Attached files

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EX-99.1 - RESERVES REPORT OF SOUTH TEXAS RESERVOIR ALLIANCE LLC FOR RESERVES OF PEDEVCO CO - PEDEVCO CORPped_ex991.htm
EX-31.1 - CERTIFICATION PURSUANT TO RULE 13A-14(A)/15D-14(A) CERTIFICATIONS SECTION 302 OF - PEDEVCO CORPped_ex311.htm
EX-32.2 - CERTIFICATE PURSUANT TO SECTION 18 U.S.C. PURSUANT TO SECTION 906 OF THE SARBANE - PEDEVCO CORPped_ex322.htm
EX-32.1 - CERTIFICATE PURSUANT TO SECTION 18 U.S.C. PURSUANT TO SECTION 906 OF THE SARBANE - PEDEVCO CORPped_ex321.htm
EX-31.2 - CERTIFICATION PURSUANT TO RULE 13A-14(A)/15D-14(A) CERTIFICATIONS SECTION 302 OF - PEDEVCO CORPped_ex312.htm
EX-23.2 - CONSENT OF SOUTH TEXAS RESERVOIR ALLIANCE LLC - PEDEVCO CORPped_ex232.htm
EX-23.1 - CONSENT OF GBH CPAS, PC - PEDEVCO CORPped_ex231.htm
EX-21.1 - LIST OF SUBSIDIARIES OF PEDEVCO CORP. - PEDEVCO CORPped_ex211.htm
 
 

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
 
FORM 10-K
 
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934
 
For the fiscal year ended December 31, 2016
 
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) 733-3826
(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 ☐ No ☑
 
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 ☐ No ☑
 
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 ☑ No ☐
 
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ☑ No ☐
 
Indicate by check mark 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. ☑
 
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
 
Large accelerated filer
Accelerated filer
Non-accelerated filer
Smaller reporting company
 
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐  No ☑
 
The aggregate market value of the voting and non-voting common equity held by non-affiliates of the registrant as of June 30, 2016 based upon the closing price reported on such date was approximately $12,094,000. Shares of voting stock held by each officer and director and by each person who, as of June 30, 2016, 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 22, 2017, 54,931,117 shares of the registrant’s common stock, $0.001 par value per share, were outstanding.


 
 
 
Table of Contents
 
 
 
Page
PART I
 
 
 
Item 1.
Business
5
 
 
 
Item 1A.
Risk Factors
35
 
 
 
Item 1B. 
Unresolved Staff Comments
72
 
 
 
Item 2.
Properties
72
 
 
 
Item 3. 
Legal Proceedings
72
 
 
 
Item 4. 
Mine Safety Disclosures
72
 
 
 
PART II
 
 
 
Item 5.
Market For Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
73
 
 
 
Item 6. 
Selected Financial Data
77
 
 
 
Item 7. 
Management’s Discussion and Analysis of Financial Condition and Results of Operations
77
 
 
 
Item 7A. 
Quantitative and Qualitative Disclosure About Market Risk
91
 
 
 
Item 8. 
Financial Statements and Supplementary Data
91
 
 
 
Item 9. 
Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
91
 
 
 
Item 9A. 
Controls and Procedures
91
 
 
 
Item 9B. 
Other Information
93
 
 
 
PART III
 
 
 
Item 10. 
Directors, Executive Officers and Corporate Governance
94
 
 
 
Item 11. 
Executive Compensation
102
 
 
 
Item 12. 
Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
112
 
 
 
Item 13. 
Certain Relationships and Related Transactions, and Director Independence
117
 
 
 
Item 14. 
Principal Accounting Fees and Services
126
 
 
 
PART IV
 
 
 
Item 15. 
Exhibits and Financial Statement Schedules
127
 
 
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, 2016. 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 (UNTIL DIVESTED EFFECTIVE JANUARY 1, 2015), WHITE HAWK PETROLEUM, LLC (DISSOLVED EFFECTIVE NOVEMBER 30, 2016), PACIFIC ENERGY TECHNOLOGY SERVICES, LLC (DISSOLVED EFFECTIVE DECEMBER 31, 2015), PACIFIC ENERGY & RARE EARTH LIMITED, BLACKHAWK ENERGY LIMITED, RED HAWK PETROLEUM, LLC, PACIFIC ENERGY DEVELOPMENT MSL LLC (DISSOLVED EFFECTIVE SEPTEMBER 30, 2016), WHITE HAWK ENERGY, LLC, AND PEDEVCO ACQUISITION SUBSIDIARY, INC. (DISSOLVED EFFECTIVE APRIL 26, 2016), 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;
 
 
3
 
 
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 activities;
environmental liabilities;
counterparty credit risk;
developments in oil-producing and natural gas-producing countries;
future operating results;
planned combination transaction with GOM Holdings, LLC; and
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.
 
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.
 
Unless the context otherwise requires and for the purposes of this report only:
 
   ● “Exchange Act” refers to the Securities Exchange Act of 1934, as amended;
   ● “SEC” or the “Commission” refers to the United States Securities and Exchange Commission; and
   ● “Securities Act” refers to the Securities Act of 1933, as amended.
 
Available Information
 
We are subject to the information and reporting requirements of 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.pacificenergydevelopment.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.
 
 
 
4
 
 
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, and in 2010 we changed the direction of the Company to focus on the acquisition of oil and gas producing properties.
 
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 was 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 Denver-Julesberg Basin (“D-J Basin”) in Colorado, which contains hydrocarbon bearing deposits in several formations, including the Niobrara, Codell, Greenhorn, Shannon, J-Sand, and D-Sand. As of December 31, 2016, we held approximately 11,538 net D-J Basin acres located in Weld County, Colorado through our wholly-owned subsidiary Red Hawk Petroleum, LLC (“Red Hawk”), which acreage is located in the Wattenberg and Wattenberg Extension areas of the D-J Basin, which we refer to as our “D-J Basin Asset.” As of December 31, 2016, we hold interests in 61 gross (17.4 net) wells in our D-J Basin Asset, of which 14 gross (12.5 net) wells are operated by Red Hawk and are currently producing, 25 gross (4.9 net) wells are non-operated, and 22 wells have an after-payout interest. During the quarter-ended December 31, 2016, the Company produced an average of approximately 1,232 gross (272 net) barrels of oil equivalent per day (“BOEPD”) from its D-J Basin Asset.
 
In February 2015, the Company sold to MIE Jurassic Energy Corp. (“MIEJ”), its then 80% partner in Condor Energy Technology LLC (“Condor”), the Company’s (i) 20% interest in Condor, and (ii) approximately 972 net acres and interests in three wells located in the Company’s legacy, non-core Niobrara acreage located in Weld County, Colorado, that were directly held by the Company in Condor-operated wells. The assets sold included working interests in five Condor-operated wells that produced approximately 26 barrels of oil per day, net to the Company’s interest, as of February 2015, as well as approximately 2,300 net acres to the Company’s interest in non-core Niobrara areas. The Company and MIEJ also agreed to aggregate and restructure all liabilities owed by the Company to MIEJ and Condor, reducing our debt outstanding with MIEJ and Condor from approximately $9.4 million to $4.925 million, revising and extending the terms of the outstanding debt due to MIEJ, and reducing our senior debt by $500,000 through MIEJ’s direct repayment of principal due to our senior lenders. See greater details regarding this transaction below in “Management’s Discussion and Analysis of Financial Condition and Results of OperationsLiquidity and Capital ResourcesAmendment to PEDCO-MIEJ Note and Condor-MIEJ Note.
 
 
5
 
 
Also in February 2015, we expanded our D-J Basin position through the acquisition of additional acreage from Golden Globe Energy (US), LLC (“GGE”), which acquisition we refer to as the GGE Acquisition, which included approximately 12,977 additional net acres in the D-J Basin located almost entirely within Weld County, Colorado, including acreage located in the prolific Wattenberg core area, and interests in 53 gross wells with an estimated then-current net daily production of approximately 500 Boepd as of February 7, 2015. The majority of these assets were originally conveyed to GGE’s predecessor-in-interest, RJ Resources Corp., by us in March 2014 in connection with our acquisition of substantially all of the acreage, well interests and operations of Continental Resources, Inc. (“Continental”) located in the D-J Basin (the “Continental Acquisition”), and are now included in our D-J Basin Asset. As partial consideration paid by the Company to GGE in the GGE Acquisition, the Company provided GGE with a one-year option to acquire all of the Company’s interests in Caspian Energy Inc., an Ontario, Canada company listed on the NEX board of the TSX Venture Exchange that holds exploration and production assets in Kazakhstan (“Caspian Energy”), comprised of 23,182,880 shares of common stock of Caspian Energy, for an option exercise price of $100,000. The option provided to GGE was not exercised and has expired, but was reissued to GGE in connection with the restructuring of certain junior debt of the Company held by GGE’s affiliates in May 2016, with the option now expiring May 12, 2019, as described in greater detail below under “Recent Developments” – “Junior Debt Restructuring.
 
On December 29, 2015, the Company entered into an Agreement and Plan of Reorganization (as amended to date, the “GOM Merger Agreement”) with White Hawk Energy, LLC (“White Hawk”) and GOM Holdings, LLC (“GOM”), a Delaware limited liability company. The GOM Merger Agreement provides for the Company’s acquisition of GOM through an exchange of certain of the shares of the Company’s common and preferred stock (the “Consideration Shares”), as described in greater detail in the Notes, for 100% of the limited liability company membership units of GOM (the “GOM Units”), with the GOM Units being received by White Hawk and GOM receiving the Consideration Shares, as described in greater detail in the Notes from the Company (the “GOM Merger”). On February 29, 2016, the parties entered into an amendment to the GOM Merger Agreement, which amended the merger agreement in order to provide GOM additional time to meet certain closing conditions contemplated by the GOM Merger Agreement. The parties entered into the Amendment to extend the deadline for closing the merger and the date after which either party could terminate the GOM Merger Agreement if the merger had not yet been consummated, from February 29, 2016 to no later than April 15, 2016.
 
On April 25, 2016, the Company entered into Amendment No. 2 to the GOM Merger Agreement (the “Amendment No. 2”) with White Hawk and GOM, which further amends the GOM Merger Agreement in order to provide GOM additional time to meet certain closing conditions contemplated by the GOM Merger Agreement. Pursuant to Amendment No. 2, the parties agreed to remove the deadline for closing the merger and work expeditiously in good faith toward closing.
 
In order for the Company to move forward with the GOM Merger, it is requiring that GOM improve its financial position, including pay off certain amounts of its accounts payable. The Company and GOM continue to move forward with the merger, which the Company is working to close as soon as possible, subject to satisfaction of closing conditions including possible approval by applicable bankruptcy courts, provided that the Company is unable to estimate when, if ever, the bankruptcy courts may approve the merger (if and as required), or the estimated timing to close such transaction (see also “The closing of the GOM merger is subject to various risks and closing conditions and such planned transaction may not occur on a timely basis, if at all.”, below under “Part I” – “Item 1A. Risk Factors”).
 
 
6
 
 
We have listed below the total production volumes and total revenue net to the Company for the years ended December 31, 2016, 2015, and 2014 attributable to our D-J Basin Asset, including the calculated production volumes and revenue numbers for our D-J Basin Asset held indirectly through Condor that would be net to our interest if reported on a consolidated basis.
 
 
 
For the Years Ended December 31,     
 
 
 
2016
 
 
2015
 
 
2014
 
Oil
 
 
 
 
 
 
 
 
 
Total Production (Bbls)
  92,966 
  117,365 
  57,753 
Average sales price (per Bbl)
 36.98 
 41.13 
 80.06 
Natural Gas:
    
    
    
Total Production (Mcf)
  168,555 
  343,967 
  94,981 
Average sales price (per Mcf)
 $1.98
 1.54 
 5.42 
Oil Equivalents:
    
    
    
Total Production (Boe) (1)
  121,058 
  174,693 
  73,583 
Average Daily Production (Boe/d)
  332 
  479 
  202 
Average Production Costs (per Boe)(2)
 10.42
 6.63 
 15.78 
_________________________
 
(1)
Assumes 6 Mcf of natural gas equivalents to 1 barrel of oil.
 
(2)
Excludes ad valorem and severance taxes.
 
Business Strategy
 
We believe that the D-J Basin shale play represents among the most promising unconventional oil and natural gas plays in the U.S. We plan to opportunistically seek additional acreage proximate to our currently held core acreage located in the Wattenberg and Wattenberg Extension areas of Weld County, Colorado. 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 next twelve months will be focused on the development of our D-J Basin Asset. Our development plan calls for the development of approximately $11.1 million in capital expenditures in order to drill and complete, participate in the drilling and completion of, and/or acquire approximately 3.3 net wells in our D-J Basin Asset in 2017. We expect our projected cash flow from operations combined with our existing cash on hand, up to $2.0 million of gross proceeds available from the issuance of our common shares through National Securities Corporation under our current “at the market offering,” and approximately $18.0 million gross available under our current senior debt facility will be sufficient to fund our drilling plans and our operations in 2017, noting that the advancement of all or any portion of the approximately $18.0 million gross available under our current senior debt facility is in the sole and absolute discretion of the senior lenders and no senior lender is obligated to fund all or any part of the requested funding (See “Part I, Item 1. Business” — “Recent Developments” — “Senior Debt Restructuring and “Part I” – “Item 1A. Risk Factors”, including “Our Tranche A Notes and Tranche B Notes include various covenants, reduces our flexibility, increases our interest expense and may adversely impact our operations and our costs.”). In addition, we may seek additional funding through asset sales, farm-out arrangements, lines of credit, or public or private debt or equity financings to fund additional 2017 capital expenditures and/or repay or refinance a portion or all of our outstanding debt. If market conditions are not conducive to raising additional funds, the Company may choose to extend the drilling program and associated capital expenditures further into 2018. The availability of additional borrowings under the senior debt facility is subject to the Company providing matching funds for all amounts borrowed, which additional borrowed funds may only be used to fund development costs.
 
 
7
 
 
During 2016, the Company has focused on growth opportunities, while addressing the expected liquidity requirements arising from a significant decrease in oil and gas prices. The Company had the following significant events:
 
 
Closed a new $25.96 million delayed draw term loan facility in May 2016, which funds are primarily to be used for funding the development of new wells in the D-J Basin Asset, and of which $6.4 million was drawn to fund drilling and completion costs related to 8 additional wells located in the D-J Basin Asset.
 
 
Restructured the Company’s previously outstanding senior debt in May 2016, capitalizing all accrued and unpaid interest and extending the maturity to June 11, 2019, with no payments due until after the new delayed draw term loan facility has been paid off.
 
 
 
 
Implemented general and administrative cost savings strategies (excluding non-cash items) which resulted in reducing annual cash-based general and administrative costs from approximately $3,360,000 in 2015 to $2,436,000 in 2016, with a current run-rate of approximately $1,800,000 at the beginning of 2017.
 
 
 
 
Continued to move forward with our business combination with GOM, which, if consummated, is expected to result in significant additional proved reserves production, and provide greater resources to raise capital (see “Part I” – “Item 1A. Risk Factors”, including “The closing of the GOM merger is subject to various risks and closing conditions and such planned transaction may not occur on a timely basis, if at all”, and other GOM Merger-related risk factors).
 
Management is continually reviewing the recoverability of its oil and gas assets given the reduction of crude oil and natural gas prices during the year. Over the course of the year, we have identified acreage that we believe has a low probability of development in the near future and have not renewed such leases where appropriate and impaired the values as necessary. We believe that a significant portion of the effects of lower crude oil prices are now being offset by the continuing reduction of drilling and completion, collection, selling and LOE costs. We believe the leases we currently plan to develop in our 2017 development plan continue to be economic due to our estimates of total recoverable reserves, expected production rates and the continued reduction in development and operational costs through this year. The recoverability of our oil and gas assets is dependent on our ability to secure sufficient funds to develop our properties. If we are unable to have access to our credit facilities or alternative financing transactions, and crude oil prices stay at their current prices or go lower or if the new development and operational costs do not hold or such costs return to higher levels, Company management may deem it appropriate in the future to impair certain of our oil and gas properties in the event we determine we will not be able to fully develop our drilling program.
 
 
The following chart reflects our current organizational structure:
 
 
 *Represents percentage of total voting power based on 54,931,117 shares of common stock and 66,625 shares of Series A Convertible Preferred Stock (solely on an issued and outstanding basis) outstanding as of March 22, 2017, with beneficial ownership calculated in accordance with Rule 13d-3 under the Exchange Act (but without reflecting the conversion of convertible securities into voting securities, including, notably, approximately 20,110,417 shares of common stock issuable to MIEJ Holdings Corporation upon conversion of principal and interest accrued through March 31, 2017 under the New MIEJ Note at a “floor price” of $0.30 per share – See “Part III” – “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” – “Liquidity and Capital Resources” – “Liquidity Outlook” – “Amendment to PEDCO-MIEJ Note and Condor-MIEJ Note” and see also “Part III” — “Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.”
 
 
8
 
 
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 a management team at our Company 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 successful energy ventures that were commercialized at Texaco, Erin Energy Corp. and other international and domestic energy companies. We believe that our management team is highly qualified to identify, acquire and exploit energy resources in the U.S.
 
Our management team is headed by our President and Chief Executive Officer, 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 Executive Vice President and General Counsel, Clark R. Moore, has over 10 years of energy industry experience, and formerly served as acting general counsel of Erin Energy Corp.
 
Our board of directors also brings extensive oil and gas industry experience, headed by our Chairman Frank C. Ingriselli, an international oil and gas industry veteran with nearly 40 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 Erin Energy Corp. Also on our Board sits Ms. Elizabeth P. Smith, who served in numerous executive-level capacities at Texaco, including as Corporate Compliance Officer, Director of Investor Relations, Vice President of Corporate Communications, and Vice President of Texaco Inc. with responsibility and oversight of Texaco’s Shareholder Services Group, and Adam McAfee, a Certified Management Accountant and “audit committee financial expert” with over 30 years’ experience, with prior positions at Nevo Energy, Inc., Aemetis, Inc., Apple Computer and others.
 
 
 
9
 
 
Key Advisors. Our key advisors include Tenet Advisory Group, LLC, which we refer to as TAG, and other industry veterans. The TAG team replaced South Texas Reservoir Alliance (“STXRA”) as our contract operator with respect to our D-J Basin operations in January 2017, pursuant to a customary written engagement providing for hourly billing for work performed by TAG for us, and terminable upon 60 days prior notice by either party. TAG has experience in drilling and completing horizontal wells, including over 150 horizontal wells with lengths exceeding 4,000 feet from 2010 to 2016, as well as experience in both slick water and hybrid multi-stage hydraulic fracturing technologies and in the operation of shale wells and fields. The TAG team has over 130 years of combined technical oil and gas experience covering reservoir engineering, geology, geophysics, drilling, completion, production operations, land and marketing across multiple producing regions and basins including East Texas, Onshore and Offshore Gulf Coast, Permian Basin, Mid-Continent and the Rockies. We believe that our relationship with TAG 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. We have accumulated interests in a total of approximately 11,538 net acres in our core D-J Basin Asset operating area, 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, we believe our current D-J Basin Asset could contain up to approximately 144 potential net wells based on 80 acre spacing, providing us with a substantial drilling inventory for future years. 
 
Marketing
 
The prices we receive for our oil and natural gas production fluctuate widely. The recent collapse in oil prices is among the most severe on record. The daily NYMEX WTI oil spot price went from a high of $107.95 per Bbl in June 2014 to low of $26.19 per Bbl in February 2016, the lowest settlement in nearly 13 years and rebounding up 100% from its February 2016 low but still more than 50% off its June 2014 high. The drop and volatility in crude oil pricing is due in large part to increased production levels, crude oil inventories and recessed global economic growth. Oil prices are also impacted by real or perceived geopolitical risks in oil producing regions, the relative strength of the U.S. dollar, weather and the global economy. We expect, and have already begun to see, that depressed oil prices will lead to cuts in the exploration and production budgets to reduce incremental oil supply, which should ultimately restore equilibrium to the world oil market and rebalance oil prices. 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” below.
 
Oil. Our crude oil is generally sold under short-term, extendable and cancellable agreements with unaffiliated purchasers. 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 are a party to a 12-month crude oil purchase contract with a third party buyer, expiring December 31, 2017, pursuant to which the buyer purchases the crude oil produced from our 14 operated wells in our D-J Basin Asset, at a price per barrel equal to the average of the New York Mercantile Exchange’s (NYMEX) daily settle quoted price for Cushing/WTI for trade days only during a calendar month, applicable to product delivered during any such calendar month, less a per barrel differential of $3.15. The crude oil is purchased at the wellhead, and we do not bear any incremental transportation costs.
 
Natural GasOur 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.
 
 
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In connection with our Continental Acquisition in March 2014, we became a party to a Gas Purchase Contract, dated December 1, 2011, 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 six (6) of our D-J Basin Asset operated 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.
 
In connection with our Continental Acquisition in March 2014, we also became a party to a Gas Purchase Agreement, dated April 1, 2012, as amended, with Sterling Energy Investments LLC, which we refer to as Sterling, pursuant to which we have agreed to sell, and Sterling has agreed to purchase, all gas produced from eight (8) of our D-J Basin 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 ensure that title to our properties is in accordance with standards generally accepted in the oil and natural gas industry. Some of our acreage may 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.
 
Oil and Gas Properties
 
We believe that the D-J Basin shale play represents among the most promising unconventional oil and natural gas plays in the U.S. We plan to opportunistically seek additional acreage proximate to our currently held core acreage located in the Wattenberg and Wattenberg Extension areas of Weld County, Colorado. 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 2017 will be focused on the development of our D-J Basin Asset. However, if the Company consummates its merger with GOM, the Company will work with GOM to prepare a projected drilling and completion schedule and budget, with the final schedule and budget anticipated to be disclosed by the Company if the GOM Merger is consummated and once they are available, which could impact our current 2017 drilling and completion plans. 
 
 
Unless otherwise noted, the following table presents summary data for our leasehold acreage in our core D-J Basin Asset as of December 31, 2016 and our drilling capital budget with respect to this acreage from January 1, 2017 to December 31, 2017. If commodity prices do not increase significantly, we may delay drilling activities. The ultimate amount of capital we will expend may fluctuate materially based on, among other things, market conditions, commodity prices, asset monetizations, the success of our drilling results as the year progresses, availability of capital, and whether we consummate the GOM Merger. In the event the GOM Merger is consummated, the Company plans to expand this development plan to incorporate development of assets held by GOM, with the final schedule and budget anticipated to be disclosed by the Company once they are available (see “Part I” – “Item 1A. Risk Factors”, including “The closing of the GOM merger is subject to various risks and closing conditions and such planned transaction may not occur on a timely basis, if at all”, and other GOM Merger-related risk factors).
 
 
11
 
 
 
 
 
 
 
 
 
 
 
 
 Drilling Capital Budget
January 1, 2017 - December 31, 2017
 
 
Current Core Assets:
 
 Net Acres
 
 
 Acre Spacing
 
 
Potential Net
Wells (1)
 
 
 Net Wells
 
 
Gross Costs
per Well (2)
 
 
Capital Cost to the Company (2)
 
D-J Basin Asset
  11,538 
  80 
  144 
 
 
 
 
 
 
 
 
 
Short lateral
    
    
    
  2.1 
 $2,592,000 
 $5,540,410 
Long lateral
    
    
    
  1.2 
 $4,763,000 
 $5,573,464 
Total Assets
  11,538 
    
  144 
  3.3 
    
 $11,113,874 
 
(1)
Potential Net Wells are calculated using 80 acre spacing, and not taking into account additional wells that could be drilled as a result of forced pooling in Niobrara, Colorado, where the D-J Basin Asset is located, which allows for forced pooling, and which may create more potential gross drilling locations than acre spacing alone would otherwise indicate.
 
(2)
Costs per well are gross costs while capital costs presented are net to our working interests.
 
D-J Basin Asset
 
We directly hold all of our interests in the D-J Basin Asset through our wholly-owned subsidiary, Red Hawk. These interests are all located in Weld County, Colorado. Red Hawk is currently the operator of 14 gross (12.5 net) wells located in our D-J Basin Asset. Our D-J Basin Asset acreage is located in the areas circled in the map below.
 
 

 
 
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Non-Core Assets
 
We own 23,182,880 shares of common stock of Caspian Energy, a Canadian publicly-traded company, representing approximately 5% of its common stock. Caspian Energy holds the rights to explore and develop certain oil and gas properties in the Republic of Kazakhstan known as the North Block, a 1,470 square kilometer area located in the vicinity of the Kazakh pre-Caspian Basin. As partial consideration paid by the Company to GGE to restructure certain junior Company debt held by GGE’s affiliates in May 2016, the Company provided GGE an option to acquire all of the Company’s interests in Caspian Energy for an option exercise price of $100,000, which expires May 12, 2019.
 
Our Core Areas
 
The majority of our capital expenditure budget for the period from January 2017 to December 2017 will be focused on the development of our core oil and natural gas properties located in the D-J Basin Asset. For additional information, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations-Liquidity and Capital Resources.
 
D-J Basin Asset
 
As of December 31, 2016 we held 11,538 net acres in oil and natural gas properties related to our D-J Basin Asset. We currently own direct interests in 61 gross (17.4 net) wells in our D-J Basin Asset, of which 14 gross (12.5 net) wells are operated by Red Hawk and are currently producing, 25 gross (4.9 net) wells are non-operated, and 22 wells have an after-payout interest. 
 
Our development plan calls for the development of approximately $11.1 million in capital expenditures in order to drill and complete, participate in the drilling and completion of, and/or acquire approximately 3.3 net wells in our D-J Basin Asset in 2017. We expect our projected cash flow from operations combined with our existing cash on hand, up to $2.0 million of gross proceeds available from the issuance of our common shares through National Securities Corporation under our current “at the market offering,” and approximately $18.0 million gross available under our current senior debt facility, will be sufficient to fund our drilling plans and our operations in 2017 (see “Part I” – “Item 1A. Risk Factors”, including “Our Tranche A Notes and Tranche B Notes include various covenants, reduces our flexibility, increases our interest expense and may adversely impact our operations and our costs.”). In addition, we may seek additional funding through asset sales, farm-out arrangements, lines of credit, or public or private debt or equity financings to fund additional 2017 capital expenditures and/or repay or refinance a portion or all of our outstanding debt. If market conditions are not conducive to raising additional funds, the Company may choose to extend the drilling program and associated capital expenditures further into 2018. The availability of additional borrowings under the senior debt facility is subject to the Company providing matching funds for all amounts borrowed, which additional borrowed funds may only be used to fund development costs.
 
Based on publicly available information and information we have received from our oilfield service vendors, average drilling and completion costs for wells in our core area continue to be significantly below prices we have seen in 2015 and prior years. In addition to more favorable drilling and completion costs, average estimated ultimate recoveries, or EURs, and initial 30-day average production rates have continued to increase through improved completion techniques in the area. The drilling and completion 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.
 
Our Non-Core Assets
 
As described above, we own 23,182,880 shares of common stock of Caspian Energy, a Canadian publicly-traded company, representing approximately 5% of its common stock. As partial consideration paid by the Company to GGE to restructure certain junior Company debt held by GGE’s affiliates in May 2016, the Company provided GGE an option to acquire all of the Company’s interests in Caspian Energy for an option exercise price of $100,000, which expires May 12, 2019, described in greater detail below under “Item 13. Certain Relationships and Related Transactions, and Director Independence” – “Agreements with Related Persons” – “Golden Globe Energy (US), LLC.
 
 
 
 
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Recent Developments
 
Senior Debt Restructuring
 
On May 12, 2016 (the “Closing Date”), the Company entered into an Amended and Restated Note Purchase Agreement (the “Amended NPA”), with SHIP, BRe BCLIC Sub, BRe WINIC 2013 LTC Primary, BRe WNIC 2013 LTC Sub, Heartland Bank, BHLN-Pedco Corp. (“BHLN”), BBLN-Pedco Corp. (“BBLN”), and RJC Credit LLC (“RJC”)(together with BHLN and BBLN, the “Tranche A Investors” and the “Lenders”), and the Agent, as agent for the Lenders. The Amended NPA amended and restated the March 2014 Notes (as defined and discussed below under “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” – “Liquidity and Capital Resources-Secured Debt Funding”), and the Company issued new Senior Secured Promissory Notes to each of the Lenders (collectively, the “Tranche B Notes”) in a transaction that qualified as a troubled debt restructuring. RJC is also a party to the RJC Junior Note (discussed below)(the “Senior Debt Restructuring”).
 
The Amended NPA amended the Senior Notes as follows:
 
Created new “Tranche A Notes,” in substantially the same form and with similar terms as the Tranche B Notes, except as discussed below, consisting of a term loan issuable in tranches with a maximum aggregate principal amount of $25,960,000, with borrowed funds accruing interest at 15% per annum, and maturing on May 11, 2019 (the “Tranche A Maturity Date”) (the “Tranche A Notes,” and together with the Tranche B Notes, the “New Senior Notes”);
The Company capitalized all accrued and unpaid interest under the Senior Notes, renaming them “Tranche B Notes,” as a term loan with an aggregate outstanding principal balance as of May 12, 2016 equal to $39,065,000. The Tranche B Notes mature on June 11, 2019 except for the Tranche B Note issued to RJC which matures on July 11, 2019;
Amended the provisions of the Senior Notes which required mandatory prepayments from our revenues, replacing them with a Net Revenue Sweep as described below; and
Provides that interest on the Tranche B Notes will continue to accrue at the rate of 15% per annum, but all accrued interest through December 31, 2017 shall be deferred until due and payable on the maturity date, with all interest amounts deferred being added to the principal of the Tranche B Notes on a monthly basis and that following December 31, 2017, all interest will accrue and be paid monthly in arrears in cash to the Tranche B Note holders, provided, however, no payment may be made on the Tranche B Notes unless and until the Tranche A Notes are repaid in full.
 
The Tranche A Notes are substantially similar to the Tranche B Notes, except that such notes are senior to the Tranche B Notes, accrue interest until maturity and have priority to the payment of Monthly Net Revenues as discussed below.
 
On the Closing Date, the Tranche A Investors loaned the Company their pro rata share of an aggregate of $6,422,000 (the “Initial Tranche A Funding”). The Initial Tranche A Funding net proceeds (also amounting to $6,422,000 less legal fees of $127,000) were used by the Company to (i) fund approximately $5.1 million due to a third party operator for drilling and completion expenses related to the acquired working interests in eight wells from Dome Energy, Inc. (“Dome Energy”), (ii) pay $750,000 of the Company’s past due payables to Liberty Oilfield Services, LLC (“Liberty”), (iii) pay $445,000 of unpaid interest payments due to Heartland Bank under its Tranche B Note through February 29, 2016, and (iv) pay fees and expenses of $127,000 incurred in connection with the transactions contemplated by the Amended NPA and related documents.
 
Subject to the terms and conditions of the Amended NPA, the Company may request each Tranche A Investor, from time to time, to advance to the Company additional amounts of funding (each, a “Subsequent Tranche A Funding”), provided that: (i) the Company may not request a Subsequent Tranche A Funding more than one time in any calendar month; (ii) Agent shall have received a written request from the Company at least 15 business days prior to the requested date of such advance (the “Advance Request”); (iii) no Event of Default or event that with the passage of time or the giving of notice, or both, would become an Event of Default (a “Default”) shall have occurred and be continuing or would result therefrom; and (iv) the Company shall provide to the Agent such documents, instruments, certificates and other writings as the Agent shall reasonably require in its sole and absolute discretion. The advancement of all or any portion of the Subsequent Tranche A Funding is in the sole and absolute discretion of the Agent and the Investors and no Investor is obligated to fund all or any part of the Subsequent Tranche A Funding. Each Subsequent Tranche A Funding is required to be in a minimum amount of $500,000 and multiples of $100,000 in excess thereof. The aggregate amount of Subsequent Tranche A Fundings that may be made by the Investors under the Amended NPA shall not exceed $18,577,876 and any Subsequent Tranche A Funding repaid may not be re-borrowed.
 
In addition, subject to the terms and conditions of the Amended NPA, RJC agreed to loan to the Company $240,000, within 30 days of the Closing Date and within 30 days of each of July 1, 2016, October 1, 2016 and January 1, 2017 (collectively, the “RJC Fundings” and collectively with the Investor Tranche A Fundings, the “Fundings”), provided that no Event of Default or Default shall have occurred and be continuing or would result therefrom. The aggregate amount of the RJC Fundings made by RJC under the Amended NPA shall not exceed $960,000 and any Funding repaid may not be re-borrowed.
 
To guarantee RJC’s obligation in connection with the RJC Fundings as required under the Amended NPA, GGE entered into a Share Pledge Agreement with the Company, dated May 12, 2016 (the “GGE Pledge Agreement”), pursuant to which GGE agreed to pledge an aggregate of 10,000 shares of the Company’s Series A Convertible Preferred Stock held by GGE (convertible into 10,000,000 shares of Company common stock), which pledged shares are subject to automatic cancellation and forfeiture based on a schedule set forth in the GGE Share Pledge Agreement, in the event RJC fails to meet each of its RJC Funding obligations pursuant to the Amended NPA. To date, RJC has not met its RJC Funding obligations under the Amended NPA and the Company is entitled to cancel and forfeit 10,000 shares of the Company’s Series A Convertible Preferred Stock held by GGE (convertible into 10,000,000 shares of Company common stock) pursuant to the terms of the GGE Pledge Agreement, which determination to cancel shares has not been made, and which shares have not been cancelled, as of the date of this filing.
 
As additional consideration for the entry into the Amended NPA and transactions related thereto, the Company has granted to BHLN and BBLN, warrants exercisable for an aggregate of 5,962,800 shares of common stock of the Company (the “Investor Warrants”). The warrants have a 3 year term, are transferrable, and are exercisable on a cashless basis at any time at $0.25 per share, subject to receipt of additional listing approval of such underlying shares of common stock from the NYSE MKT (which additional listing approval was received from the NYSE MKT on June 1, 2016). The Investor Warrants include a beneficial ownership limitation that prohibits the exercise of the Investor Warrants to the extent such exercise would result in the holder, together with its affiliates, holding more than 9.99% of the Company’s outstanding voting stock (the “Blocker Provision”). The estimated fair value of the Investor Warrants issued is approximately $707,000 based on the Black-Scholes option pricing model. The relative fair value allocated to the Tranche A Notes and recorded as debt discount was $636,000.
 
 
14
 
 
Other than the Investor Warrants, no additional warrants exercisable for common stock of the Company are due, owing, or shall be granted to the Lenders pursuant to the Senior Notes, as amended. In addition, warrants exercisable for an aggregate of 349,111 shares of the Company’s common stock at an exercise price of $1.50 per share and warrants exercisable for an aggregate of 1,201,004 shares of the Company’s common stock at an exercise price of $0.75 per share previously granted by the Company to certain of the Lenders on September 10, 2015, in connection with prior interest payment deferrals have been amended and restated to provide that all such warrants are exercisable on a cashless basis and include a Blocker Provision (the “Amended and Restated Warrants”).
 
Additionally, the Company also agreed to (a) provide to the Agent and the Investors a monthly projected general and administrative expense report (the “Projected G&A”) and a monthly comparison report of the Projected G&A provided for the preceding month, with an explanation of any variances, provided that in no event shall such variances exceed $150,000, and (B) pay to the Agent within 2 business days following the end of each calendar month all of the Company’s oil and gas revenue received by the Company during such month (the “Net Revenue Sweep”), less (i) lease operating expenses, (ii) interest payments due to Investors under the New Senior Notes, (iii) general and administrative expenses not to exceed $150,000 per month unless preapproved by the Agent (the “G&A Cap”), and (iv) preapproved extraordinary expenses (together the “Monthly Net Revenues”). Amounts paid to the Agent through the Net Revenue Sweep are applied first to the repayment of principal and then interest due under the Tranche A Notes until such notes are paid in full and then to the repayment of principal and interest amounts due under the Tranche B Notes.
 
The amounts outstanding under the New Senior Notes are secured by a first priority security interest in all of the Company’s and its subsidiaries’ assets, property, real property, intellectual property, securities and proceeds therefrom, granted in favor of the Agent for the benefit of the Lenders, pursuant to a Security Agreement and a Patent Security Agreement, each entered into as of March 7, 2014, as amended on May 12, 2016 (the “Amended Security Agreement” and “Amended Patent Agreement,” respectively). Additionally, the Agent, for the benefit of the Lenders, was granted a mortgage and security interest in all of the Company’s and its subsidiaries real property as located in the State of Colorado and the State of Texas pursuant to (i) a Leasehold Deed of Trust, Fixture Filing, Assignment of Rents and Leases, and Security Agreements, dated March 7, 2014, as amended May 12, 2016, filed in Weld County and Morgan County, Colorado; and (ii) a Mortgage, Deed of Trust, Security Agreement, Financing Statement and Assignment of Production to be filed in Matagorda County, Texas (collectively, the “Amended Mortgages”).
 
Additionally, the Company’s obligations under the New Senior Notes, Amended NPA and related agreements were guaranteed by the Company’s direct and indirect subsidiaries, Pacific Energy Development Corp., White Hawk Petroleum, LLC (“White Hawk”), Pacific Energy & Rare Earth Limited, Blackhawk Energy Limited, Pacific Energy Development MSL, LLC and Red Hawk Petroleum, LLC pursuant to a Guaranty Agreement, entered into on March 7, 2014, as amended on May 12, 2016 (the “Amended Guaranty Agreement”).
 
Other than as described above, the terms of the Amended NPA (including the covenants and obligations thereunder) are substantially the same as the March 2014 Note Purchase Agreement, and the terms of the Tranche A Notes and Tranche B Notes (including the events of default, interest rates and conditions associated therewith) are substantially the same as the original March 2014 Notes.
 
Junior Debt Restructuring
 
On May 12, 2016, the Company entered into an Amendment No. 2 to Note and Security Agreement with RJC (the “Second Amendment”), pursuant to which the Company and RJC agreed to amend the RJC Junior Note to (i) capitalize all accrued and unpaid interest under the RJC Junior Note as of the date of the parties’ entry into the Second Amendment, and add it to note principal, making the then current outstanding principal amount of the RJC Junior Note $9,379,432, (ii) extend the “Termination Date” thereunder (i.e., the maturity date) from December 31, 2017 to July 11, 2019, (iii) provide that all future interest accruing under the RJC Junior Note is deferred, due and payable on the Termination Date, with all future interest amounts deferred being added to principal on the first business day of the month following the month in which such deferred interest is accrued, and (iv) subordinate the RJC Junior Note to the Senior Notes.
 
 
 
15
 
 
As additional consideration for RJC’s agreement to enter into the Second Amendment, the Company entered into a Call Option Agreement with GGE, an affiliate of RJC, dated May 12, 2016 (the “GGE Option Agreement”), pursuant to which the Company provided GGE an option to purchase 23,182,880 common shares of Caspian Energy Inc., a British Columbia corporation, held by the Company, upon payment of $100,000 by GGE to the Company, which option expires on the “Termination Date” of the RJC Junior Note, as amended, as described above, currently May 12, 2019. The Company originally issued an option to GGE in February 2015 to acquire the Company’s interest in these shares in connection with the Company’s acquisition of certain producing oil and gas assets from GGE, which option expired unexercised in February 2016, as more fully described in the Company’s Current Report on Form 8-K filed with the Securities and Exchange Commission on February 24, 2015.
 
GOM Holdings, LLC Merger Agreement
 
On December 29, 2015, the Company entered into an Agreement and Plan of Merger (the “GOM Merger Agreement”) with White Hawk Energy, LLC, a Delaware limited liability company and wholly-owned subsidiary of the Company (“Merger Sub”), and GOM Holdings, LLC (“GOM”). The GOM Merger Agreement provides for the Company’s acquisition of GOM through an exchange of certain of the shares of the Company’s common and preferred stock (the “Consideration Shares”), as described in greater detail below, for 100% of the limited liability company membership units of GOM (the “GOM Units”), with the GOM Units being received by Merger Sub and GOM receiving the Consideration Shares, as described in greater detail below from the Company (the “Merger”).
 
On February 29, 2016, the Company entered into Amendment No. 1 to Agreement and Plan of Merger and Reorganization (the “Amendment”) with Merger Sub and GOM which amends GOM Merger Agreement. In order to provide GOM additional time to meet certain closing conditions contemplated by the GOM Merger Agreement, the parties entered into the Amendment to extend the deadline for closing the Merger and the date after which either party could terminate the GOM Merger Agreement if the Merger had not yet been consummated, from February 29, 2016 to no later than April 15, 2016.
 
On April 25, 2016, the Company entered into Amendment No. 2 to the GOM Merger Agreement (the “Amendment No. 2”) with Merger Sub and GOM, which further amends the GOM Merger Agreement in order to provide GOM additional time to meet certain closing conditions contemplated by the GOM Merger Agreement. Pursuant to Amendment No. 2, the parties agreed to remove the deadline for closing the Merger and work expeditiously in good faith toward closing.
 
The closing of the Merger is subject to various closing conditions as described below and as set forth in greater detail in the GOM Merger Agreement. At the Closing of the Merger, (i) GOM will transfer the GOM Units to Merger Sub, solely in exchange for the Consideration Shares, and (ii) Merger Sub will continue as a wholly-owned subsidiary of the Company and will continue to carry on the business of GOM. In exchange for the transfer of GOM Units to Merger Sub, the Company will issue to the members of GOM, the Consideration Shares as follows: (x) an aggregate of 1,551,552 shares of the Company’s restricted common stock (the “Common Stock”) and 698,448 restricted shares of the Company’s to-be-designated Series B Convertible Preferred Stock (the “Series B Preferred” (described in greater detail below)), and (y) will assume approximately $125 million of subordinated debt from GOM’s existing lenders and a $30 million undrawn letter of credit backing certain offshore asset retirement obligations (the “GOM Debt”), which GOM Debt is anticipated to be restructured on terms and conditions mutually acceptable to the Company and GOM prior to the Closing of the Merger.
 
 
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At or prior to Closing, we will file and cause to be effective a new Certificate of Designations of PEDEVCO Corp. Establishing the Designations, Preferences, Limitations, and Relative Rights of its Series B Convertible Preferred Stock (the “Certificate of Designation”), which will create 698,448 shares of newly-designated Series B Preferred, all of which will be issued to the members of GOM at Closing pro rata with their ownership of GOM. The Series B Preferred will (i) have a liquidation preference senior to all of the Company’s common stock and Series A Convertible Preferred Stock equal to $250 per share (the “Liquidation Preference”), (ii) accrue an annual dividend equal to 10% of the Liquidation Preference, payable annually from the date of issuance (the “Dividend”), (iii) vote together with the common stock on all shareholder matters, with each share having one (1) vote, and (iv) not be convertible into common stock of the Company until both the Shareholder Approval and NYSE MKT Approval are received (each as defined below). Upon the Company’s receipt of the Shareholder Approval and NYSE MKT Approval, (x) the Series B Preferred will automatically cease accruing Dividends and all accrued and unpaid Dividends will be automatically forfeited and forgiven in their entirety, (y) the Liquidation Preference of the Series B Preferred will be reduced to $0.001 per share from $250 per share, and (z) each share of Series B Preferred will be convertible into common stock on a 1,000:1 basis (the “Series B Conversion”), either (A) automatically upon the determination of the Company’s board of directors in its sole discretion (“Company Conversion”), or (B) at the option of the holder at any time (“Holder Conversion”), provided that no Holder Conversion is allowed to the extent the holder thereof would beneficially own more than 9.9% of the Company’s Common Stock or voting stock.
 
The parties have made customary representations, warranties and covenants in the GOM Merger Agreement including, among others, covenants relating to (1) the conduct of each party’s business during the interim period between the execution of the GOM Merger Agreement and the consummation of the Merger, (2) GOM’s Board of Managers’ and members’ approval of the GOM Merger Agreement and the Merger, and (3) equity grants anticipated to be made to the post-Closing management team by the Company, contingent upon the Equity Plan Increase (described below), which grants will be mutually agreed upon by the Company and GOM prior to Closing. In addition, within 30 days of the Closing, (A) the Company has agreed to use commercially reasonable best efforts to file all the required documents with the SEC necessary to seek shareholder approval (the “Shareholder Approval”) of (i) the issuance of the shares of common stock in connection with the Series B Conversion, (ii) an increase of shares available for issuance under the Company’s 2012 Equity Incentive Plan equal to 12.0% of the Company’s issued and outstanding capital stock (calculated post-Closing, assuming conversion of all Company Series A Preferred and Series B Preferred into Common Stock) (the “Equity Plan Increase”), and (iii) such other matters that are required to be approved by the shareholders of the Company pursuant to applicable rules and requirements of the SEC and NYSE MKT or which in the reasonable determination of the Company, shall be approved by the stockholders of the Company; and (B) the Company agreed to use commercially reasonable best efforts to file all the required documents with the NYSE MKT necessary to obtain NYSE MKT approval of the listing of the Company upon the Series B Conversion (the “NYSE MKT Approval”), if and as necessary pursuant to applicable NYSE MKT rules and regulations. The approval of the shareholders of the Company is not required under applicable law for the closing of the Merger, nor is it a required condition to closing the Merger, and the Company does not intend to seek shareholder approval for the closing of the Merger, only for the Shareholder Approval, after the closing of the Merger, as described above.
 
The Merger is subject to customary closing conditions, including (1) approval of the agreement by the board of directors of the Company, the sole Manager and member of Merger Sub, the Board of Managers of GOM, and the members of GOM, (2) receipt of required regulatory approvals, (3) the absence of any law or order prohibiting the consummation of the Merger, (4) approval of the NYSE MKT for the issuance of the common stock and shares of common stock issuable upon conversion of the Series B Preferred to the members of GOM at Closing, and (5) the effectiveness of the Certificate of Designation. Each party’s obligation to complete the GOM Merger is also subject to certain additional customary conditions, including (a) subject to certain exceptions, the accuracy of the representations and warranties of the other party, (b) performance in all material respects by the other party of its obligations under the GOM Merger Agreement, (c) completion of the restructuring of each of the Company’s and GOM’s existing debt, respectively, to the other party’s satisfaction, and (d) each of the Company and GOM furnishing the other with evidence that each has entered into amended employment agreements with certain of each party’s employees as required and in forms acceptable to the other party. In addition, each of the Company and GOM agreed to pay all costs and expenses incurred by them in connection with the GOM Merger Agreement.
 
The GOM Merger Agreement also includes customary termination provisions for both the Company and GOM. Specifically, and subject to the terms of the GOM Merger Agreement, the agreement can be terminated by either party at any time.
 
As of the date of this filing, the Company and GOM continue to move forward with the merger, which the Company is working to close as soon as possible, subject to satisfaction of closing conditions including possible approval by applicable bankruptcy courts, provided that the Company is unable to estimate when, if ever, the bankruptcy courts may approve the merger (if and as required), or the estimated timing to close such transaction (see also “The closing of the GOM merger is subject to various risks and closing conditions and such planned transaction may not occur on a timely basis, if at all.”, above under “Part I” – “Item 1A. Risk Factors”).
 
 
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The parties intend, for U.S. federal income tax purposes, that the Merger will qualify as a “reorganization” within the meaning of Section 368(a) of the Internal Revenue Code of 1986.
 
GOM is an investment owned by Platinum Partners Value Arbitrage Fund, LP, a New York based investment firm (“PPVAF”). PPVAF also owns RJ Credit LLC (“RJC”), which entity originally loaned the Company approximately $5.9 million in principal in connection with the Company’s March 2014 senior note funding and $8.9 million in principal in connection with the Company’s February 2015 acquisition of certain working interests from GGE, each as restructured in May 2016, and PPVAF also owns GGE, which entity is the holder of the Company’s Series A Convertible Preferred stock (as discussed in “Part II” – “Item 5. Market For Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities” – “Preferred Stock”). Each of GOM, RJC and GGE were formerly advised by Platinum Management (NY), LLC (“PM LLC”). PPVAF, and, by virtue of being owned by PPVAF, GGE, RJC, and GOM, are currently in the process of winding down and liquidating their assets through the oversight and control of a court-appointed liquidator in the Cayman Islands and are no longer advised by PM LLC or any of its affiliates. Additionally, the Company is aware that the former manager of PPVAF, PM LLC, is currently under investigation by the U.S. Securities and Exchange Commission and the Justice Department and that certain former executives have been indicted by the Justice Department, however, PM LLC and those certain executives no longer have any control over PPVAF, GOM, RJC or GGE, which entities are currently solely under the control of the Cayman Islands court-appointed liquidators.
 
PM LLC was also formerly an advisor to the entity that owns GGE, a greater than 5% stockholder of the Company, from whom the Company acquired approximately 12,977 net acres of oil and gas properties and interests in 53 gross wells located in the Denver-Julesburg Basin, Colorado in February 2015, in connection with which the Company assumed approximately $8.35 million of subordinated notes payable owed by GGE to RJC, issued to GGE 3,375,000 restricted shares of the Company’s common stock (representing approximately 9.9% of our then outstanding shares of common stock), and issued to GGE 66,625 restricted shares of the Company’s then newly-designated Amended and Restated Series A Convertible Preferred Stock (the “Series A Preferred”), which can be converted into shares of the Company’s common stock on a 1,000:1 basis, subject to a 9.9% ownership blocker. GGE, as the sole holder of the Company’s Series A Preferred, has the right to appoint two designees to the Company’s board of directors for as long as GGE continues to hold 15,000 shares of Series A Preferred designated as “Tranche One Shares” under the Company’s Amended and Restated Certificate of Designations of PEDEVCO Corp. Establishing the Designations, Preferences, Limitations, and Relative Rights of its Series A Convertible Preferred Stock. Mr. Steinberg is one of the Series A Preferred shareholder designees to the board of directors in connection with such right, provided that GGE has not designated any further members of the board of directors at this time.
 
Amendment to the 2012 Equity Incentive Plan
 
At the Company’s Annual Meeting of Stockholders held on December 28, 2016 (the “Annual Meeting”), the Company’s stockholders approved an amendment to the Company’s 2012 Equity Incentive Plan (the “Plan”) to increase by 5,000,000, the number of shares of common stock reserved for issuance under the Plan to a total of 15,000,000 shares.
 
Approval of Issuance of More Than 19.9% of the Company’s Outstanding Shares of Common Stock Upon Conversion of the New MIEJ Note
 
At the Company’s Annual Meeting, the Company’s stockholders approved, for purposes of Section 713 of the Company Guide of the NYSE MKT, LLC, which we refer to as the NYSE MKT, the issuance of more than 19.9% of our outstanding shares of common stock upon conversion of the principal and accrued interest owed under an outstanding Convertible Promissory Note in the principal amount of $4.925 million, held by MIE Jurassic Energy Corporation (“MIEJ”).
 
 
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Appointment of New Director
 
At the Annual Meeting, the stockholders of the Company appointed Frank C. Ingriselli, Elizabeth P. Smith, David Z. Steinberg and Adam McAfee as members of the board of directors. Mr. McAfee was appointed as a member of the board of directors to fill the vacancy left by departing director, David C. Crikelair, who did not stand for reelection at the Annual Meeting (Mr. Crikelair previously served as the Chairman of the Audit Committee and as a member of the Compensation Committee and Nominating and Corporate Governance Committee). At the time of appointment, the board of directors made the affirmative determination that Mr. McAfee was “independent” pursuant to applicable NYSE MKT rules and regulations and as defined under Rule 10A-3 of the Exchange Act. Effective upon his appointment to the board of directors on December 28, 2016, Mr. McAfee was also appointed to serve on the Compensation Committee, Nominating and Corporate Governance Committee, and Audit Committee of the Company’s board of directors, replacing Mr. Crikelair who previously served on each committee, with Mr. McAfee replacing Mr. Crikelair as Chairman of the Audit Committee and as the “audit committee financial expert” as defined under Item 407(d)(5) of Regulation S-K of the Securities Exchange Act.
 
Pursuant to the Company’s Board of Director’s compensation program (the “Board Compensation Program”), Mr. McAfee shall receive a quarterly cash payment of $5,000, and on December 28, 2016 he received a grant of 545,455 restricted shares of Company common stock valued at $60,000 on the date of grant, which shares vest in full on the date that is one year following the date of grant, subject to Mr. McAfee continuing to serve as a member of the board of directors on such date and conditions of a Restricted Shares Grant Agreement entered into by and between the Company and Mr. McAfee.
 
Reverse Stock Split
 
At the Company’s Annual Meeting, the Company’s stockholders authorized the board of directors of the Company, in their sole discretion and without further stockholder approval, to amend the Company’s Certificate of Formation, at any time prior to the earlier of (a) the one year anniversary of the Annual Meeting; and (b) the date of our 2017 annual meeting of stockholders, to effect a reverse stock split of our outstanding common stock in a ratio of between one-for-two and one-for-ten, provided that all fractional shares as a result of the split shall be automatically rounded up to the next whole share. The Company plans to effect the reverse split by May 3, 2017 as required by the NYSE MKT.
 
Restricted Stock and Option Awards
 
On December 28, 2016, in accordance with the terms of the Company’s Board Compensation Program, the Company granted 545,455 shares of restricted Company common stock under the Plan to each member of the Company’s board of directors – Messrs. Ingriselli, McAfee and Steinberg, and Ms. Smith – which shares vest on the date that is one year following the anniversary date of each director’s appointment to the Company’s board of directors as a non-employee director, in each case subject to the recipient of the shares being a member of the Company’s board of directors on such vesting date, and subject to the terms and conditions of a Restricted Shares Grant Agreement entered into by and between the Company and the recipient.
 
In addition, on December 28, 2016, in connection with the Company’s annual compensation review process, the Company granted restricted stock awards to Messrs. Michael L. Peterson (President and Chief Executive Officer) and Clark R. Moore (Executive Vice President, General Counsel and Secretary), of 1,650,000 and 1,050,000 shares, respectively, and options to purchase 600,000 shares of common stock to Gregory Overholtzer (Chief Financial Officer), which options have an exercise price of $0.11 per share and expire in five (5) years from the date of grant. The restricted stock and option awards were granted under the Company’s 2012 Equity Incentive Plan, as amended. The restricted stock and option awards vest as follows: 50% of the shares on the six (6) month anniversary of December 28, 2016 (the “Grant Date”); (ii) 30% on the twelve (12) month anniversary of the Grant Date; and (iii) 20% on the eighteen (18) month anniversary of the Grant Date, in each case subject to the recipient of the shares or options being an employee of or consultant to the Company on such vesting date, and subject to the terms and conditions of a Restricted Shares Grant Agreement or Stock Option Agreement, as applicable, entered into by and between the Company and the recipient.
 
 
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Notice of Delisting of Failure to Satisfy a Continued Listing Rule or Standard; Transfer of Listing.
 
On December 27, 2016, the Company received notice from the NYSE MKT LLC (the “Exchange”) that the Company is not in compliance with Section 1003(a)(iii) of the NYSE MKT Company Guide (“Company Guide”) since it reported stockholders’ equity of less than $6,000,000 at September 30, 2016 and has incurred net losses in its five most recent fiscal years ended December 31, 2015.
 
Receipt of the letter does not have any immediate effect upon the listing of the Company’s common stock, provided that in order to maintain its listing on the Exchange, the Exchange has requested that the Company submit a plan of compliance (the “Plan”) by January 27, 2017 addressing how the Company intends to regain compliance with Section 1003(a)(iii) of the Company Guide by June 27, 2018.
 
The Company’s management submitted a Plan to the Exchange by the January 27, 2017 deadline and the Exchange has accepted the Company’s Plan. As such, the Company will be able to continue its listing during the plan period and will be subject to continued periodic review by the Exchange staff. If the Company is unable to regain compliance with the continued listing standards by June 27, 2018, or the Company does not make progress consistent with the Plan during the plan period, the Company will be subject to delisting procedures as set forth in the Company Guide. The Company may then appeal such a determination by the staff of the Exchange in accordance with the provisions of the Company Guide. There can be no assurance that the Company will be able to achieve compliance with the Exchange’s continued listing standards within the required time frame. Until the Company regains compliance with the Exchange’s listing standards, a “.BC” indicator will be affixed to the Company’s trading symbol to denote non-compliance with the Exchange’s continued listing standards; provided that as disclosed in the Current Report on Form 8-K filed by the Company on November 9, 2016, a “.BC” indicator is already affixed to the Company’s trading symbol due to the fact that the Company is not in compliance with Section 1003(f)(v) of the Company Guide.
 
Shale Oil and Natural Gas Overview
 
The 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. Since 2010 alone, the U.S. production of tight oil has increased from less than 1 million barrels per day (MMBbl/d) in 2010, to more than 3 MMBbl/d in the second half of 2013, and to more than 4 MMBbl/d in 2016. This turnaround is mainly attributable to shale oil and natural gas output that has more than quintupled 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 2016 Annual Energy Outlook, the U.S. Energy Information Administration (“EIA”) estimated in its high resource case that total domestic crude oil production would increase to approximately 17 MMBbl/d by 2040, approximately 12 MMBbl/d of which would come from tight oil production, with net U.S. oil imports declining through 2040, with the U.S. becoming a net petroleum exporter in late 2022 and continuing as a net exporter through 2040.
 
 
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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 8,000 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. According to the EIA, the seven most prolific shale production areas in the Lower 48 states, which together account for 92% of domestic oil production growth and all domestic natural gas production growth during 2011-2014, are the Bakken Shale located in North Dakota and Eastern Montana, the Niobrara Shale in northeastern Colorado and parts of adjacent Wyoming, Nebraska, and Kansas, the Eagle Ford Shale in southern Texas, the Marcellus Shale spanning several states in the northeastern U.S., the Utica Shale in eastern Ohio, the Haynesville Shale in eastern Texas and western Louisiana, and the Permian Shale in western Texas and eastern New Mexico. According to the EIA’s September 2015 assessment, the total technically recoverable world resources of shale oil and gas are estimated at 418.9 billion barrels (oil) and 7,576.6 trillion cubic feet (gas), with an estimated 78.2 billion barrels (oil) and 622.5 trillion cubic feet (gas) being concentrated in the U.S.
 
Beginning in 2014, the oil and natural gas industry began to experience a sharp decline in commodity prices, with the daily NYMEX WTI oil spot price went from a high of $107.95 per Bbl in June 2014 to low of $26.19 per Bbl in February 2016, the lowest settlement in nearly 13 years. This recent decline in oil prices has resulted in a slowing of the pace of U.S. shale oil production, with Baker Hughes’ rig count data showing a decrease in the number of oil rigs operating in the DJ-Niobrara from 42 rigs at the end of December 2014 to 25 rigs at the end of December 2016. However, this has also led to average drilling and completion costs for wells in the DJ-Niobrara significantly dropping from between $4.3 million (short-lateral) and $8.3 million (long lateral) per well in early 2015 to between $2.7 million and $5.0 million per well currently, which reduced costs partially offset the decline in commodity prices, resulting in new shale oil wells drilled in more thermally mature formations of the DJ-Niobrara expected to continue to yield positive economic returns.
 
 
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Regulation of the Oil and Gas Industry
 
Our operations are substantially affected by federal, state and local laws and regulations. Failure to comply with applicable laws and regulations can result in substantial penalties. The regulatory burden on the industry increases the cost of doing business and affects profitability. Historically, our compliance costs have not had a material adverse effect on our results of operations; however, we are unable to predict the future costs or impact of compliance. Additional proposals and proceedings that affect the oil and natural gas industry are regularly considered by Congress, the states, the Federal Energy Regulatory Commission (the “FERC”) and the courts. We cannot predict when or whether any such proposals may become effective. We do not believe that we would be affected by any such action materially differently than similarly situated competitors.
 
Regulation Affecting Production
 
The production of oil and natural gas is subject to United States federal and state laws and regulations, and orders of regulatory bodies under those laws and regulations, governing a wide variety of matters. All of the jurisdictions in which we own or operate producing oil and natural gas properties have statutory provisions regulating the exploration for and production of oil and natural gas, including provisions related to permits for the drilling of wells, bonding requirements to drill or operate wells, the location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled, sourcing and disposal of water used in the drilling and completion process, and the abandonment of wells. Our operations are also subject to various conservation laws and regulations. These include the regulation of the size of drilling and spacing units or proration units, the number of wells which may be drilled in an area, and the unitization or pooling of oil or natural gas wells, as well as regulations that generally prohibit the venting or flaring of natural gas, and impose certain requirements regarding the ratability or fair apportionment of production from fields and individual wells. These laws and regulations may limit the amount of oil and gas we can drill. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, NGL and gas within its jurisdiction.
 
States do not regulate wellhead prices or engage in other similar direct regulation, but there can be no assurance that they will not do so in the future. The effect of such future regulations may be to limit the amounts of oil and gas that may be produced from our wells, negatively affect the economics of production from these wells or limit the number of locations we can drill.
 
The failure to comply with the rules and regulations of oil and natural gas production and related operations can result in substantial penalties. Our competitors in the oil and natural gas industry are subject to the same regulatory requirements and restrictions that affect our operations.
 
Regulation Affecting Sales and Transportation of Commodities
 
Sales prices of gas, oil, condensate and NGL are not currently regulated and are made at market prices. Although prices of these energy commodities are currently unregulated, the United States Congress historically has been active in their regulation. We cannot predict whether new legislation to regulate oil and gas, or the prices charged for these commodities might be proposed, what proposals, if any, might actually be enacted by the United States Congress or the various state legislatures and what effect, if any, the proposals might have on our operations. Sales of oil and natural gas may be subject to certain state and federal reporting requirements.
 
 
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The price and terms of service of transportation of the commodities, including access to pipeline transportation capacity, are subject to extensive federal and state regulation. Such regulation may affect the marketing of oil and natural gas produced by the Company, as well as the revenues received for sales of such production. Gathering systems may be subject to state ratable take and common purchaser statutes. Ratable take statutes generally require gatherers to take, without undue discrimination, oil and natural gas production that may be tendered to the gatherer for handling. Similarly, common purchaser statutes generally require gatherers to purchase, or accept for gathering, without undue discrimination as to source of supply or producer. These statutes are designed to prohibit discrimination in favor of one producer over another producer or one source of supply over another source of supply. These statutes may affect whether and to what extent gathering capacity is available for oil and natural gas production, if any, of the drilling program and the cost of such capacity. Further state laws and regulations govern rates and terms of access to intrastate pipeline systems, which may similarly affect market access and cost.
 
The FERC regulates interstate natural gas pipeline transportation rates and service conditions. The FERC is continually proposing and implementing new rules and regulations affecting interstate transportation. The stated purpose of many of these regulatory changes is to ensure terms and conditions of interstate transportation service are not unduly discriminatory or unduly preferential, to promote competition among the various sectors of the natural gas industry and to promote market transparency. We do not believe that our drilling program will be affected by any such FERC action in a manner materially differently than other similarly situated natural gas producers.
 
In addition to the regulation of natural gas pipeline transportation, FERC has additional, jurisdiction over the purchase or sale of gas or the purchase or sale of transportation services subject to FERC’s jurisdiction pursuant to the Energy Policy Act of 2005 (“EPAct 2005”). Under the EPAct 2005, it is unlawful for “any entity,” including producers such as us, that are otherwise not subject to FERC’s jurisdiction under the Natural Gas Act of 1938 (“NGA”) to use any deceptive or manipulative device or contrivance in connection with the purchase or sale of gas or the purchase or sale of transportation services subject to regulation by FERC, in contravention of rules prescribed by FERC. FERC’s rules implementing this provision make it unlawful, in connection with the purchase or sale of gas subject to the jurisdiction of FERC, or the purchase or sale of transportation services subject to the jurisdiction of FERC, for any entity, directly or indirectly, to use or employ any device, scheme or artifice to defraud; to make any untrue statement of material fact or omit to make any such statement necessary to make the statements made not misleading; or to engage in any act or practice that operates as a fraud or deceit upon any person. EPAct 2005 also gives FERC authority to impose civil penalties for violations of the NGA and the Natural Gas Policy Act of 1978 up to $1.0 million per day, per violation. The anti-manipulation rule applies to activities of otherwise non-jurisdictional entities to the extent the activities are conducted “in connection with” gas sales, purchases or transportation subject to FERC jurisdiction, which includes the annual reporting requirements under FERC Order No. 704 (defined below).
 
In December 2007, FERC issued a final rule on the annual natural gas transaction reporting requirements, as amended by subsequent orders on rehearing (“Order No. 704”). Under Order No. 704, any market participant, including a producer that engages in certain wholesale sales or purchases of gas that equal or exceed 2.2 million MMBtus of physical natural gas in the previous calendar year, must annually report such sales and purchases to FERC on Form No. 552 on May 1 of each year. Form No. 552 contains aggregate volumes of natural gas purchased or sold at wholesale in the prior calendar year to the extent such transactions utilize, contribute to the formation of price indices. Not all types of natural gas sales are required to be reported on Form No. 552. It is the responsibility of the reporting entity to determine which individual transactions should be reported based on the guidance of Order No. 704. Order No. 704 is intended to increase the transparency of the wholesale gas markets and to assist FERC in monitoring those markets and in detecting market manipulation.
 
The FERC also regulates rates and terms and conditions of service on interstate transportation of liquids, including oil and NGL, under the Interstate Commerce Act, as it existed on October 1, 1977 (“ICA”). Prices received from the sale of liquids may be affected by the cost of transporting those products to market. The ICA requires that certain interstate liquids pipelines maintain a tariff on file with FERC. The tariff sets forth the established rates as well as the rules and regulations governing the service. The ICA requires, among other things, that rates and terms and conditions of service on interstate common carrier pipelines be “just and reasonable.” Such pipelines must also provide jurisdictional service in a manner that is not unduly discriminatory or unduly preferential. Shippers have the power to challenge new and existing rates and terms and conditions of service before FERC.
 
 
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The rates charged by many interstate liquids pipelines are currently adjusted pursuant to an annual indexing methodology established and regulated by FERC, under which pipelines increase or decrease their rates in accordance with an index adjustment specified by FERC. For the five-year period beginning July 1, 2016, FERC established an annual index adjustment equal to the change in the producer price index for finished goods plus 1.23%. This adjustment is subject to review every five years. Under FERC’s regulations, a liquids pipeline can request a rate increase that exceeds the rate obtained through application of the indexing methodology by obtaining market-based rate authority (demonstrating the pipeline lacks market power), establishing rates by settlement with all existing shippers, or through a cost-of-service approach (if the pipeline establishes that a substantial divergence exists between the actual costs experienced by the pipeline and the rates resulting from application of the indexing methodology). Increases in liquids transportation rates may result in lower revenue and cash flows for the Company.
 
In addition, due to common carrier regulatory obligations of liquids pipelines, capacity must be prorated among shippers in an equitable manner in the event there are nominations in excess of capacity or for new shippers. Therefore, new shippers or increased volume by existing shippers may reduce the capacity available to us. Any prolonged interruption in the operation or curtailment of available capacity of the pipelines that we rely upon for liquids transportation could have a material adverse effect on our business, financial condition, results of operations and cash flows. However, we believe that access to liquids pipeline transportation services generally will be available to us to the same extent as to our similarly situated competitors.
 
Rates for intrastate pipeline transportation of liquids are subject to regulation by state regulatory commissions. The basis for intrastate liquids pipeline regulation, and the degree of regulatory oversight and scrutiny given to intrastate liquids pipeline rates, varies from state to state. We believe that the regulation of liquids pipeline transportation rates will not affect our operations in any way that is materially different from the effects on our similarly situated competitors.
 
In addition to FERC’s regulations, we are required to observe anti-market manipulation laws with regard to our physical sales of energy commodities. In November 2009, the Federal Trade Commission (“FTC”) issued regulations pursuant to the Energy Independence and Security Act of 2007, intended to prohibit market manipulation in the petroleum industry. Violators of the regulations face civil penalties of up to $1 million per violation per day. In July 2010, Congress passed the Dodd-Frank Act, which incorporated an expansion of the authority of the Commodity Futures Trading Commission (“CFTC”) to prohibit market manipulation in the markets regulated by the CFTC. This authority, with respect to oil swaps and futures contracts, is similar to the anti-manipulation authority granted to the FTC with respect to oil purchases and sales. In July 2011, the CFTC issued final rules to implement their new anti-manipulation authority. The rules subject violators to a civil penalty of up to the greater of $1 million or triple the monetary gain to the person for each violation.
 
Regulation of Environmental and Occupational Safety and Health Matters
 
Our operations are subject to stringent federal, state and local laws and regulations governing occupational safety and health aspects of our operations, the discharge of materials into the environment and environmental protection. Numerous governmental entities, including the U.S. Environmental Protection Agency (“EPA”) and analogous state agencies have the power to enforce compliance with these laws and regulations and the permits issued under them, often requiring difficult and costly actions. These laws and regulations may, among other things (i) require the acquisition of permits to conduct drilling and other regulated activities; (ii) restrict the types, quantities and concentration of various substances that can be released into the environment or injected into formations in connection with oil and natural gas drilling and production activities; (iii) limit or prohibit drilling activities on certain lands lying within wilderness, wetlands and other protected areas; (iv) require remedial measures to mitigate pollution from former and ongoing operations, such as requirements to close pits and plug abandoned wells; (v) apply specific health and safety criteria addressing worker protection; and (vi) impose substantial liabilities for pollution resulting from drilling and production operations. Any failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of corrective or remedial obligations, the occurrence of delays or restrictions in permitting or performance of projects, and the issuance of orders enjoining performance of some or all of our operations.
 
 
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These laws and regulations may also restrict the rate of oil and natural gas production below the rate that would otherwise be possible. The regulatory burden on the oil and natural gas industry increases the cost of doing business in the industry and consequently affects profitability. The 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 well drilling, construction, completion or water management activities, or waste handling, storage transport, disposal, or remediation requirements could have a material adverse effect on our financial position and results of operations. 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. Continued compliance with existing requirements is not expected to materially affect us. However, there is no assurance that we will be able to remain in compliance in the future with such existing or any new laws and regulations or that such future compliance will not have a material adverse effect on our business and operating results.
 
The following is a summary of the more significant existing and proposed environmental and occupational safety and health laws, as amended from time to time, to which our business operations are or may be subject and for which compliance may have a material adverse impact on our capital expenditures, results of operations or financial position.
 
Hazardous Substances and Wastes
 
The Resource Conservation and Recovery Act (“RCRA”), and comparable state statutes, regulate the generation, transportation, treatment, storage, disposal and cleanup of hazardous and non-hazardous wastes. Pursuant to rules issued by the EPA, the individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. Drilling fluids, produced waters, and most of the other wastes associated with the exploration, development, and production of oil or natural gas, if properly handled, are currently exempt from regulation as hazardous waste under RCRA and, instead, are regulated under RCRA’s less stringent non-hazardous waste provisions, state laws or other federal laws. However, it is possible that certain oil and natural gas drilling and production wastes now classified as non-hazardous could be classified as hazardous wastes in the future. For example, on May 4, 2016, several non-governmental environmental groups filed suit against the EPA in the U.S. District Court for the District of Columbia for failing to timely assess its RCRA Subtitle D criteria regulations for oil and natural gas wastes, asserting that the agency is required to review its Subtitle D regulations every three years but has not conducted an assessment on those oil and natural gas waste regulations since July 1988. Any such change could result in an increase in our as well as the oil and natural gas exploration and production industry’s costs to manage and dispose of wastes, which could have a material adverse effect on our results of operations and financial position. In the course of our operations, we generate some amounts of ordinary industrial wastes, such as paint wastes, waste solvents and waste oils that may be regulated as hazardous wastes.

The Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), also known as the Superfund law, and comparable state laws impose joint and several liability, without regard to fault or legality of conduct, on classes of persons who are considered to be responsible for the release of a hazardous substance into the environment. These persons include the current and former owners and operators of the site where the release occurred and anyone who disposed or arranged for the disposal of a hazardous substance released at the site. Under CERCLA, such persons may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. CERCLA also authorizes the EPA and, in some instances, third parties to act in response to threats to the public health or the environment and to seek to recover from the responsible classes of persons the costs they incur. 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 the hazardous substances released into the environment. We generate materials in the course of our operations that may be regulated as hazardous substances.
 
 
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We currently lease or operate numerous properties that have been used for oil and natural gas exploration, production and processing for many years. Although we believe that we have utilized operating and waste disposal practices that were standard in the industry at the time, hazardous substances, wastes, or petroleum hydrocarbons may have been released on, under or from the properties owned or leased by us, or on, under or from other locations, including off-site locations, where such substances have been taken for treatment or disposal. In addition, some of our properties have been operated by third parties or by previous owners or operators whose treatment and disposal of hazardous substances, wastes, or petroleum hydrocarbons was not under our control. These properties and the substances disposed or released on, under or from them may be subject to CERCLA, RCRA and analogous state laws. Under such laws, we could be required to undertake response or corrective measures, which could include removal of previously disposed substances and wastes, cleanup of contaminated property or performance of remedial plugging or pit closure operations to prevent future contamination, the costs of which could be substantial.
 
Water Discharges
 
The Federal Water Pollution Control Act, also known as the Clean Water Act (“CWA”), and analogous state laws, impose restrictions and strict controls with respect to the discharge of pollutants, including spills and leaks of oil and hazardous substances, into state waters and waters of the United States. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or an analogous state agency. Spill prevention, control and countermeasure plan requirements imposed under the CWA require appropriate containment berms and similar structures to help prevent the contamination of navigable waters in the event of a petroleum hydrocarbon tank spill, rupture or leak. In addition, the CWA and analogous state laws require individual permits or coverage under general permits for discharges of storm water runoff from certain types of facilities. The CWA also prohibits the discharge of dredge and fill material in regulated waters, including wetlands, unless authorized by permit. The EPA has issued final rules attempting to clarify the federal jurisdictional reach over waters of the United States but this rule has been stayed nationwide by the U.S. Sixth Circuit Court of Appeals as that appellate court and numerous district courts ponder lawsuits opposing implementation of the rule. In February 2016, a split three-judge panel of the Sixth Circuit Court of Appeals concluded that it has jurisdiction to review challenges to these final rules and the Sixth Circuit subsequently elected not to review this decision en banc but it is currently unknown whether other federal Circuit Courts or state courts currently considering this rulemaking will place their cases on hold, pending the Sixth Circuit’s hearing of the case. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with discharge permits or other requirements of the CWA and analogous state laws and regulations.
 
The Oil Pollution Act of 1990 (“OPA”), amends the CWA and sets minimum standards for prevention, containment and cleanup of oil spills. The OPA applies to vessels, offshore facilities, and onshore facilities, including exploration and production facilities that may affect waters of the United States. Under OPA, responsible parties including owners and operators of onshore facilities may be held strictly liable for oil cleanup costs and natural resource damages as well as a variety of public and private damages that may result from oil spills. The OPA also requires owners or operators of certain onshore facilities to prepare Facility Response Plans for responding to a worst-case discharge of oil into waters of the United States.
 
Subsurface Injections
 
 In the course of our operations, we produce water in addition to oil and natural gas. Water that is not recycled may be disposed of in disposal wells, which inject the produced water into non-producing subsurface formations. Underground injection operations are regulated pursuant to the Underground Injection Control (“UIC”) program established under the federal Safe Drinking Water Act (“SDWA”) and analogous state laws. The UIC program requires permits from the EPA or an analogous state agency for the construction and operation of disposal wells, establishes minimum standards for disposal well operations, and restricts the types and quantities of fluids that may be disposed. A change in UIC disposal well regulations or the inability to obtain permits for new disposal wells in the future may affect our ability to dispose of produced water and ultimately increase the cost of our operations. For example, in response to recent seismic events near belowground disposal wells used for the injection of oil and natural gas-related wastewaters, federal and some state agencies have begun investigating whether such wells have caused increased seismic activity, and some states have shut down or imposed moratoria on the use of such disposal wells. In response to these concerns, regulators in some states have adopted, and other states are considering adopting, additional requirements related to seismic safety. Increased costs associated with the transportation and disposal of produced water, including the cost of complying with regulations concerning produced water disposal, may reduce our profitability; however, these costs are commonly incurred by all oil and natural gas producers and we do not believe that the costs associated with the disposal of produced water will have a material adverse effect on our operations.
 
 
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Air Emissions
 
The Clean Air Act (“CAA”) and comparable state laws restrict the emission of air pollutants from many sources, such as, for example, tank batteries and compressor stations, through air emissions standards, construction and operating permitting programs and the imposition of other compliance standards. These laws and regulations may require us toobtain pre-approval for the construction or modification of certain projects or facilities expected to produce or significantly increase air emissions, obtain and strictly comply with stringent air permit requirements or utilize specific equipment or technologies to control emissions of certain pollutants. The need to obtain permits has the potential to delay the development of oil and natural gas projects. Over the next several years, we may be charged royalties on natural gas losses or required to incur certain capital expenditures for air pollution control equipment or other air emissions related issues. For example, on January 22, 2016, the federal Bureau of Land Management (“BLM”) released a proposed rule aimed at reducing natural gas lost through natural gas venting, flaring and equipment leaks from both new and existing production activities on federal lands. Except where natural gas loss is “unavoidable,” as defined by the proposed rule, operators would be charged royalties on natural gas losses from onshore federal and Indian mineral leases administered by the BLM. In a second example, the EPA promulgated rules in 2012 under the CAA that subject oil and natural gas production, processing, transmission and storage operations to regulation under the New Source Performance Standards (“NSPS”) and a separate set of requirements to address certain hazardous air pollutants frequently associated with oil and natural gas production and processing activities pursuant to the National Standards for Emission of Hazardous Air Pollutants (“NESHAPS”) program. With regards to production activities, these final rules require, among other things, the reduction of volatile organic compound (“VOC”) emissions from certain fractured and refractured natural gas wells for which well completion operations are conducted and further requires that a subset of these selected wells use reduced emission completions, also known as “green completions.” These regulations also establish specific new requirements regarding emissions from production-related wet seal and reciprocating compressors, and from pneumatic controllers and storage vessels. On June 3, 2016, the EPA published final rules establishing new air emission controls for methane emissions from certain new, modified or reconstructed equipment and processes in the oil and natural gas source category, including production, processing, transmission and storage activities. The EPA’s final rules include the NSPS to limit methane emissions from equipment and processes across the oil and natural gas source category. The rules also extend limitations on VOC emissions to sources that were unregulated under the previous NSPS at Subpart OOOO. Affected methane and VOC sources include hydraulically fractured (or re-fractured) oil and natural gas well completions, fugitive emissions from well sites and compressors, and pneumatic pumps. In a third example, on October 1, 2015, the EPA issued a final rule under the Clean Air Act, lowering the National Ambient Air Quality Standard (“NAAQS”) for ground-level ozone from the current standard of 75 parts per billion (“ppb”) for the current 8-hour primary and secondary ozone standards to 70 ppb for both standards. The final rule became effective on December 28, 2015. States are expected to implement more stringent requirements as a result of this new final rule, which could apply to our operations.
  
Compliance with one or more of these and other air pollution control and permitting requirements has the potential to delay the development of oil and natural gas projects and increase our costs of development and production, which costs could be significant.
 
Regulation of GHG Emissions
 
In response to findings that emissions of carbon dioxide, methane and other greenhouse gases (“GHGs”) present an endangerment to public health and the environment, the EPA has adopted regulations under existing provisions of the Clean Air Act that, among other things, establish Prevention of Significant Deterioration (“PSD”) construction and Title V operating permit reviews for certain large stationary sources that are already potential major sources of certain principal, or criteria, pollutant emissions. Facilities required to obtain PSD permits for their GHG emissions also will be required to meet “best available control technology” standards that typically will be established by state agencies. In addition, the EPA has adopted rules requiring the monitoring and annual reporting of GHG emissions from specified large, GHG emission sources in the United States, including certain onshore and offshore oil and natural gas production sources, which include certain of our operations.
 
 
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While Congress has from time to time considered legislation to reduce emissions of GHGs, there has not been significant activity in the form of adopted legislation to reduce GHG emissions at the federal level in recent years. In the absence of such federal climate legislation, a number of state and regional efforts have emerged that are aimed at tracking and/or reducing GHG emissions by means of cap and trade programs that typically require major sources of GHG emissions to acquire and surrender emission allowances in return for emitting those GHGs. In addition, the United States is one of almost 200 nations that, in December 2015, agreed to the Paris Agreement, an international climate change agreement in Paris, France (“Paris Agreement”) that calls for countries to set their own GHG emissions targets and be transparent about the measures each country will use to achieve its GHG emissions targets. A long-term goal of this Paris Agreement is to limit global warming to below two degrees Celsius by 2100 from temperatures in the pre-industrial era. The Paris Agreement entered into force in November 2016. Although it is not possible at this time to predict how new laws or regulations in the United States or any legal requirements imposed following the United States’ agreeing to the Paris Agreement that may be adopted or issued to address GHG emissions would impact our business, any such future laws, regulations or legal requirements imposing reporting or permitting obligations on, or limiting emissions of GHGs from, our equipment and operations could require us to incur costs to reduce emissions of GHGs associated with our operations as well as delays or restrictions in our ability to permit GHG emissions from new or modified sources. In addition, substantial limitations on GHG emissions could adversely affect demand for the oil and natural gas we produce. Finally, it should be noted that increasing concentrations of GHGs 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.
 
Hydraulic Fracturing Activities
 
 Hydraulic fracturing is an important and common practice that is used to stimulate production of natural gas and/or oil from dense subsurface rock formations. We regularly use hydraulic fracturing as part of our operations. Hydraulic fracturing involves the injection of water, sand or alternative proppant and chemicals under pressure into targeted geological formations to fracture the surrounding rock and stimulate production.
 
 Hydraulic fracturing is typically regulated by state oil and natural gas commissions. However, several federal agencies have asserted regulatory authority over certain aspects of the process. For example, the EPA published final CAA regulations in 2012 and, more recently, in June 2016 governing performance standards, including standards for the capture of air emissions released during oil and natural gas hydraulic fracturing, leak detection, and permitting; published on June 28, 2016 an effluent limited guideline final rule prohibiting the discharge of wastewater from onshore unconventional oil and natural gas extraction facilities to publicly owned wastewater treatment plants; and issued in 2014 a prepublication of its Advance Notice of Proposed Rulemaking regarding Toxic Substances Control Act reporting of the chemical substances and mixtures used in hydraulic fracturing. Also, the BLM published a final rule in March 2015, establishing stringent standards relating to hydraulic fracturing on federal and American Indian lands, but on June 21, 2016, a Wyoming federal judge struck down this final rule, finding that the BLM lacked congressional authority to promulgate the rule. Also, from time to time, legislation has been introduced, but not enacted, in Congress to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the fracturing process. In the event that a new, federal level of legal restrictions relating to the hydraulic-fracturing process is adopted in areas where we operate, we may incur additional costs to comply with such federal requirements that may be significant in nature, and also could become subject to additional permitting requirements and experience added delays or curtailment in the pursuit of exploration, development, or production activities.
 
 
 
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At the state level, Colorado, where we conduct operations, is among the states that has adopted, and other states are considering adopting, regulations that could impose new or more stringent permitting, disclosure or well-construction requirements on hydraulic fracturing operations. States could elect to prohibit high volume hydraulic fracturing altogether, following the approach taken by the State of New York in 2015. In addition to state laws, local land use restrictions, such as city ordinances, may restrict drilling in general and/or hydraulic fracturing in particular. For example, several cities in Colorado passed temporary or permanent moratoria on hydraulic fracturing within their respective cities’ limits in 2012-2013 but, since that time, in response to lawsuits brought by an industry trade group, the Colorado Oil and Gas Association, local district courts struck down the ordinances for certain of those Colorado cities in 2014, primarily on the basis that state law preempts local bans on hydraulic fracturing. The cities of Fort Collins and Longmont, among those cities whose ordinances were struck down in 2014, appealed their decisions to the Colorado Supreme Court, but on May 2, 2016, the state supreme court upheld the lower court rulings in the two cases, holding that the legal measures pursued by Fort Collins and Longmont were pre-empted by state law and, therefore, unenforceable. Notwithstanding attempts at the local level to prohibit hydraulic fracturing, there exists the opportunity for cities to adopt local ordinances allowing hydraulic fracturing activities within their jurisdictions but regulating the time, place and manner of those activities.
 
In addition, certain interest groups in Colorado opposed to oil and natural gas development generally, and hydraulic fracturing in particular, have from time to time advanced various options for ballot initiatives aimed at significantly limiting or preventing oil and natural gas development. In response to such initiatives, the Governor of Colorado created the Task Force on State and Local Regulation of Oil and Gas Operations (“Task Force”) in September 2014 to make recommendations to the state legislature regarding the responsible development of Colorado’s oil and gas resources. In February 2015, the Task Force made nine non-binding recommendations to the Governor that will require legislative or regulatory action to be implemented. See “Risk Factors—Federal, state and local legislative and regulatory initiatives relating to hydraulic fracturing as well as governmental reviews of such activities could result in increased costs and additional operating restrictions or delays in the completion of oil and natural gas wells and adversely affect our production,” for more information on these recommendations. It is possible that, as a result of the Task Force’s recommendations, the Colorado state legislature could seek to adopt new policies or legislation relating to oil and natural gas operations, including measures that would give local governments in Colorado greater authority to limit hydraulic fracturing and other oil and natural gas operations or require greater distances between well sites and occupied structures. In addition, it is possible that notwithstanding the recommendations made by the Task Force, certain interest groups in Colorado or even members of the Colorado state legislature may seek to pursue ballot initiatives in the future, and/or legislation that may or may not coincide with the Task Force’s recommendations, including, among other things, pursuit of initiatives or legislation for changes in state law that would allow local governments to ban hydraulic fracturing in Colorado.
 
In the event that ballot initiatives or local or state restrictions or prohibitions are adopted in areas where we conduct operations, including the Wattenberg Field in Colorado, that impose more stringent limitations on the production and development of oil and natural gas, including, among other things, the development of increased setback distances, we and similarly situated oil and natural exploration and production operators in the state may incur significant costs to comply with such requirements or may experience delays or curtailment in the pursuit of exploration, development, or production activities, and possibly be limited or precluded in the drilling of wells or in the amounts that we and similarly situated operates are ultimately able to produce from our reserves. Any such increased costs, delays, cessations, restrictions or prohibitions could have a material adverse effect on our business, prospects, results of operations, financial condition, and liquidity.
 
Certain governmental reviews are either underway or being proposed that focus on environmental aspects of hydraulic fracturing practices. The White House Council on Environmental Quality is coordinating an administration-wide review of hydraulic fracturing practices. Additionally, in December 2016, the EPA released its final report on the potential impacts of hydraulic fracturing on drinking water resources. The EPA report concluded that hydraulic fracturing activities have not led to widespread, systemic impacts on drinking water resources in the United States, although there are above and below ground mechanisms by which hydraulic fracturing activities have the potential to impact drinking water resources. Other governmental agencies, including the United States Department of Energy and the United States Department of the Interior, are evaluating various other aspects of hydraulic fracturing. These ongoing or proposed studies could spur initiatives to further regulate hydraulic fracturing under the federal SDWA or other regulatory mechanisms. 
 
 
 
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Ballot Initiatives that would Further Limit Certain Oil and Natural Gas Development Activities
 
In accordance with the Colorado Constitution, citizens in Colorado have the right to pursue amended or new state legislation through a ballot initiative process. Proponents of legal requirements imposing more stringent restrictions on oil and gas exploration and production activities in Colorado sought to include on the November 2016 ballot certain ballot initiatives that, if approved, would have allowed revisions to the state constitution in a manner that would make such exploration and production activities in the state more difficult in the future. Among the ballot initiatives pursued in 2016 were Initiative Number 75 (“Initiative 75”), which sought to authorize local governmental control over oil and natural gas development in Colorado that could have resulted in the imposition of more stringent requirements than currently implemented under state law, and Initiative 78 (“Initiative 78”), which proposed a much more stringent 2,500-foot mandatory setback between an oil and natural gas development facility (including oil and natural gas wells, production and processing equipment and pits) and specified occupied structures and areas of special concern. Changes sought under these ballot initiatives would have applied to new oil and gas development facilities in Colorado. Proponents of these measures collected signatures for placing Initiatives 75 and 78 on the November 2016 ballot and submitted those signatures to the Colorado Secretary of State by the August 8, 2016 deadline. However, on August 29, 2016, the Secretary of State announced that the proponents had failed to gather enough valid signatures to put Initiatives 75 and 78 on the November 2016 ballot. Notwithstanding the Colorado Secretary of State’s announcement on August 29, 2016, in the event that ballot initiatives or local or state restrictions or prohibitions are adopted in the future in areas where we conduct operations that impose more stringent limitations on the production and development of oil and natural gas, we may incur significant costs to comply with such requirements or may experience delays or curtailment in the pursuit of exploration, development, or production activities, and possibly be limited or precluded in the drilling of wells or in the amounts that we are ultimately able to produce from our reserves.
 
Activities on Federal Lands
 
Oil and natural gas exploration, development and production activities on federal lands, including American Indian lands and lands administered by the BLM, are subject to the National Environmental Policy Act (“NEPA”). NEPA requires federal agencies, including the BLM, to evaluate major agency actions having the potential to significantly impact the environment. In the course of such evaluations, an agency will prepare an Environmental Assessment that assesses the potential direct, indirect and cumulative impacts of a proposed project and, if necessary, will prepare a more detailed Environmental Impact Statement that may be made available for public review and comment. While we currently have no exploration, development and production activities on federal lands, our future exploration, development and production activities may include leasing of federal mineral interests, which will require the acquisition of governmental permits or authorizations that are subject to the requirements of NEPA. This process has the potential to delay or limit, or increase the cost of, the development of oil and natural gas projects. Authorizations under NEPA are also subject to protest, appeal or litigation, any or all of which may delay or halt projects. Moreover, depending on the mitigation strategies recommended in Environmental Assessments or Environmental Impact Statements, we could incur added costs, which may be substantial.
 
Endangered Species and Migratory Birds Considerations
 
The federal Endangered Species Act (“ESA”), and comparable state laws were established to protect endangered and threatened species. Pursuant to the ESA, if a species is listed as threatened or endangered, restrictions may be imposed on activities adversely affecting that species’ habitat. Similar protections are offered to migrating birds under the Migratory Bird Treaty Act. We may conduct operations on oil and natural gas leases in areas where certain species that are listed as threatened or endangered are known to exist and where other species, such as the sage grouse, that potentially could be listed as threatened or endangered under the ESA may exist. Moreover, as a result of a 2011 settlement agreement, the U.S. Fish and Wildlife Service (“FWS”) is required to make a determination on listing of numerous species as endangered or threatened under the FSA by no later than completion of the agency’s 2017 fiscal year. The identification or designation of previously unprotected species as threatened or endangered in areas where underlying property operations are conducted could cause us to incur increased costs arising from species protection measures, time delays or limitations on our exploration and production activities that could have an adverse impact on our ability to develop and produce reserves. If we were to have a portion of our leases designated as critical or suitable habitat, it could adversely impact the value of our leases.
 
 
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OSHA
 
We are subject to the requirements of the Occupational Safety and Health Administration (“OSHA”) and comparable state statutes whose purpose is to protect the health and safety of workers. In addition, the OSHA hazard communication standard, the Emergency Planning and Community Right-to-Know Act and comparable state statutes and any implementing regulations require that we organize and/or disclose information about hazardous materials used or produced in our operations and that this information be provided to employees, state and local governmental authorities and citizens.
 
Related Permits and Authorizations
 
Many environmental laws require us to obtain permits or other authorizations from state and/or federal agencies before initiating certain drilling, construction, production, operation, or other oil and natural gas activities, and to maintain these permits and compliance with their requirements for on-going operations. These permits are generally subject to protest, appeal, or litigation, which can in certain cases delay or halt projects and cease production or operation of wells, pipelines, and other 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 further discussion in “Part I” – “Item 1A. Risk Factors.”
 
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;
 
 
 
 
    
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.
 
Employees
 
At December 31, 2016, we employed 6 people and also utilize the services of independent contractors to perform various field and other services. Our future success will depend partially on our ability to attract, retain and motivate qualified personnel. We are not a party to any collective bargaining agreements and have not experienced any strikes or work stoppages. We consider our relations with our employees to be satisfactory.
 
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.
 
AFE or Authorization for Expenditures. A document that lays out proposed expenses for a particular project and authorizes an individual or group to spend a certain amount of money for that project.
 
 
 
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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.
 
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.
 
Henry Hub. A natural gas pipeline located in Erath, Louisiana that serves as the official delivery location for futures contracts on the NYMEX. The settlement prices at the Henry Hub are used as benchmarks for the entire North American natural gas market.
 
 
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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.
 
LOE or Lease operating expenses. The costs of maintaining and operating property and equipment on a producing oil and gas lease.
 
MBbl. One thousand barrels of crude oil or other liquid hydrocarbons.
 
MMBbl/d. One thousand barrels of crude oil or other liquid hydrocarbons per day.
 
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 or PUDs. 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.
 
 
 
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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.
 
WTI or West Texas Intermediate. A grade of crude oil used as a benchmark in oil pricing. This grade is described as light because of its relatively low density, and sweet because of its low sulfur content.
 
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.
 
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
 
Continuation of the recent declines, or further declines, in oil and, to a lesser extent, natural gas prices, will adversely affect our business, financial condition or results of operations and our ability to meet our capital expenditure obligations or targets and financial commitments.
 
The price we receive for our oil and, to a lesser extent, natural gas and NGLs, heavily influences our revenue, profitability, cash flows, liquidity, access to capital, present value and quality of our reserves, the nature and scale of our operations 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. In recent years, the markets for oil and natural gas have been volatile. These markets will likely continue to be volatile in the future. Further, oil prices and natural gas prices do not necessarily fluctuate in direct relation to each other. Because approximately 58% of our estimated proved reserves as of December 31, 2016 were oil, our financial results are more sensitive to movements in oil prices. Since mid-2014, the price of crude oil has significantly declined. As a result, we experienced significant decreases in crude oil revenues and recorded asset impairment charges driven by commodity price declines. A prolonged period of low market prices for oil and natural gas, like the current commodity price environment, or further declines in the market prices for oil and natural gas, will likely result in capital expenditures being further curtailed and will adversely affect our business, financial condition and liquidity and our ability to meet obligations, targets or financial commitments and could ultimately lead to restructuring or filing for bankruptcy, which would have a material adverse effect on our stock price and indebtedness. Additionally, lower oil and natural gas prices may cause further decline in our stock price. During the year ended December 31, 2016, the daily NYMEX WTI oil spot price ranged from a high of $54.01 per Bbl to a low of $26.19 per Bbl and the NYMEX natural gas Henry Hub spot price ranged from a high of $3.59 per MMBtu to a low of $1.73 per MMBtu.
 
 
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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 net losses of $101,731,000 from the date of inception (February 9, 2011) through December 31, 2016. 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 will be required 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.
 
We require significant additional financing to pay our outstanding liabilities and in the event we cannot raise additional funding or undertake a business combination transaction prior to the due date of such liabilities, we may be forced to sell assets, our debtors may foreclose on our assets or we may be forced to seek bankruptcy protection.
 
We currently have significant indebtedness and our debt agreements require us to use a significant portion of our revenues to pay down our outstanding debt. Due to the nature of oil and gas interests, i.e., that rates of production generally decline over time as oil and gas reserves are depleted, if we are unable to drill additional wells and develop our reserves, either because we are unable to raise sufficient funding for such development activities, or otherwise, or in the event we are unable to acquire additional operating properties, we believe that our revenues will continue to decline over time. Furthermore, in the event we are unable to raise additional funding in the future, we will not be able to participate in the drilling of additional wells, will not be able to complete other drilling and/or workover activities, and may not be able to make required payments on our outstanding liabilities. We are currently working to complete the GOM Merger, which we believe will provide us additional capital, but in the event we are unable to raise necessary funding in the future or complete a business combination or similar transaction in the near term, we may not be able to pay our debts (or make required amortization and principal payments on such debts) as they come due or continue to drill wells and/or participate in their drilling.
 
 
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If this were to happen, we may be forced to scale back our business plan, sell or liquidate assets to satisfy outstanding debts (or our creditors may undertake a foreclosure of such assets in order to satisfy amounts we owe to such creditors, with or without our assistance) and/or take other steps which may include seeking bankruptcy protection, all of which could result in the value of our outstanding securities declining in value or becoming worthless.
 
We may not be able to generate sufficient cash flow to meet our debt service and other obligations due to events beyond our control.
 
Our ability to generate cash flows from operations, to make scheduled payments on or refinance our indebtedness and to fund working capital needs and planned capital expenditures will depend on our future financial performance and our ability to generate cash in the future. Our future financial performance will be affected by a range of economic, financial, competitive, business and other factors that we cannot control, such as general economic, legislative, regulatory and financial conditions in our industry, the economy generally, the price of oil and other risks described below. A significant reduction in operating cash flows resulting from changes in economic, legislative or regulatory conditions, increased competition or other events beyond our control could increase the need for additional or alternative sources of liquidity and could have a material adverse effect on our business, financial condition, results of operations, prospects and our ability to service our debt and other obligations. If we are unable to service our indebtedness or to fund our other liquidity needs, we may be forced to adopt an alternative strategy that may include actions such as reducing or delaying capital expenditures, selling assets, restructuring or refinancing our indebtedness, seeking additional capital, or any combination of the foregoing. If we raise additional debt, it would increase our interest expense, leverage and our operating and financial costs. We cannot assure you that any of these alternative strategies could be affected on satisfactory terms, if at all, or that they would yield sufficient funds to make required payments on our indebtedness or to fund our other liquidity needs. Reducing or delaying capital expenditures or selling assets could delay future cash flows. In addition, the terms of existing or future debt agreements may restrict us from adopting any of these alternatives. We cannot assure you that our business will generate sufficient cash flows from operations or that future borrowings will be available in an amount sufficient to enable us to pay our indebtedness or to fund our other liquidity needs.
 
If for any reason we are unable to meet our debt service and repayment obligations, we would be in default under the terms of the agreements governing our indebtedness, which would allow our creditors at that time to declare all of our outstanding indebtedness to be due and payable. This would likely in turn trigger cross-acceleration or cross-default rights between our applicable debt agreements. Under these circumstances, our lenders could compel us to apply all of our available cash to repay our borrowings. In addition, the lenders under our credit facilities or other secured indebtedness could seek to foreclose on our assets that are their collateral. If the amounts outstanding under our indebtedness were to be accelerated, or were the subject of foreclosure actions, our assets may not be sufficient to repay in full the money owed to the lenders or to our other debt holders.
 
Our Tranche A Notes and Tranche B Notes include 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 certain assets from Continental on March 7, 2014, we entered into a senior debt facility pursuant to which we borrowed $34.5 million initially and have subsequently borrowed an additional $2.0 million (our “Tranche B Notes”) which amounts represent a significant amount of indebtedness. In addition, in connection with our Senior Debt Restructuring in May 2016, we borrowed an additional $6.4 million (our “Tranche A Notes,” and together with our Tranche B Notes, our “senior debt facility”), leaving approximately $18.0 million available for future drilling operations thereunder, subject to the terms and conditions of such facility which amounts also represent a significant amount of indebtedness.
 
 
 
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This senior 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 assets (except in the usual course of business), altering our organizational structure, winding up or liquidating, except in certain limited circumstances.
 
Our senior 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, with the Company required to pay all of its oil and gas revenues on a monthly basis to the lenders, subject to a monthly general and administrative expense (“G&A”) cap of $150,000 which is permitted to be applied against Company general and administrative expenses. See “Part I, Item 1. Business” — “Recent Developments” — “Senior Debt Restructuring”);
 
 
 
 
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 our senior 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, all revenues we do generate above $150,000 per month 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 these debt facilities. 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.
 
A portion of our Tranche B Notes, our junior debt held by RJC, and all of our Series A Convertible Preferred stock are held by entities whose parent company is in liquidation, which may have a negative impact on the Company and its business.
 
Each of GOM, RJC and GGE are owned by Partners Value Arbitrage Fund, LP, a New York based investment firm (“PPVAF”), and were formerly advised by Platinum Management (NY), LLC (“PM LLC”). PPVAF, and, by virtue of being owned by PPVAF, GGE, RJC, and GOM, are currently in the process of winding down and liquidating their assets through the oversight and control of a court-appointed liquidator in the Cayman Islands and are no longer advised by PM LLC or any of its affiliates. Additionally, the Company is aware that the former manager of PPVAF, PM LLC, is currently under investigation by the U.S. Securities and Exchange Commission and the Justice Department and that certain former executives have been indicted by the Justice Department, however, PM LLC and those certain executives no longer have any control over PPVAF, GOM, RJC or GGE, which entities are currently solely under the control of the Cayman Islands court-appointed liquidators. While the Company does not foresee that the confluence of these events or control of these entities by the court-appointed liquidator will disrupt or have a negative impact on the Company or its business, these extraordinary events may have a negative impact on the Company and its business, including, but not limited to, potential inability or delays in the Company’s efforts to restructure Company debt and equity controlled by the liquidator or consummate the GOM Merger.
  
 
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The repayment of our senior debt facility is secured by a security interest in all of our assets.
 
The repayment of our senior debt facility (which has an outstanding principal balance of approximately $48.95 million as of March 1, 2017 and provides us the option, pursuant to the terms of the debt facility, to borrow an additional approximately $18.0 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 senior 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.
 
The occurrence of an event of default under the notes sold in connection with our senior debt facility could have a material adverse effect on us and our financial condition.
 
The notes issued in connection with our senior 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.
 
We owe certain obligations to MIEJ under the New MIEJ Note, which is secured by a subordinated security interest in substantially all of our assets and is convertible into shares of our common stock subject to the terms of such New MIEJ Note, and may result in substantial dilution to existing shareholders.
 
The New MIEJ Note is subordinated in every way to the senior credit facility as well as to New Senior Lending (defined below); however, MIEJ has no control over our cash flow, nor is MIEJ’s consent required in connection with any disposition, sale, or use of any of our assets, provided that the requirements of the New MIEJ Note requiring the prepayment of interest, where applicable, as described below are followed. We have the right under the New MIEJ Note to enter into a loan, or a series of new loans or any other new non-equity investment or assumption of indebtedness (a “New Senior Lending”) which will be senior to the New MIEJ Note, without the prior consent of MIEJ, provided that, in addition to the approximately $35.5 million principal balance of the original PEDEVCO Senior Loan created in March 2014, the New Senior Lending is subject to a cap of an additional $60 million in the aggregate, such that the total lending, debt or similar investment under such cap shall not exceed $95 million in the aggregate (the “Senior Debt Cap”), with any portion of New Senior Lending in excess of the Senior Debt Cap advanced first to MIEJ until the New MIEJ Note is paid in full. The New MIEJ Note shall automatically, and without further consent from MIEJ, be subordinated in every way to any such New Senior Lending. Should we enter into any new financing transaction that results in raising New Senior Lending of at least $20 million in excess of the balance of the PEDEVCO Senior Loan, then MIEJ has a right to be paid all interest and fees that have accrued on the New MIEJ Note each and every time that a new financing transaction reaches or exceeds the $20 million threshold.
 
 
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The New MIEJ Note was originally due and payable on March 8, 2017, but is now due and payable on March 8, 2019, due to an automatic maturity date extension as a result of the May 2016 Senior Debt Restructuring, and with such date also subject to additional automatic extensions upon the occurrence of a Long-Term Financing or additional PEDEVCO Senior Lending Restructuring (each as defined below) (the “Maturity”). On a one-time basis, the PEDEVCO Senior Loan may be refinanced by a new loan (“Long-Term Financing”) by one or more third party replacement lenders (“Replacement Lenders”), and in such event we are required to undertake commercially reasonable best efforts to cause the Replacement Lenders to simultaneously refinance both the PEDEVCO Senior Loan and the New MIEJ Note as part of such Long-Term Financing. Despite such efforts, should the Replacement Lenders be unable or unwilling to include the New MIEJ Note in such financing, then the Long-Term Financing may proceed without including the New MIEJ Note, and the New MIEJ Note shall remain in place and shall be automatically subordinated, without further consent of MIEJ, to such Long-Term Financing. Furthermore, upon the occurrence of a Long-Term Financing, the Maturity of the New MIEJ Note is automatically extended, without further consent of MIEJ, to the same maturity date of the Long-Term Financing (the “Extended Maturity Date”), provided that the Extended Maturity Date may not exceed March 8, 2020. Additionally, upon the closing of such Long-Term Financing: (a) the Long-Term Financing is required to be subject to the Senior Debt Cap, (b) we are required to make commercially reasonable best efforts for the Long-Term Financing to include adequate reserves or other payment provisions whereby MIEJ is paid all interest and fees accrued on the New MIEJ Note commencing as of March 8, 2017 (and annually thereafter, until such time as the New MIEJ Note is paid in full), but in any event the Replacement Lenders are required to agree to allow for quarterly interest payments (starting March 31, 2017) of not less than 5% per annum on the outstanding balance of the New MIEJ Note, plus a one-time payment of accrued interest (not to exceed $500,000) as of March 31, 2017 (the “Subordinated Interest Payments”), and the remaining 5% interest shall continue to accrue, and (c) MIEJ has the Right of Conversion (defined below) commencing as of March 8, 2017, the original maturity date of the New MIEJ Note. If the PEDEVCO Senior Loan and/or New Senior Lending is not refinanced by Replacement Lenders, but is instead refinanced, restructured or extended by the existing Investors (a “PEDEVCO Senior Lending Restructuring”), the maturity of both the New MIEJ Note and the PEDEVCO Senior Loan may be extended to no later than March 8, 2019, without requiring the consent of MIEJ, provided that (i) any such extension of the maturity date of the New MIEJ Note past March 8, 2017 shall give MIEJ the Right of Conversion (described below) commencing on March 8, 2017, and (ii) such extension agreement shall include payment provisions whereby MIEJ shall be paid all interest and fees accrued on the New MIEJ Note as of March 8, 2018. The May 2016 Senior Debt Restructuring qualified as a PEDEVCO Senior Lending Restructuring and the issuance of the Tranche A Notes qualified as a New Senior Lending, the result of which the Maturity of the New MIEJ Note has been extended to March 8, 2019. The New MIEJ Note may be prepaid any time without penalty.
 
The New MIEJ Note has a conversion feature that provides that beginning March 8, 2017, MIEJ has the right, at its discretion, to have the outstanding balance of the New MIEJ Note plus any accrued and unpaid interest thereon converted in whole or in part into our common stock at a price (the “Conversion Price”) equal to 80% of the average closing price per share of our common stock over the then previous 60 days from the date MIEJ exercises its conversion right (subject to adjustment for stock splits, recapitalizations and the like)(such event, a “Right of Conversion”); provided, however, that in no event shall the Conversion Price be less than $0.30 per share (the “Floor Price”). The New MIEJ Note originally included a conversion limitation subject to us receiving shareholder approval under applicable NYSE MKT rules, but at the 2016 Annual Meeting held on December 28, 2016, the Company’s stockholders approved the full conversion of the New MIEJ Note and the New MIEJ Note is now fully convertible into our common stock in accordance with its terms.
 
If an event of default occurs under the New MIEJ Note, MIEJ may enforce their security interests over our assets (subject to the subordination rights in such note) which secure the repayment of such obligations, and we could be forced to curtail or abandon our current business plans and operations. If that were to happen, any investment in us could become worthless.
 
 
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The required interest and principal payments due under the New MIEJ Note may make it harder for us to refinance the New MIEJ Note or raise funding in the future, or could materially decrease the amount of cash we receive for our operations upon any refinancing or funding.
 
The issuance of common stock pursuant to the terms of the New MIEJ Note could result in immediate and substantial dilution to the interests of other stockholders.
 
A substantial part of our crude oil, natural gas and NGLs production is located in the D-J Basin, making us vulnerable to risks associated with operating primarily in a single geographic area. In addition, we have a large amount of proved reserves attributable to a small number of producing formations.
 
Our operations are focused primarily in the D-J Basin of Weld County, Colorado, which means our current producing properties and new drilling opportunities are geographically concentrated in that area. Because our operations are not as diversified geographically as many of our competitors, the success of our operations and our profitability may be disproportionately exposed to the effect of any regional events, including:
 
 
fluctuations in prices of crude oil, natural gas and NGLs produced from the wells in the area;
 
 
 
 
natural disasters such as the flooding that occurred in the area in September 2013;
 
 
 
 
restrictive governmental regulations; and
 
 
 
 
curtailment of production or interruption in the availability of gathering, processing or transportation infrastructure and services, and any resulting delays or interruptions of production from existing or planned new wells.
 
For example, bottlenecks in processing and transportation that have occurred in some recent periods in the D-J Basin have negatively affected our results of operations, and these adverse effects may be disproportionately severe to us compared to our more geographically diverse competitors. Similarly, the concentration of our assets within a small number of producing formations exposes us to risks, such as changes in field-wide rules that could adversely affect development activities or production relating to those formations. Such an event could have a material adverse effect on our results of operations and financial condition. In addition, in areas where exploration and production activities are increasing, as has been the case in recent years in the D-J Basin, the demand for, and cost of, drilling rigs, equipment, supplies, personnel and oilfield services increase. Shortages or the high cost of drilling rigs, equipment, supplies, personnel or oilfield services could delay or adversely affect our development and exploration operations or cause us to incur significant expenditures that are not provided for in our capital forecast, which could have a material adverse effect on our business, financial condition or results of operations.
 
 
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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.
 
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.
 
 
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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, the price of oil has fallen dramatically since mid-2014, with a high over $100 per barrel in June 2014 to lows below $30 per barrel in early 2016, in each case based on WTI prices, due to a combination of factors including increased U.S. supply, global economic concerns, the likely resumption of oil exports from Iran and OPEC’s decision not to reduce supply. Prices for natural gas and NGLs have experienced declines of similar magnitude. An extended period of continued lower oil prices, or additional price declines, will have further adverse effects on us. The prices we receive for our production, and the levels of our production, will continue to depend on numerous factors, including 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;
 
 
 
 
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.
 
 
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Future conditions might require us to make write-downs in our assets, which would adversely affect our balance sheet and results of operations.
 
We review our long-lived tangible and intangible assets for impairment whenever events or changes in circumstances indicate that the carrying value of an asset may not be recoverable. We also test our goodwill and indefinite-lived intangible assets for impairment at least annually on December 31 of each year, or when events or changes in the business environment indicate that the carrying value of a reporting unit may exceed its fair value. If conditions in any of the businesses in which we compete were to deteriorate, we could determine that certain of our assets were impaired and we would then be required to write-off all or a portion of our costs for such assets. Any such significant write-offs would adversely affect our balance sheet and results of operations.
 
The report of our independent registered public accounting firm expressed substantial doubt about the Company’s ability to continue as a going concern.
 
Our auditors indicated in their report on the Company’s consolidated audited financial statements for the fiscal year ended December 31, 2016 that conditions existed that could raise substantial doubt about our ability to continue as a going concern due in part to the current crude oil price environment and the fact that the Company had a working capital deficit and accumulated deficit at December 31, 2016. Uncertainties related to our continuation as a going concern may impair our ability to finance our operations through the sale of equity, incurring debt, or other financing alternatives and/or negatively affect our relationships with partners and service providers. Our ability to continue as a going concern will depend upon the availability and terms of future funding, our ability to grow our operations and integrate newly acquired assets and operations, our ability to acquire additional assets and operations, and our ability to improve operating margins and regain profitability. If we are unable to achieve these goals, our business would be jeopardized and the Company may not be able to continue. If we ceased operations, it is likely that all of our investors would lose their investment.
 
The Company will seek financing from other sources. Such financings may not be available or, if available, may not be on terms acceptable to the Company. Accordingly, the financial statements do not include any adjustments related to the recoverability of assets or classification of liabilities that might be necessary should the Company be unable to continue as a going concern. The ability of the Company to continue as a going concern is dependent upon its ability to raise capital to meet its obligations and attain profitable operations.
 
Declining general economic, business or industry conditions may have a material adverse effect on our results of operations, liquidity and financial condition.
 
Concerns over global economic conditions, energy costs, geopolitical issues, inflation, the availability and cost of credit, the United States mortgage market and a declining real estate market in the United States have contributed to increased economic uncertainty and diminished expectations for the global economy. These factors, combined with volatile prices of oil and natural gas, declining business and consumer confidence and increased unemployment, have precipitated an economic slowdown and a recession. Concerns about global economic growth have had a significant adverse impact on global financial markets and commodity prices. If the economic climate in the United States or abroad continues to deteriorate, demand for petroleum products could diminish, which could impact the price at which we can sell our oil, natural gas and natural gas liquids, affect the ability of our vendors, suppliers and customers to continue operations and ultimately adversely impact our results of operations, liquidity and financial condition.
 
 
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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.
 
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.
 
 
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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 record impairments of oil and gas properties that would reduce our shareholders’ equity.
 
The successful efforts method of accounting is used for oil and gas exploration and production activities. Under this method, all costs for development wells, support equipment and facilities, and proved mineral interests in oil and gas properties are capitalized. We review the carrying value of our long-lived assets annually or whenever events or changes in circumstances indicate that the historical cost-carrying value of an asset may no longer be appropriate. We assess the recoverability of the carrying value of the asset by estimating the future net undiscounted cash flows expected to result from the asset, including eventual disposition. If the future net undiscounted cash flows are less than the carrying value of the asset, an impairment loss is recorded equal to the difference between the asset’s carrying value and estimated fair value. This impairment does not impact cash flows from operating activities but does reduce earnings and our shareholders’ equity. The risk that we will be required to recognize impairments of our oil and gas properties increases during periods of low oil or gas prices. As a result, there is an increased risk that we will incur an impairment in 2017. In addition, impairments would occur if we were to experience sufficient downward adjustments to our estimated proved reserves or the present value of estimated future net revenues. An impairment recognized in one period may not be reversed in a subsequent period even if higher oil and gas prices increase the cost center ceiling applicable to the subsequent period. We have in the past and could in the future incur additional impairments of oil and gas properties.
 
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 D-J Basin Asset, also maintains a $10 million control of well 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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The threat and impact of terrorist attacks, cyber attacks or similar hostilities may adversely impact our operations.
 
We cannot assess the extent of either the threat or the potential impact of future terrorist attacks on the energy industry in general, and on us in particular, either in the short-term or in the long-term. Uncertainty surrounding such hostilities may affect our operations in unpredictable ways, including the possibility that infrastructure facilities, including pipelines and gathering systems, production facilities, processing plants and refineries, could be targets of, or indirect casualties of, an act of terror, a cyber attack or electronic security breach, or an act of war.
 
Failure to adequately protect critical data and technology systems could materially affect our operations.
 
Information technology solution failures, network disruptions and breaches of data security could disrupt our operations by causing delays or cancellation of customer orders, impeding processing of transactions and reporting financial results, resulting in the unintentional disclosure of customer, employee or our information, or damage to our reputation. There can be no assurance that a system failure or data security breach will not have a material adverse effect on our financial condition, results of operations or cash flows.
 
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 current operations are concentrated in the state of Colorado. 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 Colorado, natural disasters in Colorado, competition for equipment, services and materials available in Colorado and access to infrastructure and markets in Colorado.
 
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, including our planned combination with GOM, or not produce projected revenues associated with the future acquisitions 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.
 
 
 
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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 not be able to produce the projected revenues related to future acquisitions. There are many assumptions related to the projection of the revenues of future acquisitions including, but not limited to, drilling success, oil and natural gas prices, production decline curves and other data. If revenues from future acquisitions do not meet projections, this could adversely affect our business and financial condition.
 
Failure to complete the GOM Merger could negatively impact our stock price and future business and financial results.
 
If the GOM Merger is not completed, our ongoing business may be adversely affected and we would be subject to a number of risks, including the following:
 
 
we will not realize the benefits expected from the GOM Merger, including a potentially enhanced competitive and financial position, expansion of assets and therefore opportunities, and will instead be subject to all the risks we currently face as an independent company;
 
 
 
 
we may experience negative reactions from the financial markets and our partners and employees;
 
 
 
 
the GOM Merger Agreement places certain restrictions on the conduct of our business prior to the completion of the GOM Merger or the termination of the GOM Merger Agreement. Such restrictions, the waiver of which is subject to the consent of GOM, may prevent us from making certain acquisitions, taking certain other specified actions or otherwise pursuing business opportunities during the pendency of the GOM Merger; and
 
 
 
 
matters relating to the GOM Merger (including integration planning) may require substantial commitments of time and resources by our management, which would otherwise have been devoted to other opportunities that may have been beneficial to us as an independent company.
 
The GOM Merger Agreement may be terminated in accordance with its terms and the GOM Merger may not be completed.
 
The GOM Merger Agreement is subject to a number of conditions which must be fulfilled in order to complete the GOM Merger. Those conditions include (1) approval of the GOM Merger Agreement by the board of directors of the Company, the sole Manager and member of Merger Sub, the Board of Managers of GOM, and the members of GOM, (2) receipt of required regulatory approvals, (3) the absence of any law or order prohibiting the consummation of the GOM Merger, and (4) approval of the NYSE MKT for the issuance of the common stock and shares of common stock issuable upon conversion of the Series B Preferred to the members of GOM at closing. In addition, prior to the closing of the GOM Merger, either the Company or GOM may terminate the GOM Merger at any time.
 
Termination of the GOM Merger Agreement could negatively impact the Company.
 
In the event the GOM Merger Agreement is terminated, our business may have been adversely impacted by our failure to pursue other beneficial opportunities due to the focus of management on the GOM Merger, and the market price of our common stock might decline to the extent that the current market price reflects a market assumption that the GOM Merger will be completed. If the GOM Merger Agreement is terminated and our board of directors seeks another transaction or business combination, our stockholders cannot be certain that we will be able to find a party willing to offer equivalent or more attractive consideration than the consideration provided for by the GOM Merger.
 
 
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The closing of the GOM merger is subject to various risks and closing conditions and such planned transaction may not occur on a timely basis, if at all.
 
The GOM Merger is subject to various closing conditions as set forth in greater detail in the GOM Merger Agreement. Additionally, the Company is aware that the parent company of GOM has experienced significant liquidity problems, is currently under investigation by the U.S. Securities and Exchange Commission and the Justice Department, is currently under the control of a court-appointed liquidator that is taking steps to liquidate its assets, including the assets subject to the GOM Merger, has filed for Bankruptcy protection, and certain of its assets are also subject to separate Bankruptcy proceedings initiated by certain creditors. In addition, to the extent GOM’s assets are encumbered by debt, and such debtholders do not agree to the assumption of the debt by the Company, or to otherwise refinance or restructure such debt as needed to consummate the GOM Merger, GOM and the Company may not be able to consummate the GOM Merger. Any one of these circumstances may delay the closing of the GOM Merger or prevent certain closing conditions associated therewith from occurring, which in turn could prevent the merger from closing.
 
We will be subject to business uncertainties and contractual restrictions while the GOM Merger is pending.
 
Uncertainty about the effect of the GOM Merger on employees and partners may have an adverse effect on us. These uncertainties may impair our ability to attract, retain and motivate key personnel until the GOM Merger is completed, and could cause partners and others that deal with us to seek to change existing business relationships, cease doing business with us or cause potential new partners to delay doing business with us until the GOM Merger has been successfully completed. Retention of certain employees may be challenging during the pendency of the GOM Merger, as certain employees may experience uncertainty about their future roles or compensation structure. If key employees depart because of issues relating to the uncertainty and difficulty of integration or a desire not to remain with the business, our business following the GOM Merger could be negatively impacted. In addition, the GOM Merger Agreement restricts us from making certain acquisitions and taking other specified actions until the GOM Merger is completed without the consent of GOM. These restrictions may prevent us from pursuing attractive business opportunities that may arise prior to the completion of the GOM Merger.
 
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 increases 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 Tenet Advisory Group, 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.
 
 
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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 retained Tenet Advisory Group, LLC as a key advisor for our operations, exploration and drilling efforts. 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.
 
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.
 
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.
 
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.
 
 
 
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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;
 
 
 
 
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.
 
 
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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 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.
 
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.
 
Changes in the legal and regulatory environment governing the oil and natural gas industry, particularly changes in the current Colorado forced pooling system, could have a material adverse effect on our business.
 
 Our business is subject to various forms of government regulation, including laws and regulations concerning the location, spacing and permitting of the oil and natural gas wells we drill, among other matters. In particular, our business utilizes a methodology available in Colorado known as “forced pooling,” which refers to the ability of a holder of an oil and natural gas interest in a particular prospective drilling spacing unit to apply to the Colorado Oil & Gas Conservation Commission (the “COGCC”) for an order forcing all other holders of oil and natural gas interests in such area into a common pool for purposes of developing that drilling spacing unit. This methodology is especially important for our operations in the Greeley area, where there are many interest holders. Changes in the legal and regulatory environment governing our industry, particularly any changes to Colorado forced pooling procedures that make forced pooling more difficult to accomplish, could result in increased compliance costs and adversely affect our business, financial condition and results of operations.
 
 
 
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SEC rules could limit our ability to book additional proved undeveloped reserves (“PUDs”) in the future.
 
SEC rules require that, subject to limited exceptions, PUDs may only be booked if they relate to wells scheduled to be drilled within five years after the date of booking. This requirement has limited and may continue to limit our ability to book additional PUDs as we pursue our drilling program. Moreover, we may be required to write down our PUDs if we do not drill or plan on delaying those wells within the required five-year timeframe.
 
We are subject to stringent federal, state and local laws and regulations related to environmental and occupational health and safety issues that could adversely affect the cost, manner or feasibility of conducting our operations or expose us to significant liabilities.
 
Our operations are subject to stringent federal, state and local laws and regulations governing occupational safety and health aspects of our operations, the discharge of materials into the environment and environmental protection. These laws and regulations may impose numerous obligations applicable to our operations including the acquisition of a permit before conducting drilling and other regulated activities; the restriction of types, quantities and concentration of materials that may be released into the environment; the limitation or prohibition of drilling activities on certain lands lying within wilderness, wetlands and other protected areas; the application of specific health and safety criteria addressing worker protection; and the imposition of substantial liabilities for pollution resulting from our operations. Numerous governmental authorities, such as the EPA and analogous state agencies have the power to enforce compliance with these laws and regulations and the permits issued under them. Such enforcement actions often involve taking difficult and costly compliance measures or corrective actions. Failure to comply with these laws and regulations may result in the assessment of sanctions, including administrative, civil or criminal penalties, the imposition of investigatory or remedial obligations, and the issuance of orders limiting or prohibiting some or all of our operations. In addition, we may experience delays in obtaining or be unable to obtain required permits, which may delay or interrupt our operations or specific projects and limit our growth and revenue.
 
There is inherent risk of incurring significant environmental costs and liabilities in the performance of our operations due to our handling of petroleum hydrocarbons and other hazardous substances and wastes, as a result of air emissions and wastewater discharges related to our operations, and because of historical operations and waste disposal practices at our leased and owned properties. Spills or other releases of regulated substances, including such spills and releases that occur in the future, could expose us to material losses, expenditures and liabilities under applicable environmental laws and regulations. Under certain of such laws and regulations, we could be subject to strict, joint and several liability for the removal or remediation of previously released materials or property contamination, regardless of whether we were responsible for the release or contamination and even if our operations met previous standards in the industry at the time they were conducted. We may not be able to recover some or any of these costs from insurance. Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent or costly well drilling, construction, completion or water management activities, air emissions control or waste handling, storage, transport, disposal or cleanup requirements could require us to make significant expenditures to attain and maintain compliance and may otherwise have a material adverse effect on our results of operations, competitive position or financial condition. For example, on October 1, 2015, the EPA issued a final rule under the Clean Air Act, lowering the National Ambient Air Quality Standard (“NAAQS”) for ground-level ozone from the current standard of 75 parts per billion (“ppb”) for the current 8-hour primary and secondary ozone standards to 70 ppb for both standards. States are expected to implement more stringent requirements as a result of this new final rule, which could apply to our operations. Compliance with this more stringent standard and other environmental regulations could delay or prohibit our ability to obtain permits for operations or require us to install additional pollution control equipment, the costs of which could be significant. Please read “Part I” – “Item 1. Business” — “Regulation of the Oil and Gas Industry” and “Regulation of Environmental and Occupational Safety and Health Matters” for a further description of the laws and regulations that affect us.
 
 
 
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Should we fail to comply with all applicable regulatory agency administered statutes, rules, regulations and orders, we could be subject to substantial penalties and fines.
 
Under the Energy Policy Act of 2005 (“EPAct 2005”), the Federal Energy Regulatory Commission (the “FERC”) has civil penalty authority under the Natural Gas Act of 1938 (“NGA”) to impose penalties for current violations of up to $1 million per day for each violation. The FERC may also impose administrative and criminal remedies and disgorgement of profits associated with any violation. While our operations have not been regulated by FERC as a natural gas company under the NGA, FERC has adopted regulations that may subject certain of our otherwise non-FERC jurisdictional facilities to FERC annual reporting requirements. We also must comply with the anti-market manipulation rules enforced by FERC. Additional rules and regulations pertaining to those and other matters may be considered or adopted by FERC from time to time. Additionally, the Federal Trade Commission (“FTC”) has regulations intended to prohibit market manipulation in the petroleum industry with authority to fine violators of the regulations civil penalties of up to $1 million per day and the Commodity Futures Trading Commission (“CFTC”) prohibits market manipulation in the markets regulated by the CFTC, including similar anti-manipulation authority with respect to oil swaps and futures contracts as that granted to the CFTC with respect to oil purchases and sales. The CFTC rules subject violators to a civil penalty of up to the greater of $1 million or triple the monetary gain to the person for each violation. Failure to comply with those regulations in the future could subject us to civil penalty liability, as described in “Part I” – “Item 1. Business” — “Regulation of the Oil and Gas Industry”.
 
Climate change laws and regulations restricting emissions of greenhouse gases could result in increased operating costs and reduced demand for the oil, natural gas and NGL that we produce while potential physical effects of climate change could disrupt our production and cause us to incur significant costs in preparing for or responding to those effects.
 
In response to findings that emissions of carbon dioxide, methane and other greenhouse gases (“GHGs”) present an endangerment to public health and the environment, the EPA has adopted regulations under existing provisions of the Clean Air Act that, among other things, establish Prevention of Significant Deterioration (“PSD”) construction and Title V operating permit reviews for GHG emissions from certain large stationary sources that are already potential major sources of certain principal, or criteria, pollutant emissions. Facilities required to obtain PSD permits for their GHG emissions also will be required to meet “best available control technology” standards that typically will be established by state agencies. In addition, the EPA has adopted rules requiring the monitoring and annual reporting of GHG emissions from specified large GHG emission sources in the United States, including certain onshore oil and natural gas production sources, which include certain of our operations.
 
While Congress has from time to time considered legislation to reduce emissions of GHGs, there has not been significant activity in the form of adopted legislation to reduce GHG emissions at the federal level in recent years. In the absence of such federal climate legislation, a number of state and regional efforts have emerged that are aimed at tracking and/or reducing GHG emissions by means of cap and trade programs that typically require major sources of GHG emissions to acquire and surrender emission allowances in return for emitting those GHGs. In addition, the United States is one of almost 200 nations that, in December 2015, agreed to an international climate change agreement in Paris, France (“Paris Agreement”) that calls for countries to set their own GHG emissions targets and be transparent about the measures each country will use to achieve its GHG emissions targets. Although it is not possible at this time to predict how new laws or regulations in the United States or any legal requirements imposed following the United States’ agreeing to the Paris Agreement that may be adopted or issued to address GHG emissions would impact our business, any such future laws, regulations or legal requirements imposing reporting or permitting obligations on, or limiting emissions of GHGs from, our equipment and operations could require us to incur costs to reduce emissions of GHGs associated with our operations as well as delays or restrictions in our ability to permit GHG emissions from new or modified sources. In addition, substantial limitations on GHG emissions could adversely affect demand for the oil, natural gas and NGL we produce. Finally, it should be noted that increasing concentrations of GHGs 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.
 
 
 
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Federal, state and local legislative and regulatory initiatives relating to hydraulic fracturing as well as governmental reviews of such activities could result in increased costs and additional operating restrictions or delays in the completion of oil and natural gas wells and adversely affect our production.
 
Hydraulic fracturing is an important and common practice that is used to stimulate production of natural gas and/or oil from dense subsurface rock formations. We regularly use hydraulic fracturing as part of our operations. Hydraulic fracturing involves the injection of water, sand or alternative proppant and chemicals under pressure into targeted geological formations to fracture the surrounding rock and stimulate production.
 
Hydraulic fracturing is typically regulated by state oil and natural gas commissions. However, several federal agencies have asserted regulatory authority over certain aspects of the process. For example, the EPA has published final Clean Air Act (“CAA”) regulations in 2012 and, more recently, in June 2016 governing performance standards, including standards for the capture of air emissions released during oil and natural gas hydraulic fracturing, leak detection, and permitting; published on June 28, 2016 an effluent limited guideline final rule prohibiting the discharge of wastewater from onshore unconventional oil and natural gas extraction facilities to publicly owned wastewater treatment plants; and issued in 2014 a prepublication of its Advance Notice of Proposed Rulemaking regarding Toxic Substances Control Act reporting of the chemical substances and mixtures used in hydraulic fracturing. Also, the federal Bureau of Land Management (“BLM”) published a final rule in March 2015, establishing stringent standards relating to hydraulic fracturing on federal and American Indian lands, including well casing and wastewater storage requirements and an obligation for exploration and production operators to disclose what chemicals they are using in fracturing activities; however, on June 21, 2016, a Wyoming federal judge struck down this final rule, finding that the BLM lacked congressional authority to promulgate the rule. Also, from time to time, legislation has been introduced, but not enacted, in Congress to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the fracturing process. In the event that a new, federal level of legal restrictions relating to the hydraulic-fracturing process is adopted in areas where we operate, we may incur additional costs to comply with such federal requirements that may be significant in nature, and also could become subject to additional permitting requirements and experience added delays or curtailment in the pursuit of exploration, development, or production activities.
 
 Certain governmental reviews are either underway or being proposed that focus on environmental aspects of hydraulic fracturing practices. The White House Council on Environmental Quality is coordinating an administration-wide review of hydraulic fracturing practices. Additionally, in December 2016, the EPA released its final report on the potential impacts of hydraulic fracturing on drinking water resources. The EPA report concluded that hydraulic fracturing activities have not led to widespread, systemic impacts on drinking water resources in the United States, although there are above and below ground mechanisms by which hydraulic fracturing activities have the potential to impact drinking water resources. Other governmental agencies, including the United States Department of Energy and the United States Department of the Interior, are evaluating various other aspects of hydraulic fracturing. These ongoing or proposed studies could spur initiatives to further regulate hydraulic fracturing under the federal SDWA or other regulatory mechanisms. 
 
 At the state level, Colorado, where we conduct operations, is among the states that has adopted, and other states are considering adopting, regulations that impose new or more stringent permitting, disclosure or well-construction requirements on hydraulic fracturing operations. In addition to state laws, local land use restrictions may restrict drilling in general and/or hydraulic fracturing in particular. For example, several cities in Colorado passed temporary or permanent moratoria on hydraulic fracturing within their respective cities’ limits in 2012-2013 but, since that time, in response to lawsuits brought by an industry trade group, the Colorado Oil and Gas Association, local district courts struck down the ordinances for certain of those Colorado cities in 2014, primarily on the basis that state law preempts local bans on hydraulic fracturing. The cities of Fort Collins and Longmont, among those cities whose ordinances were struck down in 2014, appealed their decisions to the Colorado Supreme Court, but on May 2, 2016, the state supreme court upheld the lower court rulings in those two cases, holding that a five-year moratorium on hydraulic fracturing adopted by Fort Collins and a ban on fracturing adopted by Longmont were pre-empted by state law and, therefore, unenforceable. Another suit brought by the Colorado trade group against one other city, Broomfield, who had adopted a moratorium on fracturing, has been on hold pending the outcome of the Colorado Supreme Court ruling in the Fort Collins and Longmont cases. Notwithstanding attempts at the local level to prohibit hydraulic fracturing, there exists the opportunity for cities to adopt local ordinances allowing hydraulic fracturing activities within their jurisdictions but regulating the time, place and manner of those activities.
 
 
 
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In addition, certain interest groups in Colorado opposed to oil and natural gas development generally, and hydraulic fracturing in particular, have from time to time advanced various options for ballot initiatives aimed at significantly limiting or preventing oil and natural gas development. In response to such initiatives, the Governor of Colorado created a Task Force on State and Local Regulation of Oil and Gas Operations (“Task Force”) in September 2014 to make recommendations to the state legislature regarding the responsible development of Colorado’s oil and gas resources. In February 2015, the Task Force made nine non-binding recommendations to the Governor that will require legislative or regulatory action to be implemented. Among other things, the recommendations received from the Task Force would require pursuit of state rulemaking targeting increased collaborative efforts between oil and natural gas operators and local governments regarding large-scale oil and natural gas facilities in defined “urban mitigation areas”; operator registration with local government designees and possible advance notice of future oil and natural gas drilling and production facility locations that would be integrated into the local comprehensive planning process; development of enhanced local governmental designee roles and functions to more effectively serve as liaisons between industry, residents and local officials; increased staffing levels at the state environmental and oil and natural gas agencies; establishing an oil and natural gas information clearinghouse; establishing a working group to investigate ways to reduce oil and natural gas vehicular traffic on roadways; pursuit of state air emissions rules including methane emissions capture rules; and establishing a compliance assistance program to assist oil and natural gas operators in complying with applicable rules. On January 25, 2016, two of the recommendations, regarding the collaboration of local governments, the COGCC and oil and natural gas operators in the siting of large scale oil and natural gas facilities in defined urban mitigation areas and long-term planning for including future oil and natural gas development in local comprehensive planning processes, were approved by the COGCC as new rules. It is possible that the COGCC could elect to pursue one or more of the remaining Task Force recommendations or the Colorado state legislature could seek to adopt new policies or legislation relating to oil and natural gas operations, including measures that would give local governments in Colorado greater authority to limit hydraulic fracturing and other oil and natural gas operations or require greater distances between well sites and occupied structures. In addition, it is possible that notwithstanding the recommendations made by the Task Force, certain interest groups in Colorado or even members of the Colorado state legislature may seek to pursue ballot initiatives in the future and/or legislation that may or may not coincide with the Task Force’s recommendations, including, among other things, pursuit of initiatives or legislation for changes in state law that would allow local governments to ban hydraulic fracturing in Colorado. 
 
In the event that ballot initiatives or local or state restrictions or prohibitions are adopted in areas where we conduct operations, including the Wattenberg Field in Colorado, that impose more stringent limitations on the production and development of oil and natural gas, we may incur significant costs to comply with such requirements or may experience delays or curtailment in the pursuit of exploration, development, or production activities, and possibly be limited or precluded in the drilling of wells or in the amounts that we are ultimately able to produce from our reserves. Any such increased costs, delays, cessations, restrictions or prohibitions could have a material adverse effect on our business, prospects, results of operations, financial condition, and liquidity.
 
Please read “Part I” – “Item 1. Business” — “Regulation of the Oil and Gas Industry” and “Regulation of Environmental and Occupational Safety and Health Matters” for a further description of the laws and regulations that affect us.
 

 
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Ballot initiatives that would impose more stringent restrictions for new oil and natural gas wells and related facilities may serve to limit future oil and natural gas exploration and production activities and could have a material adverse effect on our results of operations, financial position and business.
 
 Proponents of legal requirements imposing more stringent restrictions on oil and gas exploration and production activities in Colorado sought to include on the November 2016 ballot certain ballot initiatives that, if approved, would have allowed revisions to the state constitution in a manner that would have made such exploration and production activities in the state more difficult in the future. Among the ballot initiatives pursued in 2016 were ballot initiative Number 75 (“Initiative 75”), which sought to authorize local governmental to control oil and natural gas development in Colorado that could have resulted in the imposition of more stringent requirements than currently implemented under state law, and ballot initiative Number 78 (“Initiative 78”), which proposed a much more stringent 2,500-foot mandatory setback between an oil and natural gas development facility (including oil and natural gas wells, production and processing equipment and pits) and specified occupied structures and areas of special concern. Changes sought under these ballot initiatives would have applied to new oil and gas development facilities in Colorado. Proponents of these measures collected signatures for placing Initiatives 75 and 78 on the November 2016 ballot and submitted those signatures to the Colorado Secretary of State by the August 8, 2016 deadline. However, on August 29, 2016, the Secretary of State announced that the proponents had failed to gather enough valid signatures to put Initiatives 75 and 78 on the November 2016 ballot. Notwithstanding the Colorado Secretary of State’s announcement on August 29, 2016, in the event that ballot initiatives or local or state restrictions or prohibitions are adopted in the future in areas where we conduct operations that impose more stringent limitations on the production and development of oil and natural gas, we may incur significant costs to comply with such requirements or may experience delays or curtailment in the pursuit of exploration, development, or production activities, and possibly be limited or precluded in the drilling of wells or in the amounts that we are ultimately able to produce from our reserves.
 
Recently announced rules regulating methane emissions from oil and natural gas operations could cause us to incur increased capital expenditures and operating costs or delays in production of oil and natural gas, which could have a material adverse effect on our business.
 
On June 3, 2016, the EPA published final rules establishing new air emission controls for methane emissions from certain new, modified or reconstructed equipment and processes in the oil and natural gas source category, including production, processing, transmission and storage activities, as part of an overall effort to reduce methane emissions in the oil and natural gas source category by up to 45% from 2012 levels by the year 2025. The EPA’s final rules include New Source Performance Standards (“NSPS”) to limit methane emissions from equipment and processes across the oil and natural gas source category. The rules also extend limitations on volatile organic compound (“VOC”) emissions to sources that were unregulated under the previous NSPS at Subpart OOOO. Affected methane and VOC sources include hydraulically fractured (or re-fractured) oil and natural gas well completions, fugitive emissions from well sites and compressors, and pneumatic pumps. The new methane and VOC standards require the implementation of the best system of emission reduction to achieve these emission reductions, mirroring the existing VOC standards under Subpart OOOO. These rules could require a number of modifications to our operations, including the installation of new equipment to control methane and VOC emissions from certain hydraulic fracturing wells, which could result in significant costs, including increased capital expenditures and operating costs, and could adversely impact or delay oil and natural gas production activities, which could have a material adverse effect on our business.
 
Restrictions on drilling activities intended to protect certain species of wildlife may adversely affect our ability to conduct drilling activities areas where we operate.
 
 Oil and natural gas operations in our operating areas may 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 or 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. The 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 on our exploration and production activities that could have a material adverse impact on our ability to develop and produce our reserves.
 
 
 
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As a result of future legislation, certain U.S. federal income tax deductions currently available with respect to oil and gas exploration and development may be eliminated and our production may be subject to the imposition of new U.S. federal taxes.
 
The U.S. President’s Fiscal Year 2017 Budget Proposal and legislation introduced in a prior session of Congress includes proposals that, if enacted into law, would eliminate certain key U.S. federal income tax provisions currently available to oil and gas exploration and production companies or potentially make our operations subject to the imposition of new U.S. federal taxes. These changes include, but are not limited to, (i) the repeal of the percentage depletion allowance for oil and gas properties, (ii) the elimination of current deductions for intangible drilling and development costs, (iii) the elimination of the deduction for certain domestic production activities, (iv) an extension of the amortization period for certain geological and geophysical expenditures and (v) imposition of a $10.25 per barrel fee on oil, to be paid by oil companies (but the budget does not describe where and how such a fee would be collected). It is unclear whether these or similar changes will be enacted and, if enacted, how soon any such changes could become effective. The passage of any legislation as a result of these proposals or any similar changes in U.S. federal income tax laws could eliminate or postpone certain tax deductions that are currently available with respect to oil and gas exploration and development, and any such change, as well as any changes to or the imposition of new U.S. federal, state or local taxes (including the imposition of, or increase in production, severance or similar taxes), could increase the cost of exploration and development of oil and gas resources, which would negatively affect our financial condition and results of operations.
 
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 D-J Basin in Weld County, Colorado, 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. 
 
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. The loss of substantial leases could have a material adverse effect on our assets, operations, revenues and cash flow and could cause the value of our securities to decline in value.
 
 
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Competition for 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 eastern Colorado, could materially and adversely affect our operations and the timeliness of executing our development plans within our budget.
 
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.
 
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.
 
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). 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 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.
 
Michael L. Peterson, our President and Chief Executive Officer, and Clark R. Moore, our Executive Vice President, General Counsel and Secretary, hold various other management positions with privately-held companies not involved in the oil and gas industry. We believe these positions require only an immaterial amount of each officers’ time and will not conflict with their roles or responsibilities with our company. If any of these companies enter into one or more transactions with our company, or if the officers’ position with any such company requires significantly more time than currently anticipated, potential conflicts of interests could arise from the officers performing services for us and these other entities.
 
Downturns and volatility in global economies and commodity and credit markets could materially adversely affect our business, results of operations and financial condition.
 
Our results of operations are materially affected by the conditions of the global economies and the credit, commodities and stock markets. Among other things, we may be adversely impacted if consumers of oil and gas are not able to access sufficient capital to continue to operate their businesses or to operate them at prior levels. A decline in consumer confidence or changing patterns in the availability and use of disposable income by consumers can negatively affect the demand for oil and gas and as a result our results of operations.
 
Improvements in or new discoveries of alternative energy technologies could have a material adverse effect on our financial condition and results of operations.
 
Because our operations depend on the demand for oil and used oil, any improvement in or new discoveries of alternative energy technologies (such as wind, solar, geothermal, fuel cells and biofuels) that increase the use of alternative forms of energy and reduce the demand for oil, gas and oil and gas related products could have a material adverse impact on our business, financial condition and results of operations.
 
Competition due to advances in renewable fuels may lessen the demand for our products and negatively impact our profitability.
 
Alternatives to petroleum-based products and production methods are continually under development. For example, a number of automotive, industrial and power generation manufacturers are developing alternative clean power systems using fuel cells or clean-burning gaseous fuels that may address increasing worldwide energy costs, the long-term availability of petroleum reserves and environmental concerns, which if successful could lower the demand for oil and gas. If these non-petroleum based products and oil alternatives continue to expand and gain broad acceptance such that the overall demand for oil and gas is decreased it could have an adverse effect on our operations and the value of our assets.
 
Currently pending or future litigation or governmental proceedings could result in material adverse consequences, including judgments or settlements.
 
From time to time, we are involved in lawsuits, regulatory inquiries and may be involved in governmental and other legal proceedings arising out of the ordinary course of our business. Many of these matters raise difficult and complicated factual and legal issues and are subject to uncertainties and complexities. The timing of the final resolutions to these types of matters is often uncertain. Additionally, the possible outcomes or resolutions to these matters could include adverse judgments or settlements, either of which could require substantial payments, adversely affecting our results of operations and liquidity.
 
 
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We may be subject in the normal course of business to judicial, administrative or other third-party proceedings that could interrupt or limit our operations, require expensive remediation, result in adverse judgments, settlements or fines and create negative publicity.
 
Governmental agencies may, among other things, impose fines or penalties on us relating to the conduct of our business, attempt to revoke or deny renewal of our operating permits, franchises or licenses for violations or alleged violations of environmental laws or regulations or as a result of third-party challenges, require us to install additional pollution control equipment or require us to remediate potential environmental problems relating to any real property that we or our predecessors ever owned, leased or operated or any waste that we or our predecessors ever collected, transported, disposed of or stored. Individuals, citizens groups, trade associations or environmental activists may also bring actions against us in connection with our operations that could interrupt or limit the scope of our business. Any adverse outcome in such proceedings could harm our operations and financial results and create negative publicity, which could damage our reputation, competitive position and stock price. We may also be required to take corrective actions, including, but not limited to, installing additional equipment, which could require us to make substantial capital expenditures. We could also be required to indemnify our employees in connection with any expenses or liabilities that they may incur individually in connection with regulatory action against us. These could result in a material adverse effect on our prospects, business, financial condition and our results of operations.
 
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.
 
 
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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.
 
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 bridge notes in the aggregate amount of $475,000 in principal and $48,000 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 by 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.
 
In addition, that certain Amended and Restated Secured Subordinated Promissory Note, in the principal amount $4.925 million, dated February 19, 2015, issued by the Company to MIE Jurassic Energy Corporation (“MIEJ”), provides MIEJ the right, beginning March 8, 2017, to convert the outstanding balance plus accrued and unpaid interest thereon, into common stock of the Company at a price equal to 80% of the average closing price per share of common stock over the then previous 60 days from the date MIEJ exercises its conversion right, subject to a floor price of $0.30 per share of common stock. Any such issuances of common stock will result in immediate and substantial dilution to the interests of other stockholders.
 
 
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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 bridge notes and New MIEJ Note. The convertible bridge 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”, at a discount to the trading price of our common stock, subject to a floor of $0.50 per share, and the New MIEJ Note is convertible into shares of common stock as described in the same risk factor after March 8, 2017 at a discount to the trading price of our common stock, subject to a floor of $0.30 per share and other restrictions. 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 bridge notes and New MIEJ Note 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.
 
Because we are a small company, the requirements of being a public company, including compliance with the reporting requirements of 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.
 
 
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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. 333-214415) that we filed with the Securities and Exchange Commission on December 20, 2016, and which was declared effective on January 17, 2017. To date, an aggregate of approximately $17.5 million in securities have been sold by us under the prior Form S-3 which the December 2016 Form S-3 replaced, leaving approximately $82.5 million 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. We have also entered into an At Market Issuance Sales Agreement, or sales agreement, with National Securities Corporation, or NSC, relating to up to $2.0 million of shares of our common stock which may be offered from time to time in “at the market offerings” and filed a final prospectus in connection with such offering with the SEC, provided that to date, we have not sold any securities under the At Market Issuance Sales Agreement or the prospectus associated therewith. Additionally, if our existing shareholders sell, or indicate an intention 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, 2016, there were outstanding stock options to purchase approximately 5,187,223 shares of our common stock and outstanding warrants to purchase approximately 12,566,079 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 registration statements with the SEC on Form S-8 providing for the registration of an aggregate of approximately 16,349,138 shares of our common stock, issued, 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.
 
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.
 
 
 
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Seven of our directors and executive officers own approximately 17.5% of our common stock, and three of our major shareholders own approximately 17.6% of our common stock, which may give them influence over important corporate matters in which their interests are different from your interests.
 
Seven of our directors and executive officers beneficially own approximately 17.5% of our outstanding shares of common stock, and our largest three non-director or officer shareholders own approximately 17.6% of our outstanding voting shares of common stock and Series A Preferred Stock (excluding exercise of warrants and options and other convertible securities held thereby) based on a total of 54,997,742 shares of common stock and Series A Preferred Stock outstanding as of March 22, 2017. 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.
 
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. To date our board of directors has authorized Series A Convertible Preferred Stock, the rights and preferences associated therewith, and risks related to such preferred stock, is described in greater detail under “Risks Related to Our Series A Convertible Preferred Stock”. We have also agreed to issue Series B Preferred stock in the event the GOM Merger closes as described in greater detail above under “Item 1. Business” – “Business Overview” — “Recent Developments” – “GOM Holdings, LLC Merger Agreement”.
 
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.
 
 
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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.
 
We are subject to the Continued Listing Criteria of the NYSE MKT and our failure to satisfy these criteria may result in delisting of our common stock.
 
Our common stock is currently listed on the NYSE MKT. In order to maintain this listing, we must maintain certain share prices, financial and share distribution targets, including maintaining a minimum amount of shareholders’ equity and a minimum number of public shareholders. In addition to these objective standards, the NYSE MKT may delist the securities of any issuer if, in its opinion, the issuer’s financial condition and/or operating results appear unsatisfactory; if it appears that the extent of public distribution or the aggregate market value of the security has become so reduced as to make continued listing on the NYSE MKT inadvisable; if the issuer sells or disposes of principal operating assets or ceases to be an operating company; if an issuer fails to comply with the NYSE MKT’s listing requirements; if an issuer’s common stock sells at what the NYSE MKT considers a “low selling price” (generally trading below $0.20 per share for an extended period of time) and the issuer fails to correct this via a reverse split of shares after notification by the NYSE MKT (provided that issuers can also be delisted if any shares of the issuer trade below $0.06 per share); or if any other event occurs or any condition exists which makes continued listing on the NYSE MKT, in its opinion, inadvisable.
 
If the NYSE MKT delists our common stock, investors may face material adverse consequences, including, but not limited to, a lack of trading market for our securities, reduced liquidity, decreased analyst coverage of our securities, and an inability for us to obtain additional financing to fund our operations.
 
 
 
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We are required to complete a reverse stock split of our issued and outstanding common stock prior to May 3, 2017, in order to continue to trade our common stock on the NYSE MKT.
 
On November 3, 2016, we were notified by the NYSE MKT that our common stock had been selling for a low price per share (i.e., under $0.20 per share), for a substantial period of time, and that our continued listing on the NYSE MKT was predicated on us completing a reverse stock split of our issued and outstanding common stock by May 3, 2017. Pursuant to the rules of the NYSE MKT, if an issuer’s common stock sells at what the NYSE MKT considers a “low selling price” (generally trading below $0.20 per share for an extended period of time) and the issuer fails to correct this via a reverse split after notification by the NYSE MKT (provided that issuers can also be delisted if any shares of the issuer trade below $0.06 per share), the NYSE MKT may delist the securities of such issuer. The NYSE MKT also advised us that we were ‘below compliance’ with applicable NYSE MKT listing standards due to the low trading price of our common stock and that a “.BC” indicator would be affixed to our trading symbol until such time as we regained compliance with the NYSE MKT’s listing standards. While the Company obtained stockholder approval for a reverse stock split at our 2016 annual meeting of stockholders on December 28, 2016, in the event we fail to effect a reverse stock split by May 3, 2017, the NYSE MKT may delist our common stock. If the NYSE MKT delists our common stock, investors may face material adverse consequences, including, but not limited to, a lack of trading market for our securities, reduced liquidity, decreased analyst coverage of our securities, and an inability for us to obtain additional financing to fund our operations. In addition, delisting from the NYSE MKT might negatively impact our reputation and, as a consequence, our business. Finally, if we were delisted from the NYSE MKT and are not able to list our common stock on another national exchange we will no longer be eligible to use Form S-3 registration statements, which may delay our ability to raise funds in the future, may limit the type of offerings of common stock we could undertake, and could increase the expenses of any offering.
 
We are currently below compliance with certain continued listing requirements of the NYSE MKT. 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.
 
On December 27, 2016, we received notice from the NYSE MKT LLC (the “Exchange”) that we were not in compliance with Section 1003(a)(iii) of the NYSE MKT Company Guide (“Company Guide”) since we reported stockholders’ equity of less than $6,000,000 at September 30, 2016 and had incurred net losses in our five most recent fiscal years ended December 31, 2015.  Receipt of the letter does not have any immediate effect upon the listing of our common stock, provided that in order to maintain our listing on the Exchange, the Exchange requested that we submit a plan of compliance (the “Plan”) by January 27, 2017 addressing how we intend to regain compliance with Section 1003(a)(iii) of the Company Guide by June 27, 2018.  We submitted our Plan to the Exchange by the requested deadline, and such plan was accepted by the Exchange on February 13, 2017.  In connection with such acceptance, we have been provided until June 27, 2018 to regain compliance with Section 1003(a)(iii) of the Company Guide, which requires our stockholders’ equity to be at least $6 million.  If we do not make progress consistent with the Plan during the Plan period or regain compliance with the applicable continued listing standards of the Exchange by June 27, 2018, the Exchange will initiate delisting proceedings as appropriate.  We are confident that we will be able to regain compliance with applicable listing standards by June 27, 2018, provided that if we are unable to regain compliance, our common stock will be delisted from the Exchange.
 
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.
 
 
 
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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 Exchange Act. 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.
 
Risks Related to Our Series A Convertible Preferred Stock
 
The issuance of common stock upon conversion of the Series A Convertible Preferred stock will cause immediate and substantial dilution to existing shareholders.
 
Our 66,625 outstanding shares of Series A Convertible Preferred stock are convertible into common stock on a 1,000:1 basis (subject to certain limitations on conversions described in the Series A Preferred designation), provided that no conversion of the Series A Convertible Preferred stock is allowed in the event the holder thereof would beneficially own more than 9.9% of our common stock or voting stock.
 
The issuance of common stock upon conversion of the Series A Convertible Preferred stock will result in immediate and substantial dilution to the interests of other stockholders since the holder of the Series A Convertible Preferred stock may ultimately receive and sell the full amount of shares issuable in connection with the conversion of such Series A Convertible Preferred stock. Although the Series A Convertible Preferred stock may not be converted if such conversion would cause the holder thereof to own more than 9.9% of our outstanding common stock, this restriction does not prevent the holder from converting some of its holdings, selling those shares, and then converting the rest of its holdings, while still staying below the 9.9% limit. In this way, the holder of the Series A Convertible Preferred stock could sell more than this limit while never actually holding more shares than this limit allows. If the holder of the Series A Convertible Preferred stock chooses to do this, it will cause substantial dilution to the then holders of our common stock.
 
The issuance and sale of common stock upon conversion of the Series A Convertible Preferred stock may depress the market price of our common stock.
 
All of our Series A Convertible Preferred Stock is held by GGE, the parent company of which is controlled by a court-appointed liquidator that is currently taking steps to liquidate GGE’s parent company’s assets. If GGE were to distribute our Series A Convertible Preferred Stock in connection with such liquidation, and/or these shares are converted in sequential conversions and sales of such converted shares take place, the price of our common stock may decline.
  
In addition, the common stock issuable upon conversion of the Series A Convertible Preferred stock may represent overhang that may also adversely affect the market price of our common stock. Overhang occurs when there is a greater supply of a company’s stock in the market than there is demand for that stock. When this happens the price of the company’s stock will decrease, and any additional shares which shareholders attempt to sell in the market will only further decrease the share price. If the share volume of our common stock cannot absorb converted shares sold by the Series A Convertible Preferred stock holder, then the value of our common stock will likely decrease.
 
The holder of our Series A Convertible Preferred stock has the right to appoint two members to our board of directors.
 
In February 2015, by resolution of the board of directors, we formally increased the size of our board of directors from three (3) members to five (5) members. Pursuant to the designation of the Series A Convertible Preferred stock, we provided the holder thereof the right, upon notice to us, to appoint designees to fill the two (2) vacant seats, one of which must be an independent director as defined by applicable rules. In July 2015, David Z. Steinberg joined our board of directors as one of the holder’s independent director designees. The holder’s second designee has not been appointed to date. Mr. Steinberg was formerly employed by PM LLC, the former advisor and former affiliate of PPVAF, GOM, RJC and GGE, from May 2009 to November 2016. The board appointment rights continue until the holder no longer holds any of the first tranche of shares issued to the holder. The board appointment rights mean that assuming such rights are exercised; the common stock shareholders may only have the right to appoint 60% (three of five members) of our board of directors.
 
 
 
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ITEM 1B. UNRESOLVED STAFF COMMENTS.
 
None.
 
ITEM 2. PROPERTIES.
 
Office Lease
 
Our corporate headquarters are located in approximately 2,100 square feet of office space at 4125 Blackhawk Plaza Circle, Suite 201, Danville, California 94506. We lease that space pursuant to a lease that expires on July 31, 2017 and that has a base monthly rent of approximately $4,661.
 
Oil and Gas Properties
 
The Company’s oil and gas properties are described under “Item 1. Business - Oil and Gas Properties” - “Our Core Areas” — “Our Non-Core Assets”, “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” – “D-J Basin Asset Reserves Estimates”, and “Note 5 – Oil and Gas Properties” to the consolidated audited financial statements attached hereto and “Production Volumes” and “Supplemental Information on Oil and Gas Producing Activities” at the end of the consolidated audited financial statements attached hereto.
 
ITEM 3. LEGAL PROCEEDINGS
 
The Company is currently not a party to any material legal proceedings and has no current legal proceedings outstanding.
 
 On December 18, 2015, a complaint was filed against Red Hawk Petroleum, LLC (“Red Hawk”), our wholly-owned subsidiary, in the District Court, County of Weld, State of Colorado (Case Number: 2015CV31079) (the “Court”), pursuant to which Liberty Oilfield Services, LLC (“Liberty”) made various claims against Red Hawk in connection with certain completion services provided by Liberty to Red Hawk in November and December 2014. The complaint alleged causes of action for foreclosure of lien, breach of contract, quantum meruit and account stated, and sought payment of amounts allegedly owed, pre- and post-judgment interest, attorneys’ fees and court costs in connection with Red Hawk’s alleged failure to pay Liberty approximately $2.9 million in fees due for completion services provided by Liberty. On May 12, 2016, the Company and Liberty entered into a settlement agreement, pursuant to which the Company paid Liberty $750,000 and issued 2,450,000 fully-vested shares of restricted Company common stock, valued at $588,000, based on the market price on the grant date, as full settlement of all amounts due for the services previously rendered, for which the Company owed approximately $2.6 million.
 
Although we may, from time to time, be involved in litigation and claims arising out of our operations in the normal course of business, other than the Liberty matter described above, we are not currently a party to any material legal proceeding. In addition, other than the Liberty matter, we are not aware of any material legal or governmental proceedings against us, or contemplated to be brought against us.
 
ITEM 4. MINE SAFETY DISCLOSURES.
 
Not applicable
 
 
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PART II
 
ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES.
 
Market Information
 
Our common stock traded on the OTC Bulletin Board over-the-counter market from January 13, 2003 to September 9, 2013. On September 10, 2013, the Company’s shares of common stock commenced trading on the NYSE MKT under the ticker symbol “PED.
 
The following high and low sales prices of our common stock, reflects inter-dealer prices, without retail mark-up, mark-down or commission and may not represent actual transactions.
 
Quarter Ended
 
High
 
 
 Low 
 
March 31, 2016
 $0.32 
 $0.15 
June 30, 2016
  0.41 
  0.16 
September 30, 2016
  0.32 
  0.12 
December 31, 2016
  0.21 
  0.09 
 
    
    
March 31, 2015
 $0.95 
 $0.31 
June 30, 2015
  0.78 
  0.42 
September 30, 2015
  0.48 
  0.22 
December 31, 2015
  0.31 
  0.10 
 
    
    
Shareholders
 
As of March 22, 2017, there were approximately 914 holders of record of our common stock, not including any persons who hold their stock in “street name,” and one holder of our preferred stock.
 
Common Stock
 
The Company is authorized to issue 200,000,000 shares of common stock with $0.001 par value per share. Holders of shares of common stock are entitled to one vote per share on each matter submitted to a vote of shareholders. In the event of liquidation, holders of common stock are entitled to share pro rata in the distribution of assets remaining after payment of liabilities, if any. Holders of common stock have no cumulative voting rights, and, accordingly, the holders of a majority of the outstanding shares have the ability to elect all of the directors of the Company. Holders of common stock have no preemptive or other rights to subscribe for shares. Holders of common stock are entitled to such dividends as may be declared by the Board out of funds legally available therefore. The outstanding shares of common stock are validly issued, fully paid and non-assessable. 
 
Preferred Stock
 
The Company is authorized to issue 100,000,000 shares of preferred stock, $0.001 par value per share, of which 66,625 shares have been designated “Series A Convertible Preferred Stock” (the “Series A Preferred”). On February 23, 2015 (the “Original Issuance Date”), the Company issued all 66,625 shares of Series A Preferred to Golden Globe Energy (US), LLC (“GGE”) in connection with the GGE Acquisition, all of which shares remain issued and outstanding as of the date of this filing.
 
 
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The 66,625 shares of Series A Preferred issued to GGE (i) had a liquidation preference senior to all of the Company’s common stock equal to $400 per share (the “Liquidation Preference”) prior to the date the Shareholder Approval (defined below) was received, (ii) accrued an annual dividend equal to 10% of their Liquidation Preference, payable annually from the date of issuance (the “Dividend”) prior to the date the Shareholder Approval (defined below) was received, (iii) vote together with the common stock on all matters, with each share having one (1) vote, and (iv) since the date of the Shareholder Approval are convertible into common stock of the Company on a 1,000:1 basis. On October 7, 2015, the Company obtained shareholder approval of the issuance of the Company’s common stock upon conversion of the Series A Preferred, and other related matters (the “Shareholder Approval”). Notwithstanding the above, no conversion is allowed in the event the holder thereof would beneficially own more than 9.9% of the Company’s common stock or voting stock (see “Part I” – “Item 1A. Risk Factors”, including “The issuance and sale of common stock upon conversion of the Series A Convertible Preferred stock may depress the market price of our common stock”, and other risk factors related to our Series A Convertible Preferred stock).
 
Additionally, Golden Globe Energy (US), LLC, which we refer to as GGE, the sole holder of our Series A Preferred stock, has the right pursuant to the purchase agreement with GGE and the certificate of designation designating the Series A Preferred, upon notice to us, voting separately as a single class, to appoint designees to fill two (2) seats on our board of directors, one of which must be an independent director as defined by applicable rules and the exclusive right, voting the Series A Preferred Stock as sole stockholder thereof, separately as a single class, to elect such two (2) nominees to the board of directors. On July 15, 2015, at the request of GGE the board of directors of the Company increased the number of members of the board of directors from three to four, pursuant to the power provided to the board of directors in the Company’s Bylaws, and appointed David Z. Steinberg as a member of the board of directors to fill the newly created vacancy, also pursuant to the power provided to the board of directors in the Company’s Bylaws. At the time of appointment, the board of directors made the affirmative determination that Mr. Steinberg was independent pursuant to applicable NYSE MKT and Securities and Exchange Commission rules and regulations. Mr. Steinberg serves as one of GGE’s representatives on the Company’s board of directors. The board of directors appointment rights continue until GGE no longer holds any of the Tranche One Shares (defined and described in greater detail under “Item 13. Certain Relationships and Related Transactions, and Director Independence” — “Agreements with Related Persons” — “Golden Globe Energy (US), LLC”). To date, GGE has not provided notice to PEDEVCO regarding the appointment of the second member to the board of directors, other than Mr. Steinberg.
 
All Series A Preferred Stock nominee members on our board of directors are required to immediately resign at the option of the other members of our board of directors upon such time as the rights of the Series A Preferred Stock holder to appoint members to our board of directors expires. For so long as the board appointment rights remain in effect, if for any reason a Series A Preferred Stock nominee on our board of directors resigns or is otherwise removed from the board of directors, then his or her replacement shall be a person elected by the remaining Series A Preferred Stock nominee or the holder of the Series A Preferred Stock. The board appointment rights continue until the holder no longer holds any of the first tranche of shares issued to the holder. The board appointment rights continue until the holder no longer holds any of the first tranche of shares issued to the holder.
 
Dividend Policy
 
 We have never declared or paid any dividends on our common stock and do not anticipate that we will pay dividends in the foreseeable future. Any payment of cash dividends on our common stock in the future will be dependent upon the amount of funds legally available, our earnings, if any, our financial condition, our anticipated capital requirements and other factors that the board of directors may think are relevant. However, we currently intend for the foreseeable future to follow a policy of retaining all of our earnings, if any, to finance the development and expansion of our business and, therefore, do not expect to pay any dividends on our common stock in the foreseeable future.
 
 
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Securities Authorized for Issuance Under Equity Compensation Plans
 
The following table sets forth information, as of December 31, 2016, with respect to our compensation plans under which common stock is authorized for issuance.
 
EQUITY COMPENSATION PLAN INFORMATION
 
Plan Category
 
 
Number of securities to be issued upon exercise of outstanding options, warrants and rights
(A)
 
 
 
Weighted-average exercise price of outstanding options, warrants and rights
(B)
 
 

Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in Column A)
(C)
 
 
 
 
 
 
 
 
 
 
 
Equity compensation plans approved by shareholders (1)
  4,280,560 
 $0.50 
  12,010(2)
Equity compensation plans not approved by shareholders (3)
  13,472,747 
 $0.77 
  - 
Total
  17,753,307 
 $0.71 
  12,010 
 
(1)
Consists of (i) options to purchase 310,136 shares of common stock issued and outstanding under the Pacific Energy Development Corp. 2012 Amended and Restated Equity Incentive Plan, (ii) options to purchase 3,424 shares of common stock issued and outstanding under the Blast Energy Services, Inc. 2009 Incentive Plan, and (iii) options to purchase 3,967,000 shares of common stock issued and outstanding under the PEDEVCO Corp. 2012 Amended and Restated Equity Incentive Plan.
 
(2)
Consists of 12,010 shares of common stock reserved and available for issuance under the PEDEVCO Corp. 2012 Amended and Restated Equity Incentive Plan.
 
(3)
Consists of (i) options to purchase 906,668 shares of common stock granted by Pacific Energy Development Corp. to employees and consultants of the company in October 2011 and June 2012, and (ii) warrants to purchase 12,566,079 shares of common stock granted by PEDEVCO Corp. to placement agents, investors and consultants between March 2013 and May 2016.
 
Stock Transfer Agent
 
Our stock transfer agent is First American Stock Transfer, located at 4747 N. 7th Street, Suite 170, Phoenix, AZ 85014.
 
Recent Sales of Unregistered Securities
 
On December 28, 2016 the Company issued 200,000 fully-vested shares of restricted Company common stock to a financial advisor as a mobilization fee.
 
The issuance described above which constituted an “offer” and/or “sale” of securities, was exempt from registration pursuant to Regulation S of the Securities Act since the foregoing issuance and grant did not involve a public offering, the recipient took the securities for investment and not resale, we took appropriate measures to restrict transfer, and the recipient was) not a “U.S. Person” within the meaning of Regulation S under the Securities Act.
 
 
 
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Recent Sales of Registered Securities
 
            
None.
 
Use of Proceeds From Sale of Registered Securities
 
Our Registration Statement on Form S-3 (Reg. No. 333-214415) in connection with the sale by us of up to $100 million in securities (common stock, preferred stock, warrants and units) was declared effective by the Securities and Exchange Commission on January 17, 2017.
 
On September 29, 2016, we entered into an At Market Issuance Sales Agreement (the “Sales Agreement”) with National Securities Corporation (“NSC”), a wholly owned subsidiary of National Holdings Corporation (NasdaqCM:NHLD), pursuant to which the Company may issue and sell shares of its common stock, having an aggregate offering price of up to $2,000,000 (the “Shares”) from time to time, as the Company deems prudent, through NSC (the “Offering”). Upon delivery of a placement notice and subject to the terms and conditions of the Sales Agreement, NSC may sell the Shares by methods deemed to be an “at the market offering” as defined in Rule 415 promulgated under the Securities Act.
 
With the Company’s prior written approval, NSC may also sell the Shares by any other method permitted by law, including in negotiated transactions. The Company may elect not to issue and sell any Shares in the Offering and the Company or NSC may suspend or terminate the offering of Shares upon notice to the other party and subject to other conditions. NSC will act as sales agent on a commercially reasonable efforts basis consistent with its normal trading and sales practices and applicable state and federal law, rules and regulations and the rules of the NYSE MKT.
 
The Company has agreed to pay NSC commissions for its services in acting as agent in the sale of the Shares in the amount equal to 3.0% of the gross sales price of all Shares sold pursuant to the Agreement. The Company also agreed to pay various expenses in connection with the offering, including reimbursing up to $30,000 of NSC’s legal fees, which was paid in three (3) installments as follows: (a) $10,000 on the date of the parties’ entry into the Sales Agreement, (b) $10,000 on the date that was thirty (30) days from the date of the Sales Agreement, and (c) the balance due (not to exceed $10,000) on the date that was sixty (60) days from the date of the Sales Agreement. The Company has also agreed to provide NSC with customary indemnification and contribution rights.
 
The Company intends to use the net proceeds from the offering, if any, to fund development and for working capital and general corporate purposes, including general and administrative purposes. The Company is not obligated to make any sales of common stock under the Sales Agreement, and no assurance can be given that the Company will sell any shares under the Sales Agreement, or, if it does, as to the price or amount of Shares that it will sell, or the dates on which any such sales will take place.
 
The Company has filed a final prospectus in connection with such offering with the SEC (as part of the Form S-3 registration statement), provided that to date, we have not sold any securities under the At Market Issuance Sales Agreement or the prospectus associated therewith.
 
No payments for our expenses will be made in connection with the offering described above directly or indirectly to (i) any of our directors, officers or their associates, (ii) any person(s) owning 10% or more of any class of our equity securities or (iii) any of our affiliates. We plan to use the net proceeds from the offering as described in our final prospectus filed with the SEC pursuant to Rule 424(b).
 
There has been no material change in the planned use of proceeds from our offering as described in our final prospectuses filed with the SEC pursuant to Rule 424(b).
 
 
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Issuer Purchases of Equity Securities
 
Under our 2012 Equity Incentive Plan, the Company may permit an employee to satisfy minimum statutory federal, state and local tax withholding obligations arising from equity awards, including fully-vested and restricted stock awards, to elect to have the Company withhold otherwise deliverable restricted stock to satisfy such tax withholding obligation. The following table provides information with respect to shares withheld by the Company to satisfy these obligations to the extent permitted by the Company and requested by employees. These repurchases were not part of any publicly announced stock repurchase program.
 
 
Period
 
 
 No. of Shares 
 Average Price 
 
 
 
 
 
 
 
 
April 1 – April 30, 2016
 
  323,490 
 $0.23 
 
 
ITEM 6. SELECTED FINANCIAL DATA
 
Not required under Regulation S-K for “smaller reporting companies.”
 
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
 
The following discussion and analysis of our financial condition and results of operations should be read in conjunction with the consolidated financial statements and related notes appearing elsewhere in this Annual Report. The following discussion contains “forward-looking statements” that reflect our future plans, estimates, beliefs and expected performance. We caution you that assumptions, expectations, projections, intentions or beliefs about future events may, and often do, vary from actual results and the differences can be material. See “Risk Factors” and “Forward Looking Statements.
 
Overview
 
We are an energy company engaged primarily in the acquisition, exploration, development and production of oil and natural gas shale plays in the Denver-Julesberg Basin (“D-J Basin”) in Colorado, which contains hydrocarbon bearing deposits in several formations, including the Niobrara, Codell, Greenhorn, Shannon, J-Sand, and D-Sand. As of December 31, 2016, we held approximately 11,538 net D-J Basin acres located in Weld County, Colorado through our wholly-owned subsidiary Red Hawk Petroleum, LLC (“Red Hawk”), which acreage is located in the Wattenberg and Wattenberg Extension areas of the D-J Basin, which we refer to as our “D-J Basin Asset.” As of December 31, 2016, we hold interests in 61 gross (17.4 net) wells in our D-J Basin Asset, of which 14 gross (12.5 net) wells are operated by Red Hawk and are currently producing, 25 gross (4.9 net) wells are non-operated, and 22 wells have an after-payout interest. During the quarter-ended December 31, 2016, the Company produced an average of approximately 1,232 gross (272 net) barrels of oil equivalent per day (“BOEPD”) from its D-J Basin Asset.
 
In February 2015, we expanded our D-J Basin position through the acquisition of additional acreage from Golden Globe Energy (US), LLC (“GGE”), which acquisition we refer to as the GGE Acquisition, which included approximately 12,977 additional net acres in the D-J Basin located almost entirely within Weld County, Colorado, including acreage located in the prolific Wattenberg core area, and interests in 53 gross wells with an estimated then-current net daily production of approximately 500 Boepd as of February 7, 2015. The majority of these assets were originally conveyed to GGE’s predecessor-in-interest, RJ Resources Corp., by us in March 2014 in connection with our acquisition of substantially all of the acreage, well interests and operations of Continental Resources, Inc. located in the D-J Basin (the “Continental Acquisition”), and are now included in our D-J Basin Asset.
 
 
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Immediately following the termination of the Reorganization Agreement, on December 29, 2015, the Company entered into an Agreement and Plan of Reorganization (as amended to date, the “GOM Merger Agreement”) with White Hawk Energy, LLC (“White Hawk”) and GOM Holdings, LLC (“GOM”), a Delaware limited liability company. The GOM Merger Agreement provides for the Company’s acquisition of GOM through an exchange of certain of the shares of the Company’s common and preferred stock (the “Consideration Shares”), for 100% of the limited liability company membership units of GOM (the “GOM Units”), with the GOM Units being received by White Hawk and GOM receiving the Consideration Shares (the “GOM Merger”). On February 29, 2016, the parties entered into an amendment to the GOM Merger Agreement, which amended the merger agreement in order to provide GOM additional time to meet certain closing conditions contemplated by the GOM Merger Agreement. The parties entered into the Amendment to extend the deadline for closing the merger and the date after which either party could terminate the GOM Merger Agreement if the merger had not yet been consummated, from February 29, 2016 to no later than April 15, 2016. On April 25, 2016, the parties further amended the GOM Merger Agreement to eliminate the April 15, 2016, closing deadline. See alsoPart I, Item 1. Business” — “Recent Developments” — “GOM Holdings, LLC Merger Agreement” for a more detailed description of the GOM Merger. See also “Part I” – “Item 1A. Risk Factors”, including “The closing of the GOM merger is subject to various risks and closing conditions and such planned transaction may not occur on a timely basis, if at all”, and other GOM Merger-related risk factors.
 
We believe that the D-J Basin shale play represents 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 located in the Wattenberg and Wattenberg Extension areas of Weld County, Colorado. 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.
 
We have listed below the total production volumes and total revenue net to the Company for the years ended December 31, 2016, 2015, and 2014 attributable to our D-J Basin Asset, including the calculated production volumes and revenue numbers for our D-J Basin Asset held indirectly through Condor that would be net to our interest if reported on a consolidated basis.
 
 
 
For the Years Ended December 31,
 
 
 
2016
 
 
2015
 
 
2014
 
Oil
 
 
 
 
 
 
 
 
 
Total Production (Bbls)
  92,966 
  117,365 
  57,753 
Average sales price (per Bbl)
 36.98 
 41.13 
 80.06 
Natural Gas:
    
    
    
Total Production (Mcf)
  168,555 
  343,967 
  94,981 
Average sales price (per Mcf)
 1.98
 1.54 
 5.42 
Oil Equivalents:
    
    
    
Total Production (Boe) (1)
  121,058 
  174,693 
  73,583 
Average Daily Production (Boe/d)
  332 
  479 
  202 
Average Production Costs (per Boe)(2)
 10.42
 6.63 
 15.78 
_________________________
 
(1)
Assumes 6 Mcf of natural gas equivalents to 1 barrel of oil.
 
(2)
Excludes ad valorem and severance taxes.
 
Detailed information about our business plans and operations, including our core DJ Basin Asset is contained under “Part 1” — “Item 1. Business” beginning on page 5 of this Annual Report. 
 
 
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The reserve estimates, including PV-10, set forth above were prepared on January 6, 2017 by South Texas Reservoir Alliance, LLC (“STXRA”). STXRA is an independent professional engineering firm certified by the Texas Board of Professional Engineers (Registration number F­1580), under the direction of Michael Rozenfeld of STXRA. STXRA, and its employees, have no material interest in our Company. STXRA also performs internal reservoir engineering services for the Company, previously participated in a joint venture with the Company for which no substantial activity has occurred to date and was dissolved in April 2016 with an effective date of December 31, 2015, and periodically receives compensation for assistance in locating additional oil and gas properties. The reserve estimates were prepared by STXRA using reserve definitions and pricing requirements prescribed by the SEC. STXRA estimated the proved reserves for our properties by performance methods and analogy. All of the proved producing reserves attributable to producing wells and/or reservoirs were estimated by performance methods. These performance methods, such as decline curve analysis, utilized extrapolations of historical production and pressure data available through December 2016 in those cases where such data were considered to be definitive. The data utilized were furnished to STXRA by the Company or obtained from public data sources. All of the proved developed non­producing and undeveloped reserves were estimated by analogy.
A copy of the report issued by STXRA is filed with this report as Exhibit 99.1.
 
The preliminary appraisal reports and changes in our reserves are reviewed by Michael Peterson, our President and Chief Executive Officer, for completeness of the data presented and reasonableness of the results obtained. Mr. Peterson has over 14 years’ experience in the oil and gas industry. Once any questions have been addressed, STXRA issues the final appraisal reports, reflecting their conclusions.
 
For more information regarding our oil and gas reserves, please refer to “Supplemental Oil and Gas Disclosures (Unaudited)” beginning on page F-36 of this Annual Report, which information is incorporated by reference in this “Item 2. Properties”, by reference.
 
 
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How We Conduct Our Business and Evaluate Our Operations
 
Our use of capital for acquisitions and development allows us to direct our capital resources to what we believe to be the most attractive opportunities as market conditions evolve. We have historically acquired properties that we believe had significant appreciation potential. We intend to continue to acquire both operated and non-operated properties to the extent we believe they meet our return objectives.
 
We will use a variety of financial and operational metrics to assess the performance of our oil and natural gas operations, including:
 
production volumes;
realized prices on the sale of oil and natural gas, including the effects of our commodity derivative contracts;
oil and natural gas production and operating expenses;
capital expenditures;
general and administrative expenses;
net cash provided by operating activities; and
net income.
 
Production Volumes
 
Production volumes will directly impact our results of operations. As of December 31, 2016, we hold interests in 61 gross (17.4 net) wells in our D-J Basin Asset, of which 14 gross (12.5 net) wells are operated by Red Hawk and are currently producing, 25 gross (4.9 net) wells are non-operated, and 22 wells have an after-payout interest. During the quarter-ended December 31, 2016, the Company produced an average of approximately 1,232 gross (272 net) barrels of oil equivalent per day (“BOEPD”) from its D-J Basin Asset. Additionally, we expect to increase production assuming drilling success in the future as we expand operations in our DJ Basin Asset.
 
Liquidity and Capital Resources
 
Liquidity Outlook
 
We expect to incur substantial expenses and generate significant operating losses as we continue to explore for and develop our oil and natural gas prospects, and as we opportunistically invest in additional oil and natural gas properties, develop our discoveries which we determine to be commercially viable and incur expenses related to operating as a public company and compliance with regulatory requirements.
 
Our future financial condition and liquidity will be impacted by, among other factors, the success of our exploration and appraisal drilling program, the number of commercially viable oil and natural gas discoveries made and the quantities of oil and natural gas discovered, the speed with which we can bring such discoveries to production, and the actual cost of exploration, appraisal and development of our prospects.
 
Our current liquidity uses and debt service requirements are managed under the terms of our senior debt facility whereby we are subject to a cash sweep of our net revenues after operating costs. The debt service arrangement provides for budgeted general and administrative cost allowance of $150,000 each month which we believe is sufficient to meet our foreseeable recurring costs.  Such financing arrangement is sufficient to manage recurring cash requirements but provides no additional funds for extraordinary items, execution of our capital expenditure program or the repayment of outstanding debt obligations other than our senior debt facility.  Any equity funds we are able to raise through offerings is not subject to the cash sweep and is not subject to payment to or approval by the senior lenders. 
 
Subject to the availability of the additional funding, which is not currently in place and requires approval of our senior lenders in the event of a debt offering, we plan to make capital expenditures, excluding capitalized interest and general and administrative expense, of up to approximately $11.1 million during the period from January 1, 2017 to December 31, 2017 in order to achieve our plans. We expect our projected cash flow from operations combined with our existing cash on hand, up to $2.0 million of gross proceeds available from the issuance of our common shares through NSC under our current “at the market offering”, and the approximately $18.0 million available under our current senior debt facility will be sufficient to fund our drilling plans and our operations in 2017, noting that the advancement of all or any portion of the approximately $18.0 million gross available under our current senior debt facility is in the sole and absolute discretion of the senior lenders and no senior lender is obligated to fund all or any part of the requested funding.  See “Part I, Item 1. Business” — “Recent Developments” — “Senior Debt Restructuring and “Part I” – “Item 1A. Risk Factors”, including “Our Tranche A Notes and Tranche B Notes include various covenants, reduces our flexibility, increases our interest expense and may adversely impact our operations and our costs. In addition, we may seek additional funding through asset sales, farm-out arrangements, lines of credit, or public or private debt or equity financings to fund additional 2017 capital expenditures and/or repay or refinance a portion or all of our outstanding debt.

 
 
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Our capital budget may be adjusted as business conditions warrant. The amount, timing and allocation of capital expenditures are largely discretionary and within our control. If oil and natural gas prices continue to decline or fail to improve or costs increase significantly, we could defer a significant portion of our budgeted capital expenditures until later periods to prioritize capital projects that we believe have the highest expected returns and potential to generate near-term cash flows. We routinely monitor and adjust our capital expenditures in response to changes in prices, availability of financing, drilling and acquisition costs, industry conditions, timing of regulatory approvals, availability of rigs, success or lack of success in drilling activities, contractual obligations, internally generated cash flows and other factors both within and outside our control.
 
At The Market Offering
 
On September 29, 2016, we entered into an At Market Issuance Sales Agreement (the “Sales Agreement”) with National Securities Corporation (“NSC”), a wholly owned subsidiary of National Holdings Corporation (NasdaqCM:NHLD), pursuant to which the Company may issue and sell shares of its common stock, having an aggregate offering price of up to $2,000,000 (the “Shares”) from time to time, as the Company deems prudent, through NSC (the “Offering”). Upon delivery of a placement notice and subject to the terms and conditions of the Sales Agreement, NSC may sell the Shares by methods deemed to be an “at the market offering” as defined in Rule 415 promulgated under the Securities Act.
 
With the Company’s prior written approval, NSC may also sell the Shares by any other method permitted by law, including in negotiated transactions. The Company may elect not to issue and sell any Shares in the Offering and the Company or NSC may suspend or terminate the offering of Shares upon notice to the other party and subject to other conditions. NSC will act as sales agent on a commercially reasonable efforts basis consistent with its normal trading and sales practices and applicable state and federal law, rules and regulations and the rules of the NYSE MKT.
 
The Company has agreed to pay NSC commissions for its services in acting as agent in the sale of the Shares in the amount equal to 3.0% of the gross sales price of all Shares sold pursuant to the Agreement. The Company also agreed to pay various expenses in connection with the offering, including reimbursing up to $30,000 of NSC’s legal fees, which was paid in three (3) installments as follows: (a) $10,000 on the date of the parties’ entry into the Sales Agreement, (b) $10,000 on the date that was thirty (30) days from the date of the Sales Agreement, and (c) the balance due (not to exceed $10,000) on the date that was sixty (60) days from the date of the Sales Agreement. The Company has also agreed to provide NSC with customary indemnification and contribution rights.
 
The Company intends to use the net proceeds from the offering, if any, to fund development and for working capital and general corporate purposes, including general and administrative purposes. The Company is not obligated to make any sales of common stock under the Sales Agreement, and no assurance can be given that the Company will sell any shares under the Sales Agreement, or, if it does, as to the price or amount of Shares that it will sell, or the dates on which any such sales will take place.
 
The Company has filed a final prospectus in connection with such offering with the SEC (as part of the Form S-3 registration statement), provided that to date, we have not sold any securities under the At Market Issuance Sales Agreement or the prospectus associated therewith.
 
Secured Debt Funding
 
During March 2014, we entered into 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”).
 
 
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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 Initial 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 $190,000 of the legal fees and expenses of the Investors’ counsel, and paid Casimir Capital LP (“Casimir”), our investment banker in the transaction, a fee of $1,742,000, resulting in net proceeds of approximately $27,393,000 which was received by us on March 7, 2014. 
 
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 had 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, originally up to an additional $13.5 million in total or an aggregate of $50 million together with the Initial Notes and approximately $2 million of Subsequent Notes issued in 2014. We were 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 were only eligible to be used by us, together with Company Deposits, for approved AFEs issued for a well or wells to be drilled and completed on any properties acquired in connection with the Continental Acquisition. The total aggregate amount of any Subsequent Notes could not 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.
 
In addition, during the year ended December 31, 2014, the Company borrowed $1,967,000 for drilling activities (net proceeds of $1,593,000, which was reduced from the $1,967,000 by debt discounts of $276,000 related to underwriting fees and a 5% original issue discount of $98,000). There were no borrowings made under the Senior Notes during the year ended December 31, 2015. As of December 31, 2015, there was approximately $13.5 million gross ($11.0 million net, after origination-related fees and expenses) available to draw down under Subsequent Notes from RJC. The Notes are due and payable on March 7, 2017 (the “Maturity Date”), and may be repaid in full without premium or penalty at any time. As a result of the May 12, 2016 restructuring of the Notes and Note Purchase as described below, effective May 12, 2016, the Company may no longer borrow additional funds from RJC under Subsequent Notes, and the Maturity Date of the Notes have been revised as described below.
 
As additional consideration for the initial Note Purchase transaction and for GGE agreeing to purchase the Subsequent Notes, GGE acquired ownership of 50% of all of our oil and gas assets and properties acquired in connection with the Continental Acquisition, and 50% of our interests in our Kazakhstan non-core asset.
 
The Notes initially bore interest at the rate of 15% per annum (subject to the letter agreements described below), 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 our 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 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.
 
On April 24, 2015, certain of our Investors agreed to allow us to defer the mandatory principal repayments and interest payments due under the Notes for the months of May and June 2015, with such deferred amounts to be used to renew, extend, re-lease or otherwise acquire leases, which then became additional collateral under the Notes. The aggregate principal and interest that was deferred was approximately $524,000, which amount has been capitalized and added to the principal due under the Notes and is due upon maturity. The Company was also charged a one-time deferral fee of $354,000, the amount of the principal and interest deferred under this agreement, of which $320,000 was expensed as additional interest and the balance was added to the principal and due upon maturity. As additional consideration for the deferral, on September 10, 2015, we issued warrants exercisable for an aggregate of 349,111 shares of our common stock to the Investors participating in the deferral. Each warrant had a 3 year term and was exercisable on a cashless basis at an exercise price of $1.50 per share. 
 
On August 28, 2015, we entered into agreements with the Investors to (i) defer until the maturity date of the Notes the mandatory principal payments that would otherwise be due and payable by us on payment dates occurring during the six month period of August 1, 2015 through January 31, 2016, (ii) HEARTLAND Bank agreed to change the frequency of payment of accrued interest and mandatory principal repayments from monthly to semi-annually, with the next interest payment due February 1, 2016 and the next mandatory principal repayment due August 3, 2016, and with us agreeing to place an amount equal to 1/6th of the semi-annual principal and interest payments due into a sinking fund starting in February 2016 which we shall pay to HEARTLAND Bank every six months when due and owing, (iii) RJC agreed to defer all interest payments otherwise due and payable by us to RJC during the period commencing on August 1, 2015 through January 31, 2016 (the “Waiver Period”), which deferred interest is added to principal each month during the Waiver Period, (iv) certain other holders agreed to (a) defer until the maturity date of their Notes 12/17ths of the interest payments that would otherwise be due and payable by us to them on payment dates occurring during the six month period of August 1, 2015 through January 31, 2016, and (b) have us pay in cash 5/17ths of such interest payments per month, with all deferred interest being added to principal each month until the maturity date of the Notes, and (v) SHIP, BRe BCLIC Sub, BRe WINIC 2013 LTC Primary, BRe WNIC 2013 LTC Sub and RJC agreed to increase the interest rate under their Senior Notes from 15% to 17% per annum on all outstanding principal under their Notes during the Waiver Period. These deferrals agreed upon with our Investors (the “August-January Deferrals”) reduced our monthly cash interest payments and mandatory principal repayments from approximately $600,000 per month prior to these agreements, to approximately $100,000 per month during the Waiver Period after giving effect to the changes agreed upon under these agreements, thereby providing us with an estimated $500,000 per month in reduced cash flow requirements during the Waiver Period.
 
As additional consideration for these agreements and related note amendments and deferrals, on September 10, 2015, we issued warrants exercisable on a cash-only basis for an aggregate of 1,201,004 shares to the lenders, proportionately based on their individual principal, which grants were subject to NYSE MKT additional listing approval, which has been received. The warrants had a three year term and were exercisable on a cash-only basis at a price of $0.75 per share. In addition, in the event the aggregate total of principal and interest deferred in connection with the August-January deferrals exceeded $900,000 over the Waiver Period, within thirty days of February 1, 2016, and subject to NYSE MKT additional listing approval, we were required to proportionately grant additional warrants such that the total aggregate number of shares of our common stock exercisable under all warrants granted will equal the total principal and interest deferred by such Investors divided by $0.75. As of December 31, 2015, the amount of deferred interest and deferred principal was $2,527,000 and $519,000, respectively.
 
In addition, we agreed to prepare and deliver to RJC a monthly budget in form and substance reasonably satisfactory to RJC, and such financial statements as RJC may reasonably request. The monthly budget is required to include a cash flow forecast and detail of all anticipated non-recurring expenses and non-cash budget items, and we are required to comply with the budgeted expenses set forth therein in all material respects, provided, however, that a variance of less than 10% with respect to the expenses, on an aggregate basis, is permitted.
 
 
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On January 29, 2016, we entered into a Letter Agreement (the “Letter Agreement”) with the Investors and the Agent. The Letter Agreement extended by one (1) month, through February 29, 2016, the deferral of the payment of interest and principal due under the Notes (the “Deferral Extension”). The purpose of the Deferral Extension is to provide the Company with the financial resources and runaway it believes it needs to fully-focus upon and consummate the merger with GOM. Specifically, pursuant to the Letter Agreement, (i) all Investors agreed to further defer until the maturity date of their Notes the mandatory principal payments that would otherwise be due and payable by the Company to them on payment dates occurring through February 29, 2016, (ii) HEARTLAND Bank agreed to change the next scheduled semi-annual interest payment due from February 1, 2016 to March 1, 2016 (with interest due and payable thereafter on a semi-annual basis) and to change the next mandatory principal repayment due date to September 3, 2016, and the Company agreed to place an amount equal to 1/6th of the semi-annual principal and interest payments due into a sinking fund which the Company shall pay to HEARTLAND Bank every six months when due and owing, and (iii) Senior Health Insurance Company of Pennsylvania (“SHIP”) (as successor-in-interest to BRe BCLIC Primary), BRe BCLIC Sub, BRe WINIC 2013 LTC Primary, BRe WNIC 2013 LTC Sub, and RJC agreed to (a) defer until the maturity date of their Notes and the junior note held by RJC (the “RJC Junior Note”) all of the interest payments that would otherwise be due and payable by the Company to them in February 2016; (b) return the interest rate under each of their Notes to 15% per annum, and the interest rate under the RJC Junior Note to 12% cash pay per annum, effective January 31, 2016; and (c) delay the issuance of any “Subsequent Warrants” issuable pursuant thereto to within 30 days of March 1, 2016, subject to NYSE MKT additional listing approval.
 
On March 7, 2016, the Company entered into a Letter Agreement, dated March 1, 2016 (the “March Letter Agreement”), with SHIP, BRe BCLIC Sub, BRe WINIC 2013 LTC Primary, BRe WNIC 2013 LTC Sub, and RJC (collectively, the “Original Lenders”), and the Agent, which extended the Deferral Extension by one (1) month, through March 31, 2016. Pursuant to the March Letter Agreement, the Original Lenders agreed to (i) further defer until the maturity date of their Senior Notes the mandatory principal payments that would otherwise be due and payable by the Company to them on payment dates occurring through March 31, 2016, (ii) defer until the maturity date of their Senior Notes and the RJC Junior Note all of the interest payments that would otherwise be due and payable by the Company to them in March 2016, with all interest amounts deferred being added to principal on the first business day of the month following the month in which such deferred interest is accrued; and (iii) delay the issuance of any “Subsequent Warrants” issuable pursuant thereto to within 30 days of April 1, 2016, subject to NYSE MKT additional listing approval.
 
On April 7, 2016, we entered into a Letter Agreement, dated April 1, 2016 (the “Letter Agreement”), with the Investors. The Letter Agreement extended by one (1) month, through April 30, 2016, the deferral of the payment of interest and principal due under the Senior Notes and the Note and Security Agreement, dated April 10, 2014, as amended on February 23, 2015, issued by the Company to RJ Credit LLC (the “RJC Junior Note,” and together with the Senior Notes, the “Notes”)(the “Deferral Extension”), entered into with the Lenders on August 28, 2015, as amended on January 29, 2016 and March 7, 2016 (the “Original Deferral Agreements”). Specifically, pursuant to the Letter Agreement, all the Lenders agreed to: (i) further defer until the maturity date of their Senior Notes the mandatory principal payments that would otherwise be due and payable by the Company to them on payment dates occurring through April 30, 2016; (ii) defer until the maturity date of their Senior Notes and the RJC Junior Note all of the interest payments that would otherwise be due and payable by the Company to them in April 2016, with all interest amounts deferred being added to principal on the first business day of the month following the month in which such deferred interest is accrued; and (iii) delay the issuance of any “Subsequent Warrants” (as defined in the Original Deferral Agreements) issuable pursuant thereto to within 30 days of May 1, 2016, subject to NYSE MKT additional listing approval.
 
On May 12, 2016, the Company entered into Amendment No. 2 to Note and Security Agreement with RJC (the “Second Amendment”), pursuant to which the Company and RJC agreed to amend the RJC Junior Note to (i) capitalize all accrued and unpaid interest under the RJC Junior Note as of the date of the parties entry into the Second Amendment, and add it to note principal, making the current outstanding principal amount of the RJC Junior Note $9,413,823, (ii) extend the “Termination Date” thereunder (i.e., the maturity date) from December 31, 2017 to July 11, 2019, (iii) provide that all future interest accruing under the RJC Junior Note is deferred, due and payable on the Termination Date, with all future interest amounts deferred being added to principal on the first business day of the month following the month in which such deferred interest is accrued, and (iv) subordinate the RJC Junior Note to the Senior Notes.
 
 
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Also on May 12, 2016, the Company entered into the Amended NPA and undertook the transactions contemplated therein, including selling the New Senior Notes to the Lenders as described above under “Part I” –“Item 1. Business-Business Operations-Recent Developments” — “Senior Debt Restructuring”. Pursuant to the Amended NPA, the Company created new “Tranche A Notes,” in substantially the same form and with similar terms as the Tranche B Notes, with certain exceptions as described above, consisting of a term loan issuable in tranches with a maximum aggregate principal amount of $25,960,000, with borrowed funds accruing interest at 15% per annum, and maturing on May 11, 2019, under which Tranche A Notes the Company may draw up to approximately $18.0 million additional principal in accordance with their terms, including that the lenders thereof approve such loans at their sole discretion (see “Part I” – “Item 1A. Risk Factors”, including “Our Tranche A Notes and Tranche B Notes include various covenants, reduces our flexibility, increases our interest expense and may adversely impact our operations and our costs.”).
 
Amendment to PEDCO-MIEJ Note and Condor-MIEJ Note
 
On February 19, 2015 (the “MIEJ Closing Date”), the Company and PEDCO entered into a Settlement Agreement (the “MIEJ Settlement Agreement”) with MIEJ. MIEJ was PEDCO’s 80% partner in Condor, and was the lender to PEDCO under that certain Amended and Restated Secured Subordinated Promissory Note, dated March 25, 2013, in the principal amount of $6,170,065, entered into by PEDCO and MIEJ (the “MIEJ Note”). Pursuant to the MIEJ Settlement Agreement, among other things, (i) MIEJ and PEDCO agreed to restructure the MIEJ Note through the entry into a new Amended and Restated Secured Subordinated Promissory Note, dated February 19, 2015 and with an effective date of January 1, 2015 (the “New MIEJ Note”), (ii) PEDCO sold its (x) full 20% interest in Condor to MIEJ (the “Condor Interests”), and (y) interests in approximately 945 net acres and interests in three (3) wells located in PEDCO’s legacy non-core Niobrara acreage located in Weld County, Colorado, that were directly held by PEDCO to Condor (the “PEDCO Direct Interests”), effective January 1, 2015, and (iii) Condor forgave approximately $1.8 million in previous working interest expenses related to the drilling and completion of certain wells operated by Condor that was due from PEDCO, which, in summary, had the net effect of reducing approximately $9.4 million in aggregate liabilities due from PEDCO to MIEJ and Condor to $4.925 million, which is the new principal amount of the New MIEJ Note. In addition, pursuant to the MIEJ Settlement Agreement, (a) in consideration for the PEDEVCO Senior Loan Investors releasing their security interest on the Condor Interests and PEDCO Direct Interests, MIEJ paid $500,000 to the PEDEVCO Senior Loan Investors as a principal reduction on the PEDEVCO Senior Loan, which directly benefits PEDEVCO, (b) PEDCO paid $100,000 as a principal reduction under the MIEJ Note, (c) each of MIEJ, Condor and the Company fully released each other, and their respective predecessors and successors in interest, parents, subsidiaries, affiliates and assigns, and their respective officers, directors, managers, members, agents, representatives, servants, employees and attorneys, from every claim, demand or cause of action arising on or before the MIEJ Closing Date, and (d) MIEJ confirmed that the MIEJ Note was paid in full and that PEDCO owed no amounts to MIEJ or Condor other than the principal amount due as reflected in the New MIEJ Note.
 
The New MIEJ Note was effective January 1, 2015, bears an interest rate of 10.0% per annum with no interest due until Maturity (defined below) or except as detailed below, is secured by all of our current and after-acquired assets, and is subordinated in every way to the Senior Notes as well as to New Senior Lending (defined below); however, MIEJ has no control over the cash flow of the Company, nor is MIEJ’s consent required in connection with any disposition, sale, or use of any assets of the Company or any of its subsidiaries at any time in the future, provided that the requirements of the New MIEJ Note requiring the prepayment of interest, where applicable, as described below are followed. After the MIEJ Closing Date, the Company may enter into a loan, or a series of new loans or any other new non-equity investment or assumption of indebtedness (a “New Senior Lending”) which will be senior to the New MIEJ Note, without the prior consent of MIEJ, provided that, in addition to the approximately $35 million principal balance of the Notes, the New Senior Lending is subject to a cap of an additional $60 million in the aggregate, such that the total lending, debt or similar investment under such cap shall not exceed $95 million in the aggregate (the “Senior Debt Cap”), with any portion of New Senior Lending in excess of the Senior Debt Cap advanced first to MIEJ until the New MIEJ Note is paid in full. The New MIEJ Note shall automatically, and without further consent from MIEJ, be subordinated in every way to any such New Senior Lending. Should the Company enter into any new financing transaction that results in raising New Senior Lending of at least $20 million in excess of the balance of the Notes, then MIEJ has a right to be paid all interest and fees that have accrued on the New MIEJ Note each and every time that a new financing transaction reaches or exceeds the $20 million threshold.
 
 
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 The New MIEJ Note was originally due and payable on March 8, 2017, but is now due and payable on March 8, 2019 due to an automatic maturity date extension as a result of the May 2016 Senior Debt Restructuring, and with such date also subject to additional automatic extensions upon the occurrence of a Long-Term Financing or additional PEDEVCO Senior Lending Restructuring (each as defined below) (the “Maturity”). On a one-time basis, the PEDEVCO Senior Loan may be refinanced by a new loan (“Long-Term Financing”) by one or more third party replacement lenders (“Replacement Lenders”), and in such event we are required to undertake commercially reasonable best efforts to cause the Replacement Lenders to simultaneously refinance both the PEDEVCO Senior Loan and the New MIEJ Note as part of such Long-Term Financing. Despite such efforts, should the Replacement Lenders be unable or unwilling to include the New MIEJ Note in such financing, then the Long-Term Financing may proceed without including the New MIEJ Note, and the New MIEJ Note shall remain in place and shall be automatically subordinated, without further consent of MIEJ, to such Long-Term Financing. Furthermore, upon the occurrence of a Long-Term Financing, the Maturity of the New MIEJ Note is automatically extended, without further consent of MIEJ, to the same maturity date of the Long-Term Financing (the “Extended Maturity Date”), provided that the Extended Maturity Date may not exceed March 8, 2020. Additionally, upon the closing of such Long-Term Financing: (a) the Long-Term Financing is required to be subject to the Senior Debt Cap, (b) we are required to make commercially reasonable best efforts for the Long-Term Financing to include adequate reserves or other payment provisions whereby MIEJ is paid all interest and fees accrued on the New MIEJ Note commencing as of March 8, 2017 (and annually thereafter, until such time as the New MIEJ Note is paid in full), but in any event the Replacement Lenders are required to agree to allow for quarterly interest payments (starting March 31, 2017) of not less than 5% per annum on the outstanding balance of the New MIEJ Note, plus a one-time payment of accrued interest (not to exceed $500,000) as of March 31, 2017 (the “Subordinated Interest Payments”), and the remaining 5% interest shall continue to accrue, and (c) MIEJ has the Right of Conversion (defined below) commencing as of March 8, 2017, the original maturity date of the New MIEJ Note. If the PEDEVCO Senior Loan and/or New Senior Lending is not refinanced by Replacement Lenders, but is instead refinanced, restructured or extended by the existing PEDEVCO Senior Loan Investors (a “PEDEVCO Senior Lending Restructuring”), the maturity of both the New MIEJ Note and the PEDEVCO Senior Loan may be extended to no later than March 8, 2019, without requiring the consent of MIEJ, provided that (i) any such extension of the maturity date of the New MIEJ Note past March 8, 2017 shall give MIEJ the Right of Conversion (described below) commencing on March 8, 2017, and (ii) such extension agreement shall include payment provisions whereby MIEJ shall be paid all interest and fees accrued on the New MIEJ Note as of March 8, 2018. The May 2016 Senior Debt Restructuring qualified as a PEDEVCO Senior Lending Restructuring and the issuance of the Tranche A Notes qualified as a New Senior Lending, the result of which the Maturity of the New MIEJ Note has been extended to March 8, 2019. The New MIEJ Note may be prepaid any time without penalty.
 
The New MIEJ Note has a conversion feature that provides, in the event that the final maturity of the New MIEJ Note is extended beyond March 8, 2017 for whatever reason, MIEJ has the right, at its discretion, to have the outstanding balance of the New MIEJ Note plus any accrued and unpaid interest thereon converted in whole or in part into our common stock at a price (the “Conversion Price”) equal to 80% of the average closing price per share of our common stock over the then previous 60 days from the date MIEJ exercises its conversion right (subject to adjustment for stock splits, recapitalizations and the like)(such event, a “Right of Conversion”); provided, however, that in no event shall the Conversion Price be less than $0.30 per share (the “Floor Price”). Additionally, the New MIEJ Note contains a provision preventing the conversion of the MIEJ Note to the extent that such conversion would result in more than 19.9% of our outstanding common stock or voting stock being issued in aggregate upon the conversion of such note, or otherwise require shareholder approval under the NYSE MKT rules. Notwithstanding that, we agreed to include a proposal in our proxy statement for our 2016 annual meeting of our shareholders (the “2016 Annual Meeting”) for the approval of the issuance of the maximum number of shares of common stock issuable in connection with conversion of the New MIEJ Note, assuming conversion at the Floor Price (the “Maximum Conversion Shares”). At the 2016 Annual Meeting held on December 28, 2016, the Company’s stockholders approved the full conversion of the New MIEJ Note and the New MIEJ Note is now fully convertible into our common stock in accordance with its terms.
 
 
 
86
 
 
Bridge Notes
 
On March 7, 2014, we entered into the Second Amendment to Secured Promissory Notes (each, an “Amended Note,” and collectively, the “Amended Notes”) with all but one of the investors holding our secured subordinated promissory notes, originally issued on March 22, 2013, referred to herein as the “Bridge Notes”.
 
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 to such notes; 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 was $2.15 per share; and
 
(B)
following June 1, 2014, the denominator used in the calculation described above is 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 provided by the holder; and (ii) $0.50 per share.
 
Additionally, each bridge investor who entered into the Second Amendment to Secured Promissory Note also 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 in March 2014, as described in greater detail above. 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.
 
Through the date hereof, holders of $1,900,000 of the original principal amount of the Amended Notes have exercised their option to convert a portion or all of their Amended Notes into common stock of the Company. We issued an aggregate of 1,618,026 shares of common stock of the Company to holders of the Amended Notes upon conversion of an aggregate of $2,221,000 in principal, accrued interest, and payment-in-kind outstanding under their Amended Notes (the “Note Conversions”), according to the terms of the Amended Notes. Following the Note Conversions, an aggregate principal amount of $475,000 of the original $4 million principal amount of the bridge notes remain issued and outstanding, plus accrued and unpaid interest and payment-in-kind, is convertible into common stock of the Company pursuant to the terms of the Amended Notes.
 
Financial Summary
 
We had total current assets of $1.3 million as of December 31, 2016, including cash of $0.7 million, compared to total current assets of $1.9 million as of December 31, 2015, including a cash balance of $1.1 million.
 
We had total assets of $58.8 million as of December 31, 2016 and $60.8 million as of December 31, 2015. Included in total assets as of December 31, 2016 and December 31, 2015 were $57.4 million and $58.8 million, respectively, of proved oil and gas properties subject to amortization and $-0- and $-0- million, respectively, in unproved oil and gas properties not subject to amortization,
 
We had total liabilities of $60.7 million as of December 31, 2016, including current liabilities of $3.3 million, compared to total liabilities of $45.7 million as of December 31, 2015, including current liabilities of $7.6 million.