SEC Info℠

Home

Search

My Interests

Help

Sign In

Please Sign In

EnerJex Resources, Inc. – ‘10-KT’ for 12/31/10

On:  Thursday, 4/21/11, at 4:18pm ET   ·   For:  12/31/10   ·   Accession #:  1193125-11-105207   ·   File #:  0-30234

in

this entire Filing. an “Entity” Search.

Show

Documents searched

and

each “hit”. the 1st “hit”.

↓↑Hints

 Text Wildcards:  ? (any letter/digit),  * (many).  Search Logic:  for Documents:  & (and),  | (or);  for Text:  | (anywhere),  "(&)" (near).  Details... 

  As Of                Filer                Filing    For·On·As Docs:Size              Issuer               Agent

 4/21/11  EnerJex Resources, Inc.           10-KT      12/31/10    8:1.2M                                   RR Donnelley/FA

Document/Exhibit                   Description                      Pages   Size 

 1: 10-KT       Transition Report on Form 10-K                      HTML    834K 
 2: EX-10.33    Third Amendment to Credit Agreement Dated           HTML     35K 
                          September 29, 2010                                     
 3: EX-10.34    Fourth Amendment to Credit Agreement Dated          HTML     41K 
                          December 31, 2010                                      
 4: EX-21.1     List of Subsidiaries                                HTML      8K 
 5: EX-23.1     Miller & Lents, Ltd. Consent of Independent         HTML      9K 
                          Petroleum Engineers and Geologists                     
 6: EX-23.2     Consent of Weaver & Martin, LLC                     HTML      7K 
 7: EX-31.1     Certification of Chief Executive and Principal      HTML     14K 
                          Financial Officer - Section 302                        
 8: EX-32.1     Certification of Chief Executive and Principal      HTML      9K 
                          Financial Officer - Section 906                        

Table of Contents

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

For the transition period from April 1, 2010 to December 31, 2010

Commission file number 000-30234

ENERJEX RESOURCES, INC.

(Exact name of registrant as specified in its charter)

(210) 451-5545

(Registrant’s telephone number, including area code)

Securities registered pursuant to Section 12(b) of the Exchange Act:

Name of each exchange on which registered:

Securities registered pursuant to Section 12(g) of the Exchange Act: Common Stock, $0.001 par value

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.     ¨  Yes    x  No

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Act.    ¨  Yes    x  No

Indicate by checkmark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    x  Yes    ¨  No

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    ¨  Yes    x  No

Indicate by checkmark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  ¨

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

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

State the aggregate market value of the voting and non-voting common equity held by non-affiliates computed by reference to the price at which the common equity was last sold, or the average bid and asked price of such common equity, as of the last business day of the registrant’s most recently completed second fiscal quarter: $1,283,657 based on a share value of $0.25.

Indicate the number of shares outstanding of each of the registrant’s classes of common stock, as of the latest practicable date: 69,355,279 shares of common stock, $0.001 par value, outstanding on April 18, 2011.

DOCUMENTS INCORPORATED BY REFERENCE

List hereunder the following documents if incorporated by reference and the Part of the Form 10-K (e.g., Part I, Part II, etc.) into which the document is incorporated: (1) Any annual report to security holders; (2) Any proxy or information statement; and (3) Any prospectus filed pursuant to Rule 424(b) or (c) under the Securities Act of 1933. The listed documents should be clearly described for identification purposes (e.g., annual report to security holders for fiscal year ended December 24, 1980).

NONE.

Table of Contents

ENERJEX RESOURCES, INC.

FORM 10-K

TABLE OF CONTENTS

i

Table of Contents

FORWARD-LOOKING STATEMENTS

This Transition Report on Form 10-K contains forward-looking statements that involve risks and uncertainties. The statements contained in this document that are not purely historical are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, or the Securities Act, and Section 21E of the Securities Exchange Act of 1934, as amended, or the Exchange Act. Forward-looking statements are statements regarding future events, our future financial performance, and include statements regarding projected operating results. These forward-looking statements are based on current expectations, beliefs, intentions, strategies, forecasts and assumptions and involve a number of risks and uncertainties that could cause actual results to differ materially from those anticipated by these forward-looking statements. We have attempted to identify forward-looking statements by terminology including “anticipates,” “believes,” “can,” “continue,” “could,” “estimates,” “expects,” “intends,” “may,” “plans,” “potential,” “predicts” or “should” or the negative of these terms or other comparable terminology. Although we do not make forward-looking statements unless we believe we have a reasonable basis for doing so, we cannot guarantee their accuracy. Moreover, we operate in a very competitive and rapidly changing environment. New risks emerge from time to time and it is not possible for us to predict all risk factors, nor can we address the impact of all factors on our business or the extent to which any factor, or combination of factors, may cause our actual results to differ materially from those contained in any forward-looking statements. All forward-looking statements included in this document are based on information available to us on the date of this Transition Report on Form 10-K, and we assume no obligation to update any such forward-looking statements, except as may otherwise be required by law.

Our actual results could differ materially from those anticipated in these forward-looking statements as a result of certain factors, including those set forth in the “Risk Factors” section in Part I, Item 1A of this Transition Report on Form 10-K and elsewhere in this document. The factors impacting these risks and uncertainties include, but are not limited to:

All references in this report to “we,” “us,” “our,” “company” and “EnerJex” refer to EnerJex Resources, Inc. and our wholly-owned operating subsidiaries, EnerJex Kansas, Inc., DD Energy, Inc., Black Sable Energy, LLC and Working Interest, LLC, unless the context requires otherwise. We report our financial information on the basis of a nine-month transition period from April 1, 2010 to December 31, 2010. We have provided definitions for the oil industry terms used in this report in the “Glossary” beginning on page 12 of this report.

ii

Table of Contents

AVAILABLE INFORMATION

We file annual, quarterly and other reports and other information with the SEC. You can read these SEC filings and reports over the Internet at the SEC’s website at www.sec.gov or on our website at www.enerjexresources.com. You can also obtain copies of the documents at prescribed rates by writing to the Public Reference Section of the SEC at 100 F Street, NE, Washington, DC 20549 on official business days between the hours of 10:00 am and 3:00 pm. Please call the SEC at (800) SEC-0330 for further information on the operations of the public reference facilities. We will provide a copy of our annual report to security holders, including audited financial statements, at no charge upon receipt to of a written request to us at EnerJex Resources, Inc., 1600 NE Loop 410, Suite 104, San Antonio, Texas 78209.

INDUSTRY AND MARKET DATA

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

iii

Table of Contents

PART I

ITEMS 1 AND 2. BUSINESS AND PROPERTIES.

Change in Fiscal Year End

On January 21, 2011, our board of directors approved the change in our fiscal year end from March 31 to December 31, effective December 31, 2010. As a result of this change, this Annual Report on Form 10-K is a transition report and includes financial information for the nine-month transition period from April 1, 2010 to December 31, 2010, or Transition Period. References in this Transition Report on Form 10-K to fiscal year 2010 or fiscal 2010 refer to the period of April 1, 2009 through March 31, 2010 and references to fiscal year 2009 or fiscal 2009 referred to the period of April 1, 2008 through March 31, 2009. Subsequent to this Transition Report on Form 10-K, our reports on Form 10-K will cover the calendar year from January 1 to December 31, with historical periods remaining unchanged.

Company History

We were formerly known as Millennium Plastics Corporation and were incorporated in the State of Nevada on March 31, 1999. We abandoned a prior business plan focusing on the development of biodegradable plastic materials. In August 2006, we acquired Midwest Energy, Inc., a Nevada corporation pursuant to a reverse merger. After the merger, Midwest Energy became a wholly-owned subsidiary, and as a result of the merger the former Midwest Energy stockholders controlled approximately 98% of our outstanding shares of common stock. We changed our name to EnerJex Resources, Inc. in connection with the merger, and in November 2007 we changed the name of Midwest Energy (now our wholly-owned subsidiary) to EnerJex Kansas, Inc. All of our current operations are conducted through EnerJex Kansas, and all leasehold interests are held in DD Energy, Inc., Black Sable Energy, LLC and Working Interest, LLC, our wholly-owned subsidiaries.

Significant Developments in Transition Period 2010

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

1

Table of Contents

Our Business

Our principal strategy is to acquire, develop, explore and produce domestic onshore oil properties. Our business activities are currently focused in Eastern Kansas and South Texas. We have provided definitions for the oil industry terms used in this report in the “Glossary” beginning on page 12.

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 December 31, 2010 was approximately 2.32 million barrels of oil equivalent, or BOE. Of the 2.32 million BOE of total proved reserves, approximately 29% are proved developed and approximately 71% are proved undeveloped. The proved developed reserves are 100% proved developed producing reserves.

The total PV10 (present value) of our proved reserves (“PV10”) as of December 31, 2010 was approximately $31.2 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 33, for a reconciliation to the comparable GAAP financial measure.

Except where noted:

do not include Texas assets acquired in the series of transactions closing on December 31, 2010.

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, 2010 and 2009, 40.5 million barrels and 39.5 million barrels of oil were produced in Kansas. Of the total barrels produced in Kansas in the calendar year ended December 31, 2010, 20 companies accounted for approximately 34% of the total production, with the remaining 66% produced by over 2,000 active producers.

In addition to significant historical oil 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 development activities:

2

Table of Contents

Our Kansas Properties

The table below summarizes our current Eastern Kansas acreage by project name as of December 31, 2010.

The table below summarizes proved reserves on all Eastern Kansas properties as of December 31, 2010:

Black Oaks Project

Effective December 31, 2010, we entered into a Joint Operating Agreement and a Joint Development Agreement with a shareholder, Haas Petroleum, LLC (Haas), and MorMeg, LLC, (MorMeg), which are controlled by Mark Haas, whereby we agreed to elect Haas to be the operator of the Black Oaks Project in exchange for 100,000 shares of our common stock. In addition, we agreed to assign to MorMeg a 5% overriding royalty interest (ORRI) covering all leases on the Black Oaks Project, and a 10% working interest on all leases in the Black Oaks Project. We also agreed to fund MorMeg’s 10% working interest for all future capital expenditure costs invested in the Black Oaks Project until the sooner of (i) 5 years or (ii) we fund an aggregate $500,000 on behalf of MorMeg’s 10% working interest in the Black Oaks Project (capital expenditure costs apply to new producer and injector wellbores, and specifically excludes lease operating expenses). Our prior Joint Exploration Agreement dated April 9, 2007, as amended, with MorMeg has been terminated.

The Black Oaks Project encompasses approximately 2,100 gross acres in Woodson and Greenwood Counties, Kansas, and all leases are held-by-production (see “Glossary” on page 13 for definition of held-by-production). At the time of acquisition the Black Oaks Project had approximately 35 oil wells producing an average of approximately 32 barrels of oil per day, or BOPD. There are currently 67 producing wellbores and 13 injector wellbores on this project. The project is currently producing approximately 75 gross BOPD and we will focus a significant portion of the 2011 capital expenditure budget on this project. We have identified 34 additional producer locations and 45 additional injector locations on currently producing leases in this project.

Tri-County Project

On September 14, 2007, we acquired 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.

We currently have 1,262 gross acres leased in this project area and all leases are held-by-production. As of December 31, 2010, we had 207 oil wells producing an average of approximately 48 BOPD; along with 74 water injection wells and two water supply wells. We have identified a significant number of development locations and several remediation projects within this project area and we intend to devote a significant portion of our 2011 capital expenditure budget to this project.

We have identified 122 additional producer locations and 135 additional injector locations on currently producing leases in this project.

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. The original acquisition terms of this working interest include a revisionary right based on project payout. The project achieved there payout hurdles in November 2010, at which the revisionary right was triggered and our working interest was reduced to 75%. We reacquired a 12.5% interest as part of the series of transactions that closed effective December 31, 2010. As a result we have 87.5% working interest and there are no additional revisionary interests.

We currently have 405 gross acres leased in this project area and all leases are held-by-production. As of December 31, 2010, we had 42 oil wells producing an average of approximately 24 BOPD; along with 17 water injection wells and one water supply well. We have identified 15 additional producer locations and 17 additional injector locations on currently producing leases in 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.

3

Table of Contents

We currently have 880 gross acres leased in this project area and all leases are held-by-production. As of December 31, 2010, we had 129 oil wells producing an average of approximately 48 BOPD; along with 71 water injection wells and two water supply wells. We have identified 32 additional producer locations and 20 additional injector locations on currently producing leases in this project.

Working Interest Project

As part of the series of transactions that closed effective December 31, 2010, we acquired Working Interest, LLC, which holds an 80% working interest in certain producing and non-producing oil leases in Eastern Kansas, a substantial majority of which are in close proximity to our other oil leases. We currently have 1,869 gross acres leased in this project area and all leases are held-by-production. As of December 31, 2010, we had 148 oil wells producing an average of approximately 55 BOPD; along with 70 water injection wells and one water supply well.

A majority of the producing leasehold in this project area consists of newly drilled leases with virgin production, resulting in a significant amount of original oil in place remaining. We intend to add enhanced oil recovery operations to several of these leases during 2011 in order to increase production and accelerate oil recovery.

We have identified 51 additional producer locations and 49 additional injector locations on currently producing leases in this project.

Gas City Project

In August of 2007, we entered into a development agreement with Euramerica Energy, Inc., 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 required 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.

We still maintain some leaseholds within the Gas City Project, and we currently are analyzing the acreage position for potential oil prospects. Two of our leases in this project area are currently producing approximately 5 BOPD from 5 wells.

The Opportunity in South Texas

Technological advances in the oil industry have made great strides over the last decade, especially in the area of completion technologies, mainly through horizontal drilling and artificial fracture stimulation. Multiple sizeable oil deposits were discovered in South Texas during past decades, but operators lacked the technology to produce economically from these reservoirs at the time of discovery. The availability of modern completion technologies coupled with the current commodity price environment provide an opportunity for operators to economically produce oil from reservoirs that were discovered in the past, yet never fully developed due to technology and economic constraints.

Our Texas Properties

Our Texas properties were acquired through the acquisition of Black Sable Energy LLC, as part of a series of transactions that closed effective December 31, 2010. Black Sable Energy is now a wholly-owned subsidiary based in San Antonio, Texas. The Company’s Texas activities currently are focused on two project areas, the El Toro Project and the Lonesome Dove Project, with approximately 9,000 gross acres under lease. A brief overview of each project is as follows:

4

Table of Contents

El Toro Project

We continually evaluate and research our completion designs and procedures and intend to drill additional wells in 2011 to increase our oil production and test new completion designs. The El Toro Project is currently producing approximately 50 gross BOPD and we own varying non-operated working interests of 40%-49%, a small portion of which is held-by-production.

Lonesome Dove Project

We do not currently have producing wells in the Lonesome Dove Project and none of the acreage is held-by-production.

Our Business Strategy

Our principal strategy in Kansas is to focus on the acquisition and development of oil 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 principal strategy in Texas is to identify, acquire and develop leases covering known oil deposits that were never fully developed due to poor reservoir quality and low historical prices. Once acquired, subject to availability of capital, we strive to implement a development program utilizing capital resources, an experienced management and technical team, and modern fracture stimulation to attempt to increase production and demonstrate the economic viability of a larger scale development program in an effort to increase returns for our stockholders. Our oil operations are currently focused in Eastern Kansas and South Texas, with a near term focus on Eastern Kansas due to what we believe are temporary constraints of services and equipment in South Texas as a result of the rapidly developing Eagle Ford Shale play. Depending on availability of capital, and other restraints, our goal is to increase stockholder value by finding and developing oil reserves at costs that provide an attractive rate of return on our investments. The principal elements of our business strategy are:

5

Table of Contents

We are continually evaluating oil opportunities in Eastern Kansas and South Texas and plan to enter into joint venture arrangements with partners who would contribute capital and or operational expertise to develop leases we currently own or would acquire as part of a joint venture arrangement. 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 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 joint venture 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 oil; (iii) the market price for oil; 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 crude oil 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 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 hedging strategy that will allow management to hedge up to 80% of our net production.

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.

On December 31, 2010, we entered into a Joint Operating Agreement and a Joint Development Agreement with a shareholder, Haas Petroleum, LLC (Haas), and MorMeg, LLC, (MorMeg), which are controlled by Mark Haas, whereby Haas agreed to be the operator of the Black Oaks Project in exchange for 100,000 shares of our common stock. In addition, we assigned to MorMeg a 5% overriding royalty interest covering all leases on the Black Oaks Project, and a 10% working interest on all leases in the Black Oaks Project. We also agreed to fund MorMeg’s 10% working interest for all future capital expenditure costs invested in Black Oaks Project until the sooner of (i) 5 years or (ii) we fund an aggregate $500,000 on behalf of MorMeg’s 10% working interest in the Black Oaks Project (capital expenditure costs apply to new producer and injector wellbores, and specifically excludes lease operating expenses). The previous Joint Exploration Agreement dated April 9, 2007, between MorMeg and us, has been terminated. The Black Oaks Project encompasses approximately 2,100 gross acres in Woodson and Greenwood Counties, Kansas.

Drilling Activity

The following table sets forth the results of our drilling activities during the 2008, 2009 and 2010 fiscal years. These results exclude drilling operations that occurred, at the projects owned by Black Sable Energy, LLC and Working Interest, LLC; prior to the consummation of the transactions we closed on December 31, 2010.

6

Table of Contents

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

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

Results of Oil Producing Activities

The following table shows the results of operations from our oil producing activities from the nine-month transition period ended December 31, 2010, and fiscal years ended March 31, 2010 and 2009. Results of operations from these activities have been determined using historical revenues, production costs, depreciation, depletion and amortization of the capitalized costs subject to amortization. General and administrative expenses and interest expense have been excluded from this determination.

7

Table of Contents

Producing Wells

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

Eastern Kansas Reserves

Our estimated total proved PV10 (present value) before tax of reserves as of December 31, 2010 was $31.2 million, versus $29.9 million as of March 31, 2010. Of the 2.3 million net BOE at December 31, 2010 approximately 29% are proved developed and approximately 71% are proved undeveloped. See “Glossary” on page 14 for our definition of PV10.

Based on an estimated oil price of $72.43 as of December 31, 2010, and applying an annual discount rate of 10% of the future net cash flow, the estimated PV10 of the 2.3 million BOE, before tax, is calculated as set forth in the following table:

Summary of Oil Reserves

as of December 31, 2010

Oil Reserves Reported to Other Agencies

We did not file any estimates of total proved net oil reserves with, or include such information in reports to, any federal authority or agency, other than the SEC, during the nine-month transition period ended December 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 a lien 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 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 creates a greater risk of title defects.

8

Table of Contents

Sale of Oil

We do not intend to refine our 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 are currently selling oil to Coffeyville Resources and Pacer Energy Marketing, LLC on a month-to-month basis (i.e., without a long-term contract). We also have an ISDA master agreement and a fixed price swap with BP through December 31, 2015 and a fixed price swap with Pacer through December 31, 2012. 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 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 5% 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 in Eastern Kansas.

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 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 properties will help us reduce drilling risks, lower finding costs and provide for more efficient production of oil from our properties.

Markets and Marketing

The oil industry has experienced dramatic price volatility in recent years, and especially in recent months. Because oil is a commodity, global 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 Middle East, 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 oil pipelines, and general fluctuations of global and domestic supply and demand. We have currently entered into two month-to-month sales contracts with Coffeeville Resources and Pacer Energy Marketing, and we do not anticipate difficulty in finding additional sales opportunities, as and when needed.

Oil sales prices are negotiated based on factors such as the 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. Oil prices have historically experienced high volatility, related in part to ever-changing perceptions within the industry of future supply and demand.

Competition

The 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

9

Table of Contents

competitors to sustain the impact of higher exploration and production costs, 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

Our oil 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 and Texas, 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 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.

The price we may receive from the sale of oil 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.

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:

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.

10

Table of Contents

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

We currently have 18 full-time employees, including field personnel. 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 1600 N.E. Loop 410, Suite 104, San Antonio, Texas 78209, under a lease which expires in June 2011. We also have an office located at 27 Corporate Woods, Suite 350, 10975 Grandview Drive, Overland Park, Kansas 66210, the lease for which expires in September 30, 2013.

11

Table of Contents

GLOSSARY

12

Table of Contents

13

Table of Contents

14

Table of Contents

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 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, and worsening geopolitical 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 2 years, 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.

In addition, actual and attempted terrorist attacks in the United States, Middle East, Southeast Asia and Europe, and war or armed hostilities in the Middle East, Iran, North Korea or elsewhere, or the fear of such events, could further exacerbate the volatility and disruption to the financial markets and economy. The situation in Iraq and Afghanistan, tension over Iran’s nuclear program, and more recently the events in Libya, Tunisia and Egypt that resulted in changes to long-standing regimes and other regimes in the Middle East and North Africa have lead to further instability in the worldwide economy.

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 industry. There is nothing conclusive at this time on which to base an assumption that our business operations will prove to be successful or that we will be able to operate profitably. Our future operating results will depend on many factors, including:

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

15

Table of Contents

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 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 oil 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.

Oil prices are volatile. Future volatility may cause 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 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.

Oil prices are subject to wide fluctuations in response to relatively minor changes in or perceptions regarding supply and demand. Historically, the markets for 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:

16

Table of Contents

It is impossible to predict oil price movements with certainty. Lower oil prices may not only decrease our future revenues on a per unit basis but also may reduce the amount of oil that we can produce economically. A substantial or extended decline in 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, oil prices do not necessarily move together.

Approximately 71% of our total proved reserves as of December 31, 2010 consist of undeveloped and developed non-producing reserves, and those reserves may not ultimately be developed or produced.

Our estimated total proved PV10 (present value) before tax of reserves as of December 31, 2010 was $31.2 million, versus $29.9 million as of March 31, 2010. Of the 2.3 million net BOE at December 31, 2010, approximately 29% are proved developed and approximately 71% are proved undeveloped. These figures include the assets acquired in the series of transactions that closed effective December 31, 2010. See “Glossary” on page 14 for our definition of PV10.

As of December 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 December 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 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 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 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 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 oil properties also will be affected by factors such as:

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

17

Table of Contents

The differential between the New York Mercantile Exchange, or NYMEX, or other benchmark price of oil 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 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 December of 2015, the differential on physical sales after that date is still under negotiation. We cannot accurately predict oil 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, have resulted in both increases and decreases in the differential between the benchmark price for oil 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 production in comparison to what we would receive if not for the differential.

The 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 an 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 oil business involves a variety of operating risks, including:

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

18

Table of Contents

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, and any material inaccuracies in our forecasted drilling costs, estimates or underlying assumptions will materially affect our business.

Developing and exploring for 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 an oil well does not ensure a profit on investment. Exploratory wells bear a much greater risk of loss than development wells. Substantially all of our wells drilled through December 31, 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 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 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 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 reservoirs generally are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Our future oil production, and, therefore our cash flow and income, are highly dependent on our success in efficiently developing and exploiting our current reserves and economically finding or acquiring additional recoverable reserves. We may be unable to make such acquisitions because we are:

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

In order to exploit successfully our current oil lease and others that we acquire in the future, we will need to generate significant amounts of capital.

The oil exploration, development and production business is a capital-intensive undertaking. In order for us to be successful in acquiring, investigating, developing, and producing oil from our current mineral leases and other leases that we may acquire in the future, we will need to generate an amount of capital in excess of that generated from our results of operations. In order to generate that additional capital, we may need to obtain an expanded debt facility and to issue additional shares of our equity securities. There

19

Table of Contents

can be no assurance that we will be successful in ether obtaining that expanded debt facility or issuing our equity securities, and our inability to generate the needed additional capital may have a material adverse effect on our prospects and financial results of operations. If we are able to issue additional equity securities in order to generate such additional capital, then those issuances may occur at prices that represent discounts to our trading price, and will dilute the percentage ownership interest of those persons holding our shares prior to such issuances. Unless we are able to generate additional enterprise value with the proceeds of the sale of our equity securities, those issuances may adversely affect the value of our shares that are outstanding prior to those issuances.

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:

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

Any acquisitions we complete are subject to considerable risk.

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

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

20

Table of Contents

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 properties located in Eastern Kansas and South Texas. 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 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 currently sell oil to two purchasers in Eastern Kansas: Coffeyville Resources and Pacer Energy Marketing. There are approximately five potential purchasers of oil in Eastern Kansas, and 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 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 currently sell oil to Shell in South Texas. The number of purchasers in South Texas are numerous, but increased production volumes from extensive shale drilling activity in the area may result in bottle necks with various purchasers.

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; the El Toro Project or the Lonesome Dove Project. Our dependence on the operators of these projects limits our ability to influence or control the operation or future development of each 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 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, we have entered into derivative arrangements through December 31, 2015 for volumes up to 190 barrels of oil per day that could result in both realized

21

Table of Contents

and unrealized hedging losses. As of December 31, 2010, we had incurred realized and unrealized losses of approximately $1.9 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 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 production and could harm our business.

The marketability of our oil production will depend in a very large part on the availability, proximity and capacity of pipelines and oil processing facilities. The amount of oil 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 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 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 to date.

Our operations are located in established fields in Eastern Kansas and South Texas. As a result, many of our leases are in, or directly offset, areas that have produced large quantities of oil 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.

22

Table of Contents

We may face lease expirations on leases that are not currently held-by-production.

We have several leases in Texas that are not currently held-by-production, some of which have near term lease expirations. We are confident that we can maintain the lease position by drilling operations or by negotiating lease extensions, but we can make no guarantee that we can maintain these leases.

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

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

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

We may incur significant costs and liabilities as a result of environmental and safety requirements applicable to our oil 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 leases from wells previously drilled by third parties. In addition, we may indemnify sellers or lessors of oil 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.

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

The 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 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 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 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.

23

Table of Contents

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

We review the carrying value of our 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 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, 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.

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 nine-month transition period ended December 31, 2010 or year ended March 31, 2010.

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 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 Credit Facility, we may continue to have substantial indebtedness, which is secured by substantially all of our assets.

On December 31, 2010, approximately $6,116,000 of bank loans were outstanding. Under a default situation with respect to the 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, 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 $50,000,000. As of December 31, 2010, we had total indebtedness of $6,116,000 under the Credit Facility, as well as other notes payable totaling approximately $37,114. We had no outstanding letters of credit under the new facility on December 31, 2010. Our substantial indebtedness, and the related interest expense, could have important consequences to us, including:

24

Table of Contents

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

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

The Credit Facility also contain various affirmative covenants with which we are required to comply. We were not in compliance with three covenants at December 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 do not expect to pay dividends to holders of our common stock because of the terms of our Credit Facility, the terms of our Series A preferred stock, and our need to reinvest cash flow from operations in our business.

It is unlikely that we will pay any dividends to the holders of our common stock in the foreseeable future. The terms of our Credit Facility require that the lender approve any such distributions, and the lender is unlikely to provide that consent so long as we have significant unpaid indebtedness outstanding. In addition, in the transactions that closed as of December 31, 2010, we issued to Montecito Venture Partners, LLC, 4,779,460 shares of Series A preferred stock. The terms of that Series A preferred stock require that we pay to the holders of those shares cumulative distributions of $4,779,460 from one-third of our available cash from operations, which is our net cash flow from operations less principal being repaid to our lender. Because those priority distributions to holders of our Series A preferred stock will absorb our available cash from operations, we are unlikely to pay dividends on our common stock until after we have paid the entire $4,779,460 of preferential dividends to holders of our Series A preferred stock. We presently are unsure how many calendar quarters of operations we will need in order to complete the preferential payments due to the holders of our Series A preferred stock. Even after we complete those distributions, we are likely to elect to retain and reinvest any available cash flow from operations, rather than funding dividend distributions to holders of our common stock.

There are a Limited Number of Stockholders who have Significant Control over our Common Stock, Allowing them to have Significant Influence over the Outcome of all Matters Submitted to Stockholders for Approval, which may Conflict with our Interests and the Interests of other Stockholders.

Our directors, officers and principal stockholders (stockholders owning 10% or more of our common stock) and their affiliates beneficially owned approximately 62,073,782, or 91.21%, of the outstanding shares of common stock, stock options, and derivatives that could have been converted to common stock at December 31, 2010, immediately after giving effect to certain transactions that closed on that day, and such stockholders will have significant influence over the outcome of all matters submitted to our stockholders for approval, including the election of directors and other corporate actions.

25

Table of Contents

Two of our directors, R. Atticus Lowe and Lance Helfert, serve on the investment committee of West Coast Asset Management, Inc. West Coast Asset Management is the managing member of West Coast Opportunity Fund, LLC, a private investment vehicle formed for the purpose of investing in a wide variety of securities and financial instruments. West Coast Asset Management’s principals also manage Montecito Venture Partners, LLC.

In addition, we engage from time to time in transactions with certain of these significant stockholders.

On December 31, 2010, we entered into a Securities Purchase and Asset Acquisition Agreement with West Coast Opportunity Fund, Montecito Venture Partners, Working Interest Holdings, LLC, and certain other parties under which we acquired certain assets in exchange for an aggregate 61,618,991 shares of common stock, 4,779,460 shares of Series A preferred stock, and $1,500,000 cash, as further indicated in Note 3 of this Transition Report on Form 10-K. Under the Securities Purchase and Asset Acquisition Agreement, Montecito Venture Partners acquired 15,595,540 shares of common stock and 4,779,460 shares of Series A Preferred Stock, and West Coast Opportunity Fund acquired 10,550,415 shares of common stock.

On December 31, 2010, we also entered into a Securities Purchase Agreement with Montecito Venture Partners pursuant to which we sold to Montecito Venture Partners 5,025,000 shares of common stock for $2,010,000 in cash, upon the same terms and conditions as the remaining parties, as further indicated in Note 2 of this Transition Report on Form 10-K.

Our Large Stockholders may have Interests that Differ from other Stockholders.

As stated above, West Coast Opportunity Fund and Montecito Venture Partners, affiliates of our directors Mr. Lowe and Mr. Helfert, beneficially own, as of December 31, 2010, 53.20% of our outstanding common stock and 100% of our outstanding Series A preferred stock.

The interests of West Coast Opportunity Fund and Montecito Venture Partners, and their affiliates, may differ from those of our other stockholders. West Coast Opportunity Fund and Montecito Venture Partners, and their affiliates are in the business of making investments in companies and maximizing the return on those investments. They currently have, and may from time to time in the future acquire, interests in businesses that directly or indirectly compete with certain aspects of our business or our suppliers’ or customers’ businesses.

In addition, pursuant to the Securities Purchase and Asset Acquisition Agreement dated December 31, 2010, Working Interest Holding, LLC acquired 18,750,000 shares of our common stock, or 28.1% of our outstanding shares.

These stockholders’ significant ownership of our voting stock will enable it to influence or effectively control us.

The Holders of our Outstanding Shares of Series A Preferred Stock have dividend, conversion and other rights not shared with common stock holders.

As of April 18, 2011, we had 69,355,279 shares of our common stock issued and outstanding, as well as 4,779,460 shares of our Series A preferred stock issued and outstanding.

So long as any shares of Series A preferred stock are outstanding, we are required to declare dividends each calendar quarter in an aggregate amount equal to one-third of our net cash from operating activities reduced by any principal amount of debt repayment in such calendar quarter to our institutional lenders and other secured creditors. This right restricts our ability to use a portion of our net cash flow for other purposes such as developing our assets, strategic acquisitions, and dividends, and has other important consequences to us, including the potential to adversely affect:

26

Table of Contents

In addition, we cannot declare any dividends with regard to our common stock unless we concurrently pay to holders of Series A preferred stock a dividend in like amount, on an as-converted to common stock basis.

The Series A preferred stock is convertible into 4,779,460 shares of our common stock, and the Series A preferred stock, by its terms, shall convert into common stock on a one-to-one basis (subject to adjustment) once the cumulative dividends paid with regard to such stock equal the original principal value, and upon conversion would represent approximately 6.54% of our outstanding common stock. This would dilute the holdings of our existing common stockholders. In addition, the preferred stockholders vote on a one-to-one basis with our common stockholders on an as converted basis.

Furthermore, in the event of a liquidation, the holders of our Series A preferred stock would receive priority liquidation payments before payments to common stockholders equal to the liquidation amount of the preferred stock before any distributions would be made to our common stockholders. The current total liquidation amount of our Series A preferred stock is $4,779,460, or $1.00 per share, so the preferred stockholders would be entitled to receive that amount before any distributions could be made to common stockholders.

Lastly, the preferred stockholders have the right, by majority vote of the shares of preferred stock, to generally approve any issuances by us of equity that is senior to or equal in rights to the preferred stock. Therefore, the preferred stockholders can effectively bar us from entering into a transaction which they feel is not in their best interests even if the transaction would otherwise be in the best interests of EnerJex and its common stockholders.

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 stockholders.

The exercise of our outstanding options and warrants, 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 stockholder 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 (OTCBB) 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:

27

Table of Contents

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. The election by our board of directors to issue Series A preferred stock, and any future election to issue more preferred stock, could make it 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 with regard to our common stock 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.

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:

28

Table of Contents

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 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 Transition 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 transition 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.

Market Information for 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 sales prices of our common stock for the year ended March 31, 2010 and through the end of business on December 31, 2010 of the transition period. The quotations reflect inter-dealer prices without retail mark-up, markdown, or commissions and may not represent actual transactions. The market price of our common stock has been volatile. For an additional discussion, see “Item 1A: Risk Factors” of this Transition Report on Form 10-K.

29

Table of Contents

As of April 18, 2011, there were 1,195 holders of record of our common stock.

Dividends

We have never paid or declared any cash dividends on our common stock. We are required by the terms of our Series A preferred stock to declare dividends each calendar quarter in an aggregate amount equal to one-third of our net cash from operating activities reduced by any principal amount of debt repayment in such calendar quarter to institutional lenders and other secured creditors. This right is senior to the rights of common stockholders to receive dividend payments. We currently intend to retain any future earnings in excess of debt repayments and Series A preferred stock dividends 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 on common stock, 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 and holders of Series A preferred stock, if applicable at such time, and other factors our board of directors deems relevant.

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 the former Chief Executive Officer, 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 438,500 options under this plan. On August 3, 2009, we exchanged all 438,500 outstanding options for 134,400 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. There are currently 900,000 options outstanding under this plan.

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

30

Table of Contents

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

None.

Issuer Purchases of Equity Securities

None.

ITEM 6. SELECTED FINANCIAL DATA.

Not applicable.

ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS .

This Management’s Discussion and Analysis of Financial Condition and Results of Operations section should read in conjunction with the other sections of this Transition Report on Form 10-K, including “Item 1: Business” and “Item 8: Financial Statements and Supplementary Data”. This section includes forward-looking statements within the meaning of Section 27A of the Securities Act, and Section 21E of the Exchange Act. Forward-looking statements such as “will”, “believe,” “are projected to be” and similar expressions are statements regarding future events or our future performance, and include statements regarding projected operating results. These forward-looking statements are based on current expectations, beliefs, intentions, strategies, forecasts and assumptions and involve a number of risks and uncertainties that could cause actual results to differ materially from those anticipated by these forward-looking statements. These risks include, but are not limited to: our ability to deploy capital in a manner that maximizes stockholder value; the ability to identify suitable acquisition candidates or business and investments opportunities; the ability to reduce our operating costs; general economic conditions and our expected liquidity in future periods. These forward-looking statements are based on our current expectations and could be affected by the uncertainties and risk factors described throughout this filing and particularly in the “Risk Factors” set forth in Part I, Item 1A of this Transition Report on Form 10-K. As a result, our actual results may differ materially from those anticipated in these forward-looking statements.

Overview

On January 21, 2011, our board of directors approved the change in our fiscal year from March 31 to December 31. As a result of this change, this Transition Report on Form 10-K is a transition report and includes financial information for the nine-month transition period from April 1, 2010 to December 31, 2010, or Transition Period. The comparative financial information provided for the nine-month period ended January 1, 2010 is unaudited, since it represented an interim period of the fiscal year ended March 31, 2010 and includes all the normal recurring adjustments necessary for the fair statement of the results for that period. Subsequent to this Transition report on Form 10-K, our reports on Form 10-K will cover the calendar year from January 1 to December 31, with historical periods remaining unchanged.

Our principal strategy is to develop, acquire, explore and produce domestic onshore oil properties. Our business activities are currently focused in Eastern Kansas and South Texas.

31

Table of Contents

Results of Operations for the nine-month transition period ended December 31, 2010, and for fiscal years ended March 31, 2010 and 2009 compared.

Income:

Revenues

Oil revenues for the nine-month transition period ended December 31, 2010 were $2,929,103, and 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 lower production. The average price per barrel we received for oil sold during the nine-month transition period ended December 31, 2010 was $72.60 compared to the twelve months ended March 31, 2010 was $69.62 compared to $85.67 for the twelve months ended March 31, 2009

Expenses: