JUNE 17, 2014

ENERJEX RESOURCES, INC.

555,789 Shares of 10% Series A Cumulative Redeemable Perpetual Preferred Stock

$23.75 Per Share

Liquidation Preference $25.00 Per Share

We are offering 555,789 shares of our 10% Series A Cumulative Redeemable Perpetual Preferred Stock, which we refer to as the Series A preferred stock.

Dividends on the Series A preferred stock are cumulative from the date of original issue and will be payable on the last day of each calendar month commencing July 31, 2014 when, as and if declared by our board of directors. Dividends will be payable out of amounts legally available therefor at an initial rate equal to 10% per annum per $25.00 of stated liquidation preference per share, or $2.50 per share of Series A preferred stock per year.

Commencing on June 16, 2017, we may redeem, at our option, the Series A preferred stock, in whole or in part, at a cash redemption price of $25.00 per share, plus any accrued and unpaid dividends to, but not including, the redemption date. The Series A preferred stock has no stated maturity, will not be subject to any sinking fund or other mandatory redemption, and will not be convertible into or exchangeable for any of our other securities.

Holders of the Series A preferred stock generally will have no voting rights except for limited voting rights if dividends payable on the outstanding Series A preferred stock are in arrears for six or more consecutive or non-consecutive monthly dividend periods, or if we fail to maintain the listing of the Series A preferred stock on a national securities exchange for a period of at least 180 days.

There is no established trading market for the Series A preferred stock. Subject to issuance of the offered shares, we anticipate that the outstanding shares of Series A preferred stock will be listed on the NYSE MKT, and we anticipate that the trading symbol will be “ENRJPR.”

Northland Capital Markets and Euro Pacific Capital Inc. are acting as our underwriters in the public offering on a firm commitment basis.

We will receive a maximum of $13,199,989 million in gross proceeds and approximately $11,488,510 in net proceeds, after deducting the underwriting discount and estimated offering expenses payable by us.

See “Use of Proceeds” in this prospectus. There is no arrangement for funds to be received in escrow, trust or similar arrangement.

We expect the Series A preferred stock will be ready for delivery in book-entry form through The Depositary Trust Company on or about June 20, 2014.

Investing in our Series A preferred stock involves significant risks. You should carefully consider the risk factors beginning on page 7 of this prospectus before purchasing any of the Series A preferred stock offered by this prospectus.

NEITHER THE SECURITIES AND EXCHANGE COMMISSION NOR ANY STATE SECURITIES COMMISSION HAS APPROVED OR DISAPPROVED OF THESE SECURITIES OR DETERMINED IF THIS PROSPECTUS IS TRUTHFUL OR COMPLETE. ANY REPRESENTATION TO THE CONTRARY IS A CRIMINAL OFFENSE.

The date of this prospectus is June 17, 2014.

TABLE OF CONTENTS

ABOUT THIS PROSPECTUS

This document does not constitute an offer to sell, or a solicitation of an offer to buy, any securities, in any jurisdiction in which, or from any person to whom, it is unlawful to make any such offer or solicitation in such jurisdiction. The securities are not being offered in any jurisdiction where the offer of such securities is not permitted.

You should rely only on the information contained in this prospectus.  We have not, and the underwriters have not, authorized anyone to provide you with different information. If anyone provides you with different or inconsistent information, you should not rely on it. We are not, and the underwriters are not, making an offer to sell these securities in any jurisdiction where the offer or sale is not permitted or in which the person making that offer or solicitation is not qualified to do so or to anyone to whom it is unlawful to make an offer or solicitation. You should assume that the information appearing in this prospectus is accurate only as of the date on the front cover of this prospectus. Our business, financial condition, results of operations and prospects may have changed since that date. You should read this prospectus and the registration statement of which this prospectus is a part in their entirety before making an investment decision.

We further note that the representations, warranties and covenants made by us in any agreement that is filed as an exhibit to this prospectus were made solely for the benefit of the parties to such agreement, including, in some cases, for the purpose of allocating risk among the parties to such agreement, and should not be deemed to be a representation, warranty or covenant to you. Moreover, such representations, warranties or covenants were accurate only as of the date when made. Accordingly, such representations, warranties and covenants should not be relied on as accurately representing the current state of our affairs.

We are not making any representation to you regarding the legality of an investment in our securities by you under applicable law. You should consult with your own legal advisors as to the legal, tax, business, financial and related aspects of a purchase of our securities.

The information in this prospectus is accurate only as of the date of this prospectus, regardless of the time of delivery of this prospectus or the time of issuance or sale of any securities.

The EnerJex Resources logo is the property of EnerJex Resources, Inc. or a subsidiary thereof. References herein to “$” and “dollars” are to the currency of the United States of America.

In this prospectus, we refer to information regarding potential markets for our products and other industry data. We believe that all such information has been obtained from reliable sources that are customarily relied upon by companies in our industry. However, we have not independently verified any such information.

Information contained on or accessible through our website, www.enerjex.com does not constitute part of this prospectus.

The registration statement containing this prospectus, including the exhibits to the registration statement, provides additional information about us and the securities offered under this prospectus. The registration statement, including the exhibits, can be read on the Securities and Exchange Commission website or at the Securities and Exchange Commission offices mentioned under the heading “Where You Can Find More Information.”

Northland Capital Markets is the trade name for certain capital markets and investment banking services of Northland Securities, Inc., member FINRA/SIPC.

Under Rule 15c6-1 of the Securities Exchange Act of 1934, as amended, trades in the secondary market are required to settle in three business days unless the parties to any such trade expressly agree otherwise. If you wish to trade shares of our Series A preferred stock before their delivery, you should consult your advisors.

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 A preferred stock. You should read this entire prospectus carefully before making a decision about whether to invest in our Series 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 long reserve lives 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. For the three months ended March 31, 2014, we reactivated multiple oil and natural gas wells in our Adena Field Project and initiated natural gas production under a new sales contract. In addition, we successfully completed workovers on eight natural gas wells in our Niobrara Project.

As of March 31, 2014, we owned oil and natural gas leases covering more than 90,000 net acres in Kansas, Colorado, Nebraska, Texas, and Wyoming, 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.

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 May 12, 2014, West Coast Opportunity Fund, LLC ("WCOF"), and Montecito Venture Fund, LLC ("MVP"), executed an irrevocable voting and proxy agreement, pursuant to which MVP agreed to vote its shares of our capital stock, with respect to the election of nominees to our board of directors, in such manner as WCOF directs. WCOF presently owns approximately 45% of our issued and outstanding voting stock, and MVP owns approximately 6% of our issued and outstanding voting stock. By reason of that irrevocable voting and proxy agreement, WCOF will have the right and power to elect a majority of the members of our board of directors.

On May 22, 2014, we entered into a Seventh Amendment to our Amended and Restated Credit Agreement with Texas Capital Bank, N.A. (the “Bank”). In the Seventh Amendment, the Bank consented to the issuance of the Series A preferred stock and payment of dividends thereon.

Effective after closing of trading in our common stock on May 30, 2014, we effected a 1-for-15 reverse stock split, by which each share of our common stock was reclassified, and changed into 1/15^th of a fully paid and nonassessable share of common stock. In lieu of fractions of a share, we are paying to holders of fractions of a share, after the reverse stock split, cash equal to $11.25 per share, which was the minimum value designated in the amended and restated certificate of designations effecting the reverse stock split. All shares held by each stockholder are aggregated for purposes of determining whether that stockholder holds fractions of a share immediately after the reverse stock split.

We have been cleared to submit a listing application to the NYSE MKT. Our ability to become listed on the NYSE MKT is subject to, among other things, maintaining a minimum market price for our common stock for a sufficient period of time as determined by the NYSE MKT. We anticipate that the trading symbol for our common stock on the NYSE MKT will be “ENRJ.” We anticipate that the trading symbol for our Series A preferred stock on the NYSE MKT will be “ENRJPR.”

Effective immediately prior to the issuance and sale of shares of Series A preferred stock pursuant to this prospectus, we intend to adopt the Amended and Restated Certificate of Designation in the form attached as an exhibit to the registration statement of which this prospectus forms a part, and thereby modify 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-1/15^th basis upon repayment of the remaining original principal value, will exchange each outstanding share of such existing Series A preferred stock for (i) a number of shares of our common stock into which such Series A preferred stock is then convertible immediately prior to the exchange (318,630 in the aggregate) 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 pursuant to this prospectus.

That share exchange will be effected under an exchange agreement in the form attached as an exhibit to the registration statement of which this prospectus forms a part. As a result of that share exchange, 112,658 shares of Series A preferred stock will be issued and outstanding; those shares are not being registered under the registration statement of which this prospectus forms a part, but will be eligible for resale in the public capital markets under Rule 144 under the Securities Act of 1933, as amended. Holders representing at least 95% of such shares are executing with EnerJex a lock-up agreement, under which each 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. The aggregate amount of the unpaid original purchase price of our existing Series A preferred stock is $2,675,778.

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.enerjex.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 A preferred stock, see “Description of Series A Preferred Stock” beginning on page 65 of this prospectus.

RISK FACTORS

Investing in our securities has a significant degree of risk. Before you invest in the Series A 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 A preferred stock to decline and you could lose all or part of your investment.

Risks Related to Ownership of Our Series A Preferred Stock

The Series A preferred stock might not have an active trading market, which could reduce its market value and your ability to sell your shares.

An 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 the shares could be reduced and your ability to transfer your shares of Series A preferred stock could be limited. The trading price of the shares will depend on many factors, including the following:

•    prevailing interest rates;

•    the market for similar securities;

•    general economic conditions; and

•    our financial condition, performance and prospects. 

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

Although dividends on the Series A preferred stock are cumulative and will accrue until paid, you will receive cash dividends on the Series A 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 A preferred stock when payable.

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 A preferred stock.

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

The Series A 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 A 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 A preferred stock do not require us to obtain the approval of the holders of the Series A 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 A preferred stock. Upon our liquidation, our obligations to our creditors would rank senior to our Series A preferred stock and would be required to be paid before any payments could be made to holders of our Series A preferred stock.

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

We generally may not redeem the Series A preferred stock prior to June 16, 2017. On and after June 16, 2017, we may redeem the Series A 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 declared) to, but not including, the redemption date. The Series A 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 A 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 A preferred stock have extremely limited voting rights.

Except as expressly stated in the amended and restated certificate of designations governing the Series A preferred stock, as a holder of Series 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. 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 A preferred stock. The provisions relating to the Series A preferred stock do not afford the holders of the Series A 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 A preferred stock, so long as the terms and rights of the holders of Series A preferred stock are not materially and adversely changed.

The issuance of future offerings of preferred stock may adversely affect the value of our Series 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 A 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 two-thirds of the holders of the Series A preferred stock, would be senior to or on parity with our Series A preferred stock would dilute the interests of the holders of Series A preferred stock and any issuance of preferred stock that is senior to the Series A preferred stock could affect our ability to pay dividends on, redeem or pay the liquidation preference on the Series A preferred stock.

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

Distributions paid to corporate U.S. holders of the Series A 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 A 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 A 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 A 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 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 A 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 A 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 A preferred stock unless the holder beneficially owns (directly or by attribution) more than 5% of the total fair market value of the Series A 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 Series A preferred stock is not convertible and if the price of our common stock increases, then holders of Series A preferred stock may not realize a corresponding increase in the value of their Series A preferred stock.

Our Series A preferred stock is not convertible into our common stock and earns dividends at a fixed rate. Accordingly, the market value of our Series A 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 A preferred stock. Moreover, our right to redeem the Series A preferred stock on or after June 16, 2017 could impose a ceiling on its value.

Risks Related 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 March 31, 2014 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 $92 per barrel at year-end 2012. During 2013, the benchmark for crude prices fluctuated between $85 per barrel and $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 from 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 section entitled "Security Holders of Management and Principal Stockholders" beginning on page 60 for more information on the 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 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. West Coast Opportunity Fund, LLC ("WCOF"), which owns approximately 45% of our issued and outstanding voting securities, and Montecito Venture Partners, LLC ("MVP"), which owns approximately 6% of our issued and outstanding voting securities, are parties to an irrevocable voting and proxy agreement, by which MVP granted to WCOF a proxy to vote MVP's shares with regard to the election of our board of directors. That irrevocable voting and proxy agreement gives WCOF the power to elect a majority of the members of our board of directors. 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.

We are exempt from certain governance requirements applicable to other listed companies, and therefore our board will not consist of a majority of "independent directors," and our audit committee will not have three "independent" members.

The listing standards for the NYSE MKT on which our shares of Series A Preferred Stock will be listed for trading generally require that the boards of directors of listed companies consist of a majority of "independent directors," and that a listed company's audit committee must have three independent members. We are a "controlled company" because WCOF and MVP own more than 50% of our issued and outstanding voting securities and are parties to an irrevocable voting and proxy agreement that gives WCOF a proxy to vote MVP's shares, which will give WCOF control of the election of a majority of the members of our board of directors. As a result, we are exempt from the requirement that a majority of our directors be "independent directors." At present, only two of our five directors are "independent directors." In addition, because we are a "smaller reporting company," as such terms are used in the listing standards for the NYSE MKT, our audit committee is not required to have three independent members. At present, our audit committee consists of two persons, both of whom are independent directors.

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 A preferred stock.

Approximately 34% of our total proved reserves as of December 31, 2013 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, 2013 was $102.4 million, versus $60.8 million as of December 31, 2012.   Of the 5.8 million net barrels of oil equivalent at December 31, 2013, approximately 49% are proved developed producing, approximately 17% are classified as proved developed non-producing and approximately 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, 2013 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 received for our oil and gas production in Kansas are typically based on a discount to the relevant benchmark prices, such as NYMEX, that are used for calculating hedge positions. In 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 Kansas, Colorado, Nebraska, Texas, and Wyoming. 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 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 contracts from March 31, 2014 through December 31, 2015 for approximately 215,000 barrels of crude oil at an average price of approximately $87.00 per barrel. The settlement of and the mark to market of these contracts could result in both realized and unrealized hedging losses. For the year ended December 31, 2013, we incurred realized and unrealized hedging losses of approximately $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 Kansas, Colorado, Nebraska, and 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 possible requirements of the Kansas Corporation Commission, the Texas Railroad Commission, and the Colorado Oil and Gas Conservation Commission, to plug orphaned and abandoned wells on our oil and gas leases that 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.

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.

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 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 our 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 our 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 we 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 small number of customers. 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.

Natural disasters or other catastrophic events could disrupt our operations or those of our strategic partners, contractors and vendors. We might suffer losses as a result of business interruptions that exceed the coverage available under our and our contractors' insurance policies or for which we or our 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 our 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 7 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.

USE OF PROCEEDS

At an offering price of $23.75 per share, we estimate the net proceeds to us from the sale of shares of Series A preferred stock that we are selling in this offering will be approximately $11,488,510, after deducting the underwriting discount and estimated offering expenses payable by us. If the underwriter’s option to purchase additional shares is exercised in full, we estimate that we will receive net proceeds of approximately $13,290,308 assuming that the number of shares offered by us, as set forth on the cover page of this prospectus, remains the same and after deducting the underwriting discounts and 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 Kansas and 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, and management retains broad discretion as to the allocation of net proceeds from this offering.

CAPITALIZATION

The following table sets forth our cash and cash equivalents and capitalization as of March 31, 2014:

You should read this information in conjunction with the sections titled "Management's Discussion and Analysis of Financial Condition and Results of Operations," "Business and Properties," and EnerJex's financial statements beginning on pages 26, 33 and F-1, respectively.

⁽¹⁾ As of March 31, 2014, $32,000,000 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 deployed. 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 "Management's Discussion and Analysis of Financial Condition and Results of Operations," "Business and Properties," and EnerJex's financial statements beginning on pages 26, 33 and F-1, respectively.

Reconciliation of Non-GAAP Financial Measure

Adjusted EBITDA is a non-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 is frequently used by others in evaluating companies in our industry. Adjusted EBITDA is not a measurement of our financial performance under GAAP and should not be considered as an alternative to net income, operating income or any other performance measure derived in accordance with GAAP or as an alternative to net cash provided by operating activities as a measure of our profitability or liquidity. Adjusted EBITDA has significant limitations, including that it does not reflect our cash requirements for capital expenditures, contractual commitments, working capital or debt service. In addition, other companies may calculate Adjusted EBITDA differently than we do, limiting their usefulness as comparative measures.

The following table sets forth a reconciliation of net income (loss) as determined in accordance with GAAP to Adjusted EBITDA for the periods indicated:

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. Our business activities are currently focused in Kansas, Colorado, Nebraska and Texas.

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.

On May 22, 2014, we entered into a Seventh Amendment to our Amended and Restated Credit Agreement with Texas Capital Bank, N.A. (the “Bank”). In the Seventh Amendment, the Bank consented to the issuance of the Series A preferred stock and pagment of dividends thereon.

Effective after closing of trading in our common stock on May 30, 2014, we effected a 1-for-15 reverse stock split, by which each share of our common stock was reclassified, and changed into 1/15^th of a fully paid and nonassessable share of common stock. In lieu of fractions of a share, we are paying to holders of fractions of a share, after the reverse stock split, cash equal to a number of shares of our common stock into which such Series A preferred stock is then convertible immediately prior to the exchange (318,630 shares in the aggregate). All shares held by each stockholder are aggregated for purposes of determining whether that stockholder holds fractions of a share immediately after the reverse stock split.

We have been cleared to submit a listing application to the NYSE MKT. Our ability to become listed on the NYSE MKT is subject to, among other things, maintaining a minimum market price for our common stock for a sufficient period of time as determined by the NYSE MKT. We anticipate that the trading symbol for our common stock on the NYSE MKT will be "ENRJ." We anticipate that the trading symbol for our Series A preferred stock on the NYSE MKT will be “ ENRJPR.”

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-1/15^th basis upon repayment of the remaining original principal value, will exchange each outstanding share of such existing Series A preferred stock for (i) 1/15^th of one 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 as an exhibit to the registration statement of which prospectus is a part. As a result of that share exchange, 112,658 shares of Series A preferred stock will be 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. Holders representing at least 95% of such shares are executing with EnerJex a lock-up agreement, under which each 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.

Critical Accounting Policies and Estimates

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 policies 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 presents selected information regarding our operating results from continuing operations. Due to the merger with Black Raven Energy, Inc. on September 27, 2013, only the results of operations for the fourth quarter of 2013 and the first quarter of 2014 include the results of Black Raven.

Results of Operations for the Three Months Ended March 31, 2014 and 2013 compared.

⁽¹⁾ Oil revenues for the three months ended March 31, 2014 were $3,612,579 compared to revenues of $2,337,301 for the three months ended March 31, 2013. Oil revenues increased primarily as a result of increased oil production from assets that were acquired as part of our merger with Black Raven on September 27, 2013. Oil revenues also increased due to a slight increase in realized prices, which increased $3.01 to $91.08 for the quarter ended March 31, 2014 versus $88.07 for the quarter ended March 31, 2013. Oil production and revenue were negatively impacted during the first quarter of 2014 due to unseasonably cold weather and harsh operating conditions.

⁽²⁾ Natural gas revenues for the three months ended March 31, 2014 were $242,398. Natural gas revenues increased primarily as a result of increased natural gas production from assets that were acquired as part of our merger with Black Raven on September 27, 2013.

⁽³⁾ Direct operating costs primarily include direct labor and equipment costs related to pumping, gauging, pulling, well repairs, compression, transportation costs, and general maintenance requirements in our oil and gas fields. These costs also include certain contract labor costs, and other non-capitalized expenses. Direct operating costs for the three months ended March 31, 2014 increased 96% to $1,531,907 from $782,072 for the three months ended March 31, 2013. However, direct operating costs per Boe increased only 5.7% to $31.14 from $29.47. The $749,835 increase in direct operating costs is due primarily to new production associated with the assets that we acquired as part of our merger with Black Raven on September 27, 2013. Direct operating costs also increased as a result of non-recurring expenses that were incurred as a result of unseasonably cold weather and harsh operating conditions during the first quarter of 2014.

⁽⁴⁾ Depreciation, depletion and amortization for the three months ended March 31, 2014 was $763,758 compared to $444,537 for the three months ended March 31, 2013. The increase in depletion expense is due primarily to increased oil and natural gas production during the first quarter of 2014 compared to the first quarter of 2013. Depletion expense per Boe decreased $1.22 or 7.3% in first quarter of 2014 compared to the first quarter of 2013.

⁽⁵⁾ Professional fees for the three months ended March 31, 2014 were $224,902 compared to $356,222 for the three months ended March 31, 2013. The decrease in professional fees is due primarily to a reduction in transaction and lawsuit related legal fees and a reduction in fees related to outsourced third party engineering and consulting work that we conducted during the first quarter of 2013.

⁽⁶⁾ Salaries for the three months ended March 31, 2014 were $310,348 compared to $246,011 for the three months ended March 31, 2013. Salaries increased $64,337 due primarily to the addition of employees following our merger with Black Raven.

⁽⁷⁾ Administrative expenses for the three months ended March 31, 2014 were $141,029 compared to $139,404 for the three months ended March 31, 2013. Despite growth in production, employees and the addition of a new field office in 2013, administrative expenses were flat as a result of management’s focus on controlling and reducing these expenses.

⁽⁸⁾ Interest expense, which includes amortization of deferred financing costs and accretion, for the three months ended March 31, 2014 was $378,928 compared to $118,245 for the three months ended March 31, 2013. Interest expense and amortization of deferred financing costs increased as a result of increased borrowings due to the Fifth Amendment to the Amended and Restated Credit Agreement under our Credit Facility. Accretion increased due to assets that were acquired as part of our merger with Black Raven on September 27, 2013.

⁽⁹⁾ We incurred a loss of $404,353 on our derivative contracts in first quarter of 2014 compared to a loss of $239,941 for the three months ended March 31, 2013. The increase in the loss was due primarily to the completion of contracts during the three month period ended March 31, 2014 and an increase in the WTI benchmark oil price.

⁽¹⁰⁾ Net income for the three months ended March 31, 2014 was $103,634 compared to a net income of $20,036 for the three months ended March 31, 2013. The increase in net income during the first quarter of 2014 compared to the prior year period was primarily a result of higher revenues related to increased production and increased realized sales prices. The increase in net income was partially offset by higher interest expense and increased derivative losses.

Results of Operations for the Years Ended December 31, 2013 and 2014

 ⁽¹⁾ 2013 revenues increased 29% to $10.9 million from $8.5 million in 2012.  Revenues increased due to increased sales volumes.  Production increased 25% to 120,634 Boe for 2013 compared to production of 96,842 in 2012. Production increases were due primarily to results from the successful drilling programs in our Cherokee and 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 $2.97 to $90.71 per Boe in 2013 versus $87.74 per Boe for 2012.

⁽²⁾ 2013 lease operating expenses increased 32% to $4.1 million from $3.1 million during 2012. However, lease operating expenses per Boe increased only 5.9% to $33.95 in 2013 from $32.03 per Boe in 2012.  The 32% increase in lease operating expenses in 2013 was due primarily to increased expenses associated with increased Kansas production, and the new Colorado production added in 2013 that resulted from our acquisition of Black Raven Energy, Inc. on September 27, 2013 (see Note 5).

⁽³⁾ 2013 depletion expense increased 9.7% to $1.7 million compared to $1.5 million for 2012. The depletion expense increase is due primarily to increased production levels as noted in (1) above.  Depletion expense per Boe decreased $1.89 or 13.5% in 2013 compared to 2012.

⁽⁴⁾ 2013 professional fees were $1.1 million, compared to $1.5 million during 2012. Professional fees decreased as a result of reduced legal fees, investment banking fees, consulting fees and engineering fees.

⁽⁵⁾ Salaries and wages more than doubled in 2013 to $1.4 million compared to $0.6 million of salaries and wages expense incurred during 2012. The increase in salaries and wages was due primarily to the addition of employees to our Kansas and Texas staffs during 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 were flat as a result of management's focus on controlling and reducing these 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 operations 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 2014.

The following table summarizes total current assets, total current liabilities and working capital at the quarter ended March 31, 2014, as compared to the year ended December 31, 2013.

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

Senior Secured Credit Facility

On October 3, 2011, the Company and DD Energy, Inc., EnerJex Kansas, Inc., Black Sable Energy, LLC and Working Interest, LLC ("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 were used to refinance the Borrowers’ prior outstanding revolving loan facility with the Bank, dated July 3, 2008, and for working capital and general corporate purposes.

At our 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 Borrowers’ 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 our Borrowing Base Utilization Percentage (as defined in the Amended and Restated Credit Agreement).

On 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 Bank. The Amendment reflects the addition of Rantoul Partners, as an additional Borrower and adds as additional security for the loans the assets held by Rantoul Partners.

On August 31, 2012, we entered into a Second Amendment to Amended and Restated Credit Agreement with the Bank. The Second Amendment: (i) increased our borrowing base to $7,000,000  (ii) reduced the minimum interest rate to 3.75% and (iii) added additional new leases as collateral for the loan.

On November 2, 2012, we entered into a Third Amendment to Amended and Restated Credit Agreement with the Bank. The Third Amendment (i) increased our borrowing base to $12,150,000 and (ii) clarified certain continuing covenants and provided a limited waiver of compliance with one of the covenants so clarified for the fiscal quarter ended December 31, 2011.

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

On April 16, 2013, the Bank increased our borrowing base to $19.5 million.

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

On November 19, 2013, we entered into a Sixth Amendment to the Amended and Restated Credit Agreement. The Sixth Amendment reflects the following changes: (i) added Iberia Bank as a participant into our credit facility, and (ii) made a technical correction to our covenant calculations.

Our current borrowing base is $38 million, of which we had borrowed $32.0 million as of March 31, 2014. We intend to conduct an additional borrowing base review in the second quarter of 2014 and we expect increases in production and the maturity of existing production to result in an additional borrowing base increase as part of the additional borrowing base review. For the three month period ended March 31, 2014 and for the year ended December 31, 2013 the interest rate was 3.3%. This facility expires on October 3, 2015.

On May 22, 2014, we entered into a Seventh Amendment to our Amended and Restated Credit Agreement with Texas Capital Bank, N.A. (the “Bank”). The Seventh Amendment consented to the issuance of the Series A preferred stock.

Effective after closing of trading in our common stock on May 30, 2014, we effected a 1-for-15 reverse stock split, by which each share of our common stock was reclassified, and changed into 1/15^th of a fully paid and nonassessable share of common stock. In lieu of fractions of a share, we are paying to holders of fractions of a share, after the reverse stock split, cash equal to $11.25 per share, which was the minimum value designated in the amended and restated certificate of designations effecting the reverse stock split. All shares held by each stockholder are aggregated for purposes of determining whether that stockholder holds fractions of a share immediately after the reverse stock split.

We have been cleared to submit a listing application to the NYSE MKT. Our ability to become listed on the NYSE MKT is subject to, among other things, maintaining a minimum market price for our common stock for a sufficient period of time as determined by the NYSE MKT. We anticipate that the trading symbol for our common stock on the NYSE MKT will be "ENRJ."

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

We currently have 35 full-time employees including field personnel. As production and drilling activities increase or decrease, we will adjust our technical, operational and administrative personnel as appropriate. We use 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 provides 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

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 costs related to production, general corporate overhead or similar activities.

Proved properties are amortized using the units of production method (UOP). Currently we only have operations in the Unites States of America. The UOP calculation multiplies the percentage of estimated proved reserves produced each quarter by the cost of these reserves. The amortization base in the UOP calculation includes the sum of proved property, net of accumulated depreciation, depletion and amortization (DD&A), estimated future development costs (future costs to access and develop proved reserves) and asset retirement costs, less related salvage value.

The cost of unproved properties are excluded from the amortization calculation until it is determined whether or not proved reserves can be assigned to such properties or until development projects are placed into service. Geological and geophysical costs not associated with specific properties are recorded as proved property immediately. Unproved properties are reviewed for impairment quarterly.

Under the full cost method of accounting, the net book value of oil and gas properties, less deferred income taxes, may not exceed a calculated “ceiling.” The ceiling limitation is (a) the present value of future net revenues computed by applying current prices of oil & gas reserves (with consideration of price changes only to the extent provided by contractual arrangements) to estimated future production of proved oil & gas reserves as of the date of the latest balance sheet presented, less estimated future expenditures (based on current costs) to be incurred in developing and producing the proved reserves computed using a discount factor of 10 percent and assuming continuation of existing economic conditions plus (b) the cost of properties not being amortized plus (c) the lower of cost or estimated fair value of unproven properties included in the costs being amortized less (d) income tax effects related to differences between book and tax basis of properties. Future cash outflows associated with settling accrued retirement obligations are excluded from the calculation. Estimated future cash flows are calculated using end-of-period costs and an unweighted arithmetic average of commodity prices in effect on the first day of each of the previous 12 months held flat for the life of the production, except where prices are defined by contractual arrangements.

Any excess of the net book value of proved oil and gas properties, less related deferred income taxes, over the ceiling is charged to expense and reflected as additional DD&A in the statement of operations. The ceiling calculation is performed quarterly. During the years ended December 31, 2013 and 2012 there were no impairments resulting from the quarterly ceiling tests.

 Proceeds from the sale or disposition of oil and gas properties are accounted for as a reduction to capitalized costs unless a significant portion (greater than 25%) of our reserve quantities are sold, in which case a gain or loss is recognized in income.

As of December 31, 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.

On May 22, 2014, we entered into a Seventh Amendment to our Amended and Restated Credit Agreement with Texas Capital Bank, N.A. (the “Bank”). In the Seventh Amendment, the Bank consented to the issuance of the Series A preferred stock.

Effective after closing of trading in our common stock on May 30, 2014, we effected a 1-for-15 reverse stock split, by which each share of our common stock was reclassified, and changed into 1/15^th of a fully paid and nonassessable share of common stock. In lieu of fractions of a share, we are paying to holders of fractions of a share, after the reverse stock split, cash equal to $11.25 per share, which was the minimum value designated in the amended and restated certificate of designations effecting the reverse stock split. All shares held by each stockholder are aggregated for purposes of determining whether that stockholder holds fractions of a share immediately after the reverse stock split.

We have been cleared to submit a listing application to the NYSE MKT. Our ability to become listed on the NYSE MKT is subject to, among other things, maintaining a minimum market price for our common stock for a sufficient period of time as determined by the NYSE MKT. We anticipate that the trading symbol for our common stock on the NYSE MKT will be "ENRJ."

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 modify 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-1/15^th basis upon repayment of the remaining original principal value, will exchange each outstanding share of such existing Series A preferred stock for (i) 1/15^th of one 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, 112,658 shares of Series A preferred stock will be 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. Holders representing at least 95% of such shares are executing with EnerJex a lock-up agreement, under which each 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 produce domestic onshore oil and natural gas properties. Our business activities are currently focused in Kansas, Colorado, Nebraska, and Texas.

Our total net proved oil and gas reserves as of December 31, 2013 were 5.8 million barrels of oil equivalents (BOE), of which 77% was oil. 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 total PV10 (present value) of our proved reserves as of December 31, 2013 was approximately $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 29, for a reconciliation to the comparable GAAP financial measure. 

Except where noted, the discussion regarding our business in this prospectus is as of March 31, 2014.

Our Colorado Properties

The table below summarizes our current Colorado and Nebraska acreage by project name as of March 31, 2014.

Adena Field Project

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 18,760 gross acres as of March 31, 2014. 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 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 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 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 March 31, 2014, the Adena Field Project was producing approximately 200 gross barrels of oil per day and 725 Mcf of natural gas per day from 13 J-Sand wells and 9 D-Sand wells at a depth of approximately 5,500 feet. During the first quarter, we successfully completed a new contract for the sale of natural gas and initiated natural gas production at the Adena field. We intend to aggressively pursue our reactivation and recompletion strategy at Adena Field throughout 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 March 31, 2014. 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 March 31, 2014, 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. At March 31, 2014, we were producing approximately 460 net Mcf of natural gas per day from the Niobrara formation at a depth of approximately 2,500 feet.

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 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.

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 March 31, 2014, 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 March 31, 2014.

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 March 31, 2014. 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 May 15, 2014.

As of March 31, 2014, 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 our secondary recovery water injection operations, 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 March 31, 2014. As of March 31, 2014, 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 March 31, 2014, our Cherokee Project was producing approximately 230 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 in this project during 2013.

 Other

We own a 50% working interest in 584 gross acres located in Allen County, Kansas. As of March 31, 2014, 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 March 31, 2014.

El Toro Project

Our El Toro Project is located in Atascosa and Frio Counties in Texas. As of March 31, 2014, we owned a 40% working interest in 458 gross acres. As of March 31, 2014, 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

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.  

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. Our oil and gas operations are in Kansas, Colorado, Nebraska, and Texas. The principal elements of our business strategy are:

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".

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 for the three months ended March 31, 2014, and for the years ended December 31, 2013, 2012 and 2011.

The following table sets forth the results of our reactivation and recompletion activities for the three months ended March 31, 2014, and for the fourth quarter ended December 31, 2013 following our acquisition of Black Raven Energy, Inc.

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

The table below sets forth our net oil and natural gas production (net of all royalties, overriding royalties and production due to others), the average sales prices, average production costs and direct lifting costs per unit of production for the periods ending March 31, 2014 and March 31, 2013.

The table below sets forth our net oil equivalent production (net of all royalties, overriding royalties and production due to others) for the years ended December 31, 2013, 2012 and 2011, the average sales prices, average production costs and direct lifting costs per unit of production.

Results of Oil and Gas Producing Activities

The following table shows the results of operations from our oil and gas producing activities for the three months ended March 31, 2014 and 2013.

The following table shows the results of operations from our oil and gas producing activities from the years ended December 31, 2013, and 2012.

Results of operations from these activities have been determined using historical revenues, production costs, depreciation, depletion and amortization of the capitalized costs subject to amortization. General and administrative expenses and interest expense have been excluded from this determination.

Active Wells

The following table sets forth the number of wells that were actively producing oil or injecting water in which we owned an interest as of December 31, 2013.

Reserves

Proved Reserves

The estimated total PV10 (present value) of our proved reserves as of December 31, 2013 was $102.4 million, compared to $60.8 million as of December 31, 2012. Our total net proved oil and gas reserves as of December 31, 2013 were 5.8 million Boe (77% oil), compared to 2.9 million Boe as of December 31, 2012. Of the 5.8 million net Boe of total proved reserves at December 31, 2013, 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.

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.

The estimated PV10 of the 5.8 million Boe is set forth in the following table. The PV10 is calculated using an average net oil price of $87.89 per barrel, an average net natural gas price of $2.85 per Mcf and an average natural gas liquids price of $18.73 per barrel, and by applying an annual discount rate of 10% to the forecasted future net cash flow.  

Summary of Proved Oil and Gas Reserves
as of December 31, 2013

Oil Reserves Reported to Other Agencies

We did not file any estimates of total proved net oil and gas reserves with, or include such information in reports to any federal authority or agency, other than the SEC, during the year ended December 31, 2013.

Title to Properties

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

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

Sale of Oil and Gas

We do not intend to refine our oil production. We expect to sell all or most of our production to a small number of purchasers in a manner consistent with industry practices at prevailing rates by means of long-term and short-term sales contracts, some of which may have fixed price components. In 2013, we sold oil to Coffeyville Resources, Plains Marketing LP, and Sunoco, Inc. on a month-to-month basis (i.e., without a long-term contract). We sold our natural gas to United Energy Trading and Western Operating Company on a month-to-month basis. We also have an ISDA master agreement and a fixed price swap with BP through December 31, 2015. Under current conditions, we should be able to find other purchasers, if needed. All of our produced oil is held in tank batteries. Each respective purchaser picks up the oil from our tank batteries and transports it by truck to refineries. In addition, our board of directors has implemented a crude oil and gas hedging strategy that will allow management to hedge the majority of our net production in an effort to mitigate our exposure to changing oil and natural gas prices in the intermediate term.

Secondary Recovery and Other Production Enhancement Strategies

When an oil field is first produced, the oil typically is recovered as a result of natural pressure within the producing formation, often assisted by pumps of various types. The only natural force present to move the crude oil to the wellbore is the pressure differential between the higher pressure in the formation and the lower pressure in the wellbore. At the same time, there are many factors that act to impede the flow of crude oil, depending on the nature of the formation and fluid properties, such as pressure, permeability, viscosity and water saturation. This stage of production is referred to as "primary production", which typically only recovers 5% to 15% of the crude oil originally in place in a producing formation.

Production from oil fields can often be enhanced through the implementation of "secondary recovery", also known as waterflooding, which is a method in which water is injected into the reservoir through injector wells in order to maintain or increase reservoir pressure and push oil to the adjacent producing wellbores. We utilize waterflooding as a secondary recovery technique for the majority of our oil properties in Eastern Kansas, even in the early stages of production.

As a waterflood matures over time, the fluid produced contains increasing amounts of water and decreasing amounts of oil. Surface equipment is used to separate the produced oil from water, with the oil going to holding tanks for sale and the water being re-injected into the oil reservoir.

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

Markets and Marketing

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

Our market is affected by many factors beyond our control, such as the availability of other domestic production, commodity prices, the proximity and capacity of oil and gas pipelines, and general fluctuations of global and domestic supply and demand. We have currently entered into month-to-month sales contracts with Coffeeville Resources, Plains Marketing, and Sunoco, and we do not anticipate difficulty in finding additional sales opportunities, as and when needed.

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

Competition

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

Governmental Regulation of the Oil and Natural Gas Industry

Our oil exploration, production and related operations are subject to extensive rules and regulations promulgated by federal, state, tribal and local authorities and agencies that impose requirements relating to the exploration and production of oil.

Regulation of Production of Oil and Natural Gas

All of the jurisdictions in which we own or operate producing oil and natural gas properties have statutory provisions regulating the exploration for and production of oil and natural gas, including provisions related to permits for the drilling of wells, bonding requirements to drill or operate wells, the location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled, sourcing and disposal of water used in the drilling and completion process, and the abandonment of wells. In addition, laws and regulations often address conservation matters, including provisions for the unitization or pooling of oil properties, the spacing, plugging and abandonment of wells, rates of production, water discharge, prevention of waste, and other matters. Prior to drilling, we are often required to obtain permits for drilling operations, drilling bonds and file reports concerning operations.

The public attention on the production of oil will most likely increase the regulatory burden on our industry and increase the cost of doing business, which may affect our profitability. Further, failure to comply with applicable rules and regulations can result in substantial penalties. Although we believe we are in substantial compliance with all applicable laws and regulations, such laws and regulations are frequently amended or reinterpreted. Therefore, we are unable to predict the future costs or impact of compliance. Significant expenditures may be required to comply with governmental laws and regulations and may have a material adverse effect on our financial condition and results of operations. Additional proposals and proceedings that affect the oil and natural gas industry are regularly considered by Congress, the states, the FERC and the courts. We cannot predict when or whether any such proposals may become effective.

The failure to comply with these rules and regulations can result in substantial penalties. Our competitors in the oil and natural gas industry are subject to the same regulatory requirements and restrictions that affect our operations.

Moreover, laws and regulations may place burdens from previous operations on current lease owners that can be significant.

 Regulation of Transportation and Sale of Oil

The price we receive from the sale of oil will be affected by the cost of transporting products to markets, and the transportation of oil in common carrier pipelines is subject to rate and access regulation. The FERC regulates interstate oil pipeline transportation rates under the Interstate Commerce Act. In general, interstate oil pipeline rates must be cost-based, although settlement rates agreed to by all shippers are permitted and market based rates may be permitted in certain circumstances. Intrastate oil pipeline transportation rates are subject to regulation by state regulatory commissions. The basis for intrastate oil pipeline regulation, and the degree of regulatory oversight and scrutiny given to intrastate oil pipeline rates, varies from state to state. We are not able to predict with certainty the effect, if any, of these regulations on our intended operations. However, the regulations may increase transportation costs or reduce well head prices for oil.

Sales of oil are not currently regulated and are made at negotiated prices. Nevertheless, Congress could reenact price controls in the future.

Regulation of Transportation and Sales of Natural Gas

Historically, the transportation and sale for resale of natural gas in interstate commerce have been regulated by agencies of the U.S. federal government, primarily FERC. In the past, the federal government has regulated the prices at which natural gas could be sold. While sales by producers of natural gas can currently be made at uncontrolled market prices, Congress could reenact price controls in the future. Deregulation of wellhead natural gas sales began with the enactment of the NGPA, and culminated in adoption of the Natural Gas Wellhead Decontrol Act which removed controls affecting wellhead sales of natural gas effective January 1, 1993. The transportation and sale for resale of natural gas in interstate commerce is regulated primarily under the NGA, and by regulations and orders promulgated under the NGA by FERC. In certain limited circumstances, intrastate transportation and wholesale sales of natural gas may also be affected directly or indirectly by laws enacted by Congress and by FERC regulations.

The price at which we sell natural gas is not currently subject to federal rate regulation and, for the most part, is not subject to state regulation. However, with regard to our physical sales of these energy commodities, we are required to observe anti-market manipulation laws and related regulations enforced by FERC under the EP Act of 2005 and under the Commodity Exchange Act ("CEA"), and regulations promulgated thereunder by the CFTC. The CEA prohibits any person from manipulating or attempting to manipulate the price of any commodity in interstate commerce or futures on such commodity. The CEA also prohibits knowingly delivering or causing to be delivered false or misleading or knowingly inaccurate reports concerning market information or conditions that affect or tend to affect the price of a commodity. Should we violate the anti-market manipulation laws and regulations, we could also be subject to related third-party damage claims by, among others, sellers, royalty owners and taxing authorities.

Intrastate natural gas transportation is also subject to regulation by state regulatory agencies. The basis for intrastate regulation of natural gas transportation and the degree of regulatory oversight and scrutiny given to intrastate natural gas pipeline rates and services varies from state to state. Insofar as such regulation within a particular state will generally affect all intrastate natural gas shippers within the state on a comparable basis, we believe that the regulation of similarly situated intrastate natural gas transportation in any states in which we operate and ship natural gas on an intrastate basis will not affect our operations in any way that is of material difference from those of our competitors. Like the regulation of interstate transportation rates, the regulation of intrastate transportation rates affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas.

Changes in law and to FERC policies and regulations may adversely affect the availability and reliability of firm and/or interruptible transportation service on interstate pipelines, and we cannot predict what future action FERC will take. We do not believe, however, that any regulatory changes will affect us in a way that materially differs from the way they will affect other natural gas producers, gatherers and marketers with which we compete.

Regulation of Environmental and Occupational Safety and Health Matters

Our oil and natural gas exploration and production operations are subject to numerous stringent federal, regional, state and local statutes and regulations governing occupational safety and health, the discharge of materials into the environment or otherwise relating to environmental protection, some of which carry substantial administrative, civil and criminal penalties for failure to comply. These laws and regulations may require the acquisition of a permit before drilling or other regulated activity commences; restrict the types, quantities and concentrations of various substances that can be released into the environment in connection with drilling, production and transporting through pipelines; govern the sourcing and disposal of water used in the drilling and completion process; limit or prohibit drilling activities in certain areas and on certain lands lying within wilderness, wetlands, frontier and other protected areas; require some form of remedial action to prevent or mitigate pollution from former operations such as plugging abandoned wells or closing earthen pits; establish specific safety and health criteria addressing worker protection; and impose substantial liabilities for pollution resulting from operations or failure to comply with regulatory filings. In addition, these laws and regulations may restrict the rate of production.

The following is a summary of the more significant existing environmental and occupational health and safety laws and regulations, as amended from time to time, to which our business operations are subject and for which compliance may have a material adverse impact on our capital expenditures, results of operations or financial position.

Hazardous Substances and Waste Handling

CERCLA, also known as the "Superfund" law, and comparable state laws impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons that are considered to have contributed to the release of a "hazardous substance" into the environment. These persons include the current and past owner or operator of the disposal site or the site where the release occurred and companies that disposed or arranged for the disposal of the hazardous substances at the site where the release occurred. Under CERCLA, such persons may be subject to joint and several strict liability for the costs of cleaning up the hazardous substances that have been released into the environment and for damages to natural resources, and it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. We are able to control directly the operation of only those wells with respect to which we act as operator. Notwithstanding our lack of direct control over wells operated by others, the failure of an operator other than us to comply with applicable environmental regulations may, in certain circumstances, be attributed to us. We generate materials in the course of our operations that may be regulated as hazardous substances but we are unaware of any liabilities for which we may be held responsible that would materially and adversely affect us.

The RCRA and analogous state laws, impose detailed requirements for the generation, handling, storage, treatment and disposal of nonhazardous and hazardous solid wastes. RCRA specifically excludes drilling fluids, produced waters and other wastes associated with the exploration, development or production of crude oil, natural gas or geothermal energy from regulation as hazardous wastes. However, these wastes may be regulated by the EPA or state agencies under RCRA's less stringent nonhazardous solid waste provisions, state laws or other federal laws. Moreover, it is possible that these particular oil and natural gas exploration, development and production wastes now classified as nonhazardous solid wastes could be classified as hazardous wastes in the future. A loss of the RCRA exclusion for drilling fluids, produced waters and related wastes could result in an increase in our costs to manage and dispose of generated wastes, which could have a material adverse effect on our results of operations and financial position. In addition, in the course of our operations, we generate some amounts of ordinary industrial wastes, such as paint wastes, waste solvents, laboratory wastes and waste compressor oils that may be regulated as hazardous wastes if such wastes have hazardous characteristics. Although the costs of managing hazardous waste may be significant, we do not believe that our costs in this regard are materially more burdensome than those for similarly situated companies.

We currently own, lease or operate numerous properties that have been used for oil and natural gas exploration and production activities for many years. Although we believe that we have utilized operating and waste disposal practices that were standard in the industry at the time, hazardous substances, wastes or petroleum hydrocarbons may have been released on, under or from the properties owned or leased by us, or on, under or from other locations, including off-site locations, where such substances have been taken for recycling or disposal. In addition, some of our properties have been operated by third parties or by previous owners or operators whose treatment and disposal of hazardous substances, wastes or petroleum hydrocarbons was not under our control. These properties and the substances disposed or released on, under or from them may be subject to CERCLA, RCRA and analogous state laws. Under such laws, we could be required to undertake response or corrective measures, which could include removal of previously disposed substances and wastes, cleanup of contaminated property or performance of remedial plugging or pit closure operations to prevent future contamination.

Water Discharges

The Clean Water Act and comparable state laws impose restrictions and strict controls regarding the discharge of pollutants, including produced waters and other oil and natural gas wastes, into or near navigable waters. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or the state. The discharge of dredge and fill material in regulated waters, including wetlands, is also prohibited, unless authorized by a permit issued by the U.S. Army Corps of Engineers. Obtaining permits has the potential to delay the development of oil and natural gas projects. These laws and any implementing regulations provide for administrative, civil and criminal penalties for any unauthorized discharges of oil and other substances in reportable quantities and may impose substantial potential liability for the costs of removal, remediation and damages.

Pursuant to these laws and regulations, we may be required to obtain and maintain approvals or permits for the discharge of wastewater or storm water and are required to develop and implement spill prevention, control and countermeasure plans, also referred to as "SPCC plans," in connection with on-site storage of significant quantities of oil. We believe that we maintain all required discharge permits necessary to conduct our operations, and further believe we are in substantial compliance with the terms thereof. We are currently undertaking a review of recently acquired oil properties to determine the need for new or updated SPCC plans and, where necessary, we will be developing or upgrading such plans implementing the physical and operation controls imposed by these plans, the costs of which are not expected to be substantial.

Air Emissions

The federal Clean Air Act and comparable state laws restrict the emission of air pollutants from many sources, such as, for example, compressor stations, through air emissions standards, construction and operating permitting programs and the imposition of other compliance requirements. These laws and regulations may require us to obtain pre-approval for the construction or modification of certain projects or facilities expected to produce or significantly increase air emissions, obtain and strictly comply with stringent air permit requirements or utilize specific equipment or technologies to control emissions of certain pollutants. The need to obtain permits has the potential to delay the development of oil and natural gas projects. Over the next several years, we may be required to incur certain capital expenditures for air pollution control equipment or other air emissions related issues. Compliance air pollution control and permitting requirements has the potential to delay the development of oil and natural gas projects and increase our costs of development and production, which costs could be significant. However, we do not believe that compliance with such requirements will have a material adverse effect on our operations.

In summary, we believe we are in substantial compliance with currently applicable environmental laws and regulations. Although we have not experienced any material adverse effect from compliance with environmental requirements, there is no assurance that this will continue. We did not have any material capital or other non-recurring expenditures in connection with complying with environmental laws or environmental remediation matters in 2013, nor do we anticipate that such expenditures will be material in 2014.

OSHA

We are subject to the requirements of the OSHA and comparable state statutes whose purpose is to protect the health and safety of workers. In addition, the OSHA hazard communication standard, the Emergency Planning and Community Right-to-Know Act and comparable state statutes and any implementing regulations require that we organize and/or disclose information about hazardous materials used or produced in our operations and that this information be provided to employees, state and local governmental authorities and citizens. We believe that we are in substantial compliance with all applicable laws and regulations relating to worker health and safety.

Related Permits and Authorizations

Many environmental laws require us to obtain permits or other authorizations from state and/or federal agencies before initiating certain drilling, construction, production, operation or other oil and natural gas activities, and to maintain these permits and compliance with their requirements for on-going operations. These permits are generally subject to protest, appeal or litigation, which can in certain cases delay or halt projects and cease production or operation of wells, pipelines and other operations.

Employees

We currently have 35 full-time employees, including field personnel. As production and drilling activities increase or decrease, we may have to continue to adjust our technical, operational and administrative personnel as appropriate. We are using and will continue to use independent consultants and contractors to perform various professional services, particularly in the area of land services, reservoir engineering, geology, drilling, water hauling, pipeline construction, well design, well-site monitoring and surveillance, permitting and environmental assessment. We believe that this use of third-party service providers may enhance our ability to contain operating and general expenses, and capital costs. We have no collective bargaining agreements with our employees. We believe that our employee relationships are satisfactory.

Legal Proceedings

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

 On January 23, 2012, we filed a petition seeking recovery of damages arising from breach of contract, legal malpractice, breach of fiduciary duty and fraud in the Circuit Court of Jackson County, Missouri against attorneys Jeffrey T. Haughey, Robert K. Green, and the law firm Husch Blackwell LLP f/k/a Husch Blackwell Sanders, LLC. The petition in this action, EnerJex Resources, Inc., v. Haughey, et al., alleges, among other things, that the defendants violated their fiduciary duties and defrauded us in connection with our stock offering in 2008.

The petition alleges economic loss of approximately $50 million and demands judgment for unspecified actual and punitive damages together with repayment of $484,473 in legal fees paid by EnerJex. At the time the petition was filed, we estimated our economic loss of approximately $50 million by conducting an analysis that considered a number of factors, including the loss of at least $25 million of gross proceeds we would have received in the failed 2008 stock offering, the loss of the value we could have created had it been able to utilize the proceeds from the stock offering to execute its business plan in the 2008 economic environment, and the loss of market value for our common stock.

A trial to hear a portion of this case in the 16th Circuit Court of Jackson County, Missouri, began on December 2, 2013. In that trial, based on its rulings on written motions, the court disallowed our claims for actual and consequential damages for breach of contract and legal malpractice against the defendants. On December 19, 2013, the Company reached an agreement with the defendants to settle our claims for breach of fiduciary duty and fraud in return for (i) the defendants paying to us the sum of $500,000, which was paid to us in January 2014, and (ii) dismissal of the defendants’ counterclaim of $492,134 and interest on that amount, which was removed from our balance sheet and is not reflected as a liability as of March 31, 2014. Our financial statements reflect the litigation costs that we have incurred to date.

In entering into this settlement, the defendants have not admitted liability on any matter related to the claims in the litigation. As part of this settlement, we are now free to appeal the court’s rulings and request from the appellate court authorization to pursue our claims for actual and consequential damages with respect to our claims alleging breach of contract and legal malpractice against the defendants. There can be no assurance of the outcome of the appellate process, including whether the appellate court will allow us to seek actual and consequential damages for breach of contract and legal malpractice and breach of fiduciary duty, as well as what amount of damages, if any, we may recover.

Any additional monetary award resulting from a settlement of this litigation that is reached for our benefit in an amount that exceeds our total costs of litigation, shall be subject to a contingency fee for the benefit of our attorneys. There can be no assurance of the outcome of this litigation, including whether and in what amount EnerJex may recover damages.

MANAGEMENT

Directors, Executive Officers and Corporate Governance

The following table lists the names and ages as of June 16, 2014, and positions of the individuals who serve as directors and executive officers of the Company:

Business Experience:

The principal occupation and business experience during the last five years for each of our directors and executive officers are as follows. Such information is based upon information received by us from such persons.

Robert G. Watson, Jr. Mr. Watson has served as President, Chief Executive Officer, and Secretary since December 31, 2010. Prior to joining EnerJex, he co-founded Black Sable Energy, LLC, approximately 5 years ago and served as its Chief Executive Officer. During his tenure at Black Sable, Mr. Watson was responsible for the company's acquisition and development of two grassroots oil projects in South Texas, both of which were partnered with larger oil and gas companies on a promoted basis. Prior to founding Black Sable, he was a Senior Associate at American Capital, Ltd. (NASDAQ: ACAS), a publicly traded private equity firm and global asset manager with more than $100 billion of total assets under management. Mr. Watson began his career in the Energy Investment Banking Group at CIBC World Markets and subsequently founded and served as the Managing Partner of Centerra Energy Partners, LLC.

R. Atticus Lowe. Mr. Lowe has served as Senior Vice President of Corporate Development since 2011 and as a Director since December 31, 2010. Mr. Lowe is the Chief Investment Officer of West Coast Asset Management, Inc. (WCAM), a registered investment advisor that has invested more than $200 million in the oil and gas industry on behalf of its principals and clients since 2000. WCAM is the Managing Member of West Coast Opportunity Fund, LLC, which currently holds 46.9% of our common stock. Mr. Lowe formerly served as a director and chairman of the audit committee for Black Raven Energy, Inc., until we acquired Black Raven in September 2013. Mr. Lowe is a CFA charterholder.

James G. Miller. Mr. Miller has served as a Director since December 31, 2010. Mr. Miller retired in 2002 after serving as the Chief Executive Officer of Utilicorp United, Inc.'s business unit responsible for the company's electricity generation and electric and natural gas transmission and distribution businesses, which served 1.3 million customers in seven mid-continent states. Utilicorp traded on the New York Stock Exchange, and the company was renamed Aquila in 2002. In 2007, Utilicorp's electricity assets in northwest Missouri were acquired by Great Plains Energy Incorporated (NYSE: GXP) for $1.7 billion, and its natural gas properties and other assets were acquired by Black Hills Corporation (NYSE: BKH) for $940 million. Mr. Miller joined Utilicorp in 1989 through its acquisition of Michigan Gas Utilities, for which he served as the president from 1983 to 1991. Mr. Miller also is a member of the board of directors of Guardian 8 Holdings. He currently serves as Chairman of The Nature Conservancy, Missouri Chapter, for which he has been a Trustee for the past 12 years.

Lance W. Helfert. Mr. Helfert has served as a Director since December 31, 2010. Mr. Helfert is the President and a co-founder of West Coast Asset Management, Inc. (WCAM), a registered investment advisor located in Montecito, California. WCAM is the Managing Member of West Coast Opportunity Fund, LLC, which currently holds 46.9% of our common stock. Prior to co-founding WCAM, he managed a portfolio at Wilshire Associates and was involved in a full range of financial strategies at M.L. Stern & Co. Mr. Helfert is a co-author of The Entrepreneurial Investor: The Art, Science and Business of Value Investing, a book published by John Wiley & Sons. He has been featured in Kiplinger's Personal Finance, Forbes, Barron's, Fortune Magazine, and the Market Watch for his unique market prospective. In addition, Mr. Helfert has been a frequent guest commentator on CNBC and the Fox Business networks. Mr. Helfert has also served on the board of directors for Junior Achievement of Southern California and the Tri-Counties Make-A-Wish Foundation

Richard E. Menchaca. Mr. Menchaca has been a Director since June 6, 2013. Mr. Menchaca attended the University of Texas at Arlington where he received a BBA in Finance and pursued a MBA in Finance, and received a Graduate Degree from the SMU Southwestern School of Banking. Mr. Menchaca spent 18 years in the corporate banking industry with First Republic Bank (n.k.a. Bank of America), Bank One in Fort Worth and Fuji Bank, and Guaranty Bank in Houston. While at Guaranty Bank, Mr. Menchaca was one of the founding members of the Oil and Gas Banking Group, and within 18 months of its formation became the most profitable lending group within the bank with over $900,000,000 of loans to oil and gas industry. Mr. Menchaca was the principal and founder of Petras Energy, LLC, an oil and gas production company based in Midland, Texas. The company was successfully sold in January 2006. Mr. Menchaca has been the founder and principal of several privately owned oil and gas companies with operations in Texas, Oklahoma and Louisiana. Since May 2010, Mr. Menchaca currently presides as President and Chief Executive Officer of Petroflow Energy Corporation, a Tulsa-based exploration and production company, as well as a member of its board of directors since June 2009. Mr. Menchaca also serves as a director on the board of Fortis Plastics and a non-profit organization based in Houston, Texas.

Douglas M. Wright. Mr. Wright has been Chief Financial Officer since August 2012. Mr. Wright served as Corporate Controller and Chief Accounting Officer of Nations Petroleum Company Ltd. from 2006 to August 2012. Prior to Nations, he served as a Manager of Financial Reporting for Noble Energy (contract). In 1996, he founded Fashion Investments Inc. and served as its Chief Executive Officer until 2005. Fashion Investments owned and operated the largest independent commercial laundry facility in Colorado Springs. From 1986 to 1996, Mr. Wright worked for Oryx Energy Company in various capacities including, Manager, Financial Reporting, Manager, Strategic Planning and General Auditor. From 1977 to 1986, he served as a Senior Manager with Deloitte & Touche. Mr. Wright is a Certified Public Accountant and earned his B.A. from the University of Pittsburgh and his MBA from the University of North Texas.

David L. Kunovic.  Mr. Kunovic joined Black Raven Energy, Inc. on October 1, 2010 as Vice President of Exploration managing all phases of geologic and geophysical exploration and development activity for the company. Mr. Kunovic has over 34 years of experience as an exploration geologist, including 11 years as President of Kachina Energy, Inc., managing geologic and geophysical projects for several independent oil companies. He has also held positions as Vice President of Exploration for Canyon Energy, Inc. from 1994 – 2000 managing all exploration activities for the Rocky Mountain region; Petroleum Incorporated from 1991 – 1994 as Exploration Manager for all US exploration; Newport Exploration from 1984 – 1991 as Exploration Manager Rocky Mountain region; Apache Corporation from 1980 – 1984 as Senior Geologist working the Powder River and Denver Basins and Union Texas Petroleum from 1978-1980 as geologist — Rocky Mountain Basins. Mr. Kunovic holds a Bachelor's degree in Geology from the University of Colorado and also completed Masters level course work in Environmental Engineering and Groundwater at the University of Colorado.

Involvement in Certain Legal Proceedings

On December 23, 2013, the United States Securities and Exchange Commission (SEC) entered an order in an administrative proceeding, In the Matter of West Coast Asset Management, Inc., and Lance W. Helfert, File No. 3-15660. In that matter, WCAM and Mr. Helfert, without admitting or denying the allegations, entered into a settlement with the SEC regarding certain negligence-based violations of Section 17(a)(2) of the Securities Act and Sections 206(2) and 206(4) of the Investment Advisers Act of 1940 (the Advisers Act). The matter was based upon an untrue statement made in an email that Mr. Helfert sent, in 2008, to an adviser to a prospective investor in an investment fund that was managed by WCAM. The SEC ordered WCAM and Mr. Helfert to cease and desist from committing or causing further such negligence-based violations, censured them, ordered WCAM to disgorge certain fees, and ordered WCAM and Mr. Helfert each to pay a monetary fine. WCAM and Mr. Helfert timely paid those amounts to the SEC.

Except as set forth above, none of our executive officers or directors has been the subject of any Order, Judgment, or Decree of any Court of competent jurisdiction, or any regulatory agency permanently or temporarily enjoining, barring suspending or otherwise limiting him from acting as an investment advisor, underwriter, broker or dealer in the securities industry, or as an affiliated person, director or employee of an investment company, bank, savings and loan association, or insurance company or from engaging in or continuing any conduct or practice in connection with any such activity or in connection with the purchase or sale of any securities.

CORPORATE GOVERNANCE OF THE COMPANY

Corporate Governance Guidelines

The EnerJex board of directors has adopted Corporate Governance Guidelines. A copy of these Corporate Governance Guidelines can be found on the Investors—Corporate Governance section of EnerJex's corporate website at www.enerjex.com. Information contained on EnerJex's website or that can be accessed through EnerJex's website does not constitute a part of this prospectus. EnerJex has included its website addresses only as inactive textual references and does not intend it to be an active link to its website.

Among the topics addressed in EnerJex's Corporate Governance Guidelines are:

Director Independence

Under the corporate governance requirements of companies whose shares are listed for trading on the NYSE MKT, at least a majority of the members of the board of directors of each listed company must be "independent." However, that requirement does not apply to listed companies that are "controlled companies," which refers to companies in which over 50% of the voting power is held by an individual, a group, or another company. More than 50% of our shares are held by a group of stockholders consisting of West Coast Opportunity Fund, LLC, Montecito Venture Fund, LLC, Lance W. Helfert, and Atticus Lowe, who collectively own approximately 51.0% of our issued and outstanding shares of common stock. As a result, we are not required to comply with the listing standard under which at least a majority of the members of the board of directors of each listed company must be "independent." The EnerJex board of directors has determined that two of the five current directors—James G. Miller and Richard Menchaca—are "independent directors" under the NYSE MKT listing requirements. The NYSE MKT listing requirements provide a non-exclusive list of persons who are not considered independent. For example, under these rules, a director who is, or during the past three years was, employed by the Company or by any parent or subsidiary of the company, other than prior employment as an interim chairman or chief executive officer, would not be considered independent. No director qualifies as independent unless the EnerJex board of directors affirmatively determines that the director does not have a material relationship with the company that would interfere with the exercise of independent judgment. In making an affirmative determination that a director is an "independent director," the EnerJex board of directors reviewed and discussed information provided by these individuals and by EnerJex with regard to each of their business and personal activities as they may relate to EnerJex and its management.

Board Leadership Structure

The EnerJex board of directors believes that EnerJex stockholders are best served if the EnerJex board of directors retains the flexibility to adapt its leadership structure to applicable facts and circumstances, which necessarily change over time. The EnerJex board of directors believes it is best not to have a fixed policy on this issue and that it should be free to make this determination based on what it believes is best under the circumstances. However, the EnerJex board of directors strongly endorses the concept of an independent director being in a position of leadership for the rest of the outside directors. Under EnerJex's Corporate Governance Guidelines, if at any time the chief executive officer and chairman of the board positions are held by the same person, the EnerJex board of directors, upon recommendation of the nominating and corporate governance committee, will elect an independent director as a lead independent director. We currently have no designated chairman or lead director.

Executive Sessions

At each regular meeting of the EnerJex board of directors, the independent directors meet in executive session with no company management present during a portion of the meeting. James G. Miller presides over these executive sessions and serves as a liaison between the independent directors and EnerJex's Chief Executive Officer.

Board Meetings and Attendance

The EnerJex board of directors held 9 meetings during 2013. All of EnerJex's directors attended 75 percent or more of the aggregate meetings of the EnerJex board of directors and all committees on which they served during 2013.

Board Committees

The board of directors has an audit committee, and the governance, compensation and nominating committee. Each of these committees operates under a charter that has been previously approved by the EnerJex board of directors and has the composition and responsibilities described below. The board of directors from time to time may establish other committees to facilitate the management of the company and may change the composition and the responsibilities of the existing committees.

The table below summarizes the current membership of each of EnerJex's two standing board committees.

Audit Committee

The primary responsibilities of the audit committee include:

The audit committee will have the authority to engage the services of outside experts and advisors as it deems necessary or appropriate to carry out its duties and responsibilities.

Our audit committee consists of Mr. Miller, and Mr. Menchaca. The board of directors has determined that each member of the audit committee qualifies as "independent" for purposes of membership on audit committees pursuant to the NYSE MKT listing requirements and the rules and regulations of the SEC and is able to read and understand Fundamental Financial Statements as required by the NYSE MKT listing requirements. In addition, the board of directors has determined that Mr. Miller qualifies as an "audit committee financial expert" as defined by the rules and regulations of the SEC.

Governance, Compensation and Nominating Committee

The primary responsibilities of the Governance, Compensation and Nominating Committee include:

The governance, compensation and nominating committee has the authority to engage the services of outside experts and advisors as it deems necessary or appropriate to carry out its duties and responsibilities.

The governance, compensation and nominating committee consists of Mr. Menchaca, Mr. Miller and Mr. Helfert.

Role of the Board in Managing Risk

The board of directors does not have a separate risk oversight body. Instead, the EnerJex board has overall responsibility for risk oversight, including, as part of regular board and committee meetings, general oversight of executives’ management of risks relevant to us. In overseeing risks, the board seeks to understand the material risks, including financial, competitive, and operational risks, we face and the steps management is taking to manage those risks. It also has the responsibility for understanding what level of risk is appropriate. The board of directors reviews our business strategy and determines what constitutes an appropriate level of risk for EnerJex.

While the full EnerJex board has overall responsibility for risk oversight, the board has delegated oversight responsibility related to certain risks to its two committees. The audit committee, under its charter, has been delegated the responsibility of reviewing and discussing with management our major financial risk exposures and the steps that management has taken to monitor and control such exposures (including management’s risk assessment and risk management policies). EnerJex's governance, compensation and nominating committee is responsible for considering risks within its areas of responsibility. The board does not believe that our compensation policies encourage excessive risk-taking, as the compensation plans are designed to align our employees with short- and long-term corporate strategy. Generally, our equity awards vest over several years, which the board has determined encourages our employees to act with regard to the long term interest of EnerJex and to focus on sustained stock price appreciation.

The board’s role in risk oversight has not had any effect on the board’s leadership structure.

Code of Conduct and Ethics

EnerJex's code of conduct and ethics applies to all of EnerJex's employees, officers and directors, including EnerJex's principal executive officer and principal financial officer, and meets the requirements of the SEC. A copy of EnerJex's code of conduct and ethics is filed as an exhibit to EnerJex's annual report on Form 10-KSB for the fiscal year ended March 31, 2007.

Policy Regarding Director Attendance at Annual Meetings of Stockholders

It is the policy of the EnerJex board of directors that directors standing for re-election should attend EnerJex's annual meeting of stockholders, if their schedules permit. All of EnerJex's directors attended EnerJex's 2013 annual meeting of stockholders in June 2013 and our special meeting of the stockholder in September 2013.

Complaint Procedures

EnerJex's audit committee has established procedures for the receipt, retention and treatment of complaints received by EnerJex regarding accounting, internal accounting controls, or auditing matters, and the submission by EnerJex's employees, on a confidential and anonymous basis, of concerns regarding questionable accounting or auditing matters. EnerJex's personnel with such concerns are encouraged to discuss their concerns with their supervisor first, who in turn will be responsible for informing EnerJex's chief executive officer of any concerns raised. If an employee prefers not to discuss a particular matter with his or her own supervisor, the employee may instead discuss such matter with EnerJex's chief executive officer. If an individual prefers not to discuss a matter with the chief executive officer or if the chief executive officer is unavailable and the matter is urgent, the individual is encouraged to contact the chairman of EnerJex's audit committee, James G. Miller.

Process Regarding Stockholder Communications with Board of Directors

EnerJex stockholders may communicate with the EnerJex board of directors or any one particular director by sending correspondence, addressed to EnerJex's Corporate Secretary, EnerJex Resources, Inc., 4040 Broadway, Suite 508, San Antonio, Texas 78209, with an instruction to forward the communication to the EnerJex board of directors or one or more particular directors. EnerJex's Corporate Secretary will forward promptly all such stockholder communications to the EnerJex board of directors or the one or more particular directors, with the exception of any advertisements, solicitations for periodical or other subscriptions and other similar communications.

Executive Compensation

Summary Compensation Table

The following table sets forth summary compensation information for the fiscal year ended December 31, 2013, and the year ended December 31, 2012, for our chief executive officer, chief financial officer and other highly compensated executive officers. We did not have any other executive officers as of the end of 2012 or 2013, whose total compensation exceeded $100,000. We refer to these persons as our named executive officers elsewhere in this report.

Equity Compensation Plans

We currently have three equity compensation plans, each of which has been approved by our stockholders. Any outstanding stock options issued under our prior equity compensation plans remain effective in accordance with their terms. Officers (including officers who are members of the board of directors), directors, employees and consultants are eligible to receive options under our stock option plans. 

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

On December 31, 2010, we granted to Robert G. Watson, Jr., 60,000 options that vest ratably over a 48 month period and are exercisable at $6.00 per share.  The term of the options is 5 years. The fair value of the options on the date of grant as calculated using the Black-Scholes model was $307,751, using the following weighted average assumptions:  exercise price of $6.00 per share; common stock price of $6.00 per share; volatility of 128%; term of five years; dividend yield of 0%; interest rate of 1.95%.  The amount recognized as expense in the year ended December 31, 2011 was $76,938, and the amount of expense to be recognized in future periods is $153,876.

On December 1, 2012, we granted 52,333 options that vest ratably every six months over a three year period to four employees of the Company. The fair value of the options on the date of the grant calculated using the Black-Scholes model was $167,032 using the following weighted average assumptions: exercise price of $10.50 per share; common stock price of $8.40 per share; volatility of 67%; term of three years; dividend yield of 0%; interest rate of .47%. The amount recognized as expense in the years ended December 31, 2012, was $18,825 and the amount of expense to be recognized in future periods is $148,208. There were no options vested at December 31, 2012.

2000/2001 Stock Option Plan

The Board of Directors approved our 2000/2001 Stock Option Plan on September 25, 2000, and our stockholders ratified the plan.

Summary of the 2000/2001 Stock Option Plan

Administration of Plan; Board Authority to Select Grantees and Determine Awards. The Plan shall be administered by our board of directors. The Board shall have the power and authority to grant awards consistent with the terms of the Plan. The board may delegate this authority to a compensation committee of the board.

Stock Issuable Under the Plan; Mergers; Substitutions. The total number of options that can be granted under the plan is 13,333 shares and all such shares were previously granted to the former chief executive officer, C. Stephen Cochennet. On August 3, 2009, we exchanged these outstanding options for 13,333 shares of restricted common stock. Therefore, all 13,333 shares reserved for issuance under this plan are available again for issuance.

Eligibility. Grantees under the Plan will be such officers, directors, full or part-time employees, and other key persons (including consultants and prospective employees) of us and our subsidiaries, if any, as are selected from time to time by the board in its sole discretion.

Stock Options. Any stock option granted under the Plan shall be in such form as the board may from time to time approve. Stock options granted under the Plan may be non-qualified stock options or incentive stock options. Incentive stock options may be granted only to employees of us or any subsidiary that is a "subsidiary corporation" within the meaning of Section 424(f) of the Code.

Exercise Price. Non-qualified stock options will be granted by the board of directors with an option price not less than 85% of the fair market value of the shares of common stock to which the non-qualified stock option relates on the date of grant. In no event may the option price with respect to an incentive stock option granted under the stock option plan be less than the fair market value of such common stock. However the price shall not be less than 110% of the fair market value per share on the date of the grant in the case of an individual then owning more than 10% of the total combined voting power of all classes of stock of the corporation.

Option Term. Each option granted under the stock option plan will be assigned a time period for exercising not to exceed ten years after the date of the grant. Certain other restrictions will apply in connection with this plan when some awards may be exercised. Generally, all options under this plan terminate 90 days after a change of control if the option holder is terminated other than for cause.

Amendments and Termination. The board may, at any time, amend or discontinue the Plan. We must obtain stockholder approval of any Plan amendment to the extent necessary and desirable to comply with Section 422 of the Internal Revenue Code or other applicable law, including the requirements of any exchange or quotation system on which our common stock is listed or quoted. Such plan amendments are subject to approval by our stockholders entitled to vote at a meeting of stockholders. We may not amend, alter, suspend, or terminate the Plan if doing so would impair the rights of any holder, unless both the holder and the Plan's administrator agree in writing and sign the writing. The 2000-2001 Plan terminated on September 25, 2010, and no further options will be granted under this plan after that date.

The 2002-2003 Stock Option Plan/Stock Incentive Plan

The Board of Directors approved the EnerJex Resources, Inc. Stock Option Plan on August 1, 2002 (the "2002-2003 Stock Option Plan"). We had previously granted 15,900 options under this plan. On August 3, 2009, we exchanged all 15,900 outstanding options for 3,980 shares of our restricted common stock. In addition, we granted 10,116 shares of restricted common stock under the Stock Incentive Plan to employees for fiscal 2009 bonuses and 3,953 shares to our officers and directors for the prior rescission of stock options in fiscal 2008.

Summary of the 2002/2003 Stock Option Plan

Administration of Plan; Board Authority to Select Grantees and Determine Awards. The Plan shall be administered by our board of directors. The Board shall have the power and authority to grant awards consistent with the terms of the Plan.

Stock Issuable Under the Plan. Originally, the total number of options that could be granted under the 2002-2003 Stock Option Plan was not to exceed 26,666 shares. In September 2007, our stockholders approved a proposal to amend and restate the 2002-2003 Stock Option Plan to increase the number of shares issuable to 66,666. On October 14, 2008, our stockholders approved a proposal to amend and restate the 2002-2003 Stock Option Plan to (i) rename it the EnerJex Resources, Inc. Stock Incentive Plan (the "Stock Incentive Plan"), (ii) increase the maximum number of shares of our common stock that may be issued under the Stock Incentive Plan from 66,666 to 83,333, and (iii) add restricted stock as an eligible award that can be granted under the Stock Incentive Plan.

Eligibility. Grantees under the Plan will be such officers, directors, full or part-time employees, and other key persons (including consultants and prospective employees) of us and our subsidiaries, if any, as are selected from time to time by the board in its sole discretion.

Stock Options. Any stock option granted under the Plan shall be in such form as the board may from time to time approve. Stock options granted under the Plan may be non-qualified stock options or incentive stock options. Incentive stock options may be granted only to employees of us or any subsidiary that is a "subsidiary corporation" within the meaning of Section 424(f) of the Code.

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

Option Term. Each option granted under the stock option plan will be assigned a time period for exercising not to exceed ten years after the date of the grant. Certain other restrictions will apply in connection with this plan when some awards may be exercised. Generally, all options under this plan terminate 90 days after a change of control if the option holder is terminated other than for cause.

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

Amendments and Termination. The board may, at any time, amend or discontinue the Plan. We must obtain stockholder approval of any Plan amendment to the extent necessary and desirable to comply with Section 422 of the Internal Revenue Code or other applicable law, including the requirements of any exchange or quotation system on which our common stock is listed or quoted. Such plan amendments are subject to approval by our stockholders entitled to vote at a meeting of stockholders. We may not amend, alter, suspend, or terminate the Plan if doing so would impair the rights of any holder, unless both the holder and the Plan's administrator agree in writing and sign the writing. As amended, the 2002-2003 plan terminated on August 1, 2012, and no options will be granted under this plan after that date.

The 2013 Stock Incentive Plan

Our board of directors and stockholders have approved and adopted the EnerJex Resources, Inc., 2013 Stock Incentive Plan, which we refer to herein as the "Plan."

Summary of the Plan

The following is a summary of certain principal features of the Plan.

Administration of Plan; Board Authority to Select Grantees and Determine Awards. The Plan shall be administered by our board of directors. The Board shall have the power and authority to grant awards consistent with the terms of the Plan. The board may delegate this authority to a compensation committee of the board.

Stock Issuable Under the Plan; Mergers; Substitutions. The number of shares of stock initially reserved and available for issuance under the Plan shall be 333,300 shares, subject to adjustment as provided in Section 3.1(b) of the Plan. Pursuant to Section 3.1(b), we will increase the number of shares reserved and set aside annually on each January 1st by the lowest of the following: (i) five percent (5.0%) of the number of shares of stock issued and outstanding on the immediately preceding December 31st, (ii)  33,333 shares, or (iii) such lesser number of shares as is determined by the board. For purposes of this limitation, the shares of stock underlying any awards that are forfeited, canceled, held back upon exercise of an option or settlement of an award to cover the exercise price or tax withholding, reacquired by us prior to vesting, satisfied without the issuance of stock or otherwise terminated (other than by exercise) shall be added back to the shares of stock available for issuance under the Plan. Subject to such overall limitations, shares of stock may be issued up to such maximum number pursuant to any type or types of award. The shares available for issuance under the Plan may be authorized but unissued shares of stock or shares of stock reacquired by us.

Eligibility. Grantees under the Plan will be such officers, directors, full or part-time employees, and other key persons (including consultants and prospective employees) of us and our subsidiaries, if any, as are selected from time to time by the board in its sole discretion.

Stock Options. Any stock option granted under the Plan shall be in such form as the board may from time to time approve. Stock options granted under the Plan may be non-qualified stock options or incentive stock options. Incentive stock options may be granted only to employees of us or any subsidiary that is a "subsidiary corporation" within the meaning of Section 424(f) of the Code.

Exercise Price. The exercise price per share for the stock covered by a stock option shall be determined by the board at the time of grant but shall not be less than 100% of the fair market value on the date of grant. In the case of an incentive stock option that is granted to a 10% owner, the option price of such Incentive stock option shall be not less than 110% of the fair market value on the grant date.

Option Term. The term of each stock option shall be fixed by the board, but no stock option shall be exercisable more than 10 years after the date the stock option is granted. In the case of an incentive stock option that is granted to a 10% owner, the term of such stock option shall be no more than 5 years from the date of grant.

Unrestricted and Restricted Stock Awards. The board may, in its sole discretion, grant (or sell at par value or such higher purchase price determined by the board) an unrestricted stock Award or restricted stock award under the Plan. Unrestricted stock awards and restricted stock awards may be granted in respect of past services or other valid consideration, or in lieu of cash compensation due to such grantee.

Amendments and Termination. The board may, at any time, amend or discontinue the Plan. We must obtain stockholder approval of any Plan amendment to the extent necessary and desirable to comply with Section 422 of the Internal Revenue Code or other applicable law, including the requirements of any exchange or quotation system on which our common stock is listed or quoted. Such plan amendments are subject to approval by our stockholders entitled to vote at a meeting of stockholders. We may not amend, alter, suspend, or terminate the Plan if doing so would impair the rights of any holder, unless both the holder and the Plan's administrator agree in writing and sign the writing. The 2013 plan terminates on June 6, 2023, and no options will be granted under this plan after that date.

Employment Agreements

Robert G. Watson, Jr. - Chief Executive Officer

On December 31, 2010, EnerJex and Robert G. Watson, Jr., entered into an Employment Agreement pursuant to which (i) we agreed to employ Mr. Watson as our chief executive officer for a term ending on December 31, 2012, (ii) we will pay to Mr. Watson base compensation of $150,000 plus such discretionary cash bonus as our Board of Directors determines to be appropriate, (iii) we granted to Mr. Watson an option for the purchase of 60,000 shares of common stock at $6.00 per share, (A) in which option he will vest in equal monthly increments over a period of 48 months, and in full upon a change of control of the company or the sale of all or substantially all of its assets, and (B) which option will have a term of five (5) years, and (iv) if we terminate Mr. Watson's employment without "Cause" (as defined in the Employment Agreement), then we will pay to Mr. Watson as severance pay (A) the Base Compensation that would have accrued during the remainder of the term of that Employment Agreement, and (B) if that termination occurs after 16 months of employment, we also will pay to Mr. Watson additional severance pay in the amount of $100,000.

On December 31, 2012, we entered into an amended and restated employment agreement with Robert G. Watson, Jr. as Chief Executive Officer of EnerJex for a two-year period commencing December 31, 2012. The employment agreement provides for an annual base salary of $225,000 per year.

Douglas M. Wright - Chief Financial Officer

On August 15, 2012, EnerJex and Douglas M. Wright, entered into an Employment Agreement pursuant to which we will employ Mr. Wright as our chief financial officer, (ii) we will pay to Mr. Wright base compensation of $140,000 plus such discretionary cash bonus as our chief executive officer determines to be appropriate, and (iii) if we terminate Mr. Wright's employment without "Cause" (as defined in the Employment Agreement), then we will pay to Mr. Wright $32,500 as severance pay after six (6) months of employment.

Termination Under the Equity Plans

Under our 2000/2001 Stock Option Plan, if the person receiving the option (the optionee) ceases to be employed by us for any reason other than for disability or cause, the optionee's options will expire not later than 3 months afterwards. During this 3 month period and prior to the time the option expires under the terms of the option, the optionee may exercise any option that we have granted to him, but only to the extent that the options were exercisable on the date of termination of his employment. Unless exercised during this period, these options will expire at the end of the 3 month period unless the options are to terminate sooner under the terms and conditions of the option. The decision as to whether a termination for a reason other than disability, cause or death has occurred is made by the board of directors, whose decision shall be final and conclusive. If an optionee ceases to be employed by us for reason of disability, the optionee's options will expire not later than 1 year after the date that he or she is terminated. During this 1 year period and prior to the expiration of the option under its terms, the optionee may exercise any option granted to him, but only to the extent that the options were exercisable on the date of termination of his employment because of his or her disability. Except as so exercised, optionee's options will expire at the end of the 1 year period unless the options are to terminate sooner under the terms and conditions of the option. The decision as to whether a termination by reason of disability has occurred is determined by the board.

Under our Amended and Restated 2002-2003 Stock Option Plan, if an optionee ceases to be employed by, or ceases to have a relationship with us for any reason other than for disability or cause, the optionee's options will expire not later than three 3 months thereafter. During the three month period and prior to the expiration of the option by its terms, the optionee may exercise any option granted to him, but only to the extent such options were exercisable on the date of termination of his employment or relationship and except as so exercised, such options shall expire at the end of such three month period unless such options by their terms expire before such date. The decision as to whether a termination for a reason other than disability, cause or death has occurred are made by the governance, compensation and nominating committee, whose decision shall be final and conclusive, except that employment shall not be considered terminated in the case of sick leave or other bona fide leave of absence approved by us.

Under our 2013 Plan, if the optionee ceases to be employed by us for any reason other than for death, disability or cause, the optionee's options will expire not later than 3 months afterwards. During this 3 month period and prior to the time the option expires under the terms of the option, the optionee may exercise any option that we have granted to him, but only to the extent that the options were exercisable on the date of termination of his employment. Unless exercised during this period, these options will expire at the end of the 3 month period unless the options are to terminate sooner under the terms and conditions of the option. The decision as to whether a termination for a reason other than disability, cause or death has occurred is made by the board of directors, whose decision shall be final and conclusive. If an optionee ceases to be employed by us for reason of death or disability, the optionee's options will expire not later than 180 days after the date that he or she is terminated. During this 180 day period and prior to the expiration of the option under its terms, the optionee may exercise any option granted to him, but only to the extent that the options were exercisable on the date of termination of his employment because of his or her disability. Except as so exercised, optionee's options will expire at the end of the 180 day period unless the options are to terminate sooner under the terms and conditions of the option. The decision as to whether a termination by reason of disability has occurred is determined by the board.

Termination Under the Employment Agreements

Termination Without Cause or Disability, Including a Change in Control

Under Mr. Watson's employment agreement, if Mr. Watson is terminated not for cause or disability, we will pay Mr. Watson all accrued and unpaid wages, including for accrued and unused vacation time and any annual bonus accrued through the date of termination. In addition, he will receive the salary that he would have earned through December 31, 2014. If Mr. Watson is terminated after June 31, 2014, he will also receive an additional sum of $150,000.

Under Mr. Wright's employment agreement, if Mr. Wright is terminated not for cause or disability, we will pay Mr. Wright all accrued and unpaid wages, including for accrued and unused vacation time and any annual bonus accrued through the date of termination. If Mr. Wright is terminated after February 15, 2014, he will also receive an additional sum of $35,000.

Termination Because of Disability

Under Mr. Watson's and Mr. Wright's employment agreements, if the employee is terminated because of disability, he is entitled to receive all accrued and unpaid wages, including for accrued and unused vacation time and any annual bonus accrued through the date of termination.

Option Exercises for Fiscal 2013

There were no options exercised by our Named Executive Officers in fiscal year 2013.

Grants of Plan-Based Awards in Fiscal Year 2013

We have granted to Mr. Wright an option expiring on July 31, 2017, to purchase 50,000 shares of our common stock at a cash exercise price equal to $10.50. The options will vest in six equal tranches of 8,333 options every six months over a three year period, and Mr. Wright must exercise the options within three months of employment termination or forfeit them.

Outstanding Equity Awards at 2013 Fiscal Year-End

The following table lists the outstanding equity incentive awards held by our named executive officers as of the fiscal year ended December 31, 2013.