UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
  
FORM 10-K
 
þ
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934
 
For the fiscal year ended December 31, 2013
 
o
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 
For the transition period from              to
 
Commission file number: 001-35922
 
PEDEVCO Corp.
(Exact Name of Registrant as Specified in Its Charter)
 
Texas
 
22-3755993
(State or other jurisdiction of incorporation
 or organization)
 
(IRS Employer Identification No.)
     
 
4125 Blackhawk Plaza Circle, Suite 201
Danville, California 94506
(Address of Principal Executive Offices)
 
(855) 733 2685
(Registrant’s Telephone Number,
Including Area Code)
 
Securities registered pursuant to Section 12(b) of the Act:
Common Stock, $0.001 par value per share                                                                                                                     NYSE MKT
 
Securities registered pursuant to Section 12(g) of the Act:
None.
 
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes o No þ
  
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes o No þ
  
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ No o
  
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes þ No o
  
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of the 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. o
  
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
o
Accelerated filer
o
Non-accelerated filer
o
Smaller reporting company
þ
 
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No þ
 
The aggregate market value of the voting and non-voting common equity held by non-affiliates of the registrant as of June 28, 2013 based upon the closing price reported on such date was approximately $44,437,679. Shares of voting stock held by each officer and director and by each person who, as of June 28, 2013, may be deemed to have beneficially owned more than 10% of the outstanding voting stock have been excluded. This determination of affiliate status is not necessarily a conclusive determination of affiliate status for any other purpose.
 
As of March 28, 2014, 26,539,013 shares of the registrant’s common stock, $0.001 par value per share, were outstanding
 
 


 
 
 
 
 
Table of Contents
 
   
Page
 
PART I
 
Item 1
Risk Factors
   
34
 
 
Unresolved Staff Comments
   
59
 
Properties
   
59
 
 
Legal Proceedings
   
65
 
 
Mine Safety Disclosures
    65  
   
PART II
 
 
Market For Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
   
66
 
 
Selected Financial Data
   
71
 
 
Management’s Discussion and Analysis of Financial Condition and Results of Operations
   
72
 
 
Quantitative and Qualitative Disclosure About Market Risk
   
83
 
 
Financial Statements and Supplementary Data
   
83
 
 
Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
   
83
 
 
Controls and Procedures
   
83
 
 
Other Information
   
84
 
           
PART III
 
 
Directors, Executive Officers and Corporate Governance
   
85
 
 
Executive Compensation
   
91
 
 
Security Ownership of Certain Beneficial Owners and Management and Related  Stockholder Matters
   
101
 
 
Certain Relationships and Related Transactions, and Director Independence
   
103
 
 
Principal Accounting Fees and Services
   
106
 
           
PART IV
 
 
Exhibits and Financial Statement Schedules
   
F-1
 
 
 
 
 
2

 
 
Forward Looking Statements
 
ALL STATEMENTS IN THIS DISCUSSION THAT ARE NOT HISTORICAL ARE FORWARD-LOOKING STATEMENTS. STATEMENTS PRECEDED BY, FOLLOWED BY OR THAT OTHERWISE INCLUDE THE WORDS "BELIEVES," "EXPECTS," "ANTICIPATES," "INTENDS,” "PROJECTS," "ESTIMATES,” "PLANS," "MAY INCREASE," "MAY FLUCTUATE" AND SIMILAR EXPRESSIONS OR FUTURE OR CONDITIONAL VERBS SUCH AS "SHOULD", "WOULD", "MAY" AND "COULD" ARE GENERALLY FORWARD-LOOKING IN NATURE AND NOT HISTORICAL FACTS. THESE FORWARD-LOOKING STATEMENTS WERE BASED ON VARIOUS FACTORS AND WERE DERIVED UTILIZING NUMEROUS IMPORTANT ASSUMPTIONS AND OTHER IMPORTANT FACTORS THAT COULD CAUSE ACTUAL RESULTS TO DIFFER MATERIALLY FROM THOSE IN THE FORWARD-LOOKING STATEMENTS. FORWARD-LOOKING STATEMENTS INCLUDE THE INFORMATION CONCERNING OUR FUTURE FINANCIAL PERFORMANCE, BUSINESS STRATEGY, PROJECTED PLANS AND OBJECTIVES. THESE FACTORS INCLUDE, AMONG OTHERS, THE FACTORS SET FORTH BELOW UNDER THE HEADING "RISK FACTORS." ALTHOUGH WE BELIEVE THAT THE EXPECTATIONS REFLECTED IN THE FORWARD-LOOKING STATEMENTS ARE REASONABLE, WE CANNOT GUARANTEE FUTURE RESULTS, LEVELS OF ACTIVITY, PERFORMANCE OR ACHIEVEMENTS. MOST OF THESE FACTORS ARE DIFFICULT TO PREDICT ACCURATELY AND ARE GENERALLY BEYOND OUR CONTROL. WE ARE UNDER NO OBLIGATION TO PUBLICLY UPDATE ANY OF THE FORWARD-LOOKING STATEMENTS TO REFLECT EVENTS OR CIRCUMSTANCES AFTER THE DATE HEREOF OR TO REFLECT THE OCCURRENCE OF UNANTICIPATED EVENTS. READERS ARE CAUTIONED NOT TO PLACE UNDUE RELIANCE ON THESE FORWARD-LOOKING STATEMENTS. REFERENCES IN THIS FORM 10-K, UNLESS ANOTHER DATE IS STATED, ARE TO DECEMBER 31, 2013. AS USED HEREIN, THE “COMPANY,” “WE,” “US,” “OUR” AND WORDS OF SIMILAR MEANING REFER TO PEDEVCO CORP. (D/B/A PACIFIC ENERGY DEVELOPMENT), WHICH WAS KNOWN AS BLAST ENERGY SERVICES, INC. UNTIL JULY 30, 2012, AND ITS WHOLLY-OWNED AND PARTIALLY-OWNED SUBSIDIARIES, BLAST AFJ, INC. PACIFIC ENERGY DEVELOPMENT CORP., CONDOR ENERGY TECHNOLOGY LLC, WHITE HAWK PETROLEUM, LLC, PACIFIC ENERGY TECHNOLOGY SERVICES, LLC, PACIFIC ENERGY & RARE EARTH LIMITED, BLACKHAWK ENERGY LIMITED, RED HAWK PETROLEUM, LLC, AND PACIFIC ENERGY DEVELOPMENT MSL LLC, UNLESS OTHERWISE STATED.
 
This Annual Report on Form 10-K (this “Annual Report”) may contain forward-looking statements which are subject to a number of risks and uncertainties, many of which are beyond our control. All statements, other than statements of historical fact included in this Annual Report, regarding our strategy, future operations, financial position, estimated revenues and losses, projected costs and cash flows, prospects, plans and objectives of management are forward-looking statements. When used in this Annual Report, the words “could,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “may,” “should,” “continue,” “predict,” “potential,” “project” and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words.
 
Forward-looking statements may include statements about our:
 
business strategy;
reserves;
technology;
cash flows and liquidity;
financial strategy, budget, projections and operating results;
oil and natural gas realized prices;
timing and amount of future production of oil and natural gas;
availability of oil field labor;
the amount, nature and timing of capital expenditures, including future exploration and development costs;
availability and terms of capital;
drilling of wells;
government regulation and taxation of the oil and natural gas industry;
marketing of oil and natural gas;
exploitation projects or property acquisitions;
costs of exploiting and developing our properties and conducting other operations;
general economic conditions;
competition in the oil and natural gas industry;
effectiveness of our risk management and hedging activities;
environmental liabilities;
counterparty credit risk;
developments in oil-producing and natural gas-producing countries;
future operating results;
estimated future reserves and the present value of such reserves; and
plans, objectives, expectations and intentions contained in this Annual Report that are not historical.
 
 

 
 
3

 
 
All forward-looking statements speak only at the date of the filing of this Annual Report. The reader should not place undue reliance on these forward-looking statements. Although we believe that our plans, intentions and expectations reflected in or suggested by the forward-looking statements we make in this Annual Report are reasonable, we can give no assurance that these plans, intentions or expectations will be achieved. We disclose important factors that could cause our actual results to differ materially from our expectations under “Risk Factors” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and elsewhere in this Annual Report. These cautionary statements qualify all forward-looking statements attributable to us or persons acting on our behalf. We do not undertake any obligation to update or revise publicly any forward-looking statements except as required by law, including the securities laws of the United States and the rules and regulations of the SEC.
 
Certain abbreviations and oil and gas industry terms used throughout this Annual Report are described and defined in greater detail under “Glossary of Oil And Natural Gas Terms” on page 31, and readers are encouraged to review that section.
 
Available Information
 
We are subject to the information and reporting requirements of the Securities Exchange Act of 1934, or the Exchange Act, under which we file periodic reports, proxy and information statements and other information with the United States Securities and Exchange Commission, or SEC. Copies of the reports, proxy statements and other information may be examined without charge at the Public Reference Room of the SEC, 100 F Street, N.E., Room 1580, Washington, D.C. 20549, or on the Internet at http://www.sec.gov. Copies of all or a portion of such materials can be obtained from the Public Reference Room of the SEC upon payment of prescribed fees. Please call the SEC at 1-800-SEC-0330 for further information about the Public Reference Room.
 
Financial and other information about PEDEVCO Corp. is available on our website (www.pedevco.com). Information on our website is not incorporated by reference into this report. We make available on our website, free of charge, copies of our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act as soon as reasonably practicable after filing such material electronically or otherwise furnishing it to the SEC.
 
 
 
 
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PART I
 
ITEM 1. BUSINESS.
 
History
 
We were originally incorporated in September 2000 as Rocker & Spike Entertainment, Inc. In January 2001 we changed our name to Reconstruction Data Group, Inc., and in April 2003 we changed our name to Verdisys, Inc. and were engaged in the business of providing satellite services to agribusiness. In June 2005, we changed our name to Blast Energy Services, Inc. (“Blast”) to reflect our new focus on the energy services business.
 
During 2010, Blast's management chose to change the direction of the Company to attempt to generate operating capital from investing in oil producing properties. As a part of this shift in strategy, in September 2010, with an effective date of October 1, 2010, we closed on the acquisition of oil and gas interests in the North Sugar Valley Field located in Matagorda County, Texas, and we decided to divest our satellite services business unit, which we sold in December 2010.
 
On July 27, 2012, we acquired through a reverse acquisition, Pacific Energy Development Corp., a privately held Nevada corporation, which we refer to as Pacific Energy Development. As described below, pursuant to the acquisition, the shareholders of Pacific Energy Development gained control of approximately 95% of the voting securities of our company. Since the transaction resulted in a change of control, Pacific Energy Development is the acquirer for accounting purposes. In connection with the merger, which we refer to as the Pacific Energy Development merger, Pacific Energy Development became our wholly-owned subsidiary and we changed our name from Blast Energy Services, Inc. to PEDEVCO Corp. Following the merger, we refocused our business plan on the acquisition, exploration, development and production of oil and natural gas resources in the United States, with a primary focus on oil and natural gas shale plays and a secondary focus on conventional oil and natural gas plays.
 
Business Operations
 
Overview
 
We are an energy company engaged primarily in the acquisition, exploration, development and production of oil and natural gas shale plays in the United States, and a secondary focus on conventional oil and natural gas plays.  Our current operations are located primarily in the Niobrara Shale play in the Denver-Julesburg Basin (the “DJ Basin”) in Weld and Morgan Counties, Colorado, and the Mississippian Lime play in Comanche, Harper, Barber and Kiowa Counties, Kansas.  In March 2014, we expanded our DJ Basin position into the Wattenberg and Wattenberg Extension through the acquisition of additional oil and gas working interests from Continental Resources, Inc. (“Continental”), which includes approximately 14,000 net operated acres and interests in 40 wells located in Weld and Morgan Counties, Colorado, which we refer to as the “Wattenberg Asset.”  We also hold an interest in the North Sugar Valley Field in Matagorda County, Texas, though we consider this a non-core asset.   We have entered into agreements to acquire an approximately 34% indirect interest (of which we are required to assign 50% of such interest, or 17%, to RJ Resources, as discussed below) in a company holding an exploration agreement covering an approximately 380,000 acre oil and gas producing asset located in the Pre-Caspian Basin in Kazakhstan, which we plan to close upon receipt of required approvals from the Kazakhstan government, anticipated to be received no later than the third quarter of 2014, as described in greater detail below in “Recent Developments” – “Kazakhstan Acquisition”. 
 
We have approximately 16,379 net acres of oil and gas properties in the DJ Basin, including 13,995 net acres in our recently acquired Wattenberg Asset, and 2,384 net acres of oil and gas properties in our Niobrara Asset. Red Hawk holds our Wattenberg Asset with interests in 40 wells, 11 of which are operated by Red Hawk, 14 are non-operated, and Red Hawk has an after-payout interest in 15, with a two week average production from the 11 operated wells since their acquisition on March 7, 2014 of approximately 434 gross BOE per day, which does not include production from two of the wells which are currently undergoing repair.  We estimate that once we bring these two wells back on production, the production from the 11 operated wells will be 504 gross BOE per day.  We have not yet received enough information in regards to the 14 non-operated wells to estimate their current production.  Condor Energy Technology LLC (“Condor”), in which we own a 20% interest and manage with an affiliate of MIE Holdings Corporation (described in greater detail below under “Strategic Alliances” – “MIE Holdings”), operates our Niobrara Asset, including five wells in the Niobrara Asset with daily production in the month of February 2014 of approximately 240 BOE (63 BOE net). We believe our current Wattenberg Asset could contain approximately a gross total of 1,256 gross (175 net) drilling locations, and our Niobrara Asset could contain a gross total of 212 gross (81 net) drilling locations, for a combined total of 1,468 gross (256 net) possible drilling locations in the DJ Basin, based on 40 and 80 acre spacing.
 
 
 
5

 
 
We have approximately 7,006 gross (3,443 net acres) of oil and gas properties in the Mississippian Lime play, which we own an average of 49% working interest in and operate (the “Mississippian Asset”). We believe the Mississippian Asset could contain a total of 42 gross (21 net) drilling locations, based on 160 acre spacing.
 
We have also announced the entry into Kazakhstan through an agreement whereby we plan to acquire an approximate 34% indirect interest in Aral Petroleum Capital Limited Partnership (“Aral”), a Kazakhstan entity which holds a 100% operated working interest in a production license covering the contract area issued by the Republic of Kazakhstan that expires in 2034 in western Kazakhstan (the “Contract Area”), from Asia Sixth Energy Resources Limited (“Asia Sixth”), which Contract Area covers 380,000 acres within the North Block located in the Pre-Caspian Basin.  Under the agreement, we plan to acquire an interest in Aral through the acquisition of a 51% interest in Asia Sixth, by way of subscription of shares of Asia Sixth, which in turn currently holds a 60% controlling interest in Aral.  Asia Sixth’s interest in Aral is scheduled to increase to 66.5% following the completion of certain transactions to occur between Asia Sixth and Asia Sixth’s partner in Aral that currently holds the remaining 40% interest in Aral (the “Aral Transactions”).  Upon closing and completion of the Aral Transactions, Aral will be owned 66.5% by Asia Sixth.  We have also entered into an agreement with our strategic partner, RJ Resources Corp. (“RJ Resources”), pursuant to which we have agreed, at the option of RJ Resources, to either (a) provide for the issuance of the share certificate representing the shares of capital stock due from Asia Sixth representing 51% of the total issued and outstanding share capital of Asia Sixth which we have the right to purchase from Asia Sixth, to a Delaware limited liability company to be formed by us (such company, the “Nominee”) and to convey to RJ Resources fifty percent (50%) of the limited liability company interests issued by the Nominee or (b) provide for fifty percent (50%) of such Asia Sixth shares to be issued directly to RJ Resources or its designee.  Upon the closing and completion of these contemplated transactions, the Company, through its ownership in Asia Sixth, will own an approximate 17% beneficial interest in Aral.
 
Business Strategy
 
Our goal is to increase shareholder value by building reserves, production and cash flows at an attractive return on invested capital.  We intend to primarily engage in the acquisition, exploration, development and production of oil and natural gas resources in the United States, primarily shale oil and natural gas and secondarily conventional oil and natural gas opportunities. We intend to achieve our objectives as follows:
 
Aggressively drill and develop our existing acreage positions. We plan to aggressively drill our core assets, drilling approximately 11 gross (4 net) wells on the Wattenberg Asset, two gross (0.4 net) wells on the Niobrara Asset, and three gross (1.5 net) wells in the Mississippian Lime for a total of approximately 16 gross (6 net) wells through the end of 2014, funding permitting.  We believe our planned drilling schedules will allow us to begin converting our undeveloped acreage to developed acreage with production, cash flow and proved reserves.
 
Acquire additional oil and natural gas opportunities. We plan to leverage our relationships and experienced acquisition team to pursue additional leasehold assets in our core areas as well as continue to pursue additional oil and natural gas interests.   As described above, in March 2014 we expanded our DJ Basin position into the Wattenberg and Wattenberg Extension through the acquisition of additional oil and gas working interests from Continental, which includes approximately 14,000 net operated acres and interests in 40 wells located in Weld and Morgan Counties, Colorado.  We also have an agreement in place (subject to customary closing conditions including required government approvals) for the acquisition of an approximately 34% indirect interest (including 50% (or 17% of the interest) that we are obligated to assign to RJ Resources, as discussed above) in Aral (as described below under “Recent Developments” – “Kazakhstan Acquisition”), a Kazakhstan entity which holds a 100% operated interest in a company holding an exploration agreement covering a contract area issued by the Republic of Kazakhstan in western Kazakhstan from Asia Sixth, which Contract Area covers approximately 380,000 acres within the North Block located in the Pre-Caspian Basin.  This basin is one of the largest currently producing basins in Kazakhstan.  We plan to close this acquisition upon receipt of required approvals from the government of Kazakhstan, anticipated to be received no later than the third quarter of 2014.  We are also exploring additional oil and natural gas opportunities in our core areas, and in other areas of the United States and Asia.
 
Leverage expertise of management and external resources.  We plan to focus on profitable investments that provide a platform for our management expertise.  We have also engaged South Texas Reservoir Alliance LLC, or STXRA, and other industry veterans as key advisors, and in September 2012 we jointly formed Pacific Energy Technology Services, LLC with STXRA, for the purpose of providing acquisition, engineering and oil drilling and completion technology services to third parties in the United States and Pacific Rim countries. As necessary, we intend to enlist external resources and talent to operate and manage our properties during peak operations.
 
Engage and leverage strategic alliances in Asia. We have already entered into a strategic alliance with MIE Holdings, and we intend to partner with additional Chinese energy companies to (a) acquire producing oil field assets that could provide cash flow to help fund our U.S. development program, (b) provide technical horizontal drilling expertise for a fee, thus acquiring valuable experience and data in regards to the China shale formations and successful engineering techniques, and (c) acquire interests in Asian producing assets.
 
 
 
6

 
 
Limit exposure and increase diversification through engaging in joint ventures.  We own various oil and natural gas interests through joint ventures with MIE Holdings, and may in the future enter into similar joint ventures with respect to other oil and gas interests either with MIE Holdings or other partners.  We believe that conducting many of our activities through partially owned joint ventures will enable us to lower our risk exposure while increasing our ability to invest in multiple ventures.
 
Leverage partnerships and our drilling facility for financial strength and flexibility. Our joint venture partner, MIE Holdings, has been a strong financial partner. They have loaned us $432,433 toward the acquisition of the Mississippian Asset, which we repaid in March 2014, and $6.17 million through a short-term note to fund operations and development of the Niobrara Asset.  We also recently obtained a $15.5 million drilling facility from RJ Resources for the development of our Wattenberg Asset, the drawdown of which is subject to certain requirements, and which is described in greater detail below under “Recent Developments” – “Note Purchase Agreement and Sale of Secured Promissory Notes”.  We expect that proceeds from future equity offerings, internally generated cash flow, our new drilling facility, and future debt financings will provide us with the financial resources to pay off these amounts due MIE Holdings and RJ Resources and pursue our leasing and drilling and development programs through 2014.  We have also met with financial institutions introduced to us by MIE Holdings and Casimir Capital L.P., our financial advisor, seeking to secure a line of credit or reserve-based lending facilities that could be used for both acquisition and development costs where needed.  We cannot assure you, however, that we will be able to secure any such financing on terms acceptable to us, on a timely basis, or at all.

Competition
 
The oil and natural gas industry is highly competitive. We compete and will continue to compete with major and independent oil and natural gas companies for exploration opportunities, acreage and property acquisitions. We also compete for drilling rig contracts and other equipment and labor required to drill, operate and develop our properties. Most of our competitors have substantially greater financial resources, staffs, facilities and other resources than we have. In addition, larger competitors may be able to absorb the burden of any changes in federal, state and local laws and regulations more easily than we can, which would adversely affect our competitive position. These competitors may be able to pay more for drilling rigs or exploratory prospects and productive oil and natural gas properties and may be able to define, evaluate, bid for and purchase a greater number of properties and prospects than we can. Our competitors may also be able to afford to purchase and operate their own drilling rigs.
 
Our ability to drill and explore for oil and natural gas and to acquire properties will depend upon our ability to conduct operations, to evaluate and select suitable properties and to consummate transactions in this highly competitive environment. Many of our competitors have a longer history of operations than we have, and most of them have also demonstrated the ability to operate through industry cycles.
 
Competitive Strengths
 
We believe we are well positioned to successfully execute our business strategies and achieve our business objectives because of the following competitive strengths:
 
Management. We have assembled management teams at our Company and joint venture partnerships with extensive experience in the fields of international business development, petroleum engineering, geology, petroleum field development and production, petroleum operations and finance. Several members of the team developed and ran what we believe were successful energy ventures that were commercialized at Texaco, CAMAC Energy Inc., and Rosetta Resources, while members of our team at Condor have drilled and presently manage over 2,000 oil wells in the Pacific Rim and Kazakhstan. We believe that our management team is highly qualified to identify, acquire and exploit energy resources both in the U.S. and Pacific Rim countries, particularly China.
 
Our management team is headed by our President and Chief Executive Officer, Frank C. Ingriselli, an international oil and gas industry veteran with over 34 years of experience in the energy industry, including as the President of Texaco International Operations Inc., President and Chief Executive Officer of Timan Pechora Company, President of Texaco Technology Ventures, and President, Chief Executive Officer and founder of CAMAC Energy Inc. Our management team also includes Chief Financial Officer and Executive Vice President Michael L. Peterson, who brings extensive experience in the energy, corporate finance and securities sectors, including as a Vice President of Goldman Sachs & Co., Chairman and Chief Executive Officer of Nevo Energy, Inc. (formerly Solargen Energy, Inc.), and a former director of Aemetis, Inc. (formerly AE Biofuels Inc.). In addition, our Senior Vice President and Managing Director, Jamie Tseng, has over 25 years of financial management and operations experience and was a co-founder of CAMAC Energy Inc., and our Executive Vice President and General Counsel, Clark R. Moore, has nearly 10 years of energy industry experience, and formerly served as acting general counsel of CAMAC Energy Inc.
 
 
 
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Key Advisors. Our key advisors include STXRA and other industry veterans. According to STXRA, the STXRA team has experience in drilling and completing horizontal wells, including over 100 horizontal wells with lengths exceeding 4,000 feet from 2010 to 2013, as well as experience in both slick water and hybrid multi-stage hydraulic fracturing technologies and in the operation of shale wells and fields. We believe that our relationship with STXRA, both directly and through our jointly-owned services company, Pacific Energy Technology Services, LLC, will supplement the core competencies of our management team and provide us with petroleum and reservoir engineering, petrophysical, and operational competencies that will help us to evaluate, acquire, develop, and operate petroleum resources into the future.
 
Significant acreage positions and drilling potential. Without giving effect to the Kazakhstan acquisition opportunity, we have accumulated interests in a total of (19,784 net) acres in our existing core Wattenberg Asset, Niobrara Asset, and Mississippian Asset operating areas, each of which we believe represents a significant unconventional resource play. The majority of our interests are in or near areas of considerable activity by both major and independent operators, although such activity may not be indicative of our future operations. Based on our current acreage position, and without giving effect to the Kazakhstan acquisition opportunity, we estimate there could be up to 1,489 potential gross drilling locations on our acreage, and we anticipate drilling approximately 16 gross (6 net) wells through the end of 2014, leaving us a substantial drilling inventory for future years.
 
Marketing
 
The prices we receive for our oil and natural gas production fluctuate widely. Factors that cause price fluctuation include the level of demand for oil and natural gas, weather conditions, hurricanes in the Gulf Coast region, natural gas storage levels, domestic and foreign governmental regulations, the actions of OPEC (Organization of the Petroleum Exporting Countries), price and availability of alternative fuels, political conditions in oil and natural gas producing regions, the domestic and foreign supply of oil and natural gas, the price of foreign imports and overall economic conditions. Decreases in these commodity prices adversely affect the carrying value of our proved reserves and our revenues, profitability and cash flows. Short-term disruptions of our oil and natural gas production occur from time to time due to downstream pipeline system failure, capacity issues and scheduled maintenance, as well as maintenance and repairs involving our own well operations. These situations can curtail our production capabilities and ability to maintain a steady source of revenue for our company. In addition, demand for natural gas has historically been seasonal in nature, with peak demand and typically higher prices during the colder winter months. See “Risk Factors.”
 
Oil. Our crude oil is generally sold under short-term, extendable and cancellable agreements with unaffiliated purchasers based on published price bulletins reflecting an established field posting price. As a consequence, the prices we receive for crude oil move up and down in direct correlation with the oil market as it reacts to supply and demand factors. Transportation costs related to moving crude oil are also deducted from the price received for crude oil.
  
We have entered into month-to-month crude oil purchase contract with two third party buyers, pursuant to which one of the buyers purchases the crude oil produced from our initial five wells in the Niobrara Asset, periodically at a price per barrel equal to the average monthly “Light Sweet Crude Oil” contract price as reported by NYMEX from the first day of the delivery month through the last day of the delivery month, less $12.90 currently per barrel for transportation costs, and the other buyer purchases the crude oil produced from our 11 wells operated on our Wattenberg Asset, periodically at a price per barrel equal to the average monthly “Light Sweet Crude Oil” contract price as reported by NYMEX from the first day of the delivery month through the last day of the delivery month, less $11.50 currently per barrel for transportation costs.
 
Natural Gas. Our natural gas is sold under both long-term and short-term natural gas purchase agreements. Natural gas produced by us is sold at various delivery points at or near producing wells to both unaffiliated independent marketing companies and unaffiliated mid-stream companies. We receive proceeds from prices that are based on various pipeline indices less any associated fees for processing, location or transportation differentials.
 
We have entered into a Gas Purchase Contract, dated June 1, 2012, with DCP Midstream, LP, which we refer to as DCP, pursuant to which we have agreed to sell, and DCP has agreed to purchase, all gas produced from our Niobrara Asset wells located in Weld County, Colorado, at a purchase price equal to 83% of the net weighted average value for gas attributable to us that is received by DCP at its facilities sold during the month, less a $0.06/gallon local fractionation fee, for a period of ten years, terminating June 1, 2022.
 
In connection with our acquisition of the Wattenberg Asset from Continental in March 2014, we became a party to a Gas Purchase Contract, dated December 1, 2011, with DCP, pursuant to which we have agreed to sell, and DCP has agreed to purchase, all gas produced from six (6) of our Wattenberg Asset wells and surrounding lands located in Weld County, Colorado, at a purchase price equal to 83% of the net weighted average value for gas attributable to us that is received by DCP at its facilities sold during the month, less a $0.06/gallon local fractionation fee, for a period of ten years, terminating December 1, 2021.
 
 
 
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In connection with our acquisition of the Wattenberg Asset from Continental in March 2014, we also became a party to a Gas Purchase Agreement, dated April 1, 2012, as amended, with Sterling Energy Investments LLC (“Sterling”), pursuant to which we have agreed to sell, and Sterling has agreed to purchase, all gas produced from five (5) of our Wattenberg Asset wells and surrounding lands located in Weld County, Colorado, at a purchase price equal to 85% of the revenue received by Sterling from the sale of gas after processing at Sterling’s plant that is attributable to us during the month, less a $0.50/Mcf gathering fee, subject to escalation, for a period of twenty years, terminating April 1, 2032.
 
We endeavor to assure that title to our properties is in accordance with standards generally accepted in the oil and natural gas industry. Some of our acreage will be obtained through farmout agreements, term assignments and other contractual arrangements with third parties, the terms of which often will require the drilling of wells or the undertaking of other exploratory or development activities in order to retain our interests in the acreage. Our title to these contractual interests will be contingent upon our satisfactory fulfillment of these obligations. Our properties are also subject to customary royalty interests, liens incident to financing arrangements, operating agreements, taxes and other burdens that we believe will not materially interfere with the use and operation of or affect the value of these properties. We intend to maintain our leasehold interests by making lease rental payments or by producing wells in paying quantities prior to expiration of various time periods to avoid lease termination.
 
Merger with Pacific Energy Development
 
On July 27, 2012, in order to carry out our business plan, we acquired through a reverse acquisition, Pacific Energy Development Corp., a privately held Nevada corporation, which we refer to as Pacific Energy Development. As described below, pursuant to the acquisition, the shareholders of Pacific Energy Development gained control of approximately 95% of the voting securities of our company. Since the transaction resulted in a change of control, Pacific Energy Development is the acquirer for accounting purposes. In connection with the merger, which we refer to as the Pacific Energy Development merger, Pacific Energy Development became our wholly-owned subsidiary and we changed our name from Blast Energy Services, Inc. to PEDEVCO CORP.
 
As part of the Pacific Energy Development merger, we issued to the shareholders of Pacific Energy Development (a) 5,972,420 shares of our common stock, (b) 6,538,892 shares of our newly created Series A preferred stock, (c) warrants to purchase an aggregate of 373,334 shares of our common stock and 230,861 shares of our Series A preferred stock at various exercise prices, and (d) options to purchase an aggregate of 1,411,667 shares of our common stock at various exercise prices. Pursuant to the Pacific Energy Development merger, all of our shares of preferred stock that were outstanding prior to the Pacific Energy Development merger were converted into shares of common stock on a one-for-one basis and we effected a reverse stock split of our common stock on a 1 for 112 shares basis effective on July 30, 2012. All share and per share amounts used in this Annual Report have been restated to reflect this reverse stock split and a further reverse split in the ratio of 1 for 3 affected on April 23, 2013.
 
At the effective time of the Pacific Energy Development merger, (a) Pacific Energy Development owned the Niobrara and Eagle Ford assets and had begun discussions regarding the Mississippian acquisition opportunity, and (b) our primary business was developing the North Sugar Valley Field asset. As a result of our acquisition of Pacific Energy Development in the Pacific Energy Development merger, we acquired these assets and opportunities of Pacific Energy Development.
 
 
9

 
 
The following chart reflects our current core subsidiaries and joint ventures:
 
 
*Represents percentage of voting power based on 26,539,013 shares of common stock outstanding as of March 28, 2014, and excludes voting power to be acquired upon exercise of outstanding options or warrants.
 
Oil and Gas Properties
 
We believe that the Wattenberg, Niobrara and Mississippian Shale plays represent among the most promising unconventional oil and natural gas plays in the U.S. We plan to continue to seek additional acreage proximate to our currently held core acreage. Our strategy is to be the operator, directly or through our subsidiaries and joint ventures, in the majority of our acreage so we can dictate the pace of development in order to execute our business plan. The majority of our capital expenditure budget for the period from January 2014 to December 2014 will be focused on the acquisition, development and expansion of these formations.
 
 
 
10

 
 
 
 
December 31, 2013 and our drilling capital budget with respect to this acreage from January 1, 2014 to December 31, 2014, subject to availability of capital.
 
                                 
Drilling & Land Acquisition Capital Budget
January 1, 2014 - December 31, 2014
 
 Current Core Assets:
 
Total
Gross
Acreage
   
Approximate
Ownership
Interest
   
Net Acres
   
Acre Spacing
   
Potential Gross -Drilling
Locations (3)
   
Gross Wells
   
Net Wells
   
Gross Costs per Well (4)
   
Capital Cost to
the Company (4)
 
                                                       
Wattenberg (1)
   
27,914
     
50.0
%
   
13,957
     
40/80(5)
     
1,256
     
11
     
4.00
   
$
3,800,000
   
$
    
15,200,000
 
                                                                         
Niobrara (2)
   
9,067
     
26.3
%
   
2,384
     
80
     
212
     
2
     
0.40
   
$
3,800,000
   
$
1,520,000
 
 
Mississippian (3)
   
7,006
     
49.1
%
   
3,443
     
160
     
21
     
3
     
1.47
   
$
3,500,000
   
$
5,145,000
 
Current Assets
   
43,987
             
19,784
             
1,489
     
16
     
5.87
           
$
21,865,000
 
 
(1)
We acquired the Wattenberg Asset on March 7, 2014, with an effective date of December 1, 2013.  The leased acreage in the Wattenberg Asset covers 178 sections (640 acres per section).  Our gross acreage is the acreage purchased from Continental and currently held 50% by the Company and 50% by RJ Resources.
 
(2)
As discussed below, we have an average 26.3% net ownership interest in the leased acreage in the Niobrara Asset given our average 10.72% interest in certain leases held directly by us plus our 20% interest in Condor.
 
(3)
Potential gross drilling locations are calculated using the acre spacings specified for each area in the table and adjusted assuming forced pooling in the Niobrara. Colorado, where the Niobrara Asset is located, allows for forced pooling, which may create more potential gross drilling locations than acre spacing alone would otherwise indicate. 40 acre spacing assumed for Wattenberg acreage and 80 acre spacing is assumed for Wattenberg Extension acreage.
 
(4)
Costs per well are gross costs while capital costs presented are net to the Company’s working interests.
 
(5)
 40 acre spacing is assumed for Wattenberg acreage and 80 acre spacing is assumed for Wattenberg Extension acreage.
 
 
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Wattenberg Asset
 
We directly hold all of our interests in the Wattenberg Asset through our wholly-owned subsidiary, Red Hawk Petroleum, LLC (“Red Hawk”).  These interests are located in Weld and Morgan Counties, Colorado.  Red Hawk is the operator of our Wattenberg Asset.
 
Niobrara Asset
 
Our interests in the Niobrara Asset consist of the following:
 
We directly hold a portion of our interest in the Niobrara Asset through our wholly-owned subsidiary, Pacific Energy Development Corp. These interests are all located within Weld County, Colorado.
 
We indirectly hold a portion of our interest in the Niobrara Asset by virtue of our 20% ownership in Condor Energy Technology LLC (“Condor”), which is 80% owned by a subsidiary of our partner, MIE Holdings Corporation. These interests are all located within Weld and Morgan Counties, Colorado. Condor is the operator of our Niobrara Asset (both directly and indirectly owned).
 
 
Mississippian Asset
 
We hold all of our interests in the Mississippian Asset through Pacific Energy Development MSL, LLC, which is 50% owned by us, and 50% owned by our strategic partner, RJ Resources.  These interests are all located within Comanche, Harper, Barber and Kiowa Counties, Kansas.
 
North Sugar Valley Asset (non-core asset)
 
We directly hold all of our interests in the North Sugar Valley asset. These interests are all located within Matagorada County, Texas.
 
Strategic Alliances
 
MIE Holdings
 
Through the relationships developed by our founder and Chief Executive Officer, Frank Ingriselli, we formed a strategic relationship with MIE Holdings Corporation (Hong Kong Stock Exchange code: 1555.HK), one of the largest independent upstream onshore oil companies in China, which we refer to as MIE Holdings, to assist us with our plans to develop unconventional shale properties.  According to information provided by MIE Holdings, MIE Holdings has drilled and currently operates over 2,000 oil wells in China and brings extensive drilling and completion experience and expertise, as well as a strong geological team.  MIE Holdings has also been a significant investor in our operations, and our current Niobrara Asset is held in part by Condor, which is a Nevada limited liability company owned 20% by us and 80% by an affiliate of MIE Holdings.
 
Although our initial focus is on oil and natural gas opportunities in the United States, we plan to use our strategic relationship with MIE Holdings and our experience in operating U.S.-based shale oil and natural gas interests to acquire, explore, develop and produce oil and natural gas resources in Pacific Rim countries, with a particular focus on China.  We intend to use our existing or future joint ventures with MIE Holdings to acquire additional shale properties in the United States and in China, where MIE Holdings and other partners have extensive experience working in the energy sector.  
 
STXRA
 
On October 4, 2012, we established a technical services subsidiary, Pacific Energy Technology Services, LLC, which is 70% owned by us and 30% owned by STXRA, through which we plan to provide acquisition, engineering, and oil drilling and completion technology services in joint cooperation with STXRA in the United States and Pacific Rim countries, particularly in China.  While Pacific Energy Technology Services, LLC currently has no operations, only nominal assets and liabilities and limited capitalization, we anticipate actively developing this venture throughout 2014.
 
  STXRA is a consulting firm specializing in the delivery of petroleum resource acquisition services and practical engineering solutions to clients engaged in the acquisition, exploration and development of petroleum resources.  It was founded by its principals in conjunction with the forming of our company in order to provide technical and operating services to us. In April 2011, we entered into an agreement of joint cooperation with STXRA in an effort to identify suitable energy ventures for acquisition by us, with a focus on plays in shale oil and natural gas bearing regions in the United States.  According to information provided by STXRA, the STXRA team has experience in their collective careers of drilling and completing horizontal wells, including over 100 horizontal wells with lengths exceeding 4,000 feet from 2010 to 2013, as well as experience in both slick water and hybrid multi-stage hydraulic fracturing technologies and in the operation of shale wells and fields.   We believe that our relationship with STXRA, both directly and through our jointly-owned Pacific Energy Technology Services LLC services company, will supplement the core competencies of our management team and provide us with petroleum and reservoir engineering, petrophysical, and operational competencies that will help us to evaluate, acquire, develop and operate petroleum resources in the future.
 
 
12

 
 
RJ Resources
 
On March 7, 2014, in connection with our acquisition of the Wattenberg Asset, we entered into a $50 million 3-year term debt facility with RJ Resources, a subsidiary of a New York-based investment management group with more than $1.3 billion in assets under management specializing in resource investments.  As part of the transaction, RJ Resources acquired (i) an equal 13,995 net acre position in the assets acquired from Continental, (ii) 50% of our pending interest in the Kazakhstan asset, and (iii) 50% of our ownership interest in (a) Pacific Energy Development MSL, LLC, which holds our Mississippian Asset, thereby making RJ Resources a 50% working interest partner with us in the development of our Wattenberg Asset, (b) the Kazakhstan Asset which we are in the process of acquiring, and (c) our Mississippian Asset, allowing us to undertake a more aggressive drilling and development program in 2014 and beyond.
 
 
 
13

 
 
Our Core Areas
 
The majority of our capital expenditure budget for the period from January to December 2014 will be focused on the acquisition and development of our core oil and natural gas properties located in the Wattenberg Asset, Niobrara Asset and Mississippian Asset. The following paragraphs summarize each of these core areas. For additional information, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations-Liquidity and Capital Resources” and “Business.”
 
 
 
 
14

 
 
Wattenberg Asset
 
On March 7, 2014, through our wholly-owned subsidiary Red Hawk, we completed the acquisition of 13,995 net acres of oil and gas properties covering approximately 178  sections, and interests in 40 wells located in the DJ Basin, Colorado, from Continental for approximately $28.5 million in cash, and the assumption of approximately $845,000 of suspense accounts payable to royalty owners, mineral owners and other persons with an interest in production associated with the assets acquired, pertaining to oil and gas produced, which Continental had not paid as of closing.  This acreage, which we refer to as the Wattenberg Asset, is located in the Wattenberg and Wattenberg Extension Areas of the DJ Basin in Weld and Morgan Counties, Colorado.  Of these 40 wells, 11 are operated by Red Hawk, 14 are non-operated, and we will have an after-payout interest in 15.  All of Continental’s leases and related rights, oil and gas and other wells, equipment, easements, contract rights, and production effective as of the December 1, 2013 effective date of the agreement were included in the purchase.
 
In order to finance the acquisition of the Wattenberg Asset, and provide us with sufficient capital to immediately commence a meaningful development program covering this new acreage, we entered into a 3-year term debt facility with RJ Resources as described above under “RJ Resources”.
 
We plan to drill approximately 11 gross (4 net) horizontal wells on our Wattenberg Asset in 2014, utilizing the $15.5 million drilling facility provided by RJ Resources, cash on hand, proceeds from future equity offerings, internally generated cash flow, and future debt financings to aggressively develop this new asset.
 
Niobrara Asset
 
As of December 31, 2013, we held 2,384 net acres in oil and natural gas properties covering approximately 9,067 gross acres that are located in Morgan and Weld Counties, Colorado that include the Niobrara formation, which we refer to as the Niobrara Asset. We hold 972 of our Niobrara leased acreage directly, and hold the remaining 1,412 acres through our ownership in Condor, which holds 7,058 acres in the leased acreage in the Niobrara Asset.
 
Condor is designated as the operator of the Niobrara Asset. The day-to-day operations of Condor are managed by our management, and Condor’s Board of Managers is comprised of our President and Chief Executive Officer, Mr. Frank Ingriselli, and two designees of MIE Holdings. In addition, MIE Holdings has loaned us approximately $6.17 million to fund operations and development of the Niobrara Asset.
 
Based on approximately 250 square miles of 3D seismic data covering the Niobrara asset, we estimate that there are up to 212 potential gross drilling locations in the Niobrara Asset, with 2 gross well locations identified for our 2014 Niobrara development plan. We believe that the Niobrara Asset affords us the opportunity to participate in this emerging play at an early stage, with a position in the Denver-Julesburg Basin adjacent to significant drilling activity.
 
During 2012, Condor completed drilling the initial horizontal well on the Niobrara asset, the FFT2H, in April 2012, reaching a total combined vertical and horizontal depth of 11,307 feet. Halliburton performed a 20-stage frac of the well in mid-June 2012, with the well completed in July 2012 with an initial production rate of 437 BOE per day from the Niobrara formation. Condor completed drilling its second horizontal well on the Niobrara asset, the Waves 1H, in November 2012, drilling to 11,114 feet measured depth (6,200 true vertical foot depth) in eight days. The 4,339 foot lateral section was completed in 18 stages by Halliburton in February 2013, and the well tested at an initial production rate of 528 barrels of oil per day and 360 Mcf per day (588 BOE per day) from the Niobrara “B” Bench target zone. Condor also completed drilling its third horizontal well on the Niobrara asset, the Logan 2H, in December 2012 to 12,911 feet measured depth (6,112 true vertical depth) in nine days. The 6,350 foot lateral section was completed in 25 stages by Halliburton in January 2013, and tested at an initial production rate of 522 barrels of oil per day and 360 Mcf per day (585 BOE per day) from the Niobrara “B” Bench target zone.
 
 During 2013, Condor completed drilling its fourth horizontal well on the Niobrara asset, the State 16-7-60 1H well, in July 2013, reaching a total vertical depth of approximately 6,260 feet and total measured depth of approximately 10,630 feet. The well tested at an initial production rate of 480 barrels of oil per day (bopd) and 360 thousand cubic feet of gas per day (mcfgpd) (540 barrels of oil equivalent per day (boepd)), during a 4-hour test of the Niobrara “B” Bench target zone. Following removal of a down hole sand screen which was restricting flow, the well reached a peak production rate of 972 bopd and 800 mcfgd (1,105 boepd), during a 4-hour test from the Niobrara “B” Bench target zone. Condor also completed drilling its fifth horizontal well, the Wickstrom 18-2H well, located in Morgan County, Colorado, in August reaching a total vertical depth of approximately 6,125 feet and total measured depth of approximately 14,706 feet. The well tested an initial production rate of 414 bopd and 408 mcfgd (482 boepd), during a 4-hour test from the Niobrara “B” Bench target zone. The well was tested using a limited rate flowback technique to reduce frac sand entry into the well bore and test the concept of EUR increases through lower drawdown similar to the practice employed in the Eagle Ford Shale, resulting in an initial production rate at 80% of its anticipated full production potential.
 
 
 
 
15

 
 
Based on publicly available information, we believe that average drilling and completion costs for wells in the Niobrara core area which, for purposes of industry comparisons, we define as Morgan and Weld Counties, Colorado, have ranged between $3.6 million and $6.0 million per well with average estimated ultimate recoveries, or EURs, of 100,000 to 300,000 BOE per well and initial 30-day average production of 300 to 600 BOE per day per well. The costs incurred, EURs and initial production rates achieved by others may not be indicative of the well costs we will incur or the results we will achieve from our wells.
 
Recently, there has been significant industry activity in the Niobrara Shale play. The most active operators offsetting our acreage position include Carrizo Oil and Gas, Inc. (NASDAQ: CRZO), Continental Resources, Inc. (NYSE: CLR), EOG Resources (NYSE: EOG), Synergy Resources (NYSE: SYRG), Anadarko Petroleum (NYSE: APC), SM Energy (NYSE: SM), Noble Energy (NYSE: NBL), Chesapeake Energy (NYSE: CHK), Whiting Petroleum (NYSE: WLL), Quicksilver Resources (NYSE: KWK), MDU Resources (NYSE: MDU), and Bill Barrett Corp. (NYSE: BBG).
 
 
Mississippian Asset
 
Effective March 15, 2013, we acquired an average 97% working interest in the Mississippian Lime covering approximately 7,006 gross (6,763 net) acres located in Comanche, Harper, Barber and Kiowa Counties, Kansas, which we refer to as the Mississippian Asset, and approximately 10.5 square miles of related 3-D seismic data.  Also effective March 15, 2013, we acquired certain additional working interests in the same acreage located in Comanche, Harper, and Kiowa Counties, Kansas, bringing our average working interest to 98% in the Mississippian asset covering an aggregate of approximately 7,006 gross (6,885 net) acres.
 
Effective March 7, 2014, pursuant to a Membership Interest Purchase Agreement (the “Membership Purchase Agreement”) entered into by and between Pacific Energy Development Corp. (“PEDCO”) and RJ Resources, PEDCO agreed to sell 50% of PEDCO MSL Merger Sub LLC, LLC, a Nevada limited liability company (“MSL Merger Sub”), which was wholly-owned by PEDCO immediately prior to the transactions contemplated by the Membership Purchase Agreement, to RJ Resources. The Membership Purchase Agreement contained customary representations, warranties, covenants and requirements for PEDCO to indemnify RJ Resources, subject to the terms and conditions of the Membership Purchase Agreement.  Immediately subsequent to the closing of the transactions contemplated by the Membership Purchase Agreement, PEDCO’s wholly-owned subsidiary, Pacific Energy Development MSL, LLC (“PEDCO MSL”) and MSL Merger Sub, entered into an Agreement and Plan of Merger (the “Plan of Merger”), pursuant to which PEDCO MSL merged with and into MSL Merger Sub, with MSL Merger Sub being the surviving entity in the merger, and concurrently therewith effecting a name change to Pacific Energy Development MSL, LLC, which was effected pursuant to the filing of Articles of Merger with the Secretary of State of Nevada and effective March 10, 2014.  The effective result of the Membership Purchase Agreement and Plan of Merger is that RJ Resources now owns 50% of PEDCO MSL.  As a result of the transactions effected by the Membership Purchase Agreement and Plan of Merger, RJ Resources acquired effective ownership of 50% of the Mississippian Asset, with the Company now owning an average 49% working interest in the Mississippian Asset covering an aggregate of approximately 7,006 gross (3,443 net) acres.
 
 
16

 
 
The Mississippian acquisition is structured as a primary term assignment to us by Berexco of the leasehold interests which expires on December 29, 2014. If we drill at least three (3) horizontal wells on these leasehold interests during this primary term, then we have the option, in our sole discretion, to extend the primary term with respect to some or all of the leases subject to the assignment for an additional one (1) year period upon payment to Berexco of an additional $200 per net acre covered by the leases upon which the option is exercised. If we complete a commercially producing well during the primary or extended terms, then Berexco shall assign such leases to us for as long as the wells produce in paying quantities, with each horizontal well of at least 4,000 feet in length holding 320 acres covered by the leases, each short horizontal well with a length of between less than 4,000 feet and at least 2,000 feet in length holding 160 acres, and each vertical well holding 10 acres. Berexco shall retain an overriding royalty interest equal to the positive difference, if any, obtained by subtracting existing leasehold burdens from 22.5% before payout and 25% after payout (reduced to the extent Berexco assigns less than a 100% working interest to us). For purposes of the Mississippian agreement, “payout” is defined as such time, on a well by well basis, when a well has sold the following specified barrels of oil equivalent (“BOE”), (utilizing a conversion factor for gas sales of 8 Mcf per 1 barrel of oil): for a vertical well, ten thousand (10,000) BOE; for a short horizontal well: twenty-five thousand (25,000) BOE; and for a horizontal well: fifty thousand (50,000) BOE.
 
We serve as the operator of the Mississippian Asset, which includes both undeveloped and held-by-production (HBP) positions. We anticipate drilling the first three wells on the Mississippian Asset in 2014. The Mississippian oil play is one of the latest oil plays that have recently captured attention in the industry, and we believe that there is an opportunity to acquire additional interests in this emerging play on attractive terms.

Our Non-Core Area
 
North Sugar Valley Field Asset
 
We acquired the North Sugar Valley asset in Matagorda County, Texas in connection with our merger with Blast, representing an approximately 65% working interest (net revenue interest of approximately 50%) in three wells, the Millberger #1, Millberger #2 and Oxbow #1 wells. Our 2013 year-end reserve report estimates contain approximately 9,762 barrels of proved oil reserves net to the interest we acquired.
 
Sun Resources Texas, Inc. (“Sun”), a privately-held company based in Longview, Texas, is the operator of the properties. Sun retains a 1% working interest in the wells.
 
During late 2011 and early 2012, the down-hole equipment on the Oxbow #1 well began to fail which eventually caused the well to be deemed uneconomic. In late 2013, the Millberger #2 well began to have problems and work was performed in December 2013 to repair the well.  After the work was completed the well failed again and in January, 2014 it was determined that there was a casing failure and Sun presented an AFE to seek to work over the well.  We went non-consent on that AFE and Sun is researching and plans to present another plan and AFE to the working interest parties.  The Millberger #1 continues to produce and we will continue to review our options with respect to the Millberger #2 and all three wells, including reviewing divestiture options as this is a non-core asset. 
 
Recent Developments
 
Kazakhstan Acquisition
 
On September 16, 2013, we entered into a Share Subscription Agreement to acquire an approximate 51% ownership in Asia Sixth, which holds an approximate 60% ownership interest in Aral.  Aral holds a 100% operated working interest in a production license issued by the Republic of Kazakhstan that expires in 2034 in western Kazakhstan (the “Contract Area”).  The Contract Area covers 380,000 acres within the North Block located in the Pre-Caspian Basin.  This basin is the largest currently producing basin in Kazakhstan.
 
 
17

 
 
Under the agreement, we plan to acquire an interest in Aral through the acquisition of a 51% interest in Asia Sixth, by way of subscription of shares of Asia Sixth, which in turn currently holds a 60% controlling interest in Aral.  Asia Sixth’s interest in Aral is scheduled to increase to 66.5% following the completion of certain transactions to occur between Asia Sixth and Asia Sixth’s partner in Aral that currently holds the remaining 40% interest in Aral (the “Aral Transactions”).  Upon closing and completion of the Aral Transactions, Aral will be owned 66.5% by Asia Sixth. 
 
On March 7, 2014, the Company and RJ Resources entered into the Asia Sixth Purchase Agreement (the “Asia Sixth Agreement”), pursuant to which we agreed, at the option of RJ Resources, to either (a) provide for the issuance of the share certificate representing the shares of capital stock due from Asia Sixth representing 51% of the total issued and outstanding share capital of Asia Sixth (the “Subscription Shares”), which we have the right to purchase pursuant to the Shares Subscription Agreement, to a Delaware limited liability company to be formed by us (such company, the “Nominee”) and to convey to RJ Resources fifty percent (50%) of the limited liability company interests issued by the Nominee or (b) provide for fifty percent (50%) of such Subscription Shares to be issued directly to RJ Resources or its designee.
 
Upon closing and completion of the transactions contemplated by the Share Subscription Agreement and Asia Sixth Agreement, we, through our approximate 26% ownership in Asia Sixth, will own an approximate 17% beneficial interest in Aral. The closing of the transaction contemplated by the Share Subscription Agreement is anticipated to occur in September 2014, subject to the satisfaction of certain customary closing conditions including the approval of the Agency of the Republic of Kazakhstan for the Protection of Competition and the Ministry of Oil and Gas of the Republic of Kazakhstan (“MOG”), and the MOG’s waiver of its pre-emptive purchase right with respect to the transaction, and the closing of the transaction contemplated by the Asia Sixth Agreement is anticipated to occur within approximately one (1) year thereafter, similarly subject to the satisfaction of certain customary closing conditions including the approval of the Agency of the Republic of Kazakhstan for the Protection of Competition and the MOG, and the MOG’s waiver of its pre-emptive purchase right with respect to the transaction.  In addition, our ability to pay the final closing payment (if and to the extent due) is contingent upon our securing sufficient financing, of which there can be no assurances.
 
We have paid an initial deposit of $8 million in September 2013 and a subsequent deposit of $2 million on October 1, 2013 to Asia Sixth, and we were required to increase our deposit by up to $10 million to a total of $20 million contingent upon receipt of payment in full from an investor under a promissory note maturing in December 2013. The investor failed to pay the $10 million balance due under the Note by December 1, 2013,  On December 1, 2013, the Company granted a verbal extension to the investor pending further discussions regarding the investment.  Following discussions with the investor, the investor elected to forego making further investment. Accordingly, on March 7, 2014, the Company notified the investor that, effective immediately, the Escrowed Shares and Escrowed Warrants were rescinded as permitted pursuant to the terms of the Note, and the Note was cancelled and forgiven, with no further action required by the investor (the “Cancellation”).  The stock subscription receivable related to 3,333,333 shares of common stock and 999,999 warrants for shares of common stock in the amount of $10 million was extinguished as of March 7, 2014. The rescission of the note has no net effect on us or our obligations under the Share Subscription Agreement because (a) if such note was paid in full we would have been required to pay such funds directly to Asia Sixth; and (b) the result of such funds not being paid only results in a decrease in the required deposit due to Asia Sixth.
 
The $10 million deposit is subject to full refund to us in the event the transaction does not close, other than as a result of our material uncured breach, provided, however, that pursuant to the Asia Sixth Agreement, if any part of the $10 million deposit previously paid by us is returned to us, 50% of any such returned funds must be paid to RJ Resources.  These funds will also be used, in part, to recomplete and rework currently producing wells with the goal of significantly increasing their production rates. Based on how these wells perform, at closing, we shall owe to Asia Sixth a final closing payment equal to an additional:  (i) $20 million if the daily average volume of oil produced by Aral over a specified 30 day period (the “Target Volume”) equals or exceeds 1,500 barrels of oil per day (“BOPD”); (ii) $15 million if the Target Volume equals or exceeds 1,000 BOPD but is less than 1,500 BOPD; or (iii) $0 due if the Target Volume comes in less than 1,000 BOPD.  Pursuant to the Asia Sixth Agreement, RJ Resources is obligated to pay 50% of any final closing payment due to Asia Sixth.
 
Upon closing, we and the other shareholders of Asia Sixth will enter into a shareholders agreement, pursuant to which the shareholders will agree to certain restrictions on the transfer of their interests in Asia Sixth, certain pre-emption rights in the event a shareholder desires to transfer its interests in Asia Sixth, certain information rights, and certain other rights, including, but not limited to, certain management and control provisions, including: (i) our right to nominate two (2) of the five (5) directors of Asia Sixth, subject to our maintaining at least a 25% ownership of Asia Sixth; (ii) our right to nominate one (1) additional of the five (5) directors of Asia Sixth, subject to our maintaining at least a 51% ownership of Asia Sixth; (iii) our right to designate the Chairman of Asia Sixth from among its directors appointed to the Asia Sixth Board; and (iv) the appointment of two (2) of the Asia Sixth directors designated by us to the five (5) member Supervisory Council of Aral.
 
 
 
18

 
 
In February 2014, we were informed by Aral that in December 2013 the Central Development Committee of the Republic of Kazakhstan approved the development plan proposed by Aral for the development of its 2,199 acre contract area located in the East Zhagabulak Block oilfield, thereby officially moving the oilfield into the development stage under Aral's existing production license issued by the Republic of Kazakhstan. Under Kazakh law, a government-approved development plan is necessary to commence formal oil production under a production license. With receipt of this approval, Aral now formally enters into the production stage, which expires in 2034.
 
Following the previously announced completion of two target zones in wells #306 and #315, the asset has recently been producing approximately 1,522 barrels of oil equivalent per day (259 boepd to our 17% net interest) at approximately 50% choke from these two wells. Production was recently voluntarily halted by Aral pending receipt of a required gas-flaring permit or finalization of a gas off-take agreement for the sale of gas produced from the asset, following which Aral plans to commence commercial production within the coming months.

Wattenberg Asset Acquisition
 
On January 21, 2014, Red Hawk entered into a Purchase and Sale Agreement (“Purchase Agreement”) with Continental, pursuant to which we agreed to acquire Continental’s right, title and interest in the Wattenberg Asset, representing approximately 28,727 net acres of oil and gas properties and interests in 40 wells located in the DJ Basin, Colorado, including approximately 2,200 net acres in the prolific Wattenberg Area, for $30 million in cash (subject to adjustment as provided in the Purchase Agreement)(the “Purchase Price” and the “Continental Acquisition”).  The acreage, located in the Wattenberg and Wattenberg Extension Areas in the DJ Basin, includes approximately 28,241 net acres located in Weld County, Colorado and approximately 486 net acres located in Morgan County, Colorado.  Of these 40 wells, 11 are operated, 14 are non-operated, and we will have an after-payout interest in 15.  All of Continental’s leases and related rights, oil and gas and other wells, equipment, easements, contract rights, and production effective as of the December 1, 2013 effective date of the agreement were included in the purchase.
 
We paid $1.5 million of the Purchase Price as a deposit upon entering into the Purchase Agreement (the “Deposit”).  The final Purchase Price after adjustments as described in the Purchase Agreement was $28,521,822, leaving $27,031,822 due to Continental after the payment of the Deposit (the “Final Purchase Price”), provided that we also assumed an obligation in connection with approximately $845,000 of suspense accounts payable to royalty owners, mineral owners and other persons with an interest in production associated with the assets acquired, pertaining to oil and gas produced, which Continental had not paid as of closing.
 
On March 7, 2014, we paid the Final Purchase Price, closed the Purchase Agreement and acquired the Wattenberg Asset (representing an adjusted total of 27,990 net acres at closing).  Immediately upon closing, we transferred 50% of the Wattenberg Asset to RJ Resources as additional consideration for agreeing to provide the debt financing required to acquire the Wattenberg Asset, and to provide the $15.5 million drilling facility for development of the Wattenberg Asset in 2014 and going forward, as described in greater detail below under “Recent Developments” – “Note Purchase Agreement and Sale of Secured Promissory Notes”.
 
Eagle Ford Asset Sale
 
On March 29, 2012, we acquired Excellong E&P-2, Inc., a Texas corporation for a total purchase price of $3.75 million. Excellong E&P-2’s sole asset was an approximately 8% working interest in certain oil and gas leases covering approximately 1,650 net acres in the Leighton Field located in McMullen County, Texas, which is currently producing oil and natural gas from the Eagle Ford shale formation. This area is currently producing oil and natural gas from three wells, but the remainder of the acreage is under development. We subsequently transferred these assets to White Hawk Petroleum, LLC (“White Hawk”), which was 50% owned by us and 50% owned by MIE Jurassic Energy Corporation, a subsidiary of MIE Holdings, or MIEJ.
 
On December 20, 2013, White Hawk entered into a series of transactions pursuant to which MIEJ divested its 50% share of interests in the assets held through White Hawk to a third party, and withdrew from White Hawk as a member thereof effective December 31, 2013, with our effective interests in the Eagle Ford shale assets remaining unchanged and unaffected by the transactions.  As a result of the transactions, described in greater detail below under “Recent Developments” – “Eagle Ford Sale”, White Hawk divested 50% of its assets and we became the 100% owner of White Hawk.
 
On February 19, 2014, White Hawk entered into and closed a Purchase and Sales Agreement (the “Sale Agreement”) with Millennial PDP Fund IV, LP (“Millennial”), pursuant to which White Hawk sold its remaining interests in the Eagle Ford shale play to Millennial for net proceeds of $2,718,158 in cash. Pursuant to the sale agreement (which included customary indemnification requirements and representations and warranties of the parties), the sale had an effective date of November 1, 2013, and Millennial delivered to White Hawk the sale consideration on February 27, 2014.
 
 
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Issuance and Sale of 3,250,000 Shares in December 2013 Underwritten Public Offering
 
On December 9, 2013, we announced the pricing of our underwritten public offering of an aggregate of 3,250,000 shares of common stock at price of $2.25 per share to the public (the "December 2013 Offering"). The underwriters in the offering were granted a 45-day option to purchase up to 487,500 shares of common stock to cover over-allotments, of which there were none.  On December 13, 2013, we closed this underwritten offering of an aggregate of 3,250,000 shares of common stock. We received gross proceeds of $7,312,500 before deducting underwriting discounts and offering expenses as a result of the offering and net proceeds of approximately $6,281,767. We expect to use the net proceeds from the December 2013 Offering to fund drilling operations, for working capital and other general corporate purposes.
 
Issuance and Sale of 3,438,500 Shares in March 2014 Underwritten Public Offering
 
On March 4, 2014, we announced the pricing of our underwritten public offering of an aggregate of 2,990,000 shares of common stock at price of $2.15 per share to the public (the "March 2014 Offering"). The underwriters in the offering were granted a 30-day option to purchase up to 448,500 shares of common stock to cover over-allotments.  On March 7, 2014, we closed this underwritten offering of an aggregate of 3,438,500 shares of common stock, which included the full exercise of the overallotment by the underwriters and net proceeds of $6,581,280. We received gross proceeds of $7,392,775 before deducting underwriting discounts and offering expenses as a result of the offering. We expect to use the net proceeds from the March 2014 Offering to fund drilling operations, for working capital and other general corporate purposes.
 
Pursuant to the Underwriting Agreement entered into on March 4, 2014, in connection with the March 2014 Offering, (a) directors and executive officers of the Company entered into agreements providing for a 90-day “lock-up” period with respect to sales of specified securities, subject to certain exceptions; and (b) the Company agreed, without the prior written consent of the underwriters, to not offer or sell any shares of the Company’s common stock for 90 days, subject to certain exceptions including (i) pursuant to Options (defined below) or restricted stock grants issued to employees or directors of, or consultants or advisors to, the Company or any of its subsidiaries pursuant to a plan, agreement or arrangement approved by the Board of Directors; (ii) upon exercise or conversion of (x) any Options or Convertible Securities (defined below) which are outstanding on the day immediately preceding the date of the Underwriting Agreement was entered into, provided that such Options or Convertible Securities have not been amended since the date of such Underwriting Agreement to increase the number of such securities or to decrease the exercise price, exchange price or conversion price of such securities (except as a result of anti-dilution provisions therein); or (y) any outstanding debt obligations of the Company which are amended subsequent to the date of the Underwriting Agreement to provide such holders the right to convert the outstanding principal and interest due thereunder into shares of the Company’s common stock, provided that the conversion price of such security totals no more than a 20% discount to the closing sales price of the common stock (except as a result of anti-dilution provisions therein); (iii) directly to a counterparty, its affiliates or their respective stockholders in connection with any bona fide acquisitions, mergers, asset acquisitions and similar transactions approved by the Board of Directors the primary purpose of which is not to raise equity capital; (iv) in connection with transactions with lenders, customers, vendors or other commercial or strategic partners, the terms of which are approved by the Board of Directors, in each case, the primary purpose of which is not to raise equity capital; (v) pursuant to the Underwriting Agreement; (vi) up to 2,250,000 Options issued to a lender and placement agent in connection with a credit facility or debt arrangement entered into to finance the purchase price under that certain Purchase and Sale Agreement, dated January 21, 2014, entered into with Continental; and (vii) shares of common stock, preferred stock (including convertible preferred stock stock), and Options issued in a private placement transaction. “Options” means any rights, warrants or options to subscribe for or purchase shares of common stock or Convertible Securities.  “Convertible Securities” means any stock or securities (other than Options) convertible into or exercisable or exchangeable for shares of common stock.
 
Note Purchase Agreement and Sale of Secured Promissory Notes
 
In connection with our acquisition of the Wattenberg Asset, on March 7, 2014, we entered into and effected the transactions contemplated by a Note Purchase Agreement (the “Note Purchase”), between the Company, BRe BCLIC Primary, BRe BCLIC Sub, BRe WNIC 2013 LTC Primary, BRe WNIC 2013 LTC Sub, and RJ Credit LLC (“RJC”), as investors (collectively, the “Investors”), and BAM Administrative Services LLC, as agent for the Investors (the “Agent”).   Pursuant to the Note Purchase, we sold the Investors Secured Promissory Notes in the aggregate amount of $34.5 million (the “Initial Notes”).
 
We received $29,325,000 before expenses in connection with the sale of the Initial Notes after paying the Investors an original issue discount in connection with the sale of the Notes of $1,725,000 (5% of the balance of the Initial Notes); and an underwriting fee of $3,450,000 (10% of the balance of the Initial Notes). In connection with the Note Purchase, we also reimbursed approximately $135,000 of the legal fees and expenses of the Investors’ counsel, and paid the Casimir Note Closing Fee of $ 1,716,905, to Casimir Capital LP (“Casimir”), our investment banker in the transaction, as described and defined below, leaving a net of approximately $27,473,095 which was received by us on March 7, 2014.
 
 
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From time to time, subject to the terms and conditions of the Note Purchase (including the requirement that we have deposited funds in an aggregate amount of any additional requested loan into a segregated bank account (the “Company Deposits”)), and prior to the Maturity Date (defined below), we have the right to request additional loans (to be evidenced by notes with substantially similar terms as the Initial Notes, the “Subsequent Notes”, and together with the Initial Notes, the “Notes”) from RJC, up to an additional $15.5 million in total or an aggregate of $50 million together with the Initial Notes.  We are required to pay original issue discounts in the amount of 5% of the funds borrowed, underwriting fees in the amount of 10% of the amount of the funds borrowed, reimburse certain of the legal fees of RJC’s counsel, and pay applicable fees to Casimir representing 5% of any funds borrowed, in connection with funds borrowed under any Subsequent Notes.  Funds borrowed under any Subsequent Notes are only eligible to be used by us, together with Company Deposits, for approved authorization for expenditures (“AFEs”) issued for a well or wells to be drilled and completed on any properties acquired in connection with the Continental Acquisition or owed by us in connection with the Mississippian Asset (the “Permitted Expenditures”).  The total aggregate amount of any Subsequent Notes cannot exceed $15.5 million and in the event we drill a dry hole, we are prohibited from using the proceeds from the sale of any Subsequent Notes, without the consent of RJC.  Additionally, pursuant to the Note Purchase, no proceeds we receive from the transfer, sale, assignment or farm-out of the Mississippian Asset may be used to fund the Company Deposits.
 
The Notes are due and payable on March 6, 2017 (the “Maturity Date”), and may be repaid in full without premium or penalty at any time.
 
As additional consideration for RJC providing the loan evidenced by its Initial Note and agreeing, subject to the terms of the Note Purchase, to provide the funding contemplated by the Subsequent Notes, we entered into and affected the following transactions in favor of RJC and its affiliate RJ Resources, on March 7, 2014 concurrent with the closing of the transactions contemplated by the Note Purchase:
 
  
A Purchase and Sale Agreement, by and between PEDCO, Red Hawk and RJ Resources (the “Red Hawk Purchase”), described in greater detail above under “Wattenberg Asset Acquisition”;
 
  
The Asia Sixth Purchase Agreement, by and between PEDCO and RJ Resources described in greater detail above under “Kazakhstan Acquisition”; and
 
  
A Membership Interest Purchase Agreement, by and between PEDCO and RJ Resources, described in greater detail above under “Mississippian Asset”
 
As a result of the transactions affected by the Red Hawk Purchase, Asia Sixth Purchase, Membership Purchase and Plan of Merger, RJ Resources acquired ownership of 50% of all of our oil and gas assets and properties acquired in connection with the Continental Acquisition, rights to 50% of the oil and gas assets and properties which we have the right to acquire in Kazakhstan pursuant to the Shares Subscription Agreement, and effective ownership of 50% of the Mississippian Asset (the “Disposition Transactions”).
 
Pursuant to the Asia Sixth Purchase, PEDCO agreed, at the option of RJ Resources, to either (a) provide for the issuance of the share certificate representing the shares of capital stock due from Asia Sixth Energy Resources Limited (“Asia Sixth”), representing 51% of the total issued and outstanding share capital of Asia Sixth (the “Subscription Shares”), which we have the right to purchase pursuant to the Shares Subscription Agreement dated September 11, 2013 (the “Shares Subscription Agreement”), to a Delaware limited liability company to be formed by PEDCO (such company, the “Nominee”) and to convey to RJ Resources fifty percent (50%) of the limited liability company interests issued by the Nominee or (b) provide for fifty percent (50%) of such Subscription Shares to be issued directly to RJ Resources or its designee.  Additionally, the Asia Sixth Purchase provides that if any part of the $10 million deposit previously paid by us in connection with the Shares Subscription Agreement is returned to us, 50% of any such returned funds will be paid to RJ Resources. The Asia Sixth Purchase contains customary representations, warranties, covenants and requirements for PEDCO to indemnify RJ Resources, subject to the terms and conditions of the Asia Sixth Purchase.
 
The Notes bear interest at the rate of 15% per annum, payable monthly in arrears, on the first business day of each month beginning April 1, 2014 (in connection with the Initial Notes), provided that upon the occurrence of an event of default, the Notes bear interest at the lesser of 30% per annum and the maximum legal rate of interest allowable by law. We can prepay all or any portion of the principal amount of Notes, without premium or penalty.  The Notes include standard and customary events of default.
 
Additionally, we are required on the third business day of each month, commencing on April 1, 2014, to prepay the Notes in an amount equal to the lesser of (a) the outstanding principal amount of the Notes or (b) twenty-five percent (25%) of the aggregate of all net revenues actually received by us and are subsidiaries (other than net revenues received by Asia Sixth, unless and to the extent received by us in the United States) or for the immediately preceding calendar month (or such pro rata portion of the first month the payment is required).  The Notes also provide that RJC is to be repaid (i) accrued interest, only after all of the other Investors are repaid any accrued interest due and (ii) principal, only after all of the other Investors are repaid the full amount of principal due under their Notes, and (iii) that any funding in connection with Subsequent Notes will be made solely by RJC.
 
 
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The amount outstanding under the Notes is secured by a first priority security interest in all of our and our subsidiaries, assets, property, real property, intellectual property, securities and proceeds therefrom, granted in favor of the Agent for the benefit of the Investors, pursuant to a Security Agreement and Patent Security Agreement, and described in greater detail therein. Additionally, the Agent, for the benefit of the Investors, was granted a mortgage and security interest in all of our and our subsidiaries real property as located in the state of Colorado (including those assets acquired pursuant to the Continental Acquisition) and the state of Texas pursuant to (i) Leasehold Deed of Trust, Fixture Filing, Assignment of Rents and Leases, and Security Agreements filed in Weld County and Morgan County, Colorado; and (ii) a Mortgage, Deed of Trust, Security Agreement, Financing Statement and Assignment of Production filed in Matagorda County, Texas (collectively, the “Mortgages”).  Additionally, our obligations under the Notes, Note Purchase Agreement and related agreements were guaranteed by our direct and indirect subsidiaries, PEDCO, White Hawk, Pacific Energy & Rare Earth Limited, Blackhawk Energy Limited, PEDCO MSL and Red Hawk pursuant to a Guaranty Agreement.
 
The net proceeds from the Initial Funding were used by us (along with funds raised through the February 2014 sale of assets which were formerly owned by White Hawk), to purchase assets located in Weld and Morgan Counties, Colorado, from Continental Resources, Inc. as part of the Continental Acquisition, which transaction closed on March 7, 2014, and (ii) to pay fees and expenses incurred in connection with the transactions contemplated by the Note Purchase and Continental Acquisition.
 
We previously engaged Casimir as our investment banker and non-exclusive placement agent in connection with among other things, the transactions contemplated by the Note Purchase, and in connection with the closing of the Note Purchase, we paid Casimir a fee of $1,716,905 (5% of the funding amount we received before expenses of $29,325,000) of the proceeds received in connection therewith (the “Casimir Note Closing Fee”).  Upon the closing of the Note Purchase, we were also obligated to grant to Casimir warrants to purchase up to 1,000,000 shares of our common stock at an exercise price of $2.50 per share (the closing sales price of our common stock on the date immediately prior to the closing date of the Note Purchase), which warrants were issued on March 24, 2014, and which warrants have cashless exercise rights and a term of five years (the “Casimir Warrants”).

Rescission of Shares and Warrants and Cancellation of Note
 
On August 12, 2013, we sold (a) 6,666,667 shares of common stock at a price of $3.00 per share (the “Purchased Shares”), which included rights to the following warrants (b) three-year warrants exercisable on a cash basis only for (i) an aggregate of 666,667 shares of common stock at $3.75 per share, (ii) an aggregate of 666,667 shares of common stock at $4.50 per share, and (iii) an aggregate of 666,667 shares of common stock at $5.25 per share (collectively (i), (ii) and (iii), the “Purchased Warrants”), to Yao Hang Finance (Hong Kong) Limited (the “Lead Investor”) in consideration for $20 million.
 
The Lead Investor paid $10 million in cash at the closing, and entered into a common stock and Warrant Subscription Agreement (the “Subscription Agreement”), First Amendment to common stock and Warrant Subscription Agreement (the “Amendment”), and full-recourse promissory note (the “Note”), which Amendment and Note required that it pay the balance of $10 million in cash no later than December 1, 2013, with 3,333,333 of the shares of common stock issued to the Lead Investor in the Private Placement (the “Escrowed Shares”), as well as warrants exercisable for (i) an aggregate of 333,333 shares of common stock at $3.75 per share, (ii) an aggregate of 333,333 shares of common stock at $4.50 per share, and (iii) an aggregate of 333,333 shares of common stock at $5.25 per share (collectively (i), (ii) and (iii), the “Escrowed Warrants”), being held in escrow by the Company pending the Lead Investor’s payment in full of the $10 million due under the Note.
 
The Lead Investor failed to pay the $10 million balance due under the Note by December 1, 2013.  On March 7, 2014, we notified the Lead Investor that, effective immediately, the Escrowed Shares and Escrowed Warrants were rescinded as permitted pursuant to the terms of the Note, and the Note was cancelled and forgiven, with no further action required by the Lead Investor (the “Cancellation”).
 
Pursuant to the terms of our September 16, 2013, Share Subscription Agreement which provides us rights to acquire an approximately 51% ownership in Asia Sixth, which holds an approximately 60% ownership interest in Aral, a Kazakhstan entity, which holds a 100% operated working interest in a production license issued by the Republic of Kazakhstan that expires in 2034 in western Kazakhstan, we were required to pay the Note proceeds to Asia Sixth in the event we received such proceeds, provided that if such proceeds were not received, the required amount of the Share Subscription Agreement was to automatically be reduced from $20 million to $10 million (which $10 million deposit has previously been paid by us).  Consequently, the rescission of the Note has no net effect on us or our obligations under the Share Subscription Agreement because (a) if such Note was paid in full we would have been required to pay such funds directly to Asia Sixth; and (b) the result of such funds not being paid only results in a decrease in the required deposit due to Asia Sixth.
 
 
 
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Letter Amending Cash Compensation Payable to South Texas Reservoir Alliance LLC
 
On March 7, 2014, PEDCO MSL and South Texas Reservoir Alliance LLC (“STXRA”) entered into a letter agreement providing for $405,777 of cash consideration owed to STXRA for consulting services provided by STXRA to PEDCO MSL in connection with our acquisition of the Mississippian Asset in March 2013, which was satisfied in full through the issuance by the Company to STXRA on March 24, 2014 of an aggregate total of 190,000 shares of our restricted common stock.
 
Amendment to Bridge Notes and Subordination and Intercreditor Agreements
 
On December 16, 2013, we entered into an Amendment to Secured Promissory Notes, with each of the holders, or bridge investors, of those certain Secured Promissory Notes, which we refer to as the bridge notes.  The bridge notes were originally issued by us on March 22, 2013, in a private placement transaction in which we sold and issued to the bridge investors a total of $4.0 million of bridge notes and warrants exercisable for a total of up to 76,198 shares of our common stock, which we refer to as the bridge warrants, for gross proceeds of $4.0 million, which we refer to as the bridge financing.
 
The bridge notes were amended effective December 16, 2013, or the effective date, to provide for (i) the extension of the maturity date of such bridge notes, which were originally due as of December 31, 2013, to July 31, 2014, which we refer to as the extension term and new maturity date, respectively, (ii) the subordination of the bridge notes to certain of our future qualified senior indebtedness with a principal amount of at least $5.0 million, (iii) the payment in full of all accrued interest through the effective date on January 8, 2014, or the payment date, equal to an aggregate of $294,795 due and payable to the bridge investors on the payment date, (iv) the payment in full of the payment-in-kind amount, or PIK, equal to 10% of the original principal amount of such bridge notes on the payment date, equal to an aggregate of $400,000 due and payable to the bridge investors on the payment date, (v) the repayment of either none or 50% of the outstanding principal amount due under such bridge notes, as elected by the holders thereof, on the payment date, which aggregate principal repayment of $1,625,000 shall be due and payable to the bridge investors on the payment date as elected by the holders, (vi) the amendment of the interest rate of such bridge notes for the extension term from 10% per annum to 12% per annum with respect to the remaining unpaid principal amount of such bridge notes, or the deferred principal, and (vii) an additional payment-in-kind cash amount equal to 10% of the deferred principal due on the new maturity date, or the additional PIK.  In total, eleven (11) bridge investors holding bridge notes with an aggregate principal amount outstanding of $3,250,000 elected to defer 50% of their principal, agreeing to defer an aggregate of $1,625,000 in principal amount of the bridge notes, and five (5) bridge investors holding bridge notes with an aggregate principal amount outstanding of $750,000 elected to defer 100% of their principal, for a total deferred principal of $2,375,000, and an aggregate additional PIK due and paid upon the new maturity date of $237,500.
 
As additional consideration for the amendment of the bridge notes, we granted a new warrant, which we refer to as the new warrant, exercisable on a cashless basis at an exercise price of $2.34 per share for a number of shares of our common stock equal to (x) two times the number of shares issuable under the bridge warrant originally issued to each holder who agreed to defer 50% of the outstanding principal of its bridge note, and (y) three times the number of shares issuable under the bridge warrant originally issued to each holder who agreed to defer 100% of the outstanding principal of his, her, or its bridge note, for a total of new warrants exercisable for an aggregate of 166,684 shares of our common stock.  The new warrants have a 4-year life and have substantially the same terms as the bridge warrants originally issued to the bridge investors.
 
Frank C. Ingriselli, our President, Chief Executive Officer, and member of our Board of Directors, agreed to defer $500,000 of the original $1.0 million principal amount outstanding under his bridge note, and on the payment date we paid him $73,699 in accrued interest and $100,000 in PIK amounts due, and repaid 50% of his outstanding principal amount of $500,000, and Mr. Ingriselli received a new warrant exercisable for 38,096 shares of our common stock.  Clark R. Moore, our Executive Vice President and General Counsel, agreed to defer $25,000 of the original $50,000 principal amount outstanding under his bridge note, and on the payment date we paid him $3,685 in accrued interest and $5,000 in PIK amounts due, and repaid 50% of his outstanding principal amount of $25,000, and Mr. Moore received a new warrant exercisable for 1,906 shares of our common stock.
 
We amended the bridge notes in order to extend their maturity dates with respect to the deferred principal to conserve our available cash, and to subordinate the bridge notes to better position us to seek additional senior debt financing opportunities.
 
 
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On March 7, 2014, we entered into Second Amendment to Secured Promissory Notes (each, an “Amended Note,” and collectively, the “Amended Notes”) with all but one of the bridge investors.  
 
The Amended Notes amended the bridge notes to allow the holders thereof the right to convert up to 100% of the outstanding and unpaid principal amount (but in increments of not less than 25% of the principal amount of each bridge note outstanding as of the entry into the Amended Notes and only up to four (4) total conversions of not less than 25% each); the additional payment-in-kind cash amount equal to 10% of the principal amount of each holder’s bridge note which was deferred pursuant to the First Amendment; and all accrued and unpaid interest under each bridge note (collectively, the “Conversion Amount”) into our common stock, subject to an additional listing application regarding such common stock being approved by the NYSE MKT.  Upon a conversion, the applicable holder shall receive that number of shares of common stock as is determined by dividing the Conversion Amount by a conversion price (the “Conversion Price”) as follows:
 
           (A)           prior to June 1, 2014, the Conversion Price shall be $2.15 per share; and
 
           (B)           following June 1, 2014, the denominator used in the calculation described above shall be the greater of (i) 80% of the average of the closing price per share of our publicly traded common stock for the five (5) trading days immediately preceding the date of the conversion notice provide by the holder; and (ii) $0.50 per share.
 
Additionally, each bridge investor entered into a Subordination and Intercreditor Agreement in favor of the Agent, subordinating and deferring the repayment of the bridge notes, and actions in connection with the security interests provided under the bridge notes, until full repayment of the Notes sold pursuant to the Note Purchase. The Subordination and Intercreditor Agreements also prohibit us from repaying the bridge notes until the Notes have been paid in full, except that we are allowed to repay the bridge notes from net proceeds received from the sale of common or preferred stock (i) in calendar year 2014 if such net proceeds received in such calendar year exceeds $35,000,000, (ii) in calendar year 2015 if such net proceeds received in such calendar year exceeds $50,000,000, and (iii) in calendar year 2016 if such net proceeds actually received in such calendar year exceeds $50,000,000.
 
Frank C. Ingriselli, our President, Chief Executive Officer, and member of our Board of Directors, originally provided us $1.0 million in bridge notes (which was reduced to $500,000 in connection with payments made pursuant to the First Amendment) and Clark R. Moore, our Executive Vice President and General Counsel, originally provided us $50,000 in bridge notes (which was reduced to $25,000 in connection with payments made pursuant to the First Amendment), provided that prior to the bridge note Investors’ entry into the Amended Notes, Mr. Ingriselli and Mr. Moore transferred their bridge notes to non-affiliates of the Company and as such, as of the date of the Amended Notes, such officers no longer held any bridge notes or rights thereunder.
 
Shale Oil and Natural Gas Overview
 
The relatively recent surge of oil and natural gas production from underground shale rock formations has had a dramatic impact on the oil and natural gas market in the U.S., where the practice was first developed, and globally. Shale oil production is facilitated by the combination of a set of technologies that had been applied separately to other hydrocarbon reservoir types for many decades. In combination these technologies and techniques have enabled large volumes of oil to be produced from deposits with characteristics that would not otherwise permit oil to flow at rates sufficient to justify its exploitation. The application of horizontal drilling, hydraulic fracturing and advanced reservoir assessment tools to these reservoirs is unlocking a global resource of shale and other unconventional oil and natural gas that the International Energy Agency estimates could eventually double recoverable global oil reserves.
 
In 2008, U.S. natural gas production was in a decline, and the U.S. was on its way to becoming a significant importer of liquefied natural gas (LNG). By 2009, U.S.-marketed natural gas production was 14% higher than in 2005, and in 2010 it surpassed the previous annual production record set in 1973. This turnaround is mainly attributable to shale oil and natural gas output that has more than tripled since 2007. Knowledge is expanding rapidly concerning the shale oil reservoirs that are already being exploited and others that appear suitable for development with current technology. In its preliminary 2011 Annual Energy Outlook, the U.S. Department of Energy (DOE) increased its estimate of recoverable U.S. shale natural gas resources by 238% compared to its previous estimate, bringing U.S. potential natural gas resources to 2,552 trillion cubic feet (TCF), equivalent to more than a century’s supply at current consumption rates.
 
Along with the reduction in economic activity resulting from the recession, the increase in production from shale natural gas has had a significant impact on U.S. average natural gas wellhead prices, which have fallen by more than 30% since 2007. As a result, the value of natural gas has diverged significantly from that of petroleum on an energy-equivalent basis. That has provided substantial economic benefits to natural gas-consuming industries. It has also led to both economic and environmental benefits for the electricity sector, as fired power plants displace power from higher-cost and higher-emitting sources. Shale natural gas has been cited by U.S. Secretary of Energy, Stephen Chu, as helping the world shift to cleaner fuels. A report by the National Petroleum Council (NPC) to Stephen Chu in September 2011 stated that shale oil fields in the U.S. could produce 2 to 3 million barrels of oil per day by 2025, given the right regulatory environment and technology breakthroughs.
 
 
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Oil and natural gas produced from shale is considered an unconventional resource. Commercial oil and natural gas production from unconventional sources requires special techniques in order to achieve attractive oil and natural gas flow rates. Unlike conventional oil and natural gas, which is typically generated in deeper source rock and subsequently migrates into a sandstone structure with an overlying impermeable layer forming a “trap,” shale oil and natural gas is generated from organic material contained within the shale and retained by the rock’s inherent low permeability. Permeability is a measure of the ease with which natural gas, oil or other fluids can flow through the material. The same low permeability that secures large volumes of natural gas and liquids in place within the shale strata makes it much more difficult to extract them, even with a large pressure difference between the reservoir and the surface. The location and potential of many of today’s productive shale reservoirs were known for many years, but until the development of current shale oil and natural gas techniques these deposits were considered noncommercial or inaccessible.
 
The main challenge of shale oil and natural gas drilling is to overcome the low permeability of the shale reservoirs. A conventional vertical oil or natural gas well drilled into one of these reservoirs might achieve production, though at reduced rates and for a limited duration before the oil or natural gas volume in proximity to the wellbore is exhausted. That often renders such an approach impractical and uneconomic for exploiting shale oil and natural gas. The two main technologies associated with U.S. shale oil and natural gas production are horizontal drilling and hydraulic fracturing, or “hydrofracking.” They are employed to overcome these constraints by greatly increasing the exposure of each well to the shale stratum and enabling oil and natural gas located farther from the well to flow through the rock and replace the nearby oil and natural gas that has been extracted to the surface.
 
Instead of drilling a simple vertical well through the shale and then perforating the well within the zone where it is in contact with the shale, the drilling company drills a directional well vertically to within proximity of the shale and then executes a 90-degree turn in order to intersect the shale and then travel for a significant horizontal distance through it. A typical North American shale well has a horizontal extent of 1,000 feet to 5,000 feet or more.
 
Once the lateral portion of the well has reached the desired extent, the other main technique of shale oil and natural gas drilling is deployed. After the well has been completed, the farthest section of the lateral is perforated, opening up holes through which fluid can flow. This portion of the reservoir is then hydrofracked by injecting fluid into the well under high pressure to fracture the exposed shale rock and open up pathways through which oil and natural gas can flow. The “fracking fluid” consists mainly of water with a variety of chemical additives intended to reduce friction and dissolve minerals, among other purposes, along with sand or sand-like material to prop open the new pathways created by hydrofracking. This process is then repeated at intervals along the well’s horizontal extent, successively perforating and hydrofracking each section in turn. This process creates a producing well that emulates the effect of a vertical well drilled into a conventional oil and natural gas reservoir by substituting multiple horizontal “pay zones” in the shale stratum for the thinner but more prolific vertical pay zone in a more permeable reservoir. Compared to conventional oil and natural gas drilling, the production of oil and natural gas from shale reservoirs thus entails more drilling, on average, and requires a substantial supply of water.
 
Shale oil and natural gas are currently being produced from a number of reservoirs in the U.S. Among these are the Bakken Shale in Montana and North Dakota, the Niobrara Shale in northeastern Colorado and parts of adjacent Wyoming, Nebraska, and Kansas, the Eagle Ford Shale in southern Texas, the Mississippian Lime in Kansas and Oklahoma, and the Marcellus Shale spanning several states in the northeastern U.S. According to a January 2014 U.S. Energy Information Administration’s report, the total technically recoverable world resources of shale oil and gas are estimated at 345 billion barrels (oil) and 7,299 trillion cubic feet (gas), with an estimated 58 billion barrels (oil) and 665 trillion cubic feet (gas) being concentrated in the U.S.
 
Regulation
 
Oil and Natural Gas Regulation
 
Our oil and natural gas exploration, development, production and related operations are subject to extensive federal, state and local laws, rules and regulations. Failure to comply with these laws, rules and regulations can result in substantial penalties. The regulatory burden on the oil and natural gas industry increases our cost of doing business and affects our profitability. Because these rules and regulations are frequently amended or reinterpreted and new rules and regulations are promulgated, we are unable to predict the future cost or impact of complying with the laws, rules and regulations to which we are, or will become, subject. Our competitors in the oil and natural gas industry are generally subject to the same regulatory requirements and restrictions that affect our operations. We cannot predict the impact of future government regulation on our properties or operations.
 
 
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Texas, Colorado, Kansas, and many other states require permits for drilling operations, drilling bonds and reports concerning operations and impose other requirements relating to the exploration, development and production of oil and natural gas. Many states also have statutes or regulations addressing conservation of oil and natural gas matters, including provisions for the unitization or pooling of oil and natural gas properties, the establishment of maximum rates of production from wells, the regulation of well spacing, the surface use and restoration of properties upon which wells are drilled, the sourcing and disposal of water used in the drilling and completion process and the plugging and abandonment of these wells. Many states restrict production to the market demand for oil and natural gas. Some states have enacted statutes prescribing ceiling prices for natural gas sold within their boundaries. Additionally, some regulatory agencies have, from time to time, imposed price controls and limitations on production by restricting the rate of flow of oil and natural gas wells below natural production capacity in order to conserve supplies of oil and natural gas. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, natural gas and natural gas liquids within its jurisdiction.
 
Some of our oil and natural gas leases are issued by agencies of the federal government, as well as agencies of the states in which we operate. These leases contain various restrictions on access and development and other requirements that may impede our ability to conduct operations on the acreage represented by these leases.
 
Our sales of natural gas, as well as the revenues we receive from our sales, are affected by the availability, terms and costs of transportation. The rates, terms and conditions applicable to the interstate transportation of natural gas by pipelines are regulated by the Federal Energy Regulatory Commission (FERC) under the Natural Gas Act, as well as under Section 311 of the Natural Gas Policy Act. Since 1985, FERC has implemented regulations intended to increase competition within the natural gas industry by making natural gas transportation more accessible to natural gas buyers and sellers on an open-access, non-discriminatory basis. The natural gas industry has historically, however, been heavily regulated and we can give no assurance that the current less stringent regulatory approach of FERC will continue.
 
In 2005, Congress enacted the Energy Policy Act of 2005. The Energy Policy Act, among other things, amended the Natural Gas Act to prohibit market manipulation by any entity, to direct FERC to facilitate market transparency in the market for sale or transportation of physical natural gas in interstate commerce, and to significantly increase the penalties for violations of the Natural Gas Act, the Natural Gas Policy Act of 1978, or FERC rules, regulations or orders thereunder. FERC has promulgated regulations to implement the Energy Policy Act. Should we violate the anti-market manipulation laws and related regulations, in addition to FERC-imposed penalties, we may also be subject to third-party damage claims.
 
Intrastate natural gas transportation is subject to regulation by state regulatory agencies. The basis for intrastate regulation of natural gas transportation and the degree of regulatory oversight and scrutiny given to intrastate natural gas pipeline rates and services varies from state to state. Because these regulations will apply to all intrastate natural gas shippers within the same state on a comparable basis, we believe that the regulation in any states in which we operate will not affect our operations in any way that is materially different from our competitors that are similarly situated.
 
The price we receive from the sale of oil and natural gas liquids will be affected by the availability, terms and cost of transportation of the products to market. Under rules adopted by FERC, interstate oil pipelines can change rates based on an inflation index, though other rate mechanisms may be used in specific circumstances. Intrastate oil pipeline transportation rates are subject to regulation by state regulatory commissions, which varies from state to state. We are not able to predict with certainty the effects, if any, of these regulations on our operations.
 
In 2007, the Energy Independence & Security Act of 2007 (the “EISA”), went into effect. The EISA, among other things, prohibits market manipulation by any person in connection with the purchase or sale of crude oil, gasoline or petroleum distillates at wholesale in contravention of such rules and regulations that the Federal Trade Commission may prescribe, directs the Federal Trade Commission to enforce the regulations and establishes penalties for violations thereunder. We cannot predict any future regulations or their impact.
 
U.S. Federal and State Taxation
 
The federal, state and local governments in the areas in which we operate impose taxes on the oil and natural gas products we sell and, for many of our wells, sales and use taxes on significant portions of our drilling and operating costs. In the past, there has been a significant amount of discussion by legislators and presidential administrations concerning a variety of energy tax proposals. President Obama has recently proposed sweeping changes in federal laws on the income taxation of small oil and natural gas exploration and production companies such as us. President Obama has proposed to eliminate allowing small U.S. oil and natural gas companies to deduct intangible U.S. drilling costs as incurred and percentage depletion. Many states have raised state taxes on energy sources, and additional increases may occur. Changes to tax laws could adversely affect our business and our financial results.
 
 
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Environmental Regulation
 
The exploration, development and production of oil and natural gas, including the operation of saltwater injection and disposal wells, are subject to various federal, state and local environmental laws and regulations. These laws and regulations can increase the costs of planning, designing, installing and operating oil and natural gas wells. Our activities are subject to a variety of environmental laws and regulations, including but not limited to the Oil Pollution Act of 1990 (OPA 90), the Clean Water Act (CWA), the Comprehensive Environmental Response, Compensation and Liability Act (CERCLA), the Resource Conservation and Recovery Act (RCRA), the Clean Air Act (CAA), the Safe Drinking Water Act (the SDWA) and the Occupational Safety and Health Act (OSHA), as well as comparable state statutes and regulations. We are also subject to regulations governing the handling, transportation, storage and disposal of wastes generated by our activities and naturally occurring radioactive materials (NORM) that may result from our oil and natural gas operations. Civil and criminal fines and penalties may be imposed for noncompliance with these environmental laws and regulations. Additionally, these laws and regulations require the acquisition of permits or other governmental authorizations before undertaking some activities, limit or prohibit other activities because of protected wetlands, areas or species and require investigation and cleanup of pollution. We intend to remain in compliance in all material respects with currently applicable environmental laws and regulations.
 
OPA 90 and its regulations impose requirements on “responsible parties” related to the prevention of crude oil spills and liability for damages resulting from oil spills into or upon navigable waters, adjoining shorelines or in the exclusive economic zone of the U.S. A “responsible party” under OPA 90 may include the owner or operator of an onshore facility. OPA 90 subjects responsible parties to strict joint and several financial liability for removal costs and other damages, including natural resource damages, caused by an oil spill that is covered by the statute. It also imposes other requirements on responsible parties, such as the preparation of an oil spill contingency plan. Failure to comply with OPA 90 may subject a responsible party to civil or criminal enforcement action. We may conduct operations on acreage located near, or that affects navigable waters subject to OPA 90.
 
The CWA imposes restrictions and strict controls regarding the discharge of produced waters and other wastes into navigable waters. These controls have become more stringent over the years, and it is possible that additional restrictions will be imposed in the future. Permits are required to discharge pollutants into state and federal waters and to conduct construction activities in waters and wetlands. Certain state regulations and the general permits issued under the federal National Pollutant Discharge Elimination System program prohibit the discharge of produced water, produced sand, drilling fluids, drill cuttings and certain other substances related to the oil and natural gas industry into certain coastal and offshore waters. Furthermore, the EPA has adopted regulations requiring certain oil and natural gas exploration and production facilities to obtain permits for storm water discharges. Costs may be associated with the treatment of wastewater or developing and implementing storm water pollution prevention plans. The CWA and comparable state statutes provide for civil, criminal and administrative penalties for any unauthorized discharges of oil and other pollutants and impose liability for the costs of removal or remediation of contamination resulting from such discharges. In furtherance of the CWA, the EPA promulgated the Spill Prevention, Control, and Countermeasure (SPCC) regulations, which require certain oil-storing facilities to prepare plans and meet construction and operating standards.
 
CERCLA, also known as the “Superfund” law, and comparable state statutes impose liability, without regard to fault or the legality of the original conduct, on various classes of persons that are considered to have contributed to the release of a “hazardous substance” into the environment. These persons include the owner or operator of the disposal site where the release occurred and companies that disposed of, or arranged for the disposal of, the hazardous substances found at the site. Persons who are responsible for releases of hazardous substances under CERCLA may be subject to joint and several liability for the costs of cleaning up the hazardous substances and for damages to natural resources. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by hazardous substances released into the environment. Our operations may, and in all likelihood will, involve the use or handling of materials that may be classified as hazardous substances under CERCLA. Furthermore, we may acquire or operate properties that unknown to us have been subjected to, or have caused or contributed to, prior releases of hazardous wastes.
  
RCRA and comparable state and local statutes govern the management, including treatment, storage and disposal, of both hazardous and nonhazardous solid wastes. We generate hazardous and nonhazardous solid waste in connection with our routine operations. At present, RCRA includes a statutory exemption that allows many wastes associated with crude oil and natural gas exploration and production to be classified as nonhazardous waste. A similar exemption is contained in many of the state counterparts to RCRA. At various times in the past, proposals have been made to amend RCRA to eliminate the exemption applicable to crude oil and natural gas exploration and production wastes. Repeal or modifications of this exemption by administrative, legislative or judicial process, or through changes in applicable state statutes, would increase the volume of hazardous waste we are required to manage and dispose of and would cause us, as well as our competitors, to incur increased operating expenses. Hazardous wastes are subject to more stringent and costly disposal requirements than are nonhazardous wastes.
 
 
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The CAA and comparable state laws restrict the emission of air pollutants from many sources, including oil and natural gas production. These laws and any implementing regulations impose stringent air permit requirements and require us to obtain pre-approval for the construction or modification of certain projects or facilities expected to produce air emissions, or to use specific equipment or technologies to control emissions. On July 28, 2011, the EPA proposed new regulations targeting air emissions from the oil and natural gas industry. The proposed rules, if adopted, would impose new requirements on production and processing and transmission and storage facilities.
 
Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent and costly waste handling, storage, transport, disposal or cleanup requirements or operating requirements could materially adversely affect our operations and financial position, as well as those of the oil and natural gas industry in general. For instance, recent scientific studies have suggested that emissions of certain gases, commonly referred to as “greenhouse gases,” and including carbon dioxide and methane, may be contributing to the warming of the Earth’s atmosphere. As a result, there have been attempts to pass comprehensive greenhouse gas legislation. To date, such legislation has not been enacted. Any future federal laws or implementing regulations that may be adopted to address greenhouse gas emissions could, and in all likelihood would, require us to incur increased operating costs adversely affecting our profits and could adversely affect demand for the oil and natural gas we produce depressing the prices we receive for oil and natural gas.
 
On December 15, 2009, the EPA published its finding that emissions of greenhouse gases presented an endangerment to human health and the environment. These findings by the EPA allow the agency to proceed with the adoption and implementation of regulations that would restrict emissions of greenhouse gases under existing provisions of the CAA. Subsequently, the EPA proposed and adopted two sets of regulations, one of which requires a reduction in emissions of greenhouse gases from motor vehicles and the other of which regulated emissions of greenhouse gases from certain large stationary sources. In addition, on October 30, 2009, the EPA published a rule requiring the reporting of greenhouse gas emissions from specified sources in the U.S. beginning in 2011 for emissions occurring in 2010. On November 30, 2010, the EPA released a rule that expands its final rule on greenhouse gas emissions reporting to include owners and operators of onshore and offshore oil and natural gas production, onshore natural gas processing, natural gas storage, natural gas transmission and natural gas distribution facilities. Reporting of greenhouse gas emissions from such onshore production became required on an annual basis beginning in 2012 for emissions occurring in 2011. The adoption and implementation of any regulations imposing reporting obligations on, or limiting emissions of greenhouse gases from, our equipment and operations could, and in all likelihood will, require us to incur costs to reduce emissions of greenhouse gases associated with our operations adversely affecting our profits or could adversely affect demand for the oil and natural gas we produce depressing the prices we receive for oil and natural gas.
 
Some states have begun taking actions to control and/or reduce emissions of greenhouse gases, primarily through the planned development of greenhouse gas emission inventories and/or regional greenhouse gas cap and trade programs. Although most of the state-level initiatives have to date focused on significant sources of greenhouse gas emissions, such as coal-fired electric plants, it is possible that less significant sources of emissions could become subject to greenhouse gas emission limitations or emissions allowance purchase requirements in the future. Any one of these climate change regulatory and legislative initiatives could have a material adverse effect on our business, financial condition and results of operations.
 
Underground injection is the subsurface placement of fluid through a well, such as the reinjection of brine produced and separated from oil and natural gas production. In our industry, underground injection not only allows us to economically dispose of produced water, but if injected into an oil bearing zone, it can increase the oil production from such zone. The SDWA establishes a regulatory framework for underground injection, the primary objective of which is to ensure the mechanical integrity of the injection apparatus and to prevent migration of fluids from the injection zone into underground sources of drinking water. The disposal of hazardous waste by underground injection is subject to stricter requirements than the disposal of produced water. We currently do not own or operate any underground injection wells, but may do so in the future. Failure to obtain, or abide by the requirements for the issuance of necessary permits could subject us to civil and/or criminal enforcement actions and penalties.
 
Oil and natural gas exploration and production, operations and other activities have been conducted at some of our properties by previous owners and operators. Materials from these operations remain on some of the properties, and, in some instances, may require remediation. In addition, we occasionally must agree to indemnify sellers of producing properties from whom we acquire reserves against some of the liability for environmental claims associated with these properties. We cannot assure you that the costs we incur for compliance with environmental regulations and remediating previously or currently owned or operated properties will not result in material expenditures that adversely affect our profitability.
 
 
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Additionally, in the course of our routine oil and natural gas operations, surface spills and leaks, including casing leaks, of oil or other materials will occur, and we will incur costs for waste handling and environmental compliance. It is also possible that our oil and natural gas operations may require us to manage NORM. NORM is present in varying concentrations in sub-surface formations, including hydrocarbon reservoirs, and may become concentrated in scale, film and sludge in equipment that comes in contact with crude oil and natural gas production and processing streams. Some states, including Texas, have enacted regulations governing the handling, treatment, storage and disposal of NORM. Moreover, we will be able to control directly the operations of only those wells for which we act as the operator. Despite our lack of control over wells owned by us but operated by others, the failure of the operator to comply with the applicable environmental regulations may, in certain circumstances, be attributable to us.
 
We are subject to the requirements of OSHA and comparable state statutes. The OSHA Hazard Communication Standard, the “community right-to-know” regulations under Title III of the federal Superfund Amendments and Reauthorization Act and similar state statutes require us to organize information about hazardous materials used, released or produced in our operations. Certain of this information must be provided to employees, state and local governmental authorities and local citizens. We are also subject to the requirements and reporting set forth in OSHA workplace standards.
 
We cannot assure you that more stringent laws and regulations protecting the environment will not be adopted or that we will not otherwise incur material expenses in connection with environmental laws and regulations in the future. The clear trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment and, thus, any changes in environmental laws and regulations or re-interpretation of enforcement policies that result in more stringent and costly waste handling, storage, transport, disposal or remediation requirements could have a material adverse effect on our operations and financial position. We may be unable to pass on such increased compliance costs to our customers. Moreover, accidental releases or spills may occur in the course of our operations, and we cannot assure you that we will not incur significant costs and liabilities as a result of such releases or spills, including any third party claims for damage to property, natural resources or persons.
 
We maintain insurance against some, but not all, potential risks and losses associated with our industry and operations. We do not currently carry business interruption insurance. 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 materially adversely affect our financial condition and results of operations.
 
Hydraulic Fracturing Regulation
 
We use hydraulic fracturing as a means to maximize the productivity of our oil and natural gas wells in most wells that we drill and complete. Although average drilling and completion costs for each area will vary, as will the cost of each well within a given area, on average approximately 60% of the drilling and completion costs for our horizontal wells are associated with hydraulic fracturing activities. These costs are treated in the same way that all other costs of drilling and completion of our wells are treated and are built into and funded through our normal capital expenditures budget.
 
Hydraulic fracturing technology, which has been used by the oil and natural gas industry for more than 60 years and is constantly being enhanced, enables companies to produce crude oil and natural gas that would otherwise not be recovered. Specifically, hydraulic fracturing is a process in which pressurized fluid is pumped into underground formations to create tiny fractures or spaces that allow crude oil and natural gas to flow from the reservoir into the well so that it can be brought to the surface. The makeup of the fluid used in the hydraulic fracturing process is typically more than 99% water and sand, and less than 1% highly diluted chemical additives. While the majority of the sand remains underground to hold open the fractures, a significant percentage of the water and chemical additives flow back and are then either recycled or safely disposed of at sites that are approved and permitted by the appropriate regulatory authorities. Hydraulic fracturing generally takes place thousands of feet underground, a considerable distance below any drinking water aquifers, and there are impermeable layers of rock between the area fractured and the water aquifers.  
 
Recently, there has been increasing regulatory scrutiny of hydraulic fracturing, which is generally exempted from regulation as underground injection on the federal level pursuant to the SDWA. However, the U.S. Senate and House of Representatives have considered legislation to repeal this exemption. If enacted, these proposals would amend the definition of “underground injection” in the SDWA to encompass hydraulic fracturing activities. If enacted, such a provision could require hydraulic fracturing operations to meet permitting and financial assurance requirements, adhere to certain construction specifications, fulfill monitoring, reporting and recordkeeping obligations, and meet plugging and abandonment requirements. These legislative proposals have also contained language to require the reporting and public disclosure of chemicals used in the fracturing process. If the exemption for hydraulic fracturing is removed from the SDWA, or if other legislation is enacted at the federal, state or local level, any restrictions on the use of hydraulic fracturing contained in any such legislation could have a significant impact on our business, financial condition and results of operations.
 
 
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In addition, at the federal level and in some states, there has been a push to place additional regulatory burdens upon hydraulic fracturing activities. Certain bills have been introduced in the Senate and the House of Representatives that, if adopted, could increase the possibility of litigation and establish an additional level of regulation at the federal level that could lead to operational delays or increased operating costs and could, and in all likelihood would, result in additional regulatory burdens, making it more difficult to perform hydraulic fracturing operations and increasing our costs of compliance. At the state level, Wyoming and Texas, for example, have enacted requirements for the disclosure of the composition of the fluids used in hydraulic fracturing. On June 17, 2011, Texas signed into law a mandate for public disclosure of the chemicals that operators use during hydraulic fracturing in Texas. The law went into effect September 1, 2011. In addition, several local governments in Texas have imposed temporary moratoria on drilling permits within city limits so that local ordinances may be reviewed to assess their adequacy to address hydraulic fracturing activities. Additional burdens upon hydraulic fracturing, such as reporting requirements or permitting requirements for the hydraulic fracturing activity, will result in additional expense and delay in our operations.
 
We are not able to predict the timing, scope and effect of any currently proposed or future laws or regulations regarding hydraulic fracturing, but the direct and indirect costs of such laws and regulations (if enacted) could materially and adversely affect our business, financial conditions and results of operations. See “Risk Factors,” including “Our operations are subject to operational hazards and unforeseen interruptions for which we may not be adequately insured” and "Federal and state legislation and regulatory initiatives relating to hydraulic fracturing and water disposal could result increased costs and additional operating restrictions or delays."
 
International Regulation
 
Our anticipated future exploration and production operations outside the U.S. will be subject to various types of regulations imposed by the respective governments of the countries in which our operations may be conducted and that may affect our operations and costs. We currently have no operations outside of the U.S., however we will have such operations upon completion of the proposed Kazakhstan Acquisition. We have not yet assessed the scope and effect of any currently proposed or future foreign laws, regulations or treaties, including those regarding climate change and hydraulic fracturing, but the direct and indirect costs of such laws, regulations and treaties (if enacted) could materially and adversely affect our business, results of operations, financial condition and competitive position.
 
Insurance
 
Our oil and gas properties are subject to hazards inherent in the oil and gas industry, such as accidents, blowouts, explosions, implosions, fires and oil spills. These conditions can cause:
 
damage to or destruction of property, equipment and the environment; and
personal injury or loss of life; and,
suspension of operations.
 
We maintain insurance coverage that we believe to be customary in the industry against these types of hazards. However, we may not be able to maintain adequate insurance in the future at rates we consider reasonable. In addition, our insurance is subject to coverage limits and some policies exclude coverage for damages resulting from environmental contamination. The occurrence of a significant event or adverse claim in excess of the insurance coverage that we maintain or that is not covered by insurance could have a material adverse effect on our financial condition and results of operations.
 
Patents and Licenses
 
In February 2009, we filed a provisional patent (application number 61/152,885) relating to the process and unique equipment related to our applied fluid jetting process ("AFJ"). In February 2010, the final patent application was submitted. This patent was approved by the U.S. Patent Office in September 2012. We are currently in the process of working with the inventor to assign the rights to the patent to us.
 
During 2009, we tested the AFJ process on wells in the Austin Chalk play in Central Texas operated by Reliance Oil & Gas, Inc., which we refer to as Reliance, and had some initial production success. We subsequently attempted to apply the process to third-party wells in West Texas and in Kentucky. Due to mechanical failures of the surface equipment, we were unable to achieve any lateral jetting in the down-hole environment. Currently, the AFJ rig and other support vehicles have been moved to a storage yard in Spring, Texas. The AFJ asset is a secondary, non-core business focus for our company and may not ever be commercialized.
 
 
 
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Although we believe the applied fluid technology and related trade secrets may provide us with a competitive edge in the oil and gas service industry, we do not believe this technology to be core to our current business and we are currently not actively pursuing its development and commercialization. However, we are highly committed to protecting the technology. We cannot assure our investors that the scope of any protection we are able to secure for our technology will be adequate to protect such technology, or that we will have the financial resources to engage in litigation against parties who may infringe upon us or seek to rescind their agreements with us. We also cannot provide our investors with any degree of assurance regarding the possible independent development by others of technology similar to that which we have acquired, thereby possibly diminishing our competitive edge.
 
Employees
 
At December 31, 2013, we had 9 full-time employees. We believe that our relationships with our employees are satisfactory. No employee is covered by a collective bargaining agreement. In order to expand our operations in accordance with our business plan, we intend to hire additional employees with expertise in the areas of corporate development, petroleum engineering, geological and geophysical sciences and accounting, as well as hiring additional technical, operations and administrative staff. We are not currently able to estimate the number of employees that we will hire during the next twelve months since that number will depend upon the rate at which our operations expand and upon the extent to which we engage third parties to perform required services.
 
From time to time, we use the services of independent consultants and contractors to perform various professional services, particularly in the areas of geology and geophysics, construction, design, well site surveillance and supervision, permitting and environmental assessment and legal and income tax preparation and accounting services. Independent contractors, at our request, drill our wells and perform field and on-site production operation services for us, including pumping, maintenance, dispatching, inspection and testing.
 
GLOSSARY OF OIL AND NATURAL GAS TERMS
 
The following is a description of the meanings of some of the oil and natural gas terms used in this Annual Report.
 
Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, used in this Annual Report in reference to crude oil or other liquid hydrocarbons.
 
Bcf. An abbreviation for billion cubic feet. Unit used to measure large quantities of gas, approximately equal to 1 trillion Btu.
 
BOE. Barrels of oil equivalent, determined using the ratio of one Bbl of crude oil, condensate or natural gas liquids, to six Mcf of natural gas.
 
Boepd. Barrels of oil equivalent per day.
 
Bopd. Barrels of oil per day.
 
Btu or British thermal unit. The quantity of heat required to raise the temperature of one pound of water by one degree Fahrenheit.
 
Completion. The operations required to establish production of oil or natural gas from a wellbore, usually involving perforations, stimulation and/or installation of permanent equipment in the well or, in the case of a dry hole, the reporting of abandonment to the appropriate agency.
 
Condensate. Liquid hydrocarbons associated with the production of a primarily natural gas reserve.
 
Conventional resources. Natural gas or oil that is produced by a well drilled into a geologic formation in which the reservoir and fluid characteristics permit the natural gas or oil to readily flow to the wellbore.
 
Developed acreage. The number of acres that are allocated or assignable to productive wells.
 
Development well. A well drilled into a proved oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.
 
Estimated ultimate recovery or EUR. Estimated ultimate recovery is the sum of reserves remaining as of a given date and cumulative production as of that date.
 
 
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Exploratory well. A well drilled to find and produce oil or natural gas reserves not classified as proved, to find a new reservoir in a field previously found to be productive of oil or natural gas in another reservoir or to extend a known reservoir.
 
Farmin or farmout. An agreement under which the owner of a working interest in an oil or natural gas lease assigns the working interest or a portion of the working interest to another party who desires to drill on the leased acreage. Generally, the assignee is required to drill one or more wells in order to earn its interest in the acreage. The assignor usually retains a royalty or reversionary interest in the lease. The interest received by an assignee is a “farmin” while the interest transferred by the assignor is a “farmout.”
 
FERC. Federal Energy Regulatory Commission.
 
Field. An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition.
 
Gross acres or gross wells. The total acres or wells in which a working interest is owned.
 
Held by production. An oil and natural gas property under lease in which the lease continues to be in force after the primary term of the lease in accordance with its terms as a result of production from the property.
 
Horizontal drilling or well. A drilling operation in which a portion of the well is drilled horizontally within a productive or potentially productive formation. This operation typically yields a horizontal well that has the ability to produce higher volumes than a vertical well drilled in the same formation. A horizontal well is designed to replace multiple vertical wells, resulting in lower capital expenditures for draining like acreage and limiting surface disruption.
 
Liquids. Liquids, or natural gas liquids, are marketable liquid products including ethane, propane, butane and pentane resulting from the further processing of liquefiable hydrocarbons separated from raw natural gas by a natural gas processing facility.
 
MBbl. One thousand barrels of crude oil or other liquid hydrocarbons.
 
Mcf. One thousand cubic feet of natural gas.
 
Mcfgpd.  Thousands of cubic feet of natural gas per day.
 
MMcf. One million cubic feet of natural gas.
 
MMBtu. One million British thermal units.
 
Net acres or net wells. The sum of the fractional working interest owned in gross acres or wells.
 
Net revenue interest. The interest that defines the percentage of revenue that an owner of a well receives from the sale of oil, natural gas and/or natural gas liquids that are produced from the well.
 
NYMEX. New York Mercantile Exchange.
 
Permeability. A reference to the ability of oil and/or natural gas to flow through a reservoir.
 
Petrophysical analysis. The interpretation of well log measurements, obtained from a string of electronic tools inserted into the borehole, and from core measurements, in which rock samples are retrieved from the subsurface, then combining these measurements with other relevant geological and geophysical information to describe the reservoir rock properties.
 
Play. A set of known or postulated oil and/or natural gas accumulations sharing similar geologic, geographic and temporal properties, such as source rock, migration pathways, timing, trapping mechanism and hydrocarbon type.
 
Possible reserves. Additional reserves that are less certain to be recognized than probable reserves.
 
Probable reserves. Additional reserves that are less certain to be recognized than proved reserves but which, in sum with proved reserves, are as likely as not to be recovered.
 
Producing well, production well or productive well. A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of the well’s production exceed production-related expenses and taxes.
 
 
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Properties. Natural gas and oil wells, production and related equipment and facilities and natural gas, oil or other mineral fee, leasehold and related interests.
 
Prospect. A specific geographic area which, based on supporting geological, geophysical or other data and also preliminary economic analysis using reasonably anticipated prices and costs, is considered to have potential for the discovery of commercial hydrocarbons.
 
Proved developed reserves. Proved reserves that can be expected to be recovered through existing wells and facilities and by existing operating methods.
 
Proved reserves. Reserves of oil and natural gas that have been proved to a high degree of certainty by analysis of the producing history of a reservoir and/or by volumetric analysis of adequate geological and engineering data.
 
Proved undeveloped reserves. Proved reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion.
 
Repeatability. The potential ability to drill multiple wells within a prospect or trend.
 
Reservoir. A porous and permeable underground formation containing a natural accumulation of producible oil and/or natural gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.
 
Royalty interest. An interest in an oil and natural gas lease that gives the owner of the interest the right to receive a portion of the production from the leased acreage (or of the proceeds of the sale thereof), but generally does not require the owner to pay any portion of the costs of drilling or operating the wells on the leased acreage. Royalties may be either landowner’s royalties, which are reserved by the owner of the leased acreage at the time the lease is granted, or overriding royalties, which are usually reserved by an owner of the leasehold in connection with a transfer to a subsequent owner.
 
2-D seismic. The method by which a cross-section of the earth’s subsurface is created through the interpretation of reflecting seismic data collected along a single source profile.
 
3-D seismic. The method by which a three-dimensional image of the earth’s subsurface is created through the interpretation of reflection seismic data collected over a surface grid. 3-D seismic surveys allow for a more detailed understanding of the subsurface than do 2-D seismic surveys and contribute significantly to field appraisal, exploitation and production.
 
Trend. A region of oil and/or natural gas production, the geographic limits of which have not been fully defined, having geological characteristics that have been ascertained through supporting geological, geophysical or other data to contain the potential for oil and/or natural gas reserves in a particular formation or series of formations.
 
Unconventional resource play. A set of known or postulated oil and or natural gas resources or reserves warranting further exploration which are extracted from (a) low-permeability sandstone and shale formations and (b) coalbed methane. These plays require the application of advanced technology to extract the oil and natural gas resources.
 
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 natural gas, regardless of whether such acreage contains proved reserves. Undeveloped acreage is usually considered to be all acreage that is not allocated or assignable to productive wells.
 
Unproved and unevaluated properties. Refers to properties where no drilling or other actions have been undertaken that permit such property to be classified as proved.
 
Vertical well. A hole drilled vertically into the earth from which oil, natural gas or water flows is pumped.
 
Volumetric reserve analysis. A technique used to estimate the amount of recoverable oil and natural gas. It involves calculating the volume of reservoir rock and adjusting that volume for the rock porosity, hydrocarbon saturation, formation volume factor and recovery factor.
 
Wellbore. The hole made by a well.
 
Working interest. The operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and receive a share of production.
 
 
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ITEM 1A.  RISK FACTORS.
 
An investment in our common stock involves a high degree of risk. You should carefully consider the risks described below as well as the other information in this filing before deciding to invest in our company. Any of the risk factors described below could significantly and adversely affect our business, prospects, financial condition and results of operations. Additional risks and uncertainties not currently known or that are currently considered to be immaterial may also materially and adversely affect our business, prospects, financial condition and results of operations. As a result, the trading price or value of our common stock could be materially adversely affected and you may lose all or part of your investment.
 
Risks Related to the Oil and Natural Gas Industry and Our Business
 
       We have a limited operating history and expect to continue to incur losses for an indeterminable period of time.
 
We have a limited operating history and are engaged in the initial stages of exploration, development and exploitation of our leasehold acreage and will continue to be so until commencement of substantial production from our oil and natural gas properties, which will depend upon successful drilling results, additional and timely capital funding, and access to suitable infrastructure. Companies in their initial stages of development face substantial business risks and may suffer significant losses. We have generated substantial net losses and negative cash flows from operating activities in the past and expect to continue to incur substantial net losses as we continue our drilling program. In considering an investment in our common stock, you should consider that there is only limited historical and financial operating information available upon which to base your evaluation of our performance.  We have incurred losses from operations of $30,922,151 from the date of inception (February 9, 2011) through December 31, 2013. Additionally, we are dependent on obtaining additional debt and/or equity financing to roll-out and scale our planned principal business operations. Management’s plans in regard to these matters consist principally of seeking additional debt and/or equity financing combined with expected cash flows from current oil and gas assets held and additional oil and gas assets that we may acquire. Our efforts may not be successful and funds may not be available on favorable terms, if at all.
 
We face challenges and uncertainties in financial planning as a result of the unavailability of historical data and uncertainties regarding the nature, scope and results of our future activities. New companies must develop successful business relationships, establish operating procedures, hire staff, install management information and other systems, establish facilities and obtain licenses, as well as take other measures necessary to conduct their intended business activities. We may not be successful in implementing our business strategies or in completing the development of the infrastructure necessary to conduct our business as planned. In the event that one or more of our drilling programs is not completed or is delayed or terminated, our operating results will be adversely affected and our operations will differ materially from the activities described in this Annual Report. As a result of industry factors or factors relating specifically to us, we may have to change our methods of conducting business, which may cause a material adverse effect on our results of operations and financial condition.  The uncertainty and risks described in this Annual Report may impede our ability to economically find, develop, exploit and acquire oil and natural gas reserves.  As a result, we may not be able to achieve or sustain profitability or positive cash flows provided by our operating activities in the future.
 
We will need additional capital to complete future acquisitions, conduct our operations and fund our business and our ability to obtain the necessary funding is uncertain.
 
We will need to raise additional funding to complete future potential acquisitions and may need to raise additional funds through public or private debt or equity financing or other various means to fund our operations, acquire assets and complete exploration and drilling operations. In such a case, adequate funds may not be available when needed or may not be available on favorable terms. If we need to raise additional funds in the future, by issuing equity securities, dilution to existing stockholders will result, and such securities may have rights, preferences and privileges senior to those of our common stock. If funding is insufficient at any time in the future and we are unable to generate sufficient revenue from new business arrangements, to complete planned acquisitions or operations, our results of operations and the value of our securities could be adversely affected.
 
 
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Our $34.5 million Wattenberg Asset acquisition debt facility and $15.5 million drilling facility, includes various covenants, reduces our financial flexibility, increases our interest expense and may adversely impact our operations and our costs.
 
In connection with our acquisition of the Wattenberg Asset on March 7, 2014, we entered into a senior debt facility pursuant to which we borrowed $34.5 million, and have an additional $15.5 million available for future drilling operations, subject to the terms and conditions of such facility (as described in greater detail below in the risk factor entitled “Our ability to borrow additional funds under the debt facility is subject to certain requirements and limitations set forth in our debt facility”), which amounts represent a significant amount of additional indebtedness. The debt facility includes various covenants (positive and negative) binding us, including:
 
  
requiring that we maintain the registration of our common stock under Section 12 of the Securities Exchange Act of 1934, as amended;
 
  
requiring that we maintain the listing of our common stock on the NYSE MKT;
 
  
requiring that we timely file periodic reports under the Exchange Act;
 
  
requiring that we provide the lenders yearly and quarterly budgets and certain reserve reports;
 
  
requiring that we provide capital expenditure plans to the lenders prior to making certain expenditures;
 
  
prohibiting us and our subsidiaries from creating or becoming subject to any indebtedness, except pursuant to certain limited exceptions; and
 
  
prohibiting us or our subsidiaries from merging, selling their assets (except in the usual course of business), altering our organizational structure, winding up or liquidating, except in certain limited circumstances.
 
This new debt facility affects our operations in several ways, including the following:
 
  
a significant portion of our cash flows must be used to service the debt facility, including the obligation to pay monthly in arrears interest accruing at 15% per annum, and the monthly obligation to prepay the debt in an amount equal to the lesser of (a) the outstanding principal amount of the debt and (b) twenty-five percent (25%) of the aggregate of all net revenues actually received by us and our subsidiaries;
 
  
the high level of debt could increase our vulnerability to general adverse economic and industry conditions;
 
  
limiting our ability to borrow additional funds, dispose of assets, pay dividends and make certain investments; and
 
  
the debt covenants may affect our flexibility in planning for, and reacting to, changes in the economy and in our industry.
 
The high level of indebtedness under this new debt facility increases the risk that we may default on our debt obligations.  We may not be able to generate sufficient cash flows to pay the principal or interest on our debt, 25% of any revenues we do generate will be required to be used to repay the debt, and future working capital, borrowings or equity financing may not be available to pay or refinance such debt.  If we do not have sufficient funds and are otherwise unable to arrange financing to pay the interest or principal due on the debt, fund our business plan and satisfy our other obligations and liabilities, we may have to sell significant assets or have a portion of our assets foreclosed upon which could have a material adverse effect on our business, financial condition and results of operations.
 
We do not currently have any commitments of additional capital except pursuant to the terms of the debt facility. We can provide no assurance that additional financing will be available on favorable terms, if at all. If we choose to raise additional capital through the sale of other debt or equity securities, such sales may cause substantial dilution to our existing shareholders.
 
The repayment of our debt facility is secured by a security interest in all of our assets.
 
The repayment of our debt facility (which currently has an outstanding principal balance of $34.5 million and provides us the option, pursuant to the terms of the debt facility, to borrow an additional $15.5 million) is secured by a first priority security interest in all of our assets, property, real property and the securities of our subsidiaries and the repayment of such debt is further guaranteed by certain of our subsidiaries.  If we default in the repayment of the debt facility and/or any of the terms and conditions thereof, the lenders may enforce their security interest over our assets which secure the repayment of such debt, and we could be forced to curtail or abandon our current business plans and operations. If that were to happen, any investment in the Company could become worthless.
 
 
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Our ability to borrow additional funds under the debt facility is subject to certain requirements and limitations set forth in our debt facility.
 
From time to time, subject to the terms and conditions of the debt facility (including the requirement that we deposited funds in an aggregate amount of any additional requested loan into a segregated bank account (the “Company Deposits”)), we have the right to request additional loans under our debt facility up to an additional $15.5 million in total or an aggregate of $50 million under such debt facility.  We are required to pay original issue discounts in the amount of 5% of the funds borrowed, underwriting fees in the amount of 10% of the amount of the funds borrowed, reimburse certain of the legal fees of the lender’s counsel, and pay applicable investment banking fees representing 5% of any funds borrowed, in connection with funds borrowed.  Funds borrowed are only eligible to be used by us, together with Company Deposits, for approved authorization for expenditures (“AFEs”) issued for a well or wells to be drilled and completed on any properties acquired in connection with the Wattenberg Asset, or the Mississippian Asset (the “Permitted Expenditures”).  In the event we drill a dry hole, we are prohibited from using any additional proceeds borrowed under the debt facility without the consent of the lender.  Additionally, no proceeds we receive from the transfer, sale, assignment or farm-out of the Mississippian Asset may be used to fund the Company Deposits.  The requirement that we put up funds equal to any further borrowing under the facility, fees required to be paid in connection with such further loans and the restrictions on our ability to borrow funds under such debt facility and our use of such funds may limit our ability to borrow funds under such facility, complete our planned business operations with funds from such debt facility, and increase our cost of borrowing, which individually or in the aggregate could have a material adverse effect on our results of operations.

The occurrence of an event of default under the notes sold in connection with our debt facility could have a material adverse effect on us and our financial condition.
 
The notes issued in connection with our debt facility include standard and customary events of default, including, among other things, our or any subsidiary’s default in the payment of any indebtedness under any agreement, or failure to comply with the terms and conditions of any other agreement related to indebtedness or otherwise, if the effect of such failure or default, is to cause, or permit the holder or holders thereof, or any counterparty to an agreement relating to indebtedness, to cause indebtedness, or amounts due thereunder, in an aggregate amount of $250,000 or more to become due prior to its stated date of maturity or the date such amount would otherwise have been due notwithstanding such default, subject to certain exclusions; the loss, suspension or revocation of, or failure to renew, any license or permit, if such license or permit is not obtained or reinstated within thirty (30) days, unless such loss, suspension, revocation or failure to renew could not reasonably be expected to have a material adverse effect on us; or there is filed against us or any of our subsidiaries or any of our officers, members or  managers any civil or criminal action, suit or proceeding under any federal or state racketeering statute (including, without limitation, the Racketeer Influenced and Corrupt Organization Act of 1970), or any civil or criminal action, suit or proceeding under any other applicable law is filed by any governmental entity, that could result in the confiscation or forfeiture of any material portion of any collateral subject to any security interest held by the investors or their agent or other assets of such entity or person, and such action, suit or proceeding is not dismissed within one hundred twenty (120) days.
 
Upon an event of default under the notes, the holder of such note may declare the entire unpaid balance (as well as any interest, fees and expenses) immediately due and payable.  Funding to repay such notes may not be available timely, on favorable terms, if at all, and any default by us of the terms and conditions of the notes would likely have a material adverse effect on our results of operations, financial condition and the value of our common stock.
 
Drilling for and producing oil and natural gas are highly speculative and involve a high degree of risk, with many uncertainties that could adversely affect our business. We have not recorded significant proved reserves, and areas that we decide to drill may not yield oil or natural gas in commercial quantities or at all.
 
Exploring for and developing hydrocarbon reserves involves a high degree of operational and financial risk, which precludes us from definitively predicting the costs involved and time required to reach certain objectives.  Our potential drilling locations are in various stages of evaluation, ranging from locations that are ready to drill to locations that will require substantial additional interpretation before they can be drilled.  The budgeted costs of planning, drilling, completing and operating wells are often exceeded and such costs can increase significantly due to various complications that may arise during the drilling and operating processes. Before a well is spud, we may incur significant geological and geophysical (seismic) costs, which are incurred whether a well eventually produces commercial quantities of hydrocarbons or is drilled at all.  Exploration wells bear a much greater risk of loss than development wells.  The analogies we draw from available data from other wells, more fully explored locations or producing fields may not be applicable to our drilling locations.  If our actual drilling and development costs are significantly more than our estimated costs, we may not be able to continue our operations as proposed and could be forced to modify our drilling plans accordingly.
 
 
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If we decide to drill a certain location, there is a risk that no commercially productive oil or natural gas reservoirs will be found or produced.  We may drill or participate in new wells that are not productive.  We may drill wells that are productive, but that do not produce sufficient net revenues to return a profit after drilling, operating and other costs.  There is no way to predict in advance of drilling and testing whether any particular location will yield oil or natural gas in sufficient quantities to recover exploration, drilling or completion costs or to be economically viable.  Even if sufficient amounts of oil or natural gas exist, we may damage the potentially productive hydrocarbon-bearing formation or experience mechanical difficulties while drilling or completing the well, resulting in a reduction in production and reserves from the well or abandonment of the well.  Whether a well is ultimately productive and profitable depends on a number of additional factors, including the following:
 
  
general economic and industry conditions, including the prices received for oil and natural gas;
 
  
shortages of, or delays in, obtaining equipment, including hydraulic fracturing equipment, and qualified personnel;
 
  
potential drainage by operators on adjacent properties;
 
  
loss of or damage to oilfield development and service tools;
 
  
problems with title to the underlying properties;
 
  
increases in severance taxes;
 
  
adverse weather conditions that delay drilling activities or cause producing wells to be shut down;
 
  
domestic and foreign governmental regulations; and
 
  
proximity to and capacity of transportation facilities.
 
If we do not drill productive and profitable wells in the future, our business, financial condition and results of operations could be materially and adversely affected.
 
Our success is dependent on the prices of oil and natural gas.  Low oil or natural gas prices and the substantial volatility in these prices may adversely affect our business, financial condition and results of operations and our ability to meet our capital expenditure requirements and financial obligations.
 
The prices we receive for our oil and natural gas heavily influence our revenue, profitability, cash flow available for capital expenditures, access to capital and future rate of growth. Oil and natural gas are commodities and, therefore, their prices are subject to wide fluctuations in response to relatively minor changes in supply and demand. Historically, the prices for oil and natural gas have been volatile. For example, for the four years ended December 31, 2013, the NYMEX - WTI oil price ranged from a high of $113.93 per Bbl to a low of $68.01 per Bbl, while the NYMEX - Henry Hub natural gas price ranged from a high of $7.51 per MMBtu to a low of $1.82 per MMBtu. These markets will likely continue to be volatile in the future. The prices we receive for our production, and the levels of our production, depend on numerous factors. These factors include the following:
 
  
the domestic and foreign supply of oil and natural gas;
 
  
the domestic and foreign demand for oil and natural gas;
 
  
the prices and availability of competitors’ supplies of oil and natural gas;
 
  
the actions of the Organization of Petroleum Exporting Countries, or OPEC, and state-controlled oil companies relating to oil price and production controls;
 
  
the price and quantity of foreign imports of oil and natural gas;
 
  
the impact of U.S. dollar exchange rates on oil and natural gas prices;
 
  
domestic and foreign governmental regulations and taxes;
 
  
speculative trading of oil and natural gas futures contracts;
 
  
localized supply and demand fundamentals, including the availability, proximity and capacity of gathering and transportation systems for natural gas;
 
 
 
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the availability of refining capacity;
 
  
the prices and availability of alternative fuel sources;
 
  
weather conditions and natural disasters;
 
  
political conditions in or affecting oil and natural gas producing regions, including the Middle East and South America;
 
  
the continued threat of terrorism and the impact of military action and civil unrest;
 
  
public pressure on, and legislative and regulatory interest within, federal, state and local governments to stop, significantly limit or regulate hydraulic fracturing activities;
 
  
the level of global oil and natural gas inventories and exploration and production activity;
 
  
authorization of exports from the Unites States of liquefied natural gas;
 
  
the impact of energy conservation efforts;
 
  
technological advances affecting energy consumption; and
 
  
overall worldwide economic conditions.
 
Declines in oil or natural gas prices would not only reduce our revenue, but could reduce the amount of oil and natural gas that we can produce economically. Should natural gas or oil prices decrease from current levels and remain there for an extended period of time, we may elect in the future to delay some of our exploration and development plans for our prospects, or to cease exploration or development activities on certain prospects due to the anticipated unfavorable economics from such activities, and, as a result, we may have to make substantial downward adjustments to our estimated proved reserves, each of which would have a material adverse effect on our business, financial condition and results of operations.
 
Our exploration, development and exploitation projects require substantial capital expenditures that may exceed cash on hand, cash flows from operations and potential borrowings, and we may be unable to obtain needed capital on satisfactory terms, which could adversely affect our future growth.
 
Our exploration and development activities are capital intensive.  We make and expect to continue to make substantial capital expenditures in our business for the development, exploitation, production and acquisition of oil and natural gas reserves.  Our cash on hand, our operating cash flows and future potential borrowings may not be adequate to fund our future acquisitions or future capital expenditure requirements.  The rate of our future growth may be dependent, at least in part, on our ability to access capital at rates and on terms we determine to be acceptable.
  
Our cash flows from operations and access to capital are subject to a number of variables, including:
 
  
our estimated proved oil and natural gas reserves;
 
  
the amount of oil and natural gas we produce from existing wells;
 
  
the prices at which we sell our production;
 
  
the costs of developing and producing our oil and natural gas reserves;
 
  
our ability to acquire, locate and produce new reserves;
 
  
the ability and willingness of banks to lend to us; and
 
  
our ability to access the equity and debt capital markets.
 
 
 
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In addition, future events, such as terrorist attacks, wars or combat peace-keeping missions, financial market disruptions, general economic recessions, oil and natural gas industry recessions, large company bankruptcies, accounting scandals, overstated reserves estimates by major public oil companies and disruptions in the financial and capital markets have caused financial institutions, credit rating agencies and the public to more closely review the financial statements, capital structures and earnings of public companies, including energy companies.  Such events have constrained the capital available to the energy industry in the past, and such events or similar events could adversely affect our access to funding for our operations in the future.
 
If our revenues decrease as a result of lower oil and natural gas prices, operating difficulties, declines in reserves or for any other reason, we may have limited ability to obtain the capital necessary to sustain our operations at current levels, further develop and exploit our current properties or invest in additional exploration opportunities.  Alternatively, a significant improvement in oil and natural gas prices or other factors could result in an increase in our capital expenditures and we may be required to alter or increase our capitalization substantially through the issuance of debt or equity securities, the sale of production payments, the sale or farm out of interests in our assets, the borrowing of funds or otherwise to meet any increase in capital needs.  If we are unable to raise additional capital from available sources at acceptable terms, our business, financial condition and results of operations could be adversely affected.  Further, future debt financings may require that a portion of our cash flows provided by operating activities be used for the payment of principal and interest on our debt, thereby reducing our ability to use cash flows to fund working capital, capital expenditures and acquisitions.  Debt financing may involve covenants that restrict our business activities. If we succeed in selling additional equity securities to raise funds, at such time the ownership percentage of our existing stockholders would be diluted, and new investors may demand rights, preferences or privileges senior to those of existing stockholders. If we choose to farm-out interests in our prospects, we may lose operating control over such prospects.
 
Our oil and natural gas reserves are estimated and may not reflect the actual volumes of oil and natural gas we will receive, and significant inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.
 
The process of estimating accumulations of oil and natural gas is complex and is not exact, due to numerous inherent uncertainties.  The process relies on interpretations of available geological, geophysical, engineering and production data.  The extent, quality and reliability of this technical data can vary.  The process also requires certain economic assumptions related to, among other things, oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds.  The accuracy of a reserves estimate is a function of:
 
the quality and quantity of available data;
 
  
the interpretation of that data;
 
  
the judgment of the persons preparing the estimate; and
 
  
the accuracy of the assumptions.
 
The accuracy of any estimates of proved reserves generally increases with the length of the production history.  Due to the limited production history of our properties, the estimates of future production associated with these properties may be subject to greater variance to actual production than would be the case with properties having a longer production history.  As our wells produce over time and more data is available, the estimated proved reserves will be re-determined on at least an annual basis and may be adjusted to reflect new information based upon our actual production history, results of exploration and development, prevailing oil and natural gas prices and other factors.
 
Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas most likely will vary from our estimates.  It is possible that future production declines in our wells may be greater than we have estimated.  Any significant variance to our estimates could materially affect the quantities and present value of our reserves.
 
We may have accidents, equipment failures or mechanical problems while drilling or completing wells or in production activities, which could adversely affect our business.
 
While we are drilling and completing wells or involved in production activities, we may have accidents or experience equipment failures or mechanical problems in a well that cause us to be unable to drill and complete the well or to continue to produce the well according to our plans.  We may also damage a potentially hydrocarbon-bearing formation during drilling and completion operations.  Such incidents may result in a reduction of our production and reserves from the well or in abandonment of the well.
 
 
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Our operations are subject to operational hazards and unforeseen interruptions for which we may not be adequately insured.
 
There are numerous operational hazards inherent in oil and natural gas exploration, development, production and gathering, including:
 
  
unusual or unexpected geologic formations;
 
  
natural disasters;
 
  
adverse weather conditions;
 
  
unanticipated pressures;
 
  
loss of drilling fluid circulation;
 
  
blowouts where oil or natural gas flows uncontrolled at a wellhead;
 
  
cratering or collapse of the formation;
 
  
pipe or cement leaks, failures or casing collapses;
 
  
fires or explosions;
 
  
releases of hazardous substances or other waste materials that cause environmental damage;
 
  
pressures or irregularities in formations; and
 
  
equipment failures or accidents.
  
In addition, there is an inherent risk of incurring significant environmental costs and liabilities in the performance of our operations, some of which may be material, due to our handling of petroleum hydrocarbons and wastes, our emissions to air and water, the underground injection or other disposal of our wastes, the use of hydraulic fracturing fluids and historical industry operations and waste disposal practices.
 
Any of these or other similar occurrences could result in the disruption or impairment of our operations, substantial repair costs, personal injury or loss of human life, significant damage to property, environmental pollution and substantial revenue losses.  The location of our wells, gathering systems, pipelines and other facilities near populated areas, including residential areas, commercial business centers and industrial sites, could significantly increase the level of damages resulting from these risks.  Insurance against all operational risks is not available to us.  We are not fully insured against all risks, including development and completion risks that are generally not recoverable from third parties or insurance. In addition, pollution and environmental risks generally are not fully insurable.  We maintain $2 million general liability coverage and $10 million umbrella coverage that covers our and our subsidiaries’ business and operations.  Our wholly-owned subsidiary, Red Hawk, which operates our Wattenberg Asset, also maintains a $10 million control of well insurance policy that covers its operations in Colorado, and our partially-owned subsidiary, Condor, which operates our current Niobrara Asset, maintains a $10 million control of well insurance policy, a $2 million commercial general liability insurance policy, and a $10 million umbrella insurance policy that covers its operations in Colorado.  With respect to our other non-operated assets, we may elect not to obtain insurance if we believe that the cost of available insurance is excessive relative to the perceived risks presented.  Losses could, therefore, occur for uninsurable or uninsured risks or in amounts in excess of existing insurance coverage.  Moreover, insurance may not be available in the future at commercially reasonable prices or on commercially reasonable terms.  Changes in the insurance markets due to various factors may make it more difficult for us to obtain certain types of coverage in the future.  As a result, we may not be able to obtain the levels or types of insurance we would otherwise have obtained prior to these market changes, and the insurance coverage we do obtain may not cover certain hazards or all potential losses that are currently covered, and may be subject to large deductibles.  Losses and liabilities from uninsured and underinsured events and delay in the payment of insurance proceeds could have a material adverse effect on our business, financial condition and results of operations.
 
 
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Our strategy as an onshore unconventional resource player may result in operations concentrated in certain geographic areas and may increase our exposure to many of the risks described in this Annual Report.
 
Our initial operations are concentrated in the States of Colorado, Texas, and Kansas.  This concentration may increase the potential impact of many of the risks described in this Annual Report.  For example, we may have greater exposure to regulatory actions impacting these four states, natural disasters in these states, competition for equipment, services and materials available in the areas and access to infrastructure and markets in those areas.
 
Unless we replace our oil and natural gas reserves, our reserves and production will decline, which would adversely affect our business, financial condition and results of operations.
 
The rate of production from our oil and natural gas properties will decline as our reserves are depleted. Our future oil and natural gas reserves and production and, therefore, our income and cash flow, are highly dependent on our success in (a) efficiently developing and exploiting our current reserves on properties owned by us or by other persons or entities and (b) economically finding or acquiring additional oil and natural gas producing properties.  In the future, we may have difficulty acquiring new properties.  During periods of low oil and/or natural gas prices, it will become more difficult to raise the capital necessary to finance expansion activities.  If we are unable to replace our production, our reserves will decrease, and our business, financial condition and results of operations would be adversely affected.
 
            Our strategy includes acquisitions of oil and natural gas properties, and our failure to identify or complete future acquisitions successfully could reduce our earnings and hamper our growth.
 
We may be unable to identify properties for acquisition or to make acquisitions on terms that we consider economically acceptable.  There is intense competition for acquisition opportunities in our industry. Competition for acquisitions may increase the cost of, or cause us to refrain from, completing acquisitions.  The completion and pursuit of acquisitions may be dependent upon, among other things, our ability to obtain debt and equity financing and, in some cases, regulatory approvals.  Our ability to grow through acquisitions will require us to continue to invest in operations, financial and management information systems and to attract, retain, motivate and effectively manage our employees.  The inability to manage the integration of acquisitions effectively could reduce our focus on subsequent acquisitions and current operations, and could negatively impact our results of operations and growth potential.  Our financial position and results of operations may fluctuate significantly from period to period as a result of the completion of significant acquisitions during particular periods.  If we are not successful in identifying or acquiring any material property interests, our earnings could be reduced and our growth could be restricted.
 
We may engage in bidding and negotiating to complete successful acquisitions.  We may be required to alter or increase substantially our capitalization to finance these acquisitions through the use of cash on hand, the issuance of debt or equity securities, the sale of production payments, the sale of non-strategic assets, the borrowing of funds or otherwise.  If we were to proceed with one or more acquisitions involving the issuance of our common stock, our shareholders would suffer dilution of their interests.  Furthermore, our decision to acquire properties that are substantially different in operating or geologic characteristics or geographic locations from areas with which our staff is familiar may impact our productivity in such areas.
 
We may purchase oil and natural gas properties with liabilities or risks that we did not know about or that we did not assess correctly, and, as a result, we could be subject to liabilities that could adversely affect our results of operations.
 
Before acquiring oil and natural gas properties, we estimate the reserves, future oil and natural gas prices, operating costs, potential environmental liabilities and other factors relating to the properties.  However, our review involves many assumptions and estimates, and their accuracy is inherently uncertain.  As a result, we may not discover all existing or potential problems associated with the properties we buy.  We may not become sufficiently familiar with the properties to assess fully their deficiencies and capabilities.  We do not generally perform inspections on every well or property, and we may not be able to observe mechanical and environmental problems even when we conduct an inspection.  The seller may not be willing or financially able to give us contractual protection against any identified problems, and we may decide to assume environmental and other liabilities in connection with properties we acquire.  If we acquire properties with risks or liabilities we did not know about or that we did not assess correctly, our business, financial condition and results of operations could be adversely affected as we settle claims and incur cleanup costs related to these liabilities.
 
We may incur losses or costs as a result of title deficiencies in the properties in which we invest.
 
If an examination of the title history of a property that we have purchased reveals an oil and natural gas lease has been purchased in error from a person who is not the owner of the property, our interest would be worthless.  In such an instance, the amount paid for such oil and natural gas lease as well as any royalties paid pursuant to the terms of the lease prior to the discovery of the title defect would be lost.
 
 
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Prior to the drilling of an oil and natural gas well, it is the normal practice in the oil and natural gas industry for the person or company acting as the operator of the well to obtain a preliminary title review of the spacing unit within which the proposed oil and natural gas well is to be drilled to ensure there are no obvious deficiencies in title to the well.  Frequently, as a result of such examinations, certain curative work must be done to correct deficiencies in the marketability of the title, and such curative work entails expense.  Our failure to cure any title defects may adversely impact our ability in the future to increase production and reserves.  In the future, we may suffer a monetary loss from title defects or title failure.  Additionally, unproved and unevaluated acreage has greater risk of title defects than developed acreage. If there are any title defects or defects in assignment of leasehold rights in properties in which we hold an interest, we will suffer a financial loss which could adversely affect our business, financial condition and results of operations.
 
Our identified drilling locations are scheduled over several years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling.
 
Our management team has identified and scheduled drilling locations in our operating areas over a multi-year period.  Our ability to drill and develop these locations depends on a number of factors, including the availability of equipment and capital, approval by regulators, seasonal conditions, oil and natural gas prices, assessment of risks, costs and drilling results.  The final determination on whether to drill any of these locations will be dependent upon the factors described elsewhere in this filing and the documents incorporated by reference herein, as well as, to some degree, the results of our drilling activities with respect to our established drilling locations.  Because of these uncertainties, we do not know if the drilling locations we have identified will be drilled within our expected timeframe or at all or if we will be able to economically produce hydrocarbons from these or any other potential drilling locations.  Our actual drilling activities may be materially different from our current expectations, which could adversely affect our business, financial condition and results of operations.
 
We currently license only a limited amount of seismic and other geological data and may have difficulty obtaining additional data at a reasonable cost, which could adversely affect our future results of operations.
 
We currently license only a limited amount of seismic and other geological data to assist us in exploration and development activities.  We intend to obtain access to additional data in our areas of interest through licensing arrangements with companies that own or have access to that data or by paying to obtain that data directly.  Seismic and geological data can be expensive to license or obtain.  We may not be able to license or obtain such data at an acceptable cost. In addition, even when properly interpreted, seismic data and visualization techniques are not conclusive in determining if hydrocarbons are present in economically producible amounts and seismic indications of hydrocarbon saturation are generally not reliable indicators of productive reservoir rock.
 
The unavailability or high cost of drilling rigs, completion equipment and services, supplies and personnel, including hydraulic fracturing equipment and personnel, could adversely affect our ability to establish and execute exploration and development plans within budget and on a timely basis, which could have a material adverse effect on our business, financial condition and results of operations.
 
Shortages or the high cost of drilling rigs, completion equipment and services, supplies or personnel could delay or adversely affect our operations.  When drilling activity in the United States increases, associated costs typically also increase, including those costs related to drilling rigs, equipment, supplies and personnel and the services and products of other vendors to the industry.  These costs may increase, and necessary equipment and services may become unavailable to us at economical prices.  Should this increase in costs occur, we may delay drilling activities, which may limit our ability to establish and replace reserves, or we may incur these higher costs, which may negatively affect our business, financial condition and results of operations.
 
In addition, the demand for hydraulic fracturing services currently exceeds the availability of fracturing equipment and crews across the industry and in our operating areas in particular.  The accelerated wear and tear of hydraulic fracturing equipment due to its deployment in unconventional oil and natural gas fields characterized by longer lateral lengths and larger numbers of fracturing stages has further amplified this equipment and crew shortage. If demand for fracturing services continues to increase or the supply of fracturing equipment and crews decreases, then higher costs could result and could adversely affect our business, financial condition and results of operations.
 
 
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We have limited control over activities on properties we do not operate.
 
We are not the operator on some of our properties and, as a result, our ability to exercise influence over the operations of these properties or their associated costs is limited.  Our dependence on the operators and other working interest owners of these projects and our limited ability to influence operations and associated costs or control the risks could materially and adversely affect the realization of our targeted returns on capital in drilling or acquisition activities.  The success and timing of our drilling and development activities on properties operated by others therefore depends upon a number of factors, including:
 
  
timing and amount of capital expenditures;
 
  
the operator’s expertise and financial resources;
 
  
the rate of production of reserves, if any;
 
  
approval of other participants in drilling wells; and
 
  
selection of technology.
 
The marketability of our production is dependent upon oil and natural gas gathering and transportation facilities owned and operated by third parties, and the unavailability of satisfactory oil and natural gas transportation arrangements would have a material adverse effect on our revenue.
 
The unavailability of satisfactory oil and natural gas transportation arrangements may hinder our access to oil and natural gas markets or delay production from our wells.  The availability of a ready market for our oil and natural gas production depends on a number of factors, including the demand for, and supply of, oil and natural gas and the proximity of reserves to pipelines and terminal facilities.  Our ability to market our production depends in substantial part on the availability and capacity of gathering systems, pipelines and processing facilities owned and operated by third parties.  Our failure to obtain these services on acceptable terms could materially harm our business.  We may be required to shut-in wells for lack of a market or because of inadequacy or unavailability of pipeline or gathering system capacity.  If that were to occur, we would be unable to realize revenue from those wells until production arrangements were made to deliver our production to market.  Furthermore, if we were required to shut-in wells we might also be obligated to pay shut-in royalties to certain mineral interest owners in order to maintain our leases.  We do not expect to purchase firm transportation capacity on third-party facilities.  Therefore, we expect the transportation of our production to be generally interruptible in nature and lower in priority to those having firm transportation arrangements.
 
The disruption of third-party facilities due to maintenance and/or weather could negatively impact our ability to market and deliver our products.  The third parties control when or if such facilities are restored and what prices will be charged.  Federal and state regulation of oil and natural gas production and transportation, tax and energy policies, changes in supply and demand, pipeline pressures, damage to or destruction of pipelines and general economic conditions could adversely affect our ability to produce, gather and transport oil and natural gas.
 
Strategic relationships, including with MIE Holdings, STXRA, and RJ Resources, upon which we may rely, are subject to risks and uncertainties which may adversely affect our business, financial conditions and results of operations.
 
Our ability to explore, develop and produce oil and natural gas resources successfully and acquire oil and natural gas interests and acreage depends on our developing and maintaining close working relationships with industry participants and on our ability to select and evaluate suitable acquisition opportunities in a highly competitive environment.   These realities are subject to risks and uncertainties that may adversely affect our business, financial condition and results of operations.
 
To develop our business, we will endeavor to use the business relationships of our management and board to enter into strategic relationships, which may take the form of contractual arrangements with other oil and natural gas companies, including those that supply equipment and other resources that we expect to use in our business.  For example, we have entered into a strategic relationship with MIE Holdings with respect to several of our oil and natural gas interests, and have both retained STXRA as a key advisor for our exploration and drilling efforts, and formed Pacific Energy Technology Services, LLC as a jointly-owned technical services venture with STXRA to provide acquisition, engineering, and oil drilling and completion technology services in the United States and abroad.  We have also entered into a strategic relationship with RJ Resources, a subsidiary of a New York-based investment management group with more than $1.3 billion in assets under management specializing in resource investment, whereby RJ Resources has become our equal working interest partner in our Wattenberg Asset, our Mississippian Asset, and our Kazakhstan asset, and has agreed to provided us with a $15.5 million drilling facility, subject to various conditions and requirements (as described in greater detail above in the risk factor entitled “Our ability to borrow additional funds under the debt facility is subject to certain requirements and limitations set forth in our debt facility”).  We may not be able to establish these strategic relationships, or if established, we may not be able to maintain them.  In addition, the dynamics of our relationships with strategic partners may require us to incur expenses or undertake activities we would not otherwise be inclined to incur in order to fulfill our obligations to these partners or maintain our relationships.  If our strategic relationships are not established or maintained, our business, financial condition and results of operations may be adversely affected.
 
 
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An increase in the differential between the NYMEX or other benchmark prices of oil and natural gas and the wellhead price we receive for our production could adversely affect our business, financial condition and results of operations.
 
The prices that we will receive for our oil and natural gas production sometimes may reflect a discount to the relevant benchmark prices, such as NYMEX, that are used for calculating hedge positions. The difference between the benchmark price and the prices we receive is called a differential.  Increases in the differential between the benchmark prices for oil and natural gas and the wellhead price we receive could adversely affect our business, financial condition and results of operations.  We do not have, and may not have in the future, any derivative contracts covering the amount of the basis differentials we experience in respect of our production.  As such, we will be exposed to any increase in such differentials.
 
Our success depends, to a large extent, on our ability to retain our key personnel, including our Chairman of the Board, Chief Executive Officer and President, and our Chief Financial Officer and Executive Vice President, and the loss of any of our key personnel could disrupt our business operations.
 
Investors in our common stock must rely upon the ability, expertise, judgment and discretion of our management and the success of our technical team in identifying, evaluating and developing prospects and reserves.  Our performance and success are dependent to a large extent on the efforts and continued employment of our management and technical personnel, including our Chairman, President and Chief Executive Officer, Frank C. Ingriselli, and our Chief Financial Officer and Executive Vice President, Michael L. Peterson.  We do not believe that they could be quickly replaced with personnel of equal experience and capabilities, and their successors may not be as effective.  If Mr. Ingriselli, Mr. Peterson, or any of our other key personnel resign or become unable to continue in their present roles and if they are not adequately replaced, our business operations could be adversely affected.  Except for a $3 million insurance policy on the life of Mr. Ingriselli, we do not currently maintain any insurance against the loss of any of these individuals.  Further, pursuant to the promissory notes issued pursuant to that certain Note Purchase Agreement, dated March 7, 2014, entered into by and between us and certain investors in connection with our acquisition of the Wattenberg Asset and creation of our $15.5 million drilling facility with RJ Resources, the investors have the right to require us to prepay the entire amount due under the notes if either Mr. Ingriselli or Mr. Peterson cease to be involved in the management of the Company or any subsidiary (except due to death, disability, removal by the Board of Directors, or resignation in order to serve his church, and if a replacement acceptable to the holders is appointed to replace such individual), subject to certain exceptions.  Accordingly, the failure of either Mr. Ingriselli or Mr. Peterson to be involved with our management could result in us being required to prepay such debt prior to maturity, which could materially adversely affect us and disrupt our business operations.
 
We have an active board of directors that meets several times throughout the year and is intimately involved in our business and the determination of our operational strategies.  Our board of directors work closely with management to identify potential prospects, funding sources, acquisitions and areas for further development.  One of our directors has been involved with us since our inception and all of our directors have a deep understanding of our operations and culture.  If any of our directors resign or become unable to continue in their present role, it may be difficult to find replacements with the same knowledge and experience and as a result, our operations may be adversely affected.
 
We may have difficulty managing growth in our business, which could have a material adverse effect on our business, financial condition and results of operations and our ability to execute our business plan in a timely fashion.
 
Because of our small size, growth in accordance with our business plans, if achieved, will place a significant strain on our financial, technical, operational and management resources.  As we expand our activities, including our planned increase in oil exploration, development and production, and increase the number of projects we are evaluating or in which we participate, there will be additional demands on our financial, technical and management resources.  The failure to continue to upgrade our technical, administrative, operating and financial control systems or the occurrence of unexpected expansion difficulties, including the inability to recruit and retain experienced managers, geoscientists, petroleum engineers and landmen could have a material adverse effect on our business, financial condition and results of operations and our ability to execute our business plan in a timely fashion.
 
 
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We have identified material weaknesses in our internal control over financial reporting, and our business and stock price may be adversely affected if we do not adequately address those weaknesses or if we have other material weaknesses or significant deficiencies in our internal control over financial reporting.
 
As a public reporting company, we are required to establish and maintain appropriate internal controls over financial reporting. Rules adopted by the SEC pursuant to Section 404 of the Sarbanes-Oxley Act of 2002 require annual assessment of our internal control over financial reporting. The standards that must be met for management to assess the internal control over financial reporting as effective are complex, and require significant documentation, testing and possible remediation to meet the detailed standards. We may encounter problems or delays in completing activities necessary to make an assessment of our internal control over financial reporting. If we cannot assess our internal control over financial reporting as effective, investor confidence and share value may be negatively impacted. In addition, management’s assessment of internal controls over financial reporting may identify weaknesses and conditions that need to be addressed in our internal controls over financial reporting or other matters that may raise concerns for investors.
 
As described in this Annual Report, we conducted an evaluation of the effectiveness of our internal controls over financial reporting as of December 31, 2013.  Based on that evaluation, we concluded that, as of such date, our internal controls over financial reporting were not effective due to deficiencies that existed in the design of our internal controls over financial reporting that adversely affected our internal controls, and that may be considered to be a material weakness.  As a result of the early stage of our development, we have not fully implemented the necessary internal controls. The matters involving internal controls and procedures that our management considered to be material weaknesses were: (1) insufficient written policies and procedures for accounting and financial reporting with respect to the requirements and application of accounting principles generally accepted in the United States of America and SEC disclosure requirements; and (2) ineffective controls over period end financial disclosure and reporting processes.
 
Although we are in the process of taking steps to remediate these weaknesses, including hiring additional accounting staff to provide more resources and expand our technical accounting knowledge, we may continue to have material weaknesses or significant deficiencies in our internal controls. The existence of these or one or more other material weaknesses or significant deficiencies could result in errors in our financial statements, and substantial costs and resources may be required to rectify any internal control deficiencies. If we cannot produce reliable financial reports, investors could lose confidence in our reported financial information, the market price of our stock could decline significantly, we may be unable to obtain additional financing to operate and expand our business, and our business and financial condition could be harmed.
 
Financial difficulties encountered by our oil and natural gas purchasers, third-party operators or other third parties could decrease our cash flow from operations and adversely affect the exploration and development of our prospects and assets.
 
We will derive substantially all of our revenues from the sale of our oil and natural gas to unaffiliated third-party purchasers, independent marketing companies and mid-stream companies.  Any delays in payments from our purchasers caused by financial problems encountered by them will have an immediate negative effect on our results of operations.
 
Liquidity and cash flow problems encountered by our working interest co-owners or the third-party operators of our non-operated properties may prevent or delay the drilling of a well or the development of a project.  Our working interest co-owners may be unwilling or unable to pay their share of the costs of projects as they become due.  In the case of a farmout party, we would have to find a new farmout party or obtain alternative funding in order to complete the exploration and development of the prospects subject to a farmout agreement.  In the case of a working interest owner, we could be required to pay the working interest owner’s share of the project costs.  We cannot assure you that we would be able to obtain the capital necessary to fund either of these contingencies or that we would be able to find a new farmout party.
 
The calculated present value of future net revenues from our proved reserves will not necessarily be the same as the current market value of our estimated oil and natural gas reserves.
 
You should not assume that the present value of future net cash flows as included in our public filings is the current market value of our estimated proved oil and natural gas reserves.  We generally base the estimated discounted future net cash flows from proved reserves on current costs held constant over time without escalation and on commodity prices using an unweighted arithmetic average of first-day-of-the-month index prices, appropriately adjusted, for the 12-month period immediately preceding the date of the estimate.  Actual future prices and costs may be materially higher or lower than the prices and costs used for these estimates and will be affected by factors such as:
  
actual prices we receive for oil and natural gas;
 
  
actual cost and timing of development and production expenditures;
 
 
 
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the amount and timing of actual production; and
 
  
changes in governmental regulations or taxation.
 
In addition, the 10% discount factor that is required to be used to calculate discounted future net revenues for reporting purposes under GAAP is not necessarily the most appropriate discount factor based on the cost of capital in effect from time to time and risks associated with our business and the oil and natural gas industry in general.
 
We may incur additional indebtedness which could reduce our financial flexibility, increase interest expense and adversely impact our operations and our unit costs.
 
In the future, we may incur significant amounts of additional indebtedness in order to make acquisitions or to develop our properties.  Our level of indebtedness could affect our operations in several ways, including the following:
 
  
a significant portion of our cash flows could be used to service our indebtedness;
 
  
a high level of debt would increase our vulnerability to general adverse economic and industry conditions;
 
  
any covenants contained in the agreements governing our outstanding indebtedness could limit our ability to borrow additional funds, dispose of assets, pay dividends and make certain investments;
 
  
a high level of debt may place us at a competitive disadvantage compared to our competitors that are less leveraged and, therefore, may be able to take advantage of opportunities that our indebtedness may prevent us from pursuing; and
 
  
debt covenants to which we may agree may affect our flexibility in planning for, and reacting to, changes in the economy and in our industry.
 
A high level of indebtedness increases the risk that we may default on our debt obligations.  We may not be able to generate sufficient cash flows to pay the principal or interest on our debt, and future working capital, borrowings or equity financing may not be available to pay or refinance such debt.  If we do not have sufficient funds and are otherwise unable to arrange financing, we may have to sell significant assets or have a portion of our assets foreclosed upon which could have a material adverse effect on our business, financial condition and results of operations.
 
Competition in the oil and natural gas industry is intense, making it difficult for us to acquire properties, market oil and natural gas and secure trained personnel.
 
Our ability to acquire additional prospects and to find and develop reserves in the future will depend on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment for acquiring properties, marketing oil and natural gas and securing trained personnel.  Also, there is substantial competition for capital available for investment in the oil and natural gas industry.  Many of our competitors possess and employ financial, technical and personnel resources substantially greater than ours, and many of our competitors have more established presences in the United States and the Pacific Rim than we have. Those companies may be able to pay more for productive oil and natural gas properties and exploratory prospects and to evaluate, bid for and purchase a greater number of properties and prospects than our financial or personnel resources permit.  In addition, other companies may be able to offer better compensation packages to attract and retain qualified personnel than we are able to offer.  The cost to attract and retain qualified personnel has increased in recent years due to competition and may increase substantially in the future.  We may not be able to compete successfully in the future in acquiring prospective reserves, developing reserves, marketing hydrocarbons, attracting and retaining quality personnel and raising additional capital, which could have a material adverse effect on our business, financial condition and results of operations.
 
Our competitors may use superior technology and data resources that we may be unable to afford or that would require a costly investment by us in order to compete with them more effectively.
 
Our industry is subject to rapid and significant advancements in technology, including the introduction of new products and services using new technologies and databases.  As our competitors use or develop new technologies, we may be placed at a competitive disadvantage, and competitive pressures may force us to implement new technologies at a substantial cost.  In addition, many of our competitors will have greater financial, technical and personnel resources that allow them to enjoy technological advantages and may in the future allow them to implement new technologies before we can.  We cannot be certain that we will be able to implement technologies on a timely basis or at a cost that is acceptable to us.  One or more of the technologies that we will use or that we may implement in the future may become obsolete, and we may be adversely affected.
 
 
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If we do not hedge our exposure to reductions in oil and natural gas prices, we may be subject to significant reductions in prices.  Alternatively, we may use oil and natural gas price hedging contracts, which involve credit risk and may limit future revenues from price increases and result in significant fluctuations in our profitability.
 
In the event that we choose not to hedge our exposure to reductions in oil and natural gas prices by purchasing futures and by using other hedging strategies, we may be subject to significant reduction in prices which could have a material negative impact on our profitability.  Alternatively, we may elect to use hedging transactions with respect to a portion of our oil and natural gas production to achieve more predictable cash flow and to reduce our exposure to price fluctuations.  While the use of hedging transactions limits the downside risk of price declines, their use also may limit future revenues from price increases.  Hedging transactions also involve the risk that the counterparty may be unable to satisfy its obligations.
 
Environmental and overall public scrutiny focused on the oil and gas industry is increasing.  The current trend is to increase regulations of our operations in the industry.  We are subject to federal, state, and local government regulation and liability, including complex environmental laws, which could require significant expenditures and/or adversely affect the cost, manner or feasibility of doing business.
 
            Our exploration, development, production and marketing operations are regulated extensively at the federal, state, and local levels. Environmental and other governmental laws and regulations have increased our costs to plan, design, drill, install, operate and abandon natural gas and crude oil wells. Similar to other companies in our industry, we incur substantial operating and capital costs to comply with such laws and regulations. These compliance costs may put us at a competitive disadvantage compared to larger companies in the industry which can spread such additional costs over a greater number of wells and larger operating staff. Failure to comply with these laws and regulations may result in the suspension or termination of our operations and subject us to administrative, civil and criminal penalties. Moreover, public interest in environmental protection has increased in recent years—particularly with respect to hydraulic fracturing—and environmental organizations have opposed, with some success, certain drilling projects.
 
Matters subject to regulation include discharge permits, drilling bonds, reports concerning operations, the spacing of wells, unitization and pooling of properties, taxation or environmental matters and health and safety criteria addressing worker protection.  Under these laws and regulations, we may be required to make large expenditures that could materially adversely affect our business, financial condition and results of operations. These expenditures could include payments for:
 
    
personal injuries;
 
    
property damage;
 
    
containment and cleanup of oil and other spills;
 
    
the management and disposal of hazardous materials;
 
    
remediation and clean-up costs; and
 
    
other environmental damages.
 
We do not believe that full insurance coverage for all potential damages is available at a reasonable cost.  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, injunctive relief and/or the imposition of investigatory or other remedial obligations.  Laws, rules and regulations protecting the environment have changed frequently and the changes often include increasingly stringent requirements.  These laws, rules and regulations may impose liability on us for environmental damage and disposal of hazardous materials even if we were not negligent or at fault.  We may also be found to be liable for the conduct of others or for acts that complied with applicable laws, rules or regulations at the time we performed those acts.  These laws, rules and regulations are interpreted and enforced by numerous federal and state agencies.  In addition, private parties, including the owners of properties upon which our wells are drilled or the owners of properties adjacent to or in close proximity to those properties, may also pursue legal actions against us based on alleged non-compliance with certain of these laws, rules and regulations.
 
 
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Additionally, the natural gas and crude oil regulatory environment could change in ways that might substantially increase our financial and managerial costs to comply with the requirements of these laws and regulations and, consequently, adversely affect our profitability. At the state level, for instance, the Colorado Oil and Gas Conservation Commission (“COGCC”) issued a new rule governing mandatory minimum spacing, or setbacks, between oil and gas wells and occupied buildings and other areas. Similarly, it is expected that the COGCC may undertake a rulemaking focused on wellbore integrity in 2014 that would increase requirements in this area. The COGCC has also recently concluded a rulemaking that will require baseline sampling of certain ground and surface water in most areas of Colorado. These new sampling requirements could increase the costs of developing wells in certain locations. In addition to increasing costs of operation, these rules could prevent us from drilling wells on certain locations we plan to develop, thereby reducing our reserves as well as our future revenues. In addition, the Colorado Department of Public Health & Environment is expected to undertake a potentially expansive new rule regulating methane and other air emissions at oil and gas facilities in the State. This rulemaking is expected to begin and be finalized in 2014.
 
Some local governmental bodies, for instance Longmont, Colorado, have adopted or are considering regulations regarding, among other things, land use, requirements for the posting of bonds to secure restoration obligations and limitations on hydraulic fracturing and other drilling activities, and these regulations may limit, delay or prohibit exploration and development activities or make those activities more expensive. Additionally, state and local governments are undertaking air quality studies to assess potential public health impacts from oil and gas operations. These studies may result in the imposition of additional regulatory requirements on oil and gas operations.
 
The BP crude oil spill in the Gulf of Mexico and generally heightened industry scrutiny has resulted and may result in new state and federal safety and environmental laws, regulations, guidelines and enforcement interpretations. The EPA has recently focused on citizen concerns about the risk of water contamination and public health problems from drilling and hydraulic fracturing activities, and conducted public meetings around the country on this issue which have been well publicized and well attended. This renewed focus could lead to additional federal, state and local laws and regulations affecting our drilling, fracturing and other operations.
 
Other potential laws and regulations affecting us include new or increased severance taxes proposed in several states. This could adversely affect the existing operations in these states and the economic viability of future drilling. Additional laws, regulations or other changes could significantly reduce our future growth, increase our costs of operations and reduce our cash flows, in addition to undermining the demand for the natural gas and crude oil we produce.
 
Part of our strategy involves drilling in existing or emerging shale plays using some of the latest available horizontal drilling and completion techniques.  The results of our planned exploratory drilling in these plays are subject to drilling and completion technique risks, and drilling results may not meet our expectations for reserves or production.  As a result, we may incur material write-downs and the value of our undeveloped acreage could decline if drilling results are unsuccessful.
 
Our operations in the DJ Basin in Weld and Morgan Counties, Colorado, and anticipated operations in the Mississippian, involve utilizing the latest drilling and completion techniques in order to maximize cumulative recoveries and therefore generate the highest possible returns. Risks that we may face while drilling include, but are not limited to, landing our well bore in the desired drilling zone, staying in the desired drilling zone while drilling horizontally through the formation, running our casing the entire length of the well bore and being able to run tools and other equipment consistently through the horizontal well bore. Risks that we may face while completing our wells include, but are not limited to, being able to fracture stimulate the planned number of stages, being able to run tools the entire length of the well bore during completion operations and successfully cleaning out the well bore after completion of the final fracture stimulation stage.
 
The results of our drilling in new or emerging formations will be more uncertain initially than drilling results in areas that are more developed and have a longer history of established production. Newer or emerging formations and areas have limited or no production history and consequently we are less able to predict future drilling results in these areas.
 
Ultimately, the success of these drilling and completion techniques can only be evaluated over time as more wells are drilled and production profiles are established over a sufficiently long time period. If our drilling results are less than anticipated or we are unable to execute our drilling program because of capital constraints, lease expirations, access to gathering systems and limited takeaway capacity or otherwise, and/or natural gas and oil prices decline, the return on our investment in these areas may not be as attractive as we anticipate. Further, as a result of any of these developments we could incur material write-downs of our oil and natural gas properties and the value of our undeveloped acreage could decline in the future.
 
 
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Our acreage must be drilled before lease expiration, generally within three to five years, in order to hold the acreage by production. In the highly competitive market for acreage, failure to drill sufficient wells in order to hold acreage will result in a substantial lease renewal cost, or if renewal is not feasible, loss of our lease and prospective drilling opportunities.
 
Our leases on oil and natural gas properties typically have a primary term of three to five years, after which they expire unless, prior to expiration, production is established within the spacing units covering the undeveloped acres.  During the twelve month period ended December 31, 2013, 279 net acres did expire, in our Niobrara Asset. 181 net acres expire in 2014, 21 net acres expire in 2015, 169 net acres expire in 2016 and 588 net acres expire thereafter (net to our direct ownership interest only).   As of our March 7, 2014 acquisition of the Wattenberg Asset, 867 net acres were due to expire in 2014, 5,789 net acres expire in 2015, and 2,272 net acres expire thereafter in the Wattenberg Asset.  In addition, all of our net acres in the Mississippian asset will expire in 2014 if we do not drill at least three (3) long horizontal wells in the asset by December 29, 2014.  If our extension options expire and we have to renew such leases on new terms, we could incur significant cost increases, and we may not be able to renew such leases on commercially reasonable terms or at all, which could have a material adverse effect on our leased acreage. In addition, on certain portions of our acreage, third-party leases become immediately effective if our leases expire. As such, our actual drilling activities may materially differ from our current expectations, which could adversely affect our business.
 
Competition and regulation of hydraulic fracturing services and water disposal could impede our ability to develop our shale plays.
 
The unavailability or high cost of high pressure pumping services (or hydraulic fracturing services), chemicals, proppant, water and water disposal and related services and equipment could limit our ability to execute our exploration and development plans on a timely basis and within our budget.  The oil and natural gas industry is experiencing a growing emphasis on the exploitation and development of shale natural gas and shale oil resource plays, which are dependent on hydraulic fracturing for economically successful development.  Hydraulic fracturing in shale plays requires high pressure pumping service crews.  A shortage of service crews or proppant, chemical, water or water disposal options, especially if this shortage occurred in southern Texas, southern Kansas, northern Oklahoma or eastern Colorado, could materially and adversely affect our operations and the timeliness of executing our development plans within our budget.  There is significant regulatory uncertainty as some states have begun to regulate hydraulic fracturing and the U.S. Environmental Protection Agency, or the EPA, has released a progress report on its study of the impact of hydraulic fracturing on drinking water sources on December 21, 2012 describing 18 research projects underway.  The result of this study could affect the current regulatory jurisdiction of the states and increase the cycle times and costs to receive permits, delay or possibly preclude receipt of permits in certain areas, impact water usage and waste water disposal and require chemical additives disclosures.
 
We are subject to federal, state and local taxes, and may become subject to new taxes or have eliminated or reduced certain federal income tax deductions currently available with respect to oil and natural gas exploration and production activities as a result of future legislation, which could adversely affect our business, financial condition and results of operations.
 
The federal, state and local governments in the areas in which we operate impose taxes on the oil and natural gas products we sell and, for many of our wells, sales and use taxes on significant portions of our drilling and operating costs.  In the past, there has been a significant amount of discussion by legislators and presidential administrations concerning a variety of energy tax proposals.  Many states have raised state taxes on energy sources, and additional increases may occur.  Changes to tax laws that are applicable to us could adversely affect our business and our financial results.
 
Periodically, legislation is introduced to eliminate certain key U.S. federal income tax preferences currently available to oil and natural gas exploration and production companies. Such possible changes include, but are not limited to, (a) the repeal of the percentage depletion allowance for oil and natural gas properties, (b) the elimination of current deductions for intangible drilling and development costs, (c) the elimination of the deduction for certain United States production activities, and (d) the increase in the amortization period for geological and geophysical costs paid or incurred in connection with the exploration for, or development of, oil or natural gas within the United States.  It is unclear whether any such changes will actually be enacted or, if enacted, how soon any such changes could become effective. The passage of any legislation as a result of the budget proposals or any other similar change in U.S. federal income tax law could affect certain tax deductions that are currently available with respect to oil and natural gas exploration and production activities and could negatively impact our business, financial condition and results of operations.
 
The derivatives legislation adopted by Congress, and implementation of that legislation by federal agencies, could have an adverse impact on our ability to hedge risks associated with our business.
 
On July 21, 2010, President Obama signed into law the Dodd-Frank Wall Street Reform and Consumer Protection Act, the Dodd-Frank Act, which, among other things, sets forth the new framework for regulating certain derivative products including the commodity hedges of the type that we may elect to use, but many aspects of this law are subject to further rulemaking and will take effect over several years.  As a result, it is difficult to anticipate the overall impact of the Dodd-Frank Act on our ability or willingness to enter into and maintain such commodity hedges and the terms of such hedges.  There is a possibility that the Dodd-Frank Act could have a substantial and adverse impact on our ability to enter into and maintain these commodity hedges.  In particular, the Dodd-Frank Act could result in the implementation of position limits and additional regulatory requirements on derivative arrangements, which could include new margin, reporting and clearing requirements.  In addition, this legislation could have a substantial impact on our counterparties and may increase the cost of our derivative arrangements in the future.
 
 
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If these types of commodity hedges become unavailable or uneconomic, our commodity price risk could increase, which would increase the volatility of revenues and may decrease the amount of credit available to us.  Any limitations or changes in our use of derivative arrangements could also materially affect our future ability to conduct acquisitions.
 
Federal and state legislation and regulatory initiatives relating to hydraulic fracturing and water disposal could result in increased costs and additional operating restrictions or delays.
 
Congress has considered, but has not yet passed, legislation to amend the federal Safe Drinking Water Act to remove the exemption from restrictions on underground injection of fluids near drinking water sources granted to hydraulic fracturing operations and require reporting and disclosure of chemicals used by oil and natural gas companies in the hydraulic fracturing process.  Hydraulic fracturing involves the injection of water, sand or other propping agents and chemicals under pressure into rock formations to stimulate natural gas production.  We routinely use hydraulic fracturing to produce commercial quantities of oil, liquids and natural gas from shale formations.  Sponsors of bills, which have been subject to various proceedings in the legislative process, including the House Energy and Commerce Committee and the Senate Environmental and Public Works Committee, have asserted that chemicals used in the fracturing process could adversely affect drinking water supplies and otherwise cause adverse environmental impacts.  Such legislation, if adopted, could increase the possibility of litigation and establish an additional level of regulation at the federal level that could lead to operational delays or increased operating costs and could, and in all likelihood would, result in additional regulatory burdens, making it more difficult to perform hydraulic fracturing operations and increasing our costs of compliance.
 
In addition, certain members of Congress have called upon the U.S. Government Accountability Office to investigate how hydraulic fracturing might adversely affect water resources, the U.S. Securities and Exchange Commission to investigate the natural-gas industry and any possible misleading of investors or the public regarding the economic feasibility of pursuing natural-gas deposits in shales by means of hydraulic fracturing, and the U.S. Energy Information Administration to provide a better understanding of that agency’s estimates regarding natural-gas reserves, including reserves from shale formations, as well as uncertainties associated with those estimates. The U.S. Government Accountability Office released its report on hydraulic fracturing in September 2012. Depending on the outcome of these studies, federal and state legislatures and agencies may seek to further regulate hydraulic fracturing activities.
 
The EPA is also involved in regulating hydraulic fracturing.  On April 17, 2012, the EPA approved final rules under the Clean Air Act that would subject all oil and gas operations (production, processing, transmission, storage and distribution) to regulation under the New Source Performance Standards (NSPS) and National Emission Standards for Hazardous Air Pollutants (NESHAPS) programs. These rules also include NSPS standards for completions of hydraulically fractured gas wells. These standards include the reduced emission completion (REC) techniques developed in EPA’s Natural Gas STAR program along with pit flaring of gas not sent to the gathering line. The standards would be applicable to newly drilled and fractured wells as well as existing wells that are refractured. Further, the proposed regulations under NESHAPS include maximum achievable control technology (MACT) standards for those glycol dehydrators and storage vessels at major sources of hazardous air pollutants not currently subject to MACT standards. While these rules have been finalized, many of the rule’s provisions will be phased-in over time, with the more stringent requirements like REC not becoming effective until 2015.  The new rules are substantial and may increase future costs of our operations and are likely to require us to make modifications to our operations and install new equipment.
 
Moreover, the EPA is conducting a comprehensive research study on the potential adverse impacts that hydraulic fracturing may have on drinking water and groundwater.  In addition, in December 2011, the EPA published an unrelated draft report concluding that hydraulic fracturing caused groundwater pollution of a natural gas field in Wyoming, although this study remains subject to review and public comments.  Consequently, even if federal legislation is not adopted soon or at all, the performance of the hydraulic fracturing study by the EPA could spur further action at a later date towards federal legislation and regulation of hydraulic fracturing or similar production operations.
 
In addition, a number of states are considering or have implemented more stringent regulatory requirements applicable to fracturing, which could include, among other requirements, stringent permitting on air emission control requirements, disclosure, wastewater disposal, baseline sampling, well construction and well location requirements on hydraulic fracturing operations or otherwise seek to ban injection of fracturing wastewater, and effectively prohibit further production of natural gas through the use of hydraulic fracturing or similar operations.  For example, Texas has adopted legislation that requires the disclosure of information regarding the substances used in the hydraulic fracturing process to the Railroad Commission of Texas and the public.  Some municipalities and local governments, including most recently the city of Fort Collins, Colorado, have adopted or are considering similar actions.  This legislation and any implementing regulation could increase our costs of compliance and doing business.
 
 
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The adoption of new laws or regulations imposing reporting obligations on, or otherwise limiting, the hydraulic fracturing and related water disposal processes could make it more difficult to complete oil and natural gas wells in shale formations.  In addition, if hydraulic fracturing becomes regulated at the federal level as a result of federal legislation or regulatory initiatives by the EPA, fracturing activities could become subject to additional permitting requirements, and also to attendant permitting delays and potential increases in cost, which could adversely affect our business, financial condition and results of operations.
 
Legislation or regulations restricting emissions of “greenhouse gases” could result in increased operating costs and reduced demand for the natural gas, natural gas liquids and oil we produce while the physical effects of climate change could disrupt our production and cause us to incur significant costs in preparing for or responding to those effects.
 
On December 15, 2009, the EPA published its final findings that emissions of carbon dioxide, methane and other “greenhouse gases” present an endangerment to public health and welfare because emissions of such gases are, according to the EPA, contributing to the warming of the earth’s atmosphere and other climatic changes.  These findings allow the EPA to adopt and implement regulations that would restrict emissions of greenhouse gases under existing provisions of the federal Clean Air Act.  Accordingly, the EPA has adopted regulations that would require a reduction in emissions of greenhouse gases from motor vehicles and permitting and presumably requiring a reduction in greenhouse gas emissions from certain stationary sources.  In addition, on October 30, 2009, the EPA published a final rule requiring the reporting of greenhouse gas emissions from specified large greenhouse gas emission sources in the United States beginning in 2011 for emissions occurring in 2010.  On November 30, 2010, the EPA released a final rule that expands its rule on reporting of greenhouse gas emissions to include owners and operators of petroleum and natural gas systems.  The adoption and implementation of any regulations imposing reporting obligations on, or limiting emissions of greenhouse gases from, our equipment and operations could require us to incur costs to reduce emissions of greenhouse gases associated with our operations.  Further, various states have adopted legislation that seeks to control or reduce emissions of greenhouse gases from a wide range of sources.  Any such legislation could adversely affect demand for the natural gas, oil and liquids that we produce.
 
Some scientists have concluded that increasing concentrations of greenhouse gases in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods and other climatic events.  If any such effects were to occur, they could have an adverse effect on our exploration and production operations.  Significant physical effects of climate change could also have an indirect effect on our financing and operations by disrupting the transportation or process-related services provided by midstream companies, service companies or suppliers with whom we have a business relationship.  We may not be able to recover through insurance some or any of the damages, losses, or costs that may result from potential physical effects of climate change.
 
Our operations are substantially dependent on the availability of water.  Restrictions on our ability to obtain water may have an adverse effect on our financial condition, results of operations and cash flows.
 
Water is an essential component of deep shale oil and natural gas production during both the drilling and hydraulic fracturing, or fracking processes. Our operations could be adversely impacted if we are unable to locate sufficient amounts of water, or dispose of or recycle water used in our exploration and production operations. Currently, the quantity of water required in certain completion operations, such as hydraulic fracturing, and changing regulations governing usage may lead to water constraints and supply concerns (particularly in some parts of the country). According to the Lower Colorado River Authority, during 2011, Texas experienced the lowest inflows of water of any year in recorded history.  In addition, Colorado and other western states have recently experienced a drought. As a result, future availability of water from certain sources used in the past may be limited. Moreover, the imposition of new environmental initiatives and conditions could include restrictions on our ability to conduct certain operations such as hydraulic fracturing or disposal of waste, including, but not limited to, produced water, drilling fluids and other wastes associated with the exploration, development or production of oil and natural gas. The federal Clean Water Act, or CWA and analogous state laws impose restrictions and strict controls regarding the discharge of pollutants, including produced waters and other oil and natural gas waste, into navigable waters or other regulated federal and state waters. Permits or other approvals must be obtained to discharge pollutants to regulated waters and to conduct construction activities in such waters and wetlands. Uncertainty regarding regulatory jurisdiction over wetlands and other regulated waters has, and will continue to, complicate and increase the cost of obtaining such permits or other approvals. The CWA and analogous state laws provide for civil, criminal and administrative penalties for any unauthorized discharges of pollutants and unauthorized discharges of reportable quantities of oil and other hazardous substances. Many state discharge regulations, and the Federal National Pollutant Discharge Elimination System General permits issued by the EPA, prohibit the discharge of produced water and sand, drilling fluids, drill cuttings and certain other substances related to the oil and natural gas industry into coastal waters. While generally exempt under federal programs, many state agencies have also adopted regulations requiring certain oil and natural gas exploration and production facilities to obtain permits for storm water discharges. In October 2011, the EPA announced its intention to develop federal pretreatment standards for wastewater discharges associated with hydraulic fracturing activities. If adopted, the pretreatment rules will require coalbed methane and shale gas operations to pretreat wastewater before transferring it to treatment facilities Some states have banned the treatment of fracturing wastewater at publicly owned treatment facilities. There has been recent nationwide concern over earthquakes associated with Class II underground injection control wells, a predominant storage method for crude oil and gas wastewater. It is likely that new rules and regulations will be developed to address these concerns, possibly eliminating access to Class II wells in certain locations, and increasing the cost of disposal in others. Finally, the EPA study noted above has focused and will continue to focus on various stages of water use in hydraulic fracturing operations. It is possible that, following the conclusion of the EPA’s study, the agency will move to more strictly regulate the use of water in hydraulic fracturing operations. While we cannot predict the impact that these changes may have on our business at this time, they may be material to our business, financial condition, and operations. Compliance with environmental regulations and permit requirements governing the withdrawal, storage and use of surface water or groundwater necessary for hydraulic fracturing of wells or the disposal or recycling of water will increase our operating costs and may cause delays, interruptions or termination of our operations, the extent of which cannot be predicted. In addition, our inability to meet our water supply needs to conduct our completion operations may impact our business, and any such future laws and regulations could negatively affect our financial condition, results of operations and cash flows.
 
 
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Restrictions on drilling activities intended to protect certain species of wildlife may adversely affect our ability to conduct drilling activities in some of the areas where we operate.
 
Oil and natural gas operations in our operating areas can be adversely affected by seasonal or permanent restrictions on drilling activities designed to protect various wildlife. Seasonal restrictions may limit our ability to operate in protected areas and can intensify competition for drilling rigs, oilfield equipment, services, supplies and qualified personnel, which may lead to periodic shortages when drilling is allowed. These constraints and the resulting shortages or high costs could delay our operations and materially increase our operating and capital costs.  Permanent restrictions imposed to protect endangered species could prohibit drilling in certain areas or require the implementation of expensive mitigation measures.
 
As a result of a settlement approved by the U.S. District Court for the District of Columbia on September 9, 2011, the U.S. Fish and Wildlife Service is required to consider listing more than 250 species as endangered under the Endangered Species Act.  The law prohibits the harming of endangered or threatened species, provides for habitat protection, and imposes stringent penalties for noncompliance.  The final designation of previously unprotected species in areas where we operate as threatened or endangered could cause us to incur increased costs arising from species protection measures or could result in limitations, delays, or prohibitions on our exploration and production activities that could have an adverse impact on our ability to develop and produce our reserves.
 
Potential conflicts of interest could arise for certain members of our management team that hold management positions with other entities.
 
Frank C. Ingriselli, our Chairman of the Board and Chief Executive Officer, is also president and Chief Executive Officer of Global Venture Investments LLC and Michael L. Peterson, our Chief Financial Officer, is a managing partner of Pascal Management.  We believe these positions require only an immaterial amount of Messrs. Ingriselli’s and Peterson’s time and will not conflict with each of their respective roles or responsibilities with our company.  If either of these entities enters into one or more transactions with our company, or if either of these positions require significantly more time than currently anticipated,  potential conflicts of interests could arise from Messrs. Ingriselli and Peterson performing services for us and these other entities.
 
Our planned acquisition of assets in Kazakhstan may not be completed, or if completed, could force us to pay certain additional consideration to the seller, either of which could adversely affect our business and results of operations.
 
We have entered into an agreement to acquire an approximate 51% ownership in Asia Sixth Energy Resources Limited, a British Virgin Islands entity (“Asia Sixth”), which holds an approximate 60% ownership interest in Aral Petroleum Capital Limited Partnership, a Kazakhstan entity (“Aral”), and we have entered into a subsequent agreement to transfer 50% of the interest we will acquire in Asia Sixth to RJ Resources, thereby netting us a 25.5% ownership in Asia Sixth following the closing of these transactions.  Aral holds a production license covering a 380,000 acre oil and gas producing asset located in the Pre-Caspian Basin in Kazakhstan, which we plan to close upon receipt of required approvals from the government of Kazakhstan, anticipated to be received no later than the third quarter of 2014.  
 
 
 
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We have paid an initial deposit of $10 million to Asia Sixth, and were required to increase our deposit by up to $10 million to a total of $20 million contingent upon receipt of payment in full of $10 million by us from an investor under a promissory note maturing in December 2013. The investor failed to pay the $10 million balance due under the Note by December 1, 2013. On December 1, 2013, the Company granted a verbal extension to the investor pending further discussions regarding the investment.  Following discussions with the investor, the investor elected to forego making further investment. Accordingly, on March 7, 2014, the Company notified the investor that, effective immediately, the Escrowed Shares and Escrowed Warrants were rescinded as permitted pursuant to the terms of the Note, and the Note was cancelled and forgiven, with no further action required by the investor (the “Cancellation”).  The stock subscription receivable related to 3,333,333 shares of common stock and 999,999 warrants for shares of common stock in the amount of $10 million was extinguished as of March 7, 2014. The rescission of the note has no net effect on us or our obligations because (a) if such note was paid in full we would have been required to pay such funds directly to Asia Sixth; and (b) the result of such funds not being paid only results in a decrease in the required deposit due to Asia Sixth.
 
The $10 million deposit is subject to full refund to us in the event the transaction does not close, other than as a result of our material uncured breach, provided, however, that if any part of the $10 million deposit previously paid by us is returned to us, 50% of any such returned funds must be paid to RJ Resources.  These funds will also be used, in part, to recomplete and rework currently producing wells with the goal of significantly increasing their production rates. Based on how these wells perform, at closing, we shall owe to Asia Sixth a final closing payment equal to an additional:  (i) $20 million if the daily average volume of oil produced by Aral over a specified 30 day period (the “Target Volume”) equals or exceeds 1,500 barrels of oil per day (“BOPD”); (ii) $15 million if the Target Volume equals or exceeds 1,000 BOPD but is less than 1,500 BOPD; or (iii) $0 due if the Target Volume comes in less than 1,000 BOPD.  In the event we are required to pay any final closing payment to Asia Sixth, RJ Resources is obligated to pay 50% of any such amount due.
 
The closing of the transaction is scheduled to occur no earlier than September 15, 2014, subject to certain conditions precedent, including the approval of the Agency of the Republic of Kazakhstan for the Protection of Competition and the Ministry of Oil and Gas of the Republic of Kazakhstan, or the MOG, and the MOG’s waiver of its pre-emptive purchase right with respect to the transaction.  In the event the MOG does not approve the transaction or waive its pre-emptive purchase right, the transaction will be terminated, our anticipated business and results of operations could be adversely affected and there is no guarantee that we could subsequently acquire an equally attractive oil play. Additionally, in the event the transaction closes and we are required to make a final closing payment to Asia Sixth based on well performance, we will need to raise the funds required through debt and/or equity financings, which funds may not be available on favorable terms, if at all.
 
We face risks associated with our planned operations in Kazakhstan.
 
In the event we complete the pending acquisition of our Kazakhstan assets we will be subject to various risks associated with doing business in Kazakhstan and relating to Kazakhstan’s economic and political environment. As is typical of an emerging market, Kazakhstan does not possess a well-developed business, legal and regulatory infrastructure that would generally exist in a more mature free market economy and, in recent years, Kazakhstan has undergone substantial political, economic and social change.   We could also face currency risks associated with operations in Kazakhstan. Additionally, our successful operation of particular facilities or projects may be disrupted by civil unrest, acts of sabotage or terrorism, and other local security concerns. Such concerns may require us to incur greater costs for security or to shut down operations for a period of time. Our planned operations in Kazakhstan will also be subject to Kazakhstan specific laws and regulations relating to areas of labor, tax, import and export requirements, anti-corruption, foreign exchange controls and cash repatriation restrictions, environmental, health, and safety, which will be different than U.S. laws and may force us to expend additional resources complying with such laws and regulations. Our failure to manage the risks associated with doing business in Kazakhstan could have a material adverse effect upon our results of operations.
 
Our technology services company has no operating history and there is a risk that such company will not be successful or face liabilities.
 
On October 4, 2012, we established a technical services subsidiary, Pacific Energy Technology Services, LLC, which is 70% owned by us and 30% owned by STXRA, through which we plan to provide acquisition, engineering, and oil drilling and completion technology services in joint cooperation with STXRA in the United States and Pacific Rim countries, particularly in China.  While Pacific Energy Technology Services, LLC currently has no operations, only nominal assets and liabilities and limited capitalization, we anticipate actively developing this venture in 2014.  Due to the fact that this entity does not have an operating history and the fact that we have not previously provided technology services as part of its operations, there is a risk that we will not be successful in marketing this venture, that revenues will not develop and that Pacific Energy Technology Services, LLC will not be successful.  We may be subject to liability claims from clients of our planned services. Our product liability insurance and contractual limitations may not cover all potential claims. Our failure to provide services at a level requested by clients could cause us to lose revenue, as well as to experience delay in or loss of market acceptance and sales, or injury to our reputation.
 
 
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Risks Related to Our Common Stock
 
We currently have an illiquid and volatile market for our common stock, and the market for our common stock is and may remain illiquid and volatile in the future.
 
We currently have a highly sporadic, illiquid and volatile market for our common stock, which market is anticipated to remain sporadic, illiquid and volatile in the future. Factors that could affect our stock price or result in fluctuations in the market price or trading volume of our common stock include:
 
our actual or anticipated operating and financial performance and drilling locations, including reserves estimates;
 
quarterly variations in the rate of growth of our financial indicators, such as net income per share, net income and cash flows, or those of companies that are perceived to be similar to us;
 
changes in revenue, cash flows or earnings estimates or publication of reports by equity research analysts;
 
speculation in the press or investment community;
 
public reaction to our press releases, announcements and filings with the SEC;
 
sales of our common stock by us or other shareholders, or the perception that such sales may occur;
 
the limited amount of our freely tradable common stock available in the public marketplace;
 
general financial market conditions and oil and natural gas industry market conditions, including fluctuations in commodity prices;
 
the realization of any of the risk factors presented in this Annual Report;
 
the recruitment or departure of key personnel;
 
commencement of, or involvement in, litigation;
 
the prices of oil and natural gas;
 
the success of our exploration and development operations, and the marketing of any oil and natural gas we produce;
 
changes in market valuations of companies similar to ours; and
 
domestic and international economic, legal and regulatory factors unrelated to our performance.
 
Our common stock is listed on the NYSE MKT under the symbol “PED.”  Our stock price may be impacted by factors that are unrelated or disproportionate to our operating performance. The stock markets in general have experienced extreme volatility that has often been unrelated to the operating performance of particular companies. These broad market fluctuations may adversely affect the trading price of our common stock.  Additionally, general economic, political and market conditions, such as recessions, interest rates or international currency fluctuations may adversely affect the market price of our common stock. Due to the limited volume of our shares which trade, we believe that our stock prices (bid, ask and closing prices) may not be related to our actual value, and not reflect the actual value of our common stock. Shareholders and potential investors in our common stock should exercise caution before making an investment in us.
 
Additionally, as a result of the illiquidity of our common stock, investors may not be interested in owning our common stock because of the inability to acquire or sell a substantial block of our common stock at one time.  Such illiquidity could have an adverse effect on the market price of our common stock.  In addition, a shareholder may not be able to borrow funds using our common stock as collateral because lenders may be unwilling to accept the pledge of securities having such a limited market.  We cannot assure you that an active trading market for our common stock will develop or, if one develops, be sustained.
 
 
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An active liquid trading market for our common stock may not develop in the future.
 
Our common stock currently trades on the NYSE MKT, although our common stock’s trading volume is very low.   Liquid and active trading markets usually result in less price volatility and more efficiency in carrying out investors’ purchase and sale orders. However, our common stock may continue to have limited trading volume, and many investors may not be interested in owning our common stock because of the inability to acquire or sell a substantial block of our common stock at one time.  Such illiquidity could have an adverse effect on the market price of our common stock.  In addition, a shareholder may not be able to borrow funds using our common stock as collateral because lenders may be unwilling to accept the pledge of securities having such a limited market.  We cannot assure you that an active trading market for our common stock will develop or, if one develops, be sustained.
 
We do not presently intend to pay any cash dividends on or repurchase any shares of our common stock.
 
We do not presently intend to pay any cash dividends on our common stock or to repurchase any shares of our common stock.  Any payment of future dividends will be at the discretion of the Board of Directors and will depend on, among other things, our earnings, financial condition, capital requirements, level of indebtedness, statutory and contractual restrictions applying to the payment of dividends and other considerations that our Board of Directors deems relevant.  Cash dividend payments in the future may only be made out of legally available funds and, if we experience substantial losses, such funds may not be available.  Accordingly, you may have to sell some or all of your common stock in order to generate cash flow from your investment, and there is no guarantee that the price of our common stock that will prevail in the market will ever exceed the price paid by you.
 
The issuance of common stock upon conversion of our convertible notes will cause immediate and substantial dilution.
 
The issuance of common stock upon conversion of our outstanding convertible notes in the aggregate amount of $2,125,000 in principal and $212,500 of payment in kind, along with interest on the principal amount of such notes, which allow the holders thereof the right to convert such amounts from time to time, subject to certain limitations,  into common stock of the Company, as is determined by dividing the amount converted by a conversion price as follows (A) prior to June 1, 2014, the conversion price is $2.15 per share; and (B) following June 1, 2014, the denominator used in the calculation described above shall be the greater of (i) 80% of the average of the closing price per share of our publicly traded common stock for the five (5) trading days immediately preceding the date of the conversion notice provide by the holder; and (ii) $0.50 per share, will result in immediate and substantial dilution to the interests of other stockholders.
 
The continuously adjustable conversion price feature of our convertible notes could require us to issue a substantially greater number of shares, which may adversely affect the market price of our common stock and cause dilution to our existing stockholders.
 
Our existing stockholders may experience substantial dilution of their investment upon conversion of the convertible notes. The convertible notes are convertible into shares of common stock as described in the risk factor above entitled “The issuance of common stock upon conversion of our convertible notes will cause immediate and substantial dilution”, after June 1, 2014, at a discount to the trading price of our common stock, subject to a floor of $0.50 per share.  As a result, the number of shares issuable could prove to be significantly greater in the event of a decrease in the trading price of our common stock, which decrease could cause substantial dilution to our existing stockholders. As sequential conversions and sales take place, the price of our common stock may decline, and if so, the holders of the convertible notes would be entitled to receive an increasing number of shares, which could then be sold, triggering further price declines and conversions for even larger numbers of shares, which would cause additional dilution to our existing stockholders and could cause the value of our common stock to decline.
 
 
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Because we are a small company, the requirements of being a public company, including compliance with the reporting requirements of the Securities Exchange Act of 1934, as amended (the “Exchange Act”) and the requirements of the Sarbanes-Oxley Act and the Dodd-Frank Act, may strain our resources, increase our costs and distract management, and we may be unable to comply with these requirements in a timely or cost-effective manner.
 
As a public company with listed equity securities, we must comply with the federal securities laws, rules and regulations, including certain corporate governance provisions of the Sarbanes-Oxley Act of 2002 (the “Sarbanes-Oxley Act”) and the Dodd-Frank Act, related rules and regulations of the SEC and the NYSE MKT, with which a private company is not required to comply. Complying with these laws, rules and regulations will occupy a significant amount of time of our Board of Directors and management and will significantly increase our costs and expenses, which we cannot estimate accurately at this time.  Among other things, we must:
 
establish and maintain a system of internal control over financial reporting in compliance with the requirements of Section 404 of the Sarbanes-Oxley Act and the related rules and regulations of the SEC and the Public Company Accounting Oversight Board;
 
comply with rules and regulations promulgated by the NYSE MKT;
 
prepare and distribute periodic public reports in compliance with our obligations under the federal securities laws;
 
maintain various internal compliance and disclosures policies, such as those relating to disclosure controls and procedures and insider trading in our common stock;
 
involve and retain to a greater degree outside counsel and accountants in the above activities;
 
maintain a comprehensive internal audit function; and
 
maintain an investor relations function.
 
In addition, being a public company subject to these rules and regulations may require us to accept less director and officer liability insurance coverage than we desire or to incur substantial costs to obtain coverage.  These factors could also make it more difficult for us to attract and retain qualified members of our Board of Directors, particularly to serve on our audit committee, and qualified executive officers.
 
Future sales of our common stock could cause our stock price to decline.
 
If our shareholders sell substantial amounts of our common stock in the public market, the market price of our common stock could decrease significantly. The perception in the public market that our shareholders might sell shares of our common stock could also depress the market price of our common stock.  Up to $100,000,000 in total aggregate value of securities have been registered by us on a “shelf” registration statement on Form S-3 (File No. 333-191869) that we filed with the Securities and Exchange Commission on October 23, 2013, and which was declared effective on November 5, 2013.  To date, an aggregate of $14,705,275 in securities have been sold by us under the Form S-3, leaving $85,294,725 in securities which will be eligible for sale in the public markets from time to time, when sold and issued by us, subject to the requirements of Form S-3, which limits us, until such time, if ever, as our public float exceeds $75 million, from selling securities in a public primary offering under Form S-3 with a value exceeding more than one-third of the aggregate market value of the common stock held by non-affiliates of the Company every twelve months.  Additionally, if our existing shareholders sell, or indicate an intent to sell, substantial amounts of our common stock in the public market, the trading price of our common stock could decline significantly.  The market price for shares of our common stock may drop significantly when such securities are sold in the public markets. A decline in the price of shares of our common stock might impede our ability to raise capital through the issuance of additional shares of our common stock or other equity securities.
 
Our outstanding options, warrants and convertible securities may adversely affect the trading price of our common stock.
 
As of December 31, 2013, there were outstanding stock options to purchase approximately 1,438,062 shares of our common stock and outstanding warrants to purchase approximately 3,020,046 shares of common stock.  For the life of the options and warrants, the holders have the opportunity to profit from a rise in the market price of our common stock without assuming the risk of ownership.   The issuance of shares upon the exercise of outstanding securities will also dilute the ownership interests of our existing stockholders.
 
The availability of these shares for public resale, as well as any actual resales of these shares, could adversely affect the trading price of our common stock. We previously filed a registration statement with the SEC on Form S-8 providing for the registration of approximately 2,118,386 shares of our common stock issuable or reserved for issuance under our equity incentive plans. Subject to the satisfaction of vesting conditions, the expiration of lockup agreements, any management 10b5-1 plans and certain restrictions on sales by affiliates, shares registered under registration statements on Form S-8 will be available for resale immediately in the public market without restriction.
 
 
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We cannot predict the size of future issuances of our common stock pursuant to the exercise of outstanding options or warrants or conversion of other securities, or the effect, if any, that future issuances and sales of shares of our common stock may have on the market price of our common stock. Sales or distributions of substantial amounts of our common stock (including shares issued in connection with an acquisition), or the perception that such sales could occur, may cause the market price of our common stock to decline.
 
Six of our directors and executive officers own approximately 13.9% of our common stock, and two of our major shareholders own approximately 21.5% of our common stock, which may give them influence over important corporate matters in which their interests are different from your interests.
 
Six of our directors and executive officers beneficially own approximately 13.9% of our outstanding shares of common stock, and our largest two non-director or officer shareholders own approximately 21.5% of our outstanding shares of common stock (assuming exercise of warrants held thereby) based on a total of 26,539,013 shares of common stock outstanding as of March 28, 2014. These directors, executive officers and major shareholders will be positioned to influence or control to some degree the outcome of matters requiring a shareholder vote, including the election of directors, the adoption of amendments to our certificate of formation or bylaws and the approval of mergers and other significant corporate transactions.  These directors, executive officers and major shareholders, subject to any fiduciary duties owed to the shareholders generally, may have interests different than the rest of our shareholders.  Their influence or control of our company may have the effect of delaying or preventing a change of control of our company and may adversely affect the voting and other rights of other shareholders.  In addition, due to the ownership interest of these directors and officers in our common stock, they may be able to remain entrenched in their positions.
 
Furthermore, one of our major shareholders, MIE Holdings, is an independent oil company in China with its own oil and natural gas operations separate from its relationship with us.  Potential conflicts of interest could arise as a result, either in the terms of our relationship with MIE Holdings or in MIE Holdings competing with us in its operations outside of its relationship with us.
 
Provisions of Texas law may have anti-takeover effects that could prevent a change in control even if it might be beneficial to our shareholders.
 
Provisions of Texas law may discourage, delay or prevent someone from acquiring or merging with us, which may cause the market price of our common stock to decline.  Under Texas law, a shareholder who beneficially owns more than 20% of our voting stock, or any “affiliated shareholder,” cannot acquire us for a period of three years from the date this person became an affiliated shareholder, unless various conditions are met, such as approval of the transaction by our Board of Directors before this person became an affiliated shareholder or approval of the holders of at least two-thirds of our outstanding voting shares not beneficially owned by the affiliated shareholder.  
 
Our Board of Directors can authorize the issuance of preferred stock, which could diminish the rights of holders of our common stock and make a change of control of our company more difficult even if it might benefit our shareholders.
 
Our Board of Directors is authorized to issue shares of preferred stock in one or more series and to fix the voting powers, preferences and other rights and limitations of the preferred stock.   Shares of preferred stock may be issued by our Board of Directors without shareholder approval, with voting powers and such preferences and relative, participating, optional or other special rights and powers as determined by our Board of Directors, which may be greater than the shares of common stock currently outstanding.  As a result, shares of preferred stock may be issued by our Board of Directors which cause the holders to have majority voting power over our shares, provide the holders of the preferred stock the right to convert the shares of preferred stock they hold into shares of our common stock, which may cause substantial dilution to our then common stock shareholders and/or have other rights and preferences greater than those of our common stock shareholders including having a preference over our common stock with respect to dividends or distributions on liquidation or dissolution.
 
Investors should keep in mind that the Board of Directors has the authority to issue additional shares of common stock and preferred stock, which could cause substantial dilution to our existing shareholders.  Additionally, the dilutive effect of any preferred stock which we may issue may be exacerbated given the fact that such preferred stock may have voting rights and/or other rights or preferences which could provide the preferred shareholders with substantial voting control over us subsequent to the date of this filing and/or give those holders the power to prevent or cause a change in control, even if that change in control might benefit our shareholders.  As a result, the issuance of shares of common stock and/or preferred stock may cause the value of our securities to decrease.
 
 
57

 
 
Securities analysts may not cover, or continue to cover, our common stock and this may have a negative impact on our common stock’s market price.
 
The trading market for our common stock will depend, in part, on the research and reports that securities or industry analysts publish about us or our business. We do not have any control over independent analysts (provided that we have engaged various non-independent analysts). We currently only have a few independent analysts that cover our common stock, and these analysts may discontinue coverage of our common stock at any time.  Further, we may not be able to obtain additional research coverage by independent securities and industry analysts. If no independent securities or industry analysts continue coverage of us, the trading price for our common stock could be negatively impacted. If one or more of the analysts who covers us downgrades our common stock, changes their opinion of our shares or publishes inaccurate or unfavorable research about our business, our stock price could decline. If one or more of these analysts ceases coverage of us or fails to publish reports on us regularly, demand for our common stock could decrease and we could lose visibility in the financial markets, which could cause our stock price and trading volume to decline.
 
Shareholders may be diluted significantly through our efforts to obtain financing and satisfy obligations through the issuance of securities.
 
Wherever possible, our Board of Directors will attempt to use non-cash consideration to satisfy obligations.  In many instances, we believe that the non-cash consideration will consist of shares of our common stock, preferred stock or warrants to purchase shares of our common stock. Our Board of Directors has authority, without action or vote of the shareholders, subject to the requirements of the NYSE MKT (which generally require shareholder approval for any transactions which would result in the issuance of more than 20% of our then outstanding shares of common stock or voting rights representing over 20% of our then outstanding shares of stock), to issue all or part of the authorized but unissued shares of common stock, preferred stock or warrants to purchase such shares of common stock. In addition, we may attempt to raise capital by selling shares of our common stock, possibly at a discount to market in the future. These actions will result in dilution of the ownership interests of existing shareholders and may further dilute common stock book value, and that dilution may be material. Such issuances may also serve to enhance existing management’s ability to maintain control of us, because the shares may be issued to parties or entities committed to supporting existing management.
 
If we are delisted from the NYSE MKT, your ability to sell your shares of our common stock may be limited by the penny stock restrictions, which could further limit the marketability of your shares.
 
If our common stock is delisted, it could come within the definition of “penny stock” as defined in the Exchange Act and could be covered by Rule 15g-9 of the Exchange Act. That Rule imposes additional sales practice requirements on broker-dealers who sell securities to persons other than established customers and accredited investors. For transactions covered by Rule 15g-9, the broker-dealer must make a special suitability determination for the purchaser and receive the purchaser’s written agreement to the transaction prior to the sale. Consequently, Rule 15g-9, if it were to become applicable, would affect the ability or willingness of broker-dealers to sell our securities, and accordingly would affect the ability of stockholders to sell their securities in the public market. These additional procedures could also limit our ability to raise additional capital in the future.
 
Due to the fact that our common stock is listed on the NYSE MKT, we are subject to financial and other reporting and corporate governance requirements which increase our costs and expenses.
 
We are currently required to file annual and quarterly information and other reports with the Securities and Exchange Commission that are specified in Sections 13 and 15(d) of the Securities Exchange Act of 1934, as amended.  Additionally, due to the fact that our common stock is listed on the NYSE MKT, we are also subject to the requirements to maintain independent directors, comply with other corporate governance requirements and are required to pay annual listing and stock issuance fees. These obligations require a commitment of additional resources including, but not limited, to additional expenses, and may result in the diversion of our senior management’s time and attention from our day-to-day operations. These obligations increase our expenses and may make it more complicated or time consuming for us to undertake certain corporate actions due to the fact that we may require NYSE approval for such transactions and/or NYSE rules may require us to obtain shareholder approval for such transactions.
 
 
58

 
ITEM 1B. UNRESOLVED STAFF COMMENTS.
 
None.
 
ITEM 2. PROPERTIES.
 
Oil and Gas Properties
 
All oil and gas properties are currently in the United States.
 
Productive Wells
 
The following table presents our total gross and net productive wells by core operating area and by oil or natural gas completion as of December 31, 2013, including wells acquired in our Wattenberg Asset, which we acquired on March 7, 2014, with an effective date of December 1, 2013, and excluding wells on our Eagle Ford Asset, which we divested on February 19, 2014, effective November 1, 2013:
 
   
Gross Productive Wells
   
Net Productive Wells
       
   
Oil
   
Natural Gas
   
Total
   
Oil
   
Natural Gas
   
Total
   
% Operated
 
December 31, 2013
                                         
Wattenberg Asset (1)
   
25.0
     
-
     
25.0
     
12.38
     
-
     
12.38
     
42
%
Niobrara (2)
   
5.0
     
-
     
5.0
     
1.26
     
-
     
1.26
     
100
%
Eagle Ford (3)
   
5.0
     
-
     
5.0
     
0.20
     
-
     
0.20
     
0
%
Sugar Valley
   
1.0
     
-
     
1.0
     
0.50
     
-
     
0.50
     
0
%
Total
   
36.0
     
-
     
36.0
     
14.34
     
-
     
14.34
         
 
(1)
11 wells are operated by Red Hawk, our 100% owned subsidiary.
(2)
Operated by Condor, which our company jointly owns and manages with MIE Holdings.
(3)
We divested our Eagle Ford asset in full on February 19, 2014, effective November 1, 2013.
 
“Gross wells” represents the number of wells in which a working interest is owned, and “net wells” represents the total of our fractional working interests owned in gross wells.

Acreage
 
The following table sets forth certain information regarding the developed and undeveloped acreage in which we own a working interest as of December 31, 2013 for each of our core operating areas, and includes our Wattenberg Asset which was acquired March 7, 2014, with an effective date of December 1, 2013.  Acreage related to royalty, overriding royalty and other similar interests is excluded from this summary.
 
   
Undeveloped Acres
   
Developed Acres
   
Total
   
% of
Acreage
Held-by-
 
As of December 31, 2013
 
Gross
   
Net
   
Gross
   
Net
   
Gross
   
Net
   
Production
 
Current Assets:
                                         
Wattenberg (1)
   
18,365
     
9,182
     
9,549
     
4,775
     
27,914
     
13,957
     
34.2
%
Niobrara
   
5,905
     
1,529
     
3,162
     
855
     
9,067
     
2,384
     
34.9
%
Mississippian
   
7,006
     
3,443
     
-
     
-
     
7,006
     
3,443
     
-
%
Eagle Ford (2)
   
1,133
     
45
     
198
     
8
     
1,331
     
53
     
52.7
%
Sugar Valley
   
-
     
-
     
251
     
164
     
251
     
164
     
100
%
Total
   
32,409
     
14,199
     
13,160
     
5,802
     
45,569
     
20,001
         
 
(1)
We purchased the Wattenberg asset March 7, 2014 effective December 1, 2013.
(2)
We divested our Eagle Ford asset in full on February 19, 2014, effective November 1, 2013.
 
 
59

 

 Undeveloped Acreage Expirations
 
The following table sets forth the number of gross and net undeveloped acres on our Niobrara, Eagle Ford, Mississippian and North Sugar Valley assets as of December 31, 2013, and with respect to our newly acquired Wattenberg Asset, as of its acquisition date of March 7, 2014, that will expire over the next three years unless production is established within the spacing units covering the acreage prior to the expiration dates: 
 
   
As of December 31, 2013
 
   
2014
   
2015
   
2016
   
Thereafter
 
Assets
 
Gross
   
Net
   
Gross
   
Net
   
Gross
   
Net
   
Gross
   
Net
 
                                                 
Niobrara (1)
   
679
     
181
     
93
     
21
     
486
     
169
     
811
     
588
 
Eagle Ford (2)
   
-
     
-
     
-
     
-
     
-
     
-
     
-
     
-
 
North Sugar Valley (3)
   
-
     
-
     
-
     
-
     
-
     
-
     
-
     
-
 
Wattenberg (4)
   
1,734
     
867
     
11,578
     
5,789
     
4,544
     
2,272
     
450
     
225
 
Total
   
2,413
     
1,048
     
11,671
     
5,810
     
5,030
     
2,441
     
1,261
     
813
 
 
(1)
We plan to continue to hold, and not allow to expire, significantly all of this acreage through an active program of completing producing wells thereon to hold such acreage by production, and seeking to extend leases where drilling is not planned prior to expiration.  All “net” acreage reflects our acreage held directly and our 20% proportionate share of acreage held by Condor by virtue of our 20% ownership interest in Condor.
 
(2)
We divested our Eagle Ford asset in full on February 19, 2014 effective November 1, 2013
 
(3)
All of our North Sugar Valley acreage is currently held by production.
 
(4)
We plan to seek to hold and not allow to expire that acreage highest in resistivity and most likely to be developed
 
Many of the leases comprising the acreage set forth in the table above will expire at the end of their respective primary terms unless production from the leasehold acreage has been established prior to such date, in which event the lease will remain in effect until the cessation of production in commercial quantities. While we may attempt to secure a new lease upon the expiration of certain of our acreage, there are some third-party leases that may become effective immediately if our leases expire at the end of their respective terms and production has not been established prior to such date. We have options to extend some of our leases through payment of additional lease bonus payments prior the expiration of the primary term of the leases. Our leases are mainly fee leases with three to five years of primary term. We believe that our leases are similar to our competitors’ fee lease terms as they relate to primary term and reserved royalty interests.
 
Drilling Activity
 
The following table summarizes our operated and non-operated drilling activity for exploratory and development wells drilled from 2012 through 2013 on our Niobrara, Eagle Ford, and North Sugar Valley assets.
 
 
Net Exploratory
   
Net Development
 
     
2012
   
2013
       
2012
   
2013
 
Wells Drilled
                             
Productive
     
0.31
     
1.07
         
0.04
     
.08
 
Dry
     
-
     
-
         
-
     
-
 
Total
     
0.31
     
1.07
         
0.04
     
.08
 
 
 
60

 
 
Natural Gas and Oil Reserves
 
Reserves Estimates
 
The following table sets forth, by property and as of December 31, 2013, our estimated net proved oil and natural gas reserves, and the estimated present value (discounted at an annual rate of ten percent (10%)) of estimated future net revenues before future income taxes (PV-10) and after future income taxes (Standardized Measure) of our proved reserves, each prepared in accordance with assumptions described by the Securities and Exchange Commission (“SEC”).
 
The PV-10 value is a widely used measure of value of oil and natural gas assets and represents a pre-tax present value of estimated cash flows discounted at ten percent (10%). PV-10 is considered a non-GAAP financial measure as defined by the SEC. We believe that our PV-10 presentation is relevant and useful to our investors because it presents the discounted future net cash flows attributable to our proved reserves before taking into account the related future income taxes, as such taxes may differ among various companies because of differences in the amounts and timing of deductible basis, net operating loss carry forwards and other factors. We believe investors and creditors use our PV-10 as a basis for comparison of the relative size and value of our proved reserves to the reserve estimates of other companies. PV-10 is not a measure of financial or operating performance under GAAP and is not intended to represent the current market value of our estimated oil and natural gas reserves. PV-10 should not be considered in isolation or as a substitute for the standardized measure of discounted future net cash flows as defined under GAAP.
 
These calculations were prepared using standard geological and engineering methods generally accepted by the petroleum industry and in accordance with SEC financial accounting and reporting standards.
 
   
Reserves at December 31, 2013
 
Reserve Category
 
Oil
(Bbls)
   
Natural Gas
(MMcf)
   
Total (4)
(BOE)
 
Owned Directly by PEDEVCO (1)
                 
Proved Developed
                 
-Niobrara Held Directly
   
16,665
     
34
     
22,332
 
-Eagle Ford Held in White Hawk
   
27,419
     
44
     
34,752
 
-North Sugar Valley
   
9,762
     
-
     
9,762
 
Total Proved Developed (Direct)
   
53,846
     
78
     
66,846
 
                         
Proved Undeveloped
                       
-Niobrara Held Directly
   
84,925
     
176
     
114,258
 
- Eagle Ford Held in White Hawk
   
-
     
-
     
-
 
-North Sugar Valley
   
-
     
-
     
-
 
Total Proved Undeveloped (Direct)
   
84,925
     
176
     
114,258
 
                         
Total Proved Reserves (Owned Directly by PEDEVCO)
   
138,771
     
254
     
181,104
 
                         
Owned Indirectly Through Equity Investees (2)
                       
Proved Developed
                       
- Niobrara Held in Condor
   
35,465
     
73
     
47,704
 
Total Proved Developed (Indirect)
   
35,465
     
73
     
47,704
 
                         
Proved Undeveloped
                       
- Niobrara Held in Condor
   
218,807
     
454
     
294,477
 
Total Proved Undeveloped (Indirect)
   
218,807
     
454
     
294,477
 
Total Proved Reserves (Owned Indirectly through Investees)
   
254,272
     
527
     
342,181
 
                         
Combined Directly and Indirectly Owned (3)
                       
Combined Total Proved Developed Reserves
   
89,311
     
151
     
114,550
 
Combined Total Proved Undeveloped Reserves
   
303,732
     
630
     
408,735
 
Combined Total Proved Reserves  (Direct & Indirect)
   
393,043
     
781
     
523,285
 
 
(1)
Includes reserves attributable to our 9.08% average directly held interest in the Niobrara asset, Eagle Ford asset and our North Sugar Valley asset.
 
(2)
Includes reserves net to the Company’s equity interest held in unconsolidated investments in Condor.
 
(3)
Includes combined reserves as described in both (1) and (2) above.
 
(4)
Natural gas is converted on the basis of six (6) Mcf per one (1) barrel of oil equivalent.
 
 
61

 
 
   
Reserves at December 31, 2012
 
Reserve Category
 
Oil
(Bbls)
   
Natural Gas
(MMcf)
   
Total (4)
(BOE)
 
Owned Directly by PEDEVCO (1)
                 
Proved Developed
                 
-Niobrara Held Directly
   
44,512
     
74
     
56,845
 
-North Sugar Valley
   
36,988
     
-
     
36,988
 
Total Proved Developed (Direct)
   
81,500
     
74
     
93,833
 
                         
Proved Undeveloped
                       
-Niobrara Held Directly
   
195,008
     
324
     
249,008
 
-North Sugar Valley
   
-
     
-
     
-
 
Total Proved Undeveloped (Direct)
   
195,008
     
324
     
249,008
 
                         
Total Proved Reserves (Owned Directly by PEDEVCO)
   
276,508
     
398
     
342,841
 
                         
Owned Indirectly Through Equity Investees (2)
                       
Proved Developed
                       
- Niobrara Held in Condor
   
29,082
     
48
     
37,082
 
- Eagle Ford Held in White Hawk
   
11,147
     
21
     
14,647
 
Total Proved Developed (Indirect)
   
40,229
     
69
     
51,729
 
                         
Proved Undeveloped
                       
- Niobrara Held in Condor
   
323,239
     
537
     
412,739
 
- Eagle Ford Held in White Hawk
   
127,480
     
181
     
157,647
 
Total Proved Undeveloped (Indirect)
   
450,719
     
718
     
570,386
 
                         
Total Proved Reserves (Owned Indirectly through Investees)
   
490,948
     
787
     
622,115
 
                         
Combined Directly and Indirectly Owned (3)
                       
Combined Total Proved Developed Reserves
   
121,729
     
143
     
145,562
 
Combined Total Proved Undeveloped Reserves
   
645,727
     
1,042
     
819,394
 
Combined Total Proved Reserves  (Direct & Indirect)
   
767,456
     
1,185
     
964,956
 
 
(1)
Includes reserves attributable to our 18.75% average directly held interest in the Niobrara asset and our North Sugar Valley asset.
 
(2)
Includes reserves net to the Company’s equity interest held in unconsolidated investments in Condor and White Hawk.
 
(3)
Includes combined reserves as described in both (1) and (2) above.
 
(4)
Natural gas is converted on the basis of six (6) Mcf per one (1) barrel of oil equivalent.
 
 
62

 
 
The following table is a summary of Proved Reserves at December 31, 2013 and 2012 for interests owned directly by PEDEVCO and indirectly through an unconsolidated investment in Condor.  
 
   
December 31, 2013
 
PV-10 (1) (‘000s)
 
Proved Developed
   
Proved Undeveloped
   
Total Proved
 
Directly Owned Proved Reserves
 
$
2,142
   
$
(628)
   
$
1,514
 
Indirectly Owned Proved Reserves
 
$
1,055
   
$
(945)
   
$
110
 
Combined Proved Reserves
 
$
3,197
   
$
(1,573)
   
$
1,624
 
                         
   
December 31, 2012
 
PV-10 (1) (‘000s)
 
Proved Developed
   
Proved Undeveloped
   
Total Proved
 
Directly Owned Proved Reserves
 
$
2,426
   
$
689
   
$
3,115
 
Indirectly Owned Proved Reserves
 
$
1,219
   
$
2,855
   
$
4,074
 
Combined Proved Reserves
 
$
3,645
   
$
3,544
   
$
7,189
 
                         
 
(1)
In accordance with applicable financial accounting and reporting standards of the SEC, the estimates of our proved reserves and the PV-10 set forth herein reflect estimated future gross revenue to be generated from the production of proved reserves, net of estimated production and future development costs, using prices and costs under existing economic conditions at December 31, 2013 and 2012. For purposes of determining prices, we used the unweighted arithmetical average of the prices on the first day of each month within the 12-month period ended December 31, 2013 and 2012. The average prices utilized for purposes of estimating our proved reserves as of December 31, 2013 and 2012 were $90.37 and $87.35 per barrel of oil, respectively, and $5.71 and $4.73 per Mcf of natural gas, respectively, for our properties, adjusted by property for energy content, quality, transportation fees and regional price differentials. The prices should not be interpreted as a prediction of future prices. The amounts shown do not give effect to non-property related expenses, such as corporate general administrative expenses and debt service, future income taxes or to depreciation, depletion and amortization.
 
Due to the inherent uncertainties and the limited nature of reservoir data, proved reserves are subject to change as additional information becomes available. The estimates of reserves, future cash flows and present value are based on various assumptions, including those prescribed by the SEC, and are inherently imprecise. Although we believe these estimates are reasonable, actual future production, cash flows, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves may vary substantially from these estimates.
 
Reserve Estimation Process, Controls and Technologies
 
The reserve estimates, including PV-10, set forth above were prepared by Ryder Scott Company, L.P. (“Ryder Scott”). The reports from Ryder Scott were prepared on March 6, 2014 and March 14, 2014.
 
These calculations were prepared using standard geological and engineering methods generally accepted by the petroleum industry and in accordance with SEC financial accounting and reporting standards. Our year-end reserve reports are prepared by Ryder Scott based upon a review of property interests being appraised, production from such properties, current costs of operation and development, current prices for production, agreements relating to current and future operations and sale of production, geosciences and engineering data, and other information provided to them by our management team. Ryder Scott also prepares reserve estimates for Condor and White Hawk. This information is reviewed by knowledgeable members of our Company to ensure accuracy and completeness of the data, as it pertains to our Company, prior to submission to Ryder Scott Company, L.P. Upon analysis and evaluation of data provided, Ryder Scott issues preliminary appraisal reports of our directly held and indirectly held reserves. The preliminary appraisal reports and changes in our reserves are reviewed by our independent petroleum co