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EX-10.37 - EXHIBIT 10.37 - AgEagle Aerial Systems Inc.v377211_ex10-37.htm

 

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, 2014

 

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

 

Commission file number 000-30234

 

 

ENERJEX RESOURCES, INC.

(Exact name of registrant as specified in its charter)

 

Nevada   88-0422242

(State or other jurisdiction of incorporation or

organization)

  (I.R.S. Employer Identification No.)
     
4040 Broadway    
Suite 508    
San Antonio, Texas   78209
(Address of principal executive offices)   (Zip Code)

 

(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 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.

 

Large accelerated filer  ¨ Accelerated filer  ¨
   
Non-accelerated filer  ¨  (Do not check if a smaller reporting company)     Smaller reporting company  þ

 

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 12, 2014 was 109,514,028 shares.

 

 
 

 

ENERJEX RESOURCES, INC.

FORM 10-Q

TABLE OF CONTENTS

 

    Page
PART I     FINANCIAL STATEMENTS  
ITEM 1. FINANCIAL STATEMENTS 2
  Condensed Consolidated Balance Sheets 2
  Condensed Consolidated Statements of Operations 3
  Condensed Consolidated Statements of Cash Flows 4
  Notes to Condensed Consolidated Financial Statements 5
  FORWARD-LOOKING STATEMENTS 9
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS 10
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK 16
ITEM 4. CONTROLS AND PROCEDURES 16
     
PART II    OTHER INFORMATION  
ITEM 1. LEGAL PROCEEDINGS 17
ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS 17
ITEM 3. DEFAULTS UPON SENIOR SECURITIES 17
ITEM 4. MINE SAFETY DISCLOSURES 17
ITEM 5. OTHER INFORMATION 18
ITEM 6. EXHIBITS 18
     
SIGNATURES 20

 

i
 

 

PART 1 – FINANCIAL INFORMATION

 

ITEM 1. FINANCIAL STATEMENTS

EnerJex Resources, Inc. and Subsidiaries

Condensed Consolidated Balance Sheets

(Unaudited)

  

   March 31,   December 31, 
   2014   2013 
Assets          
Current assets:          
Cash  $1,436,642   $1,308,196 
Accounts receivable   2,561,045    2,461,746 
Inventory   235,243    238,794 
Marketable securities   1,018,573    1,018,573 
Deposits and prepaid expenses   711,035    373,994 
Total current assets   5,962,538    5,401,303 
           
Non-current assets:          
Fixed assets, net of accumulated depreciation of $1,857,114 and $1,785,401   2,415,022    2,406,591 
Oil and gas properties using full-cost accounting, net of accumulated DD&A   60,905,245    61,349,403 
Other non-current assets   803,277    834,180 
     Total  non-current assets   64,123,544    64,590,174 
Total assets  $70,086,082   $69,991,477 
           
Liabilities and Stockholders' Equity          
Current liabilities:          
Accounts payable  $2,505,317   $2,424,009 
Accrued liabilities   2,520,897    3,070,461 
Derivative liability   1,116,171    1,011,708 
Total current liabilities   6,142,385    6,506,178 
           
Asset retirement obligation   2,747,016    2,687,801 
Long-term debt   32,038,159    31,547,255 
Derivative liability   304,469    339,642 
Total non-current liabilities   35,089,644    34,574,698 
             Total liabilities   41,232,029    41,080,876 
Commitments & Contingencies          
Stockholders' Equity:          
Preferred stock, $0.001 par value, 25,000,000 shares authorized, 4,779,460 shares issued and outstanding   4,780    4,780 
Common stock, $0.001 par value, 250,000,000  shares authorized; shares issued and outstanding 115,257,967 at March 31, 2014 and 115,004,045 at December 31, 2013   115,258    115,005 
Treasury Stock, 5,750,000  shares   (2,551,000)   (2,551,000)
Paid-in capital   52,595,821    52,356,811 
Accumulated other comprehensive income   (552,589)   (552,589)
Retained (deficit)   (20,758,217)   (20,462,406)
            Total stockholders' equity   28,854,053    28,910,601 
           
Total liabilities and stockholders' equity  $70,086,082   $69,991,477 

  

See Notes to Condensed Consolidated Financial Statements.

 

2
 

 

EnerJex Resources, Inc. and Subsidiaries

Condensed Consolidated Statements of Operations

(Unaudited)

  

   For the Three Months Ended 
   March 31, 
   2014   2013 
         

Revenues:

        
Oil revenues  $3,612,579   $2,337,301 
Natural gas revenues   242,398    - 
Total revenues   3,854,977    2,337,301 
           
Expenses:          
Direct operating costs   1,531,907    782,072 
Depreciation, depletion and  amortization   763,758    444,537 
Professional fees   224,902    356,222 
Salaries   310,348    246,011 
Administrative expense   141,029    139,404 
Total expenses   2,971,944    1,968,246 
Income from operations   883,033    369,055 
           
Other income (expense):          
Interest expense   (378,928)   (118,245)
Derivative losses   (404,353)   (239,941)
Other income   3,882    9,167 
Total other income (expense)   (779,399)   (349,019)
Net income  $103,634   $20,036 
           
Net income   103,634    20,036 
Preferred dividends   (399,447)   (192,887)
Net (loss) attributable to common stockholders  $(295,813)  $(172,851)
Net (loss) per share basic and diluted  $(0.00)  $(0.00)
           
Weighted average shares   109,408,161    67,836,529 

    

See Notes to Condensed Consolidated Financial Statements.

 

3
 

 

EnerJex Resources, Inc. and Subsidiaries

Condensed Consolidated Statements of Cash Flows

(Unaudited)

  

   For the Three Months Ended 
   March 31, 
   2014   2013 
Cash flows  from operating activities          
Net income  $103,634   $20,036 
Depreciation, depletion and amortization   763,758    444,537 
Shares based payments issued for services   258,498    49,334 
Accretion of asset retirement obligation   63,695    28,193 
Loss on derivatives   69,289    28,775 
Settlement of asset retirement obligation   (4,996)   - 
Loss on sale of fixed assets   -    7,785 
Changes in assets and liabilities:          
Accounts receivable   (99,299)   14,877 
Inventory   3,551      
Deposits and prepaid expenses   (356,275)   26,171 
Accounts payable   81,308    (455,950)
Accrued liabilities   (949,011)   (264,889)
Cash flows from operating activities   (65,848)   (101,131)
           
Cash flows  from investing activities          
           
Purchase of fixed assets   (80,143)   (19,597)
Additions to oil and gas properties   (1,234,890)   (1,498,962)
Sales of oil and gas properties   987,521    15,000 
Proceeds from sale of fixed assets   -    1,600 
Cash flows from investing activities   (327,512)   (1,501,959)
           
Cash flows  from financing activities          
Payments on notes payable   -    (200,000)
Proceeds from borrowings   500,000    1,500,000 
    Repayment of  long-term debt   (9,096)   - 
Deferred financing costs   30,902      
Cash flows from financing activities   521,806    1,300,000 
           
Net increase (decrease) in cash   128,446    (303,090)
Cash – beginning   1,308,196    767,494 
Cash – ending  $1,436,642   $464,404 
           
Supplemental disclosures:          
Interest paid  $74,499   $71,006 
Income taxes paid  $-   $- 
           
Non-cash transactions:          
Share based payments issued for services  $258,498   $49,334 

 

See Notes to Condensed Consolidated Financial Statements.

 

4
 

 

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, 2013.

  

Our consolidated financial statements include the accounts of our wholly-owned subsidiaries, EnerJex Kansas, Inc.,  DD Energy, Inc., Black Sable Energy, LLC, Working Interest, LLC, and Black Raven Energy, Inc. (“Black Raven”) for the quarter ended March 31, 2014. On September 27, 2013 we acquired Black Raven. Accordingly, only the financial position, results of operation and cash flows of Black Raven for the quarter ended December 31, 2013 were included in the Company’s consolidated financial statements for the year ended December 31, 2013. All intercompany transactions and accounts have been eliminated in consolidation. 

 

Note 2 - Stock Options

 

A summary of stock options is as follows:

 

   Options   Weighted
Avg.
Exercise
Price
   Warrants   Weighted
Avg.
Exercise
Price
 
Outstanding December 31, 2013   3,467,000   $0.62    -   $- 
Granted   35,500    0.70    -    - 
Cancelled   (22,500)   0.70    -    - 
Exercised   -    -    -    - 
Outstanding March 31, 2014   3,480,000   $0.62    -   $- 

 

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, 2014.

 

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.

 

5
 

 

Our derivative instruments consist of fixed price commodity swaps.

 

   Fair Value Measurement 
   Level 1   Level 2   Level 3 
Crude oil contracts  $-   $(1,420,640)  $- 
Marketable Securities  $-   $-   $1,018,573 

 

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:

  

Asset retirement obligations, December 31, 2013  $2,687,801 
Liabilities incurred during the period   516 
Accretion   63,695 
Liabilities settled during the quarter   (4,996)
Asset retirement obligations, March 31, 2014  $2,747,016 

  

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, 2014:

 

   Term   Monthly Volumes    Price/Bbl   Fair Value 
Crude oil swap   7/12-12/15    1,514 Bbls  $76.74    (581,654)
Crude oil swap   7/11-12/15    2,679 Bbls  $83.70    (521,438)
Crude oil swap   1/14-12/14    1,375 Bbls  $90.25    (95,729)
Crude oil swap   1/14-12/14    1,900 Bbls  $96.00    (34,067)
Crude oil swap   1/15-12/15    5,800 Bbls  $88.55    (111,012)
Crude oil swap   9/13-12/14    3,000 Bbls  $95.15    (76,740)
                   $(1,420,640)

 

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. 

6
 

 

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 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) an increase in our Borrowing Base to $38,000,000, (iii) the addition of Black Raven Energy, Inc. to the Credit Agreement as a borrower party, (iv) the addition of certain collateral and security interests in favor of the Bank, and (v) the reduction of our current interest rate to 3.30%.  

 

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

 

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

 

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, 2014 was $38,159. 

 

7
 

 

Note 7 – Commitments & Contingencies

 

As of March 31, 2014 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, 2014 and 2013 was approximately $51,000 and $29,000 respectively. Future non-cancellable minimum lease payments are approximately $120,000 for the remainder of 2014, $154,000 for 2015, $147,000 for 2016, $145,000 for 2017, $90,000 for 2018 and $77,000 for 2019. 

 

Note 8 - Equity Transactions

 

 On January 15, 2014, 110,000 shares were issued to two employees of the Company as compensation. From February 5, 2014 through March 17, 2014, 143,922 shares were issued to a consultant for professional services rendered on behalf of the Company.

  

Note 9 - Subsequent Events

 

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

 

Effective as of May 1, 2014, our wholly-owned subsidiary, Working Interest, LLC (“WILLC”), entered into a transaction pursuant to which (i) WILLC agreed to assign to Coal Creek Energy, LLC (“Coal Creek”) all of its working interests in certain oil leases comprising approximately 373 net acres in our Cherokee Project, and (ii) Coal Creek agreed to assign to WILLC all of its working interests in certain oil leases comprising approximately 791 net acres in our Cherokee Project. As a result of this transaction, we significantly consolidated our working interests and increased our net acreage in this project by approximately 5%. The net production associated with the producing leases that we assigned and received was comparable and less than 5 barrels of oil per day in each instance.

  

8
 

 

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:

 

  · inability to attract and obtain additional development capital;
  · inability to achieve sufficient future sales levels or other operating results;
  · inability to efficiently manage our operations;
  · effect of our hedging strategies on our results of operations;
  · potential default under our secured obligations or material debt agreements;
  · estimated quantities and quality of oil reserves;
  · declining local, national and worldwide economic conditions;
  · fluctuations in the price of oil;
  · continued weather conditions that impact our abilities to efficiently manage our drilling and development activities;
  · the inability of management to effectively implement our strategies and business plans;
  · approval of certain parts of our operations by state regulators;
  · inability to hire or retain sufficient qualified operating field personnel;
  · increases in interest rates or our cost of borrowing;
  · deterioration in general or regional economic conditions;
  · adverse state or federal legislation or regulation that increases the costs of compliance, or adverse findings by a regulator with respect to existing operations;
  · the occurrence of natural disasters, unforeseen weather conditions, or other events or circumstances that could impact our operations or could impact the operations of companies or contractors we depend upon in our operations;
  · inability to acquire mineral leases at a favorable economic value that will allow us to expand our development efforts;
  · adverse state or federal legislation or regulation that increases the costs of compliance, or adverse findings by a regulator with respect to existing operations; and
  · changes in U.S. GAAP or in the legal, regulatory and legislative environments in the markets in which we operate.

 

   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, 2013.

 

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, Working Interest, LLC, and Black Raven Energy, Inc. unless the context requires otherwise. We report our financial information on the basis of a December 31st 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.

 

9
 

 

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 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.

 

We are currently focusing 100% of our capital budget on our Colorado and Kansas properties where we have identified hundreds of drilling locations that we believe will generate a high rate of return with a low risk profile.

 

Recent Developments

 

The following is a brief description of our most significant corporate developments that have occurred since the end of 2013:

  

·

During the first quarter, we successfully reactivated two oil wells in our Adena Project located in Colorado. In addition, we entered into a new natural gas purchase contract and initiated natural gas production in this project. Unseasonably cold weather and harsh operating conditions slowed our operations in Colorado during the first quarter of 2014.

 

·

During the first quarter, we successfully completed workover operations on eight natural gas wells in our Niobrara Project located in Colorado. We also filed 17 drilling permits in this project where we have identified dozens of high-ranking drilling locations based on 3D seismic analysis. We are in the process of soliciting bids for drilling and completion operations associated with these wells, along with pipeline construction and the upgrade of an existing tap into the Trailblazer pipeline.

 

·On March 14, 2014, Black Raven entered into a Settlement and Release Agreement with Atlas Resources, LLC, pursuant to which the parties settled certain disputes regarding the rights and obligations of the parties under that certain Farmout Agreement dated effective as of July 23, 2010.

 

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

 

Pursuant to the Settlement Agreement, Atlas also agreed to pay Black Raven the sum of $687,939 and assign to Black Raven its rights to depth in any zone below the Niobrara formation on approximately 8,360 acres that are held by production in Phillips and Sedgwick counties in the State of Colorado. In addition, Black Raven agreed to purchase seven non-producing wells from Atlas for $150,000.

 

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

 

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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), the average sales prices, average production costs and direct lifting costs per unit of production for the periods ending March 31, 2014 and March 31, 2013.

  

   For the Three Months Ended 
   March 31, 
   2014   2013 
         
Net Production          
Oil (Bbl)   39,665    26,537 
Natural gas (Mcf)   57,141    - 
           
Average Sales Prices          
Oil (per Bbl)  $91.08   $88.07 
Natural gas (Mcf)  $4.24   $- 
           
Average Production Cost (1)          
Per Barrel of Oil Equivalent (“Boe”)  $46.67   $46.22 
           
Average Lifting Costs (2)          
Per Boe  $31.14   $29.47 

 

(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, 2014 and 2013 compared.

 

Income:

  

   Three Months Ended   Increase / 
   March 31,   (Decrease) 
   2014   2013     
Oil revenues  $3,612,579   $2,337,301   $1,275,278 
Natural gas revenues   242,398    -    242,398 

 

Oil Revenues

  

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

 

Natural Gas Revenues

 

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

 

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Expenses:

  

   Three Months Ended   Increase / 
   March 31,   (Decrease) 
   2014   2013     
Production expenses:               
Direct operating costs  $1,531,907   $782,072   $749,835 
Depreciation, depletion and amortization   763,758    444,537    319,221 
Total production expenses   2,295,665    1,226,609    1,069,056 
                
General expenses:               
Professional fees   224,902    356,222    (131,320)
Salaries   310,348    246,011    64,337 
Administrative expense   141,029    139,404    1,625 
Total general expenses   676,279    741,637    (65,358)
Total production and general expenses   2,971,944    1,968,246    1,003,698 
                
Income from operations   883,033    369,055    513,978 
                
Other income (expense)               
Interest expense   (378,928)   (118,245)   (260,683)
Derivative losses   (404,353)   (239,941)   (164,412)
Other income   3,882    9,167    (5,285)
Total other income (expense)   (779,399)   (349,019)   (430,380)
                
Net income  $103,634   $20,036   $83,598 

 

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, 2014 increased 96% to $1,531,907 from $782,072 for the three months ended March 31, 2013. However, direct operating costs per Boe increased only 5.7% to $31.14 from $29.47. The $749,835 increase in direct operating costs is due primarily to new production associated with the assets that we acquired as part of our merger with Black Raven on September 27, 2013.  Direct operating costs also increased as a result of non-recurring expenses that were incurred as a result of unseasonably cold weather and harsh operating conditions during the first quarter of 2014.

 

Depreciation, Depletion and Amortization

  

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

 

Professional Fees

 

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

 

Salaries

 

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

 

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Administrative Expenses

  

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

 

Interest Expense

  

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

 

Derivative Losses

 

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

 

Net Income (Loss)

 

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

 

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. We believe that our historical means of meeting our capital requirements will provide us with adequate liquidity to fund our operations and capital program in 2014.

 

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

  

   March 31, 
2014
   December 31,
2013
   Increase /
(Decrease)
 
             
Current Assets  $5,962,538   $5,401,303   $561,235 
                
Current Liabilities  $6,142,385   $6,506,178   $(363,793)
                
Working Capital (deficit)  $(179,847)  $(1,104,875)  $925,028 

 

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 used to refinance Borrowers prior outstanding revolving loan facility with Bank, dated July 3, 2008, and for working capital and general corporate purposes. 

 

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  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, which closed on December 15, 2011. 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) an increase in our Borrowing Base to $38,000,000, (iii) the addition of Black Raven Energy, Inc. to the Credit Agreement as a borrower party, (iv) the addition of certain collateral and security interests in favor of the Bank, and (v) the reduction of our current interest rate to 3.30%. 

 

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

 

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

 

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.

 

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Significant changes in the number of employees

  

There have been no significant changes in the number of our employees since December 31, 2013. We currently have 35 full-time employees, including field personnel. As production and drilling activities increase or decrease, we may have to continue to adjust our technical, operational and administrative personnel as appropriate. We are using and will continue to use independent consultants and contractors to perform various professional services, particularly in the area of land services, reservoir engineering, geology drilling, water hauling, pipeline construction, well design, well-site monitoring and surveillance, permitting and environmental assessment. We believe that this use of third-party service providers may enhance our ability to contain operating 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, 2014 and the year ended December 31, 2013, 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.

 

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 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.

 

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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 transition report, there are no material pending legal proceedings to which we are a party or to which any of our property is subject, except the legal proceedings discussed below.

 

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

 

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

 

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

 

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

 

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

 

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.

 

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ITEM 5. OTHER INFORMATION.

 

None.

 

ITEM 6.  EXHIBITS.

 

Exhibit

No.

  Description
2.1   Agreement and Plan of Merger between Millennium Plastics Corporation and Midwest Energy, Inc. effective August 15, 2006 (incorporated by reference to Exhibit 2.3 to the Form 8-K filed on August 16, 2006).
2.2   Agreement and Plan of Merger by and among Registrant, BRE Merger Sub, Inc., Black Raven Energy, Inc. and West Coast Opportunity Fund, LLC dated July 23, 2013 (incorporated herein by reference to Exhibit 10.4 on Form 8-K filed July 29, 2013).
3.1   Amended and Restated Articles of Incorporation, as currently in effect (incorporated by reference to Exhibit 3.1 to the Form 10-Q filed on August 14, 2008)
3.2   Amended and Restated Bylaws, as currently in effect (incorporated by reference to Exhibit 3.3 to the Form SB-2 filed on February 23, 2001)
3.3   Certificate of Amendment of Articles of Incorporation (Previously filed)
4.1   Article VI of Amended and Restated Articles of Incorporation of Millennium Plastics Corporation (incorporated by reference to Exhibit 1.3 to the Form 8-K filed on December 6, 1999)
4.2   Article II and Article VIII, Sections 3 & 6 of Amended and Restated Bylaws of Millennium Plastics Corporation (incorporated by reference to Exhibit 4.1 to the Form SB-2 filed on February 23, 2001)
10.1   Amended and Restated 2002/2003 Stock Option Plan (incorporated by reference to Exhibit 10 to the Form 8-K filed on May 11, 2007
10.2   Form of Officer and Director Indemnification Agreement (incorporated by reference to Exhibit 10.2 to the Form 8-K filed on October 16, 2008)  
10.3   Euramerica Letter Agreement Amendment dated September 15, 2008 (incorporated by reference to Exhibit 10.10 to the Form 8-K filed on September 18, 2008)
10.4   Euramerica Letter Agreement Amendment dated October 15, 2008 (incorporated by reference to Exhibit 10.11 to the Form 8-K filed on October 21, 2008)
10.5   Joint Operating Agreement with Pharyn Resources to explore and develop the Brownrigg Lease Press Release dated June 1, 2009 (incorporated by reference to Exhibit 99.1 to the Form 8-K filed on June 5, 2009).
10.6   Amendment 4 to Joint Exploration Agreement effective as of  November 6, 2008 between MorMeg, LLC and EnerJex Resources, Inc.  (incorporated by reference to Exhibit 10.15 to the Form 10-K filed July 14, 2009)
10.7   Standby Equity Distribution Agreement with Paladin Capital Management, S.A. dated December 3, 2009 (incorporated by reference to Exhibit 10.52 to the Form S-1 filed on December 9, 2009)
10.8   Amendment 5 to Joint Exploration Agreement effective as of December 31, 2009 between MorMeg LLC and EnerJex Resources, Inc. (incorporated by reference to Exhibit 10.15 to the Form 10-Q filed on February 16, 2010)
10.9†   Amended and Restated EnerJex Resources, Inc. Stock Incentive Plan (incorporated by reference to Exhibit 10.1 to the Form 8-K filed on October 16, 2008)
10.10   Amendment 6 to Joint Exploration Agreement effective as of March 31, 2010 between MorMeg LLC and EnerJex Resources, Inc. (incorporated by reference to Exhibit 10.24 to the Form 10-K filed on July 15, 2010)
10.11   Securities Purchase and Asset Acquisition Agreement between Enerjex Resources, Inc. and West Coast Opportunity Fund, LLC; Montecito Venture Partners, LLC; J&J Operating Company, LLC and Frey Living Trust dated December 31, 2010 (incorporated by reference to Exhibit 10.1 to the Form 8-K filed on January 6, 2011).
10.12   Stock Repurchase Agreement between Enerjex Resources, Inc. and Working Interest Holdings, LLC dated December 31, 2010 (incorporated by reference to Exhibit 10.2 to the Form 8-K filed on January 6, 2011).
10.13   Securities Purchase Agreement between Enerjex Resources, Inc. and various Investors dated December 31, 2010 (incorporated by reference to Exhibit 10.3 to the Form 8-K filed on January 6, 2011).
10.14   Joint Development Agreement between Enerjex Resources, Inc. and Haas Petroleum, LLC dated December 31, 2010 (incorporated by reference to Exhibit 10.1 to the Form 8-K filed on January 27, 2011).
10.15   Joint Operating Agreement between Enerjex Resources, Inc. and Haas Petroleum, LLC and MorMeg, LLC dated December 31, 2010 (incorporated by reference to Exhibit 10.2 to the Form 8-K filed on January 27, 2011).
10.16   Letter Agreement with Registrant, James Loeffelbein, John Loeffelbein and J&J Operating dated January 14, 2011 (incorporated by reference to Exhibit 10.1 on Form 8-K filed on January 18, 2011).
10.17   Form of Securities Purchase Agreement among Registrant and Investors dated March 31, 2011 (incorporated by reference to Exhibit 10.1 on Form 8-K filed on April 4, 2011).

 

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10.18   Form of Warrant among Registrant and Investors dated March 31, 2011 (incorporated by reference to Exhibit 10.2 on Form 8-K filed on April 4, 2011).
10.19   Form of Stock Redemption Agreement among Registrant and Working Interest Holdings, LLCs dated March 31, 2011 (incorporated by reference to Exhibit 10.1 on Form 8-K filed on April 4, 2011).
10.20   Amended and Restated Credit Agreement dated October 3, 2011 (incorporated herein by reference to Exhibit 10.1 on Form 8-K filed on October 6, 2011).
10.21   Option and Joint Development Agreement by and among Registrant and MorMeg, LLC dated August 2011 (incorporated herein by reference to Exhibit 10.1 on Form 8-K filed on November 15, 2011).
10.22   Rantoul Partners General Partnership Agreement dated December 14, 2011 (incorporated herein by reference to Exhibit 10.1 on Form 8-K filed on December 14, 2011).
10.23   First Amendment to Amended and Restated Credit Agreement dated December 14, 2011 (incorporated herein by reference to Exhibit 10.2 on Form 8-K filed on December 14, 2011).
10.24   First Amendment to General Partnership Agreement for Rantoul Partners dated March 30, 2012 (incorporated herein by reference to Exhibit 10.1 on Form 8-K filed on April 5, 2012).
10.25   Share Option Agreement by and among the EnerJex and Enutroff dated August 31, 2012 (incorporated herein by reference to Exhibit 10.1 on Form 8-K filed on October 10, 2012).
10.26   Second Amendment to Amended and Restated Credit Agreement dated August 31, 2012 (incorporated herein by reference to Exhibit 10.1 on Form 8-K filed on November 8, 2012).
10.27   Third Amendment to Amended and Restated Credit Agreement dated November 2, 2012 (incorporated herein by reference to Exhibit 10.2 on Form 8-K filed on November 8, 2012).
10.28   Securities and Asset Purchase Agreement by and among Registrant and James Loeffelbein and Enutroff dated November 3, 2012 (incorporated herein by reference to Exhibit 10.1 on Form 8-K filed on January 7, 2013).
10.29†   Second Amendment to General Partnership Agreement of Rantoul Partners dated November 27, 2012 (incorporated herein by reference to Exhibit 10.1 on Form 8-K filed on November 29, 2012).
10.30   Amended and Restated Employment Agreement by and among Registrant and Robert G. Watson, Jr. dated December 31, 2012 (incorporated herein by reference to Exhibit 10.1 on Form 8-K filed on January 4, 2013).
10.31   Partial Assignment of Assets by and among Rantoul Partners and Working Interest, LLC, dated December 31, 2012 (incorporated herein by reference to Exhibit 10.1 on Form 8-K filed on January 30, 2013).
 10.32   Fourth Amendment to Amended and Restated Credit Agreement by and among Registrant and Texas Capital Bank dated December 31, 2012 (incorporated herein by reference to Exhibit 10.2 on Form 8-K filed on January 30, 2013).
10.33   First Amendment to Amended & Restated Mortgage Security Agreement, Financing Statement and Assignment of Production by and among Working Interest, LLC and Texas Capital Bank dated December 31, 2012 (incorporated herein by reference to Exhibit 10.3 on Form 8-K filed on January 30, 2013).
10.34   Mortgage, Security Agreement, Financing Statement and Assignment of Production and Revenues by and among Working Interest, LLC and Texas Capital Bank dated December 31, 2012 (incorporated herein by reference to Exhibit 10.4 on Form 8-K filed on January 30, 2013).
10.35   2013 Stock Incentive Plan (incorporated herein by reference to Exhibit 10.1 on Registration Statement on Form S-8 filed on June 12, 2013F
10.36   Fifth Amendment to Amended and Restated Credit Agreement by and among Registrant and Texas Capital Bank, N.A. dated September 30, 2013 (incorporated herein by reference to Exhibit 10.1 on Form 8-K filed October 1, 2013).
10.37   Sixth Amendment to Amended and Restated Credit Agreement by and among Registrant and Texas Capital Bank, N.A. dated November 19, 2013 (filed herewith)
31.1   Certification of Chief Executive and Principal Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
31.2   Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
32.1   Certification of Chief Executive and Principal Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
32.2   Certification of Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

 

† Indicates management contract or compensatory plan or arrangement.

 

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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.

 

ENERJEX RESOURCES, INC.  
(Registrant)  
   
By: /s/ Robert G. Watson, Jr.  
  Robert G. Watson, Jr. Chief Executive Officer  
   
Date: May 13, 2014  

 

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