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

 

 

7300 W. 110 ^th , 7 ^th 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. 110 ^th , 7 ^th Floor

Overland Park, Kansas 66210

(913) 693-4600

(Name, address, including zip code, and telephone number,

including area code, of agent for service)

 

 

 

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):

 

 

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.

 

 

TABLE OF CONTENTS

 

 

 

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.

 

SUMMARY

										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.

	•	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.

	•	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.

	•	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.

	•	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.

	•	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.

	•	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.

	•	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.

	•	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.

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.

	•	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.

														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	)

(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.

 

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:

 

 

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.

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:

 

 

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

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:

 

 

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

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:

 

 

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:

 

 

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

operational risks. We do not carry business interruption insurance at levels that would provide enough funds for us to continue operating without access to other funds. For some risks, we may not obtain insurance if we believe the cost of available insurance is excessive relative to the risks presented. In addition, pollution and environmental risks generally are not fully insurable. If a significant accident or other event occurs and is not fully covered by insurance, it could impact our operations enough to force us to cease our operations.

 

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

 

Developing and exploring for natural gas and oil involves a high degree of operational and financial risk, which precludes definitive statements as to the time required and costs involved in reaching certain objectives. The budgeted costs of drilling, completing and operating wells are often exceeded and can increase significantly when drilling costs rise due to a tightening in the supply of various types of oilfield equipment and related services. Drilling may be unsuccessful for many reasons, including geological conditions, weather, cost overruns, equipment shortages and mechanical difficulties. Moreover, the successful drilling of a natural gas or oil well does not ensure a profit on investment. Exploratory wells bear a much greater risk of loss than development wells. 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:

 

 

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:

 

 

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:

 

 

 

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.

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

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:

 

 

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

 

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

 

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

 

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

 

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

 

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

 

Although our natural gas sales activities are not currently projected to be subject to rate regulation by FERC, if FERC finds that in connection with making sales in the future, we (i) failed to comply with any applicable FERC administered statutes, rules, regulations or orders, (ii) engaged in certain fraudulent acts, or (iii) engaged in market manipulation, we could be subject to substantial penalties and fines of up to $1,000,000 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.

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

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:

 

 

 

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

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.

 

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:

 

 

You should not place undue reliance on any forward-looking statement, each of which applies only as of the date of this prospectus. Before you invest in our common stock, you should be aware that the occurrence of the events described in the section entitled “Risk Factors” and elsewhere in this prospectus could negatively affect our business, operating results, financial condition and stock price. Except as required by law, we undertake no obligation to update or revise publicly any of the forward-looking statements after the date of this prospectus to conform our statements to actual results or changed expectations.

USE OF PROCEEDS

 

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:

 

 

 

 

 

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.

 

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:

 

 

 

 

 

The information in the table above excludes:

 

 

 

 

 

The information in the table above:

 

 

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:

 

 

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.

 

 

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.

 

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.

 

 

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.

 

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.

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.

 

 

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.

 

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

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.

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

 

 

 

 

 

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:

 

 

 

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

 

 

 

 

 

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.

 

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.

 

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.

 

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.

 

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

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.

 

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:

 

 

 

 

 

 

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:

 

 

 

 

 

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:

 

 

 

 

 

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.

 

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:

 

 

 

 

 

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: