 95% working interest in all production originating from the Black Oaks Project until such point when total revenues are equal to development costs. We also agreed to contribute ongoing funding to the field as to not delay development by more than a thirty day period until the field is fully developed or as agreed to by and between the parties. Upon equalization of development cost and revenue, our working interest will adjust downward to 70% and MorMeg will increase their working interest to 30%. In addition, we agreed to pay MorMeg, LLC a one time cash payment in the amount of $200,000 pursuant to the original amended letter agreement dated December 15, 2006. As of December 31, 2007, we fulfilled this obligation.

G-13

#####

EnerJex Resources, Inc.
Notes to Consolidated Financial Statements — (Continued)
On April 18, 2007, we entered into a “Purchase and Sale Agreement” with MorMeg, LLC, a related party, to acquire the lease interests of certain producing properties for cash in the amount of $400,000. Our obligation for payment has been fulfilled at December 31, 2007.
In August of 2007, we entered into a development agreement with 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. We are the operator of the project at a cost plus 17.5% basis. Until Euramerica has completed all payments related to the option exercise, we will retain a 100% working interest in the project. Following Euramerica’s February 29, 2008 payment toward the full purchase price, Euramerica receives revenues equal to a 95% net revenue interest and we receive a management fee equal to a 5% net revenue interest in the project until Euramerica has completed the full payment of its option exercise at which time this 5% net revenue interest management fee will be converted to a 5% carried working interest and Euramerica will receive assignment of its before payout 95% working interest in the project. When the project reaches payout our 5% carried working interest will increase to a 25% working interest and Euramerica will have a 75% working interest.
On September 14, 2007, we entered into a purchase agreement for the acquisition of a 100% working interest in leaseholds located in three counties in eastern Kansas for a cash purchase price of $800,000.
On September 27, 2007, we entered into a purchase and sale agreement with certain related parties through our wholly owned subsidiary, DD Energy, Inc. (“DD”), to acquire oil leases in eastern Kansas for a purchase price of $2.7 million.

Note 6 — | Related party transactions

On October 30, 2006, we entered into an agreement with a shareholder to sell the patent we received in a reverse merger. We received a note for $10,000 payable on December 31, 2006 for the patent. As of December 31, 2007 the principal amount of the note was repaid and we agreed to write off the accrued interest.
On June 14, 2007, we entered into a “Separation Agreement” with our former Chief Financial Officer. Pursuant to the agreement, we agreed to pay a total of $56,000 as severance subject to payment in full of the outstanding promissory note in the amount of $22,000 and accrued interest.

Note 7 — | Commitments and Contingencies

Pursuant to the terms of our financing agreement entered into on April 11, 2007, we have committed to various 30- day average production thresholds as follows: (1) the equivalent of 180 Barrel of Oil Equivalent Per Day (BOPDE) by December 31, 2007; (2) 182 BOPDE by June 30, 2008; (3) 170 BOPDE by December 31, 2008 (4) 206 BOPDE by June 30, 2009. If we do not meet those thresholds on any of the days we will be required to issue an additional 3,000,000 registered shares to the debenture holders for each period we fail to meet the thresholds. We have met our initial production threshold at December 31, 2007 and we believe that we will meet all remaining production thresholds therefore not incur any penalties.
In the event we are unable to meet one remaining registration requirement (we have already met two of the prior registration requirements in August 2007 and January 2008, respectively), we may have to pay a penalty, ranging from 0.5% to 10%, to the debenture holders.

G-14

#####

EnerJex Resources, Inc.
Notes to Consolidated Financial Statements — (Continued)

Note 8 — | Income Taxes

Deferred income taxes are determined based on the tax effect of items subject to different treatment between book and tax bases. There is approximately $7,438,000 of net operating loss carry-forwards which expire in 2021-2023. The net deferred tax is as follows:

|  | December 31, |
|  | 2007 |
Non-current deferred tax asset : |  |  |  |
Goodwill and oil & gas costs |  | $ | 264,320 |
Loan costs |  |  | (172,178 | )
Net operating loss carry-forward |  |  | 2,231,450 |
Valuation allowance |  |  | (2,323,592 | )
Total deferred tax net |  | $ | — |

A reconciliation of the provision for income taxes to the statutory federal rate for continuing operations for the nine months ended December 31, 2007 is as follows:

|  | December 31, |
|  | 2007 |
Statutory tax rate |  |  | 34.0 | %
Equity based compensation |  |  | (13.0 | )%
Loan cost and other |  |  | 4.0 | %
Change in valuation allowance |  |  | (25.0 | )%
Effective tax rate |  |  | 0.0 | %

Note 9 — | Notes Payable

On September 1, 2007, we entered into a purchase and sales contract between DD Energy and various entities and individuals for the acquisition of oil properties located in eastern Kansas (see note 5) for the total purchase price of $2,700,000. Pursuant to the agreement, we paid cash at closing in the amount of $1,735,000 and entered into promissory notes totaling $965,000. Each promissory note bears interest at a rate of 5% per annum and matures September 1, 2008. Collateral for these notes is DD Energy oil leases.

Note 10 — | Subsequent Events

On January 16, 2008, we granted options to purchase 117,500 shares of our common stock to 3 employees. The options have an exercise price of $1.25 and expire on January 15, 2011.

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

G-15

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EnerJex Resources, Inc.
Notes to Consolidated Financial Statements — (Continued)
administrative expenses, professional, investor relations and interest expense is excluded from this determination.

|  | December 31, |
|  | 2007 |
Production revenues |  | $ | 1,982,119 |
Production costs |  |  | (1,104,272 | )
Depletion and depreciation |  |  | (532,665 | )
Income taxes |  |  | (117,000 | )
Results of operations for producing activities |  | $ | 228,182 |

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:

|  | December 31, |
|  | 2007 |
Proved |  | $ | 9,547,893 |
Unevaluated and unproved |  |  | 74,777 |
Accumulated depreciation and depletion |  |  | (531,727 | )
Net capitalized costs |  | $ | 9,090,943 |

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.
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:

|  | December 31, |
|  | 2007 |
Acquisition of proved and unproved properties |  | $ | 4,560,579 |
Development costs |  |  | 4,376,049 |
Exploration costs |  |  | — |
Total |  | $ | 8,936,628 |

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 (bbl) 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

G-16

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EnerJex Resources, Inc.
Notes to Consolidated Financial Statements — (Continued)
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.

|  | Gas — mcf |  |  | Oil — stb |
Proved reserves: |  |  |  |  |  |  |  |
Balance March 31, 2007 |  |  | — |  |  |  | — |
Revisions of previous estimates |  |  | — |  |  |  | — |
Purchase of minerals in place |  |  | 335,905 |  |  |  | 1,197,653 |
Production |  |  | (9,926 | ) |  |  | (25,674 | )
Balance, December 31, 2007 |  |  | 325,979 |  |  |  | 1,171,979 |

* |  | STB represents Stock Tank Barrels

Proved developed reserves at the end of the period:

Gas-mcf |  |  | Oil stb |
December 31, |  |  | December 31, |
2007 |  |  | 2007 |
| 325,976 |  |  |  | 867,443 |

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. There were no proved reserves at March 31, 2007. The standardized measure of future cash flows as of December 31, 2007 is calculated using a price per Mcf of gas of $5.657 and a price for oil of $84.25 each of which was the price received from our production at December 31, 2007. 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.
There were no proved reserves at March 31, 2007.

|  | December 31, |
|  | 2007 |
Future production revenue |  | $ | 100,583,366 |
Future production costs |  |  | (31,730,228 | )
Future development costs |  |  | (14,245,318 | )
Future cash flows before income taxes |  |  | 54,607,820 |
Future income taxes |  |  | (5,034,403 | )
Future net cash flows |  |  | 49,573,417 |
10% annual discount for estimating of future cash flows |  |  | (23,697,303 | )
Standardized measure of discounted net cash flows |  | $ | 25,876,114 |

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EnerJex Resources, Inc.
Notes to Consolidated Financial Statements — (Continued)
Changes in Standardized Measure of Discounted Future Net Cash Flows

Balance March 31, 2007 |  | $ | — |
Sales, net of production costs |  |  | (877,847 | )
Net change in pricing and production costs |  |  | — |
Net change in future estimated development costs |  |  | — |
Purchase of minerals in place |  |  | 26,753,961 |
Revisions |  |  | — |
Accretion of discount |  |  | — |
Change in income tax |  |  | — |
Balance December 31, 2007 |  | $ | 25,876,114 |

G-18

#####

BLACK OAKS PROJECT LOCATIONS
(At time of Acquisition)
BLACK OAKS PROJECT
(At Completion of Phase 1 Development)

#####

Shares
Common Stock
PROSPECTUS
, 2008
Until , 2008, all dealers that effect transactions in these securities may be required to deliver a prospectus, regardless of whether they are participating in this offering. This is in addition to the dealers’ obligation to deliver a prospectus when acting as underwriters and with respect to their unsold allotments or subscriptions.

#####

PART II
INFORMATION NOT REQUIRED IN PROSPECTUS

Item 13. | Other Expenses of Issuance and Distribution

The following table sets forth all costs and expenses, other than underwriting discounts and commissions, to be paid in connection with the sale of the common stock being registered hereunder, all of which will be paid by us. All of the amounts shown are estimates except for the Securities and Exchange Commission registration fee and the American Stock Exchange application fee.

SEC registration fee |  | $ | 1,100.40 |
American Stock Exchange listing application fee |  |  | * |
Printing expenses |  |  | * |
FINRA filing fee |  | $ | 3,300 |
Legal fees and expenses |  |  | * |
Accounting fees and expenses |  |  | * |
Blue sky fees and expenses |  |  | * |
Transfer Agent fees |  |  | * |
Miscellaneous |  |  | * |
Total |  | $ | * |

* |  | To be filed by amendment

Item 14. | Indemnification of Directors and Officers

None of our directors will have personal liability to us or any of our stockholders for monetary damages for breach of fiduciary duty as a director involving any act or omission of any such director since provisions have been made in our articles of incorporation limiting such liability. The foregoing provisions will not eliminate or limit the liability of a director (i) for any breach of the director’s duty of loyalty to us or our stockholders, (ii) for acts or omissions not in good faith or, which involve intentional misconduct or a knowing violation of law, (iii) under applicable Sections of the Nevada Revised Statutes, (iv) the payment of dividends in violation of Section 78.300 of the Nevada Revised Statutes or, (v) for any transaction from which the director derived an improper personal benefit.
Our bylaws provide for indemnification of the directors, officers, and employees of EnerJex Resources, Inc. in most cases for any liability suffered by them or arising out of their activities as directors, officers, and employees of EnerJex Resources, Inc. if they were not engaged in willful misfeasance or malfeasance in the performance of his or her duties; provided that in the event of a settlement the indemnification will apply only when the board of directors approves such settlement and reimbursement as being for the best interests of the corporation. The Bylaws, therefore, limit the liability of directors to the maximum extent permitted by Nevada law (Section 78.751).
Our officers and directors are accountable to us as fiduciaries, which means they are required to exercise good faith and fairness in all dealings affecting us. In the event that a stockholder believes the officers and/or directors have violated their fiduciary duties to us, the stockholder may, subject to applicable rules of civil procedure, be able to bring a class action or derivative suit to enforce the stockholder’s rights, including rights under certain federal and state securities laws and regulations to recover damages from and require an accounting by management. Stockholders who have suffered losses in connection with the purchase or sale of their interest in EnerJex Resources, Inc. in connection with such sale or purchase, including the misapplication by any such officer or director of the proceeds from the sale of these securities, may be able to recover such losses from us.

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Item 15. | Recent Sales of Unregistered Securities

The following is a summary of transactions by us from March 31, 2005 through the date of this registration statement involving sales of our securities that were not registered under the Securities Act. Each offer and sale was made in reliance on Section 4(2) of the Securities Act, Regulation D promulgated under Section 4(2) of the Securities Act, or Rule 701 promulgated under Section 3(b) of the Securities Act, as transactions by an issuer not involving any public offering or transactions pursuant to compensatory benefit plans and contracts relating to compensation as provided under Rule 701. The purchasers were “accredited investors,” officers, directors or employees of the registrant or known to the registrant and its management through pre-existing business relationships, friends and employees. All purchasers were provided access to all material information which they requested, and all information necessary to verify such information and was afforded access to management of the registrant in connection with their purchases. All holders of the unregistered securities acquired such securities for investment and not with a view toward distribution, acknowledging such intent to the registrant. All certificates or agreements representing such securities that were issued contained restrictive legends, prohibiting further transfer of the certificates or agreements representing such securities, without such securities either being first registered or otherwise exempt from registration under the Securities Act, in any further resale or disposition.
On July 25, 2006, we issued 31,565 shares of our restricted common stock to Paul Branagan (our former sole officer), pursuant to his conversion of $40,000 of liabilities owed to him by us. We believe that the issuance of the shares was exempt from the registration and prospectus delivery requirements of the Securities Act of 1933 by virtue of Section 4(2).
Effective August 15, 2006, we instituted a 1 for 253.45 reverse split of our outstanding shares of common stock pursuant to our merger with EnerJex Kansas completed on August 15, 2006.
On August 15, 2006, we agreed to issue 2,366,600 shares of our restricted common stock to the stockholders of EnerJex Kansas pursuant to the merger (shares were issued on September 7, 2006). We believe that the issuance and sale of the shares was exempt from the registration and prospectus delivery requirements of the Securities Act of 1933 by virtue of Section 4(2) and Regulation D, Rule 506.
On August 16, 2006, we granted 60,000 stock options to Todd Bart in consideration of his services as Chief Financial Officer. 20,000 options were to vest each year on the date of the anniversary of the agreement. Pursuant to the June 14, 2007 Separation Agreement we entered into with Mr. Bart, we vested his 60,000 options and he had until September 13, 2007 to exercise the options. The options expired without exercise. We believe that the grant of the options was exempt from the registration and prospectus delivery requirements of the Securities Act of 1933 by virtue of Section 4(2).
On October 24, 2006, we issued 3,000 shares of our restricted common stock to William Stoeckinger for his assistance in the assessment of well data and geology. We believe that the issuance of the shares was exempt from the registration and prospectus delivery requirements of the Securities Act of 1933 by virtue of Section 4(2).
On October 26, 2006, we issued 40,000 shares of our restricted common stock to Stoecklein Law Group for professional legal services provided to us. We believe that the issuance of the shares was exempt from the registration and prospectus delivery requirements of the Securities Act of 1933 by virtue of Section 4(2).
On October 26, 2006, we issued 68,000 shares of our restricted common stock to Paul Branagan pursuant to his agreement to convert all of the liabilities owed to him by us into shares of our common stock. We believe that the issuance of the shares was exempt from the registration and prospectus delivery requirements of the Securities Act of 1933 by virtue of Section 4(2).
On October 26, 2006, we issued 34,000 shares of our restricted common stock to 3GC Ltd. pursuant to its agreement to convert all of the liabilities owed to 3GC Ltd. by us into shares of our common stock. We believe that the issuance of the shares was exempt from the registration and prospectus delivery requirements of the Securities Act of 1933 by virtue of Section 4(2).

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On December 12, 2006, we agreed to issue 64,000 shares of our restricted common stock to MorMeg, LLC pursuant to the Amendment No. 1 to the Letter Agreement dated December 12, 2006 (shares were issued on February 27, 2007). We believe that the issuance of the shares was exempt from the registration and prospectus delivery requirements of the Securities Act of 1933 by virtue of Section 4(2).
Pursuant to the debentures and the Financing Agreements related thereto, on April 11, 2007, the lenders funded $6,300,000, and concurrent with First Closing, we issued 1,260,000 shares of restricted common stock to six accredited investors on April 13, 2007. Pursuant to the terms of the Securities Purchase Agreement, the lenders funded an additional $2,700,000 at the second closing on June 21, 2007 and we issued an additional 540,000 shares of restricted common stock on June 26, 2007.
Additionally, in the event EnerJex Kansas does not meet certain production thresholds, we must issue to the lenders up to an additional 1,800,000 shares of common stock or warrants to purchase shares of common stock.
Additionally, we issued a warrant to purchase 75,000 shares of our common stock to C.K. Cooper as a private placement fee on April 12, 2007 in connection with the placement of the debentures. The warrant has an exercise price of $3.00 per share and expires on April 11, 2010.
We believe that the issuance and sale of the securities (debentures, common stock and common stock purchase warrants) and the issuance of warrants to C.K. Cooper were exempt from the registration and prospectus delivery requirements of the Securities Act of 1933 by virtue of Section 4(2) and Regulation D Rule 506.
On May 4, 2007, the Governance, Compensation and Nominating Committee agreed to compensate the Audit Committee Chairman, Daran Dammeyer, $2,500 per month in cash and $1,000 per month in shares of our common stock. Additionally, it was agreed that Mr. Dammeyer will be issued the first twelve months of the stock compensation, 1,920 shares, immediately (the 1,920 shares were issued to Mr. Dammeyer on June 1, 2007).
In addition, the Governance, Compensation and Nominating Committee agreed to grant the following options to the following persons:

|  |  |  |  |  |  |  |  |  |  | Option |
Person Issued to |  | No. of options |  |  | Exercise Price |  |  | Term |  |  | Plan |
C. Stephen Cochennet, CEO |  |  | 200,000 |  |  | $ | 6.25 |  |  |  | 4 Years |  |  |  | 2000 |
Daran G. Dammeyer, Director |  |  | 40,000 |  |  | $ | 6.25 |  |  |  | 4 Years |  |  |  | 2002/2003 |
Robert G. Wonish, Director |  |  | 40,000 |  |  | $ | 6.25 |  |  |  | 4 Years |  |  |  | 2002/2003 |
Darrel G. Palmer, Director |  |  | 40,000 |  |  | $ | 6.25 |  |  |  | 4 Years |  |  |  | 2002/2003 |
Mark Haas, Service provider |  |  | 60,000 |  |  | $ | 6.25 |  |  |  | 4 Years |  |  |  | 2002/2003 |
Brad Kramer, Employee |  |  | 15,000 |  |  | $ | 6.25 |  |  |  | 4 Years |  |  |  | 2002/2003 |
Maureen Elton, Employee |  |  | 10,000 |  |  | $ | 6.25 |  |  |  | 4 Years |  |  |  | 2002/2003 |
Total: |  |  | 405,000 |  |  |  |  |  |  |  |  |  |  |  |  |

We believe that the above disclosed issuance of shares and grant of options were exempt from the registration and prospectus delivery requirements of the Securities Act of 1933 by virtue of Section 4(2).
On May 22, 2007, we issued 3,000 shares of our restricted common stock to P & R Oil Field Services for oil field services. We believe that the issuance of the shares was exempt from the registration and prospectus delivery requirements of the Securities Act of 1933 by virtue of Section 4(2).
On August 1, 2007, we granted Dierdre P. Jones, Director of Finance and Accounting of the Company, an option to purchase 20,000 shares of our restricted common stock at $7.50 per share for a period of four years expiring on July 31, 2011. We believe that the issuance of the shares was exempt from the registration and prospectus delivery requirements of the Securities Act of 1933 by virtue of Section 4(2).

II-3

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On November 1, 2007, we granted Jay Schendel, Field Operations Supervisor of the Company, an option to purchase 10,000 shares of our restricted common stock at $6.25 per share for a period of four years expiring on October 31, 2011. We believe that the issuance of the shares was exempt from the registration and prospectus delivery requirements of the Securities Act of 1933 by virtue of Section 4(2).
On January 16, 2008, we granted 23,500 options to purchase shares of our common stock to three employees. The options are exercisable until January 15, 2011 at a per share price of $6.25. Each option was fully vested upon grant. We believe that the option grants were exempt from the registration and prospectus delivery requirements of the Securities Act of 1933 by virtue of Section 4(2).
On May 15, 2008, we issued 2,182 shares of our common stock to Daran Dammeyer as compensation for his services as Audit Committee Chairman for fiscal 2009. We believe that the issuance of the shares was exempt from the registration and prospectus delivery requirements of the Securities Act of 1933 by virtue of Section 4(2).

Item 16. | Exhibits and Financial Statement Schedules

(a) Exhibits

Exhibit No. |  | Description
| 1 | .1* |  | Form of Underwriting Agreement
| 2 | .1 |  | Agreement and Plan of Merger between Millennium Plastics Corporation and Midwest Energy, Inc. effective August 15, 2006 (incorporated by reference to Exhibit 2.3 to the Form 8-K filed on August 16, 2006)
| 3 | .1 |  | Amended and Restated Articles of Incorporation, as currently in effect
| 3 | .2 |  | Amended and Restated Bylaws, as currently in effect (incorporated by reference to Exhibit 3.3 to the Form SB-2 filed on February 23, 2001)
| 4 | .1 |  | Article VI of Amended and Restated Articles of Incorporation of Millennium Plastics Corporation (incorporated by reference to Exhibit 1.3 to the Form 8-K filed on December 6, 1999)
| 4 | .2 |  | Article II and Article VIII, Sections 3 & 6 of Amended and Restated Bylaws of Millennium Plastics Corporation (incorporated by reference to Exhibit 4.1 to the Form SB-2 filed on February 23, 2001)
| 4 | .3 |  | Specimen common stock certificate
| 5 | .1* |  | Opinion of Husch Blackwell Sanders LLP
| 10 | .1 |  | Letter Agreement with MorMeg, LLC dated September 26, 2006 (incorporated by reference to Exhibit 10.9 to the Form 8-K filed on October 13, 2006)
| 10 | .2 |  | Amendment No. 1 to Letter Agreement with MorMeg, LLC dated December 12, 2006 (incorporated by reference to Exhibit 10.10 to the Form 8-K filed on January 8, 2007)
| 10 | .3 |  | Debenture Securities Purchase Agreement dated April 11, 2007 (incorporated by reference to Exhibit 10.11 to the Form 8-K filed on April 16, 2007)
| 10 | .4 |  | Debenture Registration Rights Agreement dated April 11, 2007 (incorporated by reference to Exhibit 10.12 to the Form 8-K filed on April 16, 2007)
| 10 | .5 |  | Senior Secured Debenture — ($3,500,000) West Coast Opportunity Fund, LLC dated April 11, 2007 (incorporated by reference to Exhibit 10.13 to the Form 8-K filed on April 16, 2007)
| 10 | .6 |  | Senior Secured Debenture — ($700,000) DKR Soundshore Oasis Holding Fund Ltd. dated April 11, 2007 (incorporated by reference to Exhibit 10.14 to the Form 8-K filed on April 16, 2007)
| 10 | .7 |  | Senior Secured Debenture — ($1,050,000) Enable Growth Partners, LP dated April 11, 2007 (incorporated by reference to Exhibit 10.15 to the Form 8-K filed on April 16, 2007)
| 10 | .8 |  | Senior Secured Debenture — ($350,000) Enable Opportunity Partners LP dated April 11, 2007 (incorporated by reference to Exhibit 10.16 to the Form 8-K filed on April 16, 2007)
| 10 | .9 |  | Senior Secured Debenture — ($350,000) Glacier Partners LP dated April 11, 2007 (incorporated by reference to Exhibit 10.17 to the Form 8-K filed on April 16, 2007)

II-4

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Exhibit No. |  | Description
| 10 | .10 |  | Senior Secured Debenture — ($350,000) Frey Living Trust dated April 11, 2007 (incorporated by reference to Exhibit 10.18 to the Form 8-K filed on April 16, 2007)
| 10 | .11 |  | Debenture Secured Guaranty dated April 11, 2007 (incorporated by reference to Exhibit 10.19 to the Form 8-K filed on April 16, 2007)
| 10 | .12 |  | Debenture Pledge and Security Agreement dated April 11, 2007 (incorporated by reference to Exhibit 10.20 to the Form 8-K filed on April 16, 2007)
| 10 | .13 |  | Joint Exploration Agreement with MorMeg, LLC dated March 30, 2007 (incorporated by reference to Exhibit 10.21 to the Form 8-K filed on April 16, 2007)
| 10 | .14 |  | Purchase and Sale Agreement with MorMeg, LLC dated April 18, 2007 (incorporated by reference to Exhibit 10.22 to the Form 8-K filed on May 2, 2007)
| 10 | .15† |  | 2000-2001 Stock Option Plan (incorporated by reference to Exhibit 99.2 to the Form 10-QSB filed on February 14, 2001)
| 10 | .16† |  | Amended and Restated 2002/2003 Stock Option Plan (incorporated by reference to Exhibit 10.23 to the Form 8-K filed on May 11, 2007)
| 10 | .17 |  | Senior Secured Debenture dated June 21, 2007 — ($1,500,000)West Coast Opportunity Fund, LLC (incorporated by reference to Exhibit 10.24 to the Form 8-K filed on June 25, 2007)
| 10 | .18 |  | Senior Secured Debenture — ($300,000) DKR Soundshore Oasis Holding Fund Ltd. dated June 21, 2007 (incorporated by reference to Exhibit 10.25 to the Form 8-K filed on June 25, 2007)
| 10 | .19 |  | Senior Secured Debenture — ($450,000) Enable Growth Partners LP dated June 21, 2007 (incorporated by reference to Exhibit 10.26 to the Form 8-K filed on June 25, 2007)
| 10 | .20 |  | Senior Secured Debenture — ($150,000) Enable Opportunity Partners LP dated June 21, 2007 (incorporated by reference to Exhibit 10.27 to the Form 8-K filed on June 25, 2007)
| 10 | .21 |  | Senior Secured Debenture — ($150,000) Glacier Partners LP dated June 21, 2007 (incorporated by reference to Exhibit 10.28 to the Form 8-K filed on June 25, 2007)
| 10 | .22 |  | Senior Secured Debenture — ($150,000) Frey Living Trust dated June 21, 2007 (incorporated by reference to Exhibit 10.29 to the Form 8-K filed on June 25, 2007)
| 10 | .23 |  | Debenture Mortgage, Security Agreement and Assignment of Production dated June 21, 2007 (incorporated by reference to Exhibit 10.30 to the Form 8-K filed on June 25, 2007)
| 10 | .24 |  | Separation Agreement with Todd Bart dated June 14, 2007 (incorporated by reference to Exhibit 10.31 to the Form 8-K filed on June 29, 2007)
| 10 | .25 |  | Amended and Restated Well Development Agreement and Option for Gas City Project dated August 10, 2007 (incorporated by reference to Exhibit 10.31 to the Form 10-QSB filed on August 17, 2007)
| 10 | .26 |  | Purchase and Sale Contract for Tri-County Project dated September 27, 2007 (incorporated by reference to Exhibit 10.1 to the Form 8-K filed on October 2, 2007)
| 10 | .27 |  | Purchase and Sale Contract DD Energy Project dated September 14, 2007 (incorporated by reference to Exhibit 10.33 to the Form 10-QSB filed on November 14, 2007)
| 10 | .28 |  | Amendment No. 1 to Well Development Agreement and Option for Gas City Project dated December 10, 2007 (incorporated by reference to Exhibit 10.35 to the Form 8-K filed on December 20, 2007)
| 10 | .29 |  | Debenture Holder Amendment Letter dated December 10, 2007 (incorporated by reference to Exhibit 10.36 to the Form 8-K filed on December 20, 2007)
| 10 | .30 |  | Amendment No. 2 to Joint Exploration Agreement with MorMeg, LLC dated March 20, 2008 (incorporated by reference to Exhibit 10.1 to the Form 8-K filed on March 24, 2008)
| 10 | .31 |  | Debenture Holder Consent and Waiver Agreement dated April 9, 2008 (incorporated by reference to Exhibit 10.1 to the Form 8-K filed on April 15, 2008)
| 10 | .32 |  | Agreement with Shell Trading (US) Company dated March 6, 2008 (1)
| 21 | .1 |  | List of Subsidiaries
| 23 | .1 |  | Consent of Weaver & Martin, LLC

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Exhibit No. |  | Description
| 23 | .2* |  | Consent of Husch Blackwell Sanders LLP (included in Exhibit 5.1)
| 23 | .3** |  | Consent of McCune Engineering, P.E.

* |  | To be filed by amendment.

** |  | Previously filed.

† |  | Indicates management contract or compensatory plan or arrangement.

(1) |  | Portions of this exhibit are omitted and were filed separately with the Secretary of the SEC pursuant to EnerJex application requesting confidential treatment under Rule 24b-2 of the Securities Exchange Act of 1934.

(b) Financial Statement Schedules
All schedules have been omitted because the information required to be presented in them is not applicable or is shown in the financial statements or related notes.

Item 17. | Undertakings.

Insofar as indemnification for liabilities arising under the Securities Act of 1933 (the Act”) may be permitted to directors, officers and controlling persons of the small business issuer pursuant to the foregoing provisions, or otherwise, the small business issuer has been advised that in the opinion of the Securities and Exchange Commission such indemnification is against public policy as expressed in the Act and is, therefore, unenforceable. In the event that a claim for indemnification against such liabilities (other than the payment by the small business issuer of expenses incurred or paid by a director, officer or controlling person of the small business issuer in the successful defense of any action, suit or proceeding) is asserted by such director, officer or controlling person in connection with the securities being registered, the small business issuer will, unless in the opinion of its counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction the question whether such indemnification by it is against public policy as expressed in the Securities Act.
The undersigned registrant hereby undertakes that:
1. For purposes of determining any liability under the Securities Act of 1933, the information omitted from the form of prospectus filed as part of this registration statement in reliance upon Rule 430A and contained in a form of prospectus filed by the registrant pursuant to Rule 424(b)(1) or (4) or 497(h) under the Securities Act shall be deemed to be part of this registration statement as of the time it was declared effective.
2. For the purpose of determining any liability under the Securities Act of 1933, each post-effective amendment that contains a form of prospectus shall be deemed to be a new registration statement relating to the securities offered therein, and the offering of such securities at that time shall be deemed to be the initial bona fide offering thereof.

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SIGNATURES
Pursuant to the requirements of the Securities Act of 1933, as amended, the registrant has duly caused this Amendment to the Registration Statement to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Overland Park, State of Kansas, on the 23rd day of May, 2008.
ENERJEX RESOURCES, INC.

| By: | /s/ C. Stephen Cochennet

C. Stephen Cochennet
President and Chief Executive Officer
Pursuant to the requirements of the Securities Act of 1933, as amended, this Amendment to the Registration Statement has been signed by the following persons in the capacities and on the dates indicated.

Signature |  | Title |  | Date
/s/ C. Stephen Cochennet C. Stephen Cochennet |  | President, Chief Executive Officer, (Principal Executive Officer), Chief Financial Officer (Principal Financial and Accounting Officer), Chairman |  | May 23, 2008
/s/ Robert G. Wonish Robert G. Wonish |  | Director |  | May 23, 2008
/s/ Daran G. Dammeyer Daran G. Dammeyer |  | Director |  | May 23, 2008
/s/ Darrel G. Palmer Darrel G. Palmer |  | Director |  | May 23, 2008
Dr. James W. Rector |  | Director |  | May , 2008

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EXHIBIT INDEX

Exhibit No. |  | Description
| 1 | .1* |  | Form of Underwriting Agreement
| 2 | .1 |  | Agreement and Plan of Merger between Millennium Plastics Corporation and Midwest Energy, Inc. effective August 15, 2006 (incorporated by reference to Exhibit 2.3 to the Form 8-K filed on August 16, 2006)
| 3 | .1 |  | Amended and Restated Articles of Incorporation, as currently in effect
| 3 | .2 |  | Amended and Restated Bylaws, as currently in effect (incorporated by reference to Exhibit 3.3 to the Form SB-2 filed on February 23, 2001)
| 4 | .1 |  | Article VI of Amended and Restated Articles of Incorporation of Millennium Plastics Corporation (incorporated by reference to Exhibit 1.3 to the Form 8-K filed on December 6, 1999)
| 4 | .2 |  | Article II and Article VIII, Sections 3 & 6 of Amended and Restated Bylaws of Millennium Plastics Corporation (incorporated by reference to Exhibit 4.1 to the Form SB-2 filed on February 23, 2001)
| 4 | .3 |  | Specimen common stock certificate
| 5 | .1* |  | Opinion of Husch Blackwell Sanders LLP
| 10 | .1 |  | Letter Agreement with MorMeg, LLC dated September 26, 2006 (incorporated by reference to Exhibit 10.9 to the Form 8-K filed on October 13, 2006)
| 10 | .2 |  | Amendment No. 1 to Letter Agreement with MorMeg, LLC dated December 12, 2006 (incorporated by reference to Exhibit 10.10 to the Form 8-K filed on January 8, 2007)
| 10 | .3 |  | Debenture Securities Purchase Agreement dated April 11, 2007 (incorporated by reference to Exhibit 10.11 to the Form 8-K filed on April 16, 2007)
| 10 | .4 |  | Debenture Registration Rights Agreement dated April 11, 2007 (incorporated by reference to Exhibit 10.12 to the Form 8-K filed on April 16, 2007)
| 10 | .5 |  | Senior Secured Debenture — ($3,500,000) West Coast Opportunity Fund, LLC dated April 11, 2007 (incorporated by reference to Exhibit 10.13 to the Form 8-K filed on April 16, 2007)
| 10 | .6 |  | Senior Secured Debenture — ($700,000) DKR Soundshore Oasis Holding Fund Ltd. dated April 11, 2007 (incorporated by reference to Exhibit 10.14 to the Form 8-K filed on April 16, 2007)
| 10 | .7 |  | Senior Secured Debenture — ($1,050,000) Enable Growth Partners, LP dated April 11, 2007 (incorporated by reference to Exhibit 10.15 to the Form 8-K filed on April 16, 2007)
| 10 | .8 |  | Senior Secured Debenture — ($350,000) Enable Opportunity Partners LP dated April 11, 2007 (incorporated by reference to Exhibit 10.16 to the Form 8-K filed on April 16, 2007)
| 10 | .9 |  | Senior Secured Debenture — ($350,000) Glacier Partners LP dated April 11, 2007 (incorporated by reference to Exhibit 10.17 to the Form 8-K filed on April 16, 2007)
| 10 | .10 |  | Senior Secured Debenture — ($350,000) Frey Living Trust dated April 11, 2007 (incorporated by reference to Exhibit 10.18 to the Form 8-K filed on April 16, 2007)
| 10 | .11 |  | Debenture Secured Guaranty dated April 11, 2007 (incorporated by reference to Exhibit 10.19 to the Form 8-K filed on April 16, 2007)
| 10 | .12 |  | Debenture Pledge and Security Agreement dated April 11, 2007 (incorporated by reference to Exhibit 10.20 to the Form 8-K filed on April 16, 2007)
| 10 | .13 |  | Joint Exploration Agreement with MorMeg, LLC dated March 30, 2007 (incorporated by reference to Exhibit 10.21 to the Form 8-K filed on April 16, 2007)
| 10 | .14 |  | Purchase and Sale Agreement with MorMeg, LLC dated April 18, 2007 (incorporated by reference to Exhibit 10.22 to the Form 8-K filed on May 2, 2007)
| 10 | .15† |  | 2000-2001 Stock Option Plan (incorporated by reference to Exhibit 99.2 to the Form 10-QSB filed on February 14, 2001)
| 10 | .16† |  | Amended and Restated 2002/2003 Stock Option Plan (incorporated by reference to Exhibit 10.23 to the Form 8-K filed on May 11, 2007)
| 10 | .17 |  | Senior Secured Debenture dated June 21, 2007 — ($1,500,000)West Coast Opportunity Fund, LLC (incorporated by reference to Exhibit 10.24 to the Form 8-K filed on June 25, 2007)

#####

Exhibit No. |  | Description
| 10 | .18 |  | Senior Secured Debenture — ($300,000) DKR Soundshore Oasis Holding Fund Ltd. dated June 21, 2007 (incorporated by reference to Exhibit 10.25 to the Form 8-K filed on June 25, 2007)
| 10 | .19 |  | Senior Secured Debenture — ($450,000) Enable Growth Partners LP dated June 21, 2007 (incorporated by reference to Exhibit 10.26 to the Form 8-K filed on June 25, 2007)
| 10 | .20 |  | Senior Secured Debenture — ($150,000) Enable Opportunity Partners LP dated June 21, 2007 (incorporated by reference to Exhibit 10.27 to the Form 8-K filed on June 25, 2007)
| 10 | .21 |  | Senior Secured Debenture — ($150,000) Glacier Partners LP dated June 21, 2007 (incorporated by reference to Exhibit 10.28 to the Form 8-K filed on June 25, 2007)
| 10 | .22 |  | Senior Secured Debenture — ($150,000) Frey Living Trust dated June 21, 2007 (incorporated by reference to Exhibit 10.29 to the Form 8-K filed on June 25, 2007)
| 10 | .23 |  | Debenture Mortgage, Security Agreement and Assignment of Production dated June 21, 2007 (incorporated by reference to Exhibit 10.30 to the Form 8-K filed on June 25, 2007)
| 10 | .24 |  | Separation Agreement with Todd Bart dated June 14, 2007 (incorporated by reference to Exhibit 10.31 to the Form 8-K filed on June 29, 2007)
| 10 | .25 |  | Amended and Restated Well Development Agreement and Option for Gas City Project dated August 10, 2007 (incorporated by reference to Exhibit 10.31 to the Form 10-QSB filed on August 17, 2007)
| 10 | .26 |  | Purchase and Sale Contract for Tri-County Project dated September 27, 2007 (incorporated by reference to Exhibit 10.1 to the Form 8-K filed on October 2, 2007)
| 10 | .27 |  | Purchase and Sale Contract DD Energy Project dated September 14, 2007 (incorporated by reference to Exhibit 10.33 to the Form 10-QSB filed on November 14, 2007)
| 10 | .28 |  | Amendment No. 1 to Well Development Agreement and Option for Gas City Project dated December 10, 2007 (incorporated by reference to Exhibit 10.35 to the Form 8-K filed on December 20, 2007)
| 10 | .29 |  | Debenture Holder Amendment Letter dated December 10, 2007 (incorporated by reference to Exhibit 10.36 to the Form 8-K filed on December 20, 2007)
| 10 | .30 |  | Amendment No. 2 to Joint Exploration Agreement with MorMeg, LLC dated March 20, 2008 (incorporated by reference to Exhibit 10.1 to the Form 8-K filed on March 24, 2008)
| 10 | .31 |  | Debenture Holder Consent and Waiver Agreement dated April 9, 2008 (incorporated by reference to Exhibit 10.1 to the Form 8-K filed on April 15, 2008)
| 10 | .32 |  | Agreement with Shell Trading (US) Company dated March 6, 2008(1)
| 21 | .1 |  | List of Subsidiaries
| 23 | .1 |  | Consent of Weaver & Martin, LLC
| 23 | .2* |  | Consent of Husch Blackwell Sanders LLP (included in Exhibit 5.1)
| 23 | .3** |  | Consent of McCune Engineering, P.E.

* |  | To be filed by amendment.

** |  | Previously filed.

† |  | Indicates management contract or compensatory plan or arrangement.

(1) |  | Portions of this exhibit are omitted and were filed separately with the Secretary of the SEC pursuant to EnerJex application requesting confidential treatment under Rule 24b-2 of the Securities Exchange Act of 1934.