PEDEVCO CORP - Annual Report: 2018 (Form 10-K)

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

FORM 10-K

 

 

For the fiscal year ended December 31, 2018

 

 

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.)

 

1250 Wood Branch Park Dr., Suite 400

Houston, Texas 77079

(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 American

 

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 every Interactive Data File required to be submitted 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, a smaller reporting company, or an emerging growth company.  See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” and "emerging growth company" in Rule 12b-2 of the Exchange Act.

 

Large accelerated filer  ☐	Accelerated filer   ☐
Non-accelerated filer  ☐	Smaller reporting company ☒
Emerging growth ☐

 

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.    ☐

 

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐  No ☑

 

The aggregate market value of the voting and non-voting common equity held by non-affiliates of the registrant as of June 30, 2018 based upon the closing price reported on such date was approximately $12,399,791. Shares of voting stock held by each officer and director and by each person who, as of June 30, 2018, 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 27, 2019, 45,288,828 shares of the registrant’s common stock, $0.001 par value per share, were outstanding.

 

 

Table of Contents

 

		Page
PART I
Item 1 and 2.	Business and Properties	8
Item 1A.	Risk Factors	35
Item 1B.	Unresolved Staff Comments	61
Item 3.	Legal Proceedings	61
Item 4.	Mine Safety Disclosures	61
PART II
Item 5.	Market For Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	62
Item 6.	Selected Financial Data	64
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	65
Item 7A.	Quantitative and Qualitative Disclosure About Market Risk	72
Item 8.	Financial Statements and Supplementary Data	72
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	73
Item 9A.	Controls and Procedures	73
Item 9B.	Other Information	74
PART III
Item 10.	Directors, Executive Officers and Corporate Governance	75
Item 11.	Executive Compensation	83
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	95
Item 13.	Certain Relationships and Related Transactions, and Director Independence	98
Item 14.	Principal Accounting Fees and Services	100
PART IV
Item 15.	Exhibits and Financial Statement Schedules	101

 

 

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, 2018. 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., PACIFIC ENERGY & RARE EARTH LIMITED (DISSOLVED EFFECTIVE AUGUST 11, 2017), BLACKHAWK ENERGY LIMITED (DISSOLVED EFFECTIVE MAY 1, 2018), RED HAWK PETROLEUM, LLC, WHITE HAWK ENERGY, LLC (DISSOLVED EFFECTIVE MARCH 7, 2018), CONDOR ENERGY TECHNOLOGY LLC (ACQUIRED AUGUST 1, 2018), RIDGEWAY ARIZONA OIL CORP. (ACQUIRED SEPTEMBER 1, 2018), AND EOR OPERATING COMPANY (ACQUIRED SEPTEMBER 1, 2018), 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;
●	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;
●	future acquisition transactions;
●	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” below, and readers are encouraged to review that section.

 

Unless the context otherwise requires and for the purposes of this report only:

 

 

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.

 

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.

 

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.

 

 

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.

 

Cushing/WTI. Means the price of West Texas Intermediate oil at the hub located in Cushing, Oklahoma.

 

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.

 

Frac or fraccing. A short name for hydraulic fracturing, a method for extracting oil and natural gas.

 

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.

 

 

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.

 

Hydraulic Fracturing. Means the forcing open of fissures in subterranean rocks by introducing liquid at high pressure, especially to extract oil or gas.

 

IP30. Means the production of a well for the first full calendar month of production.

 

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.

 

NGL. Natural gas liquids.

 

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.

 

 

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.

 

Transition Zone. The Transition Zone usually produces both oil and water at different ratios depending on the height above the Free Water Level (FWL). In normal conditions wells that are drilled in the Transition Zone will produce at some water cut.

 

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.

 

 

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.

 

 

PART I

 

ITEM 1 AND 2. BUSINESS AND PROPERTIES.

 

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.

 

Office Leases

 

Our corporate headquarters is located in approximately 4,600 square feet of office space at 1250 Wood Branch Park Dr., Suite 400, Houston, Texas 77079. We lease that space pursuant to a lease that expires in August 2019 and the company is currently in negotiations to extend its lease or move to new office space to accommodate growth. The Company previously had additional office space at our former corporate headquarters in Danville, California, which lease was terminated in February 2019 without penalty or other amounts due.

 

Business Operations

 

Overview

 

We are an oil and gas company focused on the acquisition and development of oil and natural gas assets where the latest in modern drilling and completion techniques and technologies have yet to be applied. In particular, we focus on legacy proven properties where there is a long production history, well defined geology and existing infrastructure that can be leveraged when applying modern field management technologies. Our current properties are located in the San Andres formation of the Permian Basin situated in West Texas and eastern New Mexico (the “Permian Basin”) and in the Denver-Julesberg Basin (“D-J Basin”) in Colorado.  As of December 31, 2018, we held approximately 23,441 net Permian Basin acres located in Chaves and Roosevelt Counties, New Mexico, through our wholly-owned operating subsidiary, Pacific Energy Development Corp. (“PEDCO”), which we refer to as our “Permian Basin Asset,” and approximately 11,948 net D-J Basin acres located in Weld and Morgan Counties, Colorado, through our wholly-owned operating subsidiary, Red Hawk Petroleum, LLC (“Red Hawk”), which asset we refer to as our “D-J Basin Asset.” As of December 31, 2018, we held interests in 337 gross (337 net) wells in our Permian Basin Asset of which 51 are active producers, 18 are active injectors and one well is an active Saltwater Disposal Well (“SWD”), all of which are held by PEDCO and operated by its wholly-owned operating subsidiaries, and interests in 69 gross (21.5 net) wells in our D-J Basin Asset, of which 18 gross (16.2 net) wells are operated by Red Hawk and currently producing, 29 gross (5.2 net) wells are non-operated, and 22 wells have an after-payout interest.

 

Restructuring

 

 

Transformation

Simultaneously with the Restructuring, the newly installed management team was in the process of evaluating several acquisitions that contemplated a shift in the Company’s overall business strategy to focus on assets with the following characteristics:

 

 

Consistent with the Company’s new business strategy, the Company consummated the following transactions in August 2018:

 

Acquisition of Permian Basin Properties

 

On August 31, 2018, the Company closed the acquisition of the Permian Basin Asset in New Mexico, from Hunter Oil Company for a purchase price of $21.3 million. The purchase price included $18.5 million for all production, associated assets and acreage, $500,000 for the operating entities and associated inventory, and $2.3 million of restricted cash held in the operating companies for bonding with the State of New Mexico. These properties had previously been evaluated by the new management team and fit the new corporate focus. Both the Milnesand and Chaveroo fields in the Permian Basin Asset are legacy oil fields having produced to date 48 million barrels of oil equivalent from the San Andres formation, via 40-acre vertical well spacing. The Company believes that by applying horizontal drilling and modern completion techniques to the Permian Basin Asset, downspacing to 20 acres can be achieved at a lower cost, with significantly better recoveries than continued vertical drilling.

 

To finance this acquisition, the Company sold $23.6 million of convertible debt with a conversion price of $2.13 per share. SK Energy purchased $22.0 million of the convertible debt, which SK Energy subsequently converted into common stock effective March 1, 2019, as discussed below under “Recent Events” – “SK Energy Note Amendment; Note Purchases and Conversion”.

Acquisition of Additional D-J Basin Properties

In August 2018 the Company also acquired additional assets consisting of four operated wells and 2,340 net acres held by production in the D-J Basin which added to the Company’s then-current position. This consolidation of ownership in existing acreage within the D-J Basin provides for a more focused development plan related to these assets.

Business Strategy

 

We believe that horizontal development and exploitation of conventional assets in the Permian Basin and development of the Wattenberg and Wattenberg Extension in the D-J Basin, represent among the most economic oil and natural gas plays in the U.S. We plan to optimize our existing assets and opportunistically seek additional acreage proximate to our currently held core acreage, as well as other attractive onshore U.S. oil and gas assets that fit our acquisition criteria, that Company management believes can be developed using our technical and operating expertise and be accretive to shareholder value. 

 

 

Specifically, we seek to increase shareholder value through the following strategies:

 

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 through 2019 will be focused on the development of our Permian Basin Asset, with a secondary focus on development of our D-J Basin Asset. Our 2019 total development plan calls for the deployment of an estimated $52 million in capital, of which approximately $22 million has been raised to date. On our Permian Basin Asset four initial horizontal wells were drilled in December 2018 and January 2019 in phase one of our development plan, followed by phase two which contemplates the drilling and completion of an additional eight horizontal wells through 2020, subject to, and based upon, the results from phase one, and in each case, available funding. Our 2019 D-J Basin Asset development plan is currently under evaluation for our operated acreage and our non-operated acreage and is projected to require approximately $7.6 million in capital through 2019. Due to the held-by-production nature of our Permian Basin assets, we believe capital can be readily allocated to our D-J Basin assets if needed. We expect that we will have sufficient cash available to meet our needs over the foreseeable future, which cash we anticipate being available from (i) our projected cash flow from operations, (ii) our existing cash on hand, (iii) equity infusions or loans (which may be convertible) made available from our largest shareholder, SK Energy, which is owned and controlled by Dr. Simon Kukes, our Chief Executive Officer and director, which funding SK Energy is under no obligation to provide and which funds may not be available on favorable terms, if at all. 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 2019 capital expenditures and/or acquisitions. 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 2020.

 

 

The following chart reflects our current organizational structure:

  

*Represents percentage of total voting power based on 45,288,828 shares of common stock (solely on an issued and outstanding basis) outstanding as of March 27, 2019, with beneficial ownership calculated in accordance with Rule 13d-3 of the Exchange Act (but without reflecting the conversion of convertible securities into voting securities, including, options exercisable for common stock of the Company. Holdings of SK Energy LLC, an entity wholly-owned and controlled by our CEO and director Dr. Simon Kukes, are also included in holdings of Senior Management and Board – See “Part III” — “Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.”

 

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 and exploitation 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. Many 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 exploit, 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 many 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:

 

Legacy Conventional Focus. Legacy conventional oil fields that have seen large-scale vertical development. Vertical production confirms moveable hydrocarbons ideal for horizontal development that may have been technologically or economically limited or missed.

 

Technical Engineering & Operations Expertise. Lateral landing decisions incorporate log analysis, fracture-geometry modeling and an understanding of local porosity and saturation distributions. Our team are creative problem solvers with expertise in wellbore mechanics, completion design, production enhancement, artificial lift design, water handling, facilities optimization, and production down-time reduction.

 

Low Cost Development. Shallow conventional reservoirs (<8,000 feet) and short to mid-range laterals (1.0 mile and 1.5 mile, respectively) allow for efficient full-scale development without the requirement for extended reach laterals and large fracs to meet economic thresholds.

 

Management. We have assembled a management team at our Company with extensive experience in the fields of business development, petroleum engineering, geology, field development and production, operations, planning and corporate finance. Our management team is headed by our Chief Executive Officer, Dr. Simon Kukes, who was formerly the CEO at Samara-Nafta, a Russian oil company partnering with Hess Corporation, President and CEO of Tyumen Oil Company, and Chairman of Yukos Oil. Our President, J. Douglas Schick, has over 20 years of experience in the oil and gas industry, having co-founded American Resources, Inc., and formerly serving in executive, management and operational planning, strategy and finance roles at Highland Oil and Gas, Mariner Energy, Inc., The Houston Exploration Co., ConocoPhillips and Shell Oil Company. In addition, our Executive Vice President and General Counsel, Clark R. Moore, has over 13 years of energy industry experience, and formerly served as acting general counsel of Erin Energy Corp. Several other members of the management team have also successfully helped develop similar companies with like kind asset profiles and technical operations at Sheridan Production Company, Trinity Operating LLC, Baker Hughes and Halliburton. We believe that our management team is highly qualified to identify, acquire and exploit energy resources in the U.S.

 

Our operations team has extensive experience in horizontal development of conventional assets in the Permian Basin at Sheridan Production Company and experience drilling and completing unconventional wells in the D-J Basin at Baker Hughes and Halliburton.

 

Our board of directors also brings extensive oil and gas industry experience, headed by our Chairman, John J. Scelfo, who brings nearly 40 years of experience in oil and gas management, finance and accounting, and who served in numerous executive-level capacities at Hess Corporation, including as Senior Vice President, Finance and Corporate Development, Chief Financial Officer, Worldwide Exploration & Producing, and as a member of Hess’ Executive Committee. In addition, our Board includes Ivar Siem, who brings over 50 years of broad experience from both the upstream and the service segments of the oil and gas industry, including serving as Chairman of Blue Dolphin Energy Company (OTCQX: BDCO), as Chairman and interim CEO of DI Industries/Grey Wolf Drilling, as Chairman and CEO of Seateam Technology ASA, and in various executive roles at multiple E&P and oil field service companies. Furthermore, our Board includes H. Douglas Evans, who brings over 40 years of experience in executive management positions with Gulf Interstate Engineering Company, one of the world's top pipeline design and engineering firms, including as its current Chairman and previously its President and Chief Executive Officer, and who is a past President and current Board member of the International Pipe Line and Offshore Contractors Association, current Chairman of its Strategy Committee, and an active member of the Pipeline Contractors Association. 

 

Significant acreage positions and drilling potential. As of December 31, 2018, we have accumulated interests in a total of approximately 23,441 net acres in our core Permian Basin Asset operating area, and 11,948 net acres in our core D-J Basin Asset operating area, both of which we believe represent significant upside potential. 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 Permian Basin Asset could contain over 195 potential net wells based on currently identified drilling locations using 120-acre spacing, and our D-J Basin Asset could contain up to approximately 149 potential net wells based on 80-acre spacing, providing us with a substantial drilling inventory for future years.

 

 

Marketing

 

We generally sell a significant portion of our oil and gas production to a relatively small number of customers, and during the year ended December 31, 2018, sales to one customer comprised 47% of the Company’s total oil and gas revenues. The Company is not dependent upon any one purchaser and believes that, if its primary customers are unable or unwilling to continue to purchase the Company’s production, there are a substantial number of alternative buyers for its production at comparable prices.

 

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 six-month crude oil purchase contract with a third party buyer, expiring June 30, 2019, pursuant to which the buyer purchases the crude oil produced from our 18 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 $6.60. The crude oil is purchased at the wellhead, and we do not bear any incremental transportation costs.

 

In connection with our September 2018 acquisition of certain Permian Basin assets from Ridgeway Arizona Oil Corp. (which we subsequently acquired), we also became a party to a month-to-month crude oil purchase contract with a third party buyer, pursuant to which the buyer purchases the crude oil produced from our 69 operated wells in our Permian Basin Asset, at a price per barrel equal to the average of the 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 $3.64. The crude oil is purchased at the wellhead, and we do not bear any incremental transportation costs.

 

Natural Gas. Our natural gas is sold under both long-term and short-term natural gas purchase agreements. Natural gas produced by us is sold at various delivery points at or near producing wells to both unaffiliated independent marketing companies and unaffiliated mid-stream companies. We receive proceeds from prices that are based on various pipeline indices less any associated fees for processing, location or transportation differentials.

 

We are 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 sell to DCP all gas produced from nine 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 NGLs, for a period of ten years ending December 1, 2021, after which time the contract reverts to a month-to-month basis and is subject to cancellation by either party at any time upon at least thirty (30) days advance notice.

 

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 sell to Sterling all gas produced from nine 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.

 

Oil and Gas Properties

 

We believe that our Permian Basin and D-J Basin assets represent among the most economic 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 Northwest Shelf of the Permian Basin in Chaves and Roosevelt Counties, New Mexico, and the Wattenberg and Wattenberg Extension areas of Weld County, Colorado in the D-J Basin. 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 2019 will be focused on the development of our Permian Basin Asset, and secondarily on development of our D-J Basin Asset. 

 

Unless otherwise noted, the following table presents summary data for our leasehold acreage in our core Permian Basin Asset and D-J Basin Asset as of December 31, 2018 and our drilling capital budget with respect to this acreage from January 1, 2019 to December 31, 2019. If commodity prices drop 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, non-operated project proposals, the success of our drilling results as the year progresses, and availability of capital (see “Part I” – “Item 1A. Risk Factors”.)

 

 

		Drilling Capital Budget January 1, 2019 - December 31, 2019
Current Core Assets:	Net Acres	Gross Wells (1)	Gross Costs per Well	Capital Cost to the Company (2)
Permian Basin Asset	23,441	12.0	$3,291,667	$39,500,000
D-J Basin Asset	11,948	3.0	$2,533,333	7,600,000
Facilities and Infrastructure (3)				5,000,000
Total Assets	35,389	15.0		$52,100,000

 

(1) Includes drilling and completion of (i) four 1.0 mile lateral wells in Phase One of the development of the Chaveroo Field in the Permian Basin Asset, (ii) seven 1.0 mile lateral wells and one 1.5 mile lateral well in the Chaveroo, Chaveroo NE, and Milnesand Fields of the Permian Basin Asset, and (iii) three gross horizontal wells in the D-J Basin Asset, subject to pending AFEs from other operators in the D-J Basin.

 

(2) Of the estimated $52.1 million total capital cost to the Company, the Company has raised $22 million to date and anticipates a portion to be funded by cash from operations.

 

(3) Estimated capital expenditures for construction of central facilities including tank batteries, injection lines, heater treaters, and SWD pumps in the Permian Basin Asset.

 

Our Core Areas

 

Permian Basin Asset

Effective September 1, 2018, we acquired 100% of the assets of Hunter Oil Company, which assets we refer to as our “Permian Basin Asset,” and which assets we hold through our wholly-owned subsidiary, PEDCO, with operations conducted through PEDCO’s wholly-owned operating subsidiaries, EOR Operating Company and Ridgeway Arizona Oil Corp. These interests are all located in Chaves and Roosevelt Counties, New Mexico, where we currently operate 337 gross (337 net) wells of which 51wells are active producers, 18 wells are active injectors, and one well is an active SWD. As of December 31, 2018, our Permian Basin Asset acreage is located in the areas shaded in yellow in the sectional map below.

 

 

It is currently estimated that there are approximately 110 billion barrels of oil-in-place in San Andres reservoirs across the Permian Basin (Research Partnership to Secure Energy for America (“RPSEA”) report dated December 21, 2015). The San Andres oilfields of the Northwest Shelf, Central Basin Platform and the Eastern Shelf are some of the largest oilfields within the Permian Basin. According to the U.S. Energy Information Administration (“EIA”), as of December 31, 2013, three oil fields that have produced from the San Andres formation were amongst the top 50 largest oilfields by reserves in the United States. The San Andres has been historically under-developed due to technological and economic limitations during early development. The San Andres is a dolomitic carbonate reservoir characterized as being highly-heterogenous with a multi-porosity system that typically shows significant oil saturation, but primary production often yields higher than normal water cut. While existing San Andres operators may ascribe different drivers for the water cut, San Andres production requires sufficient fluid removal, transportation and disposal in order to achieve higher oil cuts, through a network of on-site fluid storage and saltwater disposal systems.

Oil was originally trapped in the San Andres by three types of pre-Tertiary traps: Structural, Stratigraphic and Structurally enhanced Stratigraphic. Legacy fields exist where oil accumulated in these traps to form thick oil columns, referred to as Main Pay Zones (“MPZ”). Legacy San Andres fields lack sharp oil-water contacts creating secondary zones of increasing water saturation beneath the MPZ known as Transitional Oil Zones (“TOZ”) and Residual Oil Zones (“ROZ”). TOZs and ROZs also extend outside the historical boundaries of the legacy fields downdip to their structural limits. The vast majority of horizontal San Andres wells have been drilled in these TOZ and ROZ areas where vertical development is uneconomic.

The Company’s 23,441 net acres within the Chaveroo and Milnesand fields of Chaves and Roosevelt Counties, New Mexico offer a rare opportunity to drill infill horizontal wells targeting the higher oil-saturations of the MPZs. There are currently 337 wellbores within the leasehold, of which 51 are active producers and 18 are active injectors, and one is an active SWD. The remainder are shut-in wellbores with future potential utility for additional water injection, production reactivations, and behind-pipe recompletions. We currently own and operate two water handling facilities, one in each field, that have a current combined capacity of approximately 32,000 barrels of water per day (bbl/d).

 

 

Infill San Andres Well Performance (1)(2)(3)

Well Names		Operator		County		LateralLength (feet)		Peak IP30* (bopd)
Parker Minerals 4 22 H		Sheridan Production Co.		Ector		2,059		571
Parker Minerals 4 24H		Sheridan Production Co.		Ector		1,846		550
Earlene Fisher State 17 3H		Lime Rock Resources		Andrews		3,692		514
University 14Q 1H		Ring Energy		Andrews		4,951		509
Hamilton Unit 1H		Walsh Petroleum		Yoakum		4,061		433
Persephone 1H		Ring Energy		Andrews		7,067		402
Parker Minerals 4 21H		Sheridan Production Co.		Ector		3,187		351
Fisher 76C 6H		Lime Rock Partners		Andrews		5,461		316
Dean CSA 266H		Apache Corporation		Cochran		5,710		309
Brahaney Unit 202H		Apache Corporation		Yoakum		3,543		268
Captain Ahab Harpoon 1H		Pacesetter Energy		Andrews		5,097		264
Sooner 662 1H		Wishbone Energy Partners		Yoakum		4,101		249
Dean CSA 264H		Apache Corporation		Cochran		5,924		233
Dunbar 05 6H		Sheridan Production Co.		Gaines		4,513		225
Roberts Unit 261H		Apache Corporation		Yoakum		5,689		73

 

Source: IHS Markit

* Initial thirty (30) day production.

(1)Performance analysis of 15 horizontal wells within existing legacy vertical fields on 20-acre spacing or less.

(2) Production was normalized to a lateral length of 4,620’ to represent the length of Chaveroo & Milnesand PUD locations.

(3) Does not include the Transition Zone well performance to date.

 

D-J Basin Asset

 

We have grown our legacy D-J Basin Asset position to 11,948 net acres following the August 1, 2018 acquisition of 2,340 net acres held by production and four operated wells in Weld and Morgan Counties, Colorado, discussed above. 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 has an interest in 69 gross (21.5 net) wells and is currently the operator of 18 gross (16.2 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. The D-J Basin has seen a tremendous amount of growth in drilling activity in the past 12 months. D-J Basin operators are now drilling 16 to 24 horizontal wells per section in the Niobrara and Codell formations, utilizing the latest advances in completion design, frac stages, and frac intensity to obtain favorable well results. Notable non-operated partners leading the Niobrara revival are Noble Energy, Extraction Oil & Gas, SRC Energy and Bonanza Creek.

 

 

 

 

 

 

 

Production, Sales Price and Production Costs

 

We have listed below the total production volumes and total revenue net to the Company for the years ended December 31, 2018, 2017, and 2016:

 

	2018	2017	2016
Total Revenues	$4,523,000	$3,015,000	$3,968,000
Oil:
Total Production (Bbls)	70,395	52,260	92,966
Average sales price (per Bbl)	$59.00	$47.15	$36.98
Natural Gas:
Total Production (Mcf)	89,769	100,254	168,555
Average sales price (per Mcf)	$2.56	$2.97	$2.04
NGL:
Total Production (Mcf)	45,774	73,254	66,033
Average sales price (per Mcf)	$3.05	$3.46	$2.82
Oil Equivalents:
Total Production (Boe) (1)	92,985	81,178	132,064
Average Daily Production (Boe/d)	255	222	362
Average Production Costs (per Boe) (2)	$19.77	$13.62	$9.55

_________________________

 

(1)	Assumes 6 Mcf of natural gas and NGL equivalents to 1 barrel of oil.
(2)	Excludes workover costs, marketing, ad valorem and severance taxes.

 

As of December 31, 2018, production from our recent acquisition of the Chaveroo and Milnesand fields in the third quarter 2018 are the fields that each comprise 15% or more of our total proved reserves. In prior periods, the Wattenberg field is the only field that comprised 15% or more of our total proved reserves. The applicable production volumes from these fields for the years ended December 31, 2018, 2017, and 2016 is represented in the table below in total barrels (Bbls):

 

	2018	2017	2016
Chaveroo	3,631	-	-
Milnesand	2,917	-	-
Wattenberg	66,220	46,198	49,316

 

The following table summarizes our gross and net developed and undeveloped leasehold and mineral fee acreage at December 31, 2018:

 

	Total		Developed (1)		Undeveloped (2)
	Gross	Net	Gross	Net	Gross	Net
D-J Basin	205,994	11,948	183,370	9,388	22,624	2,560
Permian Basin	23,829	23,441	20,783	20,555	3,046	2,886
Total	229,823	35,389	204,153	29,943	25,670	5,446

 

(1) Developed acreage is the number of acres that are allocated or assignable to producing wells or wells capable of production.

 

(2) Undeveloped acreage is 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 includes proved reserves.

 

 

We believe we have satisfactory title, in all material respects, to substantially all of our producing properties in accordance with standards generally accepted in the oil and natural gas industry.

 

Total Net Undeveloped Acreage Expiration

 

In the event that production is not established or we take no action to extend or renew the terms of our leases, our net undeveloped acreage that will expire over the next three years as of December 31, 2018 is 49, 170 and 2,566 for the years ending December 31, 2019, 2020 and 2021, respectively. We expect to retain substantially all of our expiring acreage either through drilling activities, renewal of the expiring leases or through the exercise of extension options.

Well Summary

 

The following table presents our ownership in productive crude oil and natural gas wells at December 31, 2018. This summary includes crude oil wells in which we have a working interest:

 

	Gross	Net
Crude oil	106.0	80.5
Natural gas	-	-
Total*	106.0	80.5

 

*Includes crude oil wells from our Permian Basin Asset acquisition, which occurred in September 2018, and account for approximately 56% of our gross and 73% of our net totals, respectively.

 

Drilling Activity

 

We drilled wells or participated in the drilling of wells as indicated in the table below:

 

	2018		2017*		2016
	Gross	Net	Gross	Net	Gross	Net
Development
Productive	-	-	3	0.2	-	-
Dry	-	-	-	-	-	-
Exploratory
Productive	-	-	-	-	-	-
Dry	-	-	-	-	-	-

 

* Represents our participation in three non-operated wells which were completed during the applicable year.

 

The following table sets forth information about wells for which drilling was in progress or which were drilled but uncompleted at December 31, 2018, which are not included in the above table:

	Drilling In Progress		Drilled But Uncompleted
	Gross	Net	Gross	Net
Development wells	-	-	4	4.0
Exploratory wells	-	-	-	-
Total	-	-	4	4.0

 

Oil and Natural Gas Reserves

 

Reserve Information. For estimates of the Company’s net proved producing reserves of crude oil and natural gas, as well as discussion of the Company’s proved and probable undeveloped reserves, see “Part II” - “Item 8 Financial Statements and Supplementary Data” – “Supplemental Oil and Gas Disclosures (Unaudited)”. At December 31, 2018, the Company’s total estimated proved reserves were 12.4 million Boe of which 11.5 million Bbls were crude oil reserves, and 5.4 million Mcf were natural gas and NGL reserves.

 

 

Internal Controls. Clayton Riddle, our Vice President of Development (a non-executive position), is the technical person primarily responsible for our internal reserves estimation process (which are based upon the best available production, engineering and geologic data) and provides oversight of the annual audit of our year end reserves by our independent third party engineers. He has a Bachelor of Science degree in Petroleum Engineering with in excess of 15 years of oil and gas experience, including in excess of five years as a reserves estimator and is a member of the Society of Petroleum Engineers.

 

The preparation of our reserve estimates is in accordance with our prescribed procedures that include verification of input data into a reserve forecasting and economic software, as well as management review. Our reserve analysis includes, but is not limited to, the following:

 

 

Qualifications of Third Party Engineers. The technical person primarily responsible for the audit of our reserves estimates at Cawley, Gillespie & Associates, Inc. is W. Todd Brooker, who meets the requirements regarding qualifications, independence, objectivity, and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. Cawley, Gillespie & Associates, Inc. is an independent firm and does not own an interest in our properties and is not employed on a contingent fee basis. Reserve estimates are imprecise and subjective and may change at any time as additional information becomes available. Furthermore, estimates of oil and gas reserves are projections based on engineering data. There are uncertainties inherent in the interpretation of this data as well as the projection of future rates of production. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. A copy of the report issued by Cawley, Gillespie & Associates, Inc. is incorporated by reference into this report as Exhibit 99.1.

For more information regarding our oil and gas reserves, please refer to “Item 8 Financial Statements and Supplementary Data” – “Supplemental Oil and Gas Disclosures (Unaudited)”.

 

Material Events During the Year Ended December 31, 2018

 

SK Energy Note and Related Transactions

 

On June 26, 2018, the Company borrowed $7.7 million from SK Energy, which amount was evidenced by a Promissory Note dated June 25, 2018, in the amount of $7.7 million (the “SK Energy Note”). SK Energy is 100% owned and controlled by Dr. Simon Kukes, our Chief Executive Officer and director. The SK Energy Note accrues interest monthly at 8% per annum, payable quarterly (beginning October 15, 2018), in either cash or shares of common stock (at the option of the Company), or with the consent of SK Energy, such interest may be accrued and capitalized. If interest on the SK Energy Note is paid in common stock, SK Energy will be due that number of shares of common stock as equals the amount due divided by the average of the closing sales prices of the Company’s common stock for the ten trading days immediately preceding the last day of the calendar quarter prior to the applicable payment date, rounded up to the nearest whole share of common stock (the “Interest Shares”). The SK Energy Note is due and payable on June 25, 2021, but may be prepaid at any time, without penalty. Other than in connection with the Interest Shares. The SK Energy Note contains standard and customary events of default and upon the occurrence of an event of default, the amount owed under the SK Energy Note accrues interest at 10% per annum. As additional consideration for SK Energy agreeing to the terms of the SK Energy Note, the Company issued SK Energy 600,000 shares of common stock (the “Loan Shares”).

 

As part of the same transaction and as a required condition to closing the sale of the SK Energy Note, SK Energy entered into a Stock Purchase Agreement with Golden Globe Energy (US), LLC (“GGE”), the then holder of our outstanding 66,625 shares of Series A Convertible Preferred Stock (convertible pursuant to their terms into 6,662,500 shares of the Company’s common stock – 47.6% of the Company’s then outstanding shares post-conversion), pursuant to which on June 25, 2018, SK Energy purchased, for $100,000, all of the Series A Convertible Preferred Stock).

 

 

Debt Restructuring

 

On June 25, 2018, the Company entered into Debt Repayment Agreements (the “Repayment Agreements”, each described in greater detail below) with (i) the holders of our then outstanding Tranche A Secured Promissory Notes (“Tranche A Notes”) and Tranche B Secured Promissory Notes (“Tranche B Notes”), which the Company entered into pursuant to the terms of the May 12, 2016 Amended and Restated Note Purchase Agreement, (ii) RJ Credit LLC (“RJC”), which held a subordinated promissory note issued by the Company pursuant to that certain Note and Security Agreement, dated April 10, 2014, as amended (the “RJC Subordinated Note”), and (iii) MIE Jurassic Energy Corporation, which held a subordinated promissory note issued by the Company pursuant to that certain Amended and Restated Secured Subordinated Promissory Note, dated February 18, 2015, as amended (the “MIEJ Note”, and together with the “Tranche B Notes,” the “Junior Notes”), pursuant to which, on June 26, 2018, the Company retired all of the then outstanding Tranche A Notes, in the aggregate amount of approximately $7,260,000 in exchange for cash paid of $3,800,000 and all of the then outstanding Junior Notes, in the aggregate amount of approximately $70,299,000, in exchange for an aggregate amount of cash paid of $3,876,000.

 

Pursuant to the terms of the Repayment Agreement relating to the Tranche B Notes, in addition to the cash consideration due to the Tranche B Note holders, as described above, we agreed to grant to certain of the Junior Note holders their pro rata share of warrants to purchase an aggregate of 1,448,472 shares of common stock of the Company (the “Repurchase Warrants”). The Repurchase Warrants have a term of three years and an exercise price equal to $0.322, one (1) cent above the closing price of the Company’s common stock on June 26, 2018.

  

Additionally, on June 25, 2018, the Company entered into a Debt Repayment Agreement (the “Bridge Note Repayment Agreement”) with all of the holders of its convertible subordinated promissory notes issued pursuant to the Second Amendment to Secured Promissory Notes, dated March 7, 2014, originally issued on March 22, 2013 (the “Bridge Notes”), pursuant to which all of the holders, holding in aggregate $475,000 of outstanding principal amount under the Bridge Notes, agreed to the payment and full satisfaction of all outstanding amounts (including accrued interest and additional payment-in-kind) for 25% of the principal amounts owed thereunder, or an aggregate amount of cash paid of $119,000.

 

The result of the above transactions was a net reduction of liabilities of approximately $70,728,000 that were removed from the Company’s balance sheet as of June 25, 2018. For the year ended December 31, 2018, a gain on the settlement of all of these debts in the amount of $70,309,000 was recorded ($70,631,000, net of the expense related to the issuance of warrants to certain of the Tranche A Note holders with an estimated fair value of $322,000 based on the Black-Scholes option pricing model).

 

NYSE American Compliance

 

On June 27, 2018, the NYSE American (the “Exchange”) notified the Company that it had regained compliance with the NYSE American continued listing standards. Moving forward, the Company will be subject to the Exchange’s normal continued listing monitoring. In addition, in the event that the Company is again determined to be noncompliant with any of the Exchange’s continued listing standards within twelve (12) months of the notice, the Exchange will consider the relationship between the Company’s previous noncompliance and such new event of noncompliance and take appropriate action which may include implementing truncated compliance procedures or immediately initiating delisting proceedings.

 

Series A Convertible Preferred Stock Amendment and Conversion

 

In connection with the Stock Purchase Agreement, and immediately following the closing of the acquisition described in the Stock Purchase Agreement (discussed above), the Company and SK Energy, as the then holder of all of the then outstanding shares of Series A Convertible Preferred Stock, agreed to the filing of an Amendment to the Amended and Restated Certificate of Designations of PEDEVCO Corp. Establishing the Designations, Preferences, Limitations and Relative Rights of Its Series A Convertible Preferred Stock (the “Preferred Amendment”), which amended the designation of our Series A Convertible Preferred Stock (the “Designation”) to remove the beneficial ownership restriction contained therein, which prevented any holder of Series A Convertible Preferred Stock from converting such Series A Convertible Preferred Stock into shares of common stock of the Company if such conversion would result in the holder thereof holding more than 9.9% of the Company’s then outstanding common stock. The Company filed the Preferred Amendment with the Secretary of State of Texas on June 26, 2018.

 

 

On July 3, 2018, SK Energy converted all of the Series A Convertible Preferred Stock shares it acquired pursuant to the Stock Purchase Agreement with GGE, pursuant to their terms, into 6,662,500 shares of the Company’s common stock, representing 45.3% of the Company’s then outstanding common stock, and resulting in approximately 14,717,119 shares of the Company’s common stock being issued and outstanding. The issuance was deemed a change of control under applicable NYSE American rules and regulations, provided that such issuance was previously approved at the 2015 annual meeting of shareholders of the Company held on October 7, 2015. The conversion transaction constituted a change in control of the Company under applicable NYSE American rules and regulations. The shares of common stock issued upon conversion of the Series A Convertible Preferred Stock, together with the Loan Shares (issued to SK Energy on June 26, 2018) totaled 49.9% of our then outstanding shares of common stock, which shares are beneficially owned by SK Energy and Dr. Kukes.

 

Convertible Note Sales

 

On August 1, 2018, we raised $23,600,000 through the sale of $23,600,000 in Convertible Promissory Notes (the “Convertible Notes”). A total of $22,000,000 in Convertible Notes was purchased by SK Energy; $200,000 in Convertible Notes was purchased by an executive officer of SK Energy; $500,000 in Convertible Notes was purchased by a trust affiliated with John J. Scelfo, a director of the Company; $500,000 in Convertible Notes was purchased by an entity affiliated with Ivar Siem, our director, and J. Douglas Schick, who was appointed as the President of the Company on August 1, 2018; $200,000 in Convertible Notes was purchased by H. Douglas Evans, who was appointed as a member of the Board of Directors on September 27, 2018; and $200,000 in Convertible Notes were purchased by an unaffiliated party.

 

The Convertible Notes accrue interest monthly at 8.5% per annum, which interest is payable on the maturity date unless otherwise converted into our common stock as described below.

 

The Convertible Notes and all accrued interest thereon are convertible into shares of our common stock, from time to time after August 29, 2018, at the option of the holders thereof, at a conversion price equal to the greater of (x) $0.10 above the greater of the book value of the Company’s common stock and the closing sales price of the Company’s common stock on the date the Convertible Notes were entered into (the “Book/Market Price”) (which was $2.13 per share); (y) $1.63 per share; and (z) the VWAP Price, defined as the volume weighted average price (calculated by aggregate trading value on each trading day) of the Company’s common stock for the 20 trading days ending August 29, 2018, which price was $2.08 per share, and which conversion price is therefore $2.13 per share.

 

The conversion of the SK Energy Convertible Note is subject to a 49.9% conversion limitation (for so long as SK Energy or any of its affiliates holds such note), which prevents the conversion of any portion thereof into common stock of the Company if such conversion would result in SK Energy beneficially owning (as such term is defined in the Exchange Act)(“Beneficially Owning”) more than 49.9% of the Company’s outstanding shares of common stock.

 

The conversion of the other Convertible Notes is subject to a 4.99% conversion limitation, at any time such note is Beneficially Owned by any party other than (i) SK Energy or any of its affiliates (which is subject to the separate conversion limitation described above); (ii) any officer of the Company; (iii) any director of the Company; or (iv) any person which at the time of first obtaining Beneficial Ownership of the Convertible Note beneficially owns more than 9.99% of the Company’s outstanding common stock or voting stock (collectively (ii) through (iv), “Borrower Affiliates”). The Convertible Notes are not subject to a conversion limitation at any time they are owned or held by Borrower Affiliates.

 

The Convertible Notes are due and payable on August 1, 2021, but may be prepaid at any time, without penalty. The Convertible Notes contain standard and customary events of default and upon the occurrence of an event of default, the amount owed under the Convertible Notes accrues interest at 10% per annum.

 

The terms of the Convertible Notes may be amended or waived and such amendment or waiver shall be applicable to all of the Convertible Notes with the written consent of Convertible Note holders holding at least a majority in interest of the then aggregate dollar value of Convertible Notes outstanding.

 

Hunter Oil Purchase and Sale Agreement and Stock Purchase Agreement

 

On August 1, 2018, we (through our wholly-owned subsidiary PEDCO entered into a Purchase and Sale Agreement with Milnesand Minerals Inc., a Delaware corporation, Chaveroo Minerals Inc., a Delaware corporation, Ridgeway Arizona Oil Corp., an Arizona corporation (“RAOC”), and EOR Operating Company, a Texas corporation (“EOR”)(collectively “Seller”)(the “Purchase Agreement”). Pursuant to the Purchase Agreement, PEDCO agreed to acquire certain oil and gas assets described in greater detail below (the “Assets”) from the Seller in consideration for $18,500,000 (of which $500,000 is to be held back to provide for potential indemnification of PEDCO under the Purchase Agreement and Stock Purchase Agreement (described below), with one-half ($250,000) to be released to Seller 90 days after closing (which amount has been released to date) and the balance ($250,000) to be released 180 days after closing (provided that if a court of competent jurisdiction determines that any part of the amount withheld by PEDCO subsequent to 180 days after closing was in fact due to the Seller, PEDCO is required to pay Seller 200%, instead of 100%, of the amount so retained)).

 

 

On August 31, 2018, we closed the transactions contemplated by the Purchase Agreement and acquired the Assets for an aggregate of $18.5 million. The effective date of the acquisition was September 1, 2018.

 

The Purchase Agreement contains customary representations and warranties of the parties, and indemnification requirements (subject to a $25,000 aggregate minimum threshold and a $1,000,000 cap as to each of buyer and seller).  The Purchase Agreement allows PEDCO to audit the revenues and expenses of the Seller attributable to the Assets for the period of three years prior to the closing, among other things, and requires the Seller to provide assistance to PEDCO in connection with such audit for the first 180 days following closing (with such Seller’s reasonable costs associated with such audit being reimbursed by PEDCO at the rate of 150% of such costs).

 

The Assets represent approximately 23,441 net leasehold acres, current operated production, and all of Seller’s leases and related rights, oil and gas and other wells, equipment, easements, contract rights, and production (effective as of the effective date) as described in the Purchase Agreement. The Assets are located in the San Andres play in the Permian Basin situated in west Texas and eastern New Mexico, with all acreage and production 100% operated and substantially all acreage held by production. See also the more detailed description of the Assets under “Oil and Gas Properties”, below.

 

Also on August 1, 2018, PEDCO entered into a Stock Purchase Agreement with Hunter Oil Production Corp. (“Hunter Oil”). Pursuant to the Stock Purchase Agreement, which closed on August 31, 2018, PEDCO acquired all of the stock of RAOC and EOR (the “Acquired Companies”) for a net of $500,000 (an aggregate purchase price of $2,816,000, less $2,316,000 in restricted cash which the Acquired Companies are required to maintain as of the closing date). The Stock Purchase Agreement contains customary representations and warranties of the parties, post-closing adjustments, and indemnification requirements requiring Hunter Oil to indemnify us for certain items (subject to the $25,000 aggregate minimum threshold and $1,000,000 cap provided for in the Purchase Agreement) and us to indemnify Hunter Oil for certain items (which requirement does not include a threshold or cap).

  

On December 17, 2018 the Company and Seller agreed that the Company would pay to Seller $25,000 for all post-closing adjustments and post-closing support under the Purchase Agreement and accelerate the payment by the Company to Seller of the final $250,000 to be released 180 days after closing, which payments were made by the Company to Seller on December 17, 2018.

 

Condor Acquisition

 

 On August 1, 2018, Red Hawk, our wholly-owned subsidiary entered into a Membership Interest Purchase Agreement (the “Membership Purchase Agreement”) with MIE Jurassic Energy Corporation (“MIEJ”). Pursuant to the Membership Purchase Agreement, MIEJ sold Red Hawk 100% of the outstanding membership interests of Condor Energy Technology LLC (“Condor”) in consideration for $537,000. Condor owns approximately 2,340 net leasehold acres, 100% held by production (HBP), located in Weld and Morgan Counties, Colorado, with four operated producing wells. The Membership Purchase Agreement contains customary representations and warranties and provides that, as of the August 1, 2018 effective date, Red Hawk will assume responsibility for all costs, expenses and obligations outstanding and unpaid that are attributable to the properties as of the effective date and thereafter, and Red Hawk will also be entitled to all income and revenues received by Condor that are attributable to the properties, even if received by Condor with respect to oil and gas production prior to the effective date.

 

The Company previously owned 20% of Condor through PEDCO, along with MIEJ, which then held 80% of Condor, until February 19, 2015, when we and PEDCO entered into a Settlement Agreement (the “MIEJ Settlement Agreement”) with MIEJ, whereby, among other things, PEDCO sold its full 20% interest in Condor to MIEJ. Additionally, until June 25, 2018, when such amount was repaid pursuant to a Debt Repayment Agreement (described in greater detail in the Current Report on Form 8-K which we filed with the SEC on June 25, 2018), we owed approximately $6.4 million to MIEJ pursuant to the terms of a Secured Subordinated Promissory Note (the “MIEJ Note”).

 

Warrant Repurchase Agreements

 

On August 31, 2018, we entered into warrant repurchase agreements with certain of the Junior Note holders who received Repurchase Warrants, namely Senior Health Insurance Company of Pennsylvania, Principal Growth Strategies, LLC, and RJ Credit LLC (collectively, the “Warrant Holders”). Pursuant to the warrant repurchase agreements, the Company repurchased warrants to purchase an aggregate of 1,105,935 shares of the Company’s common stock (the shares of common stock issuable upon exercise of which such Repurchase Warrants, the “Warrant Shares”) held by the Warrant Holders, which warrants had a term of three years (through August 25, 2021) and an exercise price equal to $0.322 per share, as discussed above under “Debt Restructuring”. The Repurchase Warrants were repurchased for an aggregate of $1,095,000 or $0.99 per Warrant Share, which amount the Company paid to the Warrant Holders on September 17, 2018. Effective on the date of payment of the warrant purchase amounts, the Repurchase Warrants and the agreements evidencing such Repurchase Warrants were deemed to have been repurchased by the Company and cancelled. The Warrant Repurchase Agreements also included a release by which the Warrant Holders released the Company from any liability or claims associated with the Repurchase Warrants and certain of the Warrant Repurchase Agreements included a release by which we released the applicable Warrant Holders party thereto. The terms of the Warrant Repurchase Agreements were individually negotiated with each associated group of Warrant Holders.

 

 

Additional Convertible Note Sales

 

On October 25, 2018, the Company borrowed an additional $7.0 million from SK Energy, through the issuance of a convertible promissory note in the amount of $7.0 million (the “October 2018 Convertible Note”). The October 2018 Convertible Note accrues interest monthly at 8.5% per annum, which is payable on the maturity date, unless otherwise converted into shares of the Company’s common stock as described below. The October 2018 Convertible Note and all accrued interest thereon are convertible into shares of the Company’s common stock, at the option of the holder thereof, at a conversion price equal to $1.79 per share. Further, the conversion of the October 2018 Convertible Note is subject to a 49.9% conversion limitation which prevents the conversion of any portion thereof into common stock of the Company if such conversion would result in SK Energy or any of its affiliates beneficially owning more than 49.9% of the Company’s outstanding shares of common stock. The October 2018 Convertible Note is due and payable on October 25, 2021 but may be prepaid at any time without penalty.

 

Also on October 25, 2018, the Company and SK Energy agreed to convert an aggregate of $164,000 of interest accrued under the SK Energy Note from its effective date through September 30, 2018 into 75,118 shares of the Company’s common stock, based on a conversion price equal to $2.18 per share, pursuant to the conversion terms of the SK Energy Note.

 

Recent Events

 

January 2019 SK Energy Convertible Note

 

On January 11, 2019, the Company borrowed an additional $15.0 million from SK Energy, through the issuance of a convertible promissory note in the amount of $15.0 million (the “January 2019 Convertible Note”). The January 2019 Convertible Note accrues interest monthly at 8.5% per annum, which is payable on the maturity date, unless otherwise converted into shares of the Company’s common stock as described below. The January 2019 Convertible Note and all accrued interest thereon are convertible into shares of the Company’s common stock, at the option of the holder thereof, at a conversion price equal to $1.50 per share. Further, the conversion of the January 2019 Convertible Note is subject to a 49.9% conversion limitation which prevents the conversion of any portion thereof into common stock of the Company if such conversion would result in SK Energy or any of its affiliates beneficially owning more than 49.9% of the Company’s outstanding shares of common stock. The January 2019 Convertible Note Convertible Note is due and payable on January 11, 2022, but may be prepaid at any time without penalty.

 

Manzano Acquisition

 

On February 1, 2019, for consideration of $700,000, the Company completed an asset purchase from Manzano, LLC and Manzano Energy Partners II, LLC, whereby the Company purchased approximately 18,000 net leasehold acres, ownership and operated production from one horizontal well currently producing from the San Andres play in the Permian Basin, ownership of three additional shut-in wells and ownership of one saltwater disposal well.  

 

Convertible Notes Amendment and Conversion

 

On February 15, 2019, the Company and SK Energy agreed to amend the Convertible Notes and October 2018 Convertible Note described in Note 7, as well as the January 2019 Convertible Note, whereby each of the notes were amended to remove the conversion limitation that previously prevented SK Energy from converting any portion of the notes into common stock of the Company if such conversion would have resulted in SK Energy beneficially owning more than 49.9% of the Company’s outstanding shares of common stock

 

Immediately following the entry into the Amendment, on February 15, 2019, SK Energy elected to convert (i) all $15,000,000 of the outstanding principal and all $125,729 of accrued interest under the January 2019 Note into common stock of the Company at a conversion price of $1.50 per share as set forth in the January 2019 Note into 10,083,819 shares of restricted common stock of the Company, and (ii) all $7,000,000 of the outstanding principal and all $186,776 of accrued interest under the October 2018 Note into common stock of the Company at a conversion price of $1.79 per share as set forth in the October 2018 Note into 4,014,959 shares of restricted common stock of the Company, which shares in aggregate represented approximately 47.1% of the Company’s then 29,907,223 shares of issued and outstanding Company common stock after giving effect to the conversions.

 

 

SK Energy Note Amendment; Note Purchases and Conversion

 

On March 1, 2019, the Company and SK Energy entered into a First SK Energy Note Amendment to Promissory Note (the “SK Energy Note Amendment”) which amended the $7.7 million principal amount SK Energy Note, to provide SK Energy the right, at any time, at its option, to convert the principal and interest owed under such SK Energy Note, into shares of the Company’s common stock, at a conversion price of $2.13 per share. The SK Energy Note previously only included a conversion feature whereby the Company had the option to pay quarterly interest payments on the SK Energy Note in shares of Company common stock instead of cash, at a conversion price per share calculated based on the average closing sales price of the Company’s common stock on the NYSE American for the ten trading days immediately preceding the last day of the calendar quarter immediately prior to the quarterly payment date.

 

In addition, on March 1, 2019, the holders of $1,500,000 in aggregate principal amount of Convertible Promissory Notes issued by the Company on August 1, 2018 (the “August 2018 Notes”) sold their August 2018 Notes at face value plus accrued and unpaid interest through March 1, 2019 to SK Energy (the “August 2018 Note Sale”). Holders which sold their August 2018 Notes pursuant to the August 2018 Note Sale to SK Energy include an executive officer of SK Energy ($200,000 in principal amount of August 2018 Notes); a trust affiliated with John J. Scelfo, a director of the Company ($500,000 in principal amount of August 2018 Notes); an entity affiliated with Ivar Siem, a director of the Company, and J. Douglas Schick the President of the Company ($500,000 in principal amount of August 2018 Notes); and Harold Douglas Evans, a director of the Company ($200,000 in principal amount of August 2018 Notes).

 

Following the August 2018 Note Sale, the Company’s sole issued and outstanding debt was the (i) $7,700,000 in principal, plus accrued interest, under the SK Energy Note held by SK Energy, (ii) an aggregate of $23,500,000 in principal, plus accrued interest, under the August 2018 Notes and SK Energy $22 million Convertible Note held by SK Energy, and (iii) $100,000 in principal, plus accrued interest, under an August 2018 Note held by an unaffiliated holder (the “Unaffiliated Holder”).

 

Immediately following the effectiveness of the SK Energy Note Amendment and August 2018 Note Sale, on March 1, 2019, SK Energy and the Unaffiliated Holder elected to convert all $31,300,000 of outstanding principal and an aggregate of $1,462,818 of accrued interest under the SK Energy Note, SK Energy $22 million Convertible Note and August 2018 Notes into common stock of the Company at a conversion price of $2.13 per share (the “Conversion Price” and the “Conversions”) as set forth in the SK Energy Note, as amended, and the August 2018 Notes and SK Energy $22 million Convertible Note (collectively, the “Notes”), into an aggregate of 15,381,605 shares of restricted common stock of the Company (the “Conversion Shares”).

 

As a result of the Conversions, as of the date of the report, the Company now has no debt on its balance sheet and 45,288,828 shares of common stock issued and outstanding.

 

Regulation of the Oil and Gas Industry

 

All of our oil and gas 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.

 

At the state level, our operations in Colorado are regulated by the Colorado Oil & Gas Conservation Commission (“COGCC”) and our New Mexico operations are regulated by the Conservation Division of the New Mexico Energy, Minerals, and Natural Resources Department (regulates oil and gas operations) and New Mexico Environment Department (administers environmental protection laws). The Oil Conservation Division of the New Mexico Energy, Minerals and Natural Resources Department requires the posting of financial assurance for owners and operators on privately owned or state land within New Mexico in order to provide for abandonment restoration and remediation of wells.

 

  

The COGCC regulates oil and gas operators through rules, policies, written guidance, orders, permits, and inspections. Among other things, the COGCC enforces specifications regarding drilling, development, production, reclamation, enhanced recovery, safety, aesthetics, noise, waste, flowlines, and wildlife.  In recent years, the COGCC has amended its existing regulatory requirements and adopted new requirements with increased frequency. For example, in January 2016, the COGCC approved new rules that require local government consultation and certain best management practices for large-scale oil and natural gas facilities in certain urban mitigation areas. These rules also require operator registration and/or notifications to local governments with respect to future oil and natural gas drilling and production facility locations. In February 2018, the COGCC comprehensively amended its regulations for oil, gas, and water flowlines to expand requirements addressing flowline registration and safety, integrity management, leak detection, and other matters. The COGCC has also adopted or amended numerous other rules in recent years, including rules relating to safety, flood protection, and spill reporting. In December 2018, the COGCC approved new rules that require new oil and gas sites to be situated at least 1,000 feet away from school properties such as playgrounds and athletic fields.

 

We anticipate that the COGCC, the Conservation Division of the New Mexico Energy, Minerals, and Natural Resources Department and New Mexico Environment Department will continue to adopt new rules and regulations moving forward which will likely affect our oil and gas operations, and could make it more costly for our operations or limit our activities. We routinely monitor our operations and new rules and regulations which may affect our operations, to ensure that we maintain compliance.

 

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.

 

 

 

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 $1.2 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 trillion BTUs 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. 

 

 

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 $1.1 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.

 

 

Additionally, on January 14, 2019, in Martinez v. Colorado Oil and Gas Conservation Commission, the Colorado Supreme Court overturned a ruling by the Colorado Court of Appeals that held that the Colorado Oil & Gas Conservation Commission (“COGCC”) had held that the COGCC concluded that it lacked statutory authority to undertake a proposed rulemaking “to suspend the issuance of permits that allow hydraulic fracturing until it can be done without adversely impacting human health and safety and without impairing Colorado’s atmospheric resource and climate system, water, soil, wildlife, or other biological resources.” The Colorado Court of Appeals concluded that Colorado’s Oil and Gas Conservation Act mandated that oil and gas development “be regulated subject to the protection of public health, safety, and welfare, including protection of the environment and wildlife resources.” In the Colorado Supreme Court’s majority opinion, Justice Richard L. Gabriel wrote the COGCC is required first to “foster the development of oil and gas resources” and second “to prevent and mitigate significant environmental impacts to the extent necessary to protect public health, safety and welfare, but only after taking into consideration cost-effectiveness and technical feasibility.”

 

 

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. Stricter regulation of wastes generated during our operations 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.

 

 

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. In June 2015, the EPA and the U.S. Army Corps of Engineers (“Corps”) published a final rule to revise the definition of "waters of the United States" (“WOTUS”) for all Clean Water Act programs, but legal challenges to this rule followed and the rule was stayed nationwide by the U.S. Sixth Circuit Court of Appeals in October 2015. In response to this decision, the EPA and the Corps resumed nationwide use of the agencies' prior regulations defining the term "waters of the United States." However, in January 2018, the U.S. Supreme Court ruled that the rule revising the WOTUS definition must first be reviewed in the federal district courts, which could result in a withdrawal of the stay by the Sixth Circuit. In addition, the EPA has issued proposals to repeal the rule revising the WOTUS definition and to delay its implementation until 2020 to allow time for the EPA to reconsider the definition of the term "waters of the United States." To the extent this rule or a revised rule expands the scope of the CWA's jurisdiction, we could face increased costs and delays with respect to obtaining permits for dredge and fill activities in wetland areas in connection with any expansion activities. Federal and state regulatory agencies may impose substantial administrative, civil and criminal penalties as well as other enforcement mechanisms for non-compliance with discharge permits or other requirements of the CWA and analogous state laws and regulations, including spills and other non-authorized discharges. 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.

 

 

 

 

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, regulators in some states, including Colorado, have imposed more stringent permitting and operating requirements for produced water disposal wells. In Colorado, permit applications are reviewed specifically to evaluate seismic activity and, as of 2011, the state has required operators to identify potential faults near proposed wells, if earthquakes historically occurred in the area, and to accept maximum injection pressures and volumes based on fracture gradient as conditions to permit approval. Additionally, legal disputes may arise based on allegations that disposal well operations have caused damage to neighboring properties or otherwise violated state or federal rules regulating waste disposal. These developments could result in additional regulation, restriction on the use of injection wells by us or by commercial disposal well vendors whom we may use from time to time to dispose of wastewater, and increased costs of compliance, which could have a material adverse effect on our capital expenditures and operating costs, financial condition, and results of operations.

 

Air Emissions

 

The Clean Air Act (the “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 to obtain 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, in October 2015, the EPA issued a final rule under the CAA, lowering the National Ambient Air Quality Standard (“NAAQS”) for ground-level ozone from 75 parts per billion (“ppb”) for the 8-hour primary and secondary ozone standards to 70 ppb for both standards. In 2018, the EPA finalized the initial area designations for the 2015 ozone standard. Certain areas, such as the Denver Metro North Front Range (representing the counties (or parts thereof) South, East and North of Denver, Colorado), were designated as marginal (i.e., the lowest level of non-attainment) non-attainment (i.e., as an area that does not meet (or that contributes to ambient air quality in a nearby area that does not meet) the national primary or secondary ambient air quality standard for a NAAQS). The Denver Metro North Front Range area is currently under significant threat of being redesignated as a serious non-attainment area for ozone due to high levels detected in 2016 and 2017. Colorado is seeking an extension to the attainment date and the EPA has proposed to retroactively approve the requested extension by one year, to July 20, 2019. It is not likely that another one-year extension will be granted and the Denver Metro North Front Range area may be reclassified to serious non-attainment for 2020. Reclassification of areas or imposition of more stringent standards (including a lowering of the major source threshold for volatile organic compounds and oxides of nitrogen and the resulting increased likelihood that a source may be subject to Non-Attainment New Source Review) may make it more difficult to construct new or modified sources of air pollution in newly designated non-attainment areas. Also, states are expected to implement more stringent requirements as a result of this new final rule, which could apply to our operations. In addition, during the fall of 2016, EPA issued final Control Techniques Guidelines (“CTGs”) for reducing volatile organic compound emissions from existing oil and natural gas equipment and processes in ozone non-attainment areas, including the Denver Metro North Front Range Ozone 8-hour Non-Attainment area. In 2017, as part of the federal CTG process for oil and natural gas, Colorado undertook a stakeholder and rulemaking effort to compare the CTGs to existing Colorado requirements to ensure they meet applicable federal requirements, which resulted in revisions to Colorado's Regulation Number 7 (which relates to the control of ozone and hydrocarbons via oil and gas omissions). The new state regulations include more stringent air quality control requirements applicable to our operations. In another example, in June 2016, the EPA finalized a revised rule regarding criteria for aggregating multiple small surface sites into a single source for air-quality permitting purposes applicable to the oil and gas industry. This rule could cause small facilities, on an aggregate basis, to be deemed a major source, thereby triggering more stringent permitting requirements. Compliance with these or other air pollution control and permitting requirements have the potential to delay the development of oil and natural gas projects and increase our costs of development and production, which costs could have a material adverse impact on our business and results of operations.

 

 

 

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.

 

Federal agencies also have begun directly regulating emissions of methane, a GHG, from oil and natural gas operations. In June 2016, the EPA published the New Source Performance Standards (“NSPS”) Subpart OOOOa standards that require certain new, modified or reconstructed facilities in the oil and natural gas sector to reduce these methane gas and volatile organic compound emissions. These Subpart OOOOa standards expand previously issued NSPS published by the EPA in 2012 and known as Subpart OOOO, by using certain equipment-specific emissions control practices. However, in April 2017, the EPA announced that it would review this methane rule for new, modified and reconstructed sources and initiated reconsideration proceedings to potentially revise or rescind portions of the rule. In June 2017, the EPA also proposed a two-year stay of certain requirements of the methane rule pending the reconsideration proceedings; however, the rule remains in effect in the meantime. Similarly, in November 2016, the federal Bureau of Land Management (“BLM”) issued a final rule to reduce methane emissions by regulating venting, flaring, and leaks from oil and gas operations on federal and American Indian lands. California and New Mexico have challenged the rule in ongoing litigation. In addition, in April 2018, a coalition of states filed a lawsuit aiming to force EPA to establish guidelines for limiting methane emissions from existing sources in the oil and natural gas section; that lawsuit is currently pending.

 

On the international level, in December 2015, the United States joined the international community at the 21st Conference of the Parties of the United Nations Framework Convention on Climate Change in Paris, France that prepared an agreement requiring member countries to review and “represent a progression” in their intended nationally determined contributions, which set GHG emission reduction goals every five years beginning in 2020. This “Paris Agreement” was signed by the United States in April 2016 and entered into force in November 2016; however, this agreement does not create any binding obligations for nations to limit their GHG emissions, but rather includes pledges to voluntarily limit or reduce future emissions. In follow-up to an earlier announcement by President Trump, in August 2017, the U.S. Department of State officially informed the United Nations of the intent of the United States to withdraw from the Paris Agreement. The Paris Agreement provides for a four-year exit process beginning when it took effect in November 2016, which would result in an effective exit date of November 2020. The United States’ adherence to the exit process and/or the terms on which the United States may re-enter the Paris Agreement or a separately negotiated agreement are unclear at this time.

 

The adoption and implementation of any international, federal or state legislation or regulations that require reporting of GHG or otherwise limit emissions of GHG from our equipment and operations could result in increased costs to reduce emissions of GHG 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 and lower the value of our reserves, which devaluation could be significant. One or more of these developments could have a materially adverse effect on our business, financial condition and results of operations. Additionally, it should be noted that increasing concentrations of GHG 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. At this time, we have not developed a comprehensive plan to address the legal, economic, social or physical impacts of climate change on our operations. Finally, notwithstanding potential risks related to climate change, the International Energy Agency, an autonomous intergovernmental organization involved in international energy policy, estimates that global energy demand will continue to rise and will not peak until after 2040 and oil and gas will continue to represent a substantial percentage of global energy use over that time. However, recent activism directed at shifting funding away from companies with energy-related assets could result in limitations or restrictions on certain sources of funding for the energy sector.

 

 

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, in December 2016, the EPA released its final report on the potential impacts of hydraulic fracturing on drinking water resources, concluding that “water cycle” activities associated with hydraulic fracturing may impact drinking water resources under certain circumstances. Additionally, the EPA published in June 2016 an effluent limitations guideline final rule pursuant to its authority under the SDWA prohibiting the discharge of wastewater from onshore unconventional oil and natural gas extraction facilities to publicly owned wastewater treatment plants; asserted regulatory authority in 2014 under the SDWA over hydraulic fracturing activities involving the use of diesel and issued guidance covering such activities; 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 new or more stringent standards for performing 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, following years of litigation, the BLM rescinded the rule in December 2017. Additionally, 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.

 

At the state level, Colorado, where we conduct significant 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. Moreover, states could elect to prohibit high volume hydraulic fracturing altogether, following the approach taken by the State of New York in 2015. Also, 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 that, if approved, would allow revisions to the state constitution in a manner that would make such exploration and production activities in the state more difficult in the future. However, during the November 2016 voting process, one proposed amendment placed on the Colorado state ballot making it relatively more difficult to place an initiative on the state ballot was passed by the voters. As a result, there are more stringent procedures now in place for placing an initiative on a state ballot. In addition to state laws, local land use restrictions may restrict drilling or the hydraulic fracturing process and cities may adopt local ordinances allowing hydraulic fracturing activities within their jurisdictions but regulating the time, place and manner of those activities.

 

For example, on November 6, 2018, registered voters in the State of Colorado cast their ballots and rejected Proposition 112 (“Prop. 112”), with 55% of ballots cast against the measure. Prop. 112 would have created a rigid 2,500-foot setback from oil and gas facilities to the nearest occupied structure and other “vulnerable areas,” which included parks, ball fields, open space, streams, lakes and intermittent streams. It would have dramatically increased the amount of surface area off-limits to new energy development by 26 times and put 94% of private land in the top five oil and gas producing counties in the State of Colorado off-limits to new development. See further discussion in “Part I” – “Item 1A. Risk Factors.”

 

If new or more stringent federal, state or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where we operate, including, for example, on federal and American Indian lands, we could incur potentially significant added cost to comply with such requirements, experience delays or curtailment in the pursuit of exploration, development or production activities, and perhaps even be precluded from drilling wells.

 

 

 

 

Moreover, because most of our operations are conducted in two particular areas, the Permian Basin in New Mexico and the D-J Basin in Colorado, legal restrictions imposed in that area will have a significantly greater adverse effect than if we had our operations spread out amongst several diverse geographic areas. Consequently, in the event that local or state restrictions or prohibitions are adopted in the Permian Basin in New Mexico and/or the D-J Basin 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.

 

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 or 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 one or more agreements entered into by the U.S. Fish and Wildlife Service, the agency is required to make a determination on listing of numerous species as endangered or threatened under the ESA pursuant to specific timelines. 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.

 

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:

 

 

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, 2018, we employed 14 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.

 

 

 

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, NGL and Natural Gas Industry and Our Business

 

Declines in oil and, to a lesser extent, NGL and 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, NGL 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 93% of our estimated proved reserves as of December 31, 2018 were oil, our financial results are more sensitive to movements in oil prices. Since mid-2014, the price of crude oil has significantly declined, although the price of crude has subsequently recovered to current levels. 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, 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, 2018, the daily NYMEX WTI oil spot price ranged from a high of $77.41 per Bbl to a low of $44.48 per Bbl and the NYMEX natural gas Henry Hub spot price ranged from a high of $6.24 per MMBtu to a low of $2.49 per MMBtu.

  

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 $84,494,000 from the date of inception (February 9, 2011) through December 31, 2018. 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 and our subsequent periodic reports. 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.

 

Additionally, 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 required 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.

  

If this were to happen, we may be forced to scale back our business plan, sell or liquidate assets to satisfy outstanding debts, all of which could result in the value of our outstanding securities declining in value.

 

We may not be able to generate sufficient cash flow to meet any future debt service and other obligations due to events beyond our control.

 

Our ability to generate cash flows from operations, to make 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 future debt service and repayment obligations, we may be in default under the terms of the agreements governing our indebtedness, which could allow our creditors at that time to declare our outstanding indebtedness to be due and payable. 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 any of 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.

  

 

All of our crude oil, natural gas and NGLs production is located in the Permian Basin and the D-J Basin, making us vulnerable to risks associated with operating in only two geographic areas. In addition, we have a large amount of proved reserves attributable to a small number of producing formations.

 

Our operations are focused solely in the Permian Basin located in Chaves and Roosevelt Counties, New Mexico, and the D-J Basin of Weld and Morgan Counties, Colorado, which means our current producing properties and new drilling opportunities are geographically concentrated in those two areas. 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:

 

 

For example, bottlenecks in processing and transportation that have occurred in some recent periods in the Permian Basin and D-J Basin may negatively affect 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 Permian Basin and 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.

 

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:

 

 

 

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, NGLs and natural gas. Low oil or natural gas prices and the substantial volatility in these prices may adversely affect our business, financial condition and results of operations and our ability to meet our capital expenditure requirements and financial obligations.

 

The prices we receive for our oil, NGLs and natural gas heavily influence our revenue, profitability, cash flow available for capital expenditures, access to capital and future rate of growth. Oil, NGLs 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 commodities market has been volatile. For example, the price of oil fell dramatically starting in mid-2014 from a high of over $100 per barrel in June 2014 to lows below $30 per barrel in early 2016, and has only recently recovered to current levels, in each case based on West Texas Intermediate (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 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:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Declines in oil, NGL or natural gas prices would not only reduce our revenue, but could reduce the amount of oil, NGL and natural gas that we can produce economically. Should natural gas, NGL 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.

 

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.

 

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.

 

 

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:

 

 

 

 

 

 

 

 

In addition, future events, such as terrorist attacks, wars or combat peace-keeping missions, financial market disruptions, general economic recessions, oil and natural gas industry recessions, large company bankruptcies, accounting scandals, overstated reserves estimates by major public oil companies and disruptions in the financial and capital markets have caused financial institutions, credit rating agencies and the public to more closely review the financial statements, capital structures and earnings of public companies, including energy companies. Such events have constrained the capital available to the energy industry in the past, and such events or similar events could adversely affect our access to funding for our operations in the future.

 

If our revenues decrease as a result of lower oil and natural gas prices, operating difficulties, declines in reserves or for any other reason, we may have limited ability to obtain the capital necessary to sustain our operations at current levels, further develop and exploit our current properties or invest in additional exploration opportunities. Alternatively, a significant improvement in oil and natural gas prices or other factors could result in an increase in our capital expenditures and we may be required to alter or increase our capitalization substantially through the issuance of debt or equity securities, the sale of production payments, the sale or farm out of interests in our assets, the borrowing of funds or otherwise to meet any increase in capital needs. If we are unable to raise additional capital from available sources at acceptable terms, our business, financial condition and results of operations could be adversely affected. Further, future debt financings may require that a portion of our cash flows provided by operating activities be used for the payment of principal and interest on our debt, thereby reducing our ability to use cash flows to fund working capital, capital expenditures and acquisitions. Debt financing may involve covenants that restrict our business activities. If we succeed in selling additional equity securities to raise funds, at such time the ownership percentage of our existing stockholders would be diluted, and new investors may demand rights, preferences or privileges senior to those of existing stockholders. If we choose to farm-out interests in our prospects, we may lose operating control over such prospects.

  

Our oil and natural gas reserves are estimated and may not reflect the actual volumes of oil and natural gas we will receive, and significant inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.

 

The process of estimating accumulations of oil and natural gas is complex and is not exact, due to numerous inherent uncertainties. The process relies on interpretations of available geological, geophysical, engineering and production data. The extent, quality and reliability of this technical data can vary. The process also requires certain economic assumptions related to, among other things, oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. The accuracy of a reserves estimate is a function of:

 

 

 

 

 

 

The 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. 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.

 

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:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

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, and our wholly-owned subsidiary, PEDCO, which operates our Permian Basin Asset through its wholly-owned subsidiaries EOR and RAOC, also maintains a $10 million control of well insurance policy that covers its operations in New Mexico. 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.

  

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 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 states of New Mexico and 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 New Mexico and/or Colorado, natural disasters in New Mexico and/or Colorado, competition for equipment, services and materials available in, and access to infrastructure and markets in, these states.

 

Unless we replace our oil and natural gas reserves, our reserves and production will decline, which will 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, 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.

  

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.

 

 

If we complete acquisitions or enter into business combinations in the future, they may disrupt or have a negative impact on our business.

 

If we complete acquisitions or enter into business combinations in the future, funding permitting, we could have difficulty integrating the acquired companies’ assets, personnel and operations with our own. Additionally, acquisitions, mergers or business combinations we may enter into in the future could result in a change of control of the Company, and a change in the board of directors or officers of the Company. In addition, the key personnel of the acquired business may not be willing to work for us. We cannot predict the effect expansion may have on our core business. Regardless of whether we are successful in making an acquisition or completing a business combination, the negotiations could disrupt our ongoing business, distract our management and employees and increase our expenses. In addition to the risks described above, acquisitions and business combinations are accompanied by a number of inherent risks, including, without limitation, the following:

 

 

 

 

 

 

 

 

 

 

Our business could be severely impaired if and to the extent that we are unable to succeed in addressing any of these risks or other problems encountered in connection with an acquisition or business combination, many of which cannot be presently identified. These risks and problems could disrupt our ongoing business, distract our management and employees, increase our expenses and adversely affect our results of operations.

Any acquisition or business combination transaction we enter into in the future could cause substantial dilution to existing stockholders, result in one party having majority or significant control over the Company or result in a change in business focus of the Company.

We may incur indebtedness which could reduce our financial flexibility, increase interest expense and adversely impact our operations and our unit costs.

We currently have no outstanding indebtedness, but we may incur significant amounts of indebtedness in the future 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 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.

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.

 

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 Annual Report 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.

 

Potential conflicts of interest could arise for certain members of our management team and board of directors that hold management positions with other entities and our senior lender.

 

Dr. Simon Kukes, our Chief Executive Officer and member of our board of directors, J. Douglas Schick, our President, and Clark R. Moore, our Executive Vice President, General Counsel and Secretary, hold various other management positions with privately-held companies, some of which are involved in the oil and gas industry, and Dr. Simon Kukes is the principal of SK Energy LLC, the Company’s largest shareholder. Dr. Kukes also beneficially owns 82.4% of our voting securities. 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.

  

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 may 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.

 

 

We have limited control over activities on properties we do not operate.

 

We are not the operator on some of our properties located in our D-J Basin Asset, 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:

  

 

 

 

 

 

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.

 

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 the New York Mercantile Exchange (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 or hedging 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 derive and will derive in the future, substantially all of our revenues from the sale of our oil and natural gas to unaffiliated third-party purchasers, independent marketing companies and mid-stream companies. Any delays in payments from our purchasers caused by financial problems encountered by them will have an immediate negative effect on our results of operations.

 

Liquidity and cash flow problems encountered by our working interest co-owners or the third-party operators of our non-operated properties may prevent or delay the drilling of a well or the development of a project. Our working interest co-owners may be unwilling or unable to pay their share of the costs of projects as they become due. In the case of a farmout party, we would have to find a new farmout party or obtain alternative funding in order to complete the exploration and development of the prospects subject to a farmout agreement. In the case of a working interest owner, we could be required to pay the working interest owner’s share of the project costs. We cannot assure you that we would be able to obtain the capital necessary to fund either of these contingencies or that we would be able to find a new farmout party.

 

The calculated present value of future net revenues from our proved reserves will not necessarily be the same as the current market value of our estimated oil and natural gas reserves.

 

You should not assume that the present value of future net cash flows as included in our public filings is the current market value of our estimated proved oil and natural gas reserves. We generally base the estimated discounted future net cash flows from proved reserves on current costs held constant over time without escalation and on commodity prices using an unweighted arithmetic average of first-day-of-the-month index prices, appropriately adjusted, for the 12-month period immediately preceding the date of the estimate. Actual future prices and costs may be materially higher or lower than the prices and costs used for these estimates and will be affected by factors such as:

  

 

 

 

 

In addition, the 10% discount factor that is required to be used to calculate discounted future net revenues for reporting purposes under Generally Accepted Accounting Principles (“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.

 

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 continue to choose not to hedge our exposure to reductions in oil and natural gas prices by purchasing futures and/or by using other hedging strategies, we may be subject to a 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 in the D-J Basin of Colorado 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 and Gas Conservation Commission 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.

 

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.

 

New or amended environmental legislation or regulatory initiatives could result in increased costs, additional operating restrictions, or delays, or have other adverse effects on us.

 

The environmental laws and regulations to which we are subject change frequently, often to become more burdensome and/or to increase the risk that we will be subject to significant liabilities. New or amended federal, state, or local laws or implementing regulations or orders imposing new environmental obligations on, or otherwise limiting, our operations could make it more difficult and more expensive to complete oil and natural gas wells, increase our costs of compliance and doing business, delay or prevent the development of resources (especially from shale formations that are not commercial without the use of hydraulic fracturing), or alter the demand for and consumption of our products. Any such outcome could have a material and adverse impact on our cash flows and results of operations.

 

 

For example, in 2014, 2016 and 2018, opponents of hydraulic fracturing sought statewide ballot initiatives in Colorado that would have restricted oil and gas development in Colorado and could have had materially adverse impacts on us. One of the proposed initiatives would have made the vast majority of the surface area of the state ineligible for drilling, including substantially all of our planned future drilling locations. Although none of the proposed initiatives were passed, future initiatives are possible. Similarly, proposals are made from time to time to adopt new, or amend existing, laws and regulations to address hydraulic fracturing or climate change concerns through further regulation of exploration and development activities. Please read “Part I” – “Item 1 and 2. Business and Properties” — “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. We cannot predict the nature, outcome, or effect on us of future regulatory initiatives, but such initiatives could materially impact our results of operations, production, reserves, and other aspects of our business.

 

Proposed changes to U.S. tax laws, if adopted, could have an adverse effect on our business, financial condition, results of operations, and cash flows.

 

From time to time, legislative proposals are made that would, if enacted, result in the elimination of the immediate deduction for intangible drilling and development costs, the elimination of the deduction from income for domestic production activities relating to oil and gas exploration and development, the repeal of the percentage depletion allowance for oil and gas properties, and an extension of the amortization period for certain geological and geophysical expenditures. Such changes, if adopted, or other similar changes that reduce or eliminate deductions currently available with respect to oil and gas exploration and development, could adversely affect our business, financial condition, results of operations, and cash flows.

 

We may incur substantial costs to comply with the various federal, state, and local laws and regulations that affect our oil and natural gas operations, including as a result of the actions of third parties.

 

We are affected significantly by a substantial number of governmental regulations relating to, among other things, the release or disposal of materials into the environment, health and safety, land use, and other matters. A summary of the principal environmental rules and regulations to which we are currently subject is set forth in “Part I” – “Item 1 and 2. Business and Properties” — “Regulation of the Oil and Gas Industry” and “Regulation of Environmental and Occupational Safety and Health Matters.” Compliance with such laws and regulations often increases our cost of doing business and thereby decreases our profitability. Failure to comply with these laws and regulations may result in the assessment of administrative, civil, and criminal penalties, the incurrence of investigatory or remedial obligations, or the issuance of cease and desist orders.

 

The environmental laws and regulations to which we are subject may, among other things:

 

 

 

 

 

 

 

In addition, we could face liability under applicable environmental laws and regulations as a result of the activities of previous owners of our properties or other third parties. For example, over the years, we have owned or leased numerous properties for oil and natural gas activities upon which petroleum hydrocarbons or other materials may have been released by us or by predecessor property owners or lessees who were not under our control. Under applicable environmental laws and regulations, including The Comprehensive Environmental Response, Compensation, and Liability Act - otherwise known as CERCLA or Superfund, The Resource Conservation and Recovery Act (“RCRA”), and state laws, we could be held liable for the removal or remediation of previously released materials or property contamination at such locations, or at third-party locations to which we have sent waste, regardless of our fault, whether we were responsible for the release or whether the operations at the time of the release were lawful.

 

 

Compliance with, or liabilities associated with violations of or remediation obligations under, environmental laws and regulations could have a material adverse effect on our results of operations and financial condition.

 

Part of our strategy involves drilling in existing or emerging oil and gas 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 Permian Basin in Chaves and Roosevelt Counties, New Mexico, and the D-J Basin in Weld and Morgan Counties, 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. 

 

Part of our strategy involves using some of the latest available horizontal drilling and completion techniques. The results of our drilling in these plays are subject to drilling and completion technique risks, and results may not meet our expectations for reserves or production.

 

Many of our operations involve, and are planned to utilize, the latest drilling and completion techniques as developed by us and our service providers in order to maximize production and ultimate recoveries and therefore generate the highest possible returns. Risks we face while completing our wells include, but are not limited to, the inability to fracture stimulate the planned number of stages, the inability to run tools and other equipment the entire length of the well bore during completion operations, the inability to recover such tools and other equipment, and the inability to successfully clean out the well bore after completion of the final fracture stimulation. 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, limited access to gathering systems and takeaway capacity, and/or prices for crude oil, natural gas, and NGLs decline, then the return on our investment for a particular project may not be as attractive as we anticipated and we could incur material write-downs of oil and gas properties and the value of our undeveloped acreage could decline in the future.

 

Uncertainties associated with enhanced recovery methods may result in us not realizing an acceptable return on our investments in such projects.

 

Production and reserves, if any, attributable to the use of enhanced recovery methods are inherently difficult to predict. If our enhanced recovery methods do not allow for the extraction of crude oil, natural gas, and associated liquids in a manner or to the extent that we anticipate, we may not realize an acceptable return on our investments in such projects. In addition, as proposed legislation and regulatory initiatives relating to hydraulic fracturing become law, the cost of some of these enhanced recovery methods could increase substantially.

 

 

A significant amount of our D-J Basin Asset acreage must be drilled before lease expiration, generally within three to five years, and a significant amount of our Permian Basin Asset acreage must be drilled pursuant to governing agreements and leases, 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 in the D-J Basin 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. Currently 11,738 of our D-J Basin Asset acreage is held by production and not subject to lease expiration, with approximately 220 acres subject to lease expiration if these acres are not developed by us or other operators in whose wells we participate on such acreage prior to expiration. Similarly, currently 2,886 of our Permian Basin Asset acreage is held by production and not subject to lease expiration, with approximately 20,555 acres subject to lease or governing agreement expiration if these acres are not developed by us prior to expiration. 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.

 

Competition for hydraulic fracturing services and water disposal could impede our ability to develop our oil and gas 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 oil and gas 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 New Mexico or eastern Colorado, could materially and adversely affect our operations and the timeliness of executing our development plans within our budget.

 

The swaps regulatory and other provisions of the Dodd-Frank Act and the rules adopted thereunder and other regulations could adversely affect our ability to hedge risks associated with our business and our operating results and cash flows.

 

The provisions of The Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”) and the rules adopted and to be adopted by the Commodity Futures Trading Commission (“CFTC”), the SEC and other federal regulators establishing federal regulation of the over-the-counter (“OTC”) derivatives market and entities that participate in that market may adversely affect our ability to manage certain of our risks on a cost effective basis. Such laws and regulations may also adversely affect our ability to execute our strategies with respect to hedging our exposure to variability in expected future cash flows attributable to the future sale of our oil and gas.

 

We expect that our potential future hedging activities will remain subject to significant and developing regulations and regulatory oversight. However, the full impact of the various U.S. regulatory developments in connection with these activities will not be known with certainty until such derivatives market regulations are fully implemented and related market practices and structures are fully developed.

 

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 shale oil and natural gas production during both the drilling and hydraulic fracturing processes. Historically, we have been able to purchase water from local land owners for use in our operations. When drought conditions occur, governmental authorities may restrict the use of water subject to their jurisdiction for hydraulic fracturing to protect local water supplies. Both New Mexico and Colorado have relatively arid climates and experience drought conditions from time to time. If we are unable to obtain water to use in our operations from local sources or dispose of or recycle water used in operations, or if the price of water or water disposal increases significantly, we may be unable to produce oil and natural gas economically, which could have a material adverse effect on our financial condition, results of operations, and cash flows.

 

 

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.

 

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.

 

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.

  

 

A substantial percentage of our recently acquired New Mexico properties are undeveloped; therefore, the risk associated with our success is greater than would be the case if the majority of such properties were categorized as proved developed producing.

 

Because a substantial percentage of our recently acquired New Mexico properties are undeveloped, we will require significant additional capital to develop such properties before they may become productive. Further, because of the inherent uncertainties associated with drilling for oil and gas, some of these properties may never be developed to the extent that they result in positive cash flow. Even if we are successful in our development efforts, it could take several years for a significant portion of our undeveloped properties to be converted to positive cash flow.

  

Part of our strategy involves using certain of the latest available horizontal drilling and completion techniques, which involve additional risks and uncertainties in their application if compared to conventional drilling.

 

We plan to utilize some of the latest horizontal drilling and completion techniques as developed by us, other oil and gas exploration and production companies and our service providers. The additional risks that we face while drilling horizontally include, but are not limited to, the following:

 

 

 

 

 

 

Risks that we face while completing our wells include, but are not limited to, the following:

 

 

 

 

Prospects that we decide to drill may not yield oil or natural gas in commercially viable quantities.

 

Our prospects are in various stages of evaluation, ranging from prospects that are currently being drilled to prospects that will require substantial additional seismic data processing and interpretation. There is no way to predict in advance of drilling and testing whether any particular prospect will yield oil or natural gas in sufficient quantities to recover drilling or completion costs or to be economically viable. This risk may be enhanced in our situation, due to the fact that a significant percentage of our reserves is undeveloped. The use of seismic data and other technologies and the study of producing fields in the same area will not enable us to know conclusively prior to drilling whether oil or natural gas will be present or, if present, whether oil or natural gas will be present in commercial quantities. We cannot assure you that the analogies we draw from available data obtained by analyzing other wells, more fully explored prospects or producing fields will be applicable to our drilling prospects.

 

Over the past approximate nine months we have been significantly dependent on capital provided to us by SK Energy.

 

Since June 2018, SK Energy, which is owned and controlled by Dr. Simon Kukes, the Company’s Chief Executive Officer and director, has loaned us an aggregate of $51,700,000 to support our operations and for acquisitions, all of which loans were evidenced by promissory notes. The promissory notes generally had terms which were more favorable to us than we would have been able to obtain from third parties, including, generally favorable interest rates, no restrictions on further borrowing or financial covenants and no security interests in our assets. Such notes have to date been converted into 29.5 million shares of common stock at conversion prices which were above the then trading prices of our common stock. While SK Energy has verbally advised us that it intends to provide us additional funding as needed, nothing has been documented to date, and such future funding, if any, may not ultimately be provided on favorable terms, if at all. In the event that we are forced to obtain funding from parties other than SK Energy, such funding terms will likely not be as favorable to the Company as the funding provided by SK Energy, and may not be available in such amounts as previously provided by SK Energy. In the event SK Energy fails to provide us future funding, when and if needed, it could have a material adverse effect on our liquidity, results of operations and could force us to borrow funds from outside sources on less favorable terms than our prior debt.

 

 

Negative public perception regarding us and/or our industry could have an adverse effect on our operations.

Negative public perception regarding us and/or our industry resulting from, among other things, concerns raised by advocacy groups about hydraulic fracturing, waste disposal, oil spills, seismic activity, climate change, explosions of natural gas transmission lines and the development and operation of pipelines and other midstream facilities may lead to increased regulatory scrutiny, which may, in turn, lead to new state and federal safety and environmental laws, regulations, guidelines and enforcement interpretations. Additionally, environmental groups, landowners, local groups and other advocates may oppose our operations through organized protests, attempts to block or sabotage our operations or those of our midstream transportation providers, intervene in regulatory or administrative proceedings involving our assets or those of our midstream transportation providers, or file lawsuits or other actions designed to prevent, disrupt or delay the development or operation of our assets and business or those of our midstream transportation providers. These actions may cause operational delays or restrictions, increased operating costs, additional regulatory burdens and increased risk of litigation. Moreover, governmental authorities exercise considerable discretion in the timing and scope of permit issuance and the public may engage in the permitting process, including through intervention in the courts. Negative public perception could cause the permits we require to conduct our operations to be withheld, delayed or burdened by requirements that restrict our ability to profitably conduct our business.

Recently, activists concerned about the potential effects of climate change have directed their attention towards sources of funding for fossil-fuel energy companies, which has resulted in certain financial institutions, funds and other sources of capital restricting or eliminating their investment in energy-related activities. Ultimately, this could make it more difficult to secure funding for exploration and production activities.

Our business could be adversely affected by security threats, including cybersecurity threats.

We face various security threats, including cybersecurity threats to gain unauthorized access to our sensitive information or to render our information or systems unusable, and threats to the security of our facilities and infrastructure or third-party facilities and infrastructure, such as gathering and processing facilities, refineries, rail facilities and pipelines. The potential for such security threats subjects our operations to increased risks that could have a material adverse effect on our business, financial condition and results of operations. For example, unauthorized access to our seismic data, reserves information or other proprietary information could lead to data corruption, communication interruptions, or other disruptions to our operations.

Our implementation of various procedures and controls to monitor and mitigate such security threats and to increase security for our information, systems, facilities and infrastructure may result in increased capital and operating costs. Moreover, there can be no assurance that such procedures and controls will be sufficient to prevent security breaches from occurring. If any of these security breaches were to occur, they could lead to losses of, or damage to, sensitive information or facilities, infrastructure and systems essential to our business and operations, as well as data corruption, reputational damage, communication interruptions or other disruptions to our operations, which, in turn, could have a material adverse effect on our business, financial position and results of operations.

Weather and climate may have a significant and adverse impact on us.

Demand for crude oil and natural gas is, to a degree, dependent on weather and climate, which impacts, among other things, the price we receive for the commodities we produce and, in turn, our cash flows and results of operations. For example, relatively warm temperatures during a winter season generally result in relatively lower demand for natural gas (as less natural gas is used to heat residences and businesses) and, as a result, lower prices for natural gas production.

In addition, there has been public discussion that climate change may be associated with more frequent or more extreme weather events, changes in temperature and precipitation patterns, changes to ground and surface water availability, and other related phenomena, which could affect some, or all, of our operations. Our exploration, exploitation and development activities and equipment could be adversely affected by extreme weather events, such as winter storms, flooding and tropical storms and hurricanes, which may cause a loss of production from temporary cessation of activity or damaged facilities and equipment. Such extreme weather events could also impact other areas of our operations, including access to our drilling and production facilities for routine operations, maintenance and repairs, the installation and operation of gathering, processing, compression, storage and transportation facilities and the availability of, and our access to, necessary third-party services, such as gathering, processing, compression, storage and transportation services. Such extreme weather events and changes in weather patterns may materially and adversely affect our business and, in turn, our financial condition and 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 common stock is listed on the NYSE American 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 American, 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.

 

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 American, 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:

 

 

 

 

 

 

 

  

In addition, being a public company subject to these rules and regulations may require us to accept less director and officer liability insurance coverage than we desire or to incur substantial costs to obtain coverage. These factors could also make it more difficult for us to attract and retain qualified members of our board of directors, particularly to serve on our audit committee, and qualified executive officers.

 

 

Future sales of our common stock could cause our stock price to decline.

 

If our shareholders sell substantial amounts of our common stock in the public market, the market price of our common stock could decrease significantly. The perception in the public market that our shareholders might sell shares of our common stock could also depress the market price of our common stock. Up to $100,000,000 in total aggregate value of securities have been registered by us on a “shelf” registration statement on Form S-3/A (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 $18.1 million in securities have been sold by us under the prior Form S-3 which the December 2016 Form S-3 replaced, leaving approximately $81.9 million in securities which will be eligible for sale in the public markets from time to 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, pursuant to which the Company has, to date, sold an aggregate of 590,335 shares of common stock at prices ranging from $0.90 to $1.12 per share for an aggregate purchase price of $641,000, to which an underwriter’s fee of 3.0% was applied, leaving approximately $1.36 million remaining available for issuance thereunder, subject to limitation under the SEC’s “Baby Shelf Rules”. 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, 2018, there are outstanding stock options to purchase 890,232 shares of our common stock and outstanding warrants to purchase 1,216,685 shares of our 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 6,134,915 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.

  

We depend significantly upon the continued involvement of our present management.

We depend to a significant degree upon the involvement of our management, specifically, our Chief Executive Officer, Dr. Simon Kukes and our President, Mr. J. Douglas Schick. Our performance and success are dependent to a large extent on the efforts and continued employment of Dr. Kukes and Mr. Schick. We do not believe that Dr. Kukes or Mr. Schick could be quickly replaced with personnel of equal experience and capabilities, and their successor(s) may not be as effective. If Dr. Kukes, Mr. Schick, or any of our other key personnel resign or become unable to continue in their present roles and if they are not adequately replaced, our business operations could be adversely affected. We have no employment or similar agreement in place with Dr. Kukes. Mr. Schick is party to an employment agreement with us which has no stated term and can be terminated by either party without cause.

 

 

We have an active board of directors that meets several times throughout the year and is intimately involved in our business and the determination of our operational strategies. Members of our board of directors work closely with management to identify potential prospects, acquisitions and areas for further development. If any of our directors resign or become unable to continue in their present role, it may be difficult to find replacements with the same knowledge and experience and as a result, our operations may be adversely affected.

Dr. Simon Kukes, our Chief Executive Officer and a member of board of directors, beneficially owns approximately 82.4% of our common stock through SK Energy LLC, which gives him majority voting control over shareholder matters and his interests may be different from your interests.

 

Dr. Simon Kukes, our Chief Executive Officer and member of the board of directors, is the principal and sole owner of SK Energy LLC, which beneficially owns approximately 81.2% of our issued and outstanding common stock and Dr. Kukes, together with the ownership of SK Energy, beneficially owns approximately 82.4% of our issued and outstanding common stock. As such, Dr. Kukes can control the outcome of all 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. Subject to any fiduciary duties owed to the shareholders generally, while Dr. Kukes’ interests may generally be aligned with the interests of our shareholders, in some instances Dr. Kukes may have interests different than the rest of our shareholders, including but not limited to, future potential company financings in which SK Energy may participate, or his leadership at the Company. Dr. Kukes’ influence or control of our company as a shareholder 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. Because Dr. Kukes controls the shareholder vote, investors may find it difficult to replace Dr. Kukes (and such persons as he may appoint from time to time) as members of our management if they disagree with the way our business is being operated. Additionally, the interests of Dr. Kukes may differ from the interests of the other shareholders and thus result in corporate decisions that are adverse to other shareholders.

  

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 (such as the approval of our board of directors of Dr. Kukes’ ownership of the Company) or approval of the holders of at least two-thirds of our outstanding voting shares not beneficially owned by the affiliated shareholder.

 

Our board of directors can authorize the issuance of preferred stock, which could diminish the rights of holders of our common stock and make a change of control of our company more difficult even if it might benefit our shareholders.

 

Our board of directors is authorized to issue shares of preferred stock in one or more series and to fix the voting powers, preferences and other rights and limitations of the preferred stock. Shares of preferred stock may be issued by our board of directors without shareholder approval, with voting powers and such preferences and relative, participating, optional or other special rights and powers as determined by our board of directors, which may be greater than the shares of common stock currently outstanding. As a result, shares of preferred stock may be issued by our board of directors which cause the holders to have majority voting power over our shares, provide the holders of the preferred stock the right to convert the shares of preferred stock they hold into shares of our common stock, which may cause substantial dilution to our then common stock shareholders and/or have other rights and preferences greater than those of our common stock shareholders including having a preference over our common stock with respect to dividends or distributions on liquidation or dissolution.

 

Investors should keep in mind that the board of directors has the authority to issue additional shares of common stock and preferred stock, which could cause substantial dilution to our existing shareholders. Additionally, the dilutive effect of any preferred stock which we may issue may be exacerbated given the fact that such preferred stock may have voting rights and/or other rights or preferences which could provide the preferred shareholders with substantial voting control over us subsequent to the date of this Annual Report 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.

 

 

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 American (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, subject to certain exceptions, including sales in a public offerings and/or sales which are undertaken at or above the greater of the book value and/or market value of the issuer’s common stock on the date the transaction is agreed to be completed), 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 American and our failure to satisfy these criteria may result in delisting of our common stock.

 

Our common stock is currently listed on the NYSE American. 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 American 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 American 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 American’s listing requirements; if an issuer’s common stock sells at what the NYSE American 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 American (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 American, in its opinion, inadvisable.

  

If the NYSE American 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.

   

Due to the fact that our common stock is listed on the NYSE American, 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 American, 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.

 

 

If persons engage in short sales of our common stock, including sales of shares to be issued upon exercise of our outstanding warrants, the price of our common stock may decline.

 

Selling short is a technique used by a stockholder to take advantage of an anticipated decline in the price of a security. In addition, holders of options and warrants will sometimes sell short knowing they can, in effect, cover through the exercise of an option or warrant, thus locking in a profit. A significant number of short sales or a large volume of other sales within a relatively short period of time can create downward pressure on the market price of a security. Further sales of common stock issued upon exercise of our outstanding warrants could cause even greater declines in the price of our common stock due to the number of additional shares available in the market upon such exercise, which could encourage short sales that could further undermine the value of our common stock. Shareholders could, therefore, experience a decline in the values of their investment as a result of short sales of our common stock. 

  

ITEM 1B. UNRESOLVED STAFF COMMENTS.

 

None.

 

ITEM 3. LEGAL PROCEEDINGS

 

From time to time, we may become party to litigation or other legal proceedings that we consider to be a part of the ordinary course of our business. We are not currently involved in any legal proceedings that we believe could reasonably be expected to have a material adverse effect on our business, prospects, financial condition or results of operations. We may become involved in material legal proceedings in the future.

 

ITEM 4. MINE SAFETY DISCLOSURES.

 

Not applicable

  

 

PART II

 

ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES.

 

Market Information

 

Since September 10, 2013, the Company’s shares of common stock have traded on the NYSE American under the ticker symbol “PED.”

 

Shareholders

 

As of March 27, 2019, there were approximately 759 holders of record of our common stock, not including any persons who hold their stock in “street name”.

 

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

 

At December 31, 2018 and as of the date of this filing, the Company was authorized to issue 100,000,000 shares of preferred stock with a par value of $0.001 per share, of which 25,000,000 shares have been designated “Series A Convertible Preferred Stock”.

 

On February 23, 2015, the Company issued 66,625 Series A Convertible Preferred Stock shares to Golden Globe Energy (US), LLC (“GGE”) as part of the consideration paid for the acquisition of assets from GGE in February 2015. The grant date fair value of the Series A Convertible Preferred Stock was $28,402,000, based on a calculation using a binomial lattice option pricing model.

 

As part of the required conditions to closing the sale of the SK Energy Note as described further in “Part II” - “Item 8. Financial Statements and Supplementary Data” – “Note 8 Notes Payable”, SK Energy entered into a Stock Purchase Agreement with GGE, pursuant to which, SK Energy purchased, for $100,000, all of the Series A Convertible Preferred Stock.

 

In connection with the Stock Purchase Agreement, and immediately following the closing of the acquisition described in the Stock Purchase Agreement, the Company and SK Energy, as the then holder of all of the outstanding shares of Series A Convertible Preferred Stock, agreed to the filing of an Amendment to the Amended and Restated Certificate of Designations of PEDEVCO Corp. Establishing the Designations, Preferences, Limitations and Relative Rights of Its Series A Convertible Preferred Stock (the “Preferred Amendment”), which amended the designation of our Series A Convertible Preferred Stock (the “Designation”) to remove the beneficial ownership restriction contained therein, which prevented any holder of Series A Convertible Preferred Stock from converting such Series A Convertible Preferred Stock into shares of common stock of the Company if such conversion would result in the holder thereof holding more than 9.9% of the Company’s then outstanding common stock. The Company filed the Preferred Amendment with the Secretary of State of Texas on June 26, 2018.

 

The transactions affected pursuant to the Stock Purchase Agreement (i.e., the sale of the Series A Convertible Preferred Stock to a party other than GGE), triggered the automatic termination, pursuant to the terms of the Designation, of the right of GGE, upon notice to us, to appoint designees to fill up to two (2) seats on our Board of Directors, one of which must be an independent director as defined by applicable rules. As such, effective upon the closing of the Stock Purchase Agreement, our common stockholders have the right to appoint all members of our Board of Directors via plurality vote.  

 

 

On July 3, 2018, SK Energy converted all of its 66,625 outstanding shares of Series A Convertible Preferred Stock into 6,662,500 shares of the Company’s common stock.

 

As of December 31, 2018 and 2017, there were -0- and 66,625 shares of the Company’s Series A Convertible Preferred Stock outstanding, respectively.  There are no outstanding shares of preferred stock as of the date of this filing.

 

Stock Transfer Agent

 

Our stock transfer agent is First American Stock Transfer, Inc., located at 6201 15th Ave., Brooklyn, New York 11219.

 

Recent Sales of Unregistered Securities

 

There have been no sales of unregistered securities during the year ended December 31, 2018 and from the period from January 1, 2019 to the filing date of this report, which have not previously been disclosed in a Quarterly Report on Form 10-Q or in a Current Report on Form 8-K.

 

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 potential sale by us of up to $100 million in securities (common stock, preferred stock, warrants and units), subject to limitations under the SEC's “Baby Shelf Rules”, 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”) (of which $1.359 million remains available for issuance, subject to limitation under the SEC’s “Baby Shelf Rules”). 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 additional 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 American.

 

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 paid various expenses in connection with the offering, including reimbursing $30,000 of NSC’s legal fees, which has been paid. The Company has also agreed to provide NSC with customary indemnification and contribution rights.

 

The Company has used and intends to use the net proceeds from the offering to fund development and for working capital and general corporate purposes, including general and administrative purposes. The Company is not obligated to make any additional sales of common stock under the Sales Agreement, and no assurance can be given that the Company will sell any additional 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).

 

 

During the year ended December 31, 2018 and through the date of this filing, the Company made no sales of common stock under the Sales Agreement and 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). 

 

Issuer Purchases of Equity Securities

 

On August 31, 2018, we entered into Warrant Repurchase Agreements with certain former holders of the Company’s Tranche B Secured Promissory Notes, pursuant to which we repurchased and cancelled warrants to purchase an aggregate of 1,105,935 shares (the “Warrant Shares”) of the Company’s common stock for an aggregate of $1,095,000 or $0.99 per Warrant Share. 

 

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 oil and gas company focused on the development, acquisition and production of oil and natural gas assets where the latest in modern drilling and completion techniques and technologies have yet to be applied. In particular, we focus on legacy proven properties where there is a long production history, well defined geology and existing infrastructure that can be leveraged when applying modern field management technologies. Our current properties are located in the San Andres formation of the Permian Basin situated in West Texas and eastern New Mexico and in the Denver-Julesberg Basin in Colorado.  As of December 31, 2018, we held approximately 23,441 net Permian Basin acres located in Chaves and Roosevelt Counties, New Mexico, through PEDCO and approximately 11,948 net D-J Basin acres located in Weld and Morgan Counties, Colorado, through our wholly-owned operating subsidiary, Red Hawk. As of December 31, 2018, we held interests in 337 gross (337 net) wells in our Permian Basin Asset of which 51 are active producers, 18 are active injectors and one well is an active SWD, all of which are held by PEDCO and operated by its wholly-owned operating subsidiaries, and interests in 69 gross (21.5 net) wells in our D-J Basin Asset, of which 18 gross (16.2 net) wells are operated by Red Hawk and currently producing, 29 gross (5.2 net) wells are non-operated, and 22 wells have an after-payout interest.

 

Detailed information about our business plans and operations, including our core D-J Basin and Permian Basin Assets, is contained under “Part 1” — “Item 1 and 2. Business and Properties” above.

  

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:

 

 

Reserves

 

Our estimated net proved crude oil and natural gas reserves at December 31, 2018 and 2017 were approximately 12.4 million Boe and 3.7 million Boe, respectively. This reserve level increased approximately 8.7 million Boe or 244%, from 2017 to 2018. In 2018, we had a significant increase in reserves primarily due to our acquisition of the Permian Basin Assets in September 2018.

 

Using the average monthly crude oil price of $59.22 per Bbl and natural gas price of $1.56 per thousand cubic feet (Mcf) for the twelve months ended December 31, 2018, our estimated discounted future net cash flow (PV-10) before tax expenses for our proved reserves was approximately $181.3 million, of which approximately $173.3 million are proved undeveloped reserves. Total reserve value at December 31, 2018 represents an increase of approximately $150.0 million or 48% from a year earlier using the same SEC pricing and reserves methodology. The significant increase can be attributed to our acquisition noted above, which represents over 95% of our total reserves as of December 31, 2018. Oil, natural gas and NGL prices are market driven and have been historically volatile, and we expect that future prices will continue to fluctuate due to supply and demand factors, seasonality, and geopolitical and economic factors, and such volatility can have a significant impact on our estimates of proved reserves and the related PV-10 value.

 

The reserves as of December 31, 2018 were determined in accordance with standard industry practices and SEC regulations by the licensed independent petroleum engineering firm of Cawley, Gillespie & Associates, Inc. A large portion of the proved undeveloped crude oil reserves are associated with the Permian Basin formation. Although these hydrocarbon quantities have been determined in accordance with industry standards, they are prepared using the subjective judgments of the independent engineers, and may actually be more or less.

 

Oil and Natural Gas Sales Volumes

 

During the year ended December 31, 2018, our net crude oil and natural sales volumes increased to 92,985 Bbls or 255 Bopd from 81,178 Bbls, or 222 Bopd, a 15% increase over the previous fiscal year. The production increase is primarily related to the Company’ acquisition of oil and gas properties in third quarter of 2018.

 

Significant Capital Expenditures

 

The table below sets out the significant components of capital expenditures for the year ended December 31, 2018. There were no other significant expenditures in 2017 (in thousands):

 

	2018
Capital Expenditures
Leasehold Acquisitions (1)	$18,849
Property Acquisitions (1)	2,181
Drilling and Facilities (1)	8,933
Other (2)	1,928
Total	$31,891

 

 

 

Market Conditions and Commodity Prices

 

Our financial results depend on many factors, particularly the price of natural gas and crude oil and our ability to market our production on economically attractive terms. Commodity prices are affected by many factors outside of our control, including changes in market supply and demand, which are impacted by weather conditions, inventory storage levels, basis differentials and other factors. As a result, we cannot accurately predict future commodity prices and, therefore, we cannot determine with any degree of certainty what effect increases or decreases in these prices will have on our production volumes or revenues. In addition to production volumes and commodity prices, finding and developing sufficient amounts of natural gas and crude oil reserves at economical costs are critical to our long-term success. We expect prices to remain volatile for the remainder of the year. For information about the impact of realized commodity prices on our natural gas and crude oil and condensate revenues, refer to “Results of Operations” below.

Results of Operations

 

The following discussion and analysis of the results of operations for each of the two fiscal years in the period ended December 31, 2018 should be read in conjunction with the consolidated financial statements of PEDEVCO Corp. and notes thereto included herein (see “Item 8. Financial Statements and Supplementary Data”).

 

We reported net income for the year ended December 31, 2018 of $53.6 million, or $4.80 per share, compared to net loss for the year ended December 31, 2017 of $36.4 million or ($6.22) per share. The increase in net income was primarily due to the recognition of $70.3 million in gain on debt restructuring in 2018, and the effects of a $19.0 million impairment of our oil and gas properties in 2017. Excluding these two significant transactions, our net loss would have decreased by $0.7 million, mainly as result of a decrease of $5.1 million in interest expense incurred prior to our debt restructuring, offset by a decrease in our operating margin of $4.4 million, as a result of additional well and depletion costs from our acquisitions, when comparing the current period to the prior period.

 

Net Revenues

 

The following table sets forth the revenue and production data for the years ended December 31, 2018 and 2017:

 

				%
	2018	2017	Increase (Decrease)	Increase (Decrease)
Sale Volumes:
Crude Oil (Bbls)	70,395	52,260	18,135	35%
Natural Gas (Mcf)	89,769	100,254	(10,485)	(10%)
NGL (Mcf)	45,774	73,254	(27,480)	(38%)
Total (Boe)	92,985	81,178	11,807	15%
Crude Oil (Bbls per day)	193	143	50	35%
Natural Gas (Mcf per day)	246	275	(29)	(11%)
NGL (Mcf per day)	125	201	(76)	(38%)
Total (Boe per day)	255	222	33	15%
Average Sale Price:
Crude Oil ($/Bbl)	$59.00	$47.15	$11.85	25%
Natural Gas($/Mcf)	2.56	2.97	(0.41)	(14%)
NGL ($/Mcf)	3.05	3.46	(0.41)	(12%)
Net Operating Revenues (In thousands):
Crude Oil	$4,153	$2,464	$1,689	69%
Natural Gas	230	298	(68)	(23%)
NGL	140	253	(113)	(45%)
Total Revenues	$4,523	$3,015	$1,508	50%