PROSPECTUS SUMMARY

The following summary provides an overview of certain information contained elsewhere in this prospectus. Because this is a summary, it does not contain all of the information you should consider before investing in our Series B Preferred Stock.A preferred stock. You should read this entire prospectus carefully before making a decision about whether to invest in our Series B Preferred Stock.A preferred stock. Unless the context requires otherwise or unless otherwise noted, all references in this prospectus to “the Company,” “EnerJex” “we,” “us” or “our” are to EnerJex Resources, Inc. and its consolidated subsidiaries and Black Raven Energy, Inc., a wholly-owned subsidiary.

Overview

We operate as an independent exploration and production company focused on the acquisition and development of oil and natural gas properties located in the mid-continent region of the United States.

Our primary business objective is to increase our oil and natural gas production, reserves, and cash flow in a manner that is accretive for our shareholders by acquiring and developing properties that have low production decline rates and offer abundant drilling opportunities with low risk profiles.

We drilled 48 oil wells in 2013 with a 100% success rate, and our ratio of proved reserves to production is 32.8 years based on our annualized production volumes for the three months ended December 31, 2013.

As of December 31, 2013, we owned oil and natural gas leases covering more than 90,000 net acres in Kansas, Colorado, Nebraska, and Texas, of which approximately 64% is held by production. We have identified more than 500 drilling locations on this acreage from which we expect to recover commercial quantities of oil and natural gas.

Our total net proved oil and natural gas reserves as of December 31, 2013 were 5.8 million barrels of oil equivalent (Boe), of which 77% was oil. Of the 5.8 million Boe of total proved reserves, approximately 49% were classified as proved developed producing, approximately 17% were classified as proved developed non-producing, and approximately 34% were classified as proved undeveloped. The total PV10 (present value) of our proved reserves as of December 31, 2013 was $102.4 million.

The principal elements of our business strategy are to:

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, Inc., Black Raven Energy, Inc., and Black Sable Energy, LLC, and our leasehold interests are held in our wholly owned subsidiaries Black Raven Energy, Inc., Adena, LLC, DD Energy, Inc., Black Sable Energy, LLC, Working Interest, LLC, PRB Gathering, Inc., and EnerJex Kansas, Inc.

EnerJex's corporate offices are located at 4040 Broadway, Suite 508, San Antonio, Texas 78209 and its telephone number is (210) 451-5545. EnerJex's website is located at www.enerjex.com. The information contained on or connected to EnerJex's website is expressly not incorporated by reference into this prospectus. Additional information about EnerJex is included elsewhere in this prospectus. See the sections entitled "EnerJex's" Business," "EnerJex's" Management's Discussion and Analysis of Financial Condition and Results of Operations" and EnerJex's financial statements beginning on pages [Ÿ],[Ÿ]32, 26 and [Ÿ],F-1, respectively.

Recent Developments

On July 23, 2013, EnerJex, BRE Merger Sub,March 14, 2014, Black Raven Energy, Inc. ("Black Raven"), a Delaware corporation and a wholly ownedwholly-owned subsidiary of EnerJex (Merger Sub), and Black Raven Energy, Inc., a Nevada corporation (Black Raven), entered into an agreementa Settlement and plan of merger (Merger Agreement)Release Agreement with Atlas Resources, LLC, pursuant to which Black Raven would be merged withthe parties settled certain disputes regarding the rights and into Merger Sub and after which Black Raven would be a wholly owned subsidiaryobligations of EnerJex. the parties under that certain Farmout Agreement dated effective as of July 23, 2010.

On September 27,Pursuant to the Settlement Agreement, among other matters, the parties released each other from certain claims and obligations, the Farmout Agreement was terminated, and the parties entered into a new Gathering Agreement and Contract Operating Agreement under which Atlas shall pay to Black Raven an overhead charge of $12,000 per month from December 1, 2013 through November 30, 2015. Unless the transactions contemplated byContract Operating Agreement is terminated at the Merger Agreement were successfully completed.option of either party, after November 30, 2015, from and after December 1, 2015, the overhead charge per month shall be the lesser of (a) $12,000, and (b) an amount equal to $0.25 per thousand cubic feet of natural gas produced in each such month from wells that Black Raven operates for Atlas pursuant to the Contract Operating Agreement.

The following transactions were executedPursuant to the Settlement Agreement, Atlas also agreed to pay Black Raven the sum of $687,938.50 and assign to Black Raven its rights to depth in any zone below the Niobrara formation on September 27, 2013 perapproximately 8,360 acres that are held by production in Phillips and Sedgwick counties in the State of Colorado. In additional, Black Raven agreed to purchase seven non-producing wells from Atlas for $150,000.

On April 9, 2014, pursuant to a lease purchase agreement effective as of March 31, 2014, we closed a sale to Venado Operating Company, LLC of our interests in approximately 2,250 gross acres comprising our Lonesome Dove Project in Lee County, Texas, for (i) $450,000 in cash, and (ii) the right to receive an average overriding royalty interest of approximately 2.4% in the acreage.

Effective immediately prior to the issuance and sale of shares of Series A preferred stock pursuant to this registration statement, we intend to adopt the Amended and Restated Certificate of Designation in the form attached hereto, and thereby modified the terms of the Merger Agreement: (i)Series A preferred stock as set forth therein and as described in this prospectus. Concurrently with the adoption and filing of such Amended and Restated Certificate of Designation, the holders of our existing Series A preferred stock, which is currently convertible into shares of capitalour common stock on a one-for-one basis upon repayment of Black Raven were converted into (a) cash totaling $207,067the original principal value, will exchange each outstanding share of such existing Series A preferred stock for (i) 1 share of common stock and (b) 41,328,914(ii) a number of shares of EnerJex commonSeries A preferred stock (ii) all options underequal to the Black Raven option plan were cancelled, and (iii) all warrants or other rights toquotient determined by dividing (x) that portion of the holder's original Series A preferred stock purchase price that has not yet been paid in dividends, by (y) the original issue price per share at which we sell our shares of capitalSeries A preferred stock of Black Raven were converted into warrants to purchase EnerJex common stock. No fractional shares of EnerJex common stock were issuedunder this registration statement.

That share exchange will be effected under an exchange agreement in connection with the Merger, and holders of Black Raven common stock were entitled to receive cash in lieu thereof. The board of directors and executive officers of EnerJex remained unchanged asform attached hereto. As a result of that share exchange, [   ] shares of Series A preferred stock are issued and outstanding; those shares are not being registered under this registration statement, but will be eligible for resale in the closingpublic capital markets under Rule 144. Each holder of such shares is executing with EnerJex a lock-up agreement, under which such holder has agreed not to sell such shares in the public capital markets for a period of 90 days after the date of the Merger.final prospectus.

  At closing of the transactions contemplated by the Merger Agreement, the previous stockholders of Black Raven owned approximately 38% of the outstanding voting stock of EnerJex and the previous stockholders of EnerJex owned approximately 62% of the outstanding voting stock of EnerJex.

Executive Offices

Our principal executive offices are located at 4040 Broadway, Suite 508, San Antonio, Texas 78209, and our telephone number is (210) 451-5545. Our website is www.enerjexresources.com.www.enerjexr.com. Additional information that may be obtained through our website does not constitute part of this prospectus.

THE OFFERING

The following is a brief description of certain terms of this offering and does not purport to be complete. For a more complete description of the terms of the Series B Preferred Stock,A preferred stock, see “Description of Series BA Preferred Stock” beginning on page [l]64 of this prospectus.

RISK FACTORS

InvestingI nvesting in our securities has a significant degree of risk. Before you invest in the Series B Preferred StockA preferred stock offered by this prospectus, you should carefully consider the risks described below, in addition to the other information presented in this prospectus. If any of the following risks actually occur, they could seriously harm our business, financial condition, results of operations or cash flows. This could cause the trading price of our Series B Preferred StockA preferred stock to decline and you could lose all or part of your investment.

Risks Related to Ownership of Our Series BA Preferred Stock

The price of our Series B Preferred Stock may be volatile.A preferred stock might not have an active trading market, which could reduce its market value and your ability to sell your shares.

We expectAn active trading market for the Series A preferred stock might not exist after issuance of the Series A preferred stock offered hereby or, even if it develops, might not last, in which case the trading price of our commonthe shares could be reduced and your ability to transfer your shares of Series A preferred stock and Series B Preferred Stock tocould be subject to fluctuations as a resultlimited. The trading price of a variety ofthe shares will depend on many factors, including factors beyond our control. These factors include:the following:

 Ownership of the our common stock and Series A Preferred Stock is highly concentrated, and such concentration may prevent you and other stockholders from influencing significant corporate decisions and may result in conflicts of interest that could cause the combined company's stock price to decline.

EnerJex's directors and executive officers, together with their respective affiliates, beneficially own or control more than 60% of the Company (see the sections entitled "Principal Stockholders of EnerJex" beginning on page [Ÿ] for more information on the estimated ownership of the company). Accordingly, these directors, executive officers and their affiliates, acting individually or as a group, have substantial influence over the outcome of a corporate action of requiring stockholder approval, including the election of directors, any merger, consolidation or sale of all or substantially all of our assets or any other significant corporate transaction. These stockholders also may exert influence in delaying or preventing a change in control of the Company, even if such change in control would benefit the other stockholders of the Company. In addition, the significant concentration of stock ownership may affect adversely•    the market value of EnerJex's common stock and Series B Preferred Stock due to investors' perception that conflicts of interest may exist or arise.for similar securities;

Anti-takeover provisions in the our charter•    general economic conditions; and bylaws may prevent or frustrate attempts by stockholders to change the board of directors or management and could make a third-party acquisition of the combined company difficult.

Our amended•    our financial condition, performance and restated articles of incorporation and bylaws, as amended, contain provisions that may discourage, delay or prevent a merger, acquisition or other change in control that stockholders may consider favorable, including transactions in which stockholders might otherwise receive a premium for their shares. These provisions could limit the price that investors might be willing to pay in the future for shares of our common stock, and have a negative effect on the price at which shares of our Series B Preferred Stock will trade.prospects.

We could be prevented from paying dividends on the Series B Preferred Stock.A preferred stock.

Although dividends on the Series B Preferred StockA preferred stock are cumulative and will accrue until paid, you will receive cash dividends on the Series B Preferred StockA preferred stock only if we have funds legally available for the payment of dividends and such payment is not restricted or prohibited by law, the terms of any senior shares, or any documents governing our indebtedness. Our business may not generate sufficient cash flow from operations to enable us to pay dividends on the Series B Preferred StockA preferred stock when payable.

Further, pursuant to the terms of our credit facility as set forth in the Amended and Restated Credit Agreement dated effective October 3, 2011, as amended, with Texas Capital Bank, we are prohibited from declaring or paying dividends. Therefore we are currently required to receive the consent of the bank prior to declaring and making dividend payments for the Series A preferred stock, and we expect to receive such consent prior to the effectiveness of this registration statement. In addition, future debt, contractual covenants or arrangements we enter into may restrict or prevent future dividend payments. Accordingly, there is no guarantee that we will be able to pay any cash dividends on our Series B Preferred Stock.

A preferred stock.

The Series B Preferred StockA preferred stock has not been rated and will be subordinated to all of our existing and future debt.

The Series B Preferred StockA preferred stock has not been rated by any nationally recognized statistical rating organization. In addition, with respect to dividend rights and rights upon our liquidation, winding-up or dissolution, the Series B Preferred StockA preferred stock will be subordinated to all of our existing and future debt. We may also incur additional indebtedness in the future to finance potential acquisitions or other activities and the terms of the Series B Preferred StockA preferred stock do not require us to obtain the approval of the holders of the Series B Preferred StockA preferred stock prior to incurring additional indebtedness. As a result, our existing and future indebtedness may be subject to restrictive covenants or other provisions that may prevent or otherwise limit our ability to make dividend or liquidation payments on our Series B Preferred Stock.A preferred stock. Upon our liquidation, our obligations to our creditors would rank senior to our Series B Preferred StockA preferred stock and would be required to be paid before any payments could be made to holders of our Series B Preferred Stock.

The Series B Preferred Stock may be subordinated to our future equity issuances.

With the approval of holders of a majority of the issued and outstanding shares of Series B Preferred Stock, we may be able to issue shares of equity securities that have rights to dividends and liquidation that are senior to those of the holders of shares of the Series B Preferred Stock. If we obtained such approval and issued such future senior securities, then our obligations to holders of such future senior securities would be superior to those of the holders of shares of the Series B Preferred Stock, and we would be required to make payments to holders of such future senior securities before we could make any payments to holders of our Series B Preferred Stock.A preferred stock.

Investors should not expect us to redeem the Series B Preferred StockA preferred stock on the date the Series B Preferred StockA preferred stock becomes redeemable or on any particular date afterwards.

We generally may not redeem the Series B Preferred StockA preferred stock prior to [·].   ]. On and after [·],   ], we may redeem the Series B Preferred StockA preferred stock for cash at our option, from time to time, in whole or in part, at a redemption price of $25.00 per share, plus accrued and unpaid dividends (whether or not earned or declared) to the redemption date. The Series B Preferred StockA preferred stock does not have any stated maturity date and will not be subject to any sinking fund or mandatory redemption provisions. Any decision we may make at any time to redeem the Series B Preferred StockA preferred stock will depend upon, among other things, our evaluation of our capital position, including the composition of our stockholders’ equity and general market conditions at that time.

Holders of Series B Preferred StockA preferred stock have extremely limited voting rights.

Except as expressly stated in the certificate of designations governing the Series B Preferred Stock,A preferred stock, as a holder of Series B Preferred Stock,A preferred stock, you will not have any relative, participating, optional or other special voting rights and powers and your approval will not be required for the taking of any corporate action other than as provided in the certificate of designations. For example, your approval would not be required for any merger or consolidation in which we may become involved or any sale of all or substantially all of our assets except to the extent that such transaction materially adversely changes the express powers, preferences, rights or privileges of the holders of Series B Preferred Stock.A preferred stock. The provisions relating to the Series B Preferred StockA preferred stock do not afford the holders of the Series B Preferred StockA preferred stock protection in the event of a highly leveraged or other transaction, including a merger or the sale, lease or conveyance of all or substantially all of our assets or business, that might adversely affect the holders of the Series B Preferred Stock,A preferred stock, so long as the terms and rights of the holders of Series B Preferred StockA preferred stock are not materially and adversely changed.

The issuance of future offerings of preferred stock may adversely affect the value of our Series B Preferred Stock.A preferred stock.

Our articles of incorporation, as amended, currently authorizes us to issue up to 25,000,000 shares of preferred stock in one or more series on terms that may be determined at the time of issuance by our board of directors. We may issue other classes of preferred shares that would rank on parity with or senior to the Series B Preferred StockA preferred stock as to dividend rights or rights upon liquidation, winding up or dissolution. The creation and subsequent issuance of additional classes of preferred shares that, with the consent of a majority of the holders of the Series B Preferred Stock,A preferred stock, would be senior to or on parity with our Series B Preferred StockA preferred stock would dilute the interests of the holders of Series B Preferred StockA preferred stock and any issuance of preferred stock that is senior to the Series B Preferred StockA preferred stock could affect our ability to pay dividends on, redeem or pay the liquidation preference on the Series B Preferred Stock.A preferred stock.

Holders of the Series B Preferred StockA preferred stock may be unable to use the dividends-received deduction.

Distributions paid to corporate U.S. holders of the Series B Preferred StockA preferred stock may be eligible for the dividends-received deduction if we have current or accumulated earnings and profits, as determined for U.S. federal income tax purposes. We do not currently have accumulated earnings and profits. Additionally, we may not have sufficient current earnings and profits during future fiscal years for the distributions on the Series B Preferred StockA preferred stock to qualify as dividends for U.S. federal income tax purposes. If the distributions fail to qualify as dividends, U.S. holders would be unable to use the dividends-received deduction. If any distributions on the Series B Preferred StockA preferred stock with respect to any fiscal year are not eligible for the dividends-received deduction because of insufficient current or accumulated earnings and profits, it is possible that the market value of the Series B Preferred StockA preferred stock might decline.

Non-U.S. Holders may be subject to U.S. income tax with respect to gain on disposition of their Series B Preferred Stock.A preferred stock.

If we are a U.S. real property holding corporation at any time within the five-year period preceding a disposition of Series B Preferred StockA preferred stock by a non-U.S. holder or the holder’s holding period of the shares disposed of, whichever period is shorter, such non-U.S. holder may be subject to U.S. federal income tax with respect to gain on such disposition. If we are a U.S. real property holding corporation, which we expect we are, so long as the Series B Preferred StockA preferred stock is regularly traded on an established securities market, a non-U.S. holder will not be subject to U.S. federal income tax on the disposition of the Series B Preferred StockA preferred stock unless the holder beneficially owns (directly or by attribution) more than 5% of the total fair market value of the Series B Preferred StockA preferred stock at any time during the five-year period ending either on the date of disposition of such interest or other applicable determination date. For additional information concerning these matters, see “Material U.S. Federal Income Tax Consequences.”

Our ability to use net operating loss carryforwards to offset future taxable income may be subject to certain limitations.

We currently have net operating loss carryforwards that may be available to offset future taxable income. However, changes in the ownership of our stock (including certain transactions involving our stock that are outside of our control) could result (or may have already resulted) in an “ownership change” within the meaning of Section 382 of the Internal Revenue Code of 1986, as amended, which may significantly limit our ability to utilize our net operating loss carryforwards. To the extent an ownership change has occurred or were to occur in the future, it is possible that the limitations imposed on our ability to use pre-ownership change losses could cause a significant net increase in our U.S. federal income tax liability and could cause U.S. federal income taxes to be paid earlier than otherwise would be paid if such limitations were not in effect.

Our Series B Preferred StockA preferred stock is not convertible and if the price of our common stock increase,increases, then holders of Series B Preferred StockA preferred stock may not realize a corresponding increase in the value of suchtheir Series B Preferred Shares.A preferred stock.

Our Series B Preferred StockA preferred stock is not convertible into our common stock and earns dividends at a fixed rate. Accordingly, the market value of our Series B Preferred StockA preferred stock may depend on dividend and interest rates for other preferred stock, commercial paper and other investment alternatives and our actual and perceived ability to pay dividends on, and, in the event of dissolution, to satisfy the liquidation preference with respect to, our Series B Preferred Stock.A preferred stock. Moreover, our right to redeem the Series B Preferred StockA preferred stock on or after [·] could impose a ceiling on its value.

Risks Related to the Oil and Natural Gas Industry and Our Business

in General

This next discussion of risk factors relates to the oil and natural gas industry and our business in general.

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 5 years, due in part to the financial stresses affecting the liquidity of the banking system and the financial markets generally.   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, the Persian Gulf, North Africa, Iran, North Korea or elsewhere, or the fear of such events, could further exacerbate the volatility and disruption to the financial markets and 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 and gas, 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.

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

Our development, exploitation and exploration activities may be unsuccessful for many reasons, including weather, cost overruns, equipment shortages and mechanical difficulties. Moreover, the successful drilling of a 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 and natural gas business involves a variety of operating risks, including:

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

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

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

Developing and exploring for oil and natural gas 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 or gas well does not ensure a profit on investment. Exploratory wells bear a much greater risk of loss than development wells. Substantially all of EnerJex's wells drilled through December 31, 2013 have been development wells, while a majority of the wells drilled by Black Raven have been considered by Black Raven to be 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 no control and assumptions required by the SEC relating to oil and gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. We have limited 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 and gas reserves is extremely complex, and requires significant decisions and assumptions in the evaluation of available geological, geophysical, engineering and economic data for each reservoir. Our estimates may not be reliable enough to allow us to be successful in our intended business operations. Our actual production, revenues, taxes, development expenditures and operating expenses will likely vary from those anticipated. These variances may be material.

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

Unless we conduct successful development, exploitation and exploration activities or acquire properties containing proved reserves, our proved reserves will decline as those reserves are produced. Producing oil and gas reservoirs generally are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Our future oil and gas 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.

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

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

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

Regulatory authorities exercise considerable discretion in the timing and scope of well drilling 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 well drilling 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.

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. We do not have any contracts for drilling rigs and drilling rigs may not be readily available when we need them. Drilling and other costs may increase further and necessary equipment and services may not be available to us at economical prices.

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

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

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

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

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

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

Lower prices for oil and natural gas reduce demand for our services and could have a material adverse effect on our revenue and profitability.

Benchmark crude prices peaked at over $140 per barrel in July 2008 and then declined to approximately $111$92 per barrel at year-end 2012. During 2013, the benchmark for crude prices fluctuated between the high $[·]$85 per barrel and high $[·]$110 per barrel. Demand for our services depends on oil and natural gas industry activity and expenditure levels that are directly affected by trends in oil and natural gas prices. In addition, demand for our services is particularly sensitive to the level of exploration, development and production activity of and the corresponding capital spending by, oil and natural gas companies. Any prolonged reduction in oil and natural gas prices could depress the near-term levels of exploration, development, and production activity. Perceptions of longer-term lower oil and natural gas prices by oil and natural gas companies could similarly reduce or defer major expenditures given the long-term nature of many large-scale development projects. Lower levels of activity result in a corresponding decline in the demand for our services, which could have a material adverse effect on our revenue and profitability. Additionally, these factors may adversely impact our financial position if they are determined to cause an impairment of our long-lived assets.

Our business is affected by local, national and worldwide economic conditions and the condition of the oil and natural gas industry.

Recent economic data indicates the rate of economic growth worldwide has declined significantly formfrom the growth rates experienced in recent years. Current economic conditions have resulted in uncertainty regarding energy and commodity prices. In addition, future economic conditions may cause many oil and natural gas production companies to further reduce or delay expenditures in order to reduce costs, which in turn may cause a further reduction in the demand for drilling services. If conditions worsen, our business and financial condition may be adversely impacted.

Our business involves numerous operating hazards, and our insurance and contractual indemnity rights may not be adequate to cover our losses.

Our operations are subject to the usual hazards inherent in the drilling and operation of oil and natural gas wells, such as blowouts, reservoir damage, loss of production, loss of well control, punch throughs, craterings, fires and pollution. The occurrence of these events could result in the suspension of drilling or production operations, claims by the operator and others affected by such events, severe damage to, or destruction of, the property and equipment involved, injury or death to drilling personnel, environmental damage and increased insurance costs. We may also be subject to personal injury and other claims of drilling personnel as a result of our drilling operations. Operations also may be suspended because of machinery breakdowns, abnormal operating conditions, failure of subcontractors to perform or supply goods or services and personnel shortages.

Damage to the environment could result from our operations, particularly through oil spillage or extensive uncontrolled fires. We may also be subject to property, environmental and other damage claims by host governments, oil and natural gas companies and other businesses operating offshore and in coastal areas, as well as claims by individuals living in or around coastal areas.

As is customary in our industry, the risks of our operations are partially covered by our insurance and partially by contractual indemnities from our customers. However, insurance policies and contractual rights to indemnity may not adequately cover losses, and we may not have insurance coverage or rights to indemnity for all risks. Moreover, pollution and environmental risks generally are not fully insurable. If a significant accident or other event resulting in damage to our drilling units, including severe weather, terrorist acts, war, civil disturbances, pollution or environmental damage, occurs and is not fully covered by insurance or a recoverable indemnity from a customer, it could adversely affect our financial condition and results of operations.

Our business is subject to numerous governmental laws and regulations, including those that may impose significant costs and liability on us for environmental and natural resource damages.

Many aspects of our operations are affected by governmental laws and regulations that may relate directly or indirectly to the contract drilling industry, including those requiring us to control the discharge of oil and other contaminants into the environment or otherwise relating to environmental protection. Countries where we currently operate have environmental laws and regulations covering the discharge of oil and other contaminants and protection of the environment in connection with operations. Additionally, our operations and activities in the United States and its territorial waters are subject to numerous environmental laws and regulations, including the Clean Water Act, the OPA, the Outer Continental Shelf Lands Act, the Comprehensive Environmental Response, Compensation and Liability Act, the Clean Air Act, the Resource Conservation and Recovery Act and MARPOL. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of remedial obligations, the denial or revocation of permits or other authorizations and the issuance of injunctions that may limit or prohibit our operations.

Laws and regulations protecting the environment have become more stringent in recent years and may in certain circumstances impose strict liability, rendering us liable for environmental and natural resource damages without regard to negligence or fault on our part. These laws and regulations may expose us to liability for the conduct of, or conditions caused by, others or for acts that were in compliance with all applicable laws at the time the acts were performed. The application of these requirements, the modification of existing laws or regulations or the adoption of new laws or regulations relating to exploratory or development drilling for oil and natural gas could materially limit future contract drilling opportunities or materially increase our costs. In addition, we may be required to make significant capital expenditures to comply with such laws and regulations.

In addition, some financial institutions are imposing, as a condition to financing, requirements to comply with additional non-governmental environmental and social standards in connection with operations outside the United States, such as the Equator Principles, a credit risk management framework for determining, assessing and managing environmental and social risk in project finance transactions. Such additional standards could impose significant new costs on us, which may materially and adversely affect us.

Changes in U.S. federal laws and regulations, or in those of other jurisdictions where we operate, including those that may impose significant costs and liability on us for environmental and natural resource damages, may adversely affect our operations.

If the U.S. government amends or enacts new federal laws or regulations, our potential exposure to liability for operations and activities in the United States and its territorial waters may increase. Although the Oil Pollution Act of 1990 provides federal caps on liability for pollution or contamination, future laws and regulations may increase our liability for pollution or contamination resulting from any operations and activities that the Company may have in the United States and its territorial waters including punitive damages and administrative, civil and criminal penalties. Additionally, other jurisdictions where we operate have modified, or may in the future modify, their laws and regulations in a manner that would increase our liability for pollution and other environmental damage.

Our financial condition may be adversely affected if we are unable to identify and complete future acquisitions, fail to successfully integrate acquired assets or businesses we acquire, or are unable to obtain financing for acquisitions on acceptable terms.

The acquisition of assets or businesses that we believe to be complementary to our exploration and production operations is an important component of our business strategy. We believe that acquisition opportunities for EnerJex, such as the merger with Black Raven, may arise from time to time, and that any such acquisition could be significant. At any given time, discussions with one or more potential sellers may be at different stages. However, any such discussions may not result in the consummation of an acquisition transaction, and we may not be able to identify or complete any acquisitions. We cannot predict the effect, if any, that any announcement or consummation of an acquisition would have on the trading price of our securities. Our business is capital intensive and any such transactions could involve the payment by us of a substantial amount of cash. We may need to raise additional capital through public or private debt or equity financings to execute our growth strategy and to fund acquisitions. Adequate sources of capital may not be available when needed on favorable terms. If we raise additional capital by issuing additional equity securities, existing stockholders may be diluted. If our capital resources are insufficient at any time in the future, we may be unable to fund acquisitions, take advantage of business opportunities or respond to competitive pressures, any of which could harm our business.

Any future acquisitions could present a number of risks, including:

If we are unsuccessful in completing acquisitions of other operations or assets, our financial condition could be adversely affected and we may be unable to implement an important component of our business strategy successfully. In addition, if we are unsuccessful in integrating our acquisitions in a timely and cost-effective manner, our financial condition and results of operations could be adversely affected.

The loss of some of our key executive officers and employees could negatively impact our business prospects.

Our future operational performance depends to a significant degree upon the continued service of key members of our management as well as marketing, sales and operations personnel. The loss of one or more of our key personnel could have a material adverse effect on our business. We believe our future success will also depend in large part upon our ability to attract, retain and further motivate highly skilled management, marketing, sales and operations personnel. We may experience intense competition for personnel, and we cannot assure you that we will be able to retain key employees or that we will be successful in attracting, assimilating and retaining personnel in the future.

Failure to employ a sufficient number of skilled workers or an increase in labor costs could hurt our operations.

We require skilled personnel to operate and provide technical services to, and support for, our drilling units. In periods of increasing activity and when the number of operating units in our areas of operation increases, either because of new construction, re-activation of idle units or the mobilization of units into the region, shortages of qualified personnel could arise, creating upward pressure on wages and difficulty in staffing. The shortages of qualified personnel or the inability to obtain and retain qualified personnel also could negatively affect the quality and timeliness of our work. In addition, our ability to expand operations depends in part upon our ability to increase the size of the skilled labor force.

Risks Related to EnerJex

Ownership of our common stock is highly concentrated, and such concentration may prevent other stockholders from influencing significant corporate decisions and may result in conflicts of interest that could cause our stock price to decline.

EnerJex's directors and executive officers, together with their respective affiliates, beneficially own or control more than 60% of the Company (see the sections entitled "Principal Stockholders of EnerJex" beginning on page [   ] for more information on the estimated ownership of the company). Accordingly, these directors, executive officers and their affiliates, acting individually or as a group, have substantial influence over the outcome of a corporate action of requiring stockholder approval, including the election of directors, any merger, consolidation or sale of all or substantially all of our assets or any other significant corporate transaction. These stockholders also may exert influence in delaying or preventing a change in control of the Company, even if such change in control would benefit the other stockholders of the Company. In addition, the significant concentration of stock ownership may affect adversely the market value of EnerJex's common stock and Series A preferred stock due to investors' perception that conflicts of interest may exist or arise.

Anti-takeover provisions in our charter and bylaws may prevent or frustrate attempts by stockholders to change the board of directors or management and could make a third-party acquisition of the company difficult.

Our amended and restated articles of incorporation and bylaws, as amended, contain provisions that may discourage, delay or prevent a merger, acquisition or other change in control that stockholders may consider favorable, including transactions in which stockholders might otherwise receive a premium for their shares. These provisions could limit the price that investors might be willing to pay in the future for shares of our common stock, and have a negative effect on the price at which shares of our Series A preferred stock will trade.

We have sustained losses in the past, and our future profitability is subject to many risks inherent in the oil and natural gas exploration and production industry.

Our prospects must be considered in light of the risks, expenses and difficulties frequently encountered in establishing and maintaining a business in the exploration and production 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 or gas in sustainable or economic quantities.

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

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

If low oil and gas 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 a drop in crude oil prices are to maintain hedges covering a portion of our expected future oil production and 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, including rights that are senior to those of holders of our Series B Preferred Stock.A preferred stock.

Approximately 47%34% of our total proved reserves as of December 31, 20122013 consist of undeveloped 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, 20122013 was $60.8$102 million, versus $53.2$60.8 million as of December 31, 2011.2012.   Of the 2.95.8 million net barrels of oil equivalent at December 31, 2012,2013, approximately 53%49% are proved developed producing, approximately 17% are classified as proved developed non-producing and approximately 47%34% are classified as proved undeveloped.

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 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 proved recoverable reserves, you should not place undue reliance on such reserve information.

Our reserve estimates and the future net cash flows attributable to those reserves at December 31, 20122013 were prepared by MHA Petroleum Consultants LLC, 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 and gas 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 and gas 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 and gas 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 and gas 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 MHA Petroleum Consultants LLC 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 and gas 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 and gas industry in general.

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

The prices that we receivereceived for our oil and gas production in Eastern Kansas and Eastern Colorado are typically based on a discount to the relevant benchmark prices, such as NYMEX, that are used for calculating hedge positions. In South Texas, the prices that we receive for our oil and gas production are currently based on a premium to NYMEX. In Colorado, the prices that we receive for our oil and gas production are based upon a discount to NYMEX and the prices we receive for our natural gas production is based upon local market conditions but generally we receive a discount to Henry Hub. The difference between the benchmark price and the price we receive is called a differential. We cannot accurately predict oil and gas differentials. In recent years for example, production increases from competing Canadian and Rocky Mountain producers, in conjunction with limited refining and pipeline capacity from the Rocky Mountain area, have gradually widened this differential. Recent economic conditions, including volatility in the price of oil and gas, have resulted in both increases and decreases in the differential between the benchmark price for oil and gas and the wellhead price we receive. These fluctuations could have a material adverse effect on our results of operations, financial condition and cash flows by decreasing the proceeds we receive for our oil and gas production in comparison to what we would receive if not for the differential.

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

The oil and natural gas exploration, development and production business is a capital-intensive undertaking. In order for us to be successful in acquiring, investigating, developing, and producing oil and gas 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 issue additional shares of our equity securities. There can be no assurance that we will be successful in ether obtaining that expanded debt facility or issuing additional shares of 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:

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

We currently only lease and operate oil and natural gas properties located in Eastern Kansas, Eastern Colorado, Nebraska 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 Plains 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 Plains Marketing in Eastern Colorado and Sunoco in South Texas. The number of purchasers in these areas is numerous, but increased production volumes from extensive unconventional resource shale drilling activity in the area may result in bottlenecks 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 of our Mississippian Project, and our dependence on the operator of this project limits our ability to influence or control the operation or future development of this 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 and gas, such as fires, natural disasters, explosions, pipeline ruptures, spills, and acts of terrorism, all of which can result in the loss of hydrocarbons, environmental pollution, personal injury claims and other damage to our and others' properties. As protection against operating hazards, we maintain insurance coverage against some, but not all, potential losses. In addition, pollution and environmental risks generally are not fully insurable. As a result of market conditions, existing insurance policies may not be renewed and other desirable insurance may not be available on commercially reasonable terms, if at all. The occurrence of an event that is not covered, or not fully covered, by insurance could have a material adverse effect on our business, financial condition and results of operations.

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

To achieve more predictable cash flow and to reduce our exposure to adverse fluctuations in the prices of oil and gas, we have entered into derivative arrangementscontracts through December 31, 2015 for volumes of approximately 350245,000 barrels of oil per day in 2014crude oil. The settlement of and 320 barrelsthe mark to market of oil per day in 2015 thatthese contracts could result in both realized and unrealized hedging losses. As ofFor the year ended December 31, 2012,2013, we had incurred realized and unrealized gainshedging losses of approximately $56,000.$740,000. 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, 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 processing facilities owned by others. Any limitation in the availability of those facilities could interfere with our ability to market our oil and gas production and could harm our business.

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

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

A significant portion of our operations are located in or near established fields in Eastern Kansas, Colorado, Nebraska, and South Texas. As a result, many of our leases are in, or directly offset, areas that have produced large quantities of oil and gas to date.  As such, our reserves may be negatively impacted 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.

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

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

We have numerous leases that are not currently held-by-production, some of which have near term lease expirations and are likely to expire. Although we believe that we can maintain our most desirable leases by conducting drilling operations or by negotiating lease extensions, 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 and gas in the United States are subject to extensive laws and regulations, including environmental laws and regulations. We may be required to make large expenditures to comply with environmental and other governmental regulations. Matters subject to regulation include, but are not limited to:

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

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

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

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

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

We review the carrying value of our oil and gas 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 and gas 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 and gas 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,Our ability to use net operating loss carryforwards to offset future taxable income may be subject to certain limitations .

We currently have net operating loss carryforwards that may be available to offset future taxable income. However, changes in the SEC issued new regulations for oil reserve reporting were effective for fiscal years ending on or after December 31, 2009.  Oneownership of our stock (including certain transactions involving our stock that are outside of our control) could result (or may have already resulted) in an “ownership change” within the meaning of Section 382 of the key elementsInternal Revenue Code of 1986, as amended, which may significantly limit our ability to utilize our net operating loss carryforwards. To the new regulations relateextent an ownership change has occurred or were to occur in the commodity prices which are usedfuture, it is possible that the limitations imposed on our ability to calculate reservesuse pre-ownership change losses could cause a significant net increase in our U.S. federal income tax liability and their present value.  The new regulations provide for disclosure of oil reserves evaluated using annual average prices based on the pricescould cause U.S. federal income taxes to be paid earlier than otherwise would be paid if such limitations were not 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.effect.

There was no impairment for the fiscal year ended December 31, 2012, or for the fiscal year ended December 31, 2011.

Failure to maintain effective internal controls in accordance with Section 404 of the Sarbanes-Oxley Act could have a material adverse effect on the trading price of our common stock and Series B Preferred Stock.A preferred stock.

Section 404 of the Sarbanes-Oxley Act of 2002 requires our management to assess the effectiveness of its internal control over financial reporting and to provide a report by its registered independent public accounting firm addressing the effectiveness of our internal control over financial reporting. The Committee of Sponsoring Organizations of the Treadway Commission (COSO) provides a framework for companies to assess and improve their internal control systems. If we are unable to assert that itsour internal control over financial reporting is effective or if our registered independent public accounting firm is unable to express an opinion on the effectiveness of the internal controls or identifies one or more material weaknesses in our internal control over financial reporting, we could lose investor confidence in the accuracy and completeness of itsour financial reports, which in turn could have an adverse effect on the trading price of our common stock and Series A preferred stock. If we fail to maintain the adequacy of our internal controls, we may not be able to ensure that itwe can conclude on an ongoing basis that we have effective internal control over financial reporting in accordance with Section 404 of the Sarbanes-Oxley Act. Failure to achieve and maintain effective internal control over financial reporting could have an adverse effect on the trading price of our common stock and Series A preferred stock.

A small number of customers account for a significant portion of our revenues, and the loss of one or more of these customers could materially adversely affect our financial condition and results of operations.

We derive a significant portion of our revenues from a fewsmall number of customers. During the fiscal year ended December 31, 2012, our four largest customers accounted for approximately 44%, 24%, 11% and 10%, respectively, of our revenue. Our financial condition and results of operations could be materially and adversely affected if any one of these customers interrupts or curtails their activities, fail to pay for the services that have been performed, terminate their contracts, fail to renew their existing contracts or refuse to award new contracts and we are unable to enter into contracts with new customers on comparable terms. The loss of any of our significant customers could materially adversely affect our financial condition and results of operations.

We are exposed to the credit risks of our key customers, including certain affiliated companies, and certain other third parties, and nonpayment by these customers and other parties could adversely affect our financial position, results of operations and cash flows.

We are subject to risks of loss resulting from nonpayment or nonperformance by our customers. Any material nonpayment or nonperformance by key customers and certain other third parties could adversely affect our financial position, results of operations and cash flows. If any key customers or other parties default on their obligations to us, our financial results and condition could be adversely affected. Furthermore, some of these customers and other parties may be highly leveraged and subject to their own operating and regulatory risks.

Our operations might be interrupted by the occurrence of a natural disaster or other catastrophic event.

Our principal executive office is in San Antonio, Texas. Natural disasters or other catastrophic events could disrupt our operations or those of itsour strategic partners, contractors and vendors. Even though we believe we carries commercially reasonable business interruption and liability insurance, and its contractors may carry liability insurance that protect us in certain events, weWe might suffer losses as a result of business interruptions that exceed the coverage available under itsour and itsour contractors' insurance policies or for which itwe or itsour contractors do not have coverage. Any natural disaster or catastrophic event could have a significant negative impact on our operations and financial results, and could delay itsour efforts to identify and execute any strategic opportunities.

SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS

This prospectus contains “forward-looking statements” within the meaning of Section 27A of the Securities Act and Section 21E of the Exchange Act. All statements in this prospectus, other than statements of historical facts, which address activities, events or developments that we expect or anticipate will or may occur in the future, including such things as future capital expenditures, growth, product development, sales, business strategy and other similar matters are forward-looking statements. You can identify forward-looking statements by terminology such as “may,” “will,” “would,” “could,” “should,” “expect,” “intend,” “plan,” “anticipate,” “believe,” “estimate,” “predict,” “potential,” “continue” or the negative of these terms or other similar expressions or phrases. These forward-looking statements are based largely on our current expectations and assumptions and are subject to a number of risks and uncertainties, many of which are beyond our control. Actual results could differ materially from the forward-looking statements set forth herein as a result of a number of factors, including, but not limited to, our products’ current state of development, the need for additional financing, changes in our business strategy, competition in various aspects of our business, the risks described under “Risk Factors” beginning on page[·] of this prospectus and other risks detailed in our reports filed with the Securities and Exchange Commission, or the SEC. In light of these risks and uncertainties, all of the forward-looking statements made herein are qualified by these cautionary statements and there can be no assurance that the actual results or developments anticipated by us will be realized. We undertake no obligation to update or revise any of the forward-looking statements contained in this prospectus. All forward-looking statements attributable to us are expressly qualified in their entirety by these cautionary statements.

MATERIAL U.S. FEDERAL INCOME TAX CONSEQUENCES

Subject to the assumptions, qualifications, and limitations set forth below, the following is the opinion of Reicker, Pfau, Pyle & McRoy LLP, counsel to EnerJex, with respect to the material U.S. federal income tax consequences to “U.S. holders” and “Non-U.S. holders” (each as defined below) of the purchase, ownership and disposition of Series B Preferred Stock offered by the selling stockholders under this prospectus. Counsel’s opinions are limited to statements of U.S. federal income tax law and regulations and legal conclusions with respect thereto.

This discussion is based upon provisions of the Internal Revenue Code of 1986, as amended (the “Code”), Treasury regulations, rulings and judicial decisions as of the date hereof. These authorities may change, perhaps retroactively, which could result in U.S. federal income tax consequences different from those summarized below. This discussion only applies to purchasers who purchase and hold the Series A Preferred Stock as capital assets within the meaning of Section 1221 of the Code (generally property held for investment). This discussion does not address all aspects of U.S. federal income taxation (such as the alternative minimum tax) and does not describe any foreign, state, local or other tax considerations that may be relevant to a purchaser or holder of Series B Preferred Stock in light of their particular circumstances. In addition, this discussion does not describe the U.S. federal income tax consequences applicable to a purchaser or holder of Series B Preferred Stock who is subject to special treatment under U.S. federal income tax laws (including, a corporation that accumulates earnings to avoid U.S. federal income tax, a pass-through entity or an investor in a pass-through entity, a tax-exempt entity, pension or other employee benefit plans, financial institutions or broker-dealers, persons holding Series B Preferred Stock as part of a hedging or conversion transaction or straddle, a person subject to the alternative minimum tax, an insurance company, former U.S. citizens, or former long-term U.S. residents). We cannot assure you that a change in law will not significantly alter the tax considerations that we describe in this discussion. Counsel’s opinions are an expression of professional judgment and are not a guarantee of a result and are not binding on the Internal Revenue Service or the courts. Accordingly, no assurance can be given that counsel’s opinions set forth herein will be sustained if challenged by the Internal Revenue Service.

If a partnership (or any other entity treated as a partnership for U.S. federal income tax purposes) holds Series B Preferred Stock, the U.S. federal income tax treatment of a partner of that partnership generally will depend upon the status of the partner and the activities of the partnership. If you are a partnership or a partner of a partnership holding our Series B Preferred Stock, you should consult your tax advisors as to the particular U.S. federal income tax consequences of holding and disposing of our Series B Preferred Stock.

THIS DISCUSSION CANNOT BE USED BY ANY HOLDER FOR THE PURPOSE OF AVOIDING TAX PENALTIES THAT MAY BE IMPOSED ON SUCH HOLDER. IF YOU ARE CONSIDERING THE PURCHASE OF OUR SERIES B PREFERRED STOCK, YOU SHOULD CONSULT YOUR OWN TAX ADVISORS CONCERNING THE U.S. FEDERAL INCOME TAX CONSEQUENCES OF PURCHASING, OWNING AND DISPOSING OF OUR SERIES B PREFERRED STOCK IN LIGHT OF YOUR PARTICULAR CIRCUMSTANCES AND ANY CONSEQUENCES ARISING UNDER OTHER FEDERAL TAX LAW AND THE LAWS OF APPLICABLE STATE, LOCAL AND FOREIGN TAXING JURISDICTIONS. YOU SHOULD ALSO CONSULT WITH YOUR TAX ADVISORS CONCERNING ANY POSSIBLE ENACTMENT OF LEGISLATION THAT WOULD AFFECT YOUR INVESTMENT IN OUR SERIES B PREFERRED STOCK IN YOUR PARTICULAR CIRCUMSTANCES.

U.S. holders:

You are a “U.S. holder” if you are a beneficial owner of Series B Preferred stock and you are for U.S. federal income tax purposes:

Distributions in General. If distributions are made with respect to our Series B Preferred Stock, such distributions will be treated as dividends to the extent of our current and accumulated earnings and profits as determined under the Code. Any portion of a distribution that exceeds our current and accumulated earnings and profits will first be applied to reduce a U.S. holder’s tax basis in the Series B Preferred Stock on a share-by-share basis, and the excess will be treated as gain from the disposition of the Series B Preferred Stock, the tax treatment of which is discussed below under “Material U.S. Federal Income Tax Consequences—U.S. holders: Disposition of Series B Preferred Stock, Including Redemptions.”

Dividends received by individual U.S. holders of Series B Preferred Stock will be subject to a reduced maximum tax rate of 20% if such dividends are treated as “qualified dividend income” for U.S. federal income tax purposes. The rate reduction does not apply to dividends received to the extent that the individual U.S. holder elects to treat the dividends as “investment income,” which may be offset against investment expenses. Furthermore, the rate reduction does not apply to dividends that are paid to individual U.S. holders with respect to the Series B Preferred Stock that is held for 60 days or less during the 121-day period beginning on the date which is 60 days before the date on which the Series B Preferred Stock becomes ex-dividend. Also, if a dividend received by an individual U.S. holder that qualifies for the rate reduction is an “extraordinary dividend” within the meaning of Section 1059 of the Code, any loss recognized by such individual U.S. holder on a subsequent disposition of the stock will be treated as long-term capital loss to the extent of such “extraordinary dividend,” irrespective of such U.S. holder’s holding period for the stock. In addition, under the Patient Protection and 2010 Reconciliation Act (the “2010 Reconciliation Act”), dividends recognized after December 31, 2013, by U.S. holders that are individuals could be subject to the 3.8% tax on net investment income. Individual U.S. holders should consult their own tax advisors regarding the implications of these rules in light of their particular circumstances.

Dividends received by corporations generally will be eligible for the dividends-received deduction. This deduction is allowed if the underlying stock is held for at least days during the 91 day period beginning on the date 45 days before the ex-dividend date of the stock, and for cumulative preferred stock with an arrearage of dividends, the holding period is at least 91 days during the 181 day period beginning on the date 90 days before the ex-dividend date of the stock. If a corporate stockholder receives a dividend on the Series B Preferred Stock that is an “extraordinary dividend” within the meaning of Section 1059 of the Code, the corporate stockholder in certain instances must reduce its basis in the Series B Preferred Stock by the amount of the “nontaxed portion” of such “extraordinary dividend” that results from the application of the dividends-received deduction. If the “nontaxed portion” of such “extraordinary dividend” exceeds such corporate stockholder’s basis, any excess will be taxed as gain as if such stockholder had disposed of its shares in the year the “extraordinary dividend” is paid. Each domestic corporate holder of Series B Preferred Stock is urged to consult with its tax advisors with respect to the eligibility for and amount of any dividends received deduction and the application of Section 1059 of the Code to any dividends it receives.

Constructive Distributions on Series B Preferred Stock; EnerJex's Call Option. A distribution by a corporation of its stock deemed made with respect to its preferred stock is treated as a distribution of property to which Section 301 of the Code applies. If a corporation issues preferred stock that may be redeemed at a price higher than its issue price, the excess (a “redemption premium”) is treated under certain circumstances as a constructive distribution (or series of constructive distributions) of additional preferred stock.

The constructive distribution of property equal to the redemption premium would accrue without regard to the U.S. holder’s method of accounting for U.S. federal income tax purposes at a constant yield determined under principles similar to the determination of original issue discount (“OID”) under Treasury regulations under Sections 1271 through 1275 of the Code (the “OID Rules”). The constructive distributions of property would be treated for U.S. federal income tax purposes as actual distributions of Series B Preferred Stock that would constitute a dividend, return of capital or capital gain to the U.S. holder of the stock in the same manner as cash distributions described under the heading “Material U.S. Federal Income Tax Consequences—U.S. holders: Distributions in General.” The application of principles similar to those applicable to debt instruments with OID to a redemption premium for the Series B Preferred Stock is uncertain.

The Company has the right to call the Series B Preferred Stock for redemption on or after [·] (the “call option”). The stated redemption price of the Series B Preferred Stock upon the Company’s exercise of the call option is equal to the liquidation preference of the Series B Preferred Stock (i.e., $25, plus accrued and unpaid dividends) and is payable in cash.

If the redemption price of the Series B Preferred Stock exceeds the issue price of the Series B Preferred Stock upon the exercise of the call option, the excess will be treated as a redemption premium that may result in certain circumstances in a constructive distribution or series of constructive distributions to U.S. holders of additional Series B Preferred Stock. The redemption price for the Series B Preferred Stock should be the liquidation preference of the Series B Preferred Stock (i.e., $25, plus accrued and unpaid dividends). Assuming that the issue price of the Series B Preferred Stock is determined under principles similar to the OID Rules, the issue price for the Series B Preferred Stock should be the initial offering price at which a substantial amount of the Series B Preferred Stock is sold.

A redemption premium for the Series B Preferred Stock should not result in constructive distributions to U.S. holders of the Series A Preferred Stock if the redemption premium is less than a de minimis amount as determined under principles similar to the OID Rules. A redemption premium for the Series B Preferred Stock should be considered de minimis if such premium is less than [·] of the Series B Preferred Stock’s liquidation value of $25 at maturity, multiplied by the number of complete years to maturity. Because the determination under the OID Rules of a maturity date for the Series B Preferred Stock is unclear, the remainder of this discussion assumes that the Series B Preferred Stock is issued with a redemption premium greater than a de minimis amount.

In addition, our call option should not require constructive distributions of the redemption premium if, based on all of the facts and circumstances as of the issue date, the redemption pursuant to the Company’s call option is not more likely than not to occur. The Treasury regulations provide that an issuer’s right to redeem will not be treated as more likely than not to occur if: (i) the issuer and the holder of the stock are not related within the meaning of Section 267(b) or Section 707(b) of the Code (substituting “20%” for the phrase “50%”); (ii) there are no plans, arrangements, or agreements that effectively require or are intended to compel the issuer to redeem the stock; and (iii) exercise of the right to redeem would not reduce the yield on the stock determined using principles applicable to the determination of OID under the OID rules. The fact that a redemption right is not described in the preceding sentence does not mean that an issuer’s right to redeem is more likely than not to occur and the issuer’s right to redeem must still be tested under all the facts and circumstances to determine if it is more likely than not to occur. The Company believes that its right to redeem the Series B Preferred Stock should not be treated as more likely than not to occur under the foregoing test. Accordingly, no U.S. holder of Series B Preferred Stock should be required to recognize constructive distributions of the redemption premium because of the Company’s call option.

Disposition of Series B Preferred Stock, Including Redemptions. Upon any sale, exchange, redemption (except as discussed below), or other disposition of the Series B Preferred Stock, a U.S. holder will recognize capital gain or loss equal to the difference between the amount realized by the U.S. holder and the U.S. holder’s adjusted tax basis in the Series B Preferred Stock. Such capital gain or loss will be long-term capital gain or loss if the U.S. holder’s holding period for the Series B Preferred Stock is longer than one year. A U.S. holder should consult its own tax advisors with respect to applicable tax rates and netting rules for capital gains and losses. Certain limitations exist on the deduction of capital losses by both corporate and non-corporate taxpayers. In addition, under the 2010 Reconciliation Act, gains recognized after December 31, 2013, by U.S. holders that are individuals could be subject to the 3.8% tax on net investment income.

A redemption of shares of the Series B Preferred Stock will generally be a taxable event. If the redemption is treated as a sale or exchange, instead of a dividend, a U.S. holder will recognize capital gain or loss (which will be long-term capital gain or loss, if the U.S. holder’s holding period for such Series B Preferred Stock exceeds one year), equal to the difference between the amount realized by the U.S. holder and the U.S. holder’s adjusted tax basis in the Series B Preferred Stock redeemed, except to the extent that any cash or the Company’s common stock or Series B Preferred Stock received is attributable to any accrued but unpaid dividends on the Series B Preferred Stock, which will be subject to the rules discussed above in “Material U.S. Federal Income Tax Consequences—U.S. holders: Distributions in General.” A payment made in redemption of Series B Preferred Stock may be treated as a dividend, rather than as payment in exchange for the Series B Preferred Stock, unless the redemption:

In determining whether any of these tests has been met, a U.S. holder must take into account not only shares of Series B Preferred Stock and our common stock or any other stock that the U.S. holder actually owns, but also shares that the U.S. holder constructively owns within the meaning of Section 318 of the Code.

A redemption payment will be treated as “not essentially equivalent to a dividend” if it results in a “meaningful reduction” in a U.S. holder’s aggregate stock interest in the Company, which will depend on the U.S. holder’s particular facts and circumstances at such time. If the redemption payment is treated as a dividend, the rules discussed above in “Material U.S. Federal Income Tax Consequences—U.S. holders: Distributions in General” apply.

Satisfaction of the “complete redemption” and “substantially disproportionate” exceptions is dependent upon compliance with the objective tests set forth in Section 302(b)(3) and Section 302(b)(2) of the Code, respectively. A redemption will result in a “complete redemption” if either all of the shares of our stock actually and constructively owned by a U.S. holder is exchanged in the redemption or all of the shares of our stock actually owned by the U.S. holder is exchanged in the redemption and the U.S. holder is eligible to waive, and the U.S. holder effectively waives, the attribution of shares of our stock constructively owned by the U.S. holder in accordance with the procedures described in Section 302(c)(2) of Code. A redemption does not qualify for the “substantially disproportionate” exception if the stock redeemed is only non-voting stock, and for this purpose, stock which does not have voting rights until the occurrence of an event is not voting stock until the occurrence of the specified event. Accordingly, any redemption of Series B Preferred Stock generally will not qualify for this exception because the voting rights are limited as provided in the “Description of Our Series B Preferred Stock—Voting Rights.”

For purposes of the “redemption from non-corporate U.S. holders in a partial liquidation” test, a distribution will be treated as in partial liquidation of a corporation if the distribution is not essentially equivalent to a dividend (determined at the corporate level rather than the stockholder level) and the distribution is pursuant to a plan and occurs within the taxable year in which the plan was adopted or within the succeeding taxable year. For these purposes, a distribution is generally not essentially equivalent to a dividend if the distribution results in a corporate contraction. The determination of what constitutes a corporate contraction is factual in nature, and had been interpreted under case law to include the termination of a business or line of business.

Each U.S. holder of Series B Preferred Stock should consult its own tax advisors to determine whether a payment made in redemption of Series B Preferred Stock will be treated as a dividend or a payment in exchange for the Series B Preferred Stock. If the redemption payment is treated as a dividend, the rules discussed above in “Material U.S. Federal Income Tax Consequences—U.S. holders: Distributions in General” apply.

Under proposed Treasury regulations, if any amount received by a U.S. holder in redemption of Series B Preferred Stock is treated as a distribution with respect to such U.S. holder’s Series B Preferred Stock, but not as a dividend, such amount will be allocated to all shares of Series B Preferred Stock held by such U.S. holder immediately before the redemption on a pro-rata basis. The amount applied to each share will reduce such U.S. holder’s adjusted tax basis in that share and any excess after the basis is reduced to zero will result in taxable gain. If such U.S. holder has different bases in shares of Series B Preferred Stock, then the amount allocated could reduce a portion of the basis in certain shares while reducing all of the basis, and giving rise to taxable gain, in other shares. Thus, such U.S. holder could have gain even if such U.S. holder’s aggregate adjusted tax basis in all shares of Series B Preferred Stock held exceeds the aggregate amount of such distribution.

The proposed Treasury regulations permit the transfer of basis in the redeemed shares of the Series B Preferred Stock to the U.S. holder’s remaining, unredeemed Series B Preferred stock (if any), but not to any other class of stock held, directly or indirectly, by the U.S. holder. Any unrecovered basis in the Series B Preferred Stock would be treated as a deferred loss to be recognized when certain conditions are satisfied. The proposed Treasury regulations would be effective for transactions that occur after the date the regulations are published as final Treasury regulations. There can, however, be no assurance as to whether, when and in what particular form such proposed Treasury regulations are ultimately finalized.

Information Reporting and Backup Withholding. Information reporting and backup withholding may apply with respect to payments of dividends on the Series B Preferred Stock and to certain payments of proceeds on the sale or other disposition of Series B Preferred Stock. Certain non-corporate U.S. holders may be subject to U.S. backup withholding (currently at a rate of 28%) on payments of dividends on the Series B Preferred Stock and certain payments of proceeds on the sale or other disposition of our Series B Preferred Stock unless the beneficial owner thereof furnishes the payor or its agent with a taxpayer identification number, certified under penalties of perjury, and certain other information, or otherwise establishes, in the manner prescribed by law, an exemption from backup withholding.

U.S. backup withholding tax is not an additional tax. Any amounts withheld under the backup withholding rules may be allowed as a refund or a credit against a U.S. holder’s U.S. federal income tax liability, which may entitle the U.S. holder to a refund, provided the U.S. holder timely furnishes the required information to the Internal Revenue Service.

Non-U.S. holders:

You are a “Non-U.S. holder” if you are a beneficial owner of Series B Preferred Stock and you are not a “U.S. holder.”

Distributions on the Series B Preferred Stock. If distributions (whether in cash or our common stock or Series B Preferred Stock including constructive distributions as discussed under the heading “Material U.S. Federal Income Tax Consequences—U.S. holders: Distributions of Additional Shares of Common Stock or Series B Preferred Stock”) are made with respect to our Series B Preferred Stock, such distributions will be treated as dividends to the extent of our current and accumulated earnings and profits as determined under the Code and may be subject to withholding as discussed below. Any portion of a distribution that exceeds our current and accumulated earnings and profits will first be applied to reduce the Non-U.S. holder’s basis in the Series B Preferred Stock and, to the extent such portion exceeds the Non-U.S. holder’s basis, the excess will be treated as gain from the disposition of the Series B Preferred Stock, the tax treatment of which is discussed below under “Material U.S. Federal Income Tax Consequences—Non-U.S. holders: Disposition of Series B Preferred Stock, Including Redemptions.” In addition, if we are a U.S. real property holding corporation, i.e. a “USRPHC,” which we believe that we are currently, and any distribution exceeds our current and accumulated earnings and profits, we will need to choose to satisfy our withholding requirements either by treating the entire distribution as a dividend, subject to the withholding rules in the following paragraph (and withhold at a minimum rate of 10% or such lower rate as may be specified by an applicable income tax treaty for distributions from a USRPHC), or by treating only the amount of the distribution equal to our reasonable estimate of our current and accumulated earnings and profits as a dividend, subject to the withholding rules in the following paragraph, with the excess portion of the distribution subject to withholding at a rate of 10% or such lower rate as may be specified by an applicable income tax treaty as if such excess were the result of a sale of shares in a USRPHC (discussed below under “Material U.S. Federal Income Tax Consequences—Non-U.S. holders: Disposition of Series B Preferred Stock, Including Redemptions”), with a credit generally allowed against the Non-U.S. holder’s U.S. federal income tax liability in an amount equal to the amount withheld from such excess.

Dividends paid to a Non-U.S. holder of our Series B Preferred Stock will be subject to withholding of U.S. federal income tax at a 30% rate or such lower rate as may be specified by an applicable income tax treaty. However, dividends that are effectively connected with the conduct of a trade or business by the Non-U.S. holder within the United States (and, where a tax treaty applies, are attributable to a permanent establishment maintained by the Non-U.S. holder in the United States) are not subject to the withholding tax, provided certain certification and disclosure requirements are satisfied including completing Internal Revenue Service Form W-8ECI (or other applicable form). Instead, such dividends are subject to U.S. federal income tax on a net income basis in the same manner as if the Non-U.S. holder were a United States person as defined under the Code, unless an applicable income tax treaty provides otherwise. Any such effectively connected dividends received by a foreign corporation may be subject to an additional “branch profits tax” at a 30% rate or such lower rate as may be specified by an applicable income tax treaty.

A Non-U.S. holder of our Series B Preferred Stock who wishes to claim the benefit of an applicable treaty rate and avoid backup withholding, as discussed below, for dividends will be required to (a) complete Internal Revenue Service Form W-8BEN (or other applicable form) and certify under penalties of perjury that such Non-U.S. holder is not a United States person as defined under the Code and is eligible for treaty benefits, or (b) if our Series B Preferred Stock is held through certain foreign intermediaries, satisfy the relevant certification requirements of applicable Treasury regulations.

A Non-U.S. holder of our Series B Preferred Stock eligible for a reduced rate of U.S. withholding tax pursuant to an income tax treaty may obtain a refund of any excess amounts withheld by timely filing an appropriate claim for refund with the Internal Revenue Service.

Disposition of Series B Preferred Stock, Including Redemptions. Any gain realized by a Non-U.S. holder on the disposition of our Series B Preferred Stock will not be subject to U.S. federal income or withholding tax unless:

A Non-U.S. holder described in the first bullet point immediately above will generally be subject to tax on the net gain derived from the sale under regular graduated U.S. federal income tax rates in the same manner as if the Non-U.S. holder were a United States person as defined under the Code, and if the Non-U.S. holder is a corporation, may also be subject to the branch profits tax equal to 30% of its effectively connected earnings and profits or at such lower rate as may be specified by an applicable income tax treaty. An individual Non-U.S. holder described in the second bullet point immediately above will be subject to a flat 30% tax (or at such reduced rate as may be provided by an applicable treaty) on the gain derived from the sale, which may be offset by U.S. source capital losses, even though the individual is not considered a resident of the United States. A Non-U.S. holder described in the third bullet point above will be subject to U.S. federal income tax under regular graduated U.S. federal income tax rates with respect to the gain recognized in the same manner as if the Non-U.S. holder were a United States person as defined under the Code.

If a Non-U.S. holder is subject to U.S. federal income tax on any sale, exchange, redemption (except as discussed below), or other disposition of the Series B Preferred Stock, such Non-U.S. holder will recognize capital gain or loss equal to the difference between the amount realized by the Non-U.S. holder and the Non-U.S. holder’s adjusted tax basis in the Series B Preferred Stock. Such capital gain or loss will be long-term capital gain or loss if the Non-U.S. holder’s holding period for the Series B Preferred Stock is longer than one year. A Non-U.S. holder should consult its own tax advisors with respect to applicable tax rates and netting rules for capital gains and losses. Certain limitations exist on the deduction of capital losses by both corporate and non-corporate taxpayers.

If a Non-U.S. holder is subject to U.S. federal income tax on any disposition of the Series B Preferred Stock, a redemption of shares of the Series B Preferred Stock will be a taxable event. If the redemption is treated as a sale or exchange, instead of a dividend, a Non-U.S. holder generally will recognize long-term capital gain or loss, if the Non-U.S. holder’s holding period for such Series B Preferred Stock exceeds one year, equal to the difference between the amount of cash received and fair market value of property received and the Non-U.S. holder’s adjusted tax basis in the Series B Preferred Stock redeemed, except that to the extent that any cash received is attributable to any accrued but unpaid dividends on the Series B Preferred Stock, which generally will be subject to the rules discussed above in “Material U.S. Federal Income Tax Consequences—Non-U.S. holders: Distributions on the Series B Preferred Stock.” A payment made in redemption of Series B Preferred Stock may be treated as a dividend, rather than as payment in exchange for the Series B Preferred Stock, in the same circumstances discussed above under “Material U.S. Federal Income Tax Consequences—U.S. holders: Disposition of Series B Preferred Stock, Including Redemptions.” Each Non-U.S. holder of Series B Preferred Stock should consult its own tax advisors to determine whether a payment made in redemption of Series B Preferred Stock will be treated as a dividend or as payment in exchange for the Series B Preferred Stock.

Information Reporting and Backup Withholding. We must report annually to the Internal Revenue Service and to each Non-U.S. holder the amount of dividends paid to such Non-U.S. holder and the tax withheld with respect to such dividends, regardless of whether withholding was required. Copies of the information returns reporting such dividends and withholding may also be made available to the tax authorities in the country in which the Non-U.S. holder resides under the provisions of an applicable income tax treaty.

A Non-U.S. holder will not be subject to backup withholding on dividends paid to such Non-U.S. holder as long as such Non-U.S. holder certifies under penalties of perjury that it is a Non-U.S. holder (and the payor does not have actual knowledge or reason to know that such Non-U.S. holder is a United States person as defined under the Code), or such Non-U.S. holder otherwise establishes an exemption.

Depending on the circumstances, information reporting and backup withholding may apply to the proceeds received from a sale or other disposition of our Series B Preferred Stock unless the beneficial owner certifies under penalties of perjury that it is a Non-U.S. holder (and the payor does not have actual knowledge or reason to know that the beneficial owner is a United States person as defined under the Code), or such owner otherwise establishes an exemption.

U.S. backup withholding tax is not an additional tax. Any amounts withheld under the backup withholding rules may be allowed as a refund or a credit against a Non-U.S. holder’s U.S. federal income tax liability provided the required information is timely furnished to the Internal Revenue Service.

Recently Enacted Legislation Relating to Foreign Accounts. Recently enacted legislation (“FATCA”) will generally impose a 30% withholding tax on dividends on Series B Preferred Stock and the gross proceeds of a disposition of Series B Preferred Stock that are paid to: (i) a foreign financial institution (as that term is defined in Section 1471(d)(4) of the Code and the Treasury regulations thereunder) unless that foreign financial institution enters into an agreement with the U.S. Treasury Department to collect and disclose information regarding U.S. account holders of that foreign financial institution (including certain account holders that are foreign entities that have U.S. owners) and satisfies other requirements, or is otherwise exempt from FATCA withholding; and (ii) a “non-financial foreign entity” (as that term is defined in Section 1472(d) of the Code and the Treasury regulations thereunder) unless such entity certifies that it does not have any substantial U.S. owners or provides the name, address and taxpayer identification number of each substantial U.S. owner and such entity satisfies other specified requirements, or otherwise is exempt from FATCA withholding. A Non-U.S. holder should consult its own tax advisors regarding the application of this legislation to it. According to recently issued guidance from the Internal Revenue Service, FATCA withholding will apply to dividends paid on shares of our Series B Preferred Stock starting January 1, 2014, and to gross proceeds from the disposition of shares of our Series B Preferred Stock starting January 1, 2017.

USE OF PROCEEDS

At our offering price of $ per share, the midpoint of the range on the front cover of this prospectus, we estimate the net proceeds to us from the sale of shares of Series B Preferred StockA preferred stock that we are selling in this offering will be approximately $[·],   ], after deducting the underwriting commissions and estimated offering expenses payable by us. A $1.00 increase or decrease in the assumed public offering price of $[·] per share would increase or decrease, respectively, the net proceeds of to us by approximately $ [·],   ], assuming that the number of shares offered by us set forth on the cover page of this prospectus remains the same and after deducting the underwriting commissions and estimated offering expenses payable by us.

We intend to use the net proceeds from the sale of the securities offered by us under this prospectus primarily for capital expenditures to accelerate the development of our oil and natural gas properties located in Eastern Kansas and Easter Colorado. We also may use such proceeds for general corporate purposes including acquisitions, although we do not currently have any agreements, understandings or arrangements with respect to any potential acquisitions. We have historically drawn on our senior revolving credit facility with Texas Capital Bank, N.A. to fund our capital expenditures. We intend to temporarily reduce the amount outstanding under this facility with proceeds from this offering only to reduce interest expenses during the period in which such capital is deployed. We do not intend to use any proceeds from this offering to permanently repay debt.

The actual use of proceeds in the offering may vary from that set forth herein as our management has the discretion to apply the proceeds as they see fit, as management retains broad discretion as to the allocation of net proceeds from this offering.

MARKET PRICE OF AND DIVIDENDS ON ENERJEX COMMON STOCK

AND RELATED STOCKHOLDER MATTERSCAPITALIZATION

The following table shows our capitalization as of December 31, 2013 on an actual basis and as adjusted to reflect this offering of Series A Preferred Units, and the application of the net proceeds as described under “Use of Proceeds.”

You should read this information in conjunction with the sections titled "Business and Properties," "Management's Discussion and Analysis of Financial Condition and Results of Operations" and EnerJex's common stockfinancial statements beginning on pages 32, 26 and F-1, respectively.

⁽¹⁾ As of December 31, 2013, $31,500,000 of borrowings were outstanding under our revolving credit facility. We plan to use the net proceeds from this offering to temporarily reduce the amount outstanding under this facility only to reduce interest expenses during the period in which such capital is quoteddeployed. We do not intend to use any proceeds from this offering to permanently repay debt.

SELECTED HISTORICAL FINANCIAL DATA

The following table presents our selected consolidated historical financial information as of and for the periods indicated. We derived the information in the following tables from, and that information should be read together with and is qualified in its entirety by reference to, our historical consolidated financial statements and the accompanying notes incorporated by reference herein. You should read this information in conjunction with the sections titled "Business and Properties," "Management's Discussion and Analysis of Financial Condition and Results of Operations" and EnerJex's financial statements beginning on the OTCQB under the symbol "ENRJ." The OTCQBpages 32, 26 and F-1, respectively.

Reconciliation of Non-GAAP Financial Measure

Adjusted EBITDA is a regulated quotation servicenon-GAAP financial measure and as used herein represents net income before interest expense, depletion, depreciation and amortization, unrealized gain/loss on oil derivative contracts, and non-recurring income/expenses. We present Adjusted EBITDA because we believe it is an important supplemental measure of our performance that displays real-time quotes, last-sale prices, and volume informationis frequently used by others in over-the-counter (OTC) equity securities. The OTCQBevaluating companies in our industry. Adjusted EBITDA is not a quotation medium for subscribing members, not an issuer listing service,measurement of our financial performance under GAAP and should not be confused with The NASDAQ Stock Market^SMconsidered as an alternative to net income, operating income or any other stock market. There is no established public trading market for our Series A preferred stockperformance measure derived in accordance with GAAP or Series B Preferred Stock. EnerJex's fiscal year ends on December 31st.

As of [Ÿ], 2014, there were [Ÿ] sharesas an alternative to net cash provided by operating activities as a measure of our common stock issued and outstanding. Additionally, we have 1,717,000 shares of common stock reservedprofitability or liquidity. Adjusted EBITDA has significant limitations, including that it does not reflect our cash requirements for issuance upon exercise of outstanding stock options and up to 4,779,460 shares of its common stock reserved for issuance upon conversion of 4,779,460 shares of Series A preferred stock.

Currently, there is only a limited public market for EnerJex stock on the OTCQB. You should also note that the OTCQB is not a listing servicecapital expenditures, contractual commitments, working capital or exchange, but is instead a dealer quotation service for subscribing members.At present, there is no liquid market for our Series B Preferred Shares. Consequently, unless such a market develops in the future, investors subscribing for shares of our Series B Preferred shares would need to be able to hold those shares indefinitely without having the opportunity to sell or otherwise dispose of such shares.debt service. In addition, even if a market develops for our Series B Preferred shares in the future, there can be no assurance regarding how active itother companies may be, and if there is limited in the trading of such shares, then our Series B Preferred shares may be saleable only at a significant discount from the par value of those shares. If our Series B Preferred Stock is not quoted on the OTCQB or if a public market for our Series B Preferred Stock does not develop, then investors may not be able to resell the shares of its common stock that they have received and may lose all of their investment. Ifcalculate Adjusted EBITDA differently than we do, establish a trading market for our Series B Preferred Stock, the market price of our Series B Preferred Stock may be significantly affected by factors suchlimiting their usefulness as actual or anticipated fluctuations in its operating results, general market conditions and other factors. In addition, the stock market has from time to time experienced significant price and volume fluctuations that have particularly affected the market prices for the shares of small companies, which may materially adversely affect the market price of our Series B Preferred Stock. Accordingly, investors may find that the price for our Series B Preferred Stock may be highly volatile and may bear no relationship to its actual financial condition or results of operations.comparative measures.

The following table sets forth a reconciliation of net income (loss) as determined in accordance with GAAP to Adjusted EBITDA for the range of high and low closing bid quotations for our common stock during our most recent two years on the OTCQB. The quotations represent inter-dealer prices without retail markup, markdown or commission, and may not necessarily represent actual transactions.

EnerJex Common Stockperiods indicated:

On February 13, 2014, the closing price as reported on the OTCQB of our common stock was $0.50 per share, respectively. As of February __, 2014, we had [·] record holders of our common stock.

Dividend Policy

We have never declared or paid cash dividends on our common stock and do not intend to pay any cash dividends in the foreseeable future. Holders of our Series A preferred stock are eligible to receive dividends, and we regularly have paid such dividends to holders of our Series A Preferred Stock. Any future determination to pay cash dividends on the common stock will be at the discretion of our board of directors and will depend upon our financial condition, operating results, capital requirements, deployment of resources and ability to engage in strategic transactions, whether or not the merger is consummated, and such other factors as our board of directors deems relevant.

Holders of our Series B Preferred Stock will be entitled to receive, when and as declared by the board of directors, out of funds legally available for the payment of dividends, cumulative cash dividends on the Series B Preferred Stock at a rate of [·]% per annum of the $25.00 liquidation preference per share (equivalent to $[·] per annum per share). However, under certain conditions relating to our non-payment of dividends on the Series B Preferred Stock, the dividend rate on the Series B Preferred Stock may increase to [·]% per annum, which we refer to as the “Penalty Rate.” Dividends will generally be payable on the 31st day of January, July and October and the 30th day of January, commencing [·], 2014. Dividends on the Series B Preferred Stock will accrue regardless of whether:

All payments of dividends made to the holders of Series B Preferred Stock will be credited against the previously accrued dividends on such shares of Series B Preferred Stock. We will credit any dividends paid on the Series B Preferred Stock first to the earliest accrued and unpaid dividend due. The payment of dividends with respect to the Series B Preferred Stock is subordinate to any dividends to which holders of our Series A Preferred Stock are entitled, if any, and subordinate upon liquidation to the holders of the Series A Preferred Stock receiving their full liquidation preference.

Under the terms of our Articles of Incorporation and applicable provisions of the Nevada Revised Statutes, we are not able to make any distributions if we are then insolvent or to the extent that the distribution would cause us to be insolvent. We do not believe that we are presently insolvent. If, in the future, we become insolvent, then we would suspend dividend payments on our Series B Preferred Shares until after we are again solvent. In addition, under our Credit Agreement with our lender, Texas Commerce Bank, N.A., we are prohibited from making cash dividend payments to our stockholders in certain circumstances, including if we are in default of our obligations to our lender. If there arise any circumstances that, under our agreements with our lender, would restrict us from making cash distributions to our stockholders with respect to their stock, then we would not be able to lawfully make those distributions.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

You should read the following discussion and analysis of financial condition and results of operations together with the "Selected Historical Financial Data of EnerJex" section of this prospectus and EnerJex's financial statements and the related notes included in this prospectus. In addition to historical information, the following discussion contains forward-looking statements that involve risks, uncertainties and assumptions. EnerJex's actual results could differ materially from those anticipated by the forward-looking statements due to important factors including, but not limited to, those set forth in the "Risk Factors—Risks Related to EnerJex" section of this prospectus.

Business Overview

Our principal strategy is to acquire and develop oil and natural gas properties locatedproperties. Our business activities are currently focused in the mid-continent region of the United States.Kansas, Colorado, Nebraska and Texas.

Recent Developments

On July 23, 2013, EnerJex, BRE Merger Sub,March 14, 2014, Black Raven Energy, Inc. ("Black Raven"), a Delaware corporation and a wholly ownedwholly-owned subsidiary of EnerJex (Merger Sub), and Black Raven Energy, Inc., a Nevada corporation, entered into an agreementa Settlement and plan of merger (Merger Agreement)Release Agreement with Atlas Resources, LLC, pursuant to which Black Raven would be merged withthe parties settled certain disputes regarding the rights and into Merger Sub and after which Black Raven would be a wholly owned subsidiaryobligations of EnerJex. the parties under that certain Farmout Agreement dated effective as of July 23, 2010.

On September 27,Pursuant to the Settlement Agreement, among other matters, the parties released each other from certain claims and obligations, the Farmout Agreement was terminated, and the parties entered into a new Gathering Agreement and Contract Operating Agreement under which Atlas shall pay to Black Raven an overhead charge of $12,000 per month from December 1, 2013 through November 30, 2015. Unless the transactions contemplated byContract Operating Agreement is terminated at the Merger Agreement were successfully completed.option of either party, after November 30, 2015, from and after December 1, 2015, the overhead charge per month shall be the lesser of (a) $12,000, and (b) an amount equal to $0.25 per thousand cubic feet of natural gas produced in each such month from wells that Black Raven operates for Atlas pursuant to the Contract Operating Agreement.

The following transactions were executedPursuant to the Settlement Agreement, Atlas also agreed to pay Black Raven the sum of $687,938.50 and assign to Black Raven its rights to depth in any zone below the Niobrara formation on September 27, 2013 perapproximately 8,360 acres that are held by production in Phillips and Sedgwick counties in the State of Colorado. In additional, Black Raven agreed to purchase seven non-producing wells from Atlas for $150,000.

On April 9, 2014, pursuant to a lease purchase agreement effective as of March 31, 2014, we closed a sale to Venado Operating Company, LLC of our interests in approximately 2,250 gross acres comprising our Lonesome Dove Project in Lee County, Texas, for (i) $450,000 in cash, and (ii) the right to receive an average overriding royalty interest of approximately 2.4% in the acreage.

Effective immediately prior to the issuance and sale of shares of Series A preferred stock pursuant to this registration statement, we intend to adopt the Amended and Restated Certificate of Designation in the form attached hereto, and thereby modified the terms of the Merger Agreement: (i)Series A preferred stock as set forth therein and as described in this prospectus. Concurrently with the adoption and filing of such Amended and Restated Certificate of Designation, the holders of our existing Series A preferred stock, which is currently convertible into shares of capitalour common stock on a one-for-one basis upon repayment of Black Raven were converted into (a) cash totaling $207,067the original principal value, will exchange each outstanding share of such existing Series A preferred stock for (i) 1 share of common stock and (b) 41,328,914(ii) a number of shares of EnerJex commonSeries A preferred stock (ii) all options underequal to the Black Raven option plan were cancelled, and (iii) all warrants or other rights toquotient determined by dividing (x) that portion of the holder's original Series A preferred stock purchase price that has not yet been paid in dividends, by (y) the original issue price per share at which we sell our shares of capitalSeries A preferred stock of Black Raven were converted into warrants to purchase EnerJex common stock. No fractional shares of EnerJex common stock were issuedunder this registration statement.

That share exchange will be effected under an exchange agreement in connection with the Merger, and holders of Black Raven common stock were entitled to receive cash in lieu thereof. The board of directors and executive officers of EnerJex remained unchanged asform attached hereto. As a result of that share exchange, [    ] shares of Series A preferred stock are issued and outstanding; those shares are not being registered under this registration statement, but will be eligible for resale in the closingpublic capital markets under Rule 144. Each holder of such shares is executing with EnerJex a lock-up agreement, under which such holder has agreed not to sell such shares in the public capital markets for a period of 90 days after the date of the Merger.

 At closing of the transactions contemplated by the Merger Agreement, the previous stockholders of Black Raven owned approximately 38% of the outstanding voting stock of EnerJex and the previous stockholders of EnerJex owned approximately 62% of the outstanding voting stock of EnerJex.final prospectus.

Critical Accounting Policies and Estimates

EnerJex's significant accounting policies are described in Note 2 to EnerJex's financial statements for the year ended December 31, 2012 included in this document. The discussion and analysis of EnerJex's financial statements and results of operations are based upon EnerJex's financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States of America. The discussion and analysis of EnerJex's financial statements and results of operations are based upon EnerJex's financial statements, which have been prepared in accordance with GAAP. The preparation of EnerJex's financial statements requires management to make estimates and judgments that affect the reported amount of assets, liabilities, revenues and expenses, and related disclosure of contingent assets and liabilities. The SEC has defined a company's most critical accounting policies as those that are most important to the portrayal of its financial condition and results of operations, and which requires EnerJex to make its most difficult and subjective judgments, often as a result of the need to make estimates of matters that are inherently uncertain. Based on this definition, EnerJex has identified the critical accounting policypolicies described below.described in Note 1, Summary of Accounting Policies, to EnerJex's financial statements for the year ended December 31, 2013 included in this document.. Although EnerJex believes that its estimates and assumptions are reasonable, they are based upon information available when they are made. Actual results may differ significantly from these estimates under different assumptions or conditions.

Results of Operations

The following table sets forth,presents selected information regarding our operating results from continuing operations. Due to the merger with Black Raven Energy, Inc. on September 27, 2013 (see Note 5), only the results of operations for the periods indicated, EnerJex's results of operations.fourth quarter are included for Black Raven.

^(1) 2012 2013 revenues increased 35%29% to $10.9 million from $8.5 million from $6.3 million during fiscal year 2011.in 2012.  Revenues increased due to increased production sales volume.volumes.  Production sales increased 35%25% to 96,842 net barrels of oil sold during 2012120,634 Boe for 2013 compared to production sales of 71,72996,842 in 2011.2012. Production sales increased as a result ofincreases were due primarily to results from the 2012successful drilling programprograms in theour Cherokee and Mississippian project areas.Mississippi Projects and new production from our Colorado assets that resulted from our acquisition of Black Raven Energy, Inc. on September 27, 2013, as more fully described in Note 5.  Realized prices increased slightly$2.97 to $87.74during 2012 compared to realized prices of $87.63 during 2011.  $90.71 per Boe in 2013 versus $87.74 per Boe for 2012.

^{(2) 2012} 2013 lease operating expenses decreased 10%increased 32% to $4.1 million from $3.1 million from $3.7 million during 2011. Lease operating expenses decreased due to several factors, including the sale of non-core properties in December 2011, and due to increased leveraging of fixed costs associated with the Cherokee project operations. Lease2012. However, lease operating expenses per barrel decreased 33%Boe increased only 5.9% to $33.95 in 2013 from $32.03 per Boe in 2012 from $47.96 per barrel2012.  The 32% increase in 2011. Leaselease operating expenses include transportationin 2013 was due primarily to increased expenses which are paid toassociated with increased Kansas production, and the new Colorado production added in 2013 that resulted from our purchasers as partacquisition of our price differential.Black Raven Energy, Inc. on September 27, 2013 (see Note 5).

^(3) 2012  2013 depletion expense increased 45%9.7% to $1.6$1.7 million compared to $1.1$1.5 million FY2011.for 2012. The depletion expense increase is due primarily to increased production levels as noted in (1) above.  Depletion expense increases are primarily a result of increased production levels.per Boe decreased $1.89 or 13.5% in 2013 compared to 2012.

^{(4) 2012} 2013 professional fees were $1.5$1.1 million, unchanged fromcompared to $1.5 million during 2011.2012. Professional fees decreased as a result of reduced legal fees, and investment banking fees, associated with the capital raising transactions in 2011.  The decrease was offset by increases in consulting fees and engineering fees, legal fees, and audit fees incurred in 2012.  fees.

^{(5) 2012 salaries} Salaries and wages expenses increased 20%more than doubled in 2013 to $0.6$1.4 million compared to $0.5$0.6 million of salaries and wages expense incurred during 2011. Salaries2012. The increase in salaries and wages increasedwas due primarily to the addition of employees to our Kansas and Texas staffs during 2012.2013 and to the addition of Colorado employees on September 27, 2013 following the acquisition of Black Raven Energy, Inc. (see Note 5).

⁽⁶⁾ Administrative expenses in 2013 were unchanged compared to 2012 at $0.8 million. Despite growth in production, employees and the addition of a new field office in 2013, administrative expenses decreased 14% to $0.8 million compared to $1.0 million during 2011. Administrative expenses decreasedwere flat as a result of management's focus on controlling and reducing extraneousthese expenses.

Reserves

Of the 5.8 million Boe of total proved reserves, approximately 49% are classified as proved developed producing, approximately 17% are classified as proved developed non-producing, and approximately 34% are classified as proved undeveloped.

The following table presents summary information regarding our estimated net proved reserves as of December 31, 2013. All calculations of estimated net proved reserves have been made in accordance with the rules and regulations of the SEC, and, except as otherwise indicated, give no effect to federal or state income taxes. The estimates of net proved reserves are based on the reserve reports prepared by MHA Petroleum Consultants LLC, our independent petroleum consultants. For additional information regarding our reserves, please see Note 15 to our audited financial statements as of and for the fiscal year ended December 31, 2013.

Summary of Proved Oil and Gas Reserves

as of December 31, 2013

Liquidity and Capital Resources

Liquidity is a measure of a company's ability to meet potential cash requirements. We have historically met our capital requirements through debt financing, revenues from operationsoprations and the issuance of equity securities. We believe that our historical means of meeting our capital requirements will provide us with adequate liquidity to fund our operations and capital program in 2013.2014.

The following table summarizes total assets, total liabilities and working capital at the year ended December 31, 2012,2013, as compared to the year ended December 31, 2011.2012.

The working capital deficit as of December 31, 2012, includes approximately $492k of accounts payable to Hush Blackwell LLP, which are currently in dispute. The working capital deficit also includes an $825,000 promissory note related to the common stock and asset repurchase from Enutroff, LLC. The promissory note will fully amortize during 2013 and is therefore considered a current liability.

The following table summarizes total current assets, total current liabilities and working capital as of June 30, 2013 and as compared to December 31, 2012.

Senior Secured Credit Facility

On October 3, 2011, EnerJexthe Company and DD Energy, Inc., EnerJex Kansas, Inc., Black Sable Energy, LLC and Working Interest, LLC (Borrowers)("Borrowers") entered into an Amended and Restated Credit Agreement with Texas Capital Bank, N.A. (“Bank”) and other financial institutions and banks that may become a party to the Credit Agreement from time to time. The facilities provided under the Amended and Restated Credit Agreement are to bewere used to refinance Borrowersthe Borrowers’ prior outstanding revolving loan facility with the Bank, dated July 3, 2008, and for working capital and general corporate purposes.

At Borrowersour option, loans under the facility will bear stated interest based on the Base Rate plus Base Rate Margin, or Floating Rate plus Floating Rate Margin (as those terms are defined in the Credit Agreement). The Base Rate will be, for any day, a fluctuating rate per annum equal to the higher of (a) the Federal Funds Rate plus 0.50% and (b) the Bank's prime rate. The Floating Rate shall mean, at Borrower'sBorrowers’ option, a per annum interest rate equal to (i) the Eurodollar Rate plus Eurodollar Margin, or (ii) the Base Rate plus Base Rate Margin (as those terms are defined in the Amended and Restated Credit Agreement). Eurodollar borrowings may be for one, two, three, or six months, as selected by the Borrowers. The margins for all loans are based on a pricing grid ranging from 0.00% to 0.75% for the Base Rate Margin and 2.25% to 3.00% for the Floating Rate Margin based on the Company'sour Borrowing Base Utilization Percentage (as defined in the Amended and Restated Credit Agreement).

BorrowersOn December 15, 2011, we entered into a First Amendment to Amended and Restated Credit Agreement and Second Amended and Restated Promissory Note in the amount of $50,000,000 with the Texas Capital Bank, which closed on December 15, 2011.Bank. The Amendment reflectedreflects the addition of Rantoul Partners, as an additional Borrower and addedadds as additional security for the loans the assets that were held by Rantoul Partners.

InOn August 31, 2012, Borrowerswe entered into a Second Amendment to the Amended and Restated Credit Agreement with Texas Capitalthe Bank. The Second Amendment reflects the following changes:Amendment: (i) the reduction ofincreased our borrowing base to $7,000,000  (ii) reduced the minimum interest rate to 3.75%, ii) an increase in the borrowing base to $7.0 million, iii) the addition of a provision resulting in an event of default if Robert G. Watson ceases to be the chief executive officer of any Borrower for any reason and a successor reasonably acceptable to Administrative Agent is not appointed within one hundred twenty days (120) thereafter, and iv) the addition of(iii) added additional new leases toas collateral for the collateral pool.loan.

On November 2, 2012, Borrowerswe entered into a Third Amendment to the Amended and Restated Credit Agreement with Texas Capitalthe Bank. The Third Amendment reflects the following changes: i) an increase in the(i) increased our borrowing base to $12.150 million, ii) the addition of a provision permitting the repurchase of up to $2,000,000 of common stock on or before December 31, 2013, subject to$12,150,000 and (ii) clarified certain liquidity requirements, iii) the amendment of certain financial covenant definitions for the purposes of clarity,continuing covenants and iv) the provision ofprovided a limited waiver of compliance with one of the covenants so clarified for the failure to comply with the Interest Coverage Ratio for the period endingfiscal quarter ended December 31, 2011.

On January 24, 2013, Borrowerswe entered into a Fourth Amendment to Amended and Restated Credit Agreement, which was made effective as of December 31, 2012 with Texas Capitalthe Bank. The Fourth Amendment reflects the following changes: i) Texas Capital(i) the Bank consented to the restructuring transactions related to the dissolution of Rantoul Partners, and ii) Texas Capital(ii) the Bank terminated a Limited Guaranty, as defined in the Credit Agreement, executed by Rantoul Partners in favor of Texas Capital Bank.the Bank

On April 16, 2013, Texas Capitalthe Bank increased Borrowers currentour borrowing base to $19.5 million, of which we had borrowed $11.0 million as of June 30, 2013. We intend to conduct an additional borrowing base review in the third quarter of 2013 and we expect increases in our oil production and the maturity of our existing oil producing wells to result in an additional borrowing base increase.million.

On September 30, 2013, Borrowerswe entered into a Fifth Amendment to the Amended and Restated Credit Agreement (the Fifth Amendment) with Texas Capital Bank.Agreement.  The Fifth Amendment:Amendment reflects the following changes:  (i) an expanded the principal commitment amount of the Bank to $100,000,000; (ii) increased thean increase in our borrowing base to $38,000,000; (iii) addedthe addition of Black Raven Energy, Inc. and Adena, LLC (Adena) to the Credit Agreement as borrower parties; (iv) addedthe addition of certain collateral and security interests in favor of Texas Capitalthe Bank; and (v) reduced Borrowers'the reduction of our current interest rate to 3.30%.

Satisfaction of our cash obligations for the next 12 months

We intend to meet our near term cash obligations through proceeds from this offering, financings under our credit facility with Texas Capital Bank, and through cash flow generated from operations.

Summary of product research and development

We do not anticipate performing any significant product research and development under our plan of operation.

Expected purchase or sale of any significant equipment

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

Significant changes in the number of employees

There have been no significant changes in number of employees and weWe currently have 1835 full-time employees including field personnel. As production and drilling activities increase or decrease, we may have to continue towill adjust our technical, operational and administrative personnel as appropriate. We are usinguse 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 providersprovides may enhance our ability to contain operating and general expenses and capital costs.

Off-Balance Sheet Arrangements

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

Oil and Gas Properties

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

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

We review the carrying value of our oil and gas 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 and gas 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 and gas prices increase sufficiently such that an excess above the ceiling would have been eliminated (or reduced) if the increased prices were used in the calculations.

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

As of December 31, 2012,2013, approximately 100% of our proved reserves were evaluated by an independent petroleum consultant. All reserve estimates are prepared based upon a review of production histories and other geologic, economic, ownership and engineering data.

Asset Retirement Obligations

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

Share-Based Payments

The value we assign to the options and warrants that we issue is based on the fair market value as calculated by the Black-Scholes pricing model. To perform a calculation of the value of our options and warrants, we determine an estimate of the volatility of our stock. We need to estimate volatility because there has not been enough trading of our stock to determine an appropriate measure of volatility. We believe our estimate of volatility is reasonable, and we review the assumptions used to determine this whenever we issue a new equity instruments. If we have a material error in our estimate of the volatility of our stock, our expenses could be understated or overstated.

Effects of Inflation and Pricing

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

Recently Issued Accounting Pronouncements

EnerJex does not expect the adoption of any recent accounting pronouncements to have a material effect on its financial position, results of operations or cash flows.

BUSINESS AND PROPERTIES

Overview

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, Inc., Black Raven Energy, Inc., and Black Sable Energy, LLC, and our leasehold interests are held in our wholly owned subsidiaries Black Raven Energy, Inc., Adena, LLC, DD Energy, Inc., Black Sable Energy, LLC, Working Interest, LLC, PRB Gathering, Inc. and EnerJex Kansas, Inc.

Recent Developments

On March 14, 2014, Black Raven Energy, Inc. ("Black Raven"), a wholly-owned subsidiary of EnerJex entered into a Settlement and Release Agreement with Atlas Resources, LLC, pursuant to which the parties settled certain disputes regarding the rights and obligations of the parties under that certain Farmout Agreement dated effective as of July 23, 2010.

Pursuant to the Settlement Agreement, among other matters, the parties released each other from certain claims and obligations, the Farmout Agreement was terminated, and the parties entered into a new Gathering Agreement and Contract Operating Agreement under which Atlas shall pay to Black Raven an overhead charge of $12,000 per month from December 1, 2013 through November 30, 2015. Unless the Contract Operating Agreement is terminated at the option of either party, after November 30, 2015, from and after December 1, 2015, the overhead charge per month shall be the lesser of (a) $12,000, and (b) an amount equal to $0.25 per thousand cubic feet of natural gas produced in each such month from wells that Black Raven operates for Atlas pursuant to the Contract Operating Agreement.

Pursuant to the Settlement Agreement, Atlas also agreed to pay Black Raven the sum of $687,938.50 and assign to Black Raven its rights to depth in any zone below the Niobrara formation on approximately 8,360 acres that are held by production in Phillips and Sedgwick counties in the State of Colorado. In additional, Black Raven agreed to purchase seven non-producing wells from Atlas for $150,000.

On April 9, 2014, pursuant to a lease purchase agreement effective as of March 31, 2014, we closed a sale to Venado Operating Company, LLC of our interests in approximately 2,250 gross acres comprising our Lonesome Dove Project in Lee County, Texas, for (i) $450,000 in cash, and (ii) the right to receive an average overriding royalty interest of approximately 2.4% in the acreage.

Effective immediately prior to the issuance and sale of shares of Series A preferred stock pursuant to this registration statement, we intend to adopt the Amended and Restated Certificate of Designation in the form attached hereto, and thereby modified the terms of the Series A preferred stock as set forth therein and as described in this prospectus. Concurrently with the adoption and filing of such Amended and Restated Certificate of Designation, the holders of our existing Series A preferred stock, which is currently convertible into shares of our common stock on a one-for-one basis upon repayment of the original principal value, will exchange each outstanding share of such existing Series A preferred stock for (i) 1 share of common stock and (ii) a number of shares of Series A preferred stock equal to the quotient determined by dividing (x) that portion of the holder's original Series A preferred stock purchase price that has not yet been paid in dividends, by (y) the original issue price per share at which we sell our shares of Series A preferred stock under this registration statement.

That share exchange will be effected under an exchange agreement in the form attached hereto. As a result of that share exchange, [    ] shares of Series A preferred stock are issued and outstanding; those shares are not being registered under this registration statement, but will be eligible for resale in the public capital markets under Rule 144. Each holder of such shares is executing with EnerJex a lock-up agreement, under which such holder has agreed not to sell such shares in the public capital markets for a period of 90 days after the date of the final prospectus.

Our Business

Our principal strategy is to acquire, develop, explore and developproduce domestic onshore oil and natural gas properties locatedproperties. Our business activities are currently focused in the mid-continent region of the United States.Kansas, Colorado, Nebraska, and Texas.

Our total net proved oil and gas reserves as of December 31, 2012,2013 were 2.95.8 million barrels of oil equivalents (BOE), of which 77% was oil. Of the 2.95.8 million barrelsBOE of total proved reserves, approximately 53%49% are classified as proved developed producing, and approximately 47%17% are classified as proved developed non-producing, and approximately 34% are classified as proved undeveloped.

The total PV10 (present value) of our proved reserves as of December 31, 2012,2013 was approximately $61$102 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 [    ], for a reconciliation to the comparable GAAP financial measure. 

Except where noted, the discussion regarding our business in this prospectus is as of December 31, 2013.

Recent Developments

On July 23, 2013, EnerJex, BRE Merger Sub, Inc., a Delaware corporation and a wholly owned subsidiary of EnerJex (Merger Sub), and Black Raven Energy, Inc., a Nevada corporation (Black Raven), entered into an agreement and plan of merger (Merger Agreement) pursuant to which Black Raven would be merged with and into Merger Sub and after which Black Raven would be a wholly owned subsidiary of EnerJex. 

On September 27, 2013, the transactions contemplated by the Merger Agreement were successfully completed.Our Colorado Properties

The following transactions were executed on September 27, 2013 per the termstable below summarizes our current Colorado and Nebraska acreage by project name as of the Merger Agreement: (i) shares of capital stock of Black Raven were converted into (a) cash totaling $207,067 and (b) 41,328,914 shares of EnerJex common stock, (ii) all options under the Black Raven option plan were cancelled, and (iii) all warrants or other rights to purchase shares of capital stock of Black Raven were converted into warrants to purchase EnerJex common stock. No fractional shares of EnerJex common stock were issued in connection with the Merger, and holders of Black Raven common stock were entitled to receive cash in lieu thereof. The board of directors and executive officers of EnerJex remained unchanged as a result of the closing of the Merger.December 31, 2013.

Adena Field Project

At closing of the transactions contemplated by the Merger Agreement, the previous stockholders of Black Raven owned approximately 38% of the outstanding voting stock of EnerJex and the previous stockholders of EnerJex owned approximately 62% of the outstanding voting stock of EnerJex.

Our Opportunity in Kansas

According to the Kansas Geological Survey, the State of Kansas has historically been one of the top 10 domestic oil producing regionsThe Adena Field Project is located in the United States. Approximately 44Denver-Julesburg (“D-J”) Basin in Morgan County, Colorado, where we owned a 100% working interest in 18,760 gross acres as of December 31, 2013. Our acreage position covers the majority of Adena Field, which is the third largest oil field ever discovered in Colorado behind Rangely Field and Wattenberg Field. Adena Field has cumulatively produced 75 million barrels of oil were producedand 125 billion cubic feet of natural gas since its discovery in Kansas during 2012. Twenty companies accounted for approximately 35%the early 1950s. Our acreage in this project is currently held-by-production. The majority of the state’s total production,producing wells in Adena Field were temporarily abandoned or shut-in during the mid-1980’s when oil prices collapsed, and only a small number of wells have been produced since that time.

Approximately 124 wells on our acreage are currently shut-in or temporarily abandoned. We have used new data, analysis and engineering to initially identify approximately 90 wells to be reactivated in the J-Sand formation or recompleted uphole in the D-Sand formation. We intend to reactive vintage secondary recovery injection wells simultaneously with the remaining 65%reactivation and/or recompletion of producer wells. Recompletions and reactivations are expected to cost approximately $200,000 to $250,000 per well and are expected to result in stabilized production rates of approximately 10 barrels of oil per day. We have also identified a number of wells on our acreage that are prospective for natural gas production from the J-Sand and D-Sand formations.

As of December 31, 2013, the Adena Field Project was producing approximately 150 gross barrels of oil per day from 10 J-Sand wells and 9 D-Sand wells at a depth of approximately 5,500 feet. In addition, multiple wells capable of producing natural gas were shut-in at the end of 2013 pending completion of a new purchase contract that was completed in early 2014. Multiple wells were also in various stages of reactivation and recompletion as of December 31, 2013. We intend to aggressively pursue our reactivation and recompletion strategy in 2014. 

Our working interest in our Adena Field Project is subject to a 30% reversionary working interest that will be assigned to an unrelated third party after payout of all acquisition, operating, development, and financing costs including interest. The payout balance associated with this reversionary working interest was estimated to be approximately $28 million as of December 31, 2013.

Niobrara – Colorado & Nebraska

Our Niobrara Project is located in the northeastern portion of the D-J Basin, where we owned a 97% working interest in approximately 59,291 gross acres as of December 31, 2013. Our acreage is located in Phillips and Sedgwick Counties, Colorado, and Perkins County, Nebraska.

Approximately 34,000 acres in this project are held by production and leases on approximately 17,500 acres expire after 2015. As of December 31, 2013, we owned a 100% working interest in 24 Niobrara gas wells and we owned approximately a 6% overriding royalty interest in 180 Niobrara gas wells that are operated by Atlas Resources, LLC. All of these wells are located in Amherst Field in Phillips and Sedgwick Counties, Colorado. As of December 31, 2013, we produced approximately 250 net Mcf of natural gas per day from the Niobrara formation at a depth of approximately 2,500 feet. The majority of this production was attributable to our overriding royalty interest in the wells that are operated by Atlas Resources, LLC.

Our existing Niobrara acreage was high-graded based on structural features identified through analysis of 114 miles of 2D and 165 square miles (105,000 acres) of 3D seismic data on our original position of 330,000 net acres. We have identified more than 3,500 active producers.150 highly-ranked Niobrara drilling locations on our acreage based on 3D seismic analysis, which has historically yielded success rates of approximately 90% in this play. Our acreage is well situated with direct access to the Cheyenne Hub market in immediate proximity to the 1,679-mile Rocky Mountain Express pipeline and the 436-mile Trailblazer pipeline.

In addition to significant historical oil production levelsDJ Basin Resource Play Exposure

Other operators in the region,DJ basin have recently permitted, drilled and tested numerous wells on trend with our Niobrara Project acreage and our Adena Field Project acreage. Operators are targeting numerous potential unconventional resource plays in Permian and Pennsylvanian aged carbonates and shales. These plays are in the early stages of exploration and development, and widespread economic success has not yet been established. We continue to monitor these exploration efforts closely and we believecurrently own and control all depths that a confluenceare prospective for these resource plays under all of the following factors in Eastern Kansas and the surrounding region make it an attractive area for oil development activities:our current acreage position.

Other

We own an average working interest of 9% in 1,011 gross acres located in the Homestead Draw field in Wyoming. As of December 31, 2013, these properties were producing approximately 600 gross mcf of natural gas per day.

Our KansasColorado Properties

The table below summarizes our current Eastern KansasColorado and Nebraska acreage by project name as of December 31, 2012.2013.

MississippianAdena Field Project

Our MississippianThe Adena Field Project is located in Woodson and Greenwood Countiesthe Denver-Julesburg (“D-J”) Basin in Southeast Kansas,Morgan County, Colorado, where we owned a 90%100% working interest in 2,84018,760 gross acres as of December 31, 2012. All2013. Our acreage position covers the majority of Adena Field, which is the leasesthird largest oil field ever discovered in Colorado behind Rangely Field and Wattenberg Field. Adena Field has cumulatively produced 75 million barrels of oil and 125 billion cubic feet of natural gas since its discovery in the early 1950s. Our acreage in this project is currently held-by-production. The majority of the producing wells in Adena Field were temporarily abandoned or shut-in during the mid-1980’s when oil prices collapsed, and only a small number of wells have been produced since that time.

Approximately 124 wells on our acreage are currently held-by-production. In addition, we acquired an additional 3,530 gross acres (2,711 net acres)shut-in or temporarily abandoned. We have used new data, analysis and engineering to initially identify approximately 90 wells to be reactivated in this project at the endJ-Sand formation or recompleted uphole in the D-Sand formation. We intend to reactive vintage secondary recovery injection wells simultaneously with the reactivation and/or recompletion of 2012. Our Mississippianproducer wells. Recompletions and reactivations are expected to cost approximately $200,000 to $250,000 per well and are expected to result in stabilized production rates of approximately 10 barrels of oil per day. We have also identified a number of wells on our acreage that are prospective for natural gas production from the J-Sand and D-Sand formations.

As of December 31, 2013, the Adena Field Project is currentlywas producing approximately 200150 gross barrels of oil per day from 10 J-Sand wells and 9 D-Sand wells at a depth of approximately 5,500 feet. In addition, multiple wells capable of producing natural gas were shut-in at the Mississippianend of 2013 pending completion of a new purchase contract that was completed in early 2014. Multiple wells were also in various stages of reactivation and recompletion as of December 31, 2013. We intend to aggressively pursue our reactivation and recompletion strategy in 2014. 

Our working interest in our Adena Field Project is subject to a 30% reversionary working interest that will be assigned to an unrelated third party after payout of all acquisition, operating, development, and financing costs including interest. The payout balance associated with this reversionary working interest was estimated to be approximately $28 million as of December 31, 2013.

Niobrara – Colorado & Nebraska

Our Niobrara Project is located in the northeastern portion of the D-J Basin, where we owned a 97% working interest in approximately 59,291 gross acres as of December 31, 2013. Our acreage is located in Phillips and Sedgwick Counties, Colorado, and Perkins County, Nebraska.

Approximately 34,000 acres in this project are held by production and leases on approximately 17,500 acres expire after 2015. As of December 31, 2013, we owned a 100% working interest in 24 Niobrara gas wells and we owned approximately a 6% overriding royalty interest in 180 Niobrara gas wells that are operated by Atlas Resources, LLC. All of these wells are located in Amherst Field in Phillips and Sedgwick Counties, Colorado. As of December 31, 2013, we produced approximately 250 net Mcf of natural gas per day from the Niobrara formation at a depth of approximately 1,7002,500 feet. The majority of this production was attributable to our overriding royalty interest in the wells that are operated by Atlas Resources, LLC.

Our existing Niobrara acreage was high-graded based on structural features identified through analysis of 114 miles of 2D and 165 square miles (105,000 acres) of 3D seismic data on our original position of 330,000 net acres. We completed 27 new oil wells and 25 new secondary recovery water injection wellshave identified more than 150 highly-ranked Niobrara drilling locations on our acreage based on 3D seismic analysis, which has historically yielded success rates of approximately 90% in this project during 2013. Water injection from the new injector wellsplay. Our acreage is anticipated to increase oil production from the adjacent oil production wells throughout 2014. Accordingwell situated with direct access to the Kansas Geological Survey,Cheyenne Hub market in immediate proximity to the Mississippian formation has cumulatively produced more than 1 billion barrels of oil in Kansas1,679-mile Rocky Mountain Express pipeline and represents more than 25% of the state's 44 million barrels of annual oil production.436-mile Trailblazer pipeline.

Cherokee ProjectDJ Basin Resource Play Exposure

Our CherokeeOther operators in the DJ basin have recently permitted, drilled and tested numerous wells on trend with our Niobrara Project is locatedacreage and our Adena Field Project acreage. Operators are targeting numerous potential unconventional resource plays in MiamiPermian and Franklin CountiesPennsylvanian aged carbonates and shales. These plays are in Eastern Kansas, wherethe early stages of exploration and development, and widespread economic success has not yet been established. We continue to monitor these exploration efforts closely and we owned an average working interest of 85% in 10,293 gross acres as of December 31, 2012. As of December 31, 2012, approximately 24%currently own and control all depths that are prospective for these resource plays under all of our current acreage position in the Cherokee project was held by production, and numerous low risk development opportunities exist on acreage that is currently undeveloped. Our Cherokee Project is currently producing approximately 250 gross barrels of oil per day from the Squirrel formation at a depth of approximately 600 feet. We completed 35 new oil wells, and 37 new secondary recovery water injection wells in this project during 2013. The Cherokee Project is located in the prolific Paola Rantoul Field, which according to the Kansas Geological Survey has produced approximately 30 million barrels of oil and currently produces approximately 1,000 barrels of oil per day.

On December 14, 2011, we entered into an agreement with Viking Energy Partners, LLC and FL Oil Holdings, LLC (together the "Investors"), effective October 1, 2011, in which we formed a general partnership ("Rantoul Partners") for the purpose of owning and developing certain assets in our Cherokee Project. As part of this agreement, (i) EnerJex contributed certain assets to Rantoul Partners in exchange for an 88.25% ownership interest in Rantoul Partners, and (ii) the Investors contributed $2.35 million to Rantoul Partners in exchange for an 11.75% ownership interest in Rantoul Partners. The Investors contributed an additional $2.65 million throughout 2012, and the entire $5 million of contributed capital was invested in drilling and completion operations on the Rantoul Partners leases by the end of 2012. On January 24, 2013, all of the general partners mutually agreed to dissolve Rantoul Partners effective December 31, 2012. Working interests in the Rantoul Partners leases were ratably assigned to each general partner upon dissolution of Rantoul Partners, and the working interests that comprised the assets of Rantoul Partners are now governed by a joint operating agreement. We received a 75% working interest in the Rantoul Partners leases upon dissolution.position.

Other

We own aan average working interest of 9% in approximately 5841,011 gross acres located in Allen Countythe Homestead Draw field in Eastern Kansas. This acreage is currently producing approximately 5 gross barrels of oil per day and is prospective for increased production from multiple zones.

The Opportunity in South Texas

Technological advances in the oil industry have made great strides over the last decade, especially in the area of drilling and completion technologies, mainly through horizontal drilling and artificial fracture stimulation. Multiple sizeable oil deposits were discovered in South Texas during previous decades, but operators lacked the technology to economically produce oil from these reservoirs at the time of discovery. The availability of modern completion technologies, coupled with the current attractive oil price environment, provides an opportunity for operators to economically produce oil from reservoirs that were discovered in the past but were not fully developed due to technology and economic constraints.

Our Texas Properties

The table below summarizes our current South Texas acreage by project name as of December 31, 2011.

El Toro Project

Our El Toro Project is located in Atascosa and Frio Counties in South Texas.Wyoming. As of December 31, 2012, we owned a weighted average working interest of 46% in 3,433 gross acres, of which the majority is not currently held-by-production. This project was2013, these properties were producing approximately 35600 gross barrelsmcf of oilnatural gas per day from the Olmos formation at a depth of approximately 4,500 feet. We did not drill any wells in this project and focused 100% of our capital budget on our Eastern Kansas and Eastern Colorado projects during 2013.day.

Multiple oil fields surround this project, which combined have produced more than 100 million barrels of oil since the 1950's from the Olmos formation. We believe the El Toro Project acreage was neglected due to its relatively tight (low permeability) reservoir characteristics. Recent advances in stimulation technology have enabled us to drill and complete new oil wells in the El Toro project with a high degree of success. As evidence of this success, we believe that our first two wells in this project produced approximately 100% more oil during the initial 12 months of production than the best well in a directly adjacent field. This directly adjacent field was developed in the 1950’s and has produced approximately 10 million barrels of oil.

We have completed 12 wells in the El Toro Project since 2009. While petrophysical data obtained from these wells has been consistent across the project acreage, production results have been inconsistent. We intend to conduct more testing on additional wells that are temporarily shut-in. Production results from the 3 most recent wells completed in this project have been successful, although the costs and time lag associated with drilling and completing them significantly exceeded our expectations. This is a direct result of the high demand and limited supply of services and equipment available in the El Toro Project area due to the rapidly developing Eagle Ford Shale play. As a result of increasing costs in this project area, we have decided to focus our resources on our Eastern Kansas and Eastern Colorado properties in the near term. We believe the El Toro project is potentially a horizontal drilling candidate, and we intend to study further the horizontal drilling potential of this project during 2014. 

Our Opportunities in Colorado and Nebraska

Black Raven Energy, Inc., EnerJex’s wholly-owned subsidiary, is currently focused on oil and natural gas development in the Denver-Julesburg (DJ) Basin in Colorado and Nebraska. Its assets are focused in two core projects, both of which are located on trend with emerging unconventional resource plays.

Our Colorado Properties

The table below summarizes our current Colorado and Nebraska acreage by project name as of December 31, 2013.

Adena Field Project: Black Raven owns

The Adena Field Project is located in the Denver-Julesburg (“D-J”) Basin in Morgan County, Colorado, where we owned a 100% working interest in approximately 18,760 gross acres located in Morgan County, Colorado coveringas of December 31, 2013. Our acreage position covers the majority of Adena Field, which has been held by production since it was unitized by the Union Oil Company of California (Unocal) in 1956. According to the Colorado Oil and Gas Conservation Commission, Adena is the third largest oil field ever discovered in the history of Colorado behind Rangely Field and Wattenberg havingField. Adena Field has cumulatively produced 75 million barrels of oil and 125 billion cubic feet of natural gas. Nearly allgas since its discovery in the early 1950s. Our acreage in this project is currently held-by-production. The majority of the producing wells in Adena Field were temporarily abandoned or shut-in during the secondary recovery phase in the mid-1980smid-1980’s when oil prices collapsed, and only a small number of wells have been produced since that time.

Black RavenApproximately 124 wells on our acreage are currently producesshut-in or temporarily abandoned. We have used new data, analysis and engineering to initially identify approximately 250 gross90 wells to be reactivated in the J-Sand formation or recompleted uphole in the D-Sand formation. We intend to reactive vintage secondary recovery injection wells simultaneously with the reactivation and/or recompletion of producer wells. Recompletions and reactivations are expected to cost approximately $200,000 to $250,000 per well and are expected to result in stabilized production rates of approximately 10 barrels of oil andper day. We have also identified a number of wells on our acreage that are prospective for natural gas equivalent (68% oil) per dayproduction from the J-Sand and D-Sand formations in this fieldformations.

As of December 31, 2013, the Adena Field Project was producing approximately 150 gross barrels of oil per day from 10 J-Sand wells and 9 D-Sand wells at a depth of approximately 5,500 feet. Approximately 130 wells are currently shut-in or temporarily abandoned, of which Black Raven has initially identified approximately 75 wells to be re-activated in the J-Sand formation or re-completed in the D-sand formation. In addition, Black Raven initiatedmultiple wells capable of producing natural gas were shut-in at the end of 2013 pending completion of a secondary waterflood projectnew purchase contract that was completed in an isolated D-Sand oil pool during the first quarterearly 2014. Multiple wells were also in various stages of reactivation and recompletion as of December 31, 2013. We intend to aggressively pursue our reactivation and recompletion strategy in 2014. 

Black Raven’sOur working interest in itsour Adena Field acreageProject is subject to a 30% reversionary working interest that will be assigned to an unrelated third party subject to the terms and conditions of such agreement, after payout of all acquisition, operating, development, and financing costs including interest. The payout balance associated with this reversionary working interest iswas estimated to be approximately $28 million. The impact of this reversionary working interest has not been factored into Black Raven’s reserve estimatesmillion as of June 30,December 31, 2013.

Niobrara – Colorado & Nebraska

Our Nebraska Properties

Niobrara Project: Black Raven owns leases coveringProject is located in the northeastern portion of the D-J Basin, where we owned a 97% working interest in approximately 50,000 net59,291 gross acres primarilyas of December 31, 2013. Our acreage is located in Phillips and Sedgwick Counties, Colorado, and Perkins County, Nebraska, of which approximately 25,000Nebraska.

Approximately 34,000 acres in this project are held by production and more than 15,000leases on approximately 17,500 acres expire after 2015. Black Raven currently producesAs of December 31, 2013, we owned a 100% working interest in 24 Niobrara gas wells and we owned approximately a 6% overriding royalty interest in 180 Niobrara gas wells that are operated by Atlas Resources, LLC. All of these wells are located in Amherst Field in Phillips and Sedgwick Counties, Colorado. As of December 31, 2013, we produced approximately 250 thousand cubic feet (MCF)net Mcf of natural gas per day from the Niobrara formation in this project, theat a depth of approximately 2,500 feet. The majority of which isthis production was attributable to a 6%our overriding royalty interest that it owns in approximately 200the wells that were drilled during the past few yearsare operated by a large independent oil and gas company.Atlas Resources, LLC.

Black Raven'sOur existing Niobrara acreage was high-graded based on structural features identified through analysis of 114 miles of 2D and 165 square miles (105,000 acres) of 3D seismic data on itsour original position of 330,000 net acres. The company hasWe have identified more than 150 high-rankedhighly-ranked Niobrara drilling locations on its existingour acreage based on 3D seismic analysis, which has historically yielded success rates of approximately 90% in this play. Black Raven'sOur acreage is well situated with direct access to the Cheyenne Hub market andin immediate proximity to the 1,679-mile Rocky Mountain Express pipeline and the 436-mile Trailblazer pipeline.

DJ Basin Resource Play Exposure

Other operators in the DJ basin have recently permitted, drilled and tested numerous wells on trend with our Niobrara Project acreage and our Adena Field Project acreage. Operators are targeting numerous potential unconventional resource plays in Permian and Pennsylvanian aged carbonates and shales. These plays are in the early stages of exploration and development, and widespread economic success has not yet been established. We continue to monitor these exploration efforts closely and we currently own and control all depths that are prospective for these resource plays under all of our current acreage position.

Other

We own an average working interest of 9% in 1,011 gross acres located in the Homestead Draw field in Wyoming. As of December 31, 2013, these properties were producing approximately 600 gross mcf of natural gas per day.

Our Kansas Properties

The table below summarizes our current Kansas acreage by project name as of December 31, 2013.

Mississippian Project

Our Mississippian Project is located in Woodson and Greenwood Counties in Southeast Kansas, where we owned a 90% working interest in 4,040 gross acres and a 70% working interest in 2,330 gross acres as of December 31, 2013. Approximately 73.5% of the gross leased acres in this project are currently held-by-production, meaning such lease continues to be in force because of continuing production from the property.

In December 2013, we acquired a 90% working interest in 1,280 gross acres that are adjacent to acreage that we successfully developed in 2012 and 2013. We acquired a 90% working interest in approximately 1,040 gross acres through a purchase option contained in the Joint Development Agreement with Haas Petroleum, LLC and MorMeg, LLC ("Joint Development Agreement"). Per the terms of the Joint Development Agreement, we had the right to exercise a purchase option after achieving certain capital expenditure hurdles on existing acreage. The capital expenditure hurdles were achieved in December 2013 and we exercised the purchase option for the new acreage effective December 30, 2013. In December 2013, we acquired a 90% working interest in two new leases covering approximately 240 gross acres.

On December 30, 2013, we entered into a Participation Agreement with MorMeg, LLC and Haas Petroleum, LLC, to drill and develop the Golden Project in Woodson County, Kansas. Pursuant to the terms of the Participation Agreement, we acquired a 70% working interest in approximately 2,330 gross acres. We drilled two wells in the Golden Project in January 2014, and both wells were awaiting completion as of March 15, 2014.

As of December 31, 2013, our Mississippian Project was producing approximately 200 gross barrels of oil per day from the Mississippian formation at a depth of approximately 1,700 feet. We drilled and completed 22 new oil wells and 21 new water injection wells in this project during 2013. Water injection from some new injector wellbores commenced in late 2012, and new water injection operations were initiated throughout 2013 as additional injection wells were completed. We have experienced an initial production response on some acreage resulting from water injection, and we anticipate continued production increases during 2014 from water injection operations.

Cherokee Project

Our Cherokee Project is located in Miami and Franklin Counties in Kansas, where we owned an average working interest of 86% in 9,789 gross acres as of December 31, 2013. As of December 31, 2013, approximately 21% of the gross leased acres in the Cherokee Project were held by production, and numerous low risk development opportunities exist on acreage that is currently undeveloped. A majority of the undeveloped leases have between two and five years (terms refer to leases with contractual extension options) remaining in the primary term and we are not currently facing any material lease expiration issues. As of December 31, 2013, our Cherokee Project was producing approximately 250 gross barrels of oil per day from the Squirrel formation at a depth of approximately 600 feet. We drilled 26 new oil wells and 24 new water injection wells during 2013.

Other

We own a 50% working interest in 584 gross acres located in Allen County, Kansas. As of December 31, 2013, these properties were producing less than 10 gross barrels of oil per day.

Our Texas Properties

The table below summarizes our current Texas acreage by project name as of December 31, 2013.

El Toro Project

Our El Toro Project is located in Atascosa and Frio Counties in Texas. As of December 31, 2013, we owned a 40% working interest in 458 gross acres. As of December 31, 2013, this project was producing approximately 30 gross barrels of oil per day from the Olmos formation at a depth of approximately 4,500 feet.

We have completed 12 wells in the El Toro Project since 2009. While petro-physical data obtained from these wells has been consistent across the project acreage, production results have been inconsistent. The 3 most recent wells completed in this project have been successful, although the costs and time lag associated with drilling and completing them significantly exceeded our expectations. This is a direct result of the high demand and limited supply of services and equipment available in the El Toro Project area due to the Eagle Ford Shale play. As a result of increasing costs in this area, we did not drill any new wells in this project in 2013 and decided to focus 100% of our capital budget on our Kansas and Colorado properties. However, we believe the El Toro project is prospective for horizontal drilling, and we intend to evaluate this potential during 2014.

Lonesome Dove Project

Our Lonesome Dove Project is located in Lee County in South Texas. As of December 31, 2013, we owned working interests ranging from 10% to 50% in 2,372 gross acres. Our working interests under this acreage are separated by depth. We own approximately 50% of the gross acreage in horizons above approximately 4,500 feet, and we own a 10% working interest in the gross acreage in horizons below approximately 4,500 feet. We have an agreement with the majority owner of the deep rights wherein we would receive a 15% carried working interest in the first deep well drilled on this acreage at no cost to us. Deeper prospective horizons underlying this acreage include the Eagle Ford Shale, the Austin Chalk formation, the Buda formation, and the Pearsall Shale formation. Lease expirations in this project for the vast majority of the acreage range from 2017 to 2018.

Our Business Strategy

Our principal strategy focuses on the acquisition and development of shallow oil and gas properties that have low production decline rates and offer abundant drilling opportunities with low risk profiles. WeOur oil and gas operations are currently focusing our oil operations in Eastern Kansas, Eastern Colorado, South TexasNebraska, and Nebraska with a near term focus on Eastern Kansas and Eastern Colorado 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.Texas. The principal elements of our business strategy are:

We continually evaluate new oil opportunities in Eastern Kansas, Eastern Colorado, and South Texas and plan to evaluate joint venture opportunities with partners who would contribute capital and or operational expertise to develop leases that we currently own or would acquire as part of a joint venture arrangement. This economic strategy is anticipated to allow us to expand our existing operations at attractive terms. 

Our future financial results will continue to depend on:

We cannot guarantee that we will succeed in any of these respects. Further, we cannot know if the price of crude oil and natural gas prevailing at the time of production will be at a level allowing for profitable production, or that we will be able to obtain additional funding at terms favorable to us to increase our capital resources. A detailed description of these and other risks that could materially impact our actual results is in "Risk Factors".

Our board has implemented a crude oil hedging strategy that will allow management to hedge the majority of our net production.

Drilling Activity

The following table sets forth the results of our drilling activities, including both oil and gas production wells and water injection wells that were drilled and completed during the yearyears ended December 31, 2013, 2012 and the year ended December 31, 2011.