AgEagle Aerial Systems Inc. - Quarter Report: 2015 March (Form 10-Q)

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C.  20549

FORM 10-Q

þ       QUARTERLY REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended March 31, 2015

¨       TRANSITION REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

Commission file number 000-30234

(Exact name of registrant as specified in its charter)

 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 þ        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 þ        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   þ

The number of shares of Common Stock, $0.001 par value, outstanding on May 15, 2015 was 8,406,661 shares.

ENERJEX RESOURCES, INC.

FORM 10-Q

TABLE OF CONTENTS

PART 1 – FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

EnerJex Resources, Inc. and Subsidiaries

Condensed Consolidated Balance Sheets

(Unaudited)

See Notes to Condensed Consolidated Financial Statements.

EnerJex Resources, Inc. and Subsidiaries

Condensed Consolidated Statements of Operations

(Unaudited)

See Notes to Condensed Consolidated Financial Statements.

EnerJex Resources, Inc. and Subsidiaries

Condensed Consolidated Statements of Cash Flows

(Unaudited)

See Notes to Condensed Consolidated Financial Statements.

EnerJex Resources, Inc. and Subsidiaries

Notes to Condensed Consolidated Financial Statements

Note 1 – Basis of Presentation

The unaudited condensed consolidated financial statements of EnerJex Resources, Inc. (“we”, “us”, “our” and “Company”) 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 Annual Report Form 10-K for the fiscal year ended December 31, 2014.

Our consolidated financial statements include the accounts of our wholly-owned subsidiaries, EnerJex Kansas, Inc., Black Sable Energy, LLC, Working Interest, LLC, and Black Raven Energy, Inc. (“Black Raven”) for the quarter ended March 31, 2015 and for the year ended December 31, 2014. All intercompany transactions and accounts have been eliminated in consolidation.

Note 2 - Stock Options

A summary of stock options is 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. 

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. We consider our marketable securities to be Level 3.

Our derivative instruments consist of fixed price commodity swaps.

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 the Company; our counterparties, BP Corporation North America, Inc. ("BP") and Cargill Incorporated (“Cargill”) and our agent Texas Capital Bank, N.A., which allows Texas Capital Bank to also act as agent for the counterparties 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, 2015:

Monthly volume is the weighted average throughout the period.

The total fair value is shown as a derivative instrument in both current and non-current assets on the balance sheet. 

Note 6 - Long-Term Debt

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. (the “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 to be used to refinance Borrowers prior outstanding revolving loan facility with 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 Borrower's option, a per annum interest rate equal to (i) the Eurodollar Rate plus Eurodollar Margin, or (ii) the Base Rate plus Base Rate Margin (as those terms are defined in the Amended and Restated Credit Agreement). Eurodollar borrowings may be for one, two, three, or six months, as selected by the Borrowers. The margins for all loans are based on a pricing grid ranging from 0.00% to 0.75% for the Base Rate Margin and 2.25% to 3.00% for the Floating Rate Margin based on the Company's 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 reflected the addition of Rantoul Partners as an additional Borrower and added 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 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) expanded principal commitment amount of the Bank to $100,000,000, (ii) increased the Borrowing Base to $38,000,000, (iii) added Black Raven Energy, Inc. to the Credit Agreement as a borrower party, (iv) added certain collateral and security interests in favor of the Bank, and (v) reduced the Company’s 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) a technical correction to our covenant calculations.

On May 22, 2014, we entered into a Seventh Amendment to the Amended and Restated Credit Agreement. The Seventh Amendment reflects the Bank’s consent to our issuance of up to 850,000 shares of our 10% Series A Cumulative Redeemable Perpetual Preferred Stock.

On August 15, 2014, we entered into an Eighth Amendment to the Amended and Restated Credit Agreement. The Eighth Amendment reflects the following changes: (i) the borrowing base was increased from $38 million to $40 million, and (ii) the maturity of the facility was extended by three years to October 3, 2018.

Our borrowing base at March 31, 2015 and December 31, 2014 was $40 million, of which we had borrowed $23.5 million and $23 million respectively. For the three month period ended March 31, 2015 and for the year ended December 31, 2014 the interest rate was 3.3%. This facility expires on October 3, 2018. 

Other Long Term Debt

We financed the purchase of vehicles through a bank.  The notes are for four years and the vehicles collateralize these notes. The long term balance on the notes at March 31, 2015 was $4,928.  

Note 7 – Commitments & Contingencies

As of March 31, 2015, the Company has an outstanding irrevocable letter of credit in the amount of $50,000 issued in favor of the Texas Railroad Commission. The letter of credit is required by the Texas Railroad Commission for all companies operating in the state of Texas with production greater than limits they prescribe.

Rent expense for the three months ended March 31, 2015 and 2014 was approximately $43,000 and $51,000 respectively. Future non-cancellable minimum lease payments are approximately $120,000 for the remainder of 2015, $147,000 for 2016, $145,000 for 2017, $91,000 for 2018 and $77,000 for 2019. 

Note 8 - Equity Transactions

On January 15, 2015, 67,332 options were issued to employees and directors.

On March 13, 2015 the Company issued in a registered offering 763,547 registered shares of its common stock together with 1,242.17099 shares of its newly designated Series B Convertible Preferred Stock (the "Preferred Stock") convertible into 709,812 shares of common stock. We also issued in an unregistered offering, 521.62076 shares of Preferred Stock convertible into 298,069 shares of common stock, and warrants to purchase 1,771,428 shares of its common stock. The shareholder’s ability to convert a portion of the Preferred Stock and to exercise the warrant are restricted: (i) prior to the Company obtaining approval of the offering by its shareholders, which we expect to obtain before May 31, 2015, and (ii) pursuant to customary “blocker” provisions restricting the investor’s ownership to 9.99% of our outstanding common stock.

The Preferred Stock has a liquidation preference of $1,000 per share, and will be convertible at the option of the shareholder at a conversion ratio equal to approximately 571 shares of common stock for each one (1) share of Preferred Stock, subject to customary adjustments and anti-dilution price protection. Dividends are payable on the shares of Preferred Stock only if and to the extent that dividends are payable on the common stock into which the Preferred Stock is convertible. The Preferred Stock has no maturity date and can be redeemed by the Company beginning twelve months after the closing of the offering or upon a change of control. Each warrant will be exercisable for one share of common stock, for a period of five years beginning six months after March 13, 2015, at a cash exercise price of $2.75 per share, and may be exercised on a cashless basis after that six-month period if no effective registration statement covers the warrant shares by that time.

Note 9 – Impairment of Oil and Gas Properties

Pursuant to full cost accounting rules, the Company must perform a ceiling test each quarter on its proved oil and natural gas assets within each separate cost center. All of the Company’s costs are included in one cost center because all of the Company’s operations are located in the United States. The Company’s ceiling test was calculated using trailing twelve-month, unweighted-average first-day-of-the-month prices for oil and natural gas as of March 31, 2015, which were based on a West Texas Intermediate oil price of $78.82 per Bbl and a Henry Hub natural gas price of $3.74 per MMBtu (adjusted for basis and quality differentials), respectively. Utilizing these prices, the calculated ceiling amount was less than the net capitalized cost of oil and natural gas properties as of March 31, 2015, and as a result, a pre-tax write-down of $16.4 million was recorded at March 31, 2015. Additional material write-downs of the Company’s oil and gas properties could occur in subsequent quarters in the event that oil and natural gas prices remain at current levels, or if the Company experiences significant downward adjustments to its estimated proved reserves.

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.

Note 10 - Subsequent Events

We have reviewed all material events through the date of this report in accordance with ASC 855-10.

On April 15, 2015, The Company announced that Oakridge Energy, Inc. (“Oakridge”) completed the sale of its La Plata County, Colorado real estate at a sales price that is expected to generate for EnerJex a cash distribution of approximately $1.75 million. Oakridge announced plans to distribute the after-tax net proceeds from the sale, within the next 60 to 90 days, to its shareholders of record as of April 9, 2015. As of the record date for that distribution, EnerJex owned approximately 15.9% of Oakridge's issued and outstanding shares.

On April 28, 2015, the Company entered into six deferred premium put contracts with BP Energy Company for the six month period ending December 31, 2016. Each contract entitles the Company to sell 5,000 barrels of crude oil at $60.00. A premium of $5.72 per barrel will be paid by the Company at the expiration or settlement of the contract.

On April 29, 2015, the Borrowers entered into a Ninth Amendment to Amended and Restated Credit Agreement (the "Ninth Amendment") with the Banks. In the Ninth Amendment, the Banks (i) reduced the borrowing base from $40 million to $22.6 million, (ii) imposed affirmative obligations on the Borrowers to use a portion of proceeds received with regard to future sales of securities, or distributions received with regard to securities held, to repay the loan, (iii) consented to non-compliance by Borrowers with certain terms of the Credit Agreement, (iv) waived certain provisions of the Credit Agreement, and (v) agreed to certain other amendments to the Credit Agreement.

On May 1, 2015, the Borrowers and the Banks entered into a Letter Agreement (the “Letter Agreement”) to clarify that up to $1,000,000 in proceeds from any potential future securities offering will be unencumbered by the Banks’ Liens as described in the Credit Agreement through November 1, 2015, and that, until November 1, 2015, such proceeds shall not be subject to certain provisions in the Credit Agreement prohibiting the Company from declaring and paying dividends that may be due and payable to holders of securities issued in such potential offerings or issued prior to the Letter Agreement.

On May 13, 2015 the Company sold 183,433 shares of its 10% Series A Cumulative Redeemable Perpetual Preferred Stock at $12.50 per share for gross proceeds of approximately $2.3 million. The Company intends to use the net proceeds of this offering for general corporate purposes, including capital expenditures, working capital, preferred stock dividends, and repayment of outstanding borrowings under its senior credit facility.

The offering was made pursuant to a registration statement on Form S-3 (File No. 333-199030) previously filed and declared effective by the U.S. Securities and Exchange Commission (SEC). 

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:

   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 Annual Report on Form 10-K for the fiscal year ended December 31, 2014.

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., Black Sable Energy, LLC, Working Interest, LLC, and Black Raven Energy, Inc. 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.enerjex.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., 4040 Broadway, Suite 508, 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 and natural gas properties. Our business activities are currently focused in Kansas, Colorado, Nebraska and Texas.

We continue to investigate multiple opportunities to both unlock value and accelerate growth in an accretive manner on behalf of shareholders, including but not limited to mergers, acquisitions, joint ventures, and non-dilutive financings. There can be no assurance of the results or timing associated with this process.

Recent Developments

The following is a brief description of our most significant corporate developments that have occurred since the end of 2014:

The Preferred Stock has a liquidation preference of $1,000 per share, and will be convertible at the option of the shareholder at a conversion ratio equal to approximately 571 shares of common stock for each one (1) share of Preferred Stock, subject to customary adjustments and anti-dilution price protection. Dividends are payable on the shares of Preferred Stock only if and to the extent that dividends are payable on the common stock into which the Preferred Stock is convertible. The Preferred Stock has no maturity date and can be redeemed by the Company beginning twelve months after the closing of the offering or upon a change of control. Each warrant will be exercisable for one share of common stock, for a period of five years beginning six months after March 13, 2015, at a cash exercise price of $2.75 per share, and may be exercised on a cashless basis after that six-month period if no effective registration statement covers the warrant shares by that time.

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), the average sales prices, average production costs and direct lifting costs per unit of production for the periods ending March 31, 2015 and March 31, 2014.

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

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

Results of Operations for the Three Months Ended March 31, 2015 and 2014 compared.

Income:

Oil Revenues

Oil revenues for the three months ended March 31, 2015 were $1,380,646 compared to oil revenues of $3,612,579 for the three months ended March 31, 2014. Oil revenues decreased due to a $49.36 decrease in realized prices or approximately 54% to $41.72 for the quarter ended March 31, 2015 versus $91.08 for the quarter ended March 31, 2014. In addition to the decrease in realized prices, production decreased by approximately 6,600 bbls for the quarter ended March 31, 2015 compared to the quarter ended March 31, 2014.

Natural Gas Revenues

Natural gas revenues for the three months ended March 31, 2015 were $117,195 compared to natural gas revenues of $242,398 for the three months ended March 31, 2014. Natural gas revenues decreased due to a significant decrease in realized prices of 57% or $2.42 to $1.82 for the quarter ended March 31, 2015 compared to $4.24 for the quarter ended March 31, 2014. The decrease in realized prices was slightly offset by an increase in production.

Expenses:

Direct Operating Costs

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, 2015 decreased 17% to $1,267,301 from $1,531,907 for the three months ended March 31, 2014. Direct operating costs per Boe decreased 7.1% to $28.93 from $31.14. The $264,606 decrease in direct operating costs is due primarily to reduced lease operating expenses resulting from cost reductions that were implemented in response to the decline in commodity prices. 

Depreciation, Depletion and Amortization

Depreciation, depletion and amortization for the three months ended March 31, 2015 was $745,608 compared to $763,758 for the three months ended March 31, 2014. The decrease in depletion expense is due primarily to a decrease in oil production which was slightly offset by an increase in natural gas production during the first quarter of 2015 compared to the first quarter of 2014. Depletion expense per Boe decreased $1.48 or 9.5% in the first quarter of 2015 compared to the first quarter of 2014.  

Impairment of oil and gas properties

Impairment of oil and gas properties was $16,401,376 for the quarter ended March 31, 2015. The impairment was due the dramatic decrease in commodity pricing as noted above.

Professional Fees

Professional fees for the three months ended March 31, 2015 were $253,729 compared to $224,902 for the three months ended March 31, 2014. The increase in professional fees is due primarily to increased fees paid to our external reserve engineer, attorneys and financial advisors.

Salaries

Salaries for the three months ended March 31, 2015 were $521,287 compared to $310,348 for the three months ended March 31, 2014.  Salaries increased $210,939 due primarily to new hires of technical personnel during the 3^rd quarter of 2014 and raises to specialty and technical positions within the company. The Company increased its technical capabilities in 2014 to support forecasted growth and the pursuit of strategic opportunities.

Administrative Expenses

Administrative expenses for the three months ended March 31, 2015 were $230,740 compared to $141,029 for the three months ended March 31, 2014. The increase in administrative expenses is due primarily to a reduction in reimbursements from working interest partners and increased SEC filing fees.

Interest Expense

Interest expense, which includes amortization of deferred financing costs and accretion, for the three months ended March 31, 2015 was $309,496 compared to $378,928 for the three months ended March 31, 2014. Interest expense and amortization of deferred financing costs decreased as a result of decreased borrowings under our Credit Facility.  

Derivative Losses

We incurred an unrealized loss of $217,522 on our derivative contracts in the first quarter of 2015 compared to a loss of $404,353 for the three months ended March 31, 2014. The increase in the loss was due primarily to the completion of contracts.

Net Income (Loss)

Net loss for the three months ended March 31, 2015 was ($17,354,561) compared to a net income of $103,634 for the three months ended March 31, 2014.  The net loss during the first quarter of 2015 compared to the prior year period was primarily a result of the $16,401,376 impairment of oil and gas properties as well as decreased revenues related to the decrease in realized sales prices. The decreases were partially offset by realized derivative gains.

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, asset sales, and the issuance of equity securities. Due to the decline in oil prices, the resulting decline in our reserves as reflected in our reserve report which caused a corresponding reduction in our borrowing base, and the recent issuances of equity securities from our "shelf" registration, it will be more difficult in 2015 to use our historical means of meeting our capital requirements to provide us with adequate liquidity to fund our operations and capital program.

 The following table summarizes total current assets, total current liabilities and working capital.

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. (the “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 to be used to refinance Borrowers prior outstanding revolving loan facility with 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 Borrower's option, a per annum interest rate equal to (i) the Eurodollar Rate plus Eurodollar Margin, or (ii) the Base Rate plus Base Rate Margin (as those terms are defined in the Amended and Restated Credit Agreement). Eurodollar borrowings may be for one, two, three, or six months, as selected by the Borrowers. The margins for all loans are based on a pricing grid ranging from 0.00% to 0.75% for the Base Rate Margin and 2.25% to 3.00% for the Floating Rate Margin based on the Company's 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 reflected the addition of Rantoul Partners as an additional Borrower and added 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 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) increased the Borrowing Base to $38,000,000, (iii) added Black Raven Energy, Inc. to the Credit Agreement as a borrower party, (iv) added certain collateral and security interests in favor of the Bank, and (v) reduced the Company’s 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.

 On May 22, 2014, we entered into a Seventh Amendment to the Amended and Restated Credit Agreement. The Seventh Amendment reflects the Bank’s consent to our issuance of up to 850,000 shares of our 10% Series A Cumulative Redeemable Perpetual Preferred Stock.

On August 15, 2014, we entered into an Eighth Amendment to the Amended and Restated Credit Agreement. The Eighth Amendment reflects the following changes: (i) the borrowing base was increased from $38 million to $40 million, and (ii) the maturity of the facility was extended by three years to October 3, 2018.

Our borrowing base at March 31, 2015 and December 31, 2014 was $40 million, of which we had borrowed $23.5 million and $23 million respectively. For the three month period ended March 31, 2015 and for the year ended December 31, 2014 the interest rate was 3.3%. This facility expires on October 3, 2018.

Satisfaction of our cash obligations for the next 12 months

We intend to meet our near term cash obligations through 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 during our normal course of operations over the next twelve months.

Significant changes in the number of employees

There have been no significant changes in the number of our employees since December 31, 2014. We currently have 29 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 expenses, 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 of our oil and gas properties, asset retirement obligations, and share-based payments.

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 quarter ended March 31, 2015, we incurred a $16,401,376 impairment. For the year ended December 31, 2014, 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.

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 are a smaller reporting Company as defined by Rule 12b-2 under the Securities Exchange Act of 1934, and are not required to provide the information required under this item.

ITEM 4.  CONTROLS AND PROCEDURES.

Our chief executive officer, Robert G. Watson, Jr., and our Chief Financial Officer, Douglas M. Wright 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 pursuant to Exchange Act Rule 13-a-15(b). Based on the evaluation, Mr. Watson and Mr. Wright concluded that our disclosure controls and procedures are effective.

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.

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 transition 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. MINE SAFETY DISCLOSURES.

Not applicable.

ITEM 5. OTHER INFORMATION.

None.

ITEM 6.  EXHIBITS.

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.