AgEagle Aerial Systems Inc. - Quarter Report: 2011 March (Form 10-Q)

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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

For the quarterly period ended March 31, 2011

Commission file number 000-30234

ENERJEX RESOURCES, INC.

(Exact name of registrant as specified in its charter)

(210) 451-5545

(Registrant’s telephone number, including area code)

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

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

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

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

The number of shares of Common Stock, $0.001 par value, outstanding on April 18, 2011 was 69,355,279 shares.

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ENERJEX RESOURCES, INC.

FORM 10-Q

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PART 1 – FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

EnerJex Resources, Inc. and Subsidiaries

Condensed Consolidated Balance Sheets

See Notes to Condensed Consolidated Financial Statements.

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EnerJex Resources, Inc. and Subsidiaries

Condensed Consolidated Statements of Operations

(Unaudited)

See Notes to Condensed Consolidated Financial Statements.

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EnerJex Resources, Inc. and Subsidiaries

Condensed Consolidated Statements of Cash Flows

(Unaudited)

See Notes to Condensed Consolidated Financial Statements.

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EnerJex Resources, Inc. and Subsidiaries

Notes to Condensed Consolidated Financial Statements

Note 1 – Basis of Presentation

The unaudited condensed consolidated financial statements have been prepared in accordance with United States generally accepted accounting principles for interim financial information and with the instructions to Form 10-Q and reflect all adjustments which, in the opinion of management, are necessary for a fair presentation. All such adjustments are of a normal recurring nature. The results of operations for the interim period are not necessarily indicative of the results to be expected for a full year. Certain amounts in the prior year statements have been reclassified to conform to the current year presentations. The statements should be read in conjunction with the financial statements and footnotes thereto included in our Transition Report Form 10-K for the nine-month period ended December 31, 2010.

Our consolidated financial statements include the accounts of our wholly-owned subsidiaries, EnerJex Kansas, Inc., DD Energy, Inc., Black Sable Energy, LLC and Working Interest, LLC. All intercompany transactions and accounts have been eliminated in consolidation.

Note 2 - Stock Options

A summary of stock options and warrants are as follows:

Note 3 – Fair Value Measurements

We hold certain financial assets which are required to be measured at fair value on a recurring basis in accordance with the Statement of Financial Accounting Standard No. 157, “Fair Value Measurements” (“ASC Topic 820-10”). ASC Topic 820-10 establishes a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurements) and the lowest priority to unobservable inputs (Level 3 measurements). ASC Topic 820-10 defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants on the measurement date. A fair value measurement assumes that the transaction to sell the asset or transfer the liability occurs in the principal market for the asset or liability. The three levels of the fair value hierarchy under ASC Topic 820-10 are described below:

Level 1. Valuations based on quoted prices in active markets for identical assets or liabilities that an entity has the ability to access. We believe our debt approximates fair value at March 31, 2011.

Level 2. Valuations based on quoted prices for similar assets or liabilities, quoted prices for identical assets or liabilities in markets that are not active, or other inputs that are observable or can be corroborated by observable data for substantially the full term of the assets or liabilities. We consider the derivative liability to be Level 2. We determine the fair value of the derivative liability utilizing various inputs, including NYMEX price quotations and contract terms.

Level 3. Valuations based on inputs that are supported by little or no market activity and that are significant to the fair value of the assets or liabilities.

Our derivative instruments consist of variable to fixed price commodity swaps.

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Note 4 - Asset Retirement Obligation

Our asset retirement obligations relate to the liabilities associated with the abandonment of oil wells. The amounts recognized are based on numerous estimates and assumptions, including future retirement costs, inflation rates and credit adjusted risk-free interest rates. The following shows the changes in asset retirement obligations:

Note 5 - Derivative Instruments

We have entered into certain derivative or physical arrangements with respect to portions of our crude oil production to reduce our sensitivity to volatile commodity prices and/or to meet hedging requirements under our Credit Facility. We believe that these derivative arrangements, although not free of risk, allow us to achieve a more predictable cash flow and to reduce exposure to commodity price fluctuations. However, derivative arrangements limit the benefit of increases in the prices of crude oil. Moreover, our derivative arrangements apply only to a portion of our production.

We have an Intercreditor Agreement in place between us; our counterparty, BP Corporation North America, Inc. (“BP”); and our agent, Texas Capital Bank, N.A., which allows Texas Capital Bank to also act as agent for BP for the purpose of holding and enforcing any liens or security interests resulting from our derivative arrangements. Therefore, we are not required to post additional collateral, including cash.

The following derivative contracts were in place at March 31, 2011:

Monthly volume is the weighted average throughout the period. The total fair value is shown as a derivative instrument in both the current and non-current liabilities on the balance sheet. We recorded a loss on the derivative contracts of $2,468,225 in the three month period ended March 31, 2011 and a loss in the three month period ended March 31, 2010 of $1,425,327.

Note 6 - Long-Term Debt

Senior Secured Credit Facility

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

The Credit Facility is secured by a lien on substantially all of our assets in Kansas. The Credit Facility has a term of three years, and all principal amounts, together with all accrued and unpaid interest, will be due and payable in full on July 3, 2011. The Credit Facility also provides for the issuance of letters-of-credit up to a $750,000 sub-limit under the borrowing base and up to an additional $2.25 million limit not subject to the borrowing base to support our hedging program. We repaid $500,000 of debt outstanding on the Credit Facility with proceeds from the December 31, 2010 transaction.

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Advances under the Credit Facility will be in the form of either base rate loans or Eurodollar loans. The interest rate on the base rate loans fluctuates based upon the higher of (1) the lender’s “prime rate” and (2) the Federal Funds rate plus 0.50%, plus, in either case, a margin of between 0.0% and 0.5% depending on the percent of the borrowing base utilized at the time of the credit extension, but in no event shall be less than five percent (5.0%). The interest rate on the Eurodollar loans fluctuates based upon the applicable LIBOR rate, plus a margin of 2.25% to 2.75% depending on the percent of the borrowing base utilized at the time of the credit extension, but in no event shall be less than five percent (5.0%). Eurodollar loans may be based upon one, two, three and six month LIBOR options, except that beginning March 30, 2009 and continuing through the date of this report, Texas Capital Bank has suspended all LIBOR based funding with maturities less than 90 days due to the extreme volatility in the interest rate market and the unprecedented spread between the 90 day LIBOR and the shorter term LIBOR options. A commitment fee of 0.375% on the unused portion of the borrowing base will accrue, and be payable quarterly in arrears. There was no commitment fee due at March 31, 2011.

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

The Credit Facility was amended August 18, 2009 to implement a minimum interest rate of five percent (5.0%) and establish minimum volumes to be hedged of not less than seventy-five percent (75%) of the proved developed producing reserves attributable to our interest in the borrowing base oil and gas properties projected to be produced. The Credit Facility was further amended January 13, 2010 to modify the senior funded debt to EBITDA ratio on a quarterly basis beginning with the quarter ended December 31, 2009 and to modify the annualization of the interest coverage ratio, also beginning with the quarter ended December 31, 2009. The senior funded debt to EBITDA ratio allowed is 6.25:1.00 at December 31, 2009; 5.75:1.00 at March 31, 2010; 5.25:1.00 at June 30, 2010; and 4.75:1.00 at September 30, 2010; and 4.25:1.00 for all quarters ending after September 30, 2010.

On September 29, 2010, the Credit Facility with Texas Capital Bank was amended to modify the borrowing base to $6,691,000 relative to the Proved Reserves attributable to the borrowing Base Oil and Gas Properties. The amendment also modified various terms in the Credit Facility along with changing the commitment fees to 0.37% per annum times the average daily balance of the loan.

On December 31, 2010, the Credit Facility with Texas Capital Bank was amended to modify the borrowing base to $6,116,000 relative to the Proved Reserves attributable to the borrowing Base Oil and Gas Properties. The amendment also modified the EBITDA ratio on a quarterly basis with the quarter ending March 31, 2011, permit the ratio allowed to 4.25:1 00. The Credit Agreement was further amended in order to reflect the reorganization of the Company.

EnerJex is currently in discussions with Texas Capital Bank to secure a new long-term credit facility and we believe this will be accomplished by June 30, 2011.

Other Long-Term Debt

We financed the purchase of vehicles through a bank. The notes are for four years and the weighted average interest is 7.2% per annum. Vehicles collateralize these notes.

Long-term debt consists of the following at March 31, 2011:

Note 7 - Common Stock

On March 31, 2011, we completed two concurrent transactions in which the Company issued 5.68 million shares of common stock at $0.60 per share and repurchased 3.75 million shares of common stock at $0.40 per share pursuant to a Stock Redemption Agreement with Working Interest Holdings, LLC (“WIH”). These transactions resulted in 1.93 million net shares being issued for net proceeds to EnerJex of $1.9 million, resulting in an effective net issuance price of $0.99 per share. Included in equity is a subscription receivable for the purchase of shares that was remitted in April 2011.

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Note 8 - Available-for-sale securities

We classify our marketable equity securities as available-for-sale and they are carried at fair market value, with the unrealized gains and losses included in the determination of comprehensive income and reported in stockholders’ equity. At March 31, 2011 there was an unrealized loss on our marketable equity securities of $95,774.

FORWARD-LOOKING STATEMENTS

This report contains forward-looking statements. These forward-looking statements are subject to a number of risks and uncertainties, many of which are beyond our control. All statements, other than statements of historical fact, contained in this report, including statements regarding future events, our future financial performance, business strategy and plans and objectives of management for future operations, are forward-looking statements. We have attempted to identify forward-looking statements by terminology including “anticipates,” “believes,” “can,” “continue,” “could,” “estimates,” “expects,” “intends,” “may,” “plans,” “potential,” “predicts,” or “should” or the negative of these terms or other comparable terminology. Although we do not make forward-looking statements unless we believe we have a reasonable basis for doing so, we cannot guarantee their accuracy. These statements are only predictions and involve known and unknown risks, uncertainties and other factors, including the risks outlined under “Risk Factors” or elsewhere in this report, which may cause our or our industry’s actual results, levels of activity, performance or achievements to be materially different from any future results, levels of activity, performance or achievements expressed or implied by these forward-looking statements. Moreover, we operate in a very competitive and rapidly changing environment. New risks emerge from time to time and it is not possible for us to predict all risk factors, nor can we address the impact of all factors on our business or the extent to which any factor, or combination of factors, may cause our actual results to differ materially from those contained in any forward-looking statements. The factors impacting these risks and uncertainties include, but are not limited to:

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You should not place undue reliance on any forward-looking statement, each of which applies only as of the date of this report. Except as required by law, we undertake no obligation to update or revise publicly any of the forward-looking statements after the date of this report to conform our statements to actual results or changed expectations. For a detailed description of these and other factors that could cause actual results to differ materially from those expressed in any forward-looking statement, please see “Risk Factors” in this document and in our Transition Report on Form 10-K for the nine-month period ended December 31, 2010.

All references in this report to “we,” “us,” “our,” “company” and “EnerJex” refer to EnerJex Resources, Inc. and our wholly-owned operating subsidiaries, EnerJex Kansas, Inc., DD Energy, Inc., Black Sable Energy, LLC and Working Interest, LLC, unless the context requires otherwise. We report our financial information on the basis of a December 31^st fiscal year end.

AVAILABLE INFORMATION

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

INDUSTRY AND MARKET DATA

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

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.

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

Overview

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

From the beginning of fiscal 2008 through the end of fiscal 2010, we deployed approximately $12 million in capital resources to acquire and develop five operating projects and drill 179 new wells (111 producing wells and 65 water injection wells and 3 dry holes). As a result, our estimated total net proved oil reserves at December 31, 2010 was approximately 2.32 million barrels of oil, or BO. Of the 2.32 million BO of total proved reserves, approximately 29% are proved developed and approximately 71% are proved undeveloped. The proved developed reserves are 100% proved developed producing reserves.

The total PV10 (present value) of our proved reserves (“PV10”) as of December 31, 2010 was approximately $31.2 million. PV10 means the estimated future gross revenue to be generated from the production of proved reserves, net of estimated production and future development and abandonment costs, using prices and costs in effect at the determination date, before income taxes, and without giving effect to non-property related expenses, discounted to a present value using an annual discount rate of 10% in accordance with the guidelines of the SEC. PV10 is a non-GAAP financial measure and generally differs from the standardized measure of discounted future net cash flows, the most directly comparable GAAP financial measure, because it does not include the effects of income taxes on future net revenues.

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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.

The Opportunity in Kansas

According to the Kansas Geological Survey, the State of Kansas has historically been one of the top 10 domestic oil producing regions in the United States. For the years ended December 31, 2010 and 2009, 40.5 million barrels and 39.5 million barrels of oil were produced in Kansas. Of the total barrels produced in Kansas in the calendar year ended December 31, 2010, 20 companies accounted for approximately 34% of the total production, with the remaining 66% produced by over 2,000 active producers.

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

The Opportunity in South Texas

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

It is our vision to grow the business in a disciplined and well-planned manner. However, there can be no assurance that we will be successful in any of these respects, that the prices of oil prevailing at the time of production will be at a level allowing for profitable production, or that we will be able to obtain additional funding at terms favorable to us to increase our currently limited capital resources.

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Highlights for our First Quarter 2011

Operations

Eastern Kansas:

We drilled 26 development wells with a 100% success rate and 3 wildcat exploration wells with a 33% success rate. In addition, the Company re-established production from more than 50 idle wells that required maintenance work. A number of the development wells were drilled deeper than those of EnerJex’s adjacent producers, and encountered additional oil pay zones which will be tested for commercial production. EnerJex’s successful exploration well encountered two oil pay zones, one of which presently appears to have exceptional potential. The higher-potential zone will be tested and the Company may drill additional wells to evaluate the size and scope of this potential discovery.

South Texas:

We worked over a well in our El Toro Project which increased gross production by approximately 18 barrels of oil per day.

Recent Developments

The following is a brief description of our most significant corporate developments that occurred in the first quarter of 2011:

On January 14, 2011, the Registrant entered into a letter agreement with J&J Operating, LLC (“J&J”) and its two principals (collectively, the “Sellers”), whereby we purchased the field operating equipment assets from Sellers for the purchase price of $215,000. Sellers are affiliates of Working Interest Holding, LLC, which holds 15,000,000 shares of our issued and outstanding common stock, or approximately 22%. In addition to such purchase of those operating assets:

On January 28, 2011, we sold marketable securities for $1,400,000 in cash.

On March 31, 2011, we completed two concurrent transactions in which the Company issued 5.68 million shares of common stock at $0.60 per share and repurchased 3.75 million shares of common stock at $0.40 per share pursuant to a Stock Redemption Agreement with Working Interest Holdings, LLC (“WIH”). These transactions resulted in 1.93 million net shares being issued for net proceeds to EnerJex of $1.9 million, resulting in an effective net issuance price of $0.99 per share.

On April 20, we acquired approximately 280 acres of additional leasehold in Kansas for $245,000. The acreage has 9 existing wellbores that were recently drilled, cased, and evaluated, but have not begun producing oil. The acreage includes significant development potential beyond the existing wells.

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

The table below sets forth our net oil production (net of all royalties, overriding royalties and production due to others) for the period ending March 31, 2011 and period ended March 31, 2010, the average sales prices, average production costs and direct lifting costs per unit of production.

Results of Operations for the Three Months Ended March 31, 2011 and 2010 compared.

Income:

Revenues

Oil revenues for the three months ended March 31, 2011 were $1,369,167 compared to revenues of $1,152,302 in the three months ended March 31, 2010. The increase is due to additional producing properties from the recent transaction and higher oil prices.

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Expenses:

Direct Operating Costs

Direct operating costs include pumping, gauging, pulling, repairs, certain contract labor costs, and other non-capitalized expenses. Direct operating costs for the three months ended March 31, 2011 were $847,564 compared to $519,590 for the three months ended March 31, 2010. Direct costs increased primarily as a result of deferred maintenance expenditures on vintage leases and expenses associated with the additional producing properties acquired on December 31, 2010.

Depreciation, Depletion and Amortization

Depreciation, depletion and amortization for the three months ended March 31, 2011 was $271,965 and $58,209, respectively.

Professional Fees

Professional fees for the three months ended March 31, 2011 were $203,079 compared to $81,915 for the three months ended March 31, 2010. The increase in professional fees was a result of legal fees incurred for the closing of new acquisitions and equity offerings.

Salaries

Salaries for the three months ended March 31, 2011 were $118,648 compared to $129,565 for the three months ended March 31, 2010. Decreased salary expenses are the result of a reduction in headcount at the Kansas office.

Administrative Expense

Administrative expense for the three months ended March 31, 2011 were $204,354 compared to $226,657 in the three months ended March 31, 2010. The decrease in administrative expenses is a result of new management and streamlined operations.

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Interest Expense

Interest expense for the three months ended March 31, 2011 was $114,324 whereas interest expense for the three months ended March 31, 2010 was $208,530. Interest expense is lower due to reduced borrowing under the credit facility and the conversion of the subordinated debentures into common equity.

Loan Interest Accretion

There were no loan interest accretion expenses for the three months ended March 31, 2011, as compared to $163,244 for the three months ended March 31, 2010.

Gain on Derivatives

There was a loss on the derivative contracts in 2011 due to an increase in oil prices in addition to a new hedge contract entered into for the period of July 2011 through December 2015 with increased volume. The hedge price in the new hedge contract is $83.70, and the new contract replaced a prior hedge contract with a hedge price of $57.50.

Net Income (Loss)

Net loss for the three months ended March 31, 2011 was $2,846,795 as compared to net loss of $1,607,952 in the three months ended March 31, 2010. Non-cash expenses such as derivative contracts, depreciation and depletion as well as loan costs and accretions are significant factors contributing to the net loss in the prior periods.

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. Based upon the monthly commitment notices we have received to date, we have estimated and classified $6,131,000 of the borrowings outstanding under our Credit Facility as a current liability. We are in discussions with our lender, Texas Capital Bank, to enter into a new long term credit facility and we anticipate completing the new credit facility prior to expiration of the existing facility on July 3, 2011.

We manage our exposure to commodity price fluctuations by executing derivative transactions to hedge the change in prices of our production, thereby mitigating our exposure to price declines, but these transactions will also limit our earnings potential in periods of rising commodity prices. There also is a risk that we will be required to post collateral to secure our hedging activities and this could limit our available funds for our business activities.

The following table summarizes total current assets, total current liabilities and working capital at March 31, 2011 as compared to December 31, 2010.

Senior Secured Credit Facility

On July 3, 2008, EnerJex, EnerJex Kansas, and DD Energy entered into a three-year $50 million Senior Secured Credit Facility (the “Credit Facility”) with Texas Capital Bank, N.A. Borrowings under the Credit Facility will be subject to a borrowing base limitation based on our current proved oil reserves and will be subject to semi-annual redeterminations. A borrowing base redetermination was completed by Texas Capital Bank effective January 1, 2010. The borrowing base was determined to be $6,746,000 and called for $55,000 Monthly Borrowing Base Reductions (“MBBR”) beginning February 1, 2010. We repaid $500,000 of debt outstanding with proceeds from the December 31, 2010 transaction, and are no longer subject to the MBBR provision.

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

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Advances under the Credit Facility will be in the form of either base rate loans or Eurodollar loans. The interest rate on the base rate loans fluctuates based upon the higher of (1) the lender’s “prime rate” and (2) the Federal Funds rate plus 0.50%, plus, in either case, a margin of between 0.0% and 0.5% depending on the percent of the borrowing base utilized at the time of the credit extension, but in no event shall be less than five percent (5.0%). The interest rate on the Eurodollar loans fluctuates based upon the applicable LIBOR rate, plus a margin of 2.25% to 2.75% depending on the percent of the borrowing base utilized at the time of the credit extension, but in no event shall be less than five percent (5.0%). Eurodollar loans may be based upon one, two, three and six month LIBOR options, except that beginning March 30, 2009 and continuing through the date of this report, Texas Capital Bank has suspended all LIBOR based funding with maturities less than 90 days due to the extreme volatility in the interest rate market and the unprecedented spread between the 90 day LIBOR and the shorter term LIBOR options. A commitment fee of 0.375% on the unused portion of the borrowing base will accrue, and be payable quarterly in arrears. There was no commitment fee due at March 31, 2011.

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

The Credit Facility was amended August 18, 2009 to implement a minimum interest rate of five percent (5.0%) and establish minimum volumes to be hedged of not less than seventy-five percent (75%) of the proved developed producing reserves attributable to our interest in the borrowing base oil properties projected to be produced. The Credit Facility was further amended January 13, 2010 to modify the senior funded debt to EBITDA ratio on a quarterly basis beginning with the quarter ended December 31, 2009 and to modify the annualization of the interest coverage ratio, also beginning with the quarter ended December 31, 2009. The senior funded debt to EBITDA ratio allowed is 6.25:1.00 at December 31, 2009; 5.75:1.00 at March 31, 2010; 5.25:1.00 at June 30, 2010; and 4.75:1.00 at September 30, 2010; and 4.25:1.00 for all quarters ending after September 30, 2010. We were not in compliance the three technical covenants of the Credit Facility at December 31, 2010.

On September 29, 2010, the Credit Facility with Texas Capital Bank was amended to modify the borrowing base to $6,691,000 relative to the Proved Reserves attributable to the borrowing Base Oil and Gas Properties. The amendment also modified various terms in the Credit Facility along with changing the commitment fees to 0.37% per annum times the average daily balance of the loan.

On December 31, 2010, the Credit Facility with Texas Capital Bank was amended to modify the borrowing base to $6,116,000 relative to the Proved Reserves attributable to the borrowing Base Oil and Gas Properties. The amendment also modified the EBITDA ratio on a quarterly basis with the quarter ending March 31, 2011, permit the ratio allowed to 4.25:1 00. The Credit Agreement was further amended in order to reflect our reorganization.

EnerJex is currently in discussions with Texas Capital Bank to secure a new long-term credit facility and we believe this will be accomplished by June 30, 2011.

Satisfaction of our cash obligations for the next 12 months

A critical component of our operating plan is the ability to obtain additional capital through additional equity and/or debt financing and working interest participants. We believe that the transactions that closed as of December 31, 2010, significantly improved our ability to generate the additional debt and equity capital required to fund operations. In those transactions, we converted approximately $2,675,000 of debentures into equity securities, raised $3,500,000 of equity capital net of a $1,500,000 payment that we made in connection with those transactions, and reinstated our debt facility with Texas Capital Bank. As a result, we were able to significantly reduce the amount of our outstanding indebtedness. In addition, we expect to secure a new long-term credit facility with Texas Capital Bank prior to June 30, 2011.

Summary of product research and development

We do not anticipate performing any significant product research and development under our plan of operation until such time as we can raise adequate working capital to sustain our operations.

Expected purchase or sale of any significant equipment

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

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Significant changes in the number of employees

We currently have 18 full-time employees, including field personnel. As production and drilling activities increase or decrease, we may have to continue to adjust our technical, operational and administrative personnel as appropriate. We are using and will continue to use independent consultants and contractors to perform various professional services, particularly in the area of land services, reservoir engineering, geology drilling, water hauling, pipeline construction, well design, well-site monitoring and surveillance, permitting and environmental assessment. We believe that this use of third-party service providers may enhance our ability to contain operating and general expenses, and capital costs.

Off-Balance Sheet Arrangements

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

Critical Accounting Policies and Estimates

Our critical accounting estimates include the value our oil and gas properties, asset retirement obligations, current portion of long-term debt, and share-based payments.

Oil Properties

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

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

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

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

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As of March 31, 2011, 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 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 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 remains volatile.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.

We have entered into certain derivative or physical arrangements with respect to portions of our crude oil production, to reduce our sensitivity to volatile commodity prices and/or to meet hedging requirements under our Credit Facility. We believe that these derivative arrangements, although not free of risk, allow us to achieve a more predictable cash flow and to reduce exposure to commodity price fluctuations. However, derivative arrangements limit the benefit of increases in the prices of crude oil. Moreover, our derivative arrangements apply only to apportion of our production.

We have an Intercreditor Agreement in place between us; our counterparty, BP Corporation North America, Inc. (“BP”); and our agent, Texas Capital Bank, N.A., which allows Texas Capital Bank to also act as agent for BP for the purpose of holding and enforcing any liens or security interests resulting from our derivative arrangements. Therefore, we generally are not required to post additional collateral, including cash.

ITEM 4. CONTROLS AND PROCEDURES.

Our chief executive officer and principal financial officer, Robert G. Watson, evaluated the effectiveness of our disclosure controls and procedures (as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934, as amended) as of the end of the period covered by this Report. Based on the evaluation, Mr. Watson concluded that our disclosure controls and procedures are effective in timely altering him to material information relating to us (including our consolidated subsidiaries) required to be included in our periodic SEC filings.

There were no changes in our internal control over financial reporting that occurred during our most recent fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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PART II—OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS.

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

ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS.

None

ITEM 3. DEFAULTS UPON SENIOR SECURITIES.

None.

ITEM 4. (REMOVED AND RESERVED).

ITEM 5. OTHER INFORMATION.

None.

ITEM 6. EXHIBITS.

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SIGNATURES

In accordance with the requirements of the Exchange Act, the registrant caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

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