PART I

Items 1 and 2. Business and Properties.

Company History

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

Our Business

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

From the beginning of fiscal 2008 through the end of fiscal 2010, we deployed approximately $12 million in capital resources to acquire and develop five operating projects and drill 179 new wells (111 producing wells and 65 water injection wells and 3 dry holes). As a result, our estimated total net proved oil reserves at March 31, 2010 was approximately 2.5 million barrels of oil equivalent, or BOE. Of the 2.5 million BOE of total proved reserves, approximately 30% are proved developed and approximately 70% are proved undeveloped. The proved developed reserves consist of 79% proved developed producing reserves and 21% proved developed non-producing reserves.

The total proved PV10 (present value) of our reserves (“PV10”) as of March 31, 2010 was approximately $29.9 million. PV10 means the estimated future gross revenue to be generated from the production of proved reserves, net of estimated production and future development and abandonment costs, using prices and costs in effect at the determination date, before income taxes, and without giving effect to non-property related expenses, discounted to a present value using an annual discount rate of 10% in accordance with the guidelines of the SEC. PV10 is a non-GAAP financial measure and generally differs from the standardized measure of discounted future net cash flows, the most directly comparable GAAP financial measure, because it does not include the effects of income taxes on future net revenues. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations-Reserves” page 51, for a reconciliation to the comparable GAAP financial measure.

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

The Opportunity in Kansas

According to the Kansas Geological Survey, the State of Kansas has historically been one of the top 10 domestic oil producing regions in the United States. For the years ended December 31, 2009 and 2008, 39.5 million barrels and 39.7 million barrels of oil were produced in Kansas. Of the total barrels produced in Kansas in the calendar year ended December 2009, 20 companies accounted for approximately 35% of the total production, with the remaining 65% produced by over 3,600 active producers.

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

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

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

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

Our Properties

The table below summarizes our acreage by project name as of March 31, 2010.

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

(1)

Net acreage is based on our net working interest as of March 31, 2010.

Black Oaks Project

On April 9, 2007, we entered into a “Joint Exploration Agreement” with a shareholder, MorMeg, LLC, (MorMeg), controlled by Mark Haas, our chief operating officer and a director, whereby we agreed to advance $4.0 million to a joint operating account for further development of MorMeg’s Black Oaks leaseholds in exchange for a 95% working interest in the Black Oaks Project. The Black Oaks Project encompasses approximately 2,400 gross acres in Woodson and Greenwood Counties, Kansas, which at the time of acquisition had approximately 35 oil wells producing an average of approximately 32 barrels of oil per day, or BOPD.

The Black Oaks Project is a primary and enhanced secondary recovery project between us and MorMeg. Phase I of the Black Oaks Project development plan commenced shortly after closing with the drilling of 44 in-fill wells. During fiscal 2008, we began injecting water into the first five water injection wells at an average rate of approximately 50 barrels of water per day per well. This pilot program was expanded so that by June 2008, we were injecting approximately 200 barrels of water per day (bbls water/day) per well in the initial 5 injection wells. Adjacent oil wells showed increased production from an average of approximately 5 BOPD to 25 BOPD. As of March 31, 2010, we are maintaining the 200 bbls water/day average on the injection wells in the pilot program area. We have seen no additional response on this area as of yet. We are also injecting an average of 100 bbls water/day per well in 4 injection wells adjacent to the pilot program area and are closely monitoring data and activities for any resulting increase in production. Based upon the results of our testing, we expect to continue the development plan, subject to availability of capital. Phase II of the plan contemplates drilling over 25 additional water injection wells and drilling over 20 additional producer wells. Project-wide production was an average of approximately 96 BOPD as of March 31, 2010.

We will maintain our 95% working interest until “payout”, at which time the MorMeg 5% carried working interest will be converted to a 30% working interest and our working interest becomes 70%. Payout is generally the point in time when the total cumulative revenue from the project equals all of the project’s development expenditures and costs associated with funding. Pursuant to amendments to the Joint Exploration Agreement, we have until August 1, 2010 to contribute one million dollars in additional capital toward the Black Oaks Project development. In addition, we are generally required to provide additional one million dollar capital contributions every sixty days, or upon full deployment of the prior capital contribution, until the Black Oaks Project is completed. If we elect not or cannot, contribute further capital to the Black Oaks Project as discussed above prior to the project’s full development while it is economically viable to do so, MorMeg has the option to cease further joint development and we will receive an undivided interest in the Black Oaks Project. The extension will have no force and effect, however, upon a material default by EnerJex under the Texas Capital Bank Credit Facility. The undivided interest will be the proportionate amount equal to the amount that our investment bears to our investment plus $2.0 million, with MorMeg receiving an undivided interest in what remains.

As of March 31, 2010 (Restated), we had proved oil reserves on Phase I of this project of:

	Gross STB(1)		Net STB(2)		PV10(3) (before tax)
Proved, Developed Producing		439,190		284,320	$	5,546,790
Proved, Developed Non-Producing		52,330		35,650	$	1,044,890
Proved, Undeveloped		1,648,740		1,024,390	$	9,842,530
Total Proved		2,140,260		1,344,360	$	16,434,210

(1)

STB = one stock-tank barrel.

(2)

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

(3)

See “Glossary” on page 21 for our definition of PV10 and “Management’s Discussion and Analysis of Financial Condition and Results of Operations-Reserves” page 51, for a reconciliation to the comparable GAAP financial measure.

Thoren Project

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

Through March 31, 2010, we have invested approximately $800,000 for the development of this project and as of March 31, 2010, we had 32 oil wells producing an average of approximately 38 BOPD; along with 16 water injection wells and one water supply well.

As of March 31, 2010 (Restated), we had proved oil reserves on this project of:

	Gross STB(1)		Net STB(2)		PV10(3) (before tax)
Proved, Developed Producing		57,400		36,670	$	869,570
Proved, Developed Non-Producing		31,180		19,840	$	509,800
Proved, Undeveloped		73,330		55,860	$	155,310
Total Proved		161,910		112,370	$	1,534,680

(1)

STB = one stock-tank barrel.

(2)

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

(3)

We will maintain our 100% working interest until “payout” and our working interest will become 75%, at which time the working interest will be converted to a 25% working interest. Payout for this project occurs at that point in time when the total cumulative revenue from production equals the total amount of the purchase price, all costs and expenses incurred by us in the development and operation, and loan and interest costs incurred in the finance and funding of the purchase. We anticipate the conversion of our working interest to occur in fiscal 2011.

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

DD Energy Project

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

In addition, we have acquired additional leases bringing the total acreage for this project to approximately 1,700 acres. As of March 31, 2010, we had 110 oil wells, 41 water injection wells and 2 water supply wells on this project with production averaging approximately 61 BOPD. Through March 31, 2010, we have invested an additional $2.4 million in this project and have drilled 41 water injection wells and 34 producing wells. We have seen some indication of an initial response from 5 of the injectors and are closely monitoring data and activities for any resulting increase in production.

As of March 31, 2010, we had proved oil reserves on this project of:

	Gross STB(1)		Net STB(2)		PV10(3) (before tax)
Proved, Developed Producing		75,980		64,020	$	1,475,250
Proved, Developed Non-Producing		56,850		46,890	$	1,002,890
Proved, Undeveloped		200,150		165,180	$	407,420
Total Proved		332,980		276,090	$	2,885,560

(1)

STB = one stock-tank barrel.

(2)

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

(3)

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

Tri-County Project

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

Through March 31, 2010, we have invested approximately $700,000 towards the development of this project. Funds have been used to drill four producer wells, make infrastructure upgrades, and perform work-overs on approximately 20 wells in this project. We have also acquired additional leases, bringing the total project to approximately 1,300 acres.

As of March 31, 2010, the Tri-County Project consisted of 166 producing wells and 59 water injection wells with production averaging approximately 49 BOPD.

As of March 31, 2010, we had proved oil reserves on this project of:

	Gross STB(1)		Net STB(2)		PV10(3) (before tax)
Proved, Developed Producing		249,550		196,870	$	2,668,410
Proved, Developed Non-Producing		60,660		47,680	$	1,174,130
Proved, Undeveloped		609,450		488,620	$	5,084,340
Total Proved		919,660		733,170	$	8,926,880

(1)

STB = one stock-tank barrel.

(2)

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

(3)

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

Gas City Project

In August of 2007, we entered into a development agreement with Euramerica Energy, Inc., or Euramerica, to further the development and expansion of the Gas City Project, which included 6,600 acres. Over time Euramerica contributed $1,624,000 in capital toward the project, but failed to fund the full purchase and development funds needed for the project. Therefore, Euramerica forfeited all of its interest in the property, including all interests in any wells, improvements or assets, and all of Euramerica's interest in the property reverted back to us. In addition, all operating agreements between us and Euramerica relating to the Gas City Project were deemed null and void.

As of March 31, 2010, we had proved oil and natural gas reserves on this project of:

	Gross STB(1)		Net STB(2)		Gross MCF(3)		Net MCF(4)		PV10(5) (before tax)
Proved, Developed Producing		50		40		-		-	$	220
Proved, Developed Non-Producing		-		-		-		-	$	-
Proved, Undeveloped		10,900		8,990		-		-	$	71,640
Total Proved		10,950		9,030		-		-	$	71,860

(1)

STB = one stock-tank barrel.

(2)

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

(3)

MCF = thousand cubic feet of natural gas. There were no natural gas reserves at March 31, 2010.

(4)

Net MCF is based upon our net revenue interest. There were no natural gas reserves at March 31, 2010.

(5)

See “Glossary” on page 21 for our definition of PV10 and “Management’s Discussion and Analysis of Financial Condition and Results of Operations-Reserves” page 51, for reconciliation to the comparable GAAP financial measure.

Brownrigg Project

We entered into an agreement with Pharyn Resources (Pharyn) on June 1, 2009 to begin a 20 well development program on EnerJex’s Brownrigg lease in Linn County, Kansas. We contributed the 320 acre property in exchange for a 10% carried working interest and a cost-plus management fee. Pharyn contributed up to $700,000 in initial development capital. In May of 2010 we sold our 10% carried working interest to Pharyn for $50,000.

Our Business Strategy

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

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

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

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

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

We are continually evaluating oil and natural gas opportunities in Eastern Kansas and are also in various stages of discussions with potential joint venture (“JV”) partners who would contribute capital to develop leases we currently own or would acquire for the JV. In June 2009, we entered into one such opportunity on the Brownrigg lease in Linn County, Kansas, as discussed above. This economic strategy is anticipated to allow us to utilize our own financial assets toward the growth of our leased acreage holdings, pursue the acquisition of strategic oil and natural gas producing properties or companies and generally expand our existing operations while further diversifying risk. Subject to availability of capital, we plan to continue to bring potential acquisition and JV opportunities to various financial partners for evaluation and funding options.

Our future financial results will continue to depend on: (i) our ability to source and screen potential projects; (ii) our ability to discover commercial quantities of natural gas and oil; (iii) the market price for oil and natural gas; and (iv) our ability to fully implement our exploration, work-over and development program, which is in part dependent on the availability of capital resources. There can be no assurance that we will be successful in any of these respects, that the prices of oil and natural gas prevailing at the time of production will be at a level allowing for profitable production, or that we will be able to obtain additional funding at terms favorable to us to increase our currently limited capital resources. For a detailed description of these and other factors that could materially impact actual results, please see “Risk Factors” in this document under ITEM 1A.

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.

Significant Developments in Fiscal 2010

The following is a brief description of our most significant corporate developments that occurred in fiscal 2010:

In April and May of 2009, we repurchased a total of $450,000 of the subordinated debentures and in December 2009, we redeemed $150,000 of the subordinated debentures and received 75,000 shares of our stock for cancellation for $193,500 in cash. The principal balance remaining as of March 31, 2010 is approximately $2.47 million. These debentures mature on September 30, 2010.

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

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

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

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

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

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

On December 3, 2009, we entered into a Stock Equity Distribution Agreement (“SEDA”) with Paladin Capital Management, S.A. (“Paladin”). The SEDA provides that we may issue and sell to Paladin up to 1,300,000 shares (subject to adjustment as provided therein) of our common stock. We issued 90,000 shares to Paladin as a commitment fee under the terms of the SEDA. The price we receive shall be set at (i) 95% of the Market Price to the extent the Common Stock is trading at or above $2.00 per share during the Pricing Period, (ii) 92% of the Market Price to the extent the Common Stock is trading at or above $1.00 per share during the Pricing Period, (iii) 90% of the Market Price to the extent the Common Stock is trading below $1.00 per share during the Pricing Period, or (iv) 85% of the Market Price for the initial two advances. In December of 2009 we filed a registration statement on Form S-1 to register the 1,390,000 shares included in the SEDA.

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

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

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

In the first quarter of 2010, we further amended the Debentures to extend the scheduled due dates for the January and February 2010 redemption payments to March 10, 2010 and to remove the conversion feature of the Debentures. Further, the Maturity Date was extended to December 31, 2010.

Relationship with Haas Petroleum and MorMeg

In April of 2007, we entered into a consulting agreement with Mark Haas, President of Haas Petroleum and managing member of MorMeg, which was terminated in April of 2010 when Mr. Haas was appointed to serve as our chief operating officer and a director. Mr. Haas provides executive level services regarding field development, acquisition evaluation, identification of additional acquisition opportunities and overall business strategy. Haas Petroleum has been in the oil exploration and production business for over 70 years and Mark Haas has been in the business for over 30 years.

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

Drilling Activity

The following table sets forth the results of our drilling activities during the 2008, 2009 and 2010 fiscal years.

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

2008 Exploratory		10		10		-0-		10		10		-0-
2009 Exploratory(2)		12		12		-0-		12		12		-0-
2010 Exploratory		-0-		-0-		-0-		-0-		-0-		-0-

2008 Development		59		57		2		58		56		2
2009 Development		96		95		1		96		95		1
2010 Development		2		2		-0-		2		2		1

(1)

Net wells are based on our net working interest as of March 31, 2010.

(2)

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

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

The table below sets forth our net oil and natural gas production (net of all royalties, overriding royalties and production due to others) for the fiscal years ended March 31, 2010 and 2009 and 2008, the average sales prices, average production costs and direct lifting costs per unit of production.

	Fiscal Year Ended March 31, 2010		Fiscal Year Ended March 31, 2009		Fiscal Year Ended March 31, 2008
Net Production
Oil (Bbl)		64,948		74,289		43,697
Natural gas (Mcf)		-0-		12,275		17,762

Average Sales Prices
Oil (per Bbl)	$	62.64	$	85.67	$	79.71
Natural gas (per Mcf)	$	-0-	$	5.57	$	6.20

Average Production Cost (1)
Per Bbl of oil	$	40.38	$	45.01	$	56.65
Per Mcf of natural gas	$	-0-	$	15.11	$	13.12

Average Lifting Costs (2)
Per Bbl of oil	$	28.22	$	33.01	$	37.08
Per Mcf of natural gas	$	-0-	$	15.11	$	9.86

(1)

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

(2)

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

Results of Oil and Natural Gas Producing Activities

The following table shows the results of operations from our oil and natural gas producing activities from fiscal years ended March 31, 2008 through March 31, 2010. Results of operations from these activities have been determined using historical revenues, production costs, depreciation, depletion and amortization of the capitalized costs subject to amortization. General and administrative expenses and interest expense have been excluded from this determination.

	For the Fiscal Year Ended March 31, 2010 (Restated)			For the Fiscal Year Ended March 31, 2009			For the Fiscal Year Ended March 31, 2008
Production revenues	$	4,856,027		$	6,436,805		$	3,602,798
Production costs		(1,833,108	)		(2,637,333	)		(1,795,188	)
Depreciation, depletion and amortization		(588,416	)		(872,230	)		(913,224	)
Results of operations for producing activities	$	2,434,503		$	2,972,242		$	894,386

Producing Wells

The following table sets forth the number of productive oil and natural gas wells in which we owned an interest as of March 31, 2010.

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

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

(1)

Net wells are based on our net working interest as of March 31, 2010.

Reserves

Our estimated total proved PV10 (present value) before tax of reserves as of March 31, 2010 (Restated) was $29.9 million, versus $10.63 million as of March 31, 2009. Our total proved reserves increased almost 38% at March 31, 2010 over 2009 from 2.5 million and 1.3 million barrels of oil equivalent (BOE), respectively. In addition, the PV10 increased dramatically due to the estimated average price of oil at March 31, 2010 of $62.64 versus $42.65 at March 31, 2009. Of the 2.5 million BOE at March 31, 2010 approximately 30% are proved developed and approximately 70% are proved undeveloped. The proved developed reserves consist of proved developed producing (79%) and proved developed non-producing (21%). See “Glossary” on page 21 for our definition of PV10.

Based on an estimated oil price of $62.64 as of March 31, 2010, and applying an annual discount rate of 10% of the future net cash flow, the estimated PV10 of the 2.5 million BOE, before tax, is calculated as set forth in the following table:

Summary of Oil and Natural Gas Reserves

as of March 31, 2010

Proved Reserves Category	Gross STB(1)		Net STB(2) (Restated)		Gross MCF(3)		Net MCF(4)		PV10(5) (before tax) (Restated)
Proved, Developed Producing		822,180		581,900		-		-	$	10,560,200
Proved, Developed Non-Producing		201,020		150,100		-		-		3,731,700
Proved, Undeveloped		2,542,560		1,743,000		-		-		15,531,200
Total Proved		3,565,760		2,475,000		-		-	$	29,853,100

(1)

STB = one stock-tank barrel.

(2)

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

(3)

MCF = thousand cubic feet of natural gas. There we no natural gas reserves at March 31, 2010.

(4)

Net MCF is based upon our net revenue interest. There we no natural gas reserves at March 31, 2010.

(5)

Oil and Natural Gas Reserves Reported to Other Agencies

We did not file any estimates of total proved net oil or natural gas reserves with, or include such information in reports to, any federal authority or agency, other than the SEC, during the fiscal year ended March 31, 2010.

Title to Properties

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

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

Sale of Natural Gas and Oil

We do not intend to refine our natural gas or oil production. We expect to sell all or most of our production to a small number of purchasers in a manner consistent with industry practices at prevailing rates by means of long-term and short-term sales contracts, some of which may have fixed price components. We have a long-term purchase contract with Coffeyville to sell all of our current oil production through March of 2011. We also have an ISDA master agreement and a fixed price swap with BP beginning October 1, 2009 through December 31, 2013. Under current conditions, we should be able to find other purchasers, if needed. All of our produced oil is held in tank batteries and then each respective purchaser transports the oil by truck to the refinery. In addition, our board of directors has implemented a crude oil and natural gas hedging strategy that will allow management to hedge up to 80% of our net production in an effort to mitigate a majority of our exposure to changing oil prices in the intermediate term.

Secondary Recovery and Other Production Enhancement Strategies

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

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

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

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

Markets and Marketing

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

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

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

Competition

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

Research and Development Activities

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

Governmental Regulations

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

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

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

Environmental Matters

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

These laws and regulations may:

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

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

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

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

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

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

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

Personnel

As of March 31, 2010, we had 14 full-time employees; however, subsequent to year-end we have reduced staff to 5 employees. As production and drilling activities increase or decrease, we may have to continue to adjust our technical, operational and administrative personnel as appropriate. We are using and will continue to use independent consultants and contractors to perform various professional services, particularly in the area of land services, reservoir engineering, geology drilling, water hauling, pipeline construction, well design, well-site monitoring and surveillance, permitting and environmental assessment. We believe that this use of third-party service providers may enhance our ability to contain operating and general expenses, and capital costs.

Facilities

We currently lease our executive offices at 27 Corporate Woods, Suite 350, 10975 Grandview Drive, Overland Park, Kansas 66210, which expires in September 30, 2013. Future minimum payments $72,000 to $75,600 for years ended March 31, 2011-2013 and $38,750 for the year ended March 31, 2014.

GLOSSARY

Term		Definition

Barrel (bbl)		The standard unit of measurement of liquids in the petroleum industry, it contains 42 U.S. standard gallons. Abbreviated to “bbl”.

Basin		A depression in the crust of the Earth, caused by plate tectonic activity and subsidence, in which sediments accumulate. Sedimentary basins vary from bowl-shaped to elongated troughs. Basins can be bounded by faults. Rift basins are commonly symmetrical; basins along continental margins tend to be asymmetrical. If rich hydrocarbon source rocks occur in combination with appropriate depth and duration of burial, then a petroleum system can develop within the basin.

BOPD		Abbreviation for barrels of oil per day, a common unit of measurement for volume of crude oil. The volume of a barrel is equivalent to 42 U.S. standard gallons.

Carried Working Interest		The owner of this type of working interest in the drilling of a well incurs no capital contribution requirement for drilling or completion costs associated with a well and, if specified in the particular contract, may not incur capital contribution requirements beyond the completion of the well.

Completion / Completing		A well made ready to produce oil or natural gas.

Development		The phase in which a proven oil or natural gas field is brought into production by drilling development wells.

Development Drilling		Wells drilled during the Development phase.

Division order		A directive signed by the royalty owners verifying to the purchaser or operator of a well the decimal interest of production owned by the royalty owner. The Division Order generally includes the decimal interest, a legal description of the property, the operator’s name, and several legal agreements associated with the process. Completion of this step generally precedes placing the royalty owner on pay status to begin receiving revenue payments.

Drilling		Act of boring a hole through which oil and/or natural gas may be produced.

Dry Wells		A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes.

Exploration		The phase of operations which covers the search for oil or natural gas generally in unproven or semi-proven territory.

Exploratory Drilling		Drilling of a relatively high percentage of properties which are unproven.

Farm out		An arrangement whereby the owner of a lease assigns all or some portion of the lease or licenses to another company for undertaking exploration or development activity.

Field		An area consisting of a single reservoir or multiple reservoirs all grouped on, or related to, the same individual geological structural feature or stratigraphic condition. The field name refers to the surface area, although it may refer to both the surface and the underground productive formations.

Fixed price swap		A derivative instrument that exchanges or “swaps” the “floating” or daily price of a specified volume of natural gas, oil or NGL, over a specified period, for a fixed price for the specified volume over the same period (typically three months or longer).

Gathering line / system		Pipelines and other facilities that transport oil or natural gas from wells and bring it by separate and individual lines to a central delivery point for delivery into a transmission line or mainline.

Gross acre		The number of acres in which the Company owns any working interest.

Gross Producing Well		A well in which a working interest is owned and is producing oil or natural gas or other liquids or hydrocarbons. The number of gross producing wells is the total number of wells producing oil or natural gas or other liquids or hydrocarbons in which a working interest is owned.

Gross well		A well in which a working interest is owned. The number of gross wells is the total number of wells in which a working interest is owned.

Held-By-Production (HBP)		Refers to an oil and natural gas property under lease, in which the lease continues to be in force, because of production from the property.

Horizontal drilling		A drilling technique used in certain formations where a well is drilled vertically to a certain depth and then turned and drilled horizontally. Horizontal drilling allows the wellbore to follow the desired formation.

In-fill wells		In-fill wells refers to wells drilled between established producing wells; a drilling program to reduce the spacing between wells in order to increase production and recovery of in-place hydrocarbons.

Oil and Natural Gas Lease		A legal instrument executed by a mineral owner granting the right to another to explore, drill, and produce subsurface oil and natural gas. An oil and natural gas lease embodies the legal rights, privileges and duties pertaining to the lessor and lessee.

Lifting Costs		The expenses of producing oil from a well. Lifting costs are the operating costs of the wells including the gathering and separating equipment. Lifting costs do not include the costs of drilling and completing the wells or transporting the oil.

Mcf		Thousand cubic feet.

Mmcf		Million cubic feet.

Net acres		Determined by multiplying gross acres by the working interest that the Company owns in such acres.

Net Producing Wells		The number of producing wells multiplied by the working interest in such wells.

Net Revenue Interest		A share of production revenues after all royalties, overriding royalties and other nonoperating interests have been taken out of production for a well(s).

Operator		A person, acting for itself, or as an agent for others, designated to conduct the operations on its or the joint interest owners’ behalf.

Overriding Royalty		Ownership in a percentage of production or production revenues, free of the cost of production, created by the lessee, company and/or working interest owner and paid by the lessee, company and/or working interest owner out of revenue from the well.

Pooled Unit		A term frequently used interchangeably with “Unitization” but more properly used to denominate the bringing together of small tracts sufficient for the granting of a well permit under applicable spacing rules.

Proved Developed Reserves		Proved reserves that can be expected to be recovered from existing wells with existing equipment and operating methods. This definition of proved developed reserves has been abbreviated from the applicable definitions contained in Rule 4-10(a)(2-4) of Regulation S-X.

Proved Developed Non-Producing		Proved developed reserves expected to be recovered from zones behind casings in existing wells.

Proved Undeveloped Reserves		Proved undeveloped reserves are the portion of proved reserves which can be expected to be recovered from new wells on undrilled proved acreage, or from existing wells where a relatively major expenditure is required for completion. This definition of proved undeveloped reserves has been abbreviated from the applicable definitions contained in Rule 4-10(a)(2-4) of Regulation S-X.

PV10		PV10 means the estimated future gross revenue to be generated from the production of proved reserves, net of estimated production and future development and abandonment costs, using prices and costs in effect at the determination date, before income taxes, and without giving effect to non-property related expenses, discounted to a present value using an annual discount rate of 10% in accordance with the guidelines of the SEC. PV10 is a non-GAAP financial measure. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations-Reserves” on page 51 for a reconciliation to the comparable GAAP financial measure.

Re-completion		Completion of an existing well for production from one formation or reservoir to another formation or reservoir that exists behind casing of the same well.

Reservoir		The underground rock formation where oil and natural gas has accumulated. It consists of a porous rock to hold the oil or natural gas, and a cap rock that prevents its escape.

Reservoir Pressure		The pressure at the face of the producing formation when the well is shut-in. It equals the shut-in pressure at the wellhead plus the weight of the column of oil and natural gas in the well.

Roll-Up Strategy		A “roll-up strategy” is a common business term used to describe a business plan whereby a company accumulates multiple small operators in a particular business sector with a goal to generate synergies, stimulate growth and optimize the value of the individual pieces.

Secondary Recovery		The stage of hydrocarbon production during which an external fluid such as water or natural gas is injected into the reservoir through injection wells located in rock that has fluid communication with production wells. The purpose of secondary recovery is to maintain reservoir pressure and to displace hydrocarbons toward the wellbore. The most common secondary recovery techniques are natural gas injection and waterflooding. Normally, natural gas is injected into the natural gas cap and water is injected into the production zone to sweep oil from the reservoir. A pressure-maintenance program can begin during the primary recovery stage, but it is a form of enhanced recovery.

Shut-in well		A well which is capable of producing but is not presently producing. Reasons for a well being shut-in may be lack of equipment, market or other.

Stock Tank Barrel or STB		A stock tank barrel of oil is the equivalent of 42 U.S. Gallons at 60 degrees Fahrenheit.

Undeveloped acreage		Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas regardless of whether such acreage contains proved reserves.

Unitize, Unitization		When owners of oil and/or natural gas reservoir pool their individual interests in return for an interest in the overall unit.

Waterflood		The injection of water into an oil reservoir to “push” additional oil out of the reservoir rock and into the wellbores of producing wells. Typically a secondary recovery process.

Water Injection Wells		A well in which fluids are injected rather than produced, the primary objective typically being to maintain or increase reservoir pressure, often pursuant to a waterflood.

Water Supply Wells		A well in which fluids are being produced for use in a Water Injection Well.

Wellbore		A borehole; the hole drilled by the bit. A wellbore may have casing in it or it may be open (uncased); or part of it may be cased, and part of it may be open. Also called a borehole or hole.

Working Interest		An interest in an oil and natural gas lease entitling the owner to receive a specified percentage of the proceeds of the sale of oil and natural gas production or a percentage of the production, but requiring the owner of the working interest to bear the cost to explore for, develop and produce such oil and natural gas.

Item 1A. Risk Factors.

In the course of conducting our business operations, we are exposed to a variety of risks that are inherent to the oil and gas industry. The following discusses some of the key inherent risk factors that could affect our business and operations, as well as other risk factors which are particularly relevant to us in the current period of significant economic and market disruption. Other factors besides those discussed below or elsewhere in this report also could adversely affect our business and operations, and these risk factors should not be considered a complete list of potential risks that may affect us.

Declining economic conditions could negatively impact our business

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

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

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

the future prices of natural gas and oil;

our ability to raise adequate working capital;

success of our development and exploration efforts;

effects of our hedging strategies;

demand for natural gas and oil;

the level of our competition;

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

transportation and processing fees on our facilities;

fuel conservation measures;

alternate fuel requirements or advancements;

government regulation and taxation;

technical advances in fuel economy and energy generation devices; and

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

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

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

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

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

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

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

As a result of our deficiency in working capital at March 31, 2010 and other factors, our auditors have included a paragraph in their audit report regarding substantial doubt about our ability to continue as a going concern. Our plans in this regard are to increase production, seek strategic alternatives and to seek additional capital through future equity private placements or debt facilities.

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

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

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

local, national and worldwide economic conditions;

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

the domestic and foreign supply of natural gas and oil;

weather conditions;

natural disasters;

acts of terrorism;

domestic and foreign governmental regulations and taxation;

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

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

the availability of refining capacity;

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

the price and availability of other fuels.

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

Approximately 76% of our total proved reserves as of March 31, 2010 consist of undeveloped and developed non-producing reserves, and those reserves may not ultimately be developed or produced.

Our estimated total proved PV 10 (present value) before tax of reserves as of March 31, 2010 (Restated) was $29.9 million, versus $10.63 million as of March 31, 2009. The substantial increase in PV10 is primarily due to the estimated average price of oil at March 31, 2010 of $62.64 versus $42.65 at March 31, 2009. We developed total proved reserves to 2.5 million barrels of oil equivalent, or BOE, as of March 31, March 31, 2010. Of the 2.5 million BOE of total proved reserves, approximately 30% are proved developed and approximately 70% are proved undeveloped. The proved developed reserves consist of 79% proved developed producing reserves and 21% proved developed non-producing reserves. See “Glossary” on page 21 for our definition of PV10.

As of March 31, 2010, approximately 70% of our total proved reserves were undeveloped and approximately 6% were developed non-producing. Assuming we can obtain adequate capital resources, we plan to develop and produce all of our proved reserves, but ultimately some of these reserves may not be developed or produced. Furthermore, not all of our undeveloped or developed non-producing reserves may be ultimately produced in the time periods we have planned, at the costs we have budgeted, or at all.

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

Our reserve estimate and the future net cash flows attributable to those reserves at March 31, 2010 was prepared by Miller and Lents, Ltd., an independent petroleum consultant. There are numerous uncertainties inherent in estimating quantities of proved reserves and cash flows from such reserves, including factors beyond our control and the control of these independent consultants and engineers. Reserve engineering is a subjective process of estimating underground accumulations of natural gas and oil that can be economically extracted, which cannot be measured in an exact manner. The accuracy of an estimate of quantities of reserves, or of cash flows attributable to these reserves, is a function of the available data, assumptions regarding future natural gas and oil prices, expenditures for future development and exploitation activities, and engineering and geological interpretation and judgment. Reserves and future cash flows may also be subject to material downward or upward revisions based upon production history, development and exploitation activities and natural gas and oil prices. Actual future production, revenue, taxes, development expenditures, operating expenses, quantities of recoverable reserves and value of cash flows from those reserves may vary significantly from the assumptions and estimates in our reserve reports. Any significant variance from these assumptions to actual figures could greatly affect our estimates of reserves, the economically recoverable quantities of natural gas and oil attributable to any particular group of properties, the classification of reserves based on risk of recovery, and estimates of the future net cash flows. In addition, reserve engineers may make different estimates of reserves and cash flows based on the same available data. The estimated quantities of proved reserves and the discounted present value of future net cash flows attributable to those reserves included in this report were prepared by Miller and Lents, Ltd. in accordance with rules of the Securities and Exchange Commission, or SEC, and are not intended to represent the fair market value of such reserves.

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

geological conditions;

assumptions governing future oil and natural gas prices;

amount and timing of actual production;

availability of funds;

future operating and development costs;

actual prices we receive for natural gas and oil;

supply and demand for our natural gas and oil;

changes in government regulations and taxation; and

capital costs of drilling new wells.

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

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

The prices that we receive for our oil and natural gas production typically trade at a discount to the relevant benchmark prices, such as NYMEX, that are used for calculating hedge positions. The difference between the benchmark price and the price we receive is called a differential. While we have fixed this differential under the terms of our agreement with BP through March of 2011, the differential on physical sales after that date is still under negotiation. 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. Recent economic conditions, including volatility in the price of oil and natural gas, have resulted in both increases and decreases in the differential between the benchmark price for oil and natural gas and the wellhead price we receive. These fluctuations could have a material adverse effect on our results of operations, financial condition and cash flows by decreasing the proceeds we receive for our oil and natural gas production in comparison to what we would receive if not for the differential.

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

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

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

unexpected operational events and/or conditions;

unusual or unexpected geological formations;

reductions in natural gas and oil prices;

limitations in the market for oil and natural gas;

adverse weather conditions;

facility or equipment malfunctions;

title problems;

natural gas and oil quality issues;

pipe, casing, cement or pipeline failures;

natural disasters;

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

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

compliance with environmental and other governmental requirements; and

uncontrollable flows of oil, natural gas or well fluids.

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

injury or loss of life;

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

pollution and other environmental damage;

clean-up responsibilities;

regulatory investigation and penalties;

suspension of our operations; and

repairs to resume operations.

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

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

Developing and exploring for natural gas and oil involves a high degree of operational and financial risk, which precludes definitive statements as to the time required and costs involved in reaching certain objectives. The budgeted costs of drilling, completing and operating wells are often exceeded and can increase significantly when drilling costs rise due to a tightening in the supply of various types of oilfield equipment and related services. Drilling may be unsuccessful for many reasons, including geological conditions, weather, cost overruns, equipment shortages and mechanical difficulties. Moreover, the successful drilling of a natural gas or oil well does not ensure a profit on investment. Exploratory wells bear a much greater risk of loss than development wells. Substantially all of our wells drilled through March 31, 2010 have been development wells. A variety of factors, both geological and market-related, can cause a well to become uneconomical or only marginally economic. Our initial drilling and development sites, and any potential additional sites that may be developed, require significant additional exploration and development, regulatory approval and commitments of resources prior to commercial development. If our actual drilling and development costs are significantly more than our estimated costs, we may not be able to continue our business operations as proposed and would be forced to modify our plan of operation.

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

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

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

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

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

outbid by competitors.

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

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

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

higher than projected operating costs;

lower-than-expected production;

longer response times;

higher costs associated with obtaining capital;

unusual or unexpected geological formations;

fluctuations in natural gas and oil prices;

regulatory changes;

shortages of equipment; and

lack of technical expertise.

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

Any acquisitions we complete are subject to considerable risk.

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

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

an inability to integrate successfully the businesses we acquire;

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

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

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

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

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

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

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

customer or key employee losses at the acquired businesses.

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

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

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

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

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

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

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

We have contracted with Coffeyville for the sale of all of our oil through March 2011 It is not likely that there will be a large pool of available purchasers. If a key purchaser were to reduce the volume of oil or natural gas it purchases from us, our revenue and cash available for operations will decline to the extent we are not able to find new customers to purchase our production at equivalent prices.

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

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

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

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

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

To achieve more predictable cash flow and to reduce our exposure to adverse fluctuations in the prices of oil and natural gas, we have entered into derivative arrangements from April 1, 2008 until December 31, 2013 for between 30 and 130 barrels of oil per day that could result in both realized and unrealized hedging losses. As of March 31, 2010 we had incurred realized and unrealized losses of approximately 3.911 million. The extent of our commodity price exposure is related largely to the effectiveness and scope of our derivative activities. For example, the derivative instruments we may utilize may be based on posted market prices, which may differ significantly from the actual crude oil, natural gas and NGL prices we realize in our operations.

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

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

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

Cost and availability of drilling rigs, equipment, supplies, personnel and other services could adversely affect our ability to execute on a timely basis our development, exploitation and exploration plans.

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

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

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

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

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

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

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

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

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

location and density of wells;

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

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

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

transportation of natural gas and oil by pipelines;

operation of wells and reports concerning operations; and

taxation.

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

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

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

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

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

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

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

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

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

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

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

As previously announced, in December 2008, the Securities and Exchange Commission (“SEC”) issued new regulations for oil and gas reserve reporting which go into effect effective for fiscal years ending on or after December 31, 2009. One of the key elements of the new regulations relate to the commodity prices which are used to calculate reserves and their present value. The new regulations provide for disclosure of oil and gas reserves evaluated using annual average prices based on the prices in effect on the first day of each month rather than the current regulations which utilize commodity prices on the last day of the year.

There was no impairment for the fiscal year ended March 31, 2010. We recorded an impairment of $4,777,723 during the fiscal year ended March 31, 2009 primarily attributable to lower prices for both oil and natural gas at December 31, 2009.

Risks Associated with our Debt Financing

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

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

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

On March 31, 2010, $2.47 million in debentures and approximately $6.7 million of bank loans were outstanding. Under a default situation with respect to the debentures or other secured debt, the lenders may enforce their rights as a secured party and we may lose all or a portion of our assets or be forced to materially reduce our business activities.

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

On July 3, 2008, we entered into a three-year, Senior Secured Credit Facility providing for aggregate borrowings of up to $50 million. As of March 31, 2010, we had total indebtedness of $10.1 million, including $6.691 million of borrowings under the Credit Facility and $2.47 million of remaining debentures, as well as other notes payable totaling approximately $109,000. We had no outstanding letters of credit under the new facility on March 31, 2010. Our substantial indebtedness, and the related interest expense, could have important consequences to us, including:

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

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

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

increasing our vulnerability to general adverse economic and industry conditions;

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

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

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

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

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

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

incur additional indebtedness and provide additional guarantees;

pay dividends and make other restricted payments;

create or permit certain liens;

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

use the proceeds from the unwinding of certain financial hedges;

engage in certain transactions with affiliates; and

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

The Credit Facility and our debentures also contain various affirmative covenants with which we are required to comply. We were not in compliance with three covenants at March 31, 2010. We may be unable to comply with some or all of these covenants in the future as well. If we do not comply with these covenants and are unable to obtain waivers from our lenders, we would be unable to make additional borrowings under these facilities, our indebtedness under these agreements would be in default and could be accelerated by our lenders. In addition, it could cause a cross-default under our other indebtedness, including our debentures. If our indebtedness is accelerated, we may not be able to repay our indebtedness or borrow sufficient funds to refinance it. In addition, if we incur additional indebtedness in the future, we may be subject to additional covenants, which may be more restrictive than those to which we are currently subject.

Risks Associated with our Common Stock

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

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

We have the ability to issue additional shares of our common stock and shares of preferred stock without asking for stockholder approval, which could cause your investment to be diluted.

Our Articles of Incorporation authorizes the Board of Directors to issue up to 100,000,000 shares of common stock and 10,000,000 shares of preferred stock. The power of the Board of Directors to issue shares of common stock, preferred stock or warrants or options to purchase shares of common stock or preferred stock is generally not subject to shareholder approval. Accordingly, any additional issuance of our common stock, or preferred stock that may be convertible into common stock, or debt instruments that may be convertible into common or preferred stock, may have the effect of diluting one’s investment.

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

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

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

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

our operating and financial performance and prospects;

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

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

potentially limited liquidity;

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

changes in natural gas and oil prices;

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

increases in our cost of capital;

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

commencement of or involvement in litigation;

changes in market valuations of similar companies;

additions or departures of key management personnel;

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

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

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

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

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

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

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

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

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

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

As of March 31, 2010, we had warrants to purchase approximately 75,000 shares of common stock outstanding in addition to 2,500 shares issuable upon conversion of a convertible note. The exercise of our outstanding options and warrants, and the conversion of the note, will cause additional shares of common stock to be issued, resulting in dilution to our existing common stockholders.

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

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

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

Disclose certain price information about the stock;

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

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

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

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

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

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

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

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

Additional Risks and Uncertainties

We are an oil and natural gas acquisition, exploration and development company. If any of the risks that we face actually occur, irrespective of whether those risks are described in this section or elsewhere in this report, our business, financial condition and operating results could be materially adversely affected.

Item 1B. Unresolved Staff Comments.

Not applicable.

Item 3. Legal Proceedings.

We may become involved in various routine legal proceedings incidental to our business. However, to our knowledge as of the date of this report, there are no material pending legal proceedings to which we are a party or to which any of our property is subject.

PART II

Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.

(a) Market Information

PRICE RANGE OF COMMON STOCK

Our common stock currently trades on the OTC:BB under the symbol “ENRJ.” 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 on Yahoo! Finance for fiscal years 2009 and 2010. The quotations reflect inter-dealer prices without retail mark-up, markdown, or commissions and may not represent actual transactions.

	Low		High
Fiscal 2009
Quarter ended June 30, 2008		0.95		1.20
Quarter ended September 30, 2008		4.20		5.00
Quarter ended December 31, 2008		0.45		3.16
Quarter ended March 31, 2009		0.25		1.88

Fiscal 2010
Quarter ended June 30, 2009		0.15		1.34
Quarter ended September 30, 2009		0.15		1.85
Quarter ended December 31, 2009		0.41		1.00
Quarter ended March 31, 2010		0.29		1.09

The last reported sale price of our common stock on the OTC:BB was $0.69 per share on July 9, 2010.

(b) Holders of Common Stock

As of July 9, 2010, there were 1,146 holders of record of our common stock.

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

(d) Securities Authorized for Issuance under Equity Compensation Plans

2000/2001 Stock Option Plan

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

Stock Incentive Plan

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

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

General Terms of Plans

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

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

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

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

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

Recent Sales of Unregistered Securities

On August 3, 2009, we issued 100,000 shares of restricted common stock to C.K. Cooper & Company, LLC, valued at $100,000, in full satisfaction of C.K. Cooper’s outstanding balance payable as of the date of issuance. The Company believes that the issuance of the shares was exempt from the registration and prospectus delivery requirements of the Securities Act of 1933 by virtue of Section 4(2) thereof.

On August 3, 2009, we issued Accuity Financial Inc. 50,000 shares of restricted common stock, valued at $50,000, for payment against Accuity’s outstanding balance payable. The Company believes that the issuance of the shares was exempt from the registration and prospectus delivery requirements of the Securities Act of 1933 by virtue of Section 4(2) thereof.

On August 3, 2009, in an effort for us to preserve cash in light of deteriorated global economic conditions and the significant declines in commodity prices of oil and natural gas, each of the Company’s non-employee directors agreed to convert their board/committee retainers for the period from July 1, 2009 through September 30, 2009 into 32,000 shares of the Company’s restricted common stock. The Company believes that the issuance of the shares was exempt from the registration and prospectus delivery requirements of the Securities Act of 1933 by virtue of Section 4(2) thereof.

On August 3, 2009, we issued a total of 109,700 shares of our common stock in exchange for 438,500 currently outstanding options to purchase shares of our common stock. The shares issued were issued pursuant to the EnerJex Resources Stock Incentive Plan and registered on the Form S-8 filed on October 20, 2008.

On August 3, 2009, we awarded a total of 151,750 shares of our common stock for 2009 incentive bonuses to our employees. Such shares were issued to the employees in June of 2010. The shares were awarded pursuant to the EnerJex Resources Stock Incentive Plan and registered on the Form S-8 filed on October 20, 2008.

On August 3, 2009, we issued a total of 59,300 shares of our common stock to our named executive officers and directors for options that were previously rescinded for no consideration. The shares issued were issued pursuant to the EnerJex Resources Stock Incentive Plan and registered on the Form S-8 filed on October 20, 2008.

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

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

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

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

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

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

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

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

Issuer Purchases of Equity Securities

In December 2009, we redeemed $150,000 of our subordinated debentures for $150,000 in cash. In accordance with the terms of the amended Debentures, 75,000 shares were tendered to us and cancelled for the $150,000 redemption.

Other than set forth above we did not repurchase any of our equity securities during the fiscal years ended March 31, 2010 or 2009.

Item 6. Selected Financial Data.

Not applicable.

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.

The following discussion of our financial condition and results of operations should be read in conjunction with our financial statements and the related notes to our financial statements included elsewhere in this report. In addition to historical financial information, the following discussion and analysis contains forward-looking statements that involve risks, uncertainties and assumptions. Our actual results and timing of selected events may differ materially from those anticipated in these forward-looking statements as a result of many factors, including those discussed under ITEM 1A. Risk Factors and elsewhere in this report.

Overview

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

Results of Operations for the Fiscal Years Ended March 31, 2010 and 2009 compared.

Income:

	Fiscal Year Ended March 31,
	2010		2009		Increase / (Decrease)
	Amount		Amount		$
Oil and natural gas revenues	$	4,856,027	$	6,436,805	$	(1,580,778	)

Revenues

Oil and natural gas revenues for the fiscal year ended March 31, 2010 were $4,856,027 compared to revenues of $6,436,805 in the fiscal year ended March 31, 2009. The decrease in revenues is primarily the result of the lower price per barrel of oil. The average price per barrel we received for oil sold during the twelve months ended March 31, 2010 was $69.62 compared to $85.67 for the twelve months ended March 31, 2009. Natural gas sales accounted for less than 1% of the total revenues. There were no natural gas sales during the fiscal year ended March 31, 2010 and ended March 31, 2009 respectively.

Expenses:

	Fiscal Year Ended March 31,
	2010 (Restated)		2009		Increase / (Decrease)
	Amount		Amount		$
Expenses:
Direct operating costs	$	1,833,108	$	2,637,333	$	(804,225	)
Depreciation, depletion and amortization		588,416		872,230		(283,814	) )
Total production expenses		2,421,524		3,509,563		(1,088,039	)

Professional fees		561,625		1,320,332		(758,707	)
Salaries		835,576		849,340		(13,764	)
Depreciation on other fixed assets		47,081		39,063		8,018
Administrative expenses		1,016,484		1,392,645		(376,161	)
Impairment of oil & gas properties		-		4,777,723		(4,777,723	)
Total expenses	$	4,882,290	$	11,888,666	$	(7,006,376	)

Direct Operating Costs

Direct operating costs for the fiscal year ended March 31, 2010 were $1,833,108 compared to $2,637,333 for the fiscal year ended March 31, 2009. The decrease over the prior period results from the operating costs on a greater number of wells on our existing and acquired oil leases during the fiscal year ended March 31, 2010. Direct operating costs include pumping, gauging, pulling, repairs, certain contract labor costs, and other non-capitalized expenses.

Depreciation, Depletion and Amortization

Depreciation, depletion and amortization for the fiscal year ended March 31, 2010 (Restated) was $588,416, compared to $872,230 for the fiscal year ended March 31, 2009. The decrease was primarily a result of lower production. The rate of depletion was $9.06 per barrel for the fiscal year ended March 31, 2010 (Restated) as compared to $12.02 per barrel for the fiscal year ended March 31, 2009.

Professional Fees

Professional fees for the fiscal year ended March 31, 2010 were $561,625 compared to $1,320,332 for the fiscal year ended March 31, 2009. Payments for services rendered in connection with acquisition and financing activities, our audit, legal, and consulting fees are recorded as professional fees and remained relatively constant over the two fiscal years.

Salaries

Salaries for the fiscal year ended March 31, 2010 were $835,576 compared to $849,340 for the fiscal year ended March 31, 2009. The number of full-time employees was flat compared to the respective years.

Depreciation on Other Fixed Assets

Depreciation on other fixed assets fiscal year ended March 31, 2010 was $47,081 compared to $39,063 for the fiscal year ended March 31, 2009. The increase was primarily due to depreciation on fixed assets acquired during the period.

Administrative Expenses

Administrative expenses for the fiscal year ended March 31, 2010 were $1,016,484 compared to $1,392,645 in the fiscal year ended March 31, 2009. The administrative expenses decreased resulting from less activity in development and exploration and cost cutting measures.

Impairment of Oil & Gas Properties

No impairment was recorded for the fiscal year ended March 31, 2010. The impairment of oil and natural gas properties in the year ended March 31, 2009 of $4,777,723 represented an impairment through applying the full-cost ceiling test method. This ceiling test was applied to all of the cost of our oil and natural gas properties accounted for under the full-cost method that were subject to amortization at March 31, 2009. We took this impairment based on the ceiling test results during the quarter ended December 31, 2008, and was primarily due to depressed commodity prices at the time.

Reserves

Our estimated total proved PV 10 (present value) of reserves as of March 31, 2010 (Restated) increased to $29.9 million from $10.63 million as of March 31, 2009. Total proved reserves at March 31, 2010 and 2009 increased approximately 38% to 2.5 million and from 1.3 million barrels of oil equivalent (BOE), over the year ended March 31, 2009. Further, the PV10 increased dramatically due to the estimated average price of oil at March 31, 2010 of $62.64 versus $42.65 at March 31, 2009. Of the 2.5 million BOE at March 31, 2010 approximately 30% are proved developed and approximately 70% are proved undeveloped. The proved developed reserves consist of proved developed producing (79%) and proved developed non-producing (21%).

The following table presents summary information regarding our estimated net proved reserves as of March 31, 2010. All calculations of estimated net proved reserves have been made in accordance with the rules and regulations of the SEC, and, except as otherwise indicated, give no effect to federal or state income taxes. The estimates of net proved reserves are based on the reserve reports prepared by Miller and Lents, Ltd., our independent petroleum consultants. For additional information regarding our reserves, please see Note 13 to our audited financial statements as of and for the fiscal year ended March 31, 2010.

Summary of Proved Oil and Natural Gas Reserves

as of March 31, 2010

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

Proved, Developed Producing
Oil (stock-tank barrels)		822,180		581,900	$	10,560,200
Natural Gas (mcf)(2)		-		-		-
Proved, Developed Non-Producing
Oil (stock-tank barrels)		201,020		150,100	$	3,731,700
Natural Gas (mcf) (2)		-		-		-
Proved, Undeveloped
Oil (stock-tank barrels)		2,542,560		1,743,000	$	15,561,200
Natural Gas (mcf) (2)		-		-		-
Total Proved Reserves
Oil (stock-tank barrels)		3,565,760		2,475,000	$	29,853,100
Natural Gas (mcf) (2)		-		-		-

(1)

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

	As of March 31, 2010 (Restated)

PV10 (before tax)	$	29,853,100
Future income taxes, net of 10% discount		(6,774,578	)
Standardized measure of discounted future net cash flows	$	23,078,522

(2)

There were no natural gas reserves at March 31, 2010.

Liquidity and Capital Resources

Liquidity is a measure of a company’s ability to meet potential cash requirements. We have historically met our capital requirements through debt financing, revenues from operations and the issuance of equity securities. We have classified $6,691,000 of the borrowings outstanding under our Credit Facility as a current liability. As we may be unable to provide the necessary liquidity we need by the revenues generated from our net interests in our oil and natural gas production at current commodity prices, we are exploring strategic initiative and JV partnerships, as well as sales of reserves in our existing properties to finance our operations and to service our debt obligations. Further, in the future we may access funds through the sale of shares under the SEDA with Paladin.

The following table summarizes total current assets, total current liabilities and working capital at March 31, 2010 as compared to March 31, 2009.

	March 31, 2010			March 31, 2009			Increase / (Decrease) $

Current Assets	$	665,683		$	898,941			233,258

Current Liabilities	$	11,686,510		$	2,827,015			8,859,495

Working Capital (deficit)	$	(11,020,827	)	$	(1,928,074	)		9,092,753

Senior Secured Credit Facility

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

The Credit Facility is secured by a lien on substantially all assets of the Company and its subsidiaries. The Credit Facility has a term of three years, and all principal amounts, together with all accrued and unpaid interest, will be due and payable in full on July 3, 2011. The Credit Facility also provides for the issuance of letters-of-credit up to a $750,000 sub-limit under the borrowing base and up to an additional $2.25 million limit not subject to the borrowing base to support our hedging program. We have borrowed all of our available borrowing base as of March 31, 2010.

Advances under the Credit Facility will be in the form of either base rate loans or Eurodollar loans. The interest rate on the base rate loans fluctuates based upon the higher of (1) the lender’s “prime rate” and (2) the Federal Funds rate plus 0.50%, plus, in either case, a margin of between 0.0% and 0.5% depending on the percent of the borrowing base utilized at the time of the credit extension, but in no event shall be less than five percent (5.0%). The interest rate on the Eurodollar loans fluctuates based upon the applicable LIBOR rate, plus a margin of 2.25% to 2.75% depending on the percent of the borrowing base utilized at the time of the credit extension, but in no event shall be less than five percent (5.0%). Eurodollar loans may be based upon one, two, three and six month LIBOR options, except that beginning March 30, 2009 and continuing through the date of this report, TCB has suspended all LIBOR based funding with maturities less than 90 days due to the extreme volatility in the interest rate market and the unprecedented spread between the 90 day LIBOR and the shorter term LIBOR options. A commitment fee of 0.375% on the unused portion of the borrowing base will accrue, and be payable quarterly in arrears. There was no commitment fee due at March 31, 2010.

The Credit Facility includes usual and customary affirmative covenants for credit facilities of this type and size, as well as customary negative covenants, including, among others, limitations on liens, mergers, asset sales or dispositions, payments of dividends, incurrence of additional indebtedness, and investments. The Credit Facility also requires that we, at the end of each fiscal quarter beginning with the quarter ending September 30, 2008, maintain a minimum current assets to current liabilities ratio and a minimum ratio of EBITDA (earnings before interest, taxes, depreciation and amortization) to interest expense and at the end of each fiscal quarter beginning with the quarter ended September 30, 2008 to maintain a minimum ratio of EBITDA to senior funded debt.

The Credit Facility was amended August 18, 2009 to implement a minimum interest rate of five (5.0%) and establish minimum volumes to be hedged of not less than seventy-five percent (75%) of the proved developed producing reserves attributable to our interest in the borrowing base oil and gas properties projected to be produced. The Credit Facility was further amended January 13, 2010 to modify the senior funded debt to EBITDA ratio on a quarterly basis beginning with the quarter ended December 31, 2009 and to modify the annualization of the interest coverage ratio, also beginning with the quarter ended December 31, 2009. The senior funded debt to EBITDA ratio allowed is 6.25:1.00 at December 31, 2009; 5.75:1.00 at March 31, 2010; 5.25:1.00 at June 30, 2010; and 4.75:1.00 at September 30, 2010; and 4.25:1.00 for all quarters ending after September 30, 2010. We were not in compliance the three technical covenants of the Credit Facility at March 31, 2010, however, we were current with principal and interest and we have requested a waiver of this technical default from TCB. There can be no assurance that TCB will grant us a waiver. As a result, we have classified the entire outstanding balance due under the Credit Facility as a current liability.

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

Debentures

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

The proceeds from the Debentures were allocated to the long-term debt and the stock issued based on the fair market value of each item that we calculated to be $9.0 million. Since each of the instruments had a value equal to 50% of the total, we allocated $4.5 million to stock and $4.5 million to the note. The loan discount costs of $4.5 million will accrete as interest based on the interest method over the period of issue to maturity or redemption. The amount of interest accreted for the year ended March 31, 2010 was $596,108. There was is no remaining amount of interest to accrete.

We incurred debt issue costs totaling $466,835. The debt issue costs are initially recorded as assets and are amortized to expense on a straight-line basis over the life of the loan. The amount expensed in the year ended March 31, 2010 was $45,929.

The Debentures originally had a three-year term, maturing on March 31, 2010, and an interest rate equal to 10% per annum. We further amended the Debentures in June 2009 to extend the maturity date to September 30, 2010, to allow us to pay interest in either cash or payment-in-kind interest (an increase in the amount of principal due) or payment-in-kind shares (issuance of shares of common stock), and add a provision for the conversion of the debentures into shares of our common stock. Subsequent to the quarter ended December 31, 2009, we further amended the Debentures to extend the scheduled due dates for the January and February 2010 redemption payments to March 10, 2010. In addition, in April of 2010, we further amended the Debentures to remove the conversion feature and extend the Maturity Date to December 31, 2010.

Interest is payable quarterly in arrears on the first day of each succeeding quarter. The interest rate remains 14% per annum for cash interest payments. The payment-in-kind interest rate is equal to 12.5% per annum. If interest payments are made through payment-in-kind interest, we must issue common stock equal to an additional 2.5% of the quarterly interest payment due. As of March 31, 2010, we have recorded additional principal on the Debentures of $368,045 and common stock of $9,792.

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

We have no prepayment penalty so long as we maintain an effective registration statement with the Securities Exchange Commission and provided we give six (6) business days prior notice of redemption to the Buyers. During the year ended March 31, 2010 we also repurchased $450,000 of the Debentures at a gain of $406,500.

Going Concern

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

Satisfaction of our cash obligations for the next 12 months.

A critical component of our operating plan is the ability to obtain additional capital through additional equity and/or debt financing and working interest participants. During fiscal 2010, we were in the midst of a public equity offering when global economic conditions deteriorated and the commodity prices of oil and natural gas experienced significant declines. Our cash revenues from operations have been significantly impacted as has our ability to meet our monthly operating expenses and service our debt obligations. In the event we cannot obtain additional capital through other means to allow us to pursue our strategic plan, this would materially impact our ability to continue our desired growth. There is no assurance we would be able to obtain such financing on commercially reasonable terms, if at all.

We intend to implement and execute our business and marketing strategy, 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.

Significant changes in the number of employees.

As of March 31, 2010, we had 14 full-time employees; however, subsequent to year-end we have reduced personnel levels by 5 full time employees and one independent contractor in response to declining economic conditions and in an effort to reduce our operating and general expenses and cash outlay. As drilling production activities increase or decrease, we may have to adjust our technical, operational and administrative personnel as appropriate. We are using and will continue to use the services of independent consultants and contractors to perform various professional services, particularly in the area of land services, reservoir engineering, geology drilling, water hauling, pipeline construction, well design, well-site monitoring and surveillance, permitting and environmental assessment. We believe that this use of third-party service providers may enhance our ability to contain operating and general expenses, and capital costs.

Large accelerated filer ¨	Accelerated filer ¨

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

Name	Age	Position	Board Committee(s)(1)
C. Stephen Cochennet	52	President, Chief Executive Officer, Principal Financial Officer and Director	None
Mark Haas	53	Chief Operating Officer and Director	Restructuring
Thomas Kmak	49	Chairman	GCNC, Restructuring and Audit
Loren Moll	53	Director	GCNC, Restructuring (Chairman) and Audit
Darrel G. Palmer	51	Director	GCNC
Dierdre P. Jones(2)	44	Former Chief Financial Officer	None
Robert G. Wonish(3)	55	Former Director	Formerly GCNC (Chairman) and Audit
Daran G. Dammeyer(3)	48	Former Director	Formerly Audit (Chairman) and GCNC
Dr. James W. Rector(3)	48	Former Director	None

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

C. Stephen Cochennet	2010	$	150,000	$	-			-	$	33,333.34	(2)	$	183,333.34
President, Chief Executive Officer	2009	$	186,525	$	50,000			-		-		$	236,525

Dierdre P. Jones(1)	2010	$	140,000	$	20,000	(3)		-		-		$	160,000
Former Chief Financial Officer	2009	$	128,808	$	10,000			-		-		$	138,808

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

C. Stephen Cochennet	2010		-		-		-		-
Dierdre P. Jones	2010		-		-		-		-

Fiscal Year	Potential Grant Date	Maximum # of Options	Strike Price of Options	Option Expiration Date*
2009	7/1/2009	30,000	Fair market value on grant date	6/30/2012
2010	7/1/2010	45,000	Fair market value on grant date	6/30/2013
2011	7/1/2011	60,000	Fair market value on grant date	6/30/2014

Nevada		88-0422242
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

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

		Page
PART I		3
Items 1 and 2.	Business and Properties	3
Item 1A.	Risk Factors	26
Item 1B.	Unresolved Staff Comments	46
Item 3.	Legal Proceedings	46
PART II		46
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	46
Item 6.	Selected Financial Data	50
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	51
Item 7A.	Quantitative and Qualitative Disclosures about Market Risk	63
Item 8.	Financial Statements and Supplementary Data	63
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	64
Item 9A(T).	Controls and Procedures	64
Item 9B.	Other Information	65
Part III		66
Item 10.	Directors, Executive Officers and Corporate Governance	66
Item 11.	Executive Compensation	71
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	75
Item 13.	Certain Relationships and Related Transactions, and Director Independence	77
Item 14.	Principal Accountant Fees and Services	77
Part IV		80
Item 15.	Exhibits, Financial Statement Schedules	80

Name	Fees Earned or Paid in Cash $		Stock Awards $			Option Awards (2) $		All Other Compensation $			Total $
Daran G. Dammeyer(1)	$	27,375	$	15,000	(2)	$	-0-	$	12,375	(3)	$	70,000

Darrel G. Palmer	$	45,000	$	15,000	(2)	$	-0-	$	70,000	(3)	$	46,500

Robert G. Wonish(1)	$	20,625	$	10,000	(2)	$	-0-	$	17,250	(3)	$	49,000

Dr. James W. Rector(1)	$	1,500	$	10,000	(2)	$	-0-	$	11,500	(3)	$	22,500

(1)	Effective April 1, 2010, Messrs. Wonish, Dammeyer and Dr. Rector resigned as members of our board of directors.

(2)	Amount represents the estimated fair market value of shares of common stock issued for board retainer fees for fiscal year ended March 31, 2010 under SFAS 123(R).

(3)	Represents the amount of accrued but unpaid director and committee member fees for fiscal year ended March 31, 2010.

Name and Address of Beneficial Owner, Officer or Director(1)	Number of Shares			Percent of Outstanding Shares of Common Stock(2)
C. Stephen Cochennet, President & Chief Executive Officer(3)		542,061			10.6	%
Mark Haas, Chief Operating Officer and Director		189,000	(4)		3.7	%
Thomas Kmak, Director(3)		228,677	(5)		4.5	%
Darrel G. Palmer, Director(3)		32,000			*
Loren Moll, Director(3)		-0-			*

Directors and Officers as a Group		991,738			19.3	%

West Coast Opportunity Fund LLC(6) West Coast Asset Management, Inc. Paul Orfalea, Lance Helfert & R. Atticus Lowe 2151 Alessandro Drive, #100 Ventura, CA 93001		954,098			18.6	%
Enable Growth Partners L.P.(7) Enable Capital Management, LLC Mitchell S. Levine One Ferry Building, Suite 225 San Francisco, CA 94111		286,270			5.6	%

Plan Category	Number of shares to be issued upon exercise of outstanding options, warrants and rights (a)		Weighted-average exercise price of outstanding options, warrants and rights (b)		Number of shares remaining available for future issuance under equity compensation plans (excluding shares reflected in column (a) (c)
Equity compensation plans approved by stockholders		0		—		—
Equity compensation plans not approved by stockholders		—		—		—
Total		0		—		—

	For the Fiscal Years Ended March 31,
	2010			2009

Audit Fees(1)		$	63,000		$	56,000
Audit-Related Fees(2)			-0-			-0-
Tax Fees(3)			10,000			10,000
All Other Fees(4)						19,718
Total fees of our principal accountant		$	73,000		$	85,718

		Page
Management Responsibility for Financial Information		65
Management’s Report on Internal Control Over Financial Reporting		66
Index to Financial Statements		F-1
Report of Independent Registered Public Accounting Firm		F-2
Consolidated Balance Sheets		F-3
Consolidated Statements of Operations		F-4
Consolidated Statements of Stockholders Equity		F-5
Consolidated Statements of Cash Flows		F-6

Exhibit No.		Description
2.1		Agreement and Plan of Merger between Millennium Plastics Corporation and Midwest Energy, Inc. effective August 15, 2006 (incorporated by reference to Exhibit 2.3 to the Form 8-K filed on August 16, 2006)
3.1		Amended and Restated Articles of Incorporation, as currently in effect (incorporated by reference to Exhibit 3.1 to the Form 10-Q filed on August 14, 2008)
3.2		Amended and Restated Bylaws, as currently in effect (incorporated by reference to Exhibit 3.3 to the Form SB-2 filed on February 23, 2001)
4.1		Article VI of Amended and Restated Articles of Incorporation of Millennium Plastics Corporation (incorporated by reference to Exhibit 1.3 to the Form 8-K filed on December 6, 1999)
4.2		Article II and Article VIII, Sections 3 & 6 of Amended and Restated Bylaws of Millennium Plastics Corporation (incorporated by reference to Exhibit 4.1 to the Form SB-2 filed on February 23, 2001)
4.3		Specimen common stock certificate (incorporated by reference to Exhibit 4.3 to the Form S-1/A filed on May 27, 2008)
10.1		Credit Agreement with Texas Capital Bank, N.A. dated July 3, 2008 (incorporated by reference to Exhibit 10.33 to the Form 10-K filed on July 10, 2008)

10.2		Promissory Note to Texas Capital Bank, N.A. dated July 3, 2008 (incorporated by reference to Exhibit 10.34 to the Form 10-K filed on July 10, 2008)
10.3		Amended and Restated Mortgage, Security Agreement, Financing Statement and Assignment of Production and Revenues with Texas Capital Bank, N.A. dated July 3, 2008 (incorporated by reference to Exhibit 10.35 to the Form 10-K filed on July 10, 2008)
10.4		Security Agreement with Texas Capital Bank, N.A. dated July 3, 2008 (incorporated by reference to Exhibit 10.36 to the Form 10-K filed on July 10, 2008)
10.5		Letter Agreement with Debenture Holders dated July 3, 2008 (incorporated by reference to Exhibit 10.37 to the Form 10-K filed on July 10, 2008)
10.6†		C. Stephen Cochennet Employment Agreement dated August 1, 2008 (incorporated by reference to Exhibit 10.1 to the Form 8-K filed on August 1, 2008)
10.7†		Dierdre P. Jones Employment Agreement dated August 1, 2008 (incorporated by reference to Exhibit 10.2 to the Form 8-K filed on August 1, 2008)
10.8†		Amended and Restated EnerJex Resources, Inc. Stock Incentive Plan (incorporated by reference to Exhibit 10.1 to the Form 8-K filed on October 16, 2008)
10.9		Form of Officer and Director Indemnification Agreement (incorporated by reference to Exhibit 10.2 to the Form 8-K filed on October 16, 2008)
10.10		Euramerica Letter Agreement Amendment dated September 15, 2008 (incorporated by reference to Exhibit 10.10 to the Form 8-K filed on September 18, 2008)
10.11		Euramerica Letter Agreement Amendment dated October 15, 2008 (incorporated by reference to Exhibit 10.11 to the Form 8-K filed on October 21, 2008)
10.12(a) †		C. Stephen Cochennet Rescission of Option Grant Agreement dated November 17, 2008 (incorporated by reference to Exhibit 10.38(a) to the Form 10-Q filed on February 23, 2009)
10.12(b) †		Dierdre P. Jones Rescission of Option Grant Agreement dated November 17, 2008 (incorporated by reference to Exhibit 10.38(b) to the Form 10-Q filed on February 23, 2009)
10.12		Daran G. Dammeyer Rescission of Option Grant Agreement dated November 17, 2008 (incorporated by reference to Exhibit 10.38(c) to the Form 10-Q filed on February 23, 2009)
10.12(d)		Darrel G. Palmer Rescission of Option Grant Agreement dated November 17, 2008 (incorporated by reference to Exhibit 10.38(d) to the Form 10-Q filed on February 23, 2009)
10.12(e)		Dr. James W. Rector Rescission of Option Grant Agreement dated November 17, 2008 (incorporated by reference to Exhibit 10.38(e) to the Form 10-Q filed on February 23, 2009)
10.12(f)		Robert G. Wonish Rescission of Option Grant Agreement dated November 17, 2008 (incorporated by reference to Exhibit 10.38(f) to the Form 10-Q filed on February 23, 2009)
10.13		Letter Agreement with Debenture Holders dated June 11, 2009 (incorporated by reference to Exhibit 10.1 to the Form 8-K filed on June 16, 2009)
10.14		Joint Operating Agreement with Pharyn Resources to explore and develop the Brownrigg Lease Press Release dated June 1, 2009 (incorporated by reference to Exhibit 99.1 to the Form 8-K filed on June 5, 2009)
10.15		Amendment 4 to Joint Exploration Agreement effective as of November 6, 2008 between MorMeg, LLC and EnerJex Resources, Inc. (incorporated by reference to Exhibit 10.15 to the Form 10-K filed July 14, 2009)
10.16		Waiver from Texas Capital Bank, N.A. dated July 14, 2009 (incorporated by reference to Exhibit 10.16 to Form 10-K filed July 14, 2009)
10.17		First Amendment to Credit Agreement dated August 18, 2009 (incorporated by reference to the Exhibit 10.12 to the Form 10-Q filed August 18, 2009)
10.18		Debenture Holder Amendment Letter dated November 16, 2009 (incorporated by reference to the Exhibit 10.13 to the Form 10-Q filed November 20, 2009)

10.19		Standby Equity Distribution Agreement with Paladin Capital Management, S.A. dated December 3, 2009 (incorporated by reference to Exhibit 10.52 to the Form S-1 filed on December 9, 2009)
10.20		Amendment 5 to Joint Exploration Agreement effective as of December 31, 2009 between MorMeg LLC and EnerJex Resources, Inc. (incorporated by reference to Exhibit 10.15 to the Form 10-Q filed on February 16, 2010)
10.21		Second Amendment to Credit Agreement dated January 13, 2010 (incorporated by reference to Exhibit 10.16 to the Form 10-Q filed on February 16, 2010)
10.22		Debenture Holder Amendment Letter dated January 27, 2010 (incorporated by reference to Exhibit 10.17 to the Form 10-Q filed on February 16, 2010)
10.23		Waiver from Texas Capital Bank, N.A. dated February 10, 2009 (incorporated by reference to Exhibit 10.18 to the Form 10-Q filed on February 16, 2010)
10.24		Amendment 6 to Joint Exploration Agreement effective as of March 31, 2010 between MorMeg LLC and EnerJex Resources, Inc. (incorporated by reference to Exhibit 10.24 to the Form 10-K filed on July 15, 2010)
10.25		Debenture Holder Amendment Letter dated April 1, 2010 (incorporated by reference to Exhibit 10.25 to the Form 10-K filed on July 15, 2010)
21.1		List of Subsidiaries
23.1		Miller & Lents, Ltd. Consent Of Independent Petroleum Engineers and Geologists Letter dated November 12 and effective March 31, 2010
23.2		Consent of Weaver & Martin, LLC
31.1		Certification of Chief Executive and Principal Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
32.1		Certification of Chief Executive and Principal Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

ENERJEX RESOURCES, INC.

By:	/s/ C. Stephen Cochennet
	C. Stephen Cochennet, Chief Executive Officer

Date: November 12, 2010

Name	Title	Date

/s/ C. Stephen Cochennet	President, Chief Executive Officer,	November 12, 2010
C. Stephen Cochennet	(Principal Executive Officer),
	Secretary, Chairman

/s/ Tom Kmak	Director	November 12, 2010
Tom Kmak

/s/ Loren Moll	Director	November 12, 2010
Loren Moll

/s/ Darrel G. Palmer	Director	November 12, 2010
Darrel G. Palmer

	March 31,
	2010 (Restated)			2009

Assets
Current assets:
Cash	$	169,163		$	127,585
Accounts receivable		330,102			462,044
Prepaid debt issue costs		-			45,929
Deposits and prepaid expenses		166,418			263,383
Total current assets		665,683			898,941

Fixed assets		371,885			365,019
Less: Accumulated depreciation		120,545			63,988
Total fixed assets		251,340			301,031

Other assets:
Oil and gas properties using full-cost accounting:
Properties not subject to amortization		-			31,183
Properties subject to amortization		6,093,033			6,449,023
Total other assets		6,093,033			6,480,206
Total assets	$	7,010,056		$	7,680,178

Liabilities and Stockholders’ Equity (Deficit)
Current liabilities:
Accounts payable	$	877,511		$	1,016,168
Accrued liabilities		417,142			87,811
Derivative liability		1,184,178			-
Convertible note payable		25,000			-
Long-term debt, current		9,182,679			1,723,036
Total current liabilities		11,686,510			2,827,015

Asset retirement obligation		883,589			803,624
Derivative liability		2,364,068
Convertible note payable		-			25,000
Long-term debt, net of discount at March 31, 2009 of $596,108		43,440			7,818,163
Total liabilities		14,977,607			11,473,802
Contingencies and commitments
Stockholders’ Equity (Deficit):
Preferred stock, $0.001 par value, 10,000,000 shares authorized, no shares issued and outstanding		-			-
Common stock, $0.001 par value, 100,000,000 shares authorized; shares issued and outstanding –5,053,189 at March 31, 2010 and 4,443,512 at March 31, 2009 and 4,836 of owned but not issued stock at March 31, 2010		5,058			4,444
Paid in capital		9,505,417			8,932,906
Retained (deficit)		(17,478,026	)		(12,730,974	)
Total stockholders’ equity (deficit)		(7,967,551	)		(3,793,624	)

Total liabilities and stockholders’ equity (deficit)	$	7,010,056		$	7,680,178

	For the Fiscal Years Ended
	March 31,
	2010 (Restated)			2009

Oil and natural gas revenues	$	4,856,027		$	6,436,805

Expenses:
Direct operating costs		1,833,108			2,637,333
Depreciation, depletion and amortization		635,497			911,293
Impairment of oil and gas properties		-			4,777,723
Professional fees		561,625			1,320,332
Salaries		835,576			849,340
Administrative expense		1,016,484			1,392,645
Total expenses		4,882,290			11,888,666

Loss from operations		(26,263	)		(5,451,861	)

Other income (expense):
Interest expense		(751,470	)		(882,426	)
Loan interest accretion		(596,108	)		(2,814,095	)
Gain on liquidation of hedging instrument		-			3,879,050
Gain on repurchase of debentures		436,500			-
Loss on derivatives		(3,911,063	)		-
Other Gain/(Loss)		101,352			(37,736	)
Total other income (expense)		(4,720,789	)		144,793

Net income - (loss)	$	(4,747,052	)	$	(5,307,068	)

Weighted average shares outstanding - basic		4,743,774			4,443,249

Net income (loss) per share - basic	$	(1.00	)	$	(1.19	)

	Common Stock
	Shares			Par Value			Paid in Capital			Retained Deficit			Total Stockholders’ Equity (Deficit)

Balance, April 1, 2008		4,440,651		$	4,441		$	8,853,457		$	7,423,906	)	$	1,433,992

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

Stock issued for services and interest		365,416			370			328,422			-			328,792
Stock issued for employees and directors		314,261			314			274,019			-			274,333
Stock redeemed and cancelled		(70,000	)		(70	)		(29,930	)		-			(30,000	)
Net loss for the year		-			-			-			(4,747,052	)		(4,747,052	)
Balance, March 31, 2010, (Restated)		5,053,189		$	5,058		$	9,505,417		$	(17,478,026	)	$	$(7,967,551	)

	Options			Weighted Ave. Exercise Price			Warrants		Weighted Ave. Exercise Price
Outstanding April 1, 2008		458, 500		$	6.30			75,000	$	3.00
Granted		-			-			-		-
Cancelled		(20,000	)		(6.25	)		-		-
Exercised		-			-			-		-
Outstanding March 31, 2009		438,500		$	6.30			75,000	$	3.00
Granted		-			-			-		-
Cancelled		(438,500	)		(6.30	)		-		-
Exercised		-			-			-		-
Outstanding March 31, 2010		-			-			75,000	$	3.00

Asset retirement obligation at April 1, 2008	$	459,689
Liabilities incurred during the period		283,071
Liabilities settled during the period		-
Accretion		60,864
Asset retirement obligations, March 31, 2009		803,624
Liabilities incurred during the period		4,281
Liabilities settled during the period		-
Accretion		75,684
Asset retirement obligations, March 31, 2010	$	883,589

Credit Facility	$	6,691,000
Debentures		2,468,045
Vehicle notes payable		67,074
Total long-term debt		9,226,119
Less current portion		(9,182,679	)
Long-term debt	$	43,440

	March 31, 2010 (Restated)			March 31, 2009
Proven	$	9,131,405		$	8,866,979
Unevaluated and unproved		-			31,183
Accumulated depreciation and depletion		(2,406,372	)		(1,817,956	)
Sale of properties		(632,000	)		(600,000	)
Net capitalized costs	$	6,093,033		$	6,480,206

	March 31, 2010		March 31, 2009
Acquisition of proved and unproved properties	$	-	$	123,040
Development costs		228,962		2,999,963
Exploration costs		-		-
Total	$	228,962	$	3,123,003

	March 31, 2010			March 31, 2009
Non-current deferred tax asset:
Impaired oil & gas costs and long-lived assets	$	1,825,000		$	1,864,700
Derivative instruments		1,206,400			—
Net operating loss carry-forward		3,263,000			2,754,600
Valuation allowance		(6,294,400	)		(4,619,300	)
Total deferred tax net	$	-		$	-

	March 31, 2010			March 31, 2009
Statutory tax rate		34.0	%		34.0	%
Equity based compensation		-	%		(1.0	)%
Derivative instruments		(24.4	)%		-	%
Oil & gas costs and long-lived assets		(.8	)%		(29.0	) %
Change in valuation allowance		(10.4	)%		(4.0	) %
Effective tax rate		-	%		-	%

			Fair Value Measurement
	Total Amount		Level 1		Level 2		Level 3
Crude oil contracts	$	3,548,245	$	-	$	3,548,245	$	-

	Term	Monthly Volumes	Price per Bbl		Fair Value
Crude oil swap	4/10-12/13	2,266 Bbl	$	57.30	$	(3,428,307	)
Crude oil swap	4/10-3/11	963 Bbls	$	77.05	$	(119,938	)
					$	(3,548,245	)

	March 31, 2010 (Restated)			March 31, 2009
Production revenues	$	4,856,027		$	6,436,805
Production costs		(1,833,108	)		(2,637,333	)
Depletion and depreciation		(588,416	)		(892,871	)
Results of operations for producing activities	$	2,434,503		$	2,906,601

	March 31, 2010 (Restated)					March 31, 2009
	Gas-mcf		Oil-stb			Gas-mcf			Oil-stb
Proved reserves:
Beginning		-		1,336,630			401,197			1,372,014
Revisions of previous estimates				1,203,318			(394,732	)		(14,375	)
Purchase of minerals in place		-					-			53,280
Extensions and discoveries		-					-
Production				(64,948	)		(6,465	)		(74,289	)
Total		-		2,475,000			-			1,336,630

	March 31, 2010 (Restated)			March 31, 2009
Future production revenue	$	155,034,940		$	57,007,970
Future production costs		(58,706,390	)		(24,732,440	)
Future development costs		(16,330,000	)		(9,584,500	)
Future cash flows before income taxes		79,998,550			22,691,030
Future income taxes		18,999,000			-
Future net cash flows		60,999,550			22,691,030
10% annual discount for estimating of future cash flows		(37,921,028	)		(12,061,690	)
Standardized measure of discounted net cash flows	$	23,078,522		$	10,629,340

	March 31, 2010 (Restated)			March 31, 2009
Balance beginning of year	$	10,629,340		$	28,200,503
Sales, net of production costs		(3,039,640	)		(5,697,410	)
Net change in pricing and production costs		9,558,455			(31,927,063	)
Net change in future estimated development costs		(3,894,180	)		9,220,510
Purchase of minerals in place		-			136,190
Extensions and discoveries		-			518,297
Revisions		16,288,287			(1,089,039	)
Accretion of discount		310,890			(143,477	)
Change in income tax		(6,774,630	)		11,410,829
Balance end of year	$	23,078,522		$	10,629,340

	For Fiscal Year Ended March 31, 2010
	As Previously Stated			Adjustments		As Restated
Assets
Current assets:
Cash	$	169,163		$	-	$	169,163
Accounts receivable		330,102			-		330,102
Prepaid debt issue costs		-			-		-
Deposits and prepaid expenses		166,418			-		166,418
Total current assets		665,683			-		665,683

Fixed assets		371,885			-		371,885
Less: Accumulated depreciation		120,545					120,545
Total fixed assets		251,340			-		251,340

Other assets:
Oil and gas properties using full-cost accounting:
Properties not subject to amortization		-			-		-
Properties subject to amortization		5,891,994			201,039		6,093,033
Total other assets		5,891,994			201,039		6,093,033
Total assets	$	6,809,017		$	201,039	$	7,010,056

Liabilities and Stockholders’ Equity (Deficit)
Current liabilities:
Accounts payable	$	877,511		$	-	$	877,511
Accrued liabilities		417,142			-		417,142
Derivative liability		1,184,178			-		1,184,178
Convertible note payable		25,000			-		25,000
Long-term debt, current		9,182,679			-		9,182,679
Total current liabilities		11,686,510			-		11,686,510

Asset retirement obligation		883,589			-		883,589
Derivative liability		2,364,068			-		2,364,068
Convertible note payable		-			-		-
Long-term debt, net of discount at March 31, 2009 of $596,108		43,440			-		43,440
Total liabilities		14,977,607			-		14,977,607
Contingencies and commitments
Stockholders’ Equity (Deficit):
Preferred stock, $0.001 par value, 10,000,000 shares authorized, no shares issued and outstanding		-			-		-
Common stock, $0.001 par value, 100,000,000 shares authorized; shares issued and outstanding –5,053,189 at March 31, 2010 and 4,443,512 at March 31, 2009 and 4,836 of owned but not issued stock at March 31, 2010		5,058			-		5,058
Paid in capital		9,505,417			-		9,505,417
Retained (deficit)		(17,679,065	)		201,039		(17,478,026	)
Total stockholders’ equity (deficit)		(8,168,590	)		201,039		(7,967,551	)

Total liabilities and stockholders’ equity (deficit)	$	6,809,017		$	201,039	$	7,010,056