0001144204-14-018850.txt : 20140328 0001144204-14-018850.hdr.sgml : 20140328 20140328170457 ACCESSION NUMBER: 0001144204-14-018850 CONFORMED SUBMISSION TYPE: 10-K PUBLIC DOCUMENT COUNT: 15 CONFORMED PERIOD OF REPORT: 20131231 FILED AS OF DATE: 20140328 DATE AS OF CHANGE: 20140328 FILER: COMPANY DATA: COMPANY CONFORMED NAME: EnerJex Resources, Inc. CENTRAL INDEX KEY: 0000008504 STANDARD INDUSTRIAL CLASSIFICATION: CRUDE PETROLEUM & NATURAL GAS [1311] IRS NUMBER: 880422242 STATE OF INCORPORATION: NV FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-K SEC ACT: 1934 Act SEC FILE NUMBER: 000-30234 FILM NUMBER: 14726649 BUSINESS ADDRESS: STREET 1: 4040 BROADWAY, SUITE 508 CITY: SAN ANTONIO STATE: TX ZIP: 78209 BUSINESS PHONE: 210-451-5545 MAIL ADDRESS: STREET 1: 4040 BROADWAY, SUITE 508 CITY: SAN ANTONIO STATE: TX ZIP: 78209 FORMER COMPANY: FORMER CONFORMED NAME: MILLENNIUM PLASTICS CORP DATE OF NAME CHANGE: 20000525 FORMER COMPANY: FORMER CONFORMED NAME: AURORA CORP DATE OF NAME CHANGE: 19990825 10-K 1 v371565_10k.htm FORM 10-K
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C.  20549
 
FORM 10-K
 
x
ANNUAL REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 
 
¨
TRANSITION REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 
For the fiscal year-ended December 31, 2013
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
 
(I.R.S. Employer Identification No.)
organization)
 
 
 
 
 
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)
 
Securities registered pursuant to Section 12(b) of the Exchange Act:
 
Name of each exchange on which registered:
 
Securities registered pursuant to Section 12(g) of the Exchange Act: Common Stock, $0.001 par value
 
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.
¨  Yes          x  No
 
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Act.
¨  Yes          x  No
 
Indicate by checkmark 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.    x  Yes          ¨  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).
x  Yes          ¨  No
 
Indicate by checkmark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.    ¨
 
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  x
 
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
Yes  ¨          No  x
 
State the aggregate market value of the voting and non-voting common equity held by non-affiliates computed by reference to the price at which the common equity was last sold, or the average bid and asked price of such common equity, as of the last business day of the registrant's most recently completed second fiscal quarter: approximately $14 million based on a share value of $0.51.
 
Indicate the number of shares outstanding of each of the registrant's classes of common stock, as of the latest practicable date: 109,254,045 shares of common stock, $0.001 par value, outstanding on March 24, 2014.
 
DOCUMENTS INCORPORATED BY REFERENCE
 
List hereunder the following documents if incorporated by reference and the Part of the Form 10-K (e.g., Part I, Part II, etc.) into which the document is incorporated: (1) Any annual report to security holders; (2) Any proxy or information statement; and (3) Any prospectus filed pursuant to Rule 424(b) or (c) under the Securities Act of 1933. The listed documents should be clearly described for identification purposes (e.g., annual report to security holders for fiscal year ended December 24, 1980).
 
NONE.
 
 
 
ENERJEX RESOURCES, INC.
FORM 10-K
TABLE OF CONTENTS
 
 
 
 
Page
PART I
 
 
4
ITEMS 1 AND 2.  
BUSINESS AND PROPERTIES
 
4
ITEM 1A.
RISK FACTORS
 
18
ITEM 1B.
UNRESOLVED STAFF COMMENTS
 
31
ITEM 3.
LEGAL PROCEEDINGS
 
31
PART II
 
 
31
ITEM 5.
MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
 
31
ITEM 6.
SELECTED FINANCIAL DATA
 
32
ITEM 7.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
 
32
ITEM 7A.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
 
36
ITEM 8.
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
 
37
ITEM 9.
CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
 
37
ITEM 9A
CONTROLS AND PROCEDURES
 
37
ITEM 9B.
OTHER INFORMATION
 
37
Part III
 
 
37
ITEM 10.
DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
 
37
ITEM 11.
EXECUTIVE COMPENSATION
 
40
ITEM 12.
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
 
42
ITEM 13.
CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
 
43
ITEM 14.
PRINCIPAL ACCOUNTANT FEES AND SERVICES
 
44
Part IV
 
 
44
ITEM 15.
EXHIBITS, FINANCIAL STATEMENT SCHEDULES
 
44
 
 
2

 
FORWARD-LOOKING STATEMENTS
 
This Annual Report on Form 10-K contains forward-looking statements that involve risks and uncertainties. The statements contained in this document that are not purely historical are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, or the Securities Act, and Section 21E of the Securities Exchange Act of 1934, as amended, or the Exchange Act. Forward-looking statements are statements regarding future events, our future financial performance, and include statements regarding projected operating results. These forward-looking statements are based on current expectations, beliefs, intentions, strategies, forecasts and assumptions and involve a number of risks and uncertainties that could cause actual results to differ materially from those anticipated by these 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. 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. All forward-looking statements included in this document are based on information available to us on the date of this Annual Report on Form 10-K, and we assume no obligation to update any such forward-looking statements, except as may otherwise be required by law.
 
Our actual results could differ materially from those anticipated in these forward-looking statements as a result of certain factors, including those set forth in the "Risk Factors" section in Part I, Item 1A of this Annual Report on Form 10-K and elsewhere in this document. 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 and gas reserves;
· declining local, national and worldwide economic conditions;
· fluctuations in the price of oil and natural gas;
· 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 (Colorado, Western Nebraska, Eastern Kansas and South Texas) 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; and
· changes in U.S. GAAP or in the legal, regulatory and legislative environments in the markets in which we operate.
 
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, Rantoul Partners, 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. We have provided definitions for the oil and gas industry terms used in this report in the "Glossary" beginning on page 15 of this report.
 
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.
 
 
3

 
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.
 
PART I
 
ITEMS 1 AND 2. BUSINESS AND PROPERTIES.
 
Company History
 
We were formerly known as Millennium Plastics Corporation and were incorporated in the State of Nevada on March 31, 1999. We abandoned a prior business plan focusing on the development of biodegradable plastic materials. In August 2006, we acquired Midwest Energy, Inc., a Nevada corporation pursuant to a reverse merger. After the merger, Midwest Energy became a wholly-owned subsidiary, and as a result of the merger the former Midwest Energy stockholders controlled approximately 98% of our outstanding shares of common stock. We changed our name to EnerJex Resources, Inc. in connection with the merger, and in November 2007 we changed the name of Midwest Energy (now our wholly-owned subsidiary) to EnerJex Kansas, Inc. All of our current operations are conducted through EnerJex Kansas, Inc., Black Sable Energy, LLC, and Black Raven Energy, Inc., and our leasehold interests are held in our wholly-owned subsidiaries DD Energy, Inc., Black Sable Energy, LLC, Working Interest, LLC, EnerJex Kansas, Inc., Black Raven Energy, Inc., and in Rantoul Partners in which we held a 75% general partner interest and which we dissolved as of December 31, 2012. 
 
Significant Developments in 2013
 
The following briefly describes our most significant corporate developments occurring in 2013:
 
· On January 24, 2013, the Company entered into a Fourth Amendment to the Amended and Restated Credit Agreement, which was made effective as of December 31, 2012 with Texas Capital Bank, N.A. (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 May 16, 2013, the Company sold two oil and gas leases in non-core operating areas for $439,975 of net proceeds.
 
· On June 6, 2013, the Board of Directors of the Company authorized the increase in the board size from four to five directors, and appointed a new member, Richard E. Menchaca, effective immediately, to fill the vacancy. Mr. Menchaca serves as a member on the Audit and the Governance, Compensation and Nominating Committees of the Board of Directors.
 
· On July 15, 2013, the Company's Audit Committee approved the engagement of L.L. Bradford & Company, LLC (L.L. Bradford) as its independent registered public accounting firm for the Company's fiscal year ending December 31, 2013. Concurrent with its appointment of L.L. Bradford & Company, LLC, the Audit Committee dismissed Weaver Martin & Samyn, LLC, which served as the Company's independent registered public accountant for the fiscal years ended December 31, 2012, and December 31, 2011. There were no disagreements between the Company and Weaver Martin & Samyn, LLC on any matter of accounting principles or practices, financial statement disclosure, or auditing scope or procedures.
 
· On July 23, 2013, EnerJex, BRE Merger Sub, Inc., a Delaware corporation and a wholly owned subsidiary of EnerJex ("Merger Sub"), and Black Raven Energy, Inc. ("Black Raven"), a Nevada corporation, entered into an agreement and plan of merger ("Merger Agreement") pursuant to which Black Raven would be merged with and into Merger Sub and after which Black Raven would be a wholly owned subsidiary of EnerJex.
 
 
 
The following transactions were executed on September 27, 2013 pursuant to the terms of the Merger Agreement (i) shares of capital stock of Black Raven were converted into (a) cash totaling $207,067 and (b) 41,327,516 shares of EnerJex common stock, (ii) all options under the Black Raven option plan were cancelled, and (iii) all warrants or other rights to purchase shares of capital stock of Black Raven were converted into warrants to purchase EnerJex common stock.  The warrants expired December 31, 2013.  No fractional shares of EnerJex common stock were issued in connection with the Merger, and holders of Black Raven common stock were entitled to receive cash in lieu thereof. The board of directors and executive officers of EnerJex remained unchanged as a result of the closing of the Merger.
 
 
4

 
At closing of the transactions contemplated by the Merger Agreement, the previous stockholders of Black Raven owned approximately 38% of the outstanding voting stock of EnerJex and the previous stockholders of EnerJex owned approximately 62% of the outstanding voting stock of EnerJex.
 
· On September 30, 2013, the Company 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 borrower parties; (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 October 1, 2013, we appointed David L. Kunovic to the position of Executive Vice President, Exploration.
 
· We previously 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 we been able to utilize the proceeds from the stock offering to execute our 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 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.
 
· In December 2013, the Company expanded its’ acreage in the Mississippian Project. The expansion acreage is located in Woodson County, Kansas, in close proximity to EnerJex's existing operations. The expansion acreage includes a 90% working interest in 1,280 acres located adjacent to acreage that the Company successfully developed in 2012 and 2013, which is in the early stage of secondary recovery. The Company earned this acreage after achieving certain development milestones related to the adjacent acreage, and it expects to earn another 320 acres in this area after achieving additional development milestones.
 
· On December 30, 2013, the Company entered into a Participation Agreement with MorMeg, LLC and Haas Petroleum, LLC, to drill and develop the Golden Project in Woodson County, Kansas. Pursuant to the Participation Agreement, EnerJex received a 70% working interest in the Golden Project, consisting of approximately 2,330 gross acres. As consideration for entering into the Participation Agreement, the Company agreed to pay $79,555 in cash and agreed to pay 100% of all capital expenditures, up to a maximum of $320,445, associated with drilling and completing three new wells in the Golden Project prior to June 30, 2014.
 
· During 2013, we drilled 22 oil wells and 21 secondary recovery water injection wells in our Mississippian Project and 26 oil wells and 24 secondary recovery water injection wells in our Cherokee Project. Subsequent to the merger with Black Raven Energy, Inc., we recompleted four oil wells in our Adena Field Project.
 
· During 2013, the Company entered into transactions in which it hedged an additional 75,000 barrels (205 bopd) of crude oil in 2014.  Approximately 16,000 barrels were hedged at a price of $90.25 per barrel, 36,000 barrels were hedged at a price of $95.15 per barrel and approximately 23,000 barrels were hedged at a price of $96.00 per barrel.  We also entered into a transaction to hedge approximately 70,000 barrels (190 bopd) of crude oil in 2015 at a price of $88.55 per barrel.
 
Our Business 
 
Our principal strategy is to acquire, develop, explore and produce domestic onshore oil and natural gas properties. Our business activities are currently focused in Kansas, Colorado, Nebraska, and Texas.
 
Our total net proved oil and gas reserves as of December 31, 2013 were 5.8 million barrels of oil equivalents (BOE), of which 77% was oil. Of the 5.8 million BOE of total proved reserves, approximately 49% are classified as proved developed producing, approximately 17% are classified as proved developed non-producing, and approximately 34% are classified as proved undeveloped.
 
The total PV10 (present value) of our proved reserves as of December 31, 2013 was approximately $102 million. "PV10" means the estimated future gross revenue to be generated from the production of proved reserves, net of estimated production and future development and abandonment costs, using prices and costs in effect at the determination date, before income taxes, and without giving effect to non-property related expenses, discounted to a present value using an annual discount rate of 10% in accordance with the guidelines of the SEC. PV10 is a non-GAAP financial measure and generally differs from the standardized measure of discounted future net cash flows, the most directly comparable GAAP financial measure, because it does not include the effects of income taxes on future net revenues. See "Management's Discussion and Analysis of Financial Condition and Results of Operations-Reserves" page 35, for a reconciliation to the comparable GAAP financial measure.
 
Except where noted, the discussion regarding our business in this Annual Report on Form 10-K is as of December 31, 2013.
 
 
5

   
Our Colorado Properties
 
The table below summarizes our current Colorado and Nebraska acreage by project name as of December 31, 2013.
 
Project Name
 
Developed Acreage (1)
 
Undeveloped Acreage
 
Total Acreage
 
 
 
Gross
 
Net (2)
 
Gross
 
Net (2)
 
Gross
 
Net (2)
 
Adena Field
 
 
18,760
 
 
18,760
 
 
-
 
 
-
 
 
18,760
 
 
18,760
 
Niobrara - Colorado (3)
 
 
34,307
 
 
33,866
 
 
15,459
 
 
14,453
 
 
49,766
 
 
48,319
 
Niobrara - Nebraska
 
 
-
 
 
-
 
 
9,525
 
 
9,364
 
 
9,525
 
 
9,364
 
Total
 
 
53,067
 
 
52,626
 
 
24,984
 
 
23,817
 
 
78,051
 
 
76,443
 
 
(1)
Developed acreage includes all acreage that was held by production as of December 31, 2013.
(2)
Net acreage is based on our net working interest as of December 31, 2013.
(3)
Developed acreage includes 8,360 net acres with rights limited to depths below the Niobrara formation.
 
Adena Field Project
 
The Adena Field Project is located in the Denver-Julesburg (“D-J”) Basin in Morgan County, Colorado, where we owned a 100% working interest in 18,760 gross acres as of December 31, 2013. Our acreage position covers the majority of Adena Field, which is the third largest oil field ever discovered in Colorado behind Rangely Field and Wattenberg Field. Adena Field has cumulatively produced 75 million barrels of oil and 125 billion cubic feet of natural gas since its discovery in the early 1950s. Our acreage in this project is currently held-by-production (see “Glossary” on page 15 for definition of held-by-production). The majority of the producing wells in Adena Field were temporarily abandoned or shut-in during the mid-1980’s when oil prices collapsed, and only a small number of wells have been produced since that time.
 
Approximately 124 wells on our acreage are currently shut-in or temporarily abandoned. We have used new data, analysis and engineering to initially identify approximately 90 wells to be reactivated in the J-Sand formation or recompleted uphole in the D-Sand formation. We intend to reactive vintage secondary recovery injection wells simultaneously with the reactivation and/or recompletion of producer wells. Recompletions and reactivations are expected to cost approximately $200,000 to $250,000 per well and are expected to result in stabilized production rates of approximately 10 barrels of oil per day. We have also identified a number of wells on our acreage that are prospective for natural gas production from the J-Sand and D-Sand formations.
 
As of December 31, 2013, the Adena Field Project was producing approximately 150 gross barrels of oil per day from 10 J-Sand wells and 9 D-Sand wells at a depth of approximately 5,500 feet. In addition, multiple wells capable of producing natural gas were shut-in at the end of 2013 pending completion of a new purchase contract that was completed in early 2014. Multiple wells were also in various stages of reactivation and recompletion as of December 31, 2013. We intend to aggressively pursue our reactivation and recompletion strategy in 2014. 
 
Our working interest in our Adena Field Project is subject to a 30% reversionary working interest that will be assigned to an unrelated third party after payout of all acquisition, operating, development, and financing costs including interest (approximately $28 million).
 
6

 
Niobrara – Colorado & Nebraska
 
Our Niobrara Project is located in the northeastern portion of the D-J Basin, where we owned a 97% working interest in approximately 59,291 gross acres as of December 31, 2013. Our acreage is located in Phillips and Sedgwick Counties, Colorado, and Perkins County, Nebraska.
 
Approximately 34,000 acres in this project are held by production and leases on approximately 17,500 acres expire after 2015. As of December 31, 2013, we owned a 100% working interest in 24 Niobrara gas wells and we owned approximately a 6% overriding royalty interest in 180 Niobrara gas wells that are operated by Atlas Resources, LLC. All of these wells are located in Amherst Field in Phillips and Sedgwick Counties, Colorado. As of December 31, 2013, we produced approximately 250 net mcf of natural gas per day from the Niobrara formation at a depth of approximately 2,500 feet. The majority of this production was attributable to our overriding royalty interest in the wells that are operated by Atlas Resources, LLC.
 
Our existing Niobrara acreage was high-graded based on structural features identified through analysis of 114 miles of 2D and 165 square miles (105,000 acres) of 3D seismic data on our original position of 330,000 net acres. We have identified more than 150 highly-ranked Niobrara drilling locations on our acreage based on 3D seismic analysis, which has historically yielded success rates of approximately 90% in this play. Our acreage is well situated with direct access to the Cheyenne Hub market in immediate proximity to the 1,679-mile Rocky Mountain Express pipeline and the 436-mile Trailblazer pipeline.
 
DJ Basin Resource Play Exposure
 
Other operators in the DJ basin have recently permitted, drilled and tested numerous wells on trend with our Niobrara Project acreage and our Adena Field Project acreage. Operators are targeting numerous potential unconventional resource plays in Permian and Pennsylvanian aged carbonates and shales. These plays are in the early stages of exploration and development, and widespread economic success has not yet been established. We continue to monitor these exploration efforts closely and we currently own and control all depths that are prospective for these resource plays under all of our current acreage position.
 
Other
 
We own an average working interest of 9% in 1,011 gross acres located in the Homestead Draw field in Wyoming. As of December 31, 2013, these properties were producing approximately 600 gross mcf of natural gas per day.
 
Our Kansas Properties
 
The table below summarizes our current Kansas acreage by project name as of December 31, 2013.
 
Project Name
 
Developed Acreage(1)
 
Undeveloped Acreage
 
Total Acreage
 
 
 
Gross
 
Net (2)
 
Gross
 
Net (2)
 
Gross
 
Net (2)
 
Mississippian Project
 
 
4,680
 
 
4,084
 
 
1,690
 
 
1,183
 
 
6,370
 
 
5,267
 
Cherokee Project
 
 
2,015
 
 
1,498
 
 
7,774
 
 
6,904
 
 
9,789
 
 
8,402
 
Other
 
 
584
 
 
292
 
 
-
 
 
-
 
 
584
 
 
292
 
Total
 
 
7,279
 
 
5,874
 
 
9,464
 
 
8,087
 
 
16,743
 
 
13,961
 
 
(1)
Developed acreage includes all acreage that was held by production as of December 31, 2013.
(2)
Net acreage is based on our net working interest as of December 31, 2013.
 
Mississippian Project
 
Our Mississippian Project is located in Woodson and Greenwood Counties in Southeast Kansas, where we owned a 90% working interest in 4,040 gross acres and a 70% working interest in 2,330 gross acres as of December 31, 2013. Approximately 73.5% of the gross leased acres in this project are currently held-by-production (see "Glossary" on page 16 for definition of held-by-production).
 
In December 2013, we acquired a 90% working interest in 1,280 gross acres that are adjacent to acreage that we successfully developed in 2012 and 2013. We acquired a 90% working interest in approximately 1,040 gross acres through a purchase option contained in the Joint Development Agreement with Haas Petroleum, LLC and MorMeg, LLC ("Joint Development Agreement"). Per the terms of the Joint Development Agreement, we had the right to exercise a purchase option after achieving certain capital expenditure hurdles on existing acreage. The capital expenditure hurdles were achieved in December 2013 and we exercised the purchase option for the new acreage effective December 30, 2013. In December 2013, we acquired a 90% working interest in two new leases covering approximately 240 gross acres.
 
On December 30, 2013, the Company entered into a Participation Agreement with MorMeg, LLC and Haas Petroleum, LLC, to drill and develop the Golden Project in Woodson County, Kansas. Pursuant to the terms of the Participation Agreement, we acquired a 70% working interest in approximately 2,330 gross acres. We drilled two wells in the Golden Project in January 2014, and both wells were awaiting completion as of March 15, 2014.
 
As of December 31, 2013, our Mississippian Project was producing approximately 200 gross barrels of oil per day from the Mississippian formation at a depth of approximately 1,700 feet. We drilled and completed 22 new oil wells and 21 new water injection wells in this project during 2013. Water injection from some new injector wellbores commenced in late 2012, and new water injection operations were initiated throughout 2013 as additional injection wells were completed. We have experienced an initial production response on some acreage resulting from water injection, and we anticipate continued production increases during 2014 from water injection operations.
 
Cherokee Project
 
Our Cherokee Project is located in Miami and Franklin Counties in Eastern Kansas, where we owned an average working interest of 86% in 9,789 gross acres as of December 31, 2013. As of December 31, 2013, approximately 21% of the gross leased acres in the Cherokee Project were held by production, and numerous low risk development opportunities exist on acreage that is currently undeveloped. A majority of the undeveloped leases have between two and five years (terms refer to leases with contractual extension options) remaining in the primary term and we are not currently facing any material lease expiration issues. As of December 31, 2013, our Cherokee Project was producing approximately 250 gross barrels of oil per day from the Squirrel formation at a depth of approximately 600 feet. We drilled 26 new oil wells and 24 new water injection wells during 2013.
 
 
7

 
Other
 
We own a 50% working interest in 584 gross acres located in Allen County Kansas. As of December 31, 2013, these properties were producing less than 10 gross barrels of oil per day.
 
Our Texas Properties
 
The table below summarizes our current Texas acreage by project name as of December 31, 2013.
  
Project Name
 
Developed Acreage(1)
 
Undeveloped Acreage
 
Total Acreage
 
 
 
Gross
 
Net (2)
 
Gross
 
Net (2)
 
Gross
 
Net (2)
 
El Toro Project
 
458
 
 
183
 
 
-
 
 
-
 
 
458
 
 
183
 
Lonesome Dove Project(3)
 
-
 
 
-
 
 
2,372
 
 
1,186
 
 
2,372
 
 
1,186
 
Total
 
458
 
 
183
 
 
2,372
 
 
1,186
 
 
2,830
 
 
1,369
 
 
(1)
Developed acreage includes all acreage that was held by production as of December 31, 2013.
(2)
Net acreage is based on our net working interest as of December 31, 2013.
(3)
Undeveloped acreage includes a 50% working interest in depths through the Taylor Sand formation and a 10% working interest in depths below the Taylor Sand.
 
El Toro Project
 
Our El Toro Project is located in Atascosa and Frio Counties in South Texas. As of December 31, 2013, we owned a 40% working interest in 458 gross acres. As of December 31, 2013, this project was producing approximately 30 gross barrels of oil per day from the Olmos formation at a depth of approximately 4,500 feet.
 
We have completed 12 wells in the El Toro Project since 2009. While petro-physical data obtained from these wells has been consistent across the project acreage, production results have been inconsistent. The 3 most recent wells completed in this project have been successful, although the costs and time lag associated with drilling and completing them significantly exceeded our expectations. This is a direct result of the high demand and limited supply of services and equipment available in the El Toro Project area due to the Eagle Ford Shale play. As a result of increasing costs in this area, we did not drill any new wells in this project in 2013 and decided to focus 100% of our capital budget on our Kansas and Colorado properties. However, we believe the El Toro project is prospective for horizontal drilling, and we intend to evaluate this potential during 2014.
 
 
8

 
Lonesome Dove Project
 
Our Lonesome Dove Project is located in Lee County in South Texas. As of December 31, 2013, we owned working interests ranging from 10% to 50% in 2,372 gross acres. Our working interests under this acreage are separated by depth. We own approximately 50% of the gross acreage in horizons above approximately 4,500 feet, and we own a 10% working interest in the gross acreage in horizons below approximately 4,500 feet. We have an agreement with the majority owner of the deep rights wherein we would receive a 15% carried working interest in the first deep well drilled on this acreage at no cost to us. Deeper prospective horizons underlying this acreage include the Eagle Ford Shale, the Austin Chalk formation, the Buda formation, and the Pearsall Shale formation. Lease expirations in this project for the vast majority of the acreage range from 2017 to 2018.
 
Our Business Strategy
 
Our principal strategy focuses on the acquisition and development of oil and gas properties that have low production decline rates and offer abundant drilling opportunities with low risk profiles. Our oil and gas operations are in Kansas, Colorado, Nebraska, and Texas. The principal elements of our business strategy are:
 
· Develop Our Existing Properties.   Creating production, cash flow, and reserve growth by developing our extensive inventory of hundreds of drilling locations that we have identified on our existing properties.
 
· Maximize Operational Control.   We seek to operate and maintain a substantial working interest in the majority of our properties. We believe the ability to control our drilling inventory will provide us with the opportunity to more efficiently allocate capital, manage resources, control operating and development costs, and utilize our experience and knowledge of oil and gas field technologies.
 
· Pursue Selective Acquisitions and Joint Ventures.   We believe our local presence in Kansas, Colorado, Nebraska, and Texas makes us well-positioned to pursue selected acquisitions and joint venture arrangements.
 
· Reduce Unit Costs Through Economies of Scale and Efficient Operations.   As we increase our oil and gas production and develop our existing properties, we expect that our unit cost structure will benefit from economies of scale. In particular, we anticipate reducing unit costs by greater utilization of our existing infrastructure over a larger number of wells.
  
Our future financial results will continue to depend on:
 
· our ability to source and evaluate potential projects;
 
· our ability to discover commercial quantities of oil and gas;
 
· the market price for oil and gas;
 
· our ability to implement our exploration and development program, which is in part dependent on the availability of capital resources; and
 
· our ability to cost effectively manage our operations.
 
We cannot guarantee that we will succeed in any of these respects. Further, we cannot know if the price of crude oil and natural gas prevailing at the time of production will be at a level allowing for profitable production, or that we will be able to obtain additional funding at terms favorable to us to increase our capital resources. A detailed description of these and other risks that could materially impact our actual results is in "Risk Factors" under ITEM 1A.
  
 
9

 
Drilling Activity
 
The following table sets forth the results of our drilling activities, including both oil and gas production wells and water injection wells that were drilled and completed during the year ended December 31, 2013 and the year ended December 31, 2012.
 
Drilling Activity
 
 
 
Gross Wells
 
Net Wells (1)
 
Fiscal Year
 
Total
 
Successful
 
Dry
 
Total
 
Successful
 
Dry
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
2012 - Exploratory
 
2
 
-
 
2
 
1.8
 
-
 
1.8
 
2013 - Exploratory
 
-
 
-
 
-
 
-
 
-
 
-
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
2012 - Development
 
227
 
226
 
1
 
172.6
 
171.7
 
0.9
 
2013 - Development
 
93
 
93
 
-
 
75.9
 
75.9
 
-
 
 
(1) Net wells are based on our net working interest at the end of each respective year.
 
The following table sets forth the results of our reactivation and recompletion activities during the fourth quarter ended December 31, 2013 following our acquisition of Black Raven Energy, Inc.
 
Drilling Activity - Recompletion
 
 
 
 
 
 
 
 
 
 
 
Gross Wells
 
Net Wells(1)
 
Fiscal Year 
 
Total
 
Successful
 
Total
 
Successful
 
 
 
 
 
 
 
 
 
 
 
2013 - Recompletion
 
4
 
4
 
4
 
4
 
 
(1) Net wells are based on our net working interest at the end of 2013.
 
Net Production, Average Sales Price and Average Production and Lifting Costs
 
The table below sets forth our net oil and gas production (net of all royalties, overriding royalties and production due to others) for the years ended December 31, 2013 and 2012, the average sales prices, average production costs and direct lifting costs per unit of production.
 
 
 
Year Ended
 
Year Ended
 
 
 
December 31, 2013
 
December 31, 2012
 
Net Production
 
 
 
 
 
 
 
Barrels of Oil Equivalent
 
 
120,634
 
 
96,842
 
Average Sales Prices per BOE
 
$
90.71
 
$
87.74
 
Average Production Cost per BOE(1)
 
$
49.34
 
$
47.95
 
Average Lifting Costs per BOE(2)
 
$
33.95
 
$
32.03
 
 
(1) Production costs include all operating expenses, depreciation, depletion and amortization, lease operating expenses (including price differentials) and all associated taxes. Impairment of oil and gas properties is not included in production costs.
(2) Direct lifting costs do not include impairment expense or depreciation, depletion and amortization, but do include transportation costs, which are paid to our purchasers as a price differential.
 
Results of Oil and Gas Producing Activities
 
The following table shows the results of operations from our oil and gas producing activities from the years ended December 31, 2013 and 2012. Results of operations from these activities have been determined using historical revenues, production costs, depreciation, depletion and amortization of the capitalized costs subject to amortization. General and administrative expenses and interest expense have been excluded from this determination.
 
 
 
Year Ended
 
Year Ended
 
 
 
December 31,
 
December 31,
 
 
 
2013
 
2012
 
Production revenues
 
$
10,942,270
 
$
8,496,519
 
Production costs
 
 
(4,095,850)
 
 
(3,102,321)
 
Depreciation, depletion and amortization
 
 
(1,691,008)
 
 
(1,541,069)
 
Results of operations for producing activities
 
$
5,155,412
 
$
3,853,129
 
 
 
10

 
Active Wells
 
The following table sets forth the number of wells in which we owned a working interest that were actively producing oil and gas or actively injecting water as of December 31, 2013.
 
 
 
Active
 
Project
 
Gross
 
Net  (1)
 
Crude Oil
 
 
 
 
 
El Toro Project
 
12
 
4.8
 
Mississippian Project
 
216
 
194.4
 
Cherokee Project
 
596
 
443.2
 
Adena Field Project
 
38
 
38.0
 
Other
 
37
 
32.6
 
Total Oil
 
899
 
713.0
 
 
 
 
 
 
 
Natural Gas
 
 
 
 
 
Niobrara Project
 
21
 
21.0
 
Other
 
36
 
3.2
 
Total Gas
 
57
 
24.2
 
(1) Net wells are based on our net working interest as of December 31, 2013.
 
Reserves
 
Proved Reserves
 
The estimated total PV10 (present value) of our proved reserves as of December 31, 2013 was $102.4 million, compared to $60.8 million as of December 31, 2012. Our total net proved oil and gas reserves as of December 31, 2013 were 5.8 million BOE (77% oil), compared to 2.9 million BOE as of December 31, 2012. Of the 5.8 million net BOE of total proved reserves at December 31, 2013, approximately 49% are classified as proved developed producing, approximately 17% are classified as proved developed non-producing, and approximately 34% are classified as proved undeveloped. See "Glossary" on page 17 for our definition of PV10.
 
The estimated PV10 of the 5.8 million BOE is set forth in the following table. The PV10 is calculated using an average net oil price of $87.89 per barrel, an average net natural gas price of $2.85 per mcf and an average natural gas liquids price of $18.73 per barrel, and by applying an annual discount rate of 10% to the forecasted future net cash flow.  
 
Summary of Proved Oil and Gas Reserves
a
s of December 31, 2013
 
 
 
Gross
 
Net
 
PV10 (2)
 
Proved Reserves Category
 
BOE
 
BOE  (1)
 
(before tax)
 
Proved, Developed
 
5,801,000
 
3,824,800
 
74,234,300
 
Proved, Undeveloped
 
2,664,700
 
1,979,800
 
28,177,500
 
Total Proved
 
8,465,700
 
5,804,600
 
102,411,800
 
(1) Net BOE is based upon our net revenue interest
(2)
See "Management's Discussion and Analysis of Financial Condition and Results of Operations-Reserves" page 34 for a reconciliation to the comparable GAAP financial measure.
 
Oil and Gas Reserves Reported to Other Agencies
 
We did not file any estimates of total proved net oil and gas reserves with, or include such information in reports to any federal authority or agency, other than the SEC, during the year ended December 31, 2013.
 
Title to Properties
 
We believe that we have satisfactory title to or rights in all of our producing properties. As is customary in the oil and gas industry, minimal investigation of title is made at the time of acquisition of undeveloped properties. In most cases, we investigate title and obtain title opinions from counsel or have title reviewed by professional landmen only when we acquire producing properties or before we begin drilling operations. However, any acquisition of producing properties without obtaining title opinions is subject to a greater risk of title defects.
 
Our properties are subject to customary royalty interests, liens under indebtedness, liens incident to operating agreements and liens for current taxes and other burdens, including mineral encumbrances and restrictions. Further, our debt is secured by liens substantially on all of our assets. These burdens have not materially interfered with the use of our properties in the operation of our business to date, though there can be no assurance that such burdens will not materially impact our operations in the future.
 
Sale of Oil and Gas
 
We do not intend to refine our oil production. We expect to sell all or most of our production to a small number of purchasers in a manner consistent with industry practices at prevailing rates by means of long-term and short-term sales contracts, some of which may have fixed price components. In 2013, we sold oil to Coffeyville Resources, Plains Marketing LP, and Sunoco, Inc. on a month-to-month basis (i.e., without a long-term contract). We sold our natural gas to United Energy Trading and Western Operating Company on a month-to-month basis. We also have an ISDA master agreement and a fixed price swap with BP and with Cargill through December 31, 2015. Under current conditions, we should be able to find other purchasers, if needed. All of our produced oil is held in tank batteries. Each respective purchaser picks up the oil from our tank batteries and transports it by truck to refineries. In addition, our Board of Directors has implemented a crude oil and gas hedging strategy that will allow management to hedge the majority of our net production in an effort to mitigate our exposure to changing oil and natural gas prices in the intermediate term.
 
 
11

 
Secondary Recovery and Other Production Enhancement Strategies
 
When an oil field is first produced, the oil typically is recovered as a result of natural pressure within the producing formation, often assisted by pumps of various types. The only natural force present to move the crude oil to the wellbore is the pressure differential between the higher pressure in the formation and the lower pressure in the wellbore. At the same time, there are many factors that act to impede the flow of crude oil, depending on the nature of the formation and fluid properties, such as pressure, permeability, viscosity and water saturation. This stage of production is referred to as "primary production”, which typically only recovers 5% to 15% of the crude oil originally in place in a producing formation.
 
Production from oil fields can often be enhanced through the implementation of "secondary recovery", also known as waterflooding, which is a method in which water is injected into the reservoir through injector wells in order to maintain or increase reservoir pressure and push oil to the adjacent producing wellbores. We utilize waterflooding as a secondary recovery technique for the majority of our oil properties in Kansas, even in the early stages of production and we use a secondary recovery technique in parts of the Adena Field Project in Colorado.
 
As a waterflood matures over time, the fluid produced contains increasing amounts of water and decreasing amounts of oil. Surface equipment is used to separate the produced oil from water, with the oil going to holding tanks for sale and the water being re-injected into the oil reservoir.
 
In addition, we may utilize 3D seismic analysis, horizontal drilling, and other technologies and production techniques to improve drilling results and oil recovery, and to ultimately enhance our production and returns. We also believe use of such technologies and production techniques in exploring for, developing, and exploiting oil properties will help us reduce drilling risks, lower finding costs and provide for more efficient production of oil from our properties.
 
Markets and Marketing
 
The oil and gas industry has experienced dramatic price volatility in recent years. As a commodity, global oil prices respond to macro-economic factors affecting supply and demand. In particular, world oil prices have risen and fallen in response to political unrest and supply uncertainty in the Middle East, and changing demand for energy in rapidly growing economies, notably India and China. North American prospects have become more attractive as oil prices have risen and as efforts to stimulate the US economy and reduce dependence on foreign oil have increased. Escalating conflicts in the Middle East and the ability of OPEC to control supply and pricing are some of the factors impacting the availability of global supply. As a commodity, natural gas prices respond mainly to regional supply and demand imbalances. Factors that affect the supply side include production of natural gas, levels of natural gas imports and fluctuations in underground storage. Factors that affect the demand side include peak demand brought on by winter heating and summer cooling requirements and increasing demand from the petrochemical industry for their produced products such as plastics, fertilizers, paints, soaps etc. The costs of steel and other products used to construct drilling rigs and pipeline infrastructure, as well as, drilling and well-servicing rig rates, are impacted by the commodity price volatility.
 
Our market is affected by many factors beyond our control, such as the availability of other domestic production, commodity prices, the proximity and capacity of oil and gas pipelines, and general fluctuations of global and domestic supply and demand. We have currently entered into month-to-month sales contracts with Coffeeville Resources, Plains Marketing LP, and Sunoco, Inc., United Energy Trading, and Western Operating Company and we do not anticipate difficulty in finding additional sales opportunities, as and when needed.
 
Oil and gas sales prices are negotiated based on factors such as the spot price or posted price for oil and gas, price regulations, regional price variations, hydrocarbon quality, distances from wells to pipelines, well pressure, and estimated reserves. Many of these factors are outside our control. Oil and gas prices have historically experienced high volatility, related in part to ever-changing perceptions within the industry of future supply and demand.
 
Competition
 
The oil and gas industry is intensely competitive and we must compete against larger companies that may have greater financial and technical resources than we do and substantially more experience in our industry. These competitive advantages may better enable our competitors to sustain the impact of higher exploration and production costs, oil and gas price volatility, productivity variances between properties, overall industry cycles and other factors related to our industry. Their advantage may also negatively impact our ability to acquire prospective properties, develop reserves, attract and retain quality personnel and raise capital.
 
Research and Development Activities
 
We have not spent a material amount of time or money on research and development activities in the last two years.
 
 
12

 
Governmental Regulations
 
Our oil and gas exploration, production and related operations, when developed, are subject to extensive rules and regulations promulgated by federal, state, tribal and local authorities and agencies that impose requirements relating to the exploration and production of oil and natural gas. For example, laws and regulations often address conservation matters, including provisions for the unitization or pooling of oil and gas properties, the spacing, plugging and abandonment of wells, rates of production, water discharge, prevention of waste, and other matters. Prior to drilling, we are often required to obtain permits for drilling operations, drilling bonds and file reports concerning operations. Failure to comply with any such rules and regulations can result in substantial penalties. Moreover, laws and regulations may place burdens from previous operations on current lease owners that can be significant.
 
The public attention on the production of oil and gas will most likely increase the regulatory burden on our industry and increase the cost of doing business, which may affect our profitability. Although we believe we are currently in substantial compliance with all applicable laws and regulations, because such rules and regulations are frequently amended or reinterpreted, we are unable to predict the future cost or impact of complying with such laws. Significant expenditures may be required to comply with governmental laws and regulations and may have a material adverse effect on our financial condition and results of operations.
 
The price we may receive from the sale of oil and gas will be affected by the cost of transporting products to markets. Effective January 1, 1995, FERC implemented regulations establishing an indexing system for transportation rates for oil and gas pipelines, which, generally, would index such rates to inflation, subject to certain conditions and limitations. We are not able to predict with certainty the effect, if any, of these regulations on our intended operations. However, the regulations may increase transportation costs or reduce well head prices for oil and natural gas.
 
Environmental Matters
 
Our operations and properties are subject to extensive and changing federal, state and local laws and regulations relating to environmental protection, including the generation, storage, handling, emission, transportation and discharge of materials into the environment, and relating to safety and health. The recent trend in environmental legislation and regulation generally is toward stricter standards, and this trend will likely continue.
 
These laws and regulations may:
 
· require the acquisition of a permit or other authorization before construction or drilling commences and for certain other activities;
 
· limit or prohibit construction, drilling and other activities on certain lands lying within wilderness and other protected areas; and
 
· impose substantial liabilities for pollution resulting from its operations, or due to previous operations conducted on any leased lands.
 
The permits required for our operations may be subject to revocation, modification and renewal by issuing authorities. Governmental authorities have the power to enforce their regulations, and violations are subject to fines or injunctions, or both. In the opinion of management, we are in substantial compliance with current applicable environmental laws and regulations, and have no material commitments for capital expenditures to comply with existing environmental requirements. Nevertheless, changes in existing environmental laws and regulations or in interpretations thereof could have a significant impact on us, as well as the oil and gas industry in general.
 
The Comprehensive Environmental, Response, Compensation, and Liability Act, as amended ("CERCLA"), and comparable state statutes impose strict, joint and several liability on owners and operators of sites and on persons who disposed of or arranged for the disposal of "hazardous substances" found at such sites. It is not uncommon for the neighboring land owners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. The Federal Resource Conservation and Recovery Act, as amended ("RCRA"), and comparable state statutes govern the disposal of "solid waste" and "hazardous waste" and authorize the imposition of substantial fines and penalties for noncompliance. Although CERCLA currently excludes petroleum from its definition of "hazardous substance," state laws affecting our operations may impose clean-up liability relating to petroleum and petroleum related products. In addition, although RCRA classifies certain oil and gas field wastes as "non-hazardous”, such exploration and production wastes could be reclassified as hazardous wastes thereby making such wastes subject to more stringent handling and disposal requirements.
 
The Federal Water Pollution Control Act of 1972, as amended ("Clean Water Act"), and analogous state laws impose restrictions and controls on the discharge of pollutants into federal and state waters. These laws also regulate the discharge of storm water in process areas. Pursuant to these laws and regulations, we are required to obtain and maintain approvals or permits for the discharge of wastewater and storm water and develop and implement spill prevention, control and countermeasure plans, also referred to as "SPCC plans”, in connection with on-site storage of greater than threshold quantities of oil and gas. The EPA issued revised SPCC rules in July 2002 whereby SPCC plans are subject to more rigorous review and certification procedures. We believe that our operations are in substantial compliance with applicable Clean Water Act and analogous state requirements, including those relating to wastewater and storm water discharges and SPCC plans.
 
 
13

 
The Endangered Species Act, as amended ("ESA"), seeks to ensure that activities do not jeopardize endangered or threatened animal, fish and plant species, nor destroy or modify the critical habitat of such species. Under ESA, exploration and production operations, as well as actions by federal agencies, may not significantly impair or jeopardize the species or its habitat. ESA provides for criminal penalties for willful violations of the Act. Other statutes that provide protection to animal and plant species and that may apply to our operations include, but are not necessarily limited to, the Fish and Wildlife Coordination Act, the Fishery Conservation and Management Act, the Migratory Bird Treaty Act and the National Historic Preservation Act. Although we believe that our operations will be in substantial compliance with such statutes, any change in these statutes or any reclassification of a species as endangered could subject us to significant expenses to modify our operations or could force us to discontinue certain operations altogether.
 
Personnel
 
We currently have 35 full-time employees, including field personnel. As production and drilling activities increase or decrease, we may have to continue to adjust our technical, operational and administrative personnel as appropriate. We are using and will continue to use independent consultants and contractors to perform various professional services, particularly in the area of land services, reservoir engineering, geology, drilling, water hauling, pipeline construction, well design, well-site monitoring and surveillance, permitting and environmental assessment. We believe that this use of third-party service providers may enhance our ability to contain operating and general expenses, and capital costs.
 
Facilities
 
We currently lease our executive offices at 4040 Broadway, Suite 508, San Antonio, Texas 78209, under a lease which expires August 2016.   We also have a field offices located at 2038 South Princeton St., Suite B, Ottawa, Kansas, 66067 and 1331 17th Street, Suite 350, Denver, Colorado 80202. We had corporate office space under lease at 27 Corporate Woods, Suite 350, 10975 Grandview Drive, Overland Park, Kansas  66210 that expired September 30, 2013.
 
 
14

 
GLOSSARY
 
Term
 
Definition
 
 
 
Barrel (Bbl)
 
The standard unit of measurement of liquids in the petroleum industry, it contains 42 U.S. standard gallons. Abbreviated to "bbl".
 
 
 
Basin
 
A depression in the crust of the Earth, caused by plate tectonic activity and subsidence, in which sediments accumulate. Sedimentary basins vary from bowl-shaped to elongated troughs. Basins can be bounded by faults. Rift basins are commonly symmetrical; basins along continental margins tend to be asymmetrical. If rich hydrocarbon source rocks occur in combination with appropriate depth and duration of burial, then a petroleum system can develop within the basin.
 
 
 
BOE
 
Abbreviation for a barrel of oil equivalent and is a term used to summarize the amount of energy that is equivalent to the amount of energy found in a barrel of crude oil. On a BTU basis 6,000 cubic feet of natural gas is the energy equivalent to one barrel of crude oil. A conversion ratio of 6:1 is used to convert natural gas measured in thousands of cubic feet into an equivalent barrel of oil.
 
BOPD
 
 
Abbreviation for barrels of oil per day, a common unit of measurement for volume of crude oil. The volume of a barrel is equivalent to 42 U.S. standard gallons.
 
 
 
Carried Working Interest
 
The owner of this type of working interest in the drilling of a well incurs no capital contribution requirement for drilling or completion costs associated with a well and, if specified in the particular contract, may not incur capital contribution requirements beyond the completion of the well.
 
 
 
Completion/Completing
 
The activities and methods of preparing a well for the production of oil and gas or for other purposes such as injection.
 
 
 
Development
 
The phase in which a proven oil or natural gas field is brought into production by drilling development wells.
 
 
 
Development Drilling
 
Wells drilled during the Development phase.
 
 
 
Division Order
 
A directive signed by all owners verifying to the purchaser or operator of a well the decimal interest of production owned by the royalty owner and other working interest owners. The Division Order generally includes the decimal interest, a legal description of the property, the operator's name, and several legal agreements associated with the process. Completion of this step generally precedes placing the royalty owner or working interest owner on pay status to begin receiving revenue payments.
 
 
 
Drilling
 
Act of boring a hole through which oil and natural gas may be produced.
 
 
 
Dry Wells
 
A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes.
 
 
 
Exploration
 
The phase of operations which covers the search for oil and gas generally in unproven or semi-proven territory.
 
 
 
Exploratory Drilling
 
Drilling of a relatively high percentage of properties which are unproven.
 
 
 
Farm Out
 
An arrangement whereby the owner of a lease assigns all or some portion of the lease or licenses to another company for undertaking exploration or development activity.
 
 
 
Field
 
An area consisting of a single reservoir or multiple reservoirs all grouped on, or related to, the same individual geological structural feature or stratigraphic condition. The field name refers to the surface area, although it may refer to both the surface and the underground productive formations.
 
 
 
Fixed Price Swap
 
A derivative instrument that exchanges or "swaps" the "floating" or daily price of a specified volume of oil or natural gas over a specified period, for a fixed price for the specified volume over the same period (typically three months or longer).
 
 
 
Gathering Line/System
 
Pipelines and other facilities that transport oil or gas from wells and bring it by separate and individual lines to a central delivery point for delivery into a transmission line or mainline.
 
 
 
Gross Acre
 
The number of acres in which the Company owns any working interest.
 
 
15

 
Gross Producing Well
 
A well in which a working interest is owned and is producing oil or gas. The number of gross producing wells is the total number of wells producing oil or gas in which a working interest is owned.
 
 
 
 
Gross Well
 
A well in which a working interest is owned. The number of gross wells is the total number of wells in which a working interest is owned.
 
 
 
Held-By-Production (HBP)
 
Refers to an oil and gas property under lease, in which the lease continues to be in force, because of production from the property.
 
 
 
Horizontal drilling
 
A drilling technique used in certain formations where a well is drilled vertically to a certain depth and then turned and drilled horizontally. Horizontal drilling allows the wellbore to follow the desired formation.
 
 
 
In-Fill Wells
 
In-fill wells refers to wells drilled between established producing wells; a drilling program to reduce the spacing between wells in order to increase production and recovery of in-place hydrocarbons.
 
 
 
Oil and Gas Lease
 
A legal instrument executed by a mineral owner granting the right to another to explore, drill, and produce subsurface oil and gas. An oil and gas lease embodies the legal rights, privileges and duties pertaining to the lessor and lessee.
 
 
 
Lifting Costs
 
The expenses of producing oil and gas from a well. Lifting costs are the operating costs of the wells including the gathering and separating equipment. Lifting costs do not include the costs of drilling and completing the wells or transporting the oil and gas.
 
 
 
MCF
 
An abbreviation for one thousand cubic feet of natural gas.
 
 
 
Net Acres
 
Determined by multiplying gross acres by the working interest that the Company owns in such acres.
 
 
 
Net Producing Wells
 
The number of producing wells multiplied by the working interest in such wells.
 
 
 
Net Revenue Interest
 
A share of production revenues after all royalties, overriding royalties and other non-operating interests have been taken out of production for a well(s).
 
 
 
Operator
 
A person, acting for itself, or as an agent for others, designated to conduct the operations on its or the joint interest owners' behalf.
 
 
 
Overriding Royalty
 
Ownership in a percentage of production or production revenues, free of the cost of production, created by the lessee, company and/or working interest owner and paid by the lessee, company and/or working interest owner out of revenue from the well.
 
 
 
Pooled Unit
 
A term frequently used interchangeably with "Unitization" but more properly used to denominate the bringing together of small tracts sufficient for the granting of a well permit under applicable spacing rules.
 
 
 
Probable Reserves
 
Probable reserves are additional reserves that are less certain to be recovered than proved reserves but which, together with Proved reserves, are as likely as not to be recovered.
 
 
 
Proved Developed Reserves
 
Proved reserves that can be expected to be recovered from existing wells with existing equipment and operating methods. This definition of proved developed reserves has been abbreviated from the applicable definitions contained in Rule 4-10(a)(2-4) of Regulation S-X.
 
 
 
Proved Developed Non-Producing
 
Proved developed reserves expected to be recovered from zones behind casings in existing wells or from future production increases resulting from the effects of waterflood operations.
 
 
 
Proved Reserves
 
Proved reserves are estimated quantities of crude oil and gas which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic, operating methods, and government regulations prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.
 
 
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Proved Undeveloped Reserves
 
Proved undeveloped reserves are the portion of proved reserves which can be expected to be recovered from new wells on undrilled proved acreage, or from existing wells where a relatively major expenditure is required for completion. This definition of proved undeveloped reserves has been abbreviated from the applicable definitions contained in Rule 4-10(a)(2-4) of Regulation S-X.
 
 
 
PV10
 
PV10 means the estimated future gross revenue to be generated from the production of proved reserves, net of estimated production and future development and abandonment costs, using prices and costs in effect at the determination date, before income taxes, and without giving effect to non-property related expenses, discounted to a present value using an annual discount rate of 10% in accordance with the guidelines of the SEC. PV10 is a non-GAAP financial measure.  See "Management's Discussion and Analysis of Financial Condition and Results of Operations-Reserves" on page 35 for a reconciliation to the comparable GAAP financial measure.
 
 
 
Reactivation
 
After the initial completion of a well, the action and techniques of reentering the well and redoing or repairing the original completion to restore the well’s productivity.
 
 
 
Recompletion
 
Completion of an existing well for production from one formation or reservoir to another formation or reservoir that exists behind casing of the same well.
 
 
 
Reservoir
 
The underground rock formation where oil and gas has accumulated. It consists of a porous rock to hold the oil and gas, and a cap rock that prevents its escape.
 
 
 
Reservoir Pressure
 
The pressure at the face of the producing formation when the well is shut-in. It equals the shut-in pressure at the wellhead plus the weight of the column of oil and gas in the well.
 
 
 
Secondary Recovery
 
The stage of hydrocarbon production during which an external fluid such as water or natural gas is injected into the reservoir through injection wells located in rock that has fluid communication with production wells. The purpose of secondary recovery is to maintain reservoir pressure and to displace hydrocarbons toward the wellbore.  The most common secondary recovery techniques are natural gas injection and waterflooding. Normally, natural gas is injected into the natural gas cap and water is injected into the production zone to sweep oil and gas from the reservoir.  A pressure-maintenance program can begin during the primary recovery stage, but it is a form of enhanced recovery.
 
 
 
Shut-In Well
 
A well which is capable of producing but is not presently producing. Reasons for a well being shut-in may be lack of equipment, market or other.
 
 
 
Stock Tank Barrel or STB
 
A stock tank barrel of oil and gas is the equivalent of 42 U.S. Gallons at 60 degrees Fahrenheit.
 
 
 
Undeveloped Acreage
 
Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and gas regardless of whether such acreage contains proved reserves.
 
 
 
Unitize, Unitization
 
When owners of oil and gas reservoir pool their individual interests in return for an interest in the overall unit.
 
 
 
Waterflood
 
The injection of water into an oil and gas reservoir to "push" additional oil and gas out of the reservoir rock and into the wellbores of producing wells. Typically a secondary recovery process.
 
 
 
Water Injection Wells
 
A well in which fluids are injected rather than produced, the primary objective typically being to maintain or increase reservoir pressure, often pursuant to a waterflood.
 
Water Supply Wells
 
A well in which fluids are being produced for use in a water injection well.
 
 
 
Wellbore
 
A borehole; the hole drilled by the bit. A wellbore may have casing in it or it may be open (uncased); or part of it may be cased, and part of it may be open. Also called a borehole or hole.
 
 
 
Working Interest
 
An interest in an oil and gas lease entitling the owner to receive a specified percentage of the proceeds of the sale of oil and gas production or a percentage of the production, but requiring the owner of the working interest to bear the cost to explore for, develop and produce such oil and gas.
 
 
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ITEM 1A. RISK FACTORS.
 
In the course of conducting our business operations, we are exposed to a variety of risks that are inherent to the oil and gas industry. The following discusses some of the key inherent risk factors that could affect our business and operations. Other factors besides those discussed below or elsewhere in this report also could adversely affect our business and operations, and these risk factors should not be considered a complete list of potential risks that may affect us.
 
Declining economic conditions and worsening geopolitical conditions could negatively impact our business.
 
Our operations are affected by local, national and worldwide economic conditions. While the financial markets have generally strengthened over the last 5 years, bearish economic pressures remain as evidenced by a weak domestic labor market and the continued economic stimulus programs executed by the United States Federal Reserve. The consequences of uncertain economies and volatile financial and emerging markets may result in a lower level of economic activity and uncertainty regarding energy prices and the capital and commodity markets.
 
In addition, actual and attempted terrorist attacks in the United States, Middle East, Southeast Asia and Europe, and war or armed hostilities in the Middle East, Iran, North Korea or elsewhere, or the fear of such events, could exacerbate the volatility and disruption to the financial markets and economy. The situation in Iraq and Afghanistan, tension over Iran's nuclear program, and more recently the events in Libya, Ukraine and Syria highlight the instability of long-standing regimes which in turn has led to further uncertainty in the worldwide economy.
 
While the ultimate outcome and impact of the current economic conditions cannot be predicted, a lower level of economic activity might result in a decline in energy consumption, which may materially adversely affect the price of oil and gas, our revenues, liquidity and future growth.  Instability in the financial markets, as a result of recession or otherwise, also may affect the cost of capital and our ability to raise capital.
 
We have sustained losses in the past, and our future profitability is subject to many risks inherent in the oil and gas production industry.
 
Our prospects must be considered in light of the risks, expenses and difficulties frequently encountered in establishing and maintaining a business in the oil and gas industry. There is nothing conclusive at this time on which to base an assumption that our business operations will prove to be successful or that we will be able to operate profitably. Our future operating results will depend on many factors, including:
 
· the future prices of oil and gas;
· our ability to raise adequate capital;
· success of our development and exploration efforts;
· our ability to manage our operations cost effectively
· effects of our hedging strategies;
· demand for oil and gas;
· the level of our competition;
· our ability to attract and maintain key management, employees and operators;
· transportation and processing fees on our facilities;
· fuel conservation measures;
· alternate fuel requirements or advancements;
· government regulation and taxation;
· technical advances in fuel economy and energy generation devices; and
· our ability to efficiently explore, develop and produce sufficient quantities of marketable oil and gas in a highly competitive and speculative environment while maintaining and controlling costs.
 
To achieve profitable operations, we must, alone or with others, successfully execute on the factors stated above, along with continually developing ways to enhance our production efforts. Despite our best efforts, we may not be successful in our development efforts or obtain required regulatory approvals. There is a possibility that some of our wells may never produce oil and gas in sustainable or economic quantities.
 
We will need additional capital in the future to finance our planned growth, which we may not be able to raise or may be available only on terms unfavorable to us or our stockholders, which may result in our inability to fund our working capital requirements and harm our operational results.
 
We have and expect to continue to have substantial capital expenditure and working capital needs. We will need to rely on cash flow from operations and borrowings under our Credit Facility or raise additional cash to fund our operations, pay outstanding long-term debt, fund our anticipated reserve replacement needs and implement our growth strategy, or respond to competitive pressures and/or perceived opportunities, such as investment, acquisition, exploration, work-over and development activities.
 
 
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If low oil and gas prices, operating difficulties, constrained capital sources or other factors, many of which are beyond our control, cause our revenues or cash flows from operations to decrease, we may be limited in our ability to spend the capital necessary to complete our development, production exploitation and exploration programs. If our resources or cash flows do not satisfy our operational needs, we will require additional financing, in addition to anticipated cash generated from our operations, to fund our planned growth. Additional financing might not be available on terms favorable to us, or at all. If adequate funds were not available or were not available on acceptable terms, our ability to fund our operations, take advantage of opportunities, develop or enhance our business or otherwise respond to competitive pressures would be significantly limited. In such a capital restricted situation, we may curtail our acquisition, drilling, development, and exploration activities or be forced to sell some of our assets on an untimely or unfavorable basis.  Our current plans to address a drop in crude oil prices are to maintain hedges covering a portion of our expected future oil and gas production and to reduce both capital and operating expenditures to a level equal to or below cash flow from operations.  However, our plans may not be successful in improving our results of operations and liquidity.
 
If we raise additional funds through the issuance of equity or convertible debt securities, the percentage ownership of our stockholders would be reduced, and these newly issued securities might have rights, preferences or privileges senior to those of the securities held by our existing stockholders.
 
Oil and gas prices are volatile. Future volatility may cause negative change in cash flows which may result in our inability to cover our operating or capital expenditures.
 
Our future revenues, profitability, future growth and the carrying value of our properties depend substantially on the prices we may realize for our oil and gas production. Our realized prices may also affect the amount of cash flow available for operating or capital expenditures and our ability to borrow and raise additional capital.
 
Oil and gas prices are subject to wide fluctuations in response to relatively minor changes in or perceptions regarding supply and demand. Historically, the markets for oil and gas have been volatile, and they are likely to continue to be volatile in the future. Among the factors that can cause this volatility are:
 
· commodities speculators;
· local, national and worldwide economic conditions;
· worldwide or regional demand for energy, which is affected by economic conditions;
· the domestic and foreign supply of oil and gas;
· weather conditions;
· natural disasters;
· acts of terrorism;
· domestic and foreign governmental regulations and taxation;
· political and economic conditions in oil and gas producing countries, including those in the Middle East and South America;
· impact of the U.S. dollar exchange rates on oil and gas prices;
· the availability of refining capacity;
· actions of the Organization of Petroleum Exporting Countries, or OPEC, and other state controlled oil and gas companies relating to oil and gas price and production controls; and
· the price and availability of other fuels.
 
It is impossible to predict oil and gas price movements with certainty. A drop in oil and gas prices may not only decrease our future revenues on a per unit basis but also may reduce the amount of oil and gas that we can produce economically. A substantial or extended decline in oil and gas prices may materially and adversely affect our future business enough to force us to cease our business operations. In addition, our reserves, financial condition, results of operations, liquidity and ability to finance and execute planned capital expenditures will also suffer in such a price decline.
 
Approximately 34% of our total proved reserves as of December 31, 2013 consist of undeveloped reserves, and those reserves may not ultimately be developed or produced.
 
Our estimated total proved PV10 (present value) before tax of reserves as of December 31, 2013 was $102.4 million, versus $60.8 million as of December 31, 2012. Of the 5.8 million BOE of total proved reserves, approximately 49% are classified as proved developed producing, approximately 17% are classified as proved developed non-producing, and approximately 34% are classified as proved undeveloped. 
 
Assuming we can obtain adequate capital resources, we plan to develop and produce all of our proved reserves, but ultimately some of these reserves may not be developed or produced. Furthermore, not all of our undeveloped or developed non-producing reserves may be produced in the time periods we have planned, at the costs we have budgeted, or at all.
 
 
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Because we face uncertainties in estimating proved recoverable reserves, you should not place undue reliance on such reserve information.
 
Our reserve estimates and the future net cash flows attributable to those reserves at December 31, 2013 were prepared by MHA Petroleum Consultants LLC, an independent petroleum consultant.  There are numerous uncertainties inherent in estimating quantities of proved reserves and cash flows from such reserves, including factors beyond our control and the control of these independent consultants and engineers. Reserve engineering is a subjective process of estimating underground accumulations of oil and gas that can be economically extracted, which cannot be measured in an exact manner. The accuracy of an estimate of quantities of reserves, or of cash flows attributable to these reserves, is a function of the available data, assumptions regarding future oil and gas prices, expenditures for future development and exploitation activities, and engineering and geological interpretation and judgment. Reserves and future cash flows may also be subject to material downward or upward revisions based upon production history, development and exploitation activities and oil and gas prices. Actual future production, revenue, taxes, development expenditures, operating expenses, quantities of recoverable reserves and value of cash flows from those reserves may vary significantly from the assumptions and estimates in our reserve reports. Any significant variance from these assumptions to actual figures could greatly affect our estimates of reserves, the economically recoverable quantities of oil and gas attributable to any particular group of properties, the classification of reserves based on risk of recovery, and estimates of the future net cash flows. In addition, reserve engineers may make different estimates of reserves and cash flows based on the same available data. The estimated quantities of proved reserves and the discounted present value of future net cash flows attributable to those reserves included in this report were prepared by MHA Petroleum Consultants LLC in accordance with rules of the Securities and Exchange Commission, or SEC, and are not intended to represent the fair market value of such reserves.
 
The present value of future net cash flows from our proved reserves is not necessarily the same as the current market value of our estimated reserves. We base the estimated discounted future net cash flows from our proved reserves on prices and costs. However, actual future net cash flows from our oil and gas properties also will be affected by factors such as:
 
· geological conditions;
· assumptions governing future oil and gas prices;
· amount and timing of actual production;
· availability of funds;
· future operating and development costs;
· actual prices we receive for oil and gas;
· changes in government regulations and taxation; and
· capital costs of drilling new wells
 
The timing of both our production and our incurrence of expenses in connection with the development and production of our properties will affect the timing of actual future net cash flows from proved reserves, and thus their actual present value. In addition, the 10% discount factor we use when calculating discounted future net cash flows may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with our business or the oil and gas industry in general.
 
The differential between the New York Mercantile Exchange, or NYMEX, or other benchmark price of oil and gas and the wellhead price we receive could have a material adverse effect on our results of operations, financial condition and cash flows.
 
The prices that we receive for our oil and gas production in Kansas are typically based on a discount to the relevant benchmark prices, such as NYMEX, that are used for calculating hedge positions. In Texas, the prices that we receive for our oil production are currently based on a premium to NYMEX. In Colorado, the prices that we receive for our oil production are based upon a discount to NYMEX and the prices we receive for our natural gas production is based upon local market conditions but generally we receive a discount to Henry Hub. The difference between the benchmark price and the price we receive is called a differential.  We cannot accurately predict oil and gas differentials. In recent years for example, production increases from competing Canadian and Rocky Mountain producers, in conjunction with limited refining and pipeline capacity from the Rocky Mountain area, have gradually widened this differential. Recent economic conditions, including volatility in the price of oil and gas, have resulted in both increases and decreases in the differential between the benchmark price for oil and gas and the wellhead price we receive.  These fluctuations could have a material adverse effect on our results of operations, financial condition and cash flows by decreasing the proceeds we receive for our oil and gas production in comparison to what we would receive if not for the differential.
 
The oil and gas business involves numerous uncertainties and operating risks that can prevent us from realizing profits and can cause substantial losses.
 
Our development, exploitation and exploration activities may be unsuccessful for many reasons, including weather, cost overruns, equipment shortages and mechanical difficulties. Moreover, the successful drilling of an oil and gas well does not ensure a profit on investment. A variety of factors, both geological and market-related, can cause a well to become uneconomical or only marginally economical. In addition to their cost, unsuccessful wells can hurt our efforts to replace reserves.
 
The oil and gas business involves a variety of operating risks, including:
 
· unexpected operational events and/or conditions;
· reductions in oil and gas prices;
· limitations in the market for oil and gas;
· adverse weather conditions;
· facility or equipment malfunctions;
 
 
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· title problems;
· oil and gas quality issues;
· pipe, casing, cement or pipeline failures;
· natural disasters;
· fires, explosions, blowouts, surface cratering, pollution and other risks or accidents;
· environmental hazards, such as oil spills, pipeline ruptures and discharges of toxic gases;
· compliance with environmental and other governmental requirements; and
· uncontrollable flows of oil and gas or well fluids
 
If we experience any of these problems, it could affect well bores, gathering systems and processing facilities, which could adversely affect our ability to conduct operations. We could also incur substantial losses as a result of:
 
· injury or loss of life;
· severe damage to and destruction of property, natural resources and equipment;
· pollution and other environmental damage;
· clean-up responsibilities;
· regulatory investigation and penalties;
· suspension of our operations; and
· repairs to resume operations
 
Because we use third-party drilling contractors to drill our wells, we may not realize the full benefit of worker compensation laws in dealing with their employees. Our insurance does not protect us against all operational risks. We do not carry business interruption insurance at levels that would provide enough funds for us to continue operating without access to other funds. For some risks, we may not obtain insurance if we believe the cost of available insurance is excessive relative to the risks presented. In addition, pollution and environmental risks generally are not fully insurable. If a significant accident or other event occurs and is not fully covered by insurance, it could impact our operations enough to force us to cease our operations.
 
Drilling wells is speculative, and any material inaccuracies in our forecasted drilling costs, estimates or underlying assumptions will materially affect our business.
 
Developing and exploring for oil and gas involves a high degree of operational and financial risk, which precludes definitive statements as to the time required and costs involved in reaching certain objectives. The budgeted costs of drilling, completing and operating wells are often exceeded and can increase significantly when drilling costs rise due to a tightening in the supply of various types of oil and gas field equipment and related services. Drilling may be unsuccessful for many reasons, including geological conditions, weather, cost overruns, equipment shortages and mechanical difficulties. Moreover, the successful drilling of an oil and gas well does not ensure a profit on investment. Exploratory wells bear a much greater risk of loss than development wells. Substantially all of our wells drilled through December 31, 2013 have been development wells. A variety of factors, both geological and market-related, can cause a well to become uneconomical or only marginally economic. Our initial drilling and development sites, and any potential additional sites that may be developed, require significant additional exploration and development, regulatory approval and commitments of resources prior to commercial development. If our actual drilling and development costs are significantly more than our estimated costs, we may not be able to continue our business operations as proposed and would be forced to modify our plan of operation.
 
Development of our reserves, when established, may not occur as scheduled and the actual results may not be as anticipated. Drilling activity and lack of access to economically acceptable capital may result in downward adjustments in reserves or higher than anticipated costs. Our estimates will be based on various assumptions, including assumptions over which we have control and assumptions required by the SEC relating to oil and gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. We have control over our operations that affect, among other things, acquisitions and dispositions of properties, availability of funds, use of applicable technologies, hydrocarbon recovery efficiency, drainage volume and production decline rates that are part of these estimates and assumptions and any variance in our operations that affects these items within our control may have a material effect on reserves.  The process of estimating our oil and gas reserves is extremely complex, and requires significant decisions and assumptions in the evaluation of available geological, geophysical, engineering and economic data for each reservoir. Our estimates may not be reliable enough to allow us to be successful in our intended business operations. Our actual production, revenues, taxes, development expenditures and operating expenses will likely vary from those anticipated. These variances may be material.
 
Unless we replace our oil and gas reserves, our reserves and production will decline, which would adversely affect our cash flows and income.
 
Unless we conduct successful development, exploitation and exploration activities or acquire properties containing proved reserves, our proved reserves will decline as those reserves are produced. Producing oil and gas reservoirs generally are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Our future oil and gas production, and, therefore our cash flow and income, are highly dependent on our success in efficiently developing and exploiting our current reserves and economically finding or acquiring additional recoverable reserves. We may be unable to make such acquisitions because we are:
 
 
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· unable to identify attractive acquisition candidates or negotiate acceptable purchase contracts with them;
· unable to obtain financing for these acquisitions on economically acceptable terms; or
· outbid by competitors.
 
If we are unable to develop, exploit, find or acquire additional reserves to replace our current and future production, our cash flow and income will decline as production declines, until our existing properties would be incapable of sustaining commercial production.
 
In order to exploit successfully our current oil and gas leases and others that we acquire in the future, we will need to generate significant amounts of capital.
 
The oil and gas exploration, development and production business is a capital-intensive undertaking. In order for us to be successful in acquiring, investigating, developing, and producing oil and gas from our current mineral leases and other leases that we may acquire in the future, we will need to generate an amount of capital in excess of that generated from our results of operations. In order to generate that additional capital, we may need to obtain an expanded debt facility and issue additional shares of our equity securities. There can be no assurance that we will be successful in either obtaining that expanded debt facility or issuing additional shares of our equity securities, and our inability to generate the needed additional capital may have a material adverse effect on our prospects and financial results of operations. If we are able to issue additional equity securities in order to generate such additional capital, then those issuances may occur at prices that represent discounts to our trading price, and will dilute the percentage ownership interest of those persons holding our shares prior to such issuances. Unless we are able to generate additional enterprise value with the proceeds of the sale of our equity securities, those issuances may adversely affect the value of our shares that are outstanding prior to those issuances.
 
A significant portion of our potential future reserves and our business plan depend upon secondary recovery techniques to establish production. There are significant risks associated with such techniques.
 
We anticipate that a significant portion of our future reserves and our business plan will be associated with secondary recovery projects that are either in the early stage of implementation or are scheduled for implementation subject to availability of capital. We anticipate that secondary recovery will affect our reserves and our business plan, and the exact project initiation dates and, by the very nature of waterflood operations, the exact completion dates of such projects are uncertain. In addition, the reserves and our business plan associated with these secondary recovery projects, as with any reserves, are estimates only, as the success of any development project, including these waterflood projects, cannot be ascertained in advance. If we are not successful in developing a significant portion of our reserves associated with secondary recovery methods, then the project may be uneconomic or generate less cash flow and reserves than we had estimated prior to investing the capital. Risks associated with secondary recovery techniques include, but are not limited to, the following:
 
· higher than projected operating costs;
· lower-than-expected production;
· longer response times;
· higher costs associated with obtaining capital;
· unusual or unexpected geological formations;
· fluctuations in oil and gas prices;
· regulatory changes;
· shortages of equipment; and
· lack of technical expertise.
 
If any of these risks occur, it could adversely affect our financial condition or results of operations.
 
Any acquisitions we complete are subject to considerable risk.
 
Even when we make acquisitions that we believe are good for our business, all acquisitions involve potential risks, including, among other things:
 
· the validity of our assumptions about reserves, future production, revenues and costs, including synergies;
· an inability to integrate successfully the businesses we acquire;
· a decrease in our liquidity by using our available cash or borrowing capacity to finance acquisitions;
· a significant increase in our interest expense or financial leverage if we incur additional debt to finance acquisitions;
· the assumption of unknown liabilities, losses or costs for which we are not indemnified or for which our indemnity is inadequate;
 
 
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· the diversion of management's attention from other business concerns;
· an inability to hire, train or retain qualified personnel to manage the acquired properties or assets;
· the incurrence of other significant charges, such as impairment of goodwill or other intangible assets, asset devaluation or restructuring charges;
· unforeseen difficulties encountered in operating in new geographic or geological areas; and
· customer or key employee losses at the acquired businesses.
 
Our decision to acquire a property will depend in part on the evaluation of data obtained from production reports and engineering studies, geophysical and geological analyses and seismic and other information, the results of which are often incomplete or inconclusive.
 
Our reviews of acquired properties can be inherently incomplete because it is not always feasible to perform an in-depth review of the individual properties involved in each acquisition. Even a detailed review of records and properties may not necessarily reveal existing or potential problems, nor will it permit a buyer to become sufficiently familiar with the properties to assess fully their deficiencies and potential. Inspections may not always be performed on every well, and environmental problems, such as ground water contamination, plugging or orphaned well liability are not necessarily observable even when an inspection is undertaken.
 
We must obtain governmental permits and approvals for drilling operations, which can result in delays in our operations, be a costly and time consuming process, and result in restrictions on our operations.
 
Regulatory authorities exercise considerable discretion in the timing and scope of permit issuances in the regions in which we operate. Compliance with the requirements imposed by these authorities can be costly and time consuming and may result in delays in the commencement or continuation of our exploration or production operations and/or fines. Regulatory or legal actions in the future may materially interfere with our operations or otherwise have a material adverse effect on us. In addition, we are often required to prepare and present to federal, state or local authorities data pertaining to the effect or impact that a proposed project may have on the environment, threatened and endangered species, and cultural and archaeological artifacts. Accordingly, the permits we need may not be issued, or if issued, may not be issued in a timely fashion, or may involve requirements that restrict our ability to conduct our operations or to do so profitably.
 
Due to our lack of geographic diversification, adverse developments in our operating areas would materially affect our business.
 
We currently only lease and operate oil and gas properties located in Colorado, Nebraska, Kansas and Texas. As a result of this concentration, we may be disproportionately exposed to the impact of delays or interruptions of production from these properties caused by significant governmental regulation, transportation capacity constraints, curtailment of production, natural disasters, adverse weather conditions or other events which impact this area.
 
We depend on a small number of customers for all, or a substantial amount of our sales. If these customers reduce the volumes of oil and gas they purchase from us, our revenue and cash flow will decline to the extent we are not able to find new customers for our production.
 
We currently sell oil to two purchasers in Kansas: Coffeyville Resources and Plains Marketing, LP. There are approximately five potential purchasers of oil in Kansas. If a key purchaser were to reduce the volume of oil it purchases from us, our revenue and cash available for operations will decline to the extent we are not able to find new customers to purchase our production at equivalent prices.
 
We currently sell oil to Sunoco, Inc. in Texas. There are numerous purchasers in Texas, but increased production volumes from extensive shale drilling activity in the area may result in reduced purchases by several of our purchasers.
 
We currently sell oil to Plains Marketing, LP in Colorado. There are a number of potential purchasers of our oil in Colorado but increased production volumes from the DJ basin may result in reduced purchases by our purchasers. If a key purchaser were to reduce the volume of oil it purchases from us, our revenue and cash available for operations will decline to the extent we are not able to find new customers to purchase our production at equivalent prices.
 
We sell natural gas to United Energy Trading and Western Operating Company in Colorado. There are other purchasers for our natural gas in Colorado. If a key purchaser were to reduce the volume of gas it purchases from us, our revenue and cash available for operations will decline to the extent we are not able to find new customers to purchase our production at equivalent prices.
 
We are not the operator of some of our properties and we have limited control over the activities on those properties.
 
We are not the operator of our Mississippian Project, and our dependence on the operator of this project limits our ability to influence or control the operation or future development of this project. Such limitations could materially adversely affect the realization of our targeted returns on capital related to exploration, drilling or production activities and lead to unexpected future costs.
 
 
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We may suffer losses or incur liability for events for which we or the operator of a property have chosen not to obtain insurance.
 
Our operations are subject to hazards and risks inherent in producing and transporting oil and gas, such as fires, natural disasters, explosions, pipeline ruptures, spills, and acts of terrorism, all of which can result in the loss of hydrocarbons, environmental pollution, personal injury claims and other damage to our and others' properties. As protection against operating hazards, we maintain insurance coverage against some, but not all, potential losses. In addition, pollution and environmental risks generally are not fully insurable. As a result of market conditions, existing insurance policies may not be renewed and other desirable insurance may not be available on commercially reasonable terms, if at all. The occurrence of an event that is not covered, or not fully covered, by insurance could have a material adverse effect on our business, financial condition and results of operations.
 
Our hedging activities could result in financial losses or could reduce our available funds or income and therefore adversely affect our financial position.
 
To achieve more predictable cash flow and to reduce our exposure to adverse fluctuations in the prices of oil and gas, we have entered into derivative contracts through December 31, 2015 for 245,000 barrels of crude oil.  The settlement of and the mark to market of these contracts could result in both realized and unrealized hedging losses. For the year ended December 31, 2013, we incurred realized and unrealized losses of approximately $740,000. The extent of our commodity price exposure is related largely to the effectiveness and scope of our derivative activities. For example, the derivative instruments we may utilize may be based on posted market prices, which may differ significantly from the actual crude oil prices we realize in our operations.
 
Our actual future production may be significantly higher or lower than we estimate at the time we enter into derivative transactions for such period. If the actual amount is higher than we estimate, we will have greater commodity price exposure than we intended. If the actual amount is lower than the nominal amount that is subject to our derivative financial instruments, we might be forced to satisfy all or a portion of our derivative transactions without the benefit of the cash flow from our sale or purchase of the underlying physical commodity, resulting in a substantial diminution of our liquidity. As a result of these factors, our derivative activities may not be as effective as we intend in reducing the volatility of our cash flows, and in certain circumstances may actually increase the volatility of our cash flows. In addition, while we believe our existing derivative activities are with creditworthy counterparties, deterioration in the credit markets may cause a counterparty not to perform its obligation under the applicable derivative instrument or impact their willingness to enter into future transactions with us. If that occurred, then any hedging arrangement with such counterparty would not provide any effective hedge against changes in market conditions.
 
Our business depends in part on processing facilities owned by others. Any limitation in the availability of those facilities could interfere with our ability to market our oil and gas production and could harm our business.
 
The marketability of our oil and gas production will depend in part on the availability, proximity and capacity of pipelines and oil and gas processing facilities. The amount of oil and gas that can be produced and sold is subject to curtailment in certain circumstances, such as pipeline interruptions due to scheduled and unscheduled maintenance, excessive pressure, physical damage or lack of available capacity on such systems. The curtailments arising from these and similar circumstances may last from a few days to several months. In many cases, we will be provided only with limited, if any, notice as to when these circumstances will arise and their duration. Any significant curtailment in pipeline capacity or the capacity of processing facilities could significantly reduce our ability to market our oil and gas production and could materially harm our business.
 
Cost and availability of drilling rigs, equipment, supplies, personnel and other services could adversely affect our ability to execute on a timely basis our development, exploitation and exploration plans.
 
Shortages or an increase in cost of drilling rigs, equipment, supplies or personnel could delay or interrupt our operations, which could impact our financial condition and results of operations. Drilling activity in the geographic areas in which we conduct drilling activities may increase, which would lead to increases in associated costs, including those related to drilling rigs, equipment, supplies and personnel and the services and products of other vendors to the industry. Increased drilling activity in these areas may also decrease the availability of rigs. We do not have any contracts for drilling rigs and drilling rigs may not be readily available when we need them. Drilling and other costs may increase further and necessary equipment and services may not be available to us at economical prices.
 
Our exposure to possible leasehold defects and potential title failure could materially adversely impact our ability to conduct drilling operations.
 
We obtain the right and access to properties for drilling by obtaining oil and gas leases either directly from the hydrocarbon owner, or through a third party that owns the lease. The leases may be taken or assigned to us without title insurance. There is a risk of title failure with respect to such leases, and such title failures could materially adversely impact our business by causing us to be unable to access properties to conduct drilling operations.
 
 
24

 
Our reserves are subject to the risk of depletion because many of our leases are in mature fields that have produced large quantities of oil and gas to date.
 
A significant portion of our operations are located in or near established fields in Colorado, Nebraska, Kansas and Texas. As a result, many of our leases are in, or directly offset, areas that have produced large quantities of oil and gas to date.  As such, our reserves may be negatively impacted by offsetting wells or previously drilled wells, which could significantly harm our business.
 
Our lease ownership may be diluted due to financing strategies we may employ in the future.
 
To accelerate our development efforts we may take on working interest partners who will contribute to the costs of drilling and completion operations and then share in any cash flow derived from production. In addition, we may in the future, due to a lack of capital or other strategic reasons, establish joint venture partnerships or farm out all or part of our development efforts. These economic strategies may have a dilutive effect on our lease ownership and could significantly reduce our operating revenues.
 
We may face lease expirations on leases that are not currently held-by-production.
 
We have numerous leases that are not currently held-by-production, some of which have near term lease expirations and are likely to expire. Although we believe that we can maintain our most desirable leases by conducting drilling operations or by negotiating lease extensions, we can make no guarantee that we can maintain these leases.
 
We are subject to complex laws and regulations, including environmental regulations, which can adversely affect the cost, manner or feasibility of doing business.
 
Development, production and sale of oil and gas in the United States are subject to extensive laws and regulations, including environmental laws and regulations. We may be required to make large expenditures to comply with environmental and other governmental regulations. Matters subject to regulation include, but are not limited to:
 
· location and density of wells;
· the handling of drilling fluids and obtaining discharge permits for drilling operations;
· accounting for and payment of royalties on production from state, federal and Indian lands;
· bonds for ownership, development and production of oil and gas properties;
· transportation of oil and gas by pipelines;
· operation of wells and reports concerning operations; and
· taxation.
 
Under these laws and regulations, we could be liable for personal injuries, property damage, oil and gas spills, discharge of hazardous materials, remediation and clean-up costs and other environmental damages. Failure to comply with these laws and regulations also may result in the suspension or termination of our operations and subject us to administrative, civil and criminal penalties. Moreover, these laws and regulations could change in ways that substantially increase our costs. Accordingly, any of these liabilities, penalties, suspensions, terminations or regulatory changes could materially adversely affect our financial condition and results of operations enough to possibly force us to cease our business operations.
 
Our operations may expose us to significant costs and liabilities with respect to environmental, operational safety and other matters.
 
We may incur significant costs and liabilities as a result of environmental and safety requirements applicable to our oil and gas production activities. We may also be exposed to the risk of costs associated with Kansas Corporation Commission, the Texas Railroad Commission and the State of Colorado Oil and Gas Conservation Commission requirements to plug orphaned and abandoned wells on our oil and gas leases from wells previously drilled by third parties. In addition, we may indemnify sellers or lessors of oil and gas properties for environmental liabilities they or their predecessors may have created. These costs and liabilities could arise under a wide range of federal, state and local environmental and safety laws and regulations, including regulations and enforcement policies, which have tended to become increasingly strict over time. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, imposition of cleanup and site restoration costs, liens and to a lesser extent, issuance of injunctions to limit or cease operations. In addition, claims for damages to persons or property may result from environmental and other impacts of our operations.
 
Strict, joint and several liability may be imposed under certain environmental laws, which could cause us to become liable for the conduct of others or for consequences of our own actions that were in compliance with all applicable laws at the time those actions were taken. New laws, regulations or enforcement policies could be more stringent and impose unforeseen liabilities or significantly increase compliance costs. If we are not able to recover the resulting costs through insurance or increased revenues, our ability to operate effectively could be adversely affected.
 
 
25

 
We operate in a highly competitive environment and our competitors may have greater resources than do we.
 
The oil and gas industry is intensely competitive and we compete with other companies, many of which are larger and have greater financial, technological, human and other resources. Many of these companies not only explore for and produce crude oil and gas but also carry on refining operations and market petroleum and other products on a regional, national or worldwide basis. Such companies may be able to pay more for productive oil and gas properties and exploratory prospects or define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. In addition, such companies may have a greater ability to continue exploration activities during periods of low oil and gas market prices. Our ability to acquire additional properties and to discover reserves in the future will be dependent upon our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. If we are unable to compete, our operating results and financial position may be adversely affected.
 
We may incur substantial write-downs of the carrying value of our oil and gas properties, which would adversely impact our earnings.
 
We review the carrying value of our oil and gas properties under the full cost method of accounting. 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 un-weighted 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.
 
Revisions to estimates of oil and gas reserves and/or an increase or decrease in current prices can have a material impact on the present value of estimated future net revenues. 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 depreciation, depletion, and amortization in the statement of operations.
 
During the years ended December 31, 2013 and 2012 there were no impairments resulting from the quarterly ceiling tests.
 
Risks Associated with our Debt Financing
 
Significant and prolonged declines in commodity prices may negatively impact our borrowing base and our ability to borrow overall.
 
Our borrowing base, which is based on our oil and gas reserves and is subject to review and adjustment on a semi-annual basis and other interim adjustments, may be reduced when it is reviewed.  A reduction in our base results in a "loan excess" which is required to be eliminated through payment of a portion of the loan and/or cash collateralization of Letters of Credit obligations; or adding properties to the borrowing base sufficient to offset the "loan excess".  A reduction in our borrowing base or the ability to borrow under our Credit Facility, combined with a reduction in cash flow from operations resulting from a decline in oil and gas prices, may require us to further reduce our capital expenditures and our operating activities.
 
Until we repay the full amount of our outstanding Credit Facility, we may continue to have substantial indebtedness, which is secured by substantially all of our assets.
 
On December 31, 2013, we had $31,500,000 of bank loans outstanding. If we defaulted on our obligations with respect to the secured debt, the lenders may enforce their rights as secured parties and we may lose all or a portion of our assets or be forced to materially reduce our business activities.
 
Our substantial indebtedness could make it more difficult for us to fulfill our obligations under our Credit Facility and, therefore, adversely affect our business.
 
On September 30, 2013, the Company 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 borrower parties; (iv) added certain collateral and security interests in favor of the Bank; and (v) reduced the Company’s current interest rate to 3.30%.
 
As of December 31, 2013, we had total indebtedness of $31,500,000 under the Credit Facility.  Our substantial indebtedness, and the related interest expense, could have important consequences to us, including:
 
· our ability to borrow additional amounts for working capital, capital expenditures, debt service requirements, execution of our business strategy, or other general corporate purposes;
 
 
26

 
· being forced to use cash flow to reduce our outstanding balance as a result of an unfavorable borrowing base redetermination;
· our ability to use operating cash flow in other areas of our business because we must dedicate a substantial portion of these funds to service our indebtedness;
· increasing our vulnerability to general adverse economic and industry conditions;
· placing us at a competitive disadvantage as compared to our competitors that have less leverage;
· our ability to capitalize on business opportunities and to react to competitive pressures and changes in government regulation;
· our ability to, or increasing the cost of, refinancing our indebtedness; and
· our ability to enter into marketing, hedging, optimization and trading transactions by reducing the number of counterparties with whom we can enter into such transactions as well as the volume of those transactions. 
 
The covenants in our Credit Facility impose significant operating and financial restrictions on us.
 
The Credit Facility imposes significant operating and financial restrictions on us. These restrictions limit our ability and the ability of our subsidiaries, among other things, to:
 
· incur additional indebtedness and provide additional guarantees;
· pay dividends and make other restricted payments;
· create or permit certain liens;
· use the proceeds from the sales of our oil and gas properties;
· use the proceeds from the unwinding of certain financial hedges;
· engage in certain transactions with affiliates; and
· consolidate, merge, sell or transfer all or substantially all of our assets or the assets of our subsidiaries.
 
The Credit Facility also contains various affirmative covenants with which we are required to comply.  We were in compliance with these covenants as of December 31, 2013. We may be unable to comply with some or all of these covenants in the future. If we do not comply with these covenants and are unable to obtain waivers from our lenders, we would be unable to make additional borrowings under these facilities; our indebtedness under these agreements would be in default and repayment of debt could be accelerated by our lenders.   If our indebtedness is accelerated, we may not be able to repay our indebtedness or borrow sufficient funds to refinance it. In addition, if we incur additional indebtedness in the future, we may be subject to additional covenants, which may be more restrictive than those to which we are currently subject.
 
Risks Associated with our Common Stock
 
We do not expect to pay dividends to holders of our common stock because of the terms of our debt facility, the terms of our Series A preferred stock, and our need to reinvest cash flow from operations in our business.
  
It is unlikely that we will pay any dividends to the holders of our common stock in the foreseeable future. The terms of our debt facility require that the lender approve any such distributions, and the lender is unlikely to provide that consent so long as we have significant unpaid indebtedness outstanding. In addition, we issued shares of Series A preferred stock, the terms of which require us to pay to the holders of those shares cumulative distributions of $4,779,460 before making any distributions to the holders of our common stock, unless we concurrently pay to holders of Series A preferred stock a dividend in like amount, on an as-converted-to-common stock basis. Those distributions to the holders of our Series A preferred stock are to be made from one-third of our available adjusted cash from operations, which is our net cash flow from operations less principal repaid to our lender. We presently are unsure how many calendar quarters of operations we will need in order to complete the preferential payments due to the holders of our Series A preferred stock. Even after we complete those distributions, we are likely to elect to retain and reinvest any available cash flow from operations, rather than funding dividend distributions to holders of our common stock.
 
There are a limited number of stockholders who have significant control over our common stock, allowing them to have significant influence over the outcome of all matters submitted to stockholders for approval, which may conflict with our interests and the interests of other stockholders.
 
Our directors, officers and principal stockholders (stockholders owning 10% or more of our common stock) and their affiliates beneficially owned approximately 81,817,257 shares or 74.9% of the outstanding shares of common stock, stock options, and derivatives that could have been converted to common stock at December 31, 2013, and such stockholders will have significant influence over the outcome of all matters submitted to our stockholders for approval, including the election of directors and other corporate actions.
 
 
27

 
Two of our Directors, Ryan A. Lowe and Lance Helfert, serve on the investment committee of West Coast Asset Management, Inc. West Coast Asset Management is the managing member of West Coast Opportunity Fund, LLC, a private investment vehicle formed for the purpose of investing in a wide variety of securities and financial instruments. West Coast Asset Management's principals also manage Montecito Venture Partners, LLC. West Coast Opportunity Fund and Montecito Venture Partners, LLC together beneficially own 54.4% of our common stock and 50.6% of our Series A preferred stock.
 
In addition, we engage from time to time in transactions with certain of these significant stockholders.
 
As discussed more fully in Note 5 to the financial statements, on September 27, 2013, West Coast Opportunity Fund, LLC exchanged 123,539,227 Black Raven Energy, Inc. common shares for 41,327,516 common shares of EnerJex Resources, Inc.
 
Our large stockholders may have interests that differ from those of other stockholders.
 
As stated above, West Coast Opportunity Fund and Montecito Venture Partners, affiliates of our directors Mr. Lowe and Mr. Helfert, beneficially own, as of December 31, 2013, 54.4% of our common stock and 50.6% of our Series A preferred stock.
 
The interests of West Coast Opportunity Fund and Montecito Venture Partners, and their affiliates, may differ from those of our other stockholders.  West Coast Opportunity Fund and Montecito Venture Partners, and their affiliates are in the business of making investments in companies and maximizing the return on those investments. They currently have, and may from time to time in the future acquire, interests in businesses that directly or indirectly compete with certain aspects of our business or our suppliers' or customers' businesses.
 
These stockholders' significant ownership of our voting stock may enable them to influence or effectively control us.
 
The holders of our outstanding shares of Series A Preferred Stock have dividend, conversion and other rights not shared with common stock holders.
 
As of March 24, 2014, we had 109,254,045 shares of our common stock issued and outstanding, as well as 4,779,460 shares of our Series A preferred stock issued and outstanding.
   
So long as any shares of Series A preferred stock are outstanding, we are required to declare dividends each calendar quarter in an aggregate amount equal to one-third of our adjusted net cash from operating activities reduced by any principal amount of debt repayment in such calendar quarter to our institutional lenders and any other secured creditors. This right restricts our ability to use a portion of our net cash flow for other purposes such as developing our assets, strategic acquisitions, and dividends, and has other important consequences to us, including the potential to adversely affect:
 
· our ability to borrow additional amounts for working capital, capital expenditures, debt service requirements, execution of our business strategy, or other general corporate purposes;
· our ability to use a portion of our operating cash flow in other areas of our business because we must dedicate a substantial portion of these funds to pay dividends;
· our ability to capitalize on business opportunities and to react to competitive pressures and changes in government regulation; and;
· our ability to, or increasing the cost of, refinancing our indebtedness
 
In addition, we cannot declare any dividends with regard to our common stock unless we concurrently pay to holders of Series A preferred stock a dividend in like amount, on an as-converted to common stock basis.
 
The Series A preferred stock is convertible into 4,779,460 shares of our common stock, and the Series A preferred stock, by its terms, shall convert into common stock on a one-to-one basis (subject to adjustment) once we have paid cumulative dividends of $4,779,460 with regard to such Series A preferred stock. To date, we have paid cumulative dividends of $1,247,950 to the holders of our Series A preferred stock, and the holders of those shares are entitled to receive an additional $3,075,221 of distributions prior to the conversion of those Series A preferred stock to common stock. The Series A preferred stock is convertible into common stock on a one-for-one basis, and upon conversion of the shares of Series A preferred stock, the common stock issued upon conversion would represent approximately 4.2% of our outstanding common stock. This would dilute the holdings of our existing common stockholders.  In addition, the preferred stockholders vote together with our common stockholders, as a single class on an as-converted-to basis.
 
 
28

 
Furthermore, in the event of a liquidation of the Company, the holders of our Series A preferred stock would receive priority liquidation payments equal to the liquidation amount of the preferred stock before any distributions could be made to our common stockholders.  The current total liquidation amount of our Series A preferred stock is approximately $3,075,221, so the preferred shareholders would be entitled to receive that amount before any distributions would be made to common stockholders.  
 
Lastly, the preferred stockholders have the right, by majority vote of the shares of preferred stock, to generally approve any issuances by us of equity that is senior to or equal in rights to the preferred stock.  Therefore, the preferred stockholders can effectively bar us from entering into a transaction which they feel is not in their best interests even if the transaction would otherwise be in the best interests of EnerJex and its common stockholders.
 
We have derivative securities currently outstanding and we may issue derivative securities in the future. Exercise of the derivatives will cause dilution to existing and new stockholders.
 
The exercise of our outstanding options and warrants, will cause additional shares of common stock to be issued, resulting in dilution to our existing and future common stockholders
 
We have the ability to issue additional shares of our common stock and shares of preferred stock without asking for stockholder approval, which could cause your investment to be diluted.
 
Our articles of incorporation authorize the board of directors to issue up to 250,000,000 shares of common stock and 25,000,000 shares of preferred stock.   The power of the board of directors to issue shares of common stock, preferred stock or warrants or options to purchase shares of common stock or preferred stock is generally not subject to shareholder approval.  Accordingly, any additional issuance of our common stock, or preferred stock that may be convertible into common stock, or debt instruments that may be convertible into common or preferred stock, may have the effect of diluting one's investment.
 
Our common stock is traded on an illiquid market, making it difficult for investors to sell their shares.
 
Our common stock trades on the Over-the-Counter Bulletin Board (OTCBB) under the symbol "ENRJ," but trading volume has been minimal. Therefore, the market for our common stock is limited. The trading price of our common stock could be subject to wide fluctuations. Investors may not be able to purchase additional shares or sell their shares within the time frame or at a price they desire.
 
The price of our common stock may be volatile and you may not be able to resell your shares at a favorable price.
 
Regardless of whether an active trading market for our common stock develops, the market price of our common stock may be volatile and you may not be able to resell your shares at or above the price you paid for such shares. Many factors beyond our control, including but not limited to the following factors could affect our stock price:
 
· our operating and financial performance and prospects;
· quarterly variations in the rate of growth of our financial indicators, such as net income or loss per share, net income or loss and revenues;
· changes in revenue or earnings estimates or publication of research reports by analysts about us or the exploration and production industry;
· potentially limited liquidity;
· actual or anticipated variations in our reserve estimates and quarterly operating results;
· changes in oil and gas prices;
· sales of our common stock by significant stockholders and future issuances of our common stock;
· increases in our cost of capital;
· changes in applicable laws or regulations, court rulings and enforcement and legal actions;
· commencement of or involvement in litigation;
· changes in market valuations of similar companies;
· additions or departures of key management personnel;
· general market conditions, including fluctuations in and the occurrence of events or trends affecting the price of oil and gas; and
· domestic and international economic, legal and regulatory factors unrelated to our performance.
 
 
29

 
Our articles of incorporation, bylaws and Nevada Law contain provisions that could discourage an acquisition or change of control of us.
 
Our articles of incorporation authorize our board of directors to issue preferred stock and common stock without stockholder approval. The election by our board of directors to issue Series A preferred stock, and any future election to issue more preferred stock, could make it more difficult for a third party to acquire control of us. In addition, provisions of the articles of incorporation and bylaws could also make it more difficult for a third party to acquire control of us. In addition, Nevada's "Combination with Interested Stockholders' Statute" and its "Control Share Acquisition Statute" may have the effect in the future of delaying or making it more difficult to effect a change in control of us.
 
These statutory anti-takeover measures may have certain negative consequences, including an effect on the ability of our stockholders or other individuals to (i) change the composition of the incumbent board of directors; (ii) benefit from certain transactions which are opposed by the incumbent board of directors; and (iii) make a tender offer or attempt to gain control of us, even if such attempt were beneficial to us and our stockholders. Since such measures may also discourage the accumulations of large blocks of our common stock by purchasers whose objective is to seek control of us or have such common stock repurchased by us or other persons at a premium, these measures could also depress the market price of our common stock. Accordingly, our stockholders may be deprived of certain opportunities to realize the "control premium" associated with take-over attempts.
 
We have no plans to pay dividends on our common stock. You may not receive funds without selling your stock.
 
We do not anticipate paying any cash dividends on our common stock in the foreseeable future. We currently intend to retain future earnings, if any, to finance the expansion of our business. Our future dividend policy with regard to our common stock is within the discretion of our board of directors and will depend upon various factors, including our business, financial condition, results of operations, capital requirements, investment opportunities and restrictions imposed by our debentures and Credit Facility.
 
Because our common stock is deemed a low-priced "Penny" stock, an investment in our common stock should be considered high risk and subject to marketability restrictions.
 
Our common stock is currently deemed to be a penny stock, as defined in Rule 3a51-1 under the Securities Exchange Act, which may make it more difficult for investors to liquidate their investment even if and when a market develops for the common stock. Until the trading price of the common stock consistently trades above $5.00 per share, if ever, trading in the common stock may be subject to the penny stock rules of the Securities Exchange Act specified in rules 15g-1 through 15g-10. Those rules require broker-dealers, before effecting transactions in any penny stock, to:
 
· deliver to the customer, and obtain a written receipt for, a disclosure document;
· disclose certain price information about the stock;
· disclose the amount of compensation received by the broker-dealer or any associated person of the broker-dealer;
· send monthly statements to customers with market and price information about the penny stock; and
· in some circumstances, approve the purchaser's account under certain standards and deliver written statements to the customer with information specified in the rules.
 
Consequently, the penny stock rules may restrict the ability or willingness of broker-dealers to sell the common stock and may affect the ability of holders to sell their common stock in the secondary market and the price at which such holders can sell any such securities. These additional procedures could also limit our ability to raise additional capital in the future.
 
If we fail to remain current on our reporting requirements, we could be removed from the OTC Bulletin Board, which would limit the ability of broker-dealers to sell our securities and the ability of stockholders to sell their securities in the secondary market.
 
Companies trading on the OTCBB, such as us, must be reporting issuers under Section 12 of the Securities Exchange Act of 1934, as amended, and must be current in their reports under Section 13, in order to maintain price quotation privileges on the OTC Bulletin Board.  More specifically, FINRA, which regulates trading on the OTC Bulletin Board, has enacted Rule 6530, which determines eligibility of issuers quoted on the OTCBB by requiring an issuer to be current in its filings with the Commission.  Pursuant to Rule 6530(e), if we file our reports late with the Commission three times in a two-year period or our securities are removed from the OTCBB for failure to timely file twice in a two-year period then we will be ineligible for quotation on the OTCBB.  As a result, the market liquidity for our securities could be severely adversely affected by limiting the ability of broker-dealers to sell our securities and the ability of stockholders to sell their securities in the secondary market.
 
FINRA sales practice requirements may limit a stockholder's ability to buy and sell our stock.
 
In addition to the "penny stock" rules described above, FINRA has adopted rules that require that in recommending an investment to a customer, a broker-dealer must have reasonable grounds for believing that the investment is suitable for that customer. Prior to recommending speculative low priced securities to their non-institutional customers, broker-dealers must make reasonable efforts to obtain information about the customer's financial status, tax status, investment objectives and other information. Under interpretations of these rules, FINRA believes that there is a high probability that speculative low priced securities will not be suitable for at least some customers. FINRA requirements make it more difficult for broker-dealers to recommend that their customers buy our common stock, which may limit your ability to buy and sell our stock and have an adverse effect on the market for our shares.
 
 
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Additional Risks and Uncertainties
 
We are an oil and gas acquisition, exploration and development company. If any of the risks that we face actually occur, irrespective of whether those risks are described in this section or elsewhere in this report, our business, financial condition and operating results could be materially adversely affected.
 
ITEM 1B. UNRESOLVED STAFF COMMENTS.
 
Not applicable.
 
ITEM 3. LEGAL PROCEEDINGS.
 
We may become involved in various routine legal proceedings incidental to our business. However, to our knowledge as of the date of this report, there are no material pending legal proceedings to which we are a party or to which any of our property is subject, except the legal proceedings disclosed 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.
 
PART II
 
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES.
 
Market Information for Common Stock
 
Our common stock currently trades on the OTCBB under the symbol "ENRJ." Our common stock has traded infrequently on the OTCBB, which limits our ability to locate accurate high and low bid prices for each quarter within the last two years. Therefore, the following table lists the quotations for the high and low sales prices of our common stock for the years ended December 31, 2012 and December 31, 2013. The quotations reflect inter-dealer prices without retail mark-up, markdown, or commissions and may not represent actual transactions. The market price of our common stock has been volatile. For an additional discussion, see "Item 1A: Risk Factors" of this Annual Report on Form 10-K. 
 
 
 
High
 
Low
 
Year Ended December 31, 2012
 
 
 
 
 
 
 
Quarter ended March 31, 2012
 
$
0.90
 
$
0.70
 
Quarter ended June 30, 2012
 
$
0.78
 
$
0.60
 
Quarter ended September 30, 2012
 
$
0.74
 
$
0.60
 
Quarter ended December 31, 2012
 
$
0.73
 
$
0.46
 
Year Ended December 31, 2013
 
 
 
 
 
 
 
Quarter ended March 31, 2013
 
$
0.69
 
$
0.46
 
Quarter ended June 30, 2013
 
$
0.69
 
$
0.49
 
Quarter ended September 30, 2013
 
$
0.75
 
$
0.47
 
Quarter ended December 31, 2013
 
$
0.63
 
$
0.47
 
 
Holders
 
As of March 24, 2014, there were 1,403 holders of record of our common stock, and 15 holders of record of our Series A preferred stock.
 
 
31

  
Dividends
 
We have never paid or declared any cash dividends on our common stock. We are required by the terms of our Series A preferred stock to declare dividends each calendar quarter in an aggregate amount equal to one-third of our adjusted net cash from operating activities reduced by any principal amount of debt repayment in such calendar quarter to institutional lenders and other secured creditors. This right is senior to the rights of common stockholders to receive dividend payments. We currently intend to retain any future earnings in excess of debt repayments and Series A preferred stock dividends to finance the growth and development of our business and we do not expect to pay any cash dividends on our common stock in the foreseeable future. In addition, we are contractually prohibited by the terms of our outstanding debt from paying cash dividends on our common stock. Payment of future dividends on common stock, if any, will be at the discretion of our Board of Directors and will depend on our financial condition, results of operations, capital requirements, restrictions contained in current or future financing instruments, including the consent of debt holders and holders of Series A preferred stock, if applicable at such time, and other factors our Board of Directors deems relevant.
 
Securities Authorized for Issuance under Equity Compensation Plans
 
See the section title “Equity Compensation Plan Information” under Item 12 in Part III of the Form 10-K.
 
Recent Sales of Unregistered Securities
 
None.
 
Issuer Purchases of Equity Securities
 
Effective November 30, 2012, we purchased 2,000,000 shares of stock from a stockholder for $323,035 in cash (including an option payment we previously made to the selling stockholder) and a note payable in the amount of $825,000 bearing an interest rate of 0.24% per year . The note was repaid in full on December 31, 2013.
 
ITEM 6. SELECTED FINANCIAL DATA.
 
Not applicable.
 
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.
 
This Management's Discussion and Analysis of Financial Condition and Results of Operations section should read in conjunction with the other sections of this Annual Report on Form 10-K, including "Items 1 and 2. Business and Properties" and "Item 8: Financial Statements and Supplementary Data". This section includes forward-looking statements within the meaning of Section 27A of the Securities Act, and Section 21E of the Exchange Act. Forward-looking statements such as "will", "believe," "are projected to be" and similar expressions are statements regarding future events or our future performance, and include statements regarding projected operating results. These forward-looking statements are based on current expectations, beliefs, intentions, strategies, forecasts and assumptions and involve a number of risks and uncertainties that could cause actual results to differ materially from those anticipated by these forward-looking statements. These risks include, but are not limited to: our ability to deploy capital in a manner that maximizes stockholder value; the ability to identify suitable acquisition candidates or business and investments opportunities; the ability to reduce our operating costs; general economic conditions and our expected liquidity in future periods. These forward-looking statements are based on our current expectations and could be affected by the uncertainties and risk factors described throughout this filing and particularly in the "Risk Factors" set forth in Part I, Item 1A of this Annual Report on Form 10-K. As a result, our actual results may differ materially from those anticipated in these forward-looking statements.
 
Overview
 
Our principal strategy is to develop, acquire, explore and produce domestic onshore oil and gas properties. Our business activities are currently focused in Kansas, Colorado, Nebraska, and Texas.
 
Results of Operations
 
The following table presents selected information regarding our operating results from continuing operations. Due to the merger with Black Raven Energy, Inc. on September 27, 2013 (see Note 5), only the results of operations for the fourth quarter are included for Black Raven. 
  
 
 
 
Year Ended
 
Year Ended
 
 
 
 
 
 
December 31,
 
December 31,
 
 
 
 
 
 
2013
 
2012
 
Difference
 
Oil & gas revenues(1)
 
$
10,942,270
 
$
8,469,519
 
$
2,472,751
 
Average price per boe
 
$
90.71
 
$
87.74
 
$
2.97
 
Expenses:
 
 
 
 
 
 
 
 
 
 
Lease operating expenses(2)
 
$
4,095,850
 
$
3,102,321
 
$
993,529
 
Depreciation, depletion and amortization (3)
 
 
1,691,008
 
 
1,541,069
 
 
149,939
 
Total production expenses
 
 
5,786,858
 
 
4,643,390
 
 
1,143,468
 
Professional fees(4)
 
 
1,071,740
 
 
1,483,720
 
 
(411,980)
 
Salaries(5)
 
 
1,432,081
 
 
601,533
 
 
830,548
 
Depreciation on other fixed assets
 
 
165,652
 
 
92,398
 
 
73,254
 
Administrative expenses(6)
 
 
798,457
 
 
808,836
 
 
(10,379)
 
Total expenses
 
$
9,254,788
 
$
7,629,877
 
$
1,624,911
 
 
 
32

 
(1) 2013 revenues increased 29% to 10.9 million from $8.5 million over fiscal 2012.  Revenues increased due to increased sales volumes.  Production increased 25% to 120,634 boe for 2013 compared to production of 96,842 in 2012. Production increases were due primarily to results from the successful drilling programs in our Cherokee and Mississippi Projects and new production from our Colorado assets that resulted from our acquisition of Black Raven Energy, Inc. on September 27, 2013, as more fully described in Note 5.  Realized prices increased $2.97 to $90.71 per boe in 2013 versus $87.74 per boe for 2012.
(2) 2013 lease operating expenses increased 32% to $4.1 million from $3.1 million during 2012. However, lease operating expenses per boe increased only 5.9% to $33.95 in 2013 from $32.03 per boe in 2012.  The 32% increase in lease operating expenses in 2013 was due primarily to increased expenses associated with increased Kansas production, and the new Colorado production added in 2013 that resulted from our acquisition of Black Raven Energy, Inc. on September 27, 2013 (see Note 5).
(3) 2013 depletion expense increased 9.7% to $1.7 million compared to $1.5 million for 2012. The depletion expense increase is due primarily to increased production levels as note in (2) above.  Depletion expense per boe decreased $1.89 or 13.5% in 2013 compared to 2012.
(4) 2013 professional fees were $1.1 million, compared to $1.5 million during 2012. Professional fees decreased as a result of reduced legal fees, investment banking fees, consulting fees and engineering fees.
(5) Salaries and wages more than doubled in 2013 to $1.4 million compared to $0.6 million of salaries and wages expense incurred during 2012. The increase in salaries and wages was due primarily to the addition of employees to our Kansas and Texas staffs during 2013 and to the addition of Colorado employees on September 27, 2013 following the acquisition of Black Raven Energy, Inc. (see Note 5).
(6) Administrative expenses in 2013 were unchanged compared to 2012 at $0.8 million. Despite growth in production, employees and the addition of a new field office in 2013, administrative expenses were flat as a result of management's focus on controlling and reducing these expenses.
 
Reserves
 
 
 
Year Ended
 
Year Ended
 
 
 
December 31,
 
December 31,
 
Proved Reserves
 
2013
 
2012
 
Total proved PV10 (present value) of reserves
 
$
102,411,800
 
$
60,846,300
 
Total proved reserves (BOE)
 
 
5,804,600
 
 
2,927,000
 
Average Price (per bbl)
 
$
87.89
 
$
84.21
 
Average Price (per mcf)
 
$
2.85
 
$
-
 
 
Of the 5.8 million BOE of total proved reserves, approximately 49% are classified as proved developed producing, approximately 17% are classified as proved developed non-producing, and approximately 34% are classified as proved undeveloped.
 
The following table presents summary information regarding our estimated net proved reserves as of December 31, 2013. All calculations of estimated net proved reserves have been made in accordance with the rules and regulations of the SEC, and, except as otherwise indicated, give no effect to federal or state income taxes. The estimates of net proved reserves are based on the reserve reports prepared by MHA Petroleum Consultants LLC, our independent petroleum consultants. For additional information regarding our reserves, please see Note 15 to our audited financial statements as of and for the fiscal year ended December 31, 2013.
 
Summary of Proved Oil and Gas Reserves
as of December 31, 2013
 
 
 
Gross
 
Net
 
 
PV10 (before
 
Proved Reserves Category
 
BOE
 
BOE
 
 
tax)  (1)
 
Proved, Developed
 
5,801,000
 
3,824,800
 
$
74,234,300
 
Proved, Undeveloped
 
2,664,700
 
1,979,800
 
$
28,717,500
 
Total Proved Reserves
 
8,465,700
 
5,804,600
 
$
102,411,800
 
 
 
33

 
(1) The following table shows our reconciliation of our PV10 to our standardized measure of discounted future net cash flows (the most direct comparable measure calculated and presented in accordance with GAAP). PV10 is our estimate of the present value of future net revenues from estimated proved oil and gas reserves after deducting estimated production and ad valorem taxes, future capital costs and operating expenses, but before deducting any estimates of future income taxes. The estimated future net revenues are discounted at an annual rate of 10% to determine their "present value." We believe PV10 to be an important measure for evaluating the relative significance of our oil and gas properties and that the presentation of the non-GAAP financial measure of PV10 provides useful information to investors because it is widely used by professional analysts and sophisticated investors in evaluating oil and gas companies. Because there are many unique factors that can impact an individual company when estimating the amount of future income taxes to be paid, we believe the use of a pre-tax measure is valuable for evaluating our company. We believe that most other companies in the oil and gas industry calculate PV10 on the same basis. PV10 should not be considered as an alternative to the standardized measure of discounted future net cash flows as computed under GAAP.
 
 
 
As of December
 
As of December
 
 
 
31, 2013
 
31, 2012
 
PV10 (before tax)
 
$
102,411,800
 
$
61,206,000
 
Future income taxes, net of 10% discount
 
 
(20,964,145)
 
 
(12,333,000)
 
Standardized measure of discounted future net cash flows
 
$
81,447,655
 
$
48,873,000
 
 
Liquidity and Capital Resources
 
Liquidity is a measure of a company's ability to meet potential cash requirements. We have historically met our capital requirements through debt financing, revenues from operations and the issuance of equity securities. We believe that our historical means of meeting our capital requirements will provide us with adequate liquidity to fund our operations and capital program in 2014.
 
The following table summarizes total current assets, total current liabilities and working capital at year ended December 31, 2013 compared to the year ended December 31, 2012.
 
 
 
Year Ended
 
Year Ended
 
 
 
 
 
 
December 31, 2013
 
December 31, 2012
 
Difference
 
Current Assets
 
$
5,401,304
 
$
3,536,497
 
$
1,864,807
 
Current Liabilities
 
$
6,506,178
 
$
4,556,476
 
$
(1,949,702)
 
Working Capital (deficit)
 
$
(1,104,874)
 
$
(1,019,979)
 
$
(84,895)
 
 
Senior Secured Credit Facility
 
On October 3, 2011, the Company and DD Energy, Inc., EnerJex Kansas, Inc., Black Sable Energy, LLC and Working Interest, LLC ("Borrowers") entered into an Amended and Restated Credit Agreement with Texas Capital Bank, N.A. (“Bank”) and other financial institutions and banks that may become a party to the Credit Agreement from time to time. The facilities provided under the Amended and Restated Credit Agreement were 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 reflects the addition of Rantoul Partners, as an additional Borrower and adds as additional security for the loans the assets held by Rantoul Partners.
 
 
34

 
On August 31, 2012, we entered into a Second Amendment to Amended and Restated Credit Agreement with the Bank. The Second Amendment: (i) increased the 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 the borrowing base to $12,150,000 and (ii) clarified certain continuing covenants and provided a limited waiver of compliance with one of the covenants so clarified for the fiscal quarter ended December 31, 2011.
 
On January 24, 2013, we entered into a Fourth Amendment to Amended and Restated Credit Agreement, which was made effective as of December 31, 2012 with the Bank. The Fourth Amendment reflects the following changes: (i) the Bank consented to the restructuring transactions related to the dissolution of Rantoul Partners, and (ii) the Bank terminated a Limited Guaranty, as defined in the Credit Agreement, executed by Rantoul Partners in favor of the Bank
 
On April 16, 2013, the Bank increased our borrowing base to $19.5 million.
 
On September 30, 2013, the Company 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 borrower parties; (iv) added certain collateral and security interests in favor of the Bank; and (v) reduced the Company’s current interest rate to 3.30%.
 
Summary of product research and development that we will perform for the term of our plan
 
We do not anticipate performing any significant product research and development under our plan of operation.
 
Expected purchase or sale of any significant equipment
 
We anticipate that we will purchase the necessary production and field service equipment required to produce oil and gas during our normal course of operations over the next 12 months.
 
Significant changes in the number of employees
 
We currently have 35 full-time employees including field personnel. As production and drilling activities increase or decrease, we will adjust our technical, operational and administrative personnel as appropriate. We use and will continue to use independent consultants and contractors to perform various professional services, particularly in the area of land services, reservoir engineering, geology, drilling, water hauling, pipeline construction, well design, well-site monitoring and surveillance, permitting and environmental assessment. We believe that this use of third-party service providers may enhance our ability to contain operating and general expenses, and capital costs.
 
Off-Balance Sheet Arrangements
 
We do not have any off-balance sheet arrangements that have or are reasonably likely to have a current or future effect on our financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources that is material to investors.
 
Critical Accounting Policies and Estimates
 
Our accounting policies and estimates that are critical to our business operations and understanding of our results of operations include those relating to our oil and gas properties, asset retirement obligations and the value of share-based payments. This is not a comprehensive list of all of the accounting policies. In many cases, the accounting treatment of a particular transaction is specifically dictated by U.S. GAAP, with no need for our judgment in the application. There are also areas in which our judgment in selecting any available alternative would not produce a materially different result. However, certain of our accounting policies are particularly important to the portrayal of our financial position and results of operations and we may use significant judgment in the application; as a result, they are subject to an inherent degree of uncertainty. In applying those policies, we use our judgment to determine the appropriate assumptions to be used in the determination of certain estimates. Those estimates are based on historical experience, observation of trends in the industry, and information available from other outside sources, as appropriate. For a more detailed discussion on the application of these and other accounting policies, see Note 1, Summary of Significant Accounting Policies, to our consolidated financial statements included in this report.
 
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.
 
 
35

 
Proved properties are amortized using the units of production method (UOP). Currently we only have operations in the Unites States of America. The UOP calculation multiplies the percentage of estimated proved reserves produced each quarter by the cost of these reserves. The amortization base in the UOP calculation includes the sum of proved property, net of accumulated depreciation, depletion and amortization (DD&A), estimated future development costs (future costs to access and develop proved reserves) and asset retirement costs, less related salvage value.
 
The cost of unproved properties are excluded from the amortization calculation until it is determined whether or not proved reserves can be assigned to such properties or until development projects are placed into service. Geological and geophysical costs not associated with specific properties are recorded as proved property immediately. Unproved properties are reviewed for impairment quarterly.
 
Under the full cost method of accounting, the net book value of oil and gas properties, less deferred income taxes, may not exceed a calculated “ceiling.” The ceiling limitation is (a) the present value of future net revenues computed by applying current prices of oil & gas reserves (with consideration of price changes only to the extent provided by contractual arrangements) to estimated future production of proved oil & gas reserves as of the date of the latest balance sheet presented, less estimated future expenditures (based on current costs) to be incurred in developing and producing the proved reserves computed using a discount factor of 10 percent and assuming continuation of existing economic conditions plus (b) the cost of properties not being amortized plus (c) the lower of cost or estimated fair value of unproven properties included in the costs being amortized less (d) income tax effects related to differences between book and tax basis of properties. Future cash outflows associated with settling accrued retirement obligations are excluded from the calculation. Estimated future cash flows are calculated using end-of-period costs and an unweighted arithmetic average of commodity prices in effect on the first day of each of the previous 12 months held flat for the life of the production, except where prices are defined by contractual arrangements.
 
Any excess of the net book value of proved oil and gas properties, less related deferred income taxes, over the ceiling is charged to expense and reflected as additional DD&A in the statement of operations. The ceiling calculation is performed quarterly. During the years ended December 31, 2013 and 2012 there were no impairments resulting from the quarterly ceiling tests.
 
Proceeds from the sale or disposition of oil and gas properties are accounted for as a reduction to capitalized costs unless a significant portion (greater than 25%) of our reserve quantities are sold, in which case a gain or loss is recognized in income.
 
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.
 
Recent Issued Accounting Standards
 
See Note 1, Summary of Significant Accounting Policies - Recent Issued Accounting Standards, to our consolidated financial statements included in this report.
 
Effects of Inflation and Pricing
 
The oil and gas industry is very cyclical and the demand for goods and services of oil and gas field companies, suppliers and others associated with the industry puts extreme pressure on the economic stability and pricing structure within the industry. Material changes in prices impact revenue stream, estimates of future reserves, borrowing base calculations of bank loans and value of properties in purchase and sale transactions. Material changes in prices can impact the value of oil and gas companies and their ability to raise capital, borrow money and retain personnel. We anticipate business costs and the demand for services related to production and exploration will fluctuate while the commodity price for oil and gas remains volatile.
 
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
 
Not applicable.
 
 
36

 
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
 
Management Responsibility for Financial Information
 
We are responsible for the preparation, integrity and fair presentation of our financial statements and the other information that appears in this Annual Report on Form 10-K. The financial statements have been prepared in accordance with accounting principles generally accepted in the United States and include estimates based on our best judgment.
 
We maintain a comprehensive system of internal controls and procedures designed to provide reasonable assurance, at an appropriate cost-benefit relationship, that our financial information is accurate and reliable, our assets are safeguarded and our transactions are executed in accordance with established procedures.
 
L. L. Bradford, an independent registered public accounting firm, is retained to audit our consolidated financial statements. Its accompanying report is based on audits conducted in accordance with the standards of the Public Company Accounting Oversight Board (United States).
 
Our consolidated financial statements and notes thereto, and other information required by this Item 8 are included in this report beginning on page F-1.
 
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE.
 
None.
 
ITEM 9A. CONTROLS AND PROCEDURES.
 
Evaluation of Disclosure 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 13a-15(b). Based on the evaluation, Mr. Watson and Mr. Wright concluded that our disclosure controls and procedures are effective.
 
Management's Report on Internal Control over Financial Reporting
 
Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as is defined in the Securities Exchange Act of 1934. These internal controls are designed to provide reasonable assurance that the reported financial information is presented fairly, that disclosures are adequate and that the judgments inherent in the preparation of financial statements are reasonable. There are inherent limitations in the effectiveness of any system of internal control, including the possibility of human error and overriding of controls. Consequently, an effective internal control system can only provide reasonable, not absolute, assurance, with respect to reporting financial information.
 
Management conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework and criteria established in Internal Control - Integrated Framework, issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this evaluation, management concluded that our internal control over financial reporting was effective as of December 31, 2013.
 
Changes in Internal Control over Financial Reporting
 
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.
 
ITEM 9B. OTHER INFORMATION.
 
None.
 
PART III
 
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE.
 
The following table sets forth certain information regarding our current directors and executive officers. Our executive officers serve one-year terms.
 
Name
 
Age
 
Position
 
Board Committee(s)
Robert G. Watson, Jr.
 
37
 
President, Chief Executive Officer, and Director
 
None
Ryan A. Lowe
 
33
 
Director, Senior Vice President of Corporate Development
 
Audit
James G. Miller
 
65
 
Director
 
Audit, Compensation, Nominating
Richard E. Menchaca
 
45
 
Director
 
Audit, Compensation, Nominating
Lance W. Helfert
 
40
 
Director
 
Compensation, Nominating
Douglas M. Wright
 
61
 
Chief Financial Officer
 
None
David L. Kunovic
 
62
 
Executive Vice President, Exploration
 
None
 
 
37

 
Robert G. Watson, Jr.  Mr. Watson has served as President, Chief Executive Officer, and Secretary since December 31, 2010. Prior to joining EnerJex, he co-founded Black Sable Energy, LLC, approximately 5 years ago and served as its Chief Executive Officer. During his tenure at Black Sable, Mr. Watson was responsible for the company's acquisition and development of two grassroots oil projects in South Texas, both of which were partnered with larger oil and gas companies on a promoted basis. Prior to founding Black Sable, he was a Senior Associate at American Capital, Ltd. (NASDAQ: ACAS), a publicly traded private equity firm and global asset manager with more than $100 billion of total assets under management. Mr. Watson began his career in the Energy Investment Banking Group at CIBC World Markets and subsequently founded and served as the Managing Partner of Centerra Energy Partners, LLC. Mr. Watson's experience in acquiring and developing oil projects, his knowledge of financial markets, and his managerial and leadership abilities that he has demonstrated while serving as the Company's President and Chief Executive Officer and as chief executive officer for Black Sable Energy, LLC, led to the board's conclusion that he should serve as a director.
 
Ryan A. Lowe. Mr. Lowe has served as Senior Vice President of Corporate Development since 2011 and as a Director since December 31, 2010. Mr. Lowe is the Chief Investment Officer of West Coast Asset Management, Inc., a registered investment advisor that has invested more than $200 million in the oil and gas industry on behalf of its principals and clients since 2000. He formerly served as a director and chairman of the audit committee for Black Raven Energy, Inc., before we acquired Black Raven in September 2013. Mr. Lowe is a CFA charterholder. His experience in business and finance and his experience as a director and chairman of the audit committee of a company in the oil and gas industry led to the board's conclusion that he should serve as a director.
 
James G. Miller. Mr. Miller has served as a Director since December 31, 2010. Mr. Miller retired in 2002 after serving as the Chief Executive Officer of Utilicorp United, Inc.'s business unit responsible for the company's electricity generation and electric and natural gas transmission and distribution businesses, which served 1.3 million customers in seven mid-continent states. Utilicorp traded on the New York Stock Exchange, and the company was renamed Aquila in 2002. In 2007, Utilicorp's electricity assets in northwest Missouri were acquired by Great Plains Energy Incorporated (NYSE: GXP) for $1.7 billion, and its natural gas properties and other assets were acquired by Black Hills Corporation (NYSE: BKH) for $940 million. Mr. Miller joined Utilicorp in 1989 through its acquisition of Michigan Gas Utilities, for which he served as the president from 1983 to 1991. Mr. Miller also is a member of the board of directors of Guardian 8 Holdings. He currently serves as Chairman of The Nature Conservancy, Missouri Chapter, for which he has been a Trustee for the past 12 years. Mr. Miller's experience as a chief executive officer and president, as well as his experience from serving as a board member, led to the board's conclusion that he should serve as a director.
 
Lance W. Helfert. Mr. Helfert has served as a Director since December 31, 2010. Mr. Helfert is the President and a co-founder of West Coast Asset Management, Inc. (WCAM), a registered investment advisor located in Montecito, California. Prior to co-founding WCAM, he managed a portfolio at Wilshire Associates and was involved in a full range of financial strategies at M.L. Stern & Co. Mr. Helfert is a co-author of The Entrepreneurial Investor: The Art, Science and Business of Value Investing, a book published by John Wiley & Sons. He has been featured in Kiplinger's Personal Finance, Forbes, Barron's, Fortune Magazine, and the Market Watch for his unique market prospective. In addition, Mr. Helfert has been a frequent guest commentator on CNBC and the Fox Business networks. Mr. Helfert has also served on the board of directors for Junior Achievement of Southern California and the Tri-Counties Make-A-Wish Foundation. Mr. Helfert's knowledge of the capital markets, coupled with his knowledge and understanding of finance and financial reporting led the board to conclude that he should serve as a director.
 
Richard E. Menchaca. Mr. Menchaca has been a Director since June 6, 2013. Mr. Menchaca attended the University of Texas at Arlington where he received a BBA in Finance and pursued a MBA in Finance, and received a Graduate Degree from the SMU Southwestern School of Banking. Mr. Menchaca spent 18 years in the corporate banking industry with First Republic Bank (n.k.a. Bank of America), Bank One in Fort Worth and Fuji Bank, and Guaranty Bank in Houston. While at Guaranty Bank, Mr. Menchaca was one of the founding members of the Oil and Gas Banking Group, and within 18 months of its formation became the most profitable lending group within the bank with over $900,000,000 of loans to oil and gas industry. Mr. Menchaca was the principal and founder of Petras Energy, LLC, an oil and gas production company based in Midland, Texas. The company was successfully sold in January 2006. Mr. Menchaca has been the founder and principal of several privately owned oil and gas companies with operations in Texas, Oklahoma and Louisiana. Since May 2010, Mr. Menchaca currently presides as President and Chief Executive Officer of Petroflow Energy Corporation, a Tulsa-based exploration and production company, as well as a member of its board of directors since June 2009. Mr. Menchaca also serves as a director on the board of Fortis Plastics and a non-profit organization based in Houston, Texas.
 
Douglas M. Wright. Mr. Wright has been Chief Financial Officer since August 2012. Mr. Wright served as Corporate Controller and Chief Accounting Officer of Nations Petroleum Company Ltd. from 2006 to August 2012. Prior to Nations, he served as a Manager of Financial Reporting for Noble Energy (contract). In 1996, he founded Fashion Investments Inc. and served as its Chief Executive Officer until 2005. Fashion Investments owned and operated the largest independent commercial laundry facility in Colorado Springs. From 1986 to 1996, Mr. Wright worked for Oryx Energy Company in various capacities including, Manager, Financial Reporting, Manager, Strategic Planning and General Auditor. From 1977 to 1986, he served as a Senior Manager with Deloitte & Touche. Mr. Wright is a Certified Public Accountant and earned his B.A. from the University of Pittsburgh and his MBA from the University of North Texas.
 
David L. Kunovic.  Mr. Kunovic joined Black Raven Energy, Inc. on October 1, 2010 as Vice President of Exploration managing all phases of geologic and geophysical exploration and development activity for the company. Mr. Kunovic has over 34 years of experience as an exploration geologist, including 11 years as President of Kachina Energy, Inc., managing geologic and geophysical projects for several independent oil companies. He has also held positions as Vice President of Exploration for Canyon Energy, Inc. from 1994 – 2000 managing all exploration activities for the Rocky Mountain region; Petroleum Incorporated from 1991 – 1994 as Exploration Manager for all US exploration; Newport Exploration from 1984 – 1991 as Exploration Manager Rocky Mountain region; Apache Corporation from 1980 – 1984 as Senior Geologist working the Powder River and Denver Basins and Union Texas Petroleum from 1978-1980 as geologist — Rocky Mountain Basins. Mr. Kunovic holds a Bachelor's degree in Geology from the University of Colorado and also completed Masters level course work in Environmental Engineering and Groundwater at the University of Colorado.
 
Involvement in Certain Legal Proceedings
 
On December 23, 2013, the United States Securities and Exchange Commission (SEC) entered an order in an administrative proceeding, In the Matter of West Coast Asset Management, Inc., and Lance W. Helfert, File No. 3-15660. In that matter, WCAM and Mr. Helfert, without admitting or denying the allegations, entered into a settlement with the SEC regarding certain negligence-based violations of Section 17(a)(2) of the Securities Act and Sections 206(2) and 206(4) of the Investment Advisers Act of 1940 (the Advisers Act). The matter was based upon an untrue statement made in an email that Mr. Helfert sent, in 2008, to an adviser to a prospective investor in an investment fund that was managed by WCAM. The SEC ordered WCAM and Mr. Helfert to cease and desist from committing or causing further such negligence-based violations, censured them, ordered WCAM to disgorge certain fees, and ordered WCAM and Mr. Helfert each to pay a monetary fine. WCAM and Mr. Helfert timely paid those amounts to the SEC.
 
Except as set forth above, none of our executive officers or directors has been the subject of any Order, Judgment, or Decree of any Court of competent jurisdiction, or any regulatory agency permanently or temporarily enjoining, barring suspending or otherwise limiting him from acting as an investment advisor, underwriter, broker or dealer in the securities industry, or as an affiliated person, director or employee of an investment company, bank, savings and loan association, or insurance company or from engaging in or continuing any conduct or practice in connection with any such activity or in connection with the purchase or sale of any securities.
 
 
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None of our executive officers or directors has been convicted in any criminal proceeding (excluding traffic violations) or is the subject of a criminal proceeding, which is currently pending.
 
Section 16(a) Beneficial Ownership Reporting Compliance
  
Section 16(a) of the Securities Exchange Act of 1934, as amended (the "Exchange Act"), requires our executive officers and directors, and persons who beneficially own more than ten percent of our common stock, to file initial reports of ownership and reports of changes in ownership with the SEC. Executive officers, directors and greater than ten percent beneficial owners are required by SEC regulations to furnish us with copies of all Section 16(a) forms they file. Based upon a review of the copies of such forms furnished to us and written representations from our executive officers and directors, we believe that as of the date of this report they were all current in their 16(a) reports and that all reports were filed on a timely basis other than directors Ryan A. Lowe and Lance W. Helfert, who each filed a late form 4 on October 31 and November 5, 2013 respectively.  Each late filing was with regard to one transaction.
 
Code of Ethics
 
We have adopted a Code of Business Conduct and Ethics that applies to all of our directors, officers and employees, as well as to directors, officers and employees of each subsidiary of the Company. Our Code of Ethics was filed as Exhibit 99.6 to the Annual Report on Form 10-KSB for the year ended March 31, 2007 which was filed on June 13, 2007. A copy of our Code of Business Conduct and Ethics will be provided to any person, without charge, upon request. It is available on our website: enerjex.com, or you may contact Robert G. Watson at 210-451-5545 to request a copy of the Code or send your request to EnerJex Resources, Inc., Attn: Robert G. Watson, 4040 Broadway, Suite 508, San Antonio, Texas 78209. If any substantive amendments are made to the Code of Business Conduct and Ethics or if we grant any waiver, including any implicit waiver, from a provision of the Code to any of our officers and directors, we will disclose the nature of such amendment or waiver in a report on Form 8-K.
 
 
Audit Committee
 
 
Our Board of Directors has a standing audit committee.
 
 Our Audit Committee consists of two independent directors, James G. Miller and Richard E. Menchaca and one non independent director, Ryan A. Lowe, each of whom has been selected for membership on the Audit Committee by the Board of Directors based on the board's determination that each is fully qualified, through a range of education, experiences in business and executive leadership and service on boards of directors, and an understanding of generally accepted accounting principles, to oversee our internal audit function, assess and select independent auditors, and oversee our financial reporting processes and overall risk management. The Audit Committee has the authority to seek advice and assistance from outside legal, accounting or other advisors and exercises such authority as it deems necessary. The full text of the charter of the Audit Committee can be found in the investor section of our website at www.enerjex.com.
 
The board has determined that James G. Miller and Richard E. Menchaca are financial experts as that term is used in Item 407(d)(5)(ii) of Regulation S-K promulgated under the Securities Exchange Act.
 
Although the Company is traded on OTCBB, the board of directors reviews the American Stock Exchange Company Guide listing standards on an annual basis. Mr. Miller and Mr. Menchaca qualify as independent directors as defined by Section 803 of the American Stock Exchange Company Guide and Section 10A (m) of the Securities Exchange Act of 1934, and Rule 10A-3 thereunder. In light of Mr. Lowe's relationship with West Coast Opportunity Fund, LLC, a significant shareholder, and his position as Senior Vice President of Corporate Development, our board of directors has determined that he is not independent (as independence is defined in Section 803 of the American Stock Exchange Company Guide).
 
The Audit Committee met four times during the fiscal year ended December 31, 2013.
 
 
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ITEM 11. EXECUTIVE COMPENSATION.
 
The following table sets forth summary compensation information for the fiscal year ended December 31, 2013, and the year ended December 31, 2012, for our chief executive officer, chief financial officer and other highly compensated executive officers. We did not have any other executive officers as of the end of 2012 or 2013, whose total compensation exceeded $100,000. We refer to these persons as our named executive officers elsewhere in this report.
 
Summary Compensation Table
 
Name and Principal Position
 
Fiscal
Year
 
Salary
($)
 
Bonus
($)
 
Stock
Awards
($)
 
Option
Awards
($)
 
All Other
Compensation
($)
 
Total
($)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Robert G. Watson, Jr.
 
2013
 
$
225,000
 
$
35,000
 
$
-
 
$
76,900
 
$
-
 
$
336,900
 
President, Chief Executive Officer
 
2012
 
$
150,000
 
$
-
 
$
-
 
$
76,900
 
$
-
 
$
226,900
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Douglas M. Wright(1)
 
2013
 
$
150,000
 
$
-
 
$
132,000
 
$
53,200
 
$
-
 
$
335,200
 
Chief Financial Officer
 
2012
 
$
140,000
 
$
-
 
$
25,000
 
$
17,700
 
$
-
 
$
182,700
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
David L. Kunovic(2)
 
2013
 
$
160,000
 
$
-
 
$
-
 
$
23,700
 
$
-
 
$
183,700
 
Executive Vice President, Exploration
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Ryan A. Lowe
 
2013
 
$
80,000
 
$
25,000
 
$
-
 
$
-
 
$
-
 
$
105,000
 
Senior Vice President of Corporate Development
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(1) Douglas M. Wright was hired on August 15, 2012, and the compensation figures in the table above represent his annual compensation rates.
(2)  David L. Kunovic was hired on September 27, 2013, and the compensation figures in the table above represent his annual compensation rates.
 
Outstanding Equity Awards at 2013 Fiscal Year-End
 
The following table lists the outstanding equity incentive awards held by our named executive officers as of the fiscal year ended December 31, 2013.
 
 
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Option Awards
 
 
 
 
 
 
Number of
 
Number of
 
Number of
 
 
 
 
 
 
 
 
 
 
 
 
Securities
 
Securities
 
Securities
 
 
 
 
 
 
 
 
&