Preliminary Offering Circular Subject to Completion Dated August 9, 2017

An offering statement pursuant to Regulation A relating to these securities has been filed with the U.S. Securities and Exchange Commission, which we refer to as the Commission. Information contained in this Preliminary Offering Circular is subject to completion or amendment. These securities may not be sold nor may offers to buy be accepted before the offering statement filed with the Commission is qualified. This Preliminary Offering Circular shall not constitute an offer to sell or the solicitation of an offer to buy nor may there be any sales of these securities in any state in which such offer, solicitation or sale would be unlawful before registration or qualification under the laws of any such state. We may elect to satisfy our obligation to deliver a Final Offering Circular by sending you a notice within two business days after the completion of our sale to you that contains the URL where the Final Offering Circular or the offering statement in which such Final Offering Circular was filed may be obtained.

          Shares

Energy Hunter Resources, Inc.
Common Stock

This offering circular (the “Offering Circular”) relates to an initial public offering of our common stock, par value $0.0001 per share (the “Common Stock”).

Prior to this offering, there has been no public market for our securities. The initial public offering price is expected to be between $    and $    per share. The maximum amount of securities expected to be sold in this offering is          . We have applied to list our Common Stock on the NASDAQ Capital Market (the “NASDAQ”) under the symbol “EHR”.

Immediately after this offering, we will acquire approximately 9,413 net acres within the San Andres formation in the Northwest Shelf of the West Texas Permian Basin (“San Andres Acreage”) pursuant to a Contribution and Sale Agreement (“Contribution Agreement”) with the current owner of the acreage and associated wells. We will use a substantial portion of the net proceeds of this offering to finance this acquisition and to fund new horizontal drilling on both the San Andres Acreage and the Eagle Ford Acreage (as defined herein). See “Recent Events – San Andres Acreage Acquisition” and “Use of Proceeds.”

We are an “emerging growth company” as that term is used in the Jumpstart Our Business Startups Act of 2012, and as such, we have elected to take advantage of certain reduced public company reporting requirements for this Offering Circular and future filings. See “Risk Factors” and “Offering Circular Summary—Implications of Being an ‘Emerging Growth Company’.” This Offering Circular follows the disclosure format of Part I of Form S-1 pursuant to the general instructions of Part II(a)(1)(ii) of Form 1-A.

These securities are speculative and involve a high degree of risk. You should purchase shares of Common Stock only if you can afford the complete loss of your investment. See “Risk Factors” beginning on page 12 for a discussion of risks you should consider before buying shares of our Common Stock.

The offering is being underwritten on a firm commitment basis. We have granted the underwriters an option (the “Option”) to buy up to an additional           shares of Common Stock, provided that the Option will be exercisable only to the extent that its exercise does not cause the aggregate amount of the offering to exceed $50 million. The underwriters may exercise the Option at any time and from time to time during the 30-day period from the date of this Offering Circular.

Delivery of the shares of Common Stock will be made on or about          , 2017.

The Commission does not pass upon the merits of or give its approval to any securities offered or the terms of the offering, nor does it pass upon the accuracy or completeness of any offering circular or other solicitation materials. These securities are offered pursuant to an exemption from registration with the Commission; however, the Commission has not made an independent determination that the securities offered are exempt from registration.

The date of this Offering Circular is          , 2017.

San Andres Acreage – Cochran County, TX⁽¹⁾

TABLE OF CONTENTS

Industry and Market Data

The market data and certain other statistical information used throughout this Offering Circular are based on independent industry publications, government publications and other published independent sources. Although we believe these third-party sources are reliable as of their respective dates, neither we nor the underwriters have independently verified the accuracy or completeness of this information. Some data is also based on our good faith estimates. The industry in which we operate is subject to a high degree of uncertainty and risk due to a variety of factors, including those described in the section entitled “Risk Factors.” These and other factors could cause results to differ materially from those expressed in these publications.

Oil and Natural Gas Reserves Data

We present oil and natural gas reserve data in barrels of oil equivalent, or Boe, amounts. For purposes of computing such units, a conversion rate of one Boe to six Mcf of natural gas or one Bbl of oil is used. The conversion ratio is an energy content correlation and does not reflect a volume or price relationship between the commodities. Boe amounts may be misleading, particularly if considered in isolation.

Our estimated net proved undeveloped and probable undeveloped reserves associated with our properties in the Eagle Ford Shale disclosed in this Offering Circular are based on reserve reports prepared by Netherland, Sewell & Associates, Inc. (“NSAI”), independent petroleum engineers. The estimated net proved producing reserves associated with the San Andres Acreage acquisition disclosed in this Offering Circular are based on reserve reports prepared by Mire & Associates, Inc. (“Mire”), independent petroleum engineers. The reserve reports of NSAI and Mire are included elsewhere in this Offering Circular. See “Business—Oil and Natural Gas Data.” Unless otherwise indicated, estimates of proved producing, proved non-producing, proved undeveloped and probable undeveloped reserves and future net revenues therefrom are presented in accordance with the rules and definitions promulgated by the Securities and Exchange Commission (“Commission”).

The information contained in this Offering Circular relating to our reserves and future net revenues represent estimates only and constitute forward-looking statements that are subject to risks and uncertainties. See “Risk Factors” and “Cautionary Statement Regarding Forward-Looking Statements.”

Trademarks and Trade Names

From time to time, we own or have rights to various trademarks, service marks and trade names that we use in connection with the operation of our business. This Offering Circular may also contain trademarks, service marks and trade names of third parties, which are the property of their respective owners. Our use or display of third parties’ trademarks, service marks, trade names or products in this Offering Circular is not intended to, and does not imply, a relationship with us or an endorsement or sponsorship by or of us. Solely for convenience, the trademarks, service marks and trade names referred to in this Offering Circular may appear without the ®, TM or SM symbols, but such references are not intended to indicate, in any way, that we will not assert, to the fullest extent under applicable law, our rights or the right of the applicable licensor to these trademarks, service marks and trade names.

Additional Information

You should rely only on the information contained in this Offering Circular. We have not authorized anyone to provide you with additional information or information different from that contained in this Offering Circular filed with the Commission. We take no responsibility for, and can provide no assurance as to the reliability of, any other information that others may give you. We are offering to sell, and seeking offers to buy, shares of our Common Stock only in jurisdictions where offers and sales are permitted. The information contained in this Offering Circular is accurate only as of the date of this document, regardless of the time of delivery of this Offering Circular or any sale of shares of our Common Stock. Our business, financial condition, results of operations, and prospects may have changed since that date.

OFFERING CIRCULAR SUMMARY

This summary highlights information contained elsewhere in this Offering Circular and does not contain all of the information that may be important to you. You should read this entire Offering Circular carefully, including the sections entitled “Risk Factors” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our historical financial statements and related notes included elsewhere in this Offering Circular. In this Offering Circular, unless otherwise noted, the terms “the Company,” “we,” “us,” and “our” refer to Energy Hunter Resources, Inc. The information presented in this Offering Circular assumes (i) an initial public offering price of $ per share (the midpoint of the price range set forth on the cover of this Offering Circular) and (ii) unless otherwise indicated, that the underwriters do not exercise their option to purchase additional shares of Common Stock.

This Offering Circular, including any supplement to this Offering Circular, includes “forward-looking statements.” To the extent that the information presented in this Offering Circular discusses financial projections, information or expectations about our business plans, results of operations, products or markets, or otherwise makes statements about future events, such statements are forward-looking. Such forward-looking statements can be identified by the use of words such as “should”, “may”, “intends”, “anticipates”, “believes”, “estimates”, “projects”, “forecasts”, “expects”, “plans” and “proposes”. Although we believe that the expectations reflected in these forward-looking statements are based on reasonable assumptions, there are a number of risks and uncertainties that could cause actual results to differ materially from such forward-looking statements. These include, among others, the cautionary statements in the “Risk Factors” section and the “Management’s Discussion and Analysis of Financial Condition and Results of Operations” section in this Offering Circular.

This Offering Circular includes certain terms commonly used in the oil and natural gas industry, which are defined in Annex A to this Offering Circular, “Glossary of Oil and Natural Gas Terms.”

Business Overview

Energy Hunter is an independent oil and gas company with its core focus on the acquisition, drilling and production of oil and natural gas properties and prospects within the West Texas Permian Basin and the South Texas Eagle Ford Shale Trend. We were founded in May 2016 by our Chairman and Chief Executive Officer, Gary C. Evans, a successful oil and natural gas operator and company builder with more than 35 years of energy industry experience. Our management team has a proven track record within each of these core geographic focus areas and utilizes the most recent horizontal drilling and fracture completion technology available today in order to optimize the development of hydrocarbons from these areas. Our primary mission is to target these areas and use our expertise to carefully select properties or prospects with attractive return potential to take advantage of what we believe to be a meaningful growth opportunity in an effort to deliver significant value to our shareholders.

Following the closing of the San Andres Acreage acquisition, our core properties and focus will be located in Cochran County, Texas within the San Andres formation in the Northwest Shelf of West Texas. See “Offering Circular Summary – Recent Events – San Andres Acreage.” In addition, we are focused on certain areas of the Eagle Ford Shale Trend within South Texas, particularly Karnes County, Texas, the most productive oil producing region in the Eagle Ford Shale.

The San Andres formation is one of the most prolific conventional vertical plays in the United States and is productive throughout the Permian Basin. Over the past 50 years, San Andres production has made up approximately 40% of total oil production from the Permian Basin—12 BBbl (and an additional 2 Tcf of gas) of the total 30 BBbl produced. However, this highly successful conventional play is now being re-developed into one of the best low-cost horizontal plays in the country with vertical recoveries having only produced 10-20% of primary reserves. In recent years, the introduction of horizontal drilling and multi-stage fracturing and completion techniques gives the play some of the best economic returns in the country. The San Andres formation has many of the same economic characteristics as the active and highly competitive re-development of the Spraberry and Wolfcamp formations within the Midland and Delaware Basins of West Texas and Southeast New Mexico, but in some cases, at a fraction of the drilling and completion costs compared to nearby formations. Each of these formations has large volumes of oil and gas in place, but hydrocarbons are not easily produced by conventional methods. Operators are now utilizing horizontal drilling and completion technologies to fully develop and/or re-develop these vast remaining reserves, thus creating an economically valuable opportunity.

Historically, the conventional vertical development of a San Andres field took many wells at 10, 20 and 40 acre spacing, which took 50+ years of production utilizing water and/or CO₂ secondary and tertiary recovery techniques

in order to effectively drain the reservoir. Currently, a single 1 to 1.5 mile horizontal lateral, completed with multi-stage hydraulic fracturing techniques better stimulates the rock across the entire lateral section and results in higher daily production and greater ultimate reserve recovery with more efficient drainage. Horizontal drilling enables the re-development of these fields much more quickly and efficiently thereby increasing internal rates of return (IRRs) on capital deployed.

Based upon results from new drilling techniques and industry well performance, the following key drivers can determine ultimate well performance in the San Andres:

To date, there exist only a few publicly-traded exploration and production companies active in the San Andres horizontal play as well as a large number of privately held independent operators. This unique area, its existing infrastructure, combined with numerous horizontal drilling locations, highly profitable recompletion opportunities, and the ability for horizontal re-development of the substantial reserves in place, provide significant growth opportunities for our shareholders.

Immediately after this offering, we will acquire the San Andres Acreage (approximately 9,413 net acres) within the prolific Slaughter-Levelland Field, which has produced over 2.3 BBbls of oil and 1.7 Tcf of gas. Upon closing, this acquisition will be effective for economic purposes as of June 1, 2017. See “Recent Events – San Andres Acreage Acquisition.” This acreage is held by production (“HBP”), which allows us to carefully re-complete and re-develop this property in a timely and efficient manner (“Phase 1”). In addition, the property has approximately 160 wells, full-field electricity, production facilities, significant active infrastructure and current salt water handling capability. We believe that there are 31 potential horizontal well locations to drill on the acreage to be acquired, assuming four laterals per 640-acre spacing.

During the quarter ended June 30, 2017, average daily production from the San Andres Acreage was approximately 82 BOPD, all of which was oil produced from 91 vertical wells operating on the acreage. Using the proceeds of this offering, we have immediate plans within the third and fourth quarters of 2017 to begin the re-completion program of the existing vertical wells in an effort to increase existing production under Phase 1. At the same time, we will also begin selecting horizontal well locations for our first two wells prior to year-end 2017 as part of the horizontal re-development (“Phase 2”) for the San Andres Acreage. Nearby and adjacent horizontal laterals have out-produced existing vertical wells.

Dominated by privately-owned E&P companies, many of the operators in the San Andres have been funded by leading private equity firms seeking to capture the exceptionally strong economics of the play. Approximately 164 horizontal San Andres wells have been drilled since January 2014. Given the increased activity and success we are seeing in the San Andres, some of the private equity backed companies in the play have recently been willing to monetize their position by selling for cash, equity, or a combination of both, to larger, publicly-traded companies. Pending such transactions and higher acreage values being realized, some industry experts believe that this evolving play will continue to garner industry attention during this lower commodity price environment.

In addition to our pending acquisition of the San Andres Acreage, we own and operate 162 gross (162 net) acres located in the Eagle Ford Shale in South Texas (“Eagle Ford Acreage”). The existing acreage is within a 250’ thick section in the heart of the Eagle Ford and Austin Chalk Trend in Karnes County, Texas. The lease acreage is ideally positioned for the continued development of three Eagle Ford Shale benches, and possibly the Austin Chalk formation. We drilled and cased the first Eagle Ford Shale well in this area, the Gap Band #2H, and are currently active in completion operations for hydraulic fracturing stimulation with first production in August/September 2017. We have internally planned for seven horizontal drilling locations (plus possibly two drilling locations in the Austin Chalk formation). We have permitted two additional Eagle Ford wells, the first of those to be drilled prior to the end of the first quarter of 2018.

Summary Oil and Natural Gas Data

Eagle Ford Acreage — The following table provides summary information regarding our Eagle Ford Acreage net proved undeveloped reserves and probable undeveloped reserves as of May 31, 2017, based on a reserve report prepared by NSAI, our independent petroleum engineering consultants, in accordance with the definitions and guidelines set forth in the Petroleum Resources Management System approved by the Society of Petroleum Engineers, or SPE, and using NYMEX Futures Strip Pricing for the period of 2017-2021, as described in the footnotes to the table below. Estimates of reserves and future net revenue using the SPE definitions and guidelines and NYMEX Futures Strip Pricing differ from estimates prepared in accordance with the definitions and pricing methodology approved by the Commission. See “Business—Sensitivity of Reserves to Prices By Principal Product Type and Price Scenario.”

San Andres Acreage — The following table provides summary information regarding the San Andres Acreage proved producing reserves as of January 1, 2017, based on a reserve report prepared by Mire, independent petroleum engineering consultants, in accordance with the definitions and guidelines set forth in the Petroleum Resources Management System approved by the Society of Petroleum Engineers, or SPE, and using NYMEX Futures Strip Pricing for the period of 2017-2021, as described in the footnotes to the table below. Estimates of reserves and future net revenue using the SPE definitions and guidelines and NYMEX Futures Strip Pricing differ from estimates prepared in accordance with the definitions and pricing methodology approved by the Commission. See “Business—Sensitivity of Reserves to Prices By Principal Product Type and Price Scenario.”

prices reflected in the NYMEX Futures Strip price deck, this results in an increase of approximately 275% in the PV10 presented in this table compared to the PV10 of our proved producing reserves determined using SEC Pricing. If the Commission’s definitions and SEC Pricing were used, the table would show estimated net proved producing reserves of 291.0 MBbl of oil and 185.0 MMcf of natural gas, or 322 MBoe of total net proved producing reserves; total future net revenue of $11,404,000; and PV10 of the future net revenue of $1,023,000. See “Business—Oil and Natural Gas Data—Summary of Oil and Natural Gas Reserves.” Regardless of the pricing methodology used, PV10 should not be construed as representing the fair market value of oil and natural gas properties.

Howard County Mineral Interest — On September 28, 2016, we purchased a mineral interest from Acoma Energy LLC in Howard County, Texas for $293,360. The interest acquired comprises 13.33 net mineral acres in a unit, which is approximately 1,319 acres. This translates to a royalty interest of 0.25% per well drilled on the unit. The target zones of the Midland Basin in this area are the Lower Spraberry, Wolfcamp A, and Wolfcamp B. Three new wells have been recently drilled and completed on the acreage in which we have this mineral ownership interest, which management believes has increased the value of this asset.

Management

We believe our management team is in a prime position to take advantage of opportunities within the oil and gas industry and to create value for our stockholders. Our management team has a deep knowledge of the industry and a well-established network of relationships with both public and private oil and gas companies, equity sponsors, lending institutions, landowners, and service providers from which we believe we can generate attractive acquisition opportunities. Our management also has a substantial history operating together as a team.

Gary C. Evans, Chairman & CEO: After serving nine years as a banker concentrating in the energy industry, he founded Magnum Hunter Resources Inc. (“MHRI”) in 1985, and served as Chairman & CEO for 20 years before selling to Cimarex Energy (Symbol: XEC) in 2005, overseeing the growth of a company he started with a $1,000 initial investment into an eventual $2.2 billion enterprise at the time of sale. Most recently he served as Chairman and CEO of Magnum Hunter Resources Corp. (“MHRC”), which he took from $0.35/share upon joining the company in 2009 to $9.16/share at its peak before the crash in commodity prices in 2014 and its eventual plan of reorganization under Chapter 11 of the U.S. Bankruptcy Code (“Bankruptcy Code”) completed in May, 2016, now known as Blue Ridge Mountain Resources, Inc. Mr. Evans also founded mid-stream gas gathering company Eureka Hunter Holdings, LLC (now known as Eureka Midstream Holdings) in 2010, and served as CEO of that company until May 2016.

H. C. “Kip” Ferguson, Executive Vice President, Exploration / Development: Mr. Ferguson brings more than 28 years of exploration, development and operational experience in many of the major oil and gas basins within the U.S. Mr. Ferguson uses his broad oil and gas experience to assess opportunities within our core Eagle Ford and Permian focus. Mr. Ferguson has a proven management track record of successful grassroots development and execution within unconventional plays. Mr. Ferguson most recently served as Executive Vice President of Exploration for MHRC from 2009 to July 2016, where he managed the Eagle Ford Shale division and was in charge of the exploration and development of its Eagle Ford Shale properties. This led to the successful divestment of those properties for $401 million. Prior to that, Mr. Ferguson was President and Director of Sharon Resources, Inc. and Sharon Energy Ltd., which was acquired by MHRC in 2009 as its entry point into the Eagle Ford Shale play. Mr. Ferguson has a Bachelor’s of Science in Geology, with a minor in Petroleum Engineering, from the University of Texas. Additionally, Mr. Ferguson has co-authored and written case studies, papers and articles for SPE International magazine, Unconventional Resources Technology Conference, and E&P magazine regarding successful uses of different unconventional technologies.

Brian Burgher, Senior Vice President, Land: Mr. Burgher has more than 30 years of experience in the oil and gas industry, with an emphasis on leases and land acquisitions. He was previously SVP of Land for MHRC from 2009 to 2015, where he served as land manager for its Eagle Ford assets, which were assembled, developed and sold under his oversight. Across his time at MHRC, Mr. Burgher personally oversaw the acquisition, due diligence and subsequent divesture of over $1.0 billion of leases and wells. Mr. Burgher has worked in all facets of field operations and management over the course of his career.

Deirdre M. Sanborn, Interim Chief Financial Officer, Vice President of Finance and Business Development. Ms. Sanborn is a corporate finance executive with 25 years of experience in lending, corporate finance, capital markets and investment banking, with a particular focus on the upstream and midstream sectors within the energy industry. From 1992 to 1997, Ms. Sanborn was a credit analyst in the capital markets group at Citicorp North America. From 1997 to 2009, Ms. Sanborn served as the director of corporate lending and senior relationship manager at Fortis Bank. From 2009 to 2014, Ms. Sanborn served as an executive director of investment banking and

senior relationship manager at UBS Investment Bank, where she focused on the firm’s energy lending portfolio. Most recently, she was founder and owner of Deirdre Sanborn & Associates, a strategic consulting firm focused on business coaching and financial management support. Ms. Sanborn is a registered financial advisor with the American Securities Administration Association and has a B.A in Economics from the College of the Holy Cross.

Jason Wilson, Manager, Geology: Mr. Wilson has more than 20 years of experience in geology and operations across all of our target areas. From 2009 to 2013 he was a member of the MHRC Eagle Ford operations team that successfully executed the grassroots development of the Gonzales/Lavaca county acreage in South Texas that was eventually sold for $401 million. After leaving MHRC, Mr. Wilson worked for one year as a senior geologist for New Standard Energy. Following his post at New Standard Energy until joining the Company, Mr. Wilson worked as an independent consultant for EnCap Investments, L.P. Mr. Wilson also worked previously in similar capacities for Anadarko Petroleum and Sharon Resources. Mr. Wilson has a Bachelor’s of Science and a Master’s of Science degree in Geology from Texas A&M University.

Brada Wilson, Controller and Corporate Secretary: Ms. Wilson presently serves as our Controller and Corporate Secretary. Ms. Wilson previously worked for MHRC for the five years prior to joining the Company. Prior to that, Ms. Wilson served as Controller for CWF Energy, Inc. in Dallas and Henry Energy Corporation, a public company based in Arlington, Texas. Ms. Wilson holds a Master of Professional Accounting degree from the University of Texas at Arlington and a Bachelor of Science degree from Texas Tech University. Ms. Wilson brings over 20 years of experience in all phases of oil and gas accounting.

Roger D. Burks, Financial Consulting Advisor: Mr. Burks brings more than 35 years of experience in accounting, finance, mergers and acquisitions, risk management, Sarbanes-Oxley compliance and financial reporting to the Company. Mr. Burks is Executive Managing Director/CEO of WG Consulting, a full-service oil and gas consulting firm headquartered in Houston, Texas focused on the energy industry, which he co-founded in January 2012. Pursuant to an agreement between WG Consulting and us, Mr. Burks served as our Interim Chief Financial Officer from November 1, 2016 through June 6, 2017. From June 2008 until January 2012, Mr. Burks was the CEO of SVG Advisors a consulting firm focused on the energy industry. From December 2006 until April 2008, Mr. Burks served as Executive Vice President and Chief Financial and Administrative Officer of Superior Offshore International, Inc., at that time, a leading provider of subsea construction and commercial diving services to the crude oil and natural gas exploration and production and gathering and transmission industries on the outer continental shelf of the Gulf of Mexico. Mr. Burks was a co-founder of Sirius Solutions, LLP, a financial consulting services firm, where he served as Managing Partner from August 2002 until June 2006. From January 1982 until August 2002, Mr. Burks worked at Deloitte & Touche, LLP, where he served as Partner-in-Charge of the firm’s Gulf Coast Energy Practice. Mr. Burks is a Certified Public Accountant and a National Association of Corporate Directors – Board Leadership Fellow. Mr. Burks has a Bachelor of Science in Accounting from Northeast Missouri State University.

Business Strategy

Exploit Initial Asset Portfolio — We intend to focus on the initial drilling and future development of our properties in the San Andres Formation and Eagle Ford Shale. As of June 30, 2017, the San Andres Acreage prospectively has up to 31 horizontal drilling locations and approximately 50 recompletion opportunities. 100 percent of the acreage is HBP. Our Eagle Ford Acreage includes seven identified potential drilling locations. Our first well was spud on April 14, 2017 and reached total depth on May 4, 2017. Completion activities are ongoing with first production expected to begin in August/September 2017.

Existing Infrastructure — Upon the purchase of the San Andres Acreage, Energy Hunter Resources will own and operate existing infrastructure including oil and natural gas gathering lines, salt water disposal wells (“SWD”), SWD gathering lines and injection pumps, and electricity lines, all of which are anticipated to significantly reduce initial costs and provide meaningful savings and efficiencies from field operating expenses. We will also acquire certain well inventory, including pumping units, artificial downhole equipment, tubular goods, and other ancillary material.

Look for Attractive Base Case Returns — While many oil and gas basins throughout the country remain marginally economic at current commodity strip prices, the Central Basin Platform and Eagle Ford Shale, as well as a few other basins located in West and South Texas, have been highly economic at prices below $50 per barrel. We seek to maximize stockholder value through a balanced program of acquisitions and low-risk development and exploitation drilling. Evidence of this strategy is noted in the low acreage cost for the San Andres Acreage ($2,250 per acre) as well as the below market price previously paid for the Eagle Ford Acreage ($2,500 per acre) which is surrounded by major and super independent oil companies.

Pursue Strategic Acquisitions with Significant Upside Potential — Management will target low-risk projects that offer meaningful potential production and reserve growth from existing reservoirs that have been under-exploited by previous owners. We will seek to serve as operator of the properties in which we acquire an ownership interest and initially concentrate these activities in the San Andres formation located in the Northwest Shelf of West Texas, the Eagle Ford Shale, located in South Texas, and other areas of the Permian Basin of West Texas and the Delaware Basin of Southeast New Mexico, which are among the areas where members of our management team have significant operating experience. Similar to our San Andres and Eagle Ford transactions, we intend to identify and opportunistically acquire additional lease acreage and reserves that have these characteristics.

Maintain Operating Control — We believe that operatorship provides the ability to maximize the value of our assets by allowing our experienced management team to control the timing of drilling expenditures, manage operational costs and enhance production volumes. Whenever possible, we will seek to serve as operator for the properties in which we acquire interests. We believe this flexibility to manage our drilling program allows us to optimize our returns and profitability.

Maintain Conservatively Capitalized Balance Sheet with Strong Liquidity Position — We currently intend to maintain a conservative approach to capitalizing our business and feel our minimal leverage will provide us with a significant advantage in the current volatile market environment. We expect to maintain an active hedging program that seeks to reduce our exposure to commodity price volatility and protect our cash flow.

Competitive Strengths

We believe the following strengths will help us achieve our business goals:

Experienced and Incentivized Management Team — With decades of experience, our management team has a proven track record of building and operating businesses focused on the development and acquisition of oil and natural gas properties. We believe our team’s deep knowledge of the major resource plays and operational expertise provide us with a competitive advantage. Additionally, our management’s extensive industry network provides us with access to top-tier industry partners, land owners and financial sponsors to help us identify and execute on attractive opportunities not generally known in the marketplace. Members of our senior management team have a significant economic interest in us, which will provide us a meaningful incentive to increase the value of our business for the benefit of all stockholders.

Attractive Acreage Position — Operating under the radar screen of many publicly traded companies, the San Andres formation was first discovered more than 50 years ago. Since 2009, more than 130 horizontal San Andres wells have been drilled. This horizontal well number continues to grow today as horizontal drilling technology has improved and overall costs have declined. Average well and completion costs in our region within the San Andres formation are approximately $2.4 million compared to $6 - $10 million well and completion costs in much of the deeper Permian and Delaware Basin properties being drilled today. In the Eagle Ford, all of our current acreage is located in Karnes County, Texas along the Edwards Trend in the heart of the Eagle Ford Shale play. According to monthly production data compiled by the Railroad Commission of Texas, Karnes County continues to be the top crude oil producing county in the State of Texas by volume. The Eagle Ford Shale play overlying the Edwards Trend is currently one of the most prolific liquids producers and currently generates some of the best economics in the Eagle Ford, even at recent commodity prices. Our assets provide development opportunities in a relatively mature, well-understood shale trend (as compared to other unconventional resource plays).

Proven Horizontal Drilling Expertise and Technical Acumen — Management has previously had success acquiring, developing, operating, and producing acreage in the Eagle Ford and Permian Basin. For example, several members of our management team were integral in the grass roots development of an Eagle Ford project located just one county over from our current Eagle Ford Acreage. Members of our team were key decision-makers at MHRC in growing an initial 2,000-net acre package into a 19,000-net acre asset through their knowledge of the specific land and geology, and relationships with landowners throughout the area. Ultimately, this asset produced 14,260 gross/5,277 net BOE/D at peak production for MHRC and was subsequently sold to a competitor.

High Degree of Operational Control. Our planned significant operational control will allow us to execute our development program, with a focus on the timing and allocation of capital expenditures and application of the optimal drilling and completion techniques to efficiently develop our resource base. We believe this flexibility will allow us to efficiently develop our current acreage and adjust drilling and completion activity opportunistically for the prevailing commodity price environment.

Stacked Pay Opportunities — In the Eagle Ford, we have identified seven potential undeveloped horizontal drilling locations (plus possibly two drilling locations in the Austin Chalk formation) across our three Eagle Ford benches and one Austin Chalk bench in the Gap Band Unit in Karnes County, Texas, which is partially evaluated in our proved undeveloped and probable undeveloped reserves as of May 31, 2017.

Recent Events

Pre-Paid Warrant Offering

In January and February 2017, we raised additional capital through the sale of $525,000 of Pre-Paid Warrants to existing investors. The Pre-Paid Warrants will automatically be exchanged for shares of Common Stock upon the consummation of a qualified equity offering. This offering should constitute a qualified equity offering under the Pre-Paid Warrants. The exchange price of the Pre-Paid Warrants would be 75% of the share price of this offering ($          per share based on an assumed offering price of $         , which is the midpoint of the range set forth on the cover of this Offering Circular).

Senior Secured Note Sale

On March 31, 2017, we entered into a subscription agreement under which we sold a $3,000,000 10.00% Senior Secured Promissory Note to one of our stockholders, Satellite Overseas (Holdings) Limited (“SOHL”). The Senior Secured Promissory Note was funded through three equal monthly draws of $1 million made in April, May, and June 2017. The Senior Secured Promissory Note matures on September 1, 2017. Upon the occurrence of the maturity date, at the option of the holder, the Senior Secured Promissory Note may either become due and payable or convert into shares of Common Stock at 75% of the share price in a qualified equity offering. This offering would constitute a qualified equity offering under the Senior Secured Promissory Note. The Senior Secured Promissory Note is secured, pursuant to a deed of trust, by a first priority security interest in a 50% working interest in the profits from all oil and gas produced from the well recently drilled by us at the Gap Band Prospect, Karnes County, Texas. SOHL has indicated to us that it currently prefers to be repaid from the proceeds of this offering and does not intend to convert the Senior Secured Promissory Note into shares of our Common Stock.

San Andres Acreage Acquisition

On July 12, 2017, we entered into a Contribution and Sale Agreement (the “Contribution Agreement”) with Lubbock Energy Partners, LLC, a Texas limited liability company (“LEP”). Pursuant to the Contribution Agreement, we agreed to acquire, to be effective as of June 1, 2017, certain assets, including oil and gas leases covering approximately 9,413 net acres located in Cochran County, Texas within the San Andres oil play of the Northwest Shelf of the Permian Basin (the “San Andres Acreage”), and certain other related wells, facilities, equipment and infrastructure (the “Acquisition”). The aggregate consideration for the Acquisition is approximately $22.7 million, subject to adjustment in accordance with the Contribution Agreement, consisting of approximately $10.6 million in cash (the “Cash Consideration”), and approximately $12.1 million in restricted shares of Common Stock of the Company (the “Stock Consideration”). We expect to fund the Cash Consideration from the proceeds of this offering. The number of shares of Common Stock to be issued as the Stock Consideration pursuant to the Contribution Agreement will be calculated based on the price per share issued in this offering.

The closing of the Acquisition is subject to standard closing conditions and adjustments, including, but not limited to, the consummation of this offering with gross proceeds to us of not less than $35 million and net proceeds of not less than $32 million.

The Contribution Agreement contains a price adjustment mechanism pursuant to which the purchase price for the Acquisition may be adjusted upward or downward for certain specified events, including, but not limited to, uncured environmental or title defects, or title benefits (as those terms are defined in the Contribution Agreement), which amount to greater than $1,075,000, approximately 5% of the purchase price. The parties have a 30-day period from the date of the Contribution Agreement to conduct further diligence and provide notice of any claimed defects or benefits. LEP will have the right to cure title defects within 180 days after closing of the Acquisition.

The Contribution Agreement also contains customary representations, warranties and covenants of LEP and us. Pursuant to the Contribution Agreement, each party has agreed to indemnify the other party against certain claims and losses resulting from any breach of its representations, warranties or covenants.

LEP has the right to terminate the Contribution Agreement if the closing of the Acquisition does not occur on or before September 30, 2017. LEP and we each have the right to terminate the Contribution Agreement if the aggregate

sum of (i) title defect amounts, (ii) environmental defect amounts, and (iii) the value of assets destroyed by fire or other casualty or taken in condemnation or under right of eminent domain, collectively, exceeds $1,075,000.

The Contribution Agreement also provides that we will enter into a registration rights agreement with LEP or its assignees at the closing of the Acquisition. Under the Contribution Agreement, we agreed to file an initial resale shelf registration statement with respect to the Stock Consideration within 180 days after closing of the Acquisition. The registration rights agreement will contain other customary terms, including piggyback registration rights, suspension rights, expenses and indemnification.

Implications of Being an “Emerging Growth Company”

As an issuer with less than $1 billion in total annual gross revenues during our last fiscal year, we qualify as an “emerging growth company” under the Jumpstart Our Business Startups Act (the “JOBS Act”). An emerging growth company may take advantage of certain reduced reporting requirements and is relieved of certain other significant requirements that are otherwise generally applicable to public companies. In particular, as an emerging growth company we:

We intend to take advantage of all of these reduced reporting requirements and exemptions, including the longer phase-in periods for the adoption of new or revised financial accounting standards under §107 of the JOBS Act. Our election to use the phase-in periods may make it difficult to compare our financial statements to those of non-emerging growth companies and other emerging growth companies that have opted out of the phase-in periods under §107 of the JOBS Act.

Certain of these reduced reporting requirements and exemptions are also available to us due to the fact that we may also qualify as a “smaller reporting company” under the Commission’s rules. For instance, smaller reporting companies are not required to obtain an auditor attestation on their assessment of internal control over financial reporting; are not required to provide a compensation discussion and analysis; are not required to provide a pay-for-performance graph or CEO pay ratio disclosure; and may present only two years of audited financial statements and related MD&A disclosure.

Under the JOBS Act, we may take advantage of the above-described reduced reporting requirements and exemptions for up to five years after our initial sale of common equity pursuant to a registration statement declared effective under the Securities Act of 1933, as amended (the “Securities Act”), or such earlier time that we no longer meet the definition of an emerging growth company. Note that this offering, while a public offering, is not a sale of common equity pursuant to a registration statement, since the offering is conducted pursuant to an exemption from the registration requirements. In this regard, the JOBS Act provides that we would cease to be an “emerging growth company” if we have more than $1 billion in annual revenues, have more than $700 million in market value of our Common Stock held by non-affiliates, or issue more than $1 billion in principal amount of non-convertible debt over a three-year period. Furthermore, under current Commission rules we will continue to qualify as a “smaller reporting company” for so long as we have a public float (i.e., the market value of common equity held by non-affiliates) of less than $75 million as of the last business day of our most recently completed second fiscal quarter.

Company and Other Information

The Company was formed in the State of Delaware on May 11, 2016. The Company’s principal executive office is located at 5005 Riverway Drive, Suite 160, Houston, Texas 77056. Our telephone number is 469-440-8868. Our Internet address is www.energyhunter.energy. We do not incorporate the information on or accessible through our website into this Offering Circular, and you should not consider any information on, or that can be accessed through, our website a part of this Offering Circular.

THE OFFERING

Unless otherwise indicated, all information in this Offering Circular regarding outstanding shares of our Common Stock reflects a 1-for-5.7 reverse split of our outstanding shares of Common Stock effective as of December 1, 2016. This reverse split does not increase or decrease (a) the total number of authorized shares of our Common Stock or (b) the par value of each share of Common Stock.

Unless otherwise indicated, the information presented in this Offering Circular assumes that the underwriters’ Option will not be exercised.

We currently intend to use $3.15 million of the net proceeds from this offering to redeem our Senior Secured Promissory Notes. We will use up to approximately $10.6 million to complete the acquisition of the San Andres Acreage under the Contribution Agreement. The remaining $    million will be used to fund our 2017 capital expenditures on existing assets, including the drilling, development, and completion of wells on our San Andres Acreage and our Eagle Ford Acreage. Additionally, we may use a portion of the proceeds to acquire additional acreage leaseholds, acquire additional producing properties and associated leaseholds, or for general corporate purposes.

RISK FACTORS

Investing in our Common Stock involves a high degree of risk. Prospective investors should carefully consider the risks described below, together with all of the other information included or referred to in this Offering Circular, before purchasing our Common Stock. The risks set out below are not the only risks we face. Additional risks and uncertainties not presently known to us or not presently deemed material by us might also impair our operations and performance. If any of these risks actually occurs, our business, financial condition or results of operations may be materially adversely affected. In such case, the trading price of our Common Stock, if a trading market develops, could decline and investors in our Common Stock could lose all or part of their investment.

Risks Related to our Company

We will require substantial additional capital in order to achieve commercial success and, if necessary, to finance future losses from operations as we endeavor to build our asset and revenue base, but we do not have any commitments to obtain such capital and we cannot assure you that we will be able to obtain adequate capital as and when required.

The business of oil and gas acquisition, drilling and development is very capital intensive and the level of operations attainable by an oil and gas company is directly linked to and limited by the amount of available capital. We believe that cash generated from oil and gas operations will not be sufficient to allow us to achieve our growth and other business objectives. Our ability to achieve commercial success and our continued growth will be dependent on our continued access to capital either through the additional sale of our equity securities, project financing, or joint ventures. Future equity financings may be dilutive to our stockholders and may involve preferred stock that has preferences or rights superior to our Common Stock. Project financings may involve a pledge of assets, and any debt we may incur will rank senior to our Common Stock. We cannot assure you that we will be able to raise additional capital from external sources, or enter into joint ventures or strategic partnerships, on satisfactory terms subsequent to this offering. Failure to raise additional capital subsequent to this offering, on favorable terms or at all, will have a material adverse effect on our development plans and operations and will likely cause us to curtail our planned operations.

If we are unable to obtain adequate capital funding, we may not be able to continue as a going concern.

The report of our independent registered public accounting firm for the period from May 11, 2016 through December 31, 2016 included herein contains an explanatory paragraph indicating that there is substantial doubt as to our ability to continue as a going concern. Our ability to continue as a going concern will be determined by our ability to complete this offering, which should enable us to fund our current acquisition and drilling plans and realize our near-term business objectives. In addition, we have incurred a net loss and negative operating cash flows since our inception and expect to incur losses in future periods as we continue to increase our expenses in order to position ourselves to grow our business. If we are unable to obtain adequate funding from this offering or in the future, we may not be able to continue as a going concern.

We do not have a significant operating history and, as a result, there is a limited amount of information about us on which to base an investment decision.

In considering whether to invest in our Common Stock, you should consider that there is only limited historical financial and operating information available on which to base your evaluation of our performance. The Company was formed in May 2016 and, as a result, although our management team has significant experience in our industry, we have limited financial and operating information available.

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 future activities. We may not be successful in implementing business strategies or in completing the development of the infrastructure necessary to conduct business as planned. In the event that our development plan is not completed or is delayed, operating results will be adversely affected and operations will differ materially from currently anticipated activities. As a result of industry factors or factors relating specifically to us, we may have to change our method of conducting business, which may cause a material adverse effect on results of operations and financial condition.

Failure to complete the San Andres Acreage acquisition may negatively impact our business, financial condition or results of operations.

The closing of the Acquisition of the San Andres Acreage from LEP is subject to a number of conditions, including, but not limited to, the closing of this offering and our receipt of not less than $35 million in gross proceeds and

$32 million in net proceeds in connection with the closing of this offering. Further, LEP has the right to terminate the Contribution Agreement if the closing of the Acquisition of the San Andres Acreage does not occur on or before September 30, 2017. LEP and we each have the right to terminate the Contribution Agreement if the aggregate sum of (i) title defect amounts, (ii) environmental defect amounts, and (iii) the value of assets destroyed by fire or other casualty or taken in condemnation or under right of eminent domain, collectively, exceeds $1,075,000. See “Offering Circular Summary—Recent Events”. Conversely, however, the closing of this offering is not contingent upon the consummation of the Acquisition of the San Andres Acreage, and the purchases of our Common Stock in this offering will be binding on investors prior to the closing of the Acquisition. If the San Andres Acreage Acquisition is not completed, we will not be able to realize any of the anticipated benefits of the Acquisition and our business, financial results or results of operation may be adversely affected. We will also have made substantial commitments of time and resources in connection with the proposed Acquisition, which could otherwise have been devoted to other opportunities and prospects that may have been beneficial to us.

We have no proved producing reserves, and drilling operations may not yield any oil or natural gas in commercial quantities or quality. We intend to grow our business in part through the acquisition and development of additional exploratory oil and gas prospects, which is a highly risky method of establishing oil and gas reserves.

To date, we have acquired less than 500 net acres of prospective oil and gas properties, comprising our Eagle Ford Acreage. The estimated reserves on these properties consist of approximately 2,128.1 MBOE of oil and natural gas, less than half of which is classified as proved undeveloped and the balance of which is classified as probable undeveloped reserves. Substantial exploration and development efforts will be required to establish the presence of additional proved reserves on these properties, and such efforts may not be successful. Moreover, we intend to grow our business by acquiring, drilling and developing additional exploratory oil and gas prospects, in addition to opportunistic acquisitions of producing properties or properties containing proved developed or proved undeveloped reserves, including the San Andres Acreage, that we believe have the potential for profitable production. Developing exploratory oil and gas properties requires significant capital expenditures and involves a high degree of financial risk. The budgeted costs of drilling, completing, and operating exploratory wells are often exceeded and can increase significantly when drilling costs rise. Drilling may be unsuccessful for many reasons, including title problems, unexpected drilling conditions, weather conditions, delays by project participants, compliance with governmental requirements, shortages or delays in the delivery of equipment and services, cost overruns, and mechanical difficulties. Moreover, the successful drilling or completion of an exploratory oil or gas well does not ensure a profit on investment. Exploratory wells bear a much greater risk of loss than development wells. We cannot assure you that any of the wells we drill will be productive or that we will recover all or any portion of our investment. If we are unable to successfully acquire and develop exploratory oil and gas prospects, our results of operations, financial condition and stock price will be materially adversely affected.

We may not act as an operator on many of our future prospects, which means we will be dependent on third parties for the exploration, development and production of any such leasehold interests.

An oil and gas operator is the party that takes primary responsibility for management of the day-to-day exploration, development and production activity relating to an oil and gas prospect. Part of our business strategy is to acquire operating interests in oil and natural gas properties whenever feasible. We will not always be able to do so. We anticipate that an industry partner will function as the operator for many of the oil and natural gas properties we acquire in the future. Our reliance on third party operators for the exploration, development and production of property interests subjects us to a number of risks, including our inability to control the amount and timing of costs and expenses of exploration, development and production and the risk that we may not be able to properly control the timing and quality of work conducted with respect to our projects.

We have limited management and staff and may be more dependent upon partnering arrangements.

As of June 30, 2017, we have 8 employees, including our 4 executive officers. We intend to use the services of independent consultants and contractors to perform various professional services, including reservoir engineering, accounting, land, legal, environmental and tax services. We also intend to pursue alliances with partners in the areas of geological and geophysical services and prospect generation, evaluation and prospect leasing. Our planned dependence on third party consultants and service providers creates a number of risks, including but not limited to:

If we experience significant delays in obtaining the services of such third parties or poor performance by such parties, our results of operations and stock price may be materially adversely affected.

The loss of any of our executive officers could adversely affect us.

We currently have only 8 employees, including our 4 executive officers. We are dependent on the extensive experience of our executive officers to implement our acquisition and growth strategy. The loss of the services of any of our executive officers could have a negative impact on our operations and our ability to implement our business plan.

Our success is dependent on the prices of oil and natural gas. Low oil or natural gas prices and the substantial volatility in these prices may adversely affect our financial condition and ability to meet certain capital expenditure requirements and financial obligations.

The prices we will receive for oil and natural gas will heavily influence our revenue, profitability, cash flow available for capital expenditures and access to new capital and future rate of growth. Oil and natural gas are commodities and, therefore, their prices are subject to wide fluctuations in response to relatively minor changes in supply and demand. Historically, the markets for oil and natural gas have been volatile, and prices have declined significantly in recent periods. For example, according to the Energy Information Agency (EIA), during the period from January 1, 2014 through July 31, 2017, the WTI spot price for oil declined from a high of $107.95 per Bbl on June 20, 2014 to $26.19 per Bbl on February 11, 2016, and the Henry Hub spot price for natural gas declined from a high of $7.98 per MMBtu on March 4, 2014 to a low of $1.49 per MMBtu on March 4, 2016. We believe that these markets will likely continue to be volatile in the future. The prices received for production, and the levels of production, depend on numerous factors. These factors include the following:

In the second half of 2014, oil prices began a rapid and significant decline as the global oil supply began to outpace demand. During 2015, 2016 and thus far in 2017, the global oil supply has continued to outpace demand, resulting in a sustained decline in realized prices for oil production. In general, this imbalance between supply and demand reflects the significant supply growth achieved in the United States as a result of shale drilling and oil production increases by certain other countries, including Russia and Saudi Arabia, as part of an effort to retain market share, combined with only modest demand growth in the United States and less-than-expected demand in other parts of the world, particularly in Europe and China. Although there has been a dramatic decrease in drilling activity in the industry, oil storage levels in the United States remain at historically high levels. Until supply and demand balance and the overhang in storage levels begins to decline, prices are expected to remain under pressure. In addition, the lifting of economic sanctions on Iran has resulted in increasing supplies of oil from Iran, adding further downward pressure to oil prices. Prices for domestic natural gas began to decline during the third quarter of 2014 and have continued to be weak throughout 2015, 2016 and thus far in 2017. The declines in natural gas prices are primarily due to a significant imbalance between supply and demand across North America. The duration and magnitude of the commodity price declines cannot be accurately predicted.

Lower oil and natural gas prices will reduce our future cash flows, borrowing ability and the present value of estimated reserves. Exploration, development and exploitation projects require substantial capital expenditures, and, if prices are lower, we may be unable to obtain needed capital or financing on satisfactory terms, which could lead to expiration of leases or a decline in oil and natural gas reserves. Lower oil and natural gas prices may also reduce the amount of oil and natural gas that we can produce economically and may affect any estimated proved reserves we are ultimately able to establish. The present value of future net revenues from estimated proved reserves will not necessarily be the same as the current market value of estimated oil and natural gas reserves.

Drilling for oil and natural gas is a speculative activity and involves numerous risks and substantial and uncertain costs that could adversely affect us.

Our success will depend on the success of our drilling program. 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. 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 drawn from available data from other wells, more fully explored prospects or producing fields will be applicable to current drilling prospects.

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 regardless of whether a well eventually produces commercial quantities of hydrocarbons, or is drilled at all. Exploration wells endure a much greater risk of loss than development wells. The analogies drawn from available data from other wells, more fully explored locations or producing fields may not be applicable to current drilling locations. If actual drilling and development costs are significantly more than the current estimated costs, we may not be able to continue operations as proposed and could be forced to modify drilling plans accordingly. Drilling for oil and natural gas involves numerous risks, including the risk that no commercially productive oil or natural gas reservoirs will be discovered. The cost of drilling, completing, and operating wells is substantial and uncertain, and drilling operations may be curtailed, delayed, or canceled as a result of a variety of factors beyond our control, including:

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

Our operations will 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 may face while drilling horizontally include, but are not limited to, the following:

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

We may purchase oil and natural gas properties with liabilities or risks that we do not know about or that we do not assess correctly, and, as a result, could be subject to liabilities that could adversely affect results of operations.

Before acquiring oil and natural gas properties, we estimate the reserves, future oil and natural gas prices, and operating costs. We also review land records which affect ownership, potential environmental liabilities and other factors relating to the properties. However, this 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 being purchased. We may not become sufficiently familiar with the properties to assess fully the deficiencies and capabilities. We do not generally perform inspections on every well or property, and therefore may not be able to observe mechanical and environmental problems even when an inspection is conducted. The seller may not be willing or financially able to give contractual protection against any identified problems, and we may decide to assume land, environmental and other liabilities in connection with properties acquired. If we acquire properties with risks or liabilities that were unknown or not assessed correctly, our financial condition, results of operations and cash flows could be adversely affected as claims are settled and cleanup costs related to these liabilities are incurred.

Our reserve estimates depend, and our future reserve estimates will depend, on many assumptions that may turn out to be inaccurate. Any material inaccuracies in our reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.

The process of estimating oil and natural gas reserves is complex. It requires interpretations of available technical data and many assumptions, including assumptions relating to economic factors. Any significant inaccuracies in these interpretations or assumptions could materially affect the estimated quantities and the calculation of the present value of reserves shown in these estimates.

In order to prepare reserve estimates in our reports, we will typically engage an independent petroleum consultant. The consultant will need to project production rates and timing of development expenditures. Our independent petroleum consultants will also analyze available geological, geophysical, production and engineering data. The extent, quality and reliability of this data can vary and may not be in our control. The process also requires economic assumptions about matters such as oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. Therefore, estimates of oil and natural gas reserves are inherently imprecise.

Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves will most likely vary from our estimates. Any significant variance could materially affect the estimated quantities and present value of our reserves. In addition, our independent petroleum consultants may adjust estimates of proved reserves to reflect production history, drilling results, prevailing oil and natural gas prices and other factors, many of which are beyond our control.

The marketability of our future 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 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 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 estimated reserves to pipelines and terminal facilities. Our ability to market production depends in substantial part on the quality of our oil and gas production, availability and capacity of gathering systems, pipelines and processing facilities owned and operated by third parties. Failure to obtain these services on acceptable terms could materially harm our business. As a result, 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 arrangements were made to deliver 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. The disruption of third party facilities due to maintenance and/or weather could negatively impact our ability to market and deliver our products. These third parties may control when or if such facilities are restored and what prices will be charged.

Hedging transactions may limit our potential gains or result in losses.

In order to manage our exposure to price risks in the marketing of our oil and natural gas, we intend from time to time to enter into financial oil and gas price hedging arrangements with respect to a portion of our future proved, developed-producing production. While these contracts are intended to reduce the effects of volatile oil and natural gas prices, they may also limit our potential gains if oil and natural gas prices were to rise substantially over the price established by the contract. In addition, such transactions may expose us to the risk of financial loss in certain circumstances, including instances in which:

We cannot assure you that any financial hedging transactions we may enter into will adequately protect us from declines in the prices of oil and natural gas. On the other hand, where we choose not to engage in hedging transactions in the future, we may be more adversely affected by adverse changes in oil and natural gas prices than our competitors who engage in hedging transactions. In addition, the counterparties under our derivatives contracts may fail to fulfill their contractual obligations to us.

We may have difficulty managing growth in our business, which could adversely affect our financial condition and results of operations.

We are a start-up company with few assets and very limited operating history. We will have to grow significantly to achieve our business plan. If we are able to achieve significant growth in the size and scope of our operations, that could place a strain on our financial, technical, operational and management resources. The failure to continue to upgrade our technical, administrative, operating and financial control systems or the occurrences of unexpected expansion difficulties, including the failure to recruit and retain experienced managers, geologists, engineers and other professionals in the oil and gas industry, could have a material adverse effect on our business, financial condition and results of operations and our ability to timely execute our business plans.

We are exposed to operating hazards and uninsured risks. Our operations are subject to the risks inherent in the oil and natural gas industry, including the risks of:

These events may result in substantial losses to us from:

As is customary in our industry, we intend to maintain insurance against some, but not all, of these risks. We cannot assure you that our insurance will be adequate to cover these losses or liabilities. We do not intend to carry business interruption insurance. Losses and liabilities arising from uninsured or underinsured events may have a material adverse effect on our financial condition and operations.

The producing wells in which we will have an interest may occasionally experience reduced or terminated production. These curtailments can result from mechanical failures, contract terms, pipeline and processing plant interruptions, market conditions and weather conditions. These curtailments can last from a few days to many months.

Risks Relating to the Oil and Gas Industry

Our industry is highly competitive, which may adversely affect our performance, including our ability to participate in ready-to-drill prospects in our core areas.

We operate in a highly competitive environment. In addition to capital, the principal resources necessary for the exploration and production of oil and natural gas are:

We must compete for such resources with both major oil and natural gas companies and independent operators. Many of these competitors have financial and other resources substantially greater than ours. We cannot assure you that such materials and resources will be available when needed. If we are unable to access material and resources when needed, we risk suffering a number of adverse consequences, including:

We are subject to numerous laws and regulations that can adversely affect the cost, manner or feasibility of doing business.

Our operations are subject to extensive federal, state and local laws and regulations relating to the exploration, production and sale of oil and natural gas, and operating safety. Future laws or regulations, any adverse change in the interpretation of existing laws and regulations or our failure to comply with existing legal requirements may result in substantial penalties and harm to our business, results of operations and financial condition. We may be required to make large and unanticipated capital expenditures to comply with governmental regulations, such as:

Under these laws and regulations, we could be liable for:

Our operations could be significantly delayed or curtailed and our cost of operations could significantly increase as a result of regulatory requirements or restrictions. We are unable to predict the ultimate cost of compliance with these requirements or their effect on our operations. It is also possible that a portion of our oil and gas properties could be subject to eminent domain proceedings or other government takings for which we may not be adequately compensated.

Our operations may incur substantial expenses and resulting liabilities from compliance with environmental laws and regulations. Our oil and natural gas operations are subject to stringent federal, state and local laws and regulations relating to the release or disposal of materials into the environment or otherwise relating to environmental protection. These laws and regulations:

Failure to comply with these laws and regulations may result in:

Changes in environmental laws and regulations occur frequently and any changes that result in more stringent or costly waste handling, including water disposal, storage, transport, disposal or cleanup requirements could require us to make significant expenditures to reach and maintain compliance and may otherwise have a material adverse effect on our industry in general and on our own results of operations, competitive position or financial condition. Under these environmental laws and regulations, we could be held strictly liable for the removal or remediation of previously released materials or property contamination. This could occur regardless of whether we were responsible for the release or contamination or if our operations met previous standards in the industry at the time they were performed. Our permits will require that we report any incidents that cause or could cause environmental damages.

The unavailability or high cost of drilling rigs, hydraulic fracturing equipment and crews, or oil field equipment, supplies or personnel could adversely affect our ability to execute our exploration and development plans.

The oil and gas industry is cyclical and, from time to time, there are shortages of drilling rigs, hydraulic fracturing equipment and crews, and oil field equipment, supplies or qualified personnel. During these periods, the costs of rigs, equipment and supplies may increase substantially and their availability may be limited. In addition, the demand for, and wage rates of qualified personnel, including drilling rig or hydraulic fracturing crews, may rise as the number of rigs in service increases. If drilling rigs, equipment, supplies or qualified personnel are unavailable to us due to excessive costs or demand or otherwise, our ability to execute our exploration and development plans and, as a result, our financial condition and results of operations, could be materially and adversely affected.

Current water regulation relating to hydraulic fracturing, particularly water source and groundwater regulation, could result in increased operational costs, operating restrictions and delays.

Hydraulic fracturing uses large amounts of water. It can require between three to five million gallons of water per horizontal well. We may face regulatory concerns in both the sourcing and the disposal of water used in hydraulic fracturing. In addition, hydraulic fracturing produces water that must be treated and disposed of in accordance with applicable regulatory requirements.

First, as to sourcing water for hydraulic fracturing, we will need to secure water from the local water supply or make alternative arrangements. In order to source water from the local water supply for hydraulic fracturing, we may need to pay premium rates and be subject to a lower priority if the local area becomes subject to water restrictions. We may also seek water from alternative providers supporting the hydraulic fracturing industry. If we have an insufficient water supply, we may be unable to engage in hydraulic fracturing until such supply is located.

Second, hydraulic fracturing produces water that must be treated and disposed of in accordance with applicable regulatory requirements. Environmental regulations governing the withdrawal, storage and use of surface water or groundwater necessary for hydraulic fracturing may increase operating costs and cause delays, interruptions or termination of operations, the extent of which cannot be predicted, all of which could have an adverse effect on operations and financial performance. Our ability to remove and dispose of water will affect production, and the cost of water treatment and disposal may affect our ability to achieve or maintain profitability. The imposition of new environmental initiatives and regulations could also include restrictions on our ability to conduct hydraulic fracturing or disposal of produced water, drilling fluids and other substances associated with the exploration, development and production of oil and natural gas.

Federal and state legislation and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays.

Hydraulic fracturing involves the injection of water, sand or other propping agents and chemicals under pressure into rock formations to stimulate hydrocarbon production. We intend to routinely use hydraulic fracturing to produce commercial quantities of oil, liquids and natural gas. Sponsors of bills before the Senate and House of Representatives have asserted that chemicals used in the fracturing process could adversely affect drinking water supplies. Such legislation, if adopted, could increase the possibility of litigation and establish an additional level of regulation at both the federal and state levels that could lead to operational delays or increased operating costs and could, and in all likelihood would, result in additional regulatory burdens, making it more difficult to perform hydraulic fracturing operations and increasing our costs of compliance. Moreover, the Environmental Protection Agency (the “EPA”) conducted a comprehensive research study on the potential adverse impacts that hydraulic fracturing may have on drinking water and groundwater. The study did identify a number of activities associated with hydraulic fracturing and oil and gas exploration in general that have the potential to affect groundwater.

Consequently, even if federal legislation is not adopted soon or at all, the results of the hydraulic fracturing study by the EPA, or the results of other similar studies, could spur further action at a later date towards federal legislation and regulation of hydraulic fracturing or similar production operations.

In addition, a number of states or local municipalities are considering or have implemented more stringent regulatory requirements applicable to fracturing, which could include a moratorium on drilling and effectively prohibit further production of oil, liquids or natural gas through the use of hydraulic fracturing or similar operations. In response to such local action, in 2015 the Texas legislature enacted legislation to preempt local bans and moratoriums.

The adoption of new laws or regulations imposing reporting obligations on, or otherwise limiting, the hydraulic fracturing process could make it more difficult to complete oil and natural gas wells. In addition, if hydraulic fracturing becomes regulated at the federal level as a result of federal legislation or regulatory initiatives by the EPA, fracturing activities could become subject to additional permitting requirements, and also to attendant permitting delays and potential increases in cost, which could adversely affect business and results of operations.

We rely on computer and telecommunications systems, and failures in our systems or cyber security attacks could materially disrupt our business operations.

The oil and gas industry has become increasingly dependent upon digital technologies to conduct day-to-day operations including certain exploration, development and production activities. We depend on digital technology to estimate quantities of oil and natural gas reserves, process and record financial and operating data, analyze seismic and drilling information, and communicate with our employees and other third parties. Our business partners, including vendors, service providers, purchasers of our production and financial institutions, are also dependent on digital technology. It is possible that we could incur interruptions from cyber security attacks, computer viruses or malware. We believe that we have positive relations with our vendors and maintain satisfactory anti-virus and malware software and controls. Even so, any cyber incidents or interruptions to our computing and communications infrastructure or our information systems could lead to data corruption, communication interruption, unauthorized release, gathering, monitoring, misuse or destruction of proprietary or other information, or otherwise significantly disrupt our business operations. As cyber threats continue to evolve, we may be required to expend significant additional resources to continue to modify or enhance our protective measures or to investigate and remediate any information security vulnerabilities.

Risks Relating to our Common Stock

There has been no public market for our Common Stock prior to this offering, and an active market in which investors can resell their shares may not develop.

Prior to this offering, there has been no public market for our Common Stock. We cannot predict the extent to which an active market for our Common Stock will develop or be sustained after this offering, or how the development of such a market might affect the market price of our Common Stock. The initial offering price of our Common Stock in this offering has been agreed to between us and the underwriters based on a number of factors, including market conditions in effect around the time of this offering, and it may not be in any way indicative of the price at which our shares of Common Stock will trade following the completion of this offering. Even if a trading market develops, investors may not be able to resell their shares of Common Stock at or above the initial offering price.

We do not anticipate an immediate market for our shares.

We have not yet obtained an exchange listing or an over-the-counter quotation, which are pre-requisites to liquidity for our Common Stock. We have applied to have our Common Stock listed on the NASDAQ, but there is no assurance that this exchange will approve our Common Stock for listing.

Our Chairman and Chief Executive Officer beneficially owns a significant percentage of our stock and will be able to exert significant influence over matters subject to stockholder approval.

As of the date of this Offering Circular, our Chairman and Chief Executive Officer beneficially owns 50% of our outstanding Common Stock and may continue to own more than __% after the offering. See “Principal Stockholders.” Therefore, he will have the ability to influence us through this ownership position. Our Chairman and Chief Executive Officer may be able to significantly affect matters requiring stockholder approval, including elections of directors, amendments of our organizational documents, and approval of any merger, sale of assets, or other major corporate transaction. This may prevent or discourage unsolicited acquisition proposals or offers for our Common Stock that you may believe are in your best interest as one of our stockholders.

You will experience immediate and substantial dilution as a result of this offering.

You will incur immediate and substantial dilution as a result of this offering. After giving effect to the sale by us of our Common Stock in this offering at an assumed public offering price of $ per share, which is the midpoint of the range set forth on the cover page of this Offering Circular, and after deducting the underwriting discount and commissions and estimated offering expenses payable by us, and giving effect to the issuance of the Stock Consideration in the Acquisition, valued for purposes of the Acquisition at the same price per share as the shares sold in this offering, investors in this offering can expect an immediate dilution of $ per share. See “Dilution.”

Our stockholders will experience dilution upon the issuance of the Stock Consideration in the San Andres Acreage Acquisition, and the future exercise of registration rights may adversely affect the market price of our Common Stock.

At the closing of the Acquisition, we expect that the Stock Consideration we pay to the seller of the San Andres Acreage will represent an approximately    % fully-diluted interest in the Company, which will dilute the voting and economic interests of our existing stockholders, including purchasers of Common Stock in this offering. In addition, the Contribution Agreement provides that we will enter into a registration rights agreement with LEP or its assignees at the closing of the Acquisition. Under the Contribution Agreement, we have agreed to file with the SEC an initial resale shelf registration statement with respect to the Stock Consideration within 180 days after closing of the Acquisition. We will bear the costs of registering the securities subject to that registration rights agreement, and once the Stock Consideration shares are registered, they will be freely tradable, subject to any applicable lock-up agreements. The registration and availability of such a significant number of shares for trading in the public market may have an adverse effect on the market price of the Common Stock and could impair our ability to raise additional capital through the sale of equity securities in the future.

We may not be able to satisfy listing requirements of the NASDAQ to maintain a listing of our Common Stock.

If our Common Stock is listed on the NASDAQ, we must meet certain financial and liquidity criteria to maintain such listing. If we fail to meet any of the NASDAQ’s listing standards, our Common Stock may be delisted. In addition, our board may determine that the cost of maintaining our listing on a national securities exchange outweighs the benefits of such listing. A delisting of our Common Stock from the NASDAQ may materially impair our stockholders’ ability to buy and sell our Common Stock and could have an adverse effect on the market price of, and the efficiency of the trading market for, our Common Stock. In addition, the delisting of our Common Stock could significantly impair our ability to raise capital.

We are an “emerging growth company,” and cannot be certain if the reduced reporting requirements applicable to emerging growth companies will make our Common Stock less attractive to investors.

We are an “emerging growth company,” as defined in the JOBS Act. For as long as we continue to be an emerging growth company, we may take advantage of exemptions from various reporting requirements that are applicable to other public companies that are not emerging growth companies, including not being required to comply with the auditor attestation requirements of Section 404 of the Sarbanes-Oxley Act, reduced disclosure obligations regarding executive compensation in periodic reports and proxy statements and exemptions from the requirements of holding a nonbinding advisory vote on executive compensation and stockholder approval of any golden parachute payments not previously approved. We could be an emerging growth company for up to five years, circumstances could cause us to lose that status earlier, including if the market value of our Common Stock held by non-affiliates exceeds $700 million, if we issue $1 billion or more in non-convertible debt during a three-year period, or if our annual gross revenues exceed $1 billion. We would cease to be an emerging growth company on the last day of the fiscal year following the date of the fifth anniversary of our first sale of common equity securities under an effective registration statement or a fiscal year in which we have $1 billion in gross revenues (note that the offering of Common Stock pursuant to this Offering Circular will not result in the sale of securities under an effective registration statement). Finally, at any time we may choose to opt-out of the emerging growth company reporting requirements. If we choose to opt out, we will be unable to opt back in to being an emerging growth company. We cannot predict if investors will find our Common Stock less attractive because we may rely on these exemptions. If some investors find our Common Stock less attractive as a result, there may be a less active trading market for our Common Stock and our stock price may be more volatile.

The market price of our Common Stock may be volatile.

If we obtain an exchange listing for our Common Stock, the trading price of the stock and the price at which we may sell stock in the future are subject to large fluctuations in response to any of the following:

We do not intend to pay dividends on our Common Stock.

We do not intend pay dividends on our Common Stock in the foreseeable future.

Provisions of Delaware law may delay or prevent transactions that would benefit stockholders.

The Delaware General Corporation Law (the “DGCL”) contains provisions that may have the effect of delaying, deferring or preventing a change of control of the Company. Because of these provisions, persons considering unsolicited tender offers or other unilateral takeover proposals may be more likely to negotiate with our board of directors rather than pursue non-negotiated takeover attempts. As a result, these provisions may make it more difficult for our stockholders to benefit from transactions that are opposed by an incumbent board of directors.

We may issue shares of preferred stock that could adversely affect holders of shares of Common Stock.

Our board of directors has the power, without stockholder approval and subject to the terms of our amended and restated certificate of incorporation, to set the terms of any classes or series of shares of stock that may be issued, including voting rights, dividend rights, conversion features, preferences over shares of our Common Stock with respect to dividends or upon liquidation, dissolution, or winding up of the business. If we issue shares of preferred stock in the future that have a preference over shares of Common Stock with respect to the payment of dividends or upon liquidation, dissolution or winding up, or if we issue shares of preferred stock with voting rights that dilute the voting power of shares of Common Stock, the rights of holders of Common Stock or the trading price of our Common Stock could be adversely affected.

Future issuances of debt securities, which would rank senior to our Common Stock upon our bankruptcy or liquidation, and future issuances of preferred stock, which could rank senior to our Common Stock for the purposes of dividends and liquidating distributions, may adversely affect the level of return you may be able to achieve from an investment in our Common Stock.

In the future, we may attempt to increase our capital resources by offering debt securities. Upon a potential bankruptcy or liquidation, holders of our debt securities, and lenders with respect to other borrowings we may make, would receive distributions of our available assets prior to any distributions being made to holders of our Common Stock. Because our decision to issue debt securities in any future offering, or borrow money from lenders, will depend in part on market conditions and other factors beyond our control, we cannot predict or estimate the amount, timing or nature of any such future offerings or borrowings. Holders of our Common Stock must bear the risk that any future offerings we conduct or borrowings we make may adversely affect the level of return they may be able to achieve from an investment in our Common Stock.

If our shares of Common Stock become subject to the penny stock rules, it would become more difficult to trade our shares.

The Commission has adopted rules that regulate broker-dealer practices in connection with transactions in penny stocks. Penny stocks are generally equity securities with a price per share of less than $5.00, other than securities registered on certain national securities exchanges or authorized for quotation on certain automated quotation systems, provided that current price and volume information with respect to transactions in such securities is provided by the exchange or system. If we do not obtain or retain a listing on the NASDAQ and if the price of our Common Stock is less than $5.00 per share, our Common Stock will be deemed a penny stock. The penny stock rules require a broker-dealer, before effecting a transaction in a penny stock not otherwise exempt from those rules, to deliver a standardized risk disclosure document containing specified information. In addition, the penny stock rules require that, before effecting any such transaction in a penny stock not otherwise exempt from those rules, a broker-dealer must make a special written determination that the penny stock is a suitable investment for the purchaser and receive (i) the purchaser’s written acknowledgment of the receipt of a risk disclosure statement; (ii) a written agreement to transactions involving penny stocks; and (iii) a signed and dated copy of a written suitability statement. These disclosure requirements may have the effect of reducing the trading activity in the secondary market for our Common Stock, and therefore stockholders may have difficulty selling their shares.

FINRA sales practice requirements may limit a stockholder’s ability to buy and sell our stock.

In addition to the “penny stock” rules described above, FINRA has adopted rules that require that in recommending an investment to a customer, a broker-dealer must have reasonable grounds for believing that the investment is suitable for that customer. Prior to recommending speculative, low-priced securities to their non-institutional customers, broker-dealers must make reasonable efforts to obtain information about the customer’s financial status, tax status, investment objectives and other information. The FINRA requirements may make it more difficult for broker-dealers to recommend that their customers buy our Common Stock, which may have the effect of reducing the level of trading activity in our Common Stock. As a result, fewer broker-dealers may be willing to make a market in our common stock, reducing a stockholder’s ability to resell shares of our Common Stock.

Our management has broad discretion as to the use of certain of the net proceeds from this offering.

We currently intend to use approximately $10.6 million of the net proceeds from this offering to fund the Cash Consideration portion of the purchase price for the acquisition of the San Andres Acreage. Additionally, we intend to use approximately $3.15 million of the net proceeds from this offering to redeem our Senior Secured Promissory Note which matures on September 1, 2017. We currently intend to use the remaining net proceeds to fund drilling, development, and completion of wells on the San Andres Acreage and the Eagle Ford Acreage. We may also use a portion of the proceeds to acquire additional acreage leaseholds, acquire additional producing properties and associated leaseholds, or for general corporate purposes. However, we cannot specify with certainty the particular uses of such proceeds. Our management will have broad discretion in the application of the net proceeds designated to fund our 2017 and 2018 capital expenditures on existing assets owned, acquire additional acreage leaseholds, acquire additional producing properties and associated leaseholds, or for general corporate purposes, which is subject to change in the future. Accordingly, you will have to rely upon the judgment of our management with respect to the use of these proceeds. Our management may spend a portion or all of the net proceeds from this offering in ways that holders of our Common Stock may not desire or that may not yield a significant return or any return at all. The failure by our management to apply these funds effectively could harm our business. Pending their use, we may also invest the net proceeds from this offering in a manner that does not produce income or that loses value. Please see “Use of Proceeds” below for more information.

If we are unable to implement and maintain effective internal control over financial reporting in the future, investors may lose confidence in the accuracy and completeness of our financial reports and the market price of our Common Stock may decline.

As a public company, we would be required to maintain internal control over financial reporting and to report any material weaknesses in such internal control. Further, we will be required to report any changes in internal controls on a quarterly basis. In addition, we would be required to furnish a report by management on the effectiveness of internal control over financial reporting pursuant to Section 404 of the Sarbanes-Oxley Act. We will design, implement, and test the internal controls over financial reporting required to comply with these obligations. If we identify material weaknesses in our internal control over financial reporting, if we are unable to comply with the

requirements of Section 404 in a timely manner or assert that our internal control over financial reporting is effective, or if our independent registered public accounting firm is unable to express an opinion as to the effectiveness of its internal control over financial reporting when required, investors may lose confidence in the accuracy and completeness of our financial reports and the market price of the Common Stock could be negatively affected. We also could become subject to investigations by the stock exchange on which the securities are listed, the Commission, or other regulatory authorities, which could require additional financial and management resources.

As an emerging growth company, our auditor is not required to attest to the effectiveness of our internal controls.

Our independent registered public accounting firm is not required to attest to the effectiveness of our internal control over financial reporting while we are an emerging growth company. This means that the effectiveness of our financial reporting may differ from our peer companies in that they may be required to obtain independent registered public accounting firm attestations as to the effectiveness of their internal controls over financial reporting and we are not. While our management will be required to attest to internal control over financial reporting and we will be required to detail changes to our internal controls on a quarterly basis, we cannot provide assurance that the independent registered public accounting firm’s assessment of the effectiveness of our internal controls over financial reporting, if obtained, would not find one or more material weaknesses or significant deficiencies. Further, once we cease to be an emerging growth company we will be subject to independent registered public accounting firm attestation regarding the effectiveness of our internal controls over financial reporting. Even if management finds such controls to be effective, our independent registered public accounting firm may decline to attest to the effectiveness of such internal controls and issue a qualified report.

We believe we will be considered a smaller reporting company and will be exempt from certain disclosure requirements, which could make our Common Stock less attractive to potential investors.

Rule 12b-2 of the Exchange Act defines a “smaller reporting company” as an issuer that is not an investment company, an asset-backed issuer, or a majority-owned subsidiary of a parent that is not a smaller reporting company and that:

As a smaller reporting company, we will not be required and may not include a Compensation Discussion and Analysis section in our proxy statements; we will provide only two years of financial statements; and we need not provide the table of selected financial data. We also will have other “scaled” disclosure requirements that are less comprehensive than issuers that are not smaller reporting companies which could make our Common Stock less attractive to potential investors, which could make it more difficult for our stockholders to sell their shares.

We will incur increased costs as a result of operating as a public company and our management will be required to devote substantial time to new compliance initiatives and corporate governance practices.

As a public company, and particularly if at some point in the future we are no longer an “emerging growth company,” we will incur significant legal, accounting and other expenses that we did not incur as a private company. The Sarbanes-Oxley Act, the Dodd-Frank Wall Street Reform and Consumer Protection Act, the listing requirements of the NASDAQ and other applicable securities rules and regulations impose various requirements on public companies.

Our management and other personnel will need to devote a substantial amount of time to compliance with these requirements. Moreover, these rules and regulations will increase our legal and financial compliance costs and will make some activities more time-consuming and costly. For example, we expect that these rules and regulations may make it more difficult and more expensive for us to obtain directors’ and officers’ liability insurance, which could make it more difficult for us to attract and retain qualified members of our board of directors. We cannot predict or estimate the amount of additional costs we will incur as a public company or the timing of such costs.

We are taxed as a corporation for U.S. federal income tax purposes.

We will pay U.S. federal income tax on our taxable income at the corporate tax rate, which is currently a maximum of 35%, and will pay state and local income tax at varying rates. Distributions will generally be taxed again as corporate dividends (to the extent of our current and accumulated earnings and profits), and no income, gains, losses, deductions, or credits will flow through to you. In addition, changes in current state law may subject us to additional entity-level taxation by individual states. Because of state budget deficits and other reasons, several states are evaluating ways to subject corporations to additional forms of taxation. We will be subject to a material amount of entity-level taxation, which will result in a material reduction in the anticipated cash flow and after-tax return to our shareholders.

A non-U.S. holder of our Common Stock will be treated as having income that is “effectively connected” with a United States trade or business upon the sale or disposition of our Common Stock unless (i) our Common Stock is regularly traded on an established securities market and (ii) the non-U.S. holder owned not more than 5% of our Common Stock during the applicable testing period.

A non-U.S. holder of our Common Stock generally will incur U.S. Federal income tax on any gain realized upon a sale or other disposition of our Common Stock to the extent our Common Stock constitutes a “United States real property interest,” or USRPI, under the Foreign Investment in Real Property Tax Act of 1980, or FIRPTA. A USRPI includes stock in a “United States real property holding corporation.” We are, and expect to continue to be for the foreseeable future, a “United States real property holding corporation.”

Under FIRPTA, a non-U.S. holder is taxed on any gain realized upon a sale or other disposition of a USRPI as if such gain were “effectively connected” with a United States trade or business of the non-U.S. holder. A non-U.S. holder thus will be taxed on such a gain at the same graduated rates generally applicable to U.S. persons (or long-term capital gains rates, if applicable). In addition, a non-U.S. holder would have to file a U.S. federal income tax return reporting that gain. A non-U.S. holder that is a foreign corporation and not entitled to treaty relief or exemption also may be subject to the 30% branch profits tax on such gain.

However, if our Common Stock becomes regularly traded on an established securities market, then gain realized upon a sale or other disposition of our Common Stock will not be treated as gain from the sale of a USRPI, as long as the non-U.S. holder did not own more than 5% of our Common Stock at any time during the five-year period preceding the sale or other disposition or, if shorter, the non-U.S. holder’s holding period for its shares of our Common Stock. At this time, we generally expect our Common Stock will be regularly traded on an established securities market, and so gain realized upon a sale or other disposition of our Common Stock will not be treated as gain from the sale of a USRPI, as long as the non-U.S. holder did not own more than 5% of our Common Stock at any time during the applicable testing period. However, in the event that our Common Stock is not regularly traded on an established securities market, then gain recognized by a non-U.S. holder upon a sale or other disposition of our Common Stock will be subject to tax under FIRPTA.

The tax treatment of corporations or an investment in our Common Stock could be subject to potential legislative, judicial or administrative changes and differing interpretations, possibly on a retroactive basis.

The present U.S. federal income tax treatment of corporations, including us, or an investment in our Common Stock, may be modified by administrative, legislative or judicial interpretation at any time. For example, from time to time, members of Congress and the President propose and consider substantive changes to the existing U.S. federal income tax laws that affect corporations. Any modification to the U.S. federal income tax laws and interpretations thereof may or may not be retroactively applied and could make it more difficult or impossible to meet our cash flow needs for operations, acquisitions or other purposes. We are unable to predict whether any of these changes or other proposals will be enacted. However, it is possible that a change in law could affect us, and any such changes could negatively impact the value of an investment in our Common Stock.

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

This Offering Circular, including any supplement to this Offering Circular, includes “forward-looking statements.” To the extent that the information presented in this Offering Circular discusses financial projections, information or expectations about our business plans, results of operations, products or markets, or otherwise makes statements about future events, such statements are forward-looking. Such forward-looking statements can be identified by the use of words such as “should”, “may”, “intends”, “anticipates”, “believes”, “estimates”, “projects”, “forecasts”, “expects”, “plans” and “proposes”. Although we believe that the expectations reflected in these forward-looking statements are based on reasonable assumptions, there are a number of risks and uncertainties that could cause actual results to differ materially from such forward-looking statements. These include, among others, the cautionary statements in the “Risk Factors” section and the “Management’s Discussion and Analysis of Financial Condition and Results of Operations” section in this Offering Circular.

Forward-looking statements may include statements about:

We caution you that these forward-looking statements are subject to all of the risks and uncertainties, most of which are difficult to predict and many of which are beyond our control, incident to the development, production, gathering and sale of oil and natural gas. These risks include, but are not limited to, commodity price volatility, inflation, lack of availability of drilling and production equipment and services, environmental risks, drilling and other operating risks, regulatory changes, the uncertainty inherent in estimating reserves and in projecting future rates of production, cash flow and access to capital, the timing of development expenditures and the other risks described under “Risk Factors” in this Offering Circular. The forward-looking statements are also subject to risks and uncertainties specific to our company, including but not limited to the fact that we are a recently-organized corporation with very limited operating history, no current revenue and no properties that have yet been developed into producing oil or natural gas properties, limited management and other staff, and other risks related to our company described under “Risk Factors”.

Reserve engineering is a process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact way. The accuracy of any reserve estimate depends on the quality of available data, the interpretation of such data and price and cost assumptions made by reserve engineers. In addition, the results of drilling, testing and production activities may justify revisions of estimates that were made previously. If significant,

such revisions would change the schedule of any further production and development drilling. Accordingly, reserve estimates may differ significantly from the quantities of oil and natural gas that are ultimately recovered.

Should one or more of the risks or uncertainties described in this Offering Circular occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements.

All forward-looking statements, expressed or implied, included in this Offering Circular are expressly qualified in their entirety by this cautionary statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that we or persons acting on our behalf may issue.

Except as otherwise required by applicable law, we disclaim any duty to update any forward-looking statements, all of which are expressly qualified by the statements in this section, to reflect events or circumstances after the date of this Offering Circular.

DIVIDEND POLICY

We have never declared or paid, and do not anticipate declaring or paying, any cash dividends to holders of our Common Stock in the foreseeable future. We currently intend to retain future earnings, if any, to finance our operations and the growth of our business. Our future dividend policy is within the discretion of our board of directors and will depend upon then-existing conditions, including our results of operations, financial condition, capital requirements, investment opportunities, statutory restrictions on our ability to pay dividends and other factors our board of directors may deem relevant.

USE OF PROCEEDS

We expect to receive approximately $         million of net proceeds (assuming the midpoint of the price range set forth on the cover of this Offering Circular) from the sale of Common Stock offered hereby after deducting underwriting discounts and commissions and estimated offering expenses of approximately $1.2 million payable by us.

We currently intend to use approximately $3.15 million of the net proceeds from this offering to redeem our Senior Secured Promissory Notes. We will use up to approximately $10.6 million to pay the Cash Consideration portion of the purchase price for the acquisition of the San Andres Acreage under the Contribution Agreement. The remaining $    million will be used to fund our 2017 capital expenditures on existing assets and assets currently under contract, including the drilling, development, and completion of wells on our Eagle Ford Acreage and the San Andres Acreage we will acquire in the Acquisition. Additionally, we may use a portion of the proceeds to acquire additional acreage leaseholds, acquire additional producing properties and associated leaseholds, or for general corporate purposes. Such allocation of net proceeds may be subject to future revision depending on, among other factors, market conditions, commodity prices, drilling costs and availability of drilling and production equipment, future operating results, and acquisition opportunities.

A $1.00 increase or decrease in the assumed initial public offering price of $    per share, which is the midpoint of the price range set forth on the cover page of this Offering Circular, would cause the net proceeds from this offering, after deducting the underwriting discounts and commissions and estimated offering expenses, received by us to increase or decrease, respectively, by approximately $ million, assuming the number of shares of Common Stock offered by us, as set forth on the cover page of this Offering Circular, remains the same. If the proceeds increase due to a higher initial public offering price, we would use the additional net proceeds to fund our 2017 and 2018 capital expenditures as outlined above or for general corporate purposes. Under Regulation A, the SEC regulation under which this offering is being conducted, the aggregate amount of the offering cannot exceed $50.0 million. If the proceeds decrease due to a lower initial public offering price, then we would first reduce by a corresponding amount the net proceeds directed to general corporate purposes and then, if necessary, the net proceeds directed towards additional acquisitions.

DETERMINATION OF OFFERING PRICE

Prior to this offering, there has been no public market for our Common Stock. The initial public offering price will be determined by negotiations between us and the representatives of the underwriters. In determining the initial public offering price, we and the representatives of the underwriters expect to consider a number of factors including:

Neither we nor the underwriters can assure investors that an active trading market will develop for the shares of our Common Stock, or that the securities will trade in the public market at or above the initial public offering price. See “Underwriting” for additional information regarding our arrangement with our underwriters.

CAPITALIZATION

The following table sets forth our cash and capitalization as of December 31, 2016 on:

The pro forma as-adjusted information below is illustrative only, and our capitalization following the closing of this offering will be adjusted based on the actual initial public offering price and other terms of this offering determined at the time of pricing as well as our actual expenses. This table should be read in conjunction with “Use of Proceeds,” the historical audited and unaudited consolidated and combined financial statements related to the San Andres Acreage Acquisition and accompanying notes included elsewhere in this Offering Circular.

DILUTION

Purchasers of our securities in this offering will experience immediate and substantial dilution in the net tangible book value (tangible assets less total liabilities) per share of our Common Stock for accounting purposes. Our net tangible book value as of December 31, 2016 was approximately $2.1 million, or $2.07 per share, based on 999,992 shares outstanding.

Assuming (a) the issuance of          shares of Common Stock upon the exchange of the Pre-Paid Warrants at an exchange price equal to 75% of the initial public offering price in this offering, and (b) an initial public offering price of $    per share (which is the midpoint of the price range set forth on the cover page of this Offering Circular), after giving effect to the sale of the shares in this offering and further assuming the receipt of the estimated net proceeds (after deducting estimated underwriting discounts and commissions and estimated offering expenses payable by us), our pro forma as-adjusted net tangible book value as of December 31, 2016 would have been approximately $    million, or $    per share. This represents an immediate increase in the net tangible book value of $    per share to our existing stockholders and an immediate dilution to new investors purchasing shares in this offering of $    per share, resulting from the difference between the offering price and the pro forma as-adjusted net tangible book value after this offering.

Assuming (a) closing of the San Andres Acreage Acquisition and the issuance of          shares of Common Stock as Stock Consideration, which is based on a share price of $    per share (which is the midpoint of the price range set forth on the cover page of this Offering Circular), (b) the issuance of       shares of Common Stock upon the exchange of the Pre-Paid Warrants at an exchange price equal to 75% of the initial public offering price in this offering, and (c) an initial public offering price of $    per share (which is the midpoint of the price range set forth on the cover page of this Offering Circular), after giving effect to the sale of the shares in this offering and further assuming the receipt of the estimated net proceeds (after deducting estimated underwriting discounts and commissions and estimated offering expenses payable by us), our adjusted pro forma net tangible book value as of December 31, 2016 would have been approximately $    million, or $    per share. This represents an immediate increase in the net tangible book value of $    per share to our existing stockholders and an immediate dilution to new investors purchasing shares in this offering of $    per share, resulting from the difference between the offering price and the pro forma as-adjusted net tangible book value after this offering.

The following table illustrates the per share dilution to new investors purchasing shares in this offering:

A $1.00 increase (decrease) in the assumed initial public offering price of $ per share, which is the midpoint of the price range set forth on the cover page of this Offering Circular, would increase (decrease) our as-adjusted pro forma net tangible book value per share after the offering by $    and decrease (increase) the dilution to new investors in this offering by $    per share, assuming the number of shares offered by us, as set forth on the cover page of this Offering Circular, remains the same, after deducting the estimated underwriting discounts and commissions and estimated offering expenses payable by us.

The following table summarizes, as of December 31, 2016, on the adjusted pro forma basis described above, the total number of shares of Common Stock owned by existing stockholders (including Pre-Paid Warrant holders) and to be owned by (a) new investors and (b) LEP after the closing of the San Andres Acreage Acquisition (such number based on an assumed issuance at $    per share, which is the midpoint of the price range set forth on the cover page of this Offering Circular), and the total consideration paid and the average price per share paid by our existing stockholders and to be paid by new investors in this offering at $      , the midpoint of the price range set forth on the cover page of this Offering Circular, calculated before deduction of estimated underwriting discounts and commissions.

SELECTED FINANCIAL DATA

Unaudited Pro Forma Condensed Combined Financial Information

The accompanying unaudited pro forma condensed combined financial statements present the Company’s unaudited pro forma condensed combined balance sheet as of December 31, 2016 and the unaudited pro forma condensed combined statement of operations for the year ended December 31, 2016. These unaudited pro forma condensed combined financial statements have been developed by applying pro forma adjustments to our historical financial statements. The unaudited pro forma condensed combined statement of operations data for the period presented gives effect to the initial public offering described in this offering document and the probable Acquisition of the San Andres Acreage as if both transactions had been completed as of January 1, 2016. The full year unaudited pro forma condensed combined statement of operations has been presented even though we were formed on May 11, 2016. In addition, the combined statement of operations is based upon the assumption that the San Andres Acreage Acquisition successfully closes. See Risk Factors — Failure to complete the San Andres Acreage Acquisition may negatively impact our business, financial condition or result of operations.

The pro forma adjustments related to the purchase price allocation of the San Andres Acreage Acquisition are preliminary and are subject to revision as additional information becomes available. Revisions to the preliminary purchase price allocation may have a significant impact on the pro forma amounts of total assets, total liabilities and stockholder’s equity and depreciation, depletion and amortization expense. The pro forma adjustments related to the San Andres Acreage Acquisition reflect the fair values allocated to our assets as of the assumed acquisition date and do not necessarily reflect the fair values that would have been recorded if the Acquisition had occurred on January 1, 2016.

The unaudited pro forma condensed combined financial statements should be read together with the historical financial statements of the Company and the related notes, and the historical statement of revenue and direct operating expenses for the San Andres Acreage.

The unaudited pro forma condensed combined financial statements are included for informational purposes only and do not purport to reflect the results of operations or financial position that would have occurred had the San Andres Acreage Acquisition occurred on the assumed acquisition dates. Accordingly, they should not be relied upon as indicative of our results of operations or financial position had the San Andres Acreage Acquisition occurred on the dates assumed because they necessarily exclude various operating expenses. Additionally, the unaudited pro forma condensed combined financial statements are not a projection of our results of operations or financial position for any future period or date.

Unaudited Pro Forma Condensed Combined Balance Sheet
As of December 31, 2016

Unaudited Pro Forma Condensed Combined Statement of Operations
For the Period from January 1, 2016 to December 31, 2016

Adjustments to Unaudited Pro Forma Condensed Consolidated Financial Statements

Preliminary Purchase Price Allocation

The Company has performed a preliminary valuation analysis of the fair market value of the San Andres Acreage’s assets. The following table summarizes the allocation of the preliminary purchase price as of the acquisition date:

This preliminary purchase price allocation has been used to prepare pro forma adjustments in the unaudited pro forma condensed combined balance sheet and statement of operations. The final purchase price allocation will be determined when the Company has completed the detailed valuations and necessary calculations. The final allocation could differ materially from the preliminary allocation used in the pro forma adjustments.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS

The following discussion and analysis should be read in conjunction with the accompanying financial statements and related notes included elsewhere in this Offering Circular. This discussion contains forward-looking statements reflecting our current expectations, whose actual outcomes involve risks and uncertainties. Actual results and the timing of events may differ materially from those stated in or implied by these forward-looking statements due to a number of factors, including those discussed in the sections entitled “Risk Factors,” “Cautionary Statement Regarding Forward-Looking Statements” and elsewhere in this Offering Circular..

Overview

We are an independent oil and gas company focused on the acquisition, drilling and production of oil and natural gas properties and prospects within the United States. We were founded as a Delaware corporation in May 2016 by our Chairman and Chief Executive Officer, Gary C. Evans, to take advantage of what we believe to be a unique and timely opportunity within the oil and gas industry due to the severe downturn which began in 2014. During the period from January 1, 2014 through July 31, 2017, according to the EIA, the WTI spot price for oil has declined from a high of $107.95 per Bbl on June 20, 2014 to a low of $26.19 per Bbl on February 11, 2016, and the Henry Hub spot price for natural gas has declined from a high of $7.98 per MMBtu on March 4, 2014 to a low of $1.49 per MMBtu on March 4, 2016.

Market Conditions

The oil and gas industry is cyclical and commodity prices are highly volatile. In the second half of 2014, oil prices began a rapid and significant decline as the global oil supply began to outpace demand. During 2015, 2016, and thus far in 2017, the global oil supply has continued to outpace demand, resulting in a sustained decline in realized prices for oil production. In general, this imbalance between supply and demand reflects the significant supply growth achieved in the United States as a result of shale drilling and oil production increases by certain other countries, including Russia and Saudi Arabia, as part of an effort to retain market share, combined with only modest demand growth in the United States and less-than-expected demand in other parts of the world, particularly in Europe and China. Although there has been a dramatic decrease in drilling activity in the industry, oil storage levels in the United States remain at historically high levels. Until supply and demand balance and the overhang in storage levels begins to decline, prices are expected to remain under pressure. In addition, the lifting of economic sanctions on Iran has resulted in increasing supplies of oil from Iran, adding further downward pressure to oil prices. Prices for domestic natural gas began to decline during the third quarter of 2014 and continued to be weak throughout 2015, 2016 and thus far in 2017. The declines in natural gas prices are primarily due to an imbalance between supply and demand across North America. The duration and magnitude of the commodity price declines cannot be accurately predicted.

Our Properties

In July 2016, we closed on an acquisition of two separate lease blocks from the same party totaling, at that time, approximately 423 gross (423 net) undeveloped acres located in the heart of the Eagle Ford Shale play overlying the Edwards Trend in Karnes County, Texas. The cost of the acquisition was approximately $1,070,000. The acreage position is prospective for both the lower and upper Eagle Ford Shale, as well as the Austin Chalk formation. As of July 31, 2017, following certain lease expirations, we continue to hold 162 gross (162 net) acres along the Edwards Trend in Karnes County, Texas where we have drilled one horizontal well (4,000 foot lateral). The estimated reserves for these properties consist of approximately 2,128.1 MBoe of oil and natural gas, which are classified as proved undeveloped and probable undeveloped reserves. We currently own 93.75% of the working interests in these properties and will be the operator of record on all wells drilled on this acreage position.

In addition, on September 28, 2016, we purchased a mineral interest from Acoma Energy LLC in Howard County, Texas for $293,360. The interest acquired comprises 13.33 net mineral acres in a unit, which is approximately 1,319 acres. This translates to a royalty interest of 0.25% per well drilled on the unit. The target zones of the Midland Basin in this area are the Lower Spraberry, Wolfcamp A, and Wolfcamp B. Three new wells have been recently drilled and completed on the acreage in which we have this mineral ownership interest, which management believes has increased the value of this asset.

On July 12, 2017, we entered into the Contribution Agreement with LEP. Pursuant to the Contribution Agreement, we agreed to acquire, to be effective as of June 1, 2017, the San Andres Acreage and certain other related wells, facilities, equipment and infrastructure. See “—Capital Requirements and Sources of Liquidity—San Andres Acreage Acquisition”.

Results of Operations

Our operations to date have been limited. We were incorporated on May 11, 2016. In July 2016, we completed an exempt offering of Common Stock under Regulation D pursuant to which we raised $3,200,000. Using a portion of the net proceeds of our Regulation D offering, in July 2016, we closed on our acquisition of two separate lease blocks totaling at the time of acquisition approximately 423 gross (423 net) undeveloped acres in the Eagle Ford Shale play for $1,070,000.

Outside of these formative transactions, we are in the exploratory stage of development and had not commenced any drilling operations as of December 31, 2016. As of June 30, 2017, we have eight employees, all of whom are focused primarily on start-up operations and development of our unproved leaseholds and identifying future acquisitions. Substantial exploration and development efforts will be required to establish the presence of proved reserves on these properties. The success of this offering will dictate our future drilling program, which we initially commenced early in 2017 with the spudding of our first well. As of June 30, 2017, we had successfully drilled and cased a 4,000 foot lateral. The well is scheduled for completion in August/September 2017.

As of the date of this offering, we have no oil and gas production and no revenues.

From inception through December 31, 2016, we incurred $1,131,062 in general and administrative expenses and a net operating loss of $1,132,832.

Capital Requirements and Sources of Liquidity

Background

Our exploration, development and acquisition activities will require us to make significant operating and capital expenditures. The amount and allocation of future capital expenditures will depend upon a number of factors, including the number and size of acquisition opportunities, our cash flows from operating, investing and financing activities, and our ability to assimilate acquisitions and execute our drilling program. We will periodically review our capital expenditure budget to assess changes in current and projected cash flows, acquisition activities, debt requirements, and other factors. If we are unable to obtain funds when needed or on acceptable terms, we may not be able to complete acquisitions that may be favorable to us or finance the capital expenditures necessary to develop our production or proved reserves.

Based upon current oil and natural gas price expectations for the remainder of 2017, following the closing of this offering, we believe that the proceeds from this offering and our eventual cash flow from operations will provide us with sufficient liquidity to execute our planned capital program. However, future cash flows are subject to a number of variables, including our ability to establish or acquire proved reserves or producing properties, the success of our exploration and development efforts, the level of oil and natural gas production and prices in the market, and many other risks of operating in the oil and gas industry, and we will be required to make significant additional capital expenditures to more fully develop our properties. We cannot assure you that operating and other needed capital will be available on acceptable terms or at all. In the event we make additional acquisitions and the amount of capital required is greater than the amount we have available for acquisitions at that time, we could be required to reduce the expected level of capital expenditures and/or seek additional capital. If we require additional capital for that or other reasons, we may seek such capital through joint venture partnerships, production payment financings, traditional reserve base borrowings, public or private offerings of debt and equity securities or other means. We cannot assure you that needed capital will be available on acceptable terms or at all. If we are unable to obtain funds when needed or on acceptable terms, we may be required to curtail our planned drilling program, which could impede our growth plans and result in a loss of acreage through lease expirations. In addition, we may not be able to complete acquisitions that may be favorable to us or finance the capital expenditures necessary to develop our production or increase or replace our reserves.

Going Concern

We are in the exploratory stage of development and, as of December 31, 2016, we had not yet commenced any drilling operations. Operations, as of December 31, 2016, had been devoted primarily to startup activities and the

acquisition of certain unproved leaseholds (as of December 31, 2016). For the period from inception through December 31, 2016, we reported a net loss of $1,132,832 and net cash flows used in operating activities of $297,116. As of December 31, 2016, we had a working capital deficit of $636,650, excluding $1,010,026 of deferred offering costs, which will be expensed if we are unsuccessful in an initial public offering.

The ongoing execution of our business plan is expected to result in operating losses over the next twelve months. Management believes that the capital raised through this offering will provide sufficient cash to maintain our operations for the next twelve months. We will also receive revenues from the producing acreage we obtain in the San Andres Acquisition. If the cash raised from this offering together with the revenues from the San Andres Acquisition is insufficient to execute our business plan, we will need to raise additional capital through future stock issuances or loans. There are no assurances that we will be successful in achieving our goals of obtaining cash through loans, stock issuances, or increasing revenues and reaching profitability.

In view of these conditions, our ability to continue as a going concern is dependent upon our ability to meet our financing requirements, and ultimately to achieve profitable operations. Management believes that its current and future plans, including consummation of this offering, provide an opportunity to continue as a going concern.

Founder Shares

In May 2016, we issued 438,596 shares of Common Stock for $250 to our Chief Executive Officer Gary C. Evans as founder shares. At the time of issuance, this represented 2,500,000 shares of Common Stock sold at par value, prior to giving effect to a 1-for-5.7 reverse split of shares of our outstanding Common Stock as of December 1, 2016. This reverse split did not increase or decrease (a) the total number of authorized shares of our Common Stock or (b) the par value of each share of Common Stock.

Regulation D Offering

In July 2016, we completed a private offering under Regulation D under which we issued 561,403 shares of Common Stock for aggregate gross proceeds of $3,200,000. The share numbers reflect giving effect to a 1-for-5.7 reverse split of shares of our Common Stock as of December 1, 2016.

Pre-Paid Warrant Offering

In January and February 2017, we raised additional capital through the sale of $525,000 of Pre-Paid Warrants to existing investors. The Pre-Paid Warrants will automatically be exchanged for shares of Common Stock upon the consummation of a qualified equity offering. The exchange price of the Pre-Paid Warrants is 75% of the share price in a qualified equity offering. This offering should constitute a qualified equity offering under the Pre-Paid Warrants.

Senior Secured Note Sale

On March 31, 2017, we entered into a subscription agreement under which we sold a $3,000,000 10.00% Senior Secured Promissory Note to one of our stockholders, SOHL. The Senior Secured Promissory Note was funded through three equal monthly draws of $1 million made in April, May, and June 2017. The Senior Secured Promissory Note matures on September 1, 2017. Upon the occurrence of the maturity date, at the option of the holder, the Senior Secured Promissory Note may either become due and payable or convert into shares of Common Stock at 75% of the share price in a qualified equity offering. This offering would constitute a qualified equity offering under the Senior Secured Promissory Note. The Senior Secured Promissory Note is secured, pursuant to a deed of trust, by a first priority security interest in a 50% working interest in the profits from all oil and gas produced from the well recently drilled by us at the Gap Band Prospect, Karnes County, Texas. SOHL has indicated to us that it currently prefers to be repaid from the proceeds of this offering and does not intend to convert the Senior Secured Promissory Note into shares of our Common Stock.

San Andres Acreage Acquisition

On July 12, 2017, we entered into the Contribution Agreement with LEP. Pursuant to the Contribution Agreement, we agreed to acquire, to be effective as of June 1, 2017, the San Andres Acreage and certain other related wells, facilities, equipment and infrastructure. The aggregate consideration for the Acquisition is approximately $22.7 million, subject to adjustment in accordance with the Contribution Agreement, consisting of approximately $10.6 million in cash (the “Cash Consideration”), and approximately $12.1 million in restricted stock of the

Company (the “Stock Consideration”). We expect to fund the Cash Consideration from the proceeds of this offering. The number of shares of Common Stock to be issued as the Stock Consideration pursuant to the Contribution Agreement shall be calculated based on the price per share of the Common Stock issued in this offering.

The closing of the Acquisition is subject to standard closing conditions and adjustments, including, but not limited to, the consummation of this offering with gross proceeds to us of not less than $35 million and net proceeds of not less than $32 million. The Contribution Agreement contains a price adjustment mechanism pursuant to which the purchase price for the Acquisition may be adjusted upward or downward for certain specified events, including, but not limited to, uncured environmental or title defects, or title benefits (as those terms are defined in the Contribution Agreement), which amount to greater than $1,075,000, approximately 5% of the purchase price. The parties have a 30-day period from the date of the Contribution Agreement to conduct further diligence and provide notice of any claimed defects or benefits. The Contribution Agreement also contains customary representations, warranties and covenants of LEP and us. Pursuant to the Contribution Agreement, each party has agreed to indemnify the other party against certain claims and losses resulting from any breach of its representations, warranties or covenants. LEP has the right to terminate the Contribution Agreement if the closing of the Acquisition does not occur on or before September 30, 2017. LEP and we each have the right to terminate the Contribution Agreement if the aggregate sum of (i) title defect amounts, (ii) environmental defect amounts, and (iii) the value of assets destroyed by fire or other casualty or taken in condemnation or under right of eminent domain, collectively, exceeds $1,075,000. The Contribution Agreement also provides that we will enter into a registration rights agreement with LEP or its assignees at the closing of the Acquisition. Under the Contribution Agreement, we agreed to file an initial resale shelf registration statement with respect to the Stock Consideration within 180 days after closing of the Acquisition. The registration rights agreement will contain other customary terms, including piggyback registration rights, suspension rights, expenses and indemnification.

Factors Affecting the Comparability of Our Financial Condition and Results of Operations

Our historical financial condition and results of operations for the period presented may not be comparable to our financial condition and results of operations for future periods, for the following reasons:

Deferred Offering Costs

Deferred offering costs include all specific incremental costs directly incurred for this offering. These costs will be charged against the gross proceeds of the offering when it closes. If this offering is unsuccessful, such costs will be expensed. As of December 31, 2016, we had incurred $1,010,026 in deferred offering costs.

Public Company Expenses

Upon completion of this offering, we expect to incur direct, incremental general and administrative expenses as a result of being a publicly traded company, including, but not limited to, increased scope of our operations and costs associated with hiring new personnel, implementation of compensation programs that are competitive with our public company peer group, annual and quarterly reports to shareholders, tax return preparation, independent registered public accounting firm fees, investor relations activities, registrar and transfer agent fees, incremental director and officer liability insurance costs and independent director compensation. These direct, incremental general and administrative expenses are not included in our historical results of operations.

Organizational Costs and Expenses

We were incorporated on May 11, 2016. Therefore, 2016 was our first year of operations and it is only a partial year of operations during which we incurred start-up and other one-time organizational costs and expenses.

Increased Drilling Activity

We commenced initial drilling operations in early 2017. The amount and timing of the capital expenditures related to future drilling activity is largely discretionary and within our control. We could choose to defer a portion of these planned capital expenditures depending on a variety of factors, including but not limited to the success of this offering, the success of our drilling activities, prevailing and anticipated prices for oil and natural gas, the availability of necessary equipment, infrastructure and capital, the receipt and timing of required regulatory permits and approvals, seasonal conditions, drilling and acquisition costs and the level of participation by other interest owners.

Internal Controls and Procedures

We are not currently required to comply with the SEC’s rules implementing Section 404 of the Sarbanes Oxley Act of 2002, and are therefore not required to make a formal assessment of the effectiveness of our internal control over financial reporting for that purpose. Upon becoming a public company, we will be required to comply with the SEC’s rules implementing Section 302 of the Sarbanes-Oxley Act of 2002, which will require our management to certify financial and other information in our quarterly and annual reports and provide an annual management report on the effectiveness of our internal control over financial reporting. We will not be required to make our first assessment of our internal control over financial reporting under Section 404 until our first annual report subsequent to our ceasing to be an “emerging growth company” within the meaning of Section 2(a)(19) of the Securities Act.

Inflation

Inflation in the United States has been relatively low in recent years. Although the impact of inflation on us has been insignificant in recent years, it is still a factor in the United States economy and we may experience inflationary pressure on the cost of oilfield services and equipment if, as a result of future increases in oil and natural gas prices, drilling activity increases in our areas of operations.

Off-Balance Sheet Arrangements

Currently, we do not have any off-balance sheet arrangements.

Quantitative and Qualitative Disclosure About Market Risk

We are exposed to market risk, including the effects of adverse changes in commodity prices and interest rates as described below. The primary objective of the following information is to provide quantitative and qualitative information about our potential exposure to market risks. The term “market risk” refers to the risk of loss arising from adverse changes in oil and natural gas prices and interest rates. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses.

Commodity Price Risk

Our major market risk exposure is in the pricing that we will receive for our oil and natural gas production. Pricing for oil and natural gas has been volatile and unpredictable for several years, and this volatility is expected to continue in the future. The prices we will receive in the future for our oil and natural gas production will depend on many factors outside of our control, such as the strength of the global economy.

Eagle Ford Acreage — In addition to calculating proved undeveloped and probable undeveloped reserve estimates for our Eagle Ford Acreage as of May 31, 2017 using Commission definitions and SEC Pricing, NSAI also produced a report using the definitions and guidelines set forth in the Petroleum Resources Management System approved by SPE and NYMEX Futures Strip Pricing for the period of 2017-2021 as a sensitivity analysis in calculating future net revenues. This report was prepared at our request to assess commodity price risk as well as for a comparison to the historically low period of oil and gas prices captured in the reserve report using the Commission’s required pricing methodology. See “Business—Oil and Natural Gas Data.” A copy of our independent petroleum engineer’s reserve report containing its estimate of our net proved undeveloped and probable undeveloped reserves and future net revenues therefrom using SPE definitions and NYMEX Futures Strip Pricing as of May 31, 2017 is included as Annex C to this Offering Circular.

The oil and gas prices applied by NSAI in the sensitivity analysis were based on a NYMEX Futures Strip price deck as quoted on May 31, 2017 and provided below.

Sensitivity Analysis - NYMEX Futures Strip Pricing

Sensitivity Analysis

Gross revenue is our share of the gross (100 percent) revenue from the properties prior to any deductions. Future net revenue set forth in the sensitivity analysis table above is after deductions for our share of estimated production taxes, ad valorem taxes, capital costs, abandonment costs, and operating expenses but before consideration of any income taxes.

NSAI estimated a declining operating cost schedule due to decreasing produced water volumes and changes in artificial lift method as wells mature. NSAI estimated operating costs based on the following per-well schedule:

At our request, operating costs are intended to be limited to direct lease and field-level costs and our estimate of the portion of our headquarters’ general and administrative overhead expenses necessary to operate the properties. Operating costs are divided into per-well costs and per-unit of production costs and are not escalated for inflation.

Capital costs used by NSAI were provided by us and are based on authorizations for expenditure. Capital costs are included as required for new development wells and production equipment, and are estimated to average $4,900,000 per well. Based on NSAI’s understanding of our future development plans, a review of the records which we provided

to NSAI, and NSAI’s knowledge of similar properties, NSAI regards these estimated capital costs to be reasonable. Abandonment costs were estimated at $75,000 per well. Abandonment costs were our estimates of the costs to abandon the wells and the production facilities, and are net of any salvage value. Capital costs and abandonment costs are not escalated for inflation.

San Andres Acreage — In addition to calculating the proved producing reserve estimates for the San Andres Acreage as of January 1, 2017 using Commission definitions and SEC Pricing, Mire also produced a report using the definitions and guidelines set forth in the Petroleum Resources Management System approved by SPE and NYMEX Futures Strip Pricing for the period of 2017-2021 as a sensitivity analysis in calculating future net revenues. This report was prepared at LEP’s request to assess commodity price risk as well as for a comparison to the historically low period of oil and gas prices captured in the reserve report using the Commission’s required pricing methodology. See “Business—Oil and Natural Gas Data.” A copy of the independent petroleum engineer’s reserve report containing its estimate of the San Andres Acreage net proved producing reserves and future net revenues therefrom using SPE definitions and NYMEX Futures Strip Pricing as of January 1, 2017 is included as Annex E to this Offering Circular.

The oil and gas prices applied by Mire in the sensitivity analysis were based on a NYMEX Futures Strip price deck as quoted on January 1, 2017 and provided below.

Sensitivity Analysis - NYMEX Futures Strip Pricing

Sensitivity Analysis

Gross revenue is our share of the gross (100 percent) revenue from the properties prior to any deductions. Future net revenue set forth in the sensitivity analysis table above is after deductions for our share of production taxes, ad valorem taxes, capital costs, abandonment costs, and operating expenses but before consideration of any income taxes.

Operating costs were based on historical expense data provided by LEP to Mire and which Mire analyzed on a per-lease basis. For some of the leases operating costs were divided into per-unit-of-production costs and per-well costs. As requested by us, operating costs were intended to be limited to direct lease and field-level costs and LEP’s estimate of the portion of its headquarters general and administrative overhead expenses necessary to operate the properties. Operating costs were not escalated for inflation.

Abandonment and lease restoration costs were not included in the analysis, as Mire determined that equipment salvage costs should cover these costs, based on per well estimates that were provided by LEP to Mire.

Uncertainties are inherent in estimating quantities of crude oil and natural gas reserves, including many risk factors beyond our control. These uncertainties are particularly significant for undeveloped reserves, especially probable undeveloped reserves, such as those located at our Eagle Ford Acreage. Reserve engineering is a subjective process of estimating subsurface accumulations of oil and natural gas that cannot be measured in an exact manner, and the accuracy of any reserve estimate is a function of the quality of available data and the interpretation thereof. As a result, estimates by different engineers often vary, sometimes significantly. In addition, physical factors such as the results of drilling, testing and production subsequent to the date of the estimates, as well as economic factors such as change in product prices, may require revision of such estimates. Accordingly, oil and natural gas quantities ultimately recovered will vary from reserve estimates.

Commodity Derivative Contracts — To reduce the impact of fluctuations in oil prices on our revenues, in the future, we may periodically enter into commodity derivative contracts with respect to certain of our potential future oil production through various transactions that limit the downside of future prices received. Future transactions may include price swaps whereby we will receive a fixed price for our production and pay a variable market price to the contract counterparty. Additionally, we may enter into collars, whereby we receive the excess, if any, of the fixed floor over the floating rate or pay the excess, if any, of the floating rate over the fixed ceiling price. These hedging activities are intended to support oil prices at targeted levels and to manage our exposure to oil price fluctuations.

Counterparty and Customer Credit Risk

Any derivative contracts we may enter into will expose us to credit risk in the event of nonperformance by a counterparty to that contract. We will evaluate the credit standing of such counterparties as we may deem appropriate at the time we enter into such a contract. This evaluation may include reviewing a counterparty’s credit rating and latest financial information.

Our principal exposure to credit risk will be through receivables resulting from the eventual sale of our oil and natural gas future production. The inability or failure of our significant customers to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results.

Interest Rate Risk

As of December 31, 2016, we do not have any outstanding credit facility or floating rate debt securities and are not directly subjected to interest rate risk. We may in the future incur such indebtedness. At such time, we will become subject to interest rate risk.

Subsequent Events

In January and February 2017, we raised additional capital through the sale of $525,000 of Pre-Paid Warrants to existing investors. The Pre-Paid Warrants will automatically be exchanged into shares of Common Stock upon the consummation of a qualified equity offering. The exchange price of the Pre-Paid Warrants is 75% of the share price in a qualified equity offering. This offering would constitute a qualified equity offering under the Pre-Paid Warrants.

On March 31, 2017, we entered into a subscription agreement under which we sold a $3,000,000 10.00% Senior Secured Promissory Note to one of our stockholders, SOHL. The Senior Secured Promissory Note was funded through three equal monthly draws of $1 million made in April, May, and June. The Senior Secured Promissory Note matures on September 1, 2017. Upon the occurrence of the maturity date, at the option of the holder, the Senior Secured Promissory Note may either become due and payable or convert into shares of Common Stock at 75% of the share price in a qualified equity offering. This offering would constitute a qualified equity offering under the Senior Secured Promissory Note. The Senior Secured Promissory Note is secured, pursuant to a deed of trust, by a first priority security interest in a 50% working interest in the profits from all oil and gas produced from the well recently drilled by us at the Gap Band Prospect, Karnes County, Texas. SOHL has indicated to us that it currently prefers to be repaid from the proceeds of this offering and does not intend to convert the Senior Secured Promissory Note into shares of our Common Stock.

On July 12, 2017, we entered into the Contribution Agreement with LEP. Pursuant to the Contribution Agreement, we agreed to acquire, to be effective as of June 1, 2017, the San Andres Acreage and certain other related wells, facilities, equipment and infrastructure (the “Acquisition”). The aggregate consideration for the Acquisition is approximately $22.7 million, subject to adjustment in accordance with the Contribution Agreement, consisting of approximately $10.6 million in Cash Consideration, and approximately $12.1 million in Stock Consideration. We

expect to fund the Cash Consideration from the proceeds of this offering. The number of shares of Common Stock to be issued as the Stock Consideration will be calculated based on the price per share issued in this offering. The closing of the Acquisition is subject to standard closing conditions and adjustments, including, but not limited to, the consummation of this offering with gross proceeds to us of not less than $35 million and net proceeds of not less than $32 million. The Contribution Agreement contains a price adjustment mechanism pursuant to which the purchase price for the Acquisition may be adjusted upward or downward for certain specified events, including, but not limited to, uncured environmental or title defects, or title benefits (as those terms are defined in the Contribution Agreement), which amount to greater than $1,075,000, approximately 5% of the purchase price. The parties have a 30-day period from the date of the Contribution Agreement to conduct further diligence and provide notice of any claimed defects or benefits. LEP has the right to cure title defects for 180 days after the closing date. The Contribution Agreement also contains customary representations, warranties and covenants of LEP and us. Pursuant to the Contribution Agreement, each party has agreed to indemnify the other party against certain claims and losses resulting from any breach of its representations, warranties or covenants. LEP has the right to terminate the Contribution Agreement if the closing of the Acquisition does not occur on or before September 30, 2017. In addition, both LEP and we have the right to terminate the Contribution Agreement if the aggregate sum of (i) title defect amounts, (ii) environmental defect amounts, and (iii) the value of assets destroyed by fire or other casualty or taken in condemnation or under right of eminent domain, collectively, exceeds $1,075,000. The Contribution Agreement also provides that we will enter into a registration rights agreement with LEP or its assignees at the closing of the Acquisition. Under the Contribution Agreement, we agreed to file an initial resale shelf registration statement with respect to the Stock Consideration within 180 days after closing of the Acquisition. The registration rights agreement will contain other customary terms, including piggyback registration rights, suspension rights, expenses and indemnification.

Critical Accounting Policies and Estimates

Critical accounting policies are defined as those that are reflective of significant judgments and uncertainties and that could potentially result in materially different results under different assumptions and conditions. Accounting policies are considered to be critical if (1) the nature of the estimates and assumptions is material due to the levels of subjectivity and judgment necessary to account for highly uncertain matters or the susceptibility of such matters to change, and (2) the impact of the estimates and assumptions on financial condition or operating performance is material. See Note 2 - Summary of Significant Accounting Policies in the Notes to the Financial Statements in this Offering Circular.

Use of Estimates in the Preparation of Financial Statements

The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and accompanying notes. Actual results could differ from those estimates.

Investment

Investment in common stock in which we hold less than a 20% voting interest and on which we do not have the ability to exercise significant influence are accounted for using the cost method of accounting. Under the cost method, an investor recognizes an investment in the stock of an investee as an asset and measured initially at cost. Subsequently, an investor recognizes as income dividends received that are distributed from earnings since the date of acquisition. A cost method investment is reviewed for impairment if factors indicate that a decrease in value of the investment has occurred. As of December 31, 2016, there was no impairment indicator on the cost of our cost method investment in the post-reorganization equity of Magnum Hunter Resources Corporation of $250,000.

Oil and Natural Gas Properties

We follow the successful efforts method of accounting for our oil and gas properties. Costs to acquire mineral interests in oil and gas properties and to drill and equip new development wells and related asset retirement costs are capitalized. Costs to acquire mineral interests and drill exploratory wells are also capitalized pending determination of whether the wells have proved reserves or not. These capitalized costs will be amortized using the unit-of-production method based on estimated proved reserves. Proceeds from sales of properties will be credited to property costs, and a gain or loss will be recognized when a significant portion of an amortization base is sold or abandoned. As of December 31, 2016, all properties were unproved and no drilling operations had begun.

Exploration costs, including geological and geophysical expenses and delay rentals, will be charged to expense as incurred. Exploratory drilling costs, including the cost of stratigraphic test wells, will be initially capitalized but will be charged to exploration expense if the well is determined to be nonproductive at that time. The determination of an exploratory well’s ability to produce must be made within one year from the completion of drilling activities. The acquisition costs of unproved acreage are initially capitalized and are carried at cost, net of accumulated impairment provisions, until such leases are transferred to proved properties or charged to exploration expense as impairments of unproved properties.

Provision for Depreciation, Depletion & Amortization (“DD&A”)

We will compute the provision for DD&A of oil and natural gas properties using the unit-of-production method. Proved acquisition costs will be depleted based on total proved reserves while well costs will be depleted based on proved developed reserves. Reserve estimates are expected to have a significant impact on the DD&A rate. Our properties are unproved and drilling has not yet begun, therefore, we have no production; however, when proved reserves are established through future drilling or otherwise acquired, these disclosures are expected to be material to our financial statements.

Impairment of Unproved Properties

Quarterly, we will review our unproved oil and gas properties to determine if there has been, in our judgment, impairment in value of each prospect that we consider individually significant. To the extent that the carrying cost of a prospect exceeds its estimated fair value, we will make a provision for impairment of unproved properties, and will record the provision as abandonments and impairments within exploration costs on our statement of operations. If the value is revised upward in a future period, we will not reverse the prior provision, and will continue to carry the prospect at a net cost that is lower than its estimated value. If the value is revised downward in a future period, an additional provision for impairment will be made in that period. We recently acquired the majority of our unproved properties and, therefore, no impairment was recorded as of December 31, 2016.

Oil and Gas Reserves

Reserve engineering is a subjective process of estimating underground accumulations of oil and gas that cannot be measured in an exact manner. The accuracy of a reserve estimate depends on the quality of available geological and engineering data, the precision of and the interpretation of that data, and judgment based on experience and training. Annually, we will engage one or more independent petroleum engineering firms to evaluate oil and gas reserves. As of December 31, 2016, all of our properties were unproved and drilling had not yet begun, however, when drilling begins and proved reserves are established, these disclosures are expected to be material to our financial statements.

Asset Retirement Obligations

We will record a liability relating to the plugging, abandonment and remediation of our producing properties. We will compute our liability for asset retirement obligations by calculating the present value of estimated future cash flows related to each property. This will require us to use significant assumptions, including current estimates of plugging and abandonment costs, annual inflation of these costs, the productive lives of wells and our risk-adjusted interest rate. Changes in any of these assumptions can result in significant revisions to the estimated asset retirement obligations.

Asset retirement obligations are recorded as a liability at the estimated present value at the asset’s inception, with an offsetting increase to producing properties in the accompanying balance sheet which is amortized to expense over the useful life of the asset. Periodic accretion of the discount on asset retirement obligations is recorded as an expense. All of our properties are unproved, therefore, we do not currently have any legal abandonment obligations. When drilling begins, however, these disclosures are expected to be material to our financial statements.

Revenue Recognition

When future production revenues are generated, we will utilize the sales method of accounting for our natural gas, crude oil and NGL revenues, whereby revenue will be recorded based on our share of volumes sold, regardless of whether we have taken our proportional share of volumes produced. A payable liability will be recognized only to the extent that we have a gas imbalance on a specific property greater than the expected remaining proved reserves.

JOBS Act

As an “emerging growth company” under the JOBS Act, we can take advantage of an extended transition period for complying with new or revised accounting standards. This allows an emerging growth company to delay the adoption of certain accounting standards until those standards would otherwise apply to private companies. We have elected to avail ourselves of this exemption and, as a result, our financial statements may not be comparable to the financial statements of issuers who are required to comply with the effective dates for new or revised accounting standards that are applicable to public companies. Section 107 of the JOBS Act provides that we can elect to opt out of the extended transition period at any time, which election is irrevocable.

We are in the process of evaluating the benefits of relying on other exemptions and reduced reporting requirements under the JOBS Act. Subject to certain conditions, as an emerging growth company, we intend to rely on certain of these exemptions, including without limitation (i) reduced financial statement reporting periods, (ii) an exemption from the requirement to provide an auditor’s attestation report on our system of internal controls over financial reporting pursuant to Section 404(b) of the Sarbanes-Oxley Act of 2002 and (iii) an exemption from compliance with any requirement that may be adopted by the Public Company Accounting Oversight Board regarding mandatory audit firm rotation or a supplement to the auditor’s report providing additional information about the audit and the financial statements, known as the auditor discussion and analysis. We will remain an emerging growth company until the earliest of: (a) the last day of the fiscal year in which we have total annual gross revenues of $1 billion or more; (b) the last day of the fiscal year following the fifth anniversary of the date of the completion of this offering; (c) the date on which we have issued more than $1 billion in nonconvertible debt during the previous three years; and (d) the date on which we are deemed to be a large accelerated filer under the rules of the SEC.

Recent Accounting Pronouncements

In May 2014, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) No. 2014-09 (“ASU 2014-09”), “Revenue from Contracts with Customers,” which requires an entity to recognize revenue representing the transfer of promised goods or services to customers in an amount that reflects the consideration which the company expects to receive in exchange for those goods or services. ASU 2014-09 is intended to establish principles for reporting useful information to users of financial statements about the nature, amount, timing and uncertainty of revenues and cash flows arising from the entity’s contracts with customers. ASU 2014-09 will replace most existing revenue recognition guidance in GAAP when it becomes effective. The new standard is effective for public entities on January 1, 2018 but is effective for us on January 1, 2019 due to our election to avail ourselves to the exemption of an extended transition period as an emerging growth company. The Company does not currently have any revenue and intends to assess the effect that ASU 2014-09 will have on its financial statements and related disclosures.

In February 2016, the FASB issued ASU No. 2016-02 (“ASU 2016-02”), “Leases (Topic 842).” ASU 2016-02 requires a lessee to recognize a lease liability for the obligation to make lease payments and a right-to-use asset for the right to use the underlying asset for the lease term. ASU 2016-02 is effective for public entities on January 1, 2019 but is effective for us on January 1, 2020 due to our election to avail ourselves to the exemption of an extended transition period as an emerging growth company. Early adoption is permitted. The Company is currently evaluating the effect that ASU 2016-02 will have on its financial statements and related disclosures.

In January 2017, the FASB issued ASU 2017-01, Business Combinations (Topic 805) which clarifies the definition of a business, assists in determining whether a transaction should be accounted for as an acquisition or disposal of assets or as a business. This ASU provides a screen that when substantially all of the fair value of the gross assets acquired, or disposed of, are concentrated in a single identifiable asset, or a group of similar identifiable assets, the asset will not be considered a business. If the screen is not met, an asset must include an input and a substantive process that together significantly contribute to the ability to create an output to be considered a business. This ASU is effective for public entities as of January 1, 2018, but is effective for us on January 1, 2019 due to our election to avail ourselves to the exemption of an extended transition period as an emerging growth company, and should be applied on a prospective basis to any transactions occurring within the period of adoption. The Company does not expect the implementation of ASU 2017-01 to have a material impact on its consolidated financial statements.

In January 2017, the FASB issued ASU 2017-11, “Accounting for Certain Financial Instruments with Down Round Features, Replacement of the Indefinite Deferral for Mandatorily Redeemable Financial Instruments of Certain Nonpublic Entities and Certain Mandatorily Redeemable Noncontrolling Interests with a Scope Exception.” Part I of this Update addresses the complexity of accounting for certain financial instruments with down round features.

Down round features are features of certain equity-linked instruments (or embedded features) that result in the strike price being reduced on the basis of the pricing of future equity offerings. Current accounting guidance creates cost and complexity for entities that issue financial instruments (such as warrants and convertible instruments) with down round features that require fair value measurement of the entire instrument or conversion option. Part II of this Update addresses the difficulty of navigating ASC 480, “Distinguishing Liabilities from Equity”, because of the existence of extensive pending content in the FASB Accounting Standards Codification. This pending content is the result of the indefinite deferral of accounting requirements about mandatorily redeemable financial instruments of certain nonpublic entities and certain mandatorily redeemable noncontrolling interests. This ASU is effective for public entities for fiscal years and interim periods within those fiscal years after December 15, 2018, but is effective for us after December 15, 2019 due to our election to avail ourselves to the exemption of an extended transition period as an emerging growth company. The Company is currently evaluating the effect that ASU 2017-11 will have on its financial statements and related disclosures.

BUSINESS

The following discussion should be read in conjunction with the accompanying financial statements and related notes included elsewhere in this Offering Circular.

Overview

We were founded in May 2016 by our Chairman and Chief Executive Officer, Gary C. Evans, a successful oil and natural gas operator and company builder with more than 35 years of energy industry experience. Our management team has a proven track record within each of our core geographic focus areas and intends to use the most recent horizontal drilling and fracture completion technology available today in order to optimize the development of hydrocarbons from these areas. Our primary mission is to target these areas and use our expertise to carefully select properties or prospects with lower risk to take advantage of what we believe to be a meaningful growth opportunity in an effort to deliver significant value to our shareholders.

We believe that several key factors have contributed to a favorable landscape whereby there exists significant potential to achieve attractive returns by acquiring and developing oil and natural gas assets in proven basins with limited geological risks. These factors include:

Following the closing of the San Andres Acreage acquisition, our core properties and focus will be located in Cochran County, Texas within the San Andres formation in the Northwest Shelf of West Texas. In addition, we are focused on certain areas of the Eagle Ford Shale Trend within South Texas, particularly Karnes County, Texas, the most productive oil producing region in the Eagle Ford Shale.

The San Andres formation is one of the most prolific conventional vertical plays in the United States and is productive throughout the Permian Basin. Over the past 50 years, San Andres production has made up approximately 40% of total oil production from the Permian Basin — 12 BBbl (and an additional 2 Tcf of gas) of the total 30 BBbl produced. However, this highly successful conventional play is now being re-developed into one of the best low-cost horizontal plays in the country with vertical recoveries having only produced 10-20% of primary reserves. In recent years, the introduction of horizontal drilling and multi-stage fracturing and completion techniques gives the play some of the best economic returns in the country. The San Andres formation has many of the same economic characteristics as the active and highly competitive re-development of the Spraberry and Wolfcamp formations within the Midland and Delaware Basins of West Texas and Southeast New Mexico, but in some cases, at a fraction of the drilling and completion costs compared to nearby formations. Each of these formations has large volumes of oil and gas in place, but hydrocarbons are not easily produced by conventional methods. Operators are now utilizing horizontal drilling and completion technologies to fully develop and/or re-develop these vast remaining reserves, thus creating an economically valuable opportunity.

Historically, the conventional vertical development of a San Andres field took many wells at 10, 20 and 40 acre spacing, which took 50+ years of production utilizing water and/or CO₂ secondary and tertiary recovery techniques in order to effectively drain the reservoir. Currently, a single 1 to 1.5 mile horizontal lateral, completed with multi-stage hydraulic fracturing techniques better stimulates the rock across the entire lateral section and results in

higher daily production and greater ultimate reserve recovery with more efficient drainage. Horizontal drilling enables the re-development of these fields much more quickly and efficiently thereby increasing IRRs on capital deployed.

Based upon results from new drilling techniques and industry well performance, the following key drivers can determine ultimate well performance in the San Andres:

To date, there exist only a few publicly-traded exploration and production companies active in the San Andres horizontal play as well as a large number of privately held independent operators. This unique area, its existing infrastructure, combined with numerous horizontal drilling locations, highly profitable recompletion opportunities, and the ability for horizontal re-development of the substantial reserves in place, provide significant growth opportunities for our shareholders.

Immediately after this offering, we will acquire the San Andres Acreage (approximately 9,413 net acres) within the prolific Slaughter-Levelland Field, which has produced over 2.3 BBbls of oil and 1.7 Tcf of gas. Upon closing, this acquisition will be effective for economic purposes as of June 1, 2017. See “San Andres Acreage Acquisition.” This acreage is HBP, which allows us to carefully re-complete and re-develop this property in a timely and efficient manner (“Phase 1”). In addition, the property has approximately 160 wells, full-field electricity, production facilities, significant active infrastructure and current salt water handling capability. We believe that there are 31 potential horizontal well locations to drill on the acreage to be acquired, assuming four laterals per 640-acre spacing.

During the quarter ended June 30, 2017, average daily production from the San Andres Acreage was approximately 82 BOPD, all of which was oil produced from 91 vertical wells operating on the acreage. Using the proceeds of this offering, we have immediate plans within the third and fourth quarters of 2017 to begin the re-completion program of the existing vertical wells in an effort to increase existing production under Phase 1. At the same time, we will also begin selecting horizontal well locations for our first two wells prior to year-end 2017 as part of the horizontal re-development (“Phase 2”) for the San Andres Acreage. Nearby and adjacent horizontal laterals have out-produced existing vertical wells.

Dominated by privately-owned E&P companies, many of the operators in the San Andres have been funded by leading private equity firms seeking to capture the exceptionally strong economics of the play. Approximately 164 horizontal San Andres wells have been drilled since January 2014. Given the increased activity and success we are seeing in the San Andres, some of the private equity backed companies in the play have recently been willing to monetize their position by selling for cash, equity, or a combination of both, to larger, publicly-traded companies. Pending such transactions and higher acreage values being realized, some industry experts believe that this evolving play will continue to garner industry attention during this lower commodity price environment.

In addition to our pending acquisition of the San Andres Acreage, we own and operate our Eagle Ford Acreage. The existing acreage is within a 250’ thick section in the heart of the Eagle Ford and Austin Chalk Trend in Karnes County, Texas. The lease acreage is ideally positioned for the continued development of three Eagle Ford Shale benches, and possibly the Austin Chalk formation. We drilled and cased the first Eagle Ford Shale well in this area, the Gap Band #2H, and are currently active in completion operations for hydraulic fracturing stimulation with first production in August/September 2017. We have internally planned for seven horizontal drilling locations (plus possibly two drilling locations in the Austin Chalk formation). We have permitted two additional Eagle Ford wells, the first of those to be drilled prior to the end of the first quarter of 2018.

San Andres Acreage Acquisition

On July 12, 2017, we entered into the Contribution Agreement with LEP. Pursuant to the Contribution Agreement, we agreed to acquire, to be effective as of June 1, 2017, the San Andres Acreage, which includes oil and gas leases covering approximately 9,413 net acres located in Cochran County, Texas within the San Andres oil play of the

Northwest Shelf of the Permian Basin, and certain other related wells, facilities, equipment and infrastructure (the “Acquisition”). The aggregate consideration for the Acquisition is approximately $22.7 million, subject to adjustment in accordance with the Contribution Agreement, consisting of approximately $10.6 million in Cash Consideration, and approximately $12.1 million in Stock Consideration. We expect to fund the Cash Consideration from the proceeds of this offering. The number of shares of Common Stock to be issued as the Stock Consideration pursuant to the Contribution Agreement will be calculated based on the price per share issued in this offering.

The closing of the Acquisition is subject to standard closing conditions and adjustments, including, but not limited to, the consummation of this offering with gross proceeds to us of not less than $35 million and net proceeds of not less than $32 million.

The Contribution Agreement contains a price adjustment mechanism pursuant to which the purchase price for the Acquisition may be adjusted upward or downward for certain specified events, including, but not limited to, uncured environmental or title defects, or title benefits (as those terms are defined in the Contribution Agreement), which amount to greater than $1,075,000, approximately 5% of the purchase price. The parties have a 30-day period from the date of the Contribution Agreement to conduct further diligence and provide notice of any claimed defects or benefits. LEP will have the right to cure title defects within 180 days after closing of the Acquisition.

The Contribution Agreement also contains customary representations, warranties and covenants of LEP and us. Pursuant to the Contribution Agreement, each party has agreed to indemnify the other party against certain claims and losses resulting from any breach of its representations, warranties or covenants.

LEP has the right to terminate the Contribution Agreement if the closing of the Acquisition does not occur on or before September 30, 2017. LEP and we each have the right to terminate the Contribution Agreement if the aggregate sum of (i) title defect amounts, (ii) environmental defect amounts, and (iii) the value of assets destroyed by fire or other casualty or taken in condemnation or under right of eminent domain, collectively, exceeds $1,075,000.

The Contribution Agreement also provides that we will enter into a registration rights agreement with LEP or its assignees at the closing of the Acquisition. Under the Contribution Agreement, we agreed to file an initial resale shelf registration statement with respect to the Stock Consideration within 180 days after closing of the Acquisition. The registration rights agreement will contain other customary terms, including piggyback registration rights, suspension rights, expenses and indemnification.

Oil and Natural Gas Data

Evaluation and Review of Proved Producing, Proved Undeveloped, and Probable Undeveloped Reserves. Our proved undeveloped and probable undeveloped reserve estimates as of May 31, 2017 relating to our Eagle Ford Acreage were prepared by NSAI, our independent petroleum engineer. The proved producing reserve estimates as of January 1, 2017 relating to the San Andres Acreage Acquisition were prepared by Mire in connection with the Acquisition.

Within NSAI the technical person primarily responsible for preparing the estimates for the Eagle Ford Acreage presented herein meets the requirements regarding qualifications, independence, objectivity, and confidentiality set forth in the SPE Standards. Neil H. Little, a Licensed Professional Engineer in the State of Texas, has been practicing consulting petroleum engineering at NSAI since 2011 and has over nine years of prior industry experience. NSAI are independent petroleum engineers, geologists, geophysicists, and petrophysicists; they do not own an interest in these properties nor are they employed on a contingent basis. Copies of NSAI’s reserve reports containing their estimates of reserves and related future net cash flows as of May 31, 2017 are included as Annex B and Annex C to this Offering Circular.

Within Mire, the technical person primarily responsible for preparing the estimates for the San Andres Acreage presented herein meets the requirements regarding qualifications, independence, objectivity, and confidentiality set forth in the SPE Standards. Kurt Mire, a Licensed Professional Engineer in the State of Texas, has been practicing consulting petroleum engineering at Mire since 2004 and has over seventeen years of prior industry experience. Mire are independent petroleum engineers, geologists, geophysicists, and petrophysicists; they do not own an interest in these properties nor are they employed on a contingent basis. Copies of Mire’s reserve reports containing their estimates of reserves and related future net cash flows as of January 1, 2017 are included as Annex D and Annex E to this Offering Circular.

We have internal geologists and geoscience professionals who worked closely with our independent petroleum engineer to ensure the integrity, accuracy and timeliness of the data used to calculate our proved undeveloped and

probable undeveloped reserves relating to our Eagle Ford Acreage. Our internal technical team members met with our independent petroleum engineer to discuss the assumptions and methods used in the proved undeveloped and probable undeveloped reserve estimation process. We provided information to NSAI for the Eagle Ford Acreage, such as ownership interest, commodity prices and operating and development costs. Kip Ferguson, Executive Vice President Exploration/Development, is primarily responsible for overseeing the preparation of all of our reserve estimates. Mr. Ferguson has more than 25 years of exploration and development experience in many of the major U.S. basins. His professional qualifications meet or exceed the qualifications of reserve estimators and auditors set forth in the “Standards Pertaining to Estimation and Auditing of Oil and Gas Reserves Information” promulgated by the Society of Petroleum Engineers. Mr. Ferguson reports directly to our Chief Executive Officer.

Estimation of Proved Reserves. Under SEC rules, proved reserves are those quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs and under existing economic conditions, operating methods and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. If deterministic methods are used, the SEC has defined reasonable certainty for proved reserves as a “high degree of confidence that the quantities will be recovered.” The estimation of reserves involves two distinct determinations. The first determination results in the estimation of the quantities of recoverable oil and natural gas and the second determination results in the estimation of the uncertainty associated with those estimated quantities in accordance with the definitions established under SEC rules. The process of estimating the quantities of recoverable oil and natural gas reserves relies on the use of certain generally accepted analytical procedures. These analytical procedures fall into four broad categories or methods: (i) production performance-based methods; (ii) material balance-based methods; (iii) volumetric-based methods; and (iv) analogy. These methods may be used singularly or in combination by the reserve evaluator in the process of estimating the quantities of reserves.

To estimate economically recoverable proved reserves and related future net cash flows, NSAI and Mire considered many factors and assumptions, including economic criteria based on current costs and the SEC pricing requirements and forecasts of future production rates.

Under SEC rules, reasonable certainty can be established using techniques that have been proven effective by actual production from projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology that establishes reasonable certainty. Reliable technology is a grouping of one or more technologies (including computational methods) that have been field tested and have been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation. To establish reasonable certainty with respect to our estimated proved reserves, the technologies and economic data used in the estimation of our proved reserves have been demonstrated to yield results with consistency and repeatability, and include geologic data, and analogous historical well cost and operating expense data.

Estimation of Probable Reserves. Under Commission rules, Probable Reserves are those quantities of oil and natural gas, which, by analysis of geoscience and engineering data are less certain to be recovered than proved reserves but are those unproved reserves which analysis suggests are more likely than not to be recoverable. In this context, when deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. When probabilistic methods are used, there should be at least a 50% probability that the quantities actually recovered will equal or exceed the sum of estimated proved plus probable reserves. Our probable undeveloped reserve estimates as of May 31, 2017, as prepared by NSAI, were estimated using deterministic methods. Estimates of Probable Reserves are less certain than estimates of proved reserves and are subject to substantially greater risk of not actually being realized. Probable Reserves include probable developed reserves and probable undeveloped reserves. Our Probable Reserves are probable undeveloped reserves, as described below (Summary of Oil and Natural Gas Reserves).

Uncertainties are inherent in estimating quantities of probable undeveloped reserves, including many risk factors beyond our control. Reserve engineering is a subjective process of estimating subsurface accumulations of oil and natural gas that cannot be measured in an exact manner, and the accuracy of any reserve estimate is a function of the quality of available data and the interpretation thereof. As a result, estimates by different engineers often vary, sometimes significantly. In addition, physical factors such as the results of drilling, testing and production subsequent to the date of the estimates, as well as economic factors such as changes in product prices, often require revision of such estimates. Accordingly, oil and natural gas quantities ultimately recovered will vary from reserve estimates.

Under Commission rules, more likely than not probability can be established using techniques that have been proven effective by actual production from projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology that establishes such probability. Reliable technology is a grouping of one or more technologies (including computational methods) that have been field tested and have been demonstrated to provide such results with consistency and repeatability in the formation being evaluated or in an analogous formation. To establish more likely than not probability with respect to our probable undeveloped reserves, the technologies and economic data used in the estimation of our probable undeveloped reserves have been demonstrated to yield results with consistency and repeatability, and include, local and regional production and test data, geologic data, and historical well cost and operating expense data.

For a discussion of the uncertainties associated with estimates of Proved Reserves and Probable Reserves, see “Risk Factors— Our reserve estimates depend on many assumptions that may turn out to be inaccurate. Any material inaccuracies in our reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.”

Summary of Oil and Natural Gas Reserves.

Eagle Ford Acreage

The following table presents our estimated net proved undeveloped and probable undeveloped oil and natural gas reserves as of May 31, 2017, based on the reserve report dated August 2, 2017 by NSAI, our independent petroleum engineer, prepared in accordance with the rules and regulations of the Commission. A copy of such proved undeveloped and probable undeveloped reserve report containing their estimates of reserves dated August 2, 2017 prepared by NSAI with respect to our properties is included as Annex B to this Offering Circular. All of our proved undeveloped and probable undeveloped reserves are located in the United States. We have no proved developed reserves or probable developed reserves on our Eagle Ford Acreage.

Pricing Based Upon Commission Rules

Sensitivity of Reserves to Prices By Principal Product Type and Price Scenario

In addition to calculating our proved undeveloped and probable undeveloped reserve estimates as of May 31, 2017 using Commission definitions and SEC Pricing, NSAI also produced a report using the definitions and guidelines set forth in the Petroleum Resources Management System approved by the SPE and NYMEX Futures Strip Pricing for the period of 2017-2021 as a sensitivity analysis in calculating proved undeveloped and probable undeveloped reserves and future net revenues. This report was prepared at our request as a comparison to the historically low period of oil and gas prices captured in the reserve report using SEC Pricing. A copy of our independent petroleum engineer’s reserve report containing its estimate of our net proved undeveloped and probable undeveloped reserves and future net revenues and the present value therefrom using SPE definitions and NYMEX Futures Strip Pricing dated August 3, 2017 is included as Annex C to this Offering Circular.

The oil and gas prices applied by NSAI in the sensitivity analysis were based on a NYMEX Futures Strip price deck as quoted on May 31, 2017 and provided below.

Sensitivity Analysis - NYMEX Futures Strip Pricing

Sensitivity Analysis

Gross revenue is our share of the gross (100 percent) revenue from the properties prior to any deductions. Future net revenue set forth in the sensitivity analysis table above is after deductions for our share of production taxes, ad valorem taxes, capital costs, abandonment costs, and operating expenses but before consideration of any income taxes.

NSAI estimated a declining operating cost schedule due to decreasing produced water volumes and changes in artificial lift method as wells mature. NSAI estimated operating costs based on the following per-well schedule:

At our request, operating costs are intended to be limited to direct lease and field-level costs and our estimate of the portion of our headquarters’ general and administrative overhead expenses necessary to operate the properties. Operating costs are divided into per-well costs and per-unit of production costs and are not escalated for inflation.

Capital costs used by NSAI were provided by us and are based on authorizations for expenditure. Capital costs are included as required for new development wells and production equipment, and are estimated to average $4,900,000 per well. Based on NSAI’s understanding of our future development plans, a review of the records which we provided to NSAI, and NSAI’s knowledge of similar properties, NSAI regards these estimated capital costs to be reasonable. Abandonment costs were estimated at $75,000 per well. Abandonment costs were our estimates of the costs to abandon the wells and the production facilities, and are net of any salvage value. Capital costs and abandonment costs are not escalated for inflation.

San Andres Acreage

The following table presents the estimated net proved developed producing oil and natural gas reserves for the San Andres Acreage as of January 1, 2017, based on the reserve report dated June 15, 2017 by Mire, independent petroleum engineer, prepared in accordance with the rules and regulations of the Commission. In general, under Commission rules, proved developed producing reserves are producing reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. A copy of such proved developed producing reserve report dated June 15, 2017 prepared by Mire with respect to the properties we will acquire in the Acquisition is included as Annex D to this Offering Circular. All of the San Andres Acreage’s proved developed producing reserves are located in the United States.

standardized measure of discounted future net cash flows as defined under GAAP. The 10% discount factor used to calculate the standardized measure and PV10, consistent with Commission guidance, is not necessarily the most appropriate discount rate under current or future market conditions. Present value, no matter what discount rate is used, is also materially affected by assumptions as to the volume and timing of future production, which may prove to be inaccurate.

Pricing Based Upon Commission Rules

Sensitivity of Reserves to Prices By Principal Product Type and Price Scenario

In addition to calculating the proved producing reserve estimates for the San Andres Acreage as of January 1, 2017 using Commission definitions and SEC Pricing, Mire also produced a report using the definitions and guidelines set forth in the Petroleum Resources Management System approved by SPE and NYMEX Futures Strip Pricing for the period of 2017-2021 as a sensitivity analysis in calculating future net revenues. This report was prepared at LEP’s request to assess commodity price risk as well as for a comparison to the historically low period of oil and gas prices captured in the reserve report using the Commission’s required pricing methodology. See “Business—Oil and Natural Gas Data.” A copy of the independent petroleum engineer’s reserve report dated June 16, 2017 containing its estimate of the San Andres Acreage net proved producing reserves and future net revenues therefrom using SPE definitions and NYMEX Futures Strip Pricing as of January 1, 2017 is included as Annex E to this Offering Circular.

The oil and gas prices applied by Mire in the sensitivity analysis were based on a NYMEX Futures Strip price deck as quoted on January 1, 2017 and provided below.

Sensitivity Analysis - NYMEX Futures Strip Pricing

Sensitivity Analysis

Gross revenue is our share of the gross (100 percent) revenue from the properties prior to any deductions. Future net revenue set forth in the sensitivity analysis table above is after deductions for our share of production taxes, ad valorem taxes, capital costs, abandonment costs, and operating expenses but before consideration of any income taxes.

Operating costs were based on historical expense data provided to Mire by LEP and which Mire analyzed on a per-lease basis. For some of the leases operating costs were divided into per-unit-of-production costs and per-well costs. As requested by us, operating costs were intended to be limited to direct lease and field-level costs and LEP’s estimate of the portion of its headquarters general and administrative overhead expenses necessary to operate the properties. Operating costs were not escalated for inflation.

Other Properties

In addition to the San Andres Acreage and Eagle Ford Acreage, we purchased a mineral interest from Acoma Energy LLC in Howard County, Texas for $293,360 in September 2016. The interest acquired comprises 13.33 net mineral acres in a unit, which is approximately 1,319 acres. This translates to a royalty interest of 0.25% per well drilled on the unit. The target zones of the Midland Basin in this area are the Lower Spraberry, Wolfcamp A, and Wolfcamp B. Three new wells have been recently drilled and completed on the acreage in which we have this mineral ownership interest, which management believes has increased the value of this asset.

Management

We believe our management team is in a prime position to take advantage of opportunities within the oil and gas industry and to create value for our stockholders. Our management team has deep knowledge of the industry and a well-established network of relationships with public and private oil and gas companies, equity sponsors, lending institutions, landowners, and service providers from which we expect to generate attractive acquisition opportunities. Our management also has a substantial history operating together as a team. For biographical information about the members of our management team, see “Management.”

Business Strategy

Exploit Initial Asset Portfolio — We intend to focus on the initial drilling and future development of our properties in the San Andres Formation and Eagle Ford Shale. As of June 30, 2017, the San Andres Acreage prospectively has up to 31 horizontal drilling locations and approximately 50 recompletion opportunities. 100 percent of the acreage is HBP. Our Eagle Ford Acreage includes seven identified potential drilling locations. Our first well was spud on April 14, 2017 and reached total depth on May 4, 2017. Completion activities are ongoing with first production expected to begin in August/September 2017.

Existing Infrastructure — Upon the purchase of the San Andres Acreage, Energy Hunter Resources will own and operate existing infrastructure including oil and natural gas gathering lines, salt water disposal wells (“SWD”), SWD gathering lines and injection pumps, and electricity lines, all of which are anticipated to significantly reduce initial costs and provide meaningful savings and efficiencies from field operating expenses. We will also acquire certain well inventory, including pumping units, artificial downhole equipment, tubular goods, and other related materials.

Look for Attractive Base Case Returns — While many oil and gas basins throughout the country remain marginally economic at current commodity strip prices, the Central Basin Platform and Eagle Ford Shale, as well as a few other basins located in West and South Texas, have been highly economic at prices below $50 per barrel. We seek to maximize stockholder value through a balanced program of acquisitions and low-risk development and exploitation drilling. Evidence of this strategy is noted in the low acreage cost for the San Andres Acreage ($2,250 per acre) as well as the below market price previously paid for the Eagle Ford Acreage ($2,500 per acre) which is surrounded by major and super independent oil companies.

Pursue Strategic Acquisitions with Significant Upside Potential — Management will target low-risk projects that offer meaningful potential production and reserve growth from existing reservoirs that have been under-exploited by previous owners. We will seek to serve as operator of the properties in which we acquire an ownership interest and initially concentrate these activities in the San Andres formation located in the Northwest Shelf of West Texas, the Eagle Ford Shale, located in South Texas, and other areas of the Permian Basin of West Texas and the Delaware Basin of Southeast New Mexico, which are among the areas where members of our management team have significant operating experience. Similar to our San Andres and Eagle Ford transactions, we intend to identify and opportunistically acquire additional lease acreage and reserves that have these characteristics.

Maintain Operating Control — We believe that operatorship provides the ability to maximize the value of our assets by allowing our experienced management team to control the timing of drilling expenditures, manage operational costs and enhance production volumes. Whenever possible, we will seek to serve as operator for the properties in which we acquire interests. We believe this flexibility to manage our drilling program allows us to optimize our returns and profitability.

Maintain Conservatively Capitalized Balance Sheet with Strong Liquidity Position — We currently intend to maintain a conservative approach to capitalizing our business and feel our minimal leverage will provide us with a significant advantage in the current volatile market environment. We expect to maintain an active hedging program that seeks to reduce our exposure to commodity price volatility and protect our cash flow.

Competitive Strengths

We believe the following strengths will help us achieve our business goals:

Experienced and Incentivized Management Team — With decades of experience, our management team has a proven track record of building and operating businesses focused on the development and acquisition of oil and natural gas properties. We believe our team’s deep knowledge of the major resource plays and operational expertise provide us with a competitive advantage. Additionally, our management’s extensive industry network provides us with access to top-tier industry partners, land owners and financial sponsors to help us identify and execute on attractive opportunities not generally known in the marketplace. Members of our senior management team have a significant economic interest in us, which will provide us a meaningful incentive to increase the value of our business for the benefit of all stockholders.

Attractive Acreage Position — Operating under the radar screen of many publicly traded companies, the San Andres formation was first discovered more than 50 years ago. Since 2009, more than 130 horizontal San Andres wells have been drilled. This horizontal well number continues to grow today as horizontal drilling technology has improved and overall costs have declined. Average well and completion costs in our region within the San Andres formation are approximately $2.4 million compared to $6 - $10 million well and completion costs in much of the deeper Permian and Delaware Basin properties being drilled today. In the Eagle Ford, all of our current acreage is located in Karnes County, Texas along the Edwards Trend in the heart of the Eagle Ford Shale play. According to monthly production data compiled by the Railroad Commission of Texas, Karnes County continues to be the top crude oil producing county in the State of Texas by volume. The Eagle Ford Shale play overlying the Edwards Trend is currently one of the most prolific liquids producers and currently generates some of the best economics in the Eagle Ford, even at recent commodity prices. Our assets provide development opportunities in a relatively mature, well-understood shale trend (as compared to other unconventional resource plays).

Proven Horizontal Drilling Expertise and Technical Acumen — Management has previously had success acquiring, developing, operating, and producing acreage in the Eagle Ford and Permian Basin. For example, several members of our management team were integral in the grass roots development of an Eagle Ford project located just one county over from our current Eagle Ford Acreage. Members of our team were key decision-makers at MHRC in growing an initial 2,000-net acre package into a 19,000-net acre asset through their knowledge of the specific land and geology, and relationships with landowners throughout the area. Ultimately, this asset produced 14,260 gross/5,277 net BOE/D at peak production for MHRC and was subsequently sold to a competitor.

High Degree of Operational Control. Our planned significant operational control will allow us to execute our development program, with a focus on the timing and allocation of capital expenditures and application of the optimal drilling and completion techniques to efficiently develop our resource base. We believe this flexibility will allow us to efficiently develop our current acreage and adjust drilling and completion activity opportunistically for the prevailing commodity price environment.

Stacked Pay Opportunities — In the Eagle Ford, we have identified seven potential undeveloped horizontal drilling locations (plus possibly two drilling locations in the Austin Chalk formation) across our three Eagle Ford benches and one Austin Chalk bench in the Gap Band Unit in Karnes County, Texas, which is partially evaluated in our proved undeveloped and probable undeveloped reserves as of May 31, 2017.

Marketing and Pricing

We currently plan to market the majority of the production from properties we will operate for both our account and the account of the other working interest owners in these properties. We currently plan to sell our production to

purchasers at then current market prices. We may, however, from time to time enter into commodity hedging or derivative contracts to mitigate the risks associated with the volatility of the price of crude oil, natural gas, and natural gas liquids.

Competition

The oil and natural gas industry is highly competitive in all phases. We encounter competition from other oil and natural gas exploration and production companies in all areas of operation, including the acquisition of leases. Our competitors include numerous independent oil and natural gas companies, financial sponsors, and individuals. Many of our competitors are large, well established companies that have substantially larger operating staffs and greater capital resources than we do. Our ability to acquire additional properties in the future will depend upon our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. Competition in the oil and natural gas industry is intense, which may adversely affect our ability to compete.

Seasonality of Business

Weather conditions affect the demand for, and prices of, oil and natural gas. Demand for oil and natural gas has historically been higher in the fourth and first quarters of each year resulting in higher prices. Due to these seasonal fluctuations, results of operations for individual quarterly periods may not be indicative of the results that may be realized on an annual basis.

Title to Properties

As is customary in the oil and natural gas industry, we initially conduct a limited review of the title to our properties in connection with acquisition of leasehold acreage. At such time as we determine to conduct drilling operations on those properties, we will conduct a more thorough title examination and perform curative work with respect to significant defects prior to commencement of drilling operations. To the extent title opinions or other investigations reflect title defects on those properties, we will typically be responsible for curing any title defects at our expense. We generally will not commence drilling operations on a property until we have cured any material title defects on such property.

Prior to completing an acquisition of producing oil and natural gas leases, we perform title reviews on the most significant leases and, depending on the materiality of properties, we may obtain a title opinion, obtain an updated title review or opinion or review previously obtained title opinions. Our oil and natural gas properties are expected to be subject to customary royalty and other interests, liens for current taxes and other burdens which we believe typically do not materially interfere with the use of or affect our carrying value of the properties.

We believe that we have satisfactory title to all of our material current assets. Title to these properties is subject to encumbrances in some cases, such as customary interests generally retained in connection with the acquisition of real property, customary royalty interests and contract terms and restrictions, liens for current taxes and other burdens, easements, restrictions and minor encumbrances customary in the oil and natural gas industry. However, we believe that none of these liens, restrictions, easements, burdens and encumbrances will materially detract from the value of these properties or from our interest in these properties or materially interfere with our use of these properties in the operation of our business. In addition, we believe that we have obtained sufficient rights-of-way grants and permits from public authorities and private parties for us to operate our business in all material respects as described in this Offering Circular.

In connection with the San Andres Acreage Acquisition, the Contribution Agreement contains a price adjustment mechanism pursuant to which the purchase price for the Acquisition may be adjusted upward or downward for certain specified events, including, but not limited to, uncured environmental or title defects, or title benefits (as those terms are defined in the Contribution Agreement), which amount to greater than $1,075,000, approximately 5% of the purchase price. The parties have a 30-day period from the date of the Contribution Agreement to conduct further diligence and provide notice of any claimed defects or benefits. LEP will have the right to cure title defects for 180 days after closing of the Acquisition.

Oil and Natural Gas Leases

The typical oil and natural gas lease agreement covering our properties provides for the payment of royalties to the mineral owner for all oil and natural gas produced from any wells drilled on the leased premises. We anticipate the lessor royalties and other leasehold burdens on our properties generally will range from 20% to 25%, resulting in a net revenue interest to us generally ranging from 75% to 80%.

Operating Hazards and Risks

Drilling activities are subject to many risks, including the risk that no commercially productive reservoirs will be encountered. There can be no assurance that any of the wells we drill will be productive or that we will recover all or any portion of our investment. Drilling for oil and natural gas may involve unprofitable efforts, not only from dry wells, but also from wells that are productive, but do not produce sufficient net revenues to return a profit after drilling, operating and other costs. The cost and timing of drilling, completing and operating wells is often uncertain. Our drilling operations may be curtailed, delayed or canceled as a result of numerous factors, many of which are beyond our control, including low oil and natural gas prices, title problems, unexpected drilling conditions, weather conditions, delays by project participants, compliance with governmental requirements, shortages or delays in the delivery of equipment and services and increases in the cost for such equipment and services. Our drilling activities may not be successful and, if unsuccessful, such failure may have a material adverse effect on our business, financial condition, results of operations and cash flows.

Our operations will be subject to hazards and risks inherent in drilling for and producing and transporting oil and natural gas, such as fires, natural disasters, explosions, encountering formations with abnormal pressures, blowouts, craterings, pipeline ruptures and spills, any of which can result in the loss of hydrocarbons, environmental pollution, personal injury claims and other damage to our properties and those of others. We will maintain insurance against some but not all of the risks described above. In particular, the insurance we will maintain does not cover claims relating to failure of title to oil and natural gas leases, loss of surface equipment at well locations, business interruption, loss of revenue due to low commodity prices or loss of revenues due to well failure. Furthermore, in certain circumstances where such insurance is available, we may determine not to purchase it due to cost or other factors. The occurrence of an event that is not covered by, or not fully covered by insurance could have a material adverse effect on our business, financial condition, results of operations and cash flows in the period such event may occur.

Regulation of the Oil and Natural Gas Industry

Our operations are substantially affected by federal, state and local laws and regulations. In particular, natural gas production and related operations are, or have been, subject to price controls, taxes and numerous other laws and regulations. All of the jurisdictions in which we own or will operate producing oil and natural gas properties have statutory provisions regulating the development 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 crude 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.

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. Although we believe we are in substantial compliance with all applicable laws and regulations, such laws and regulations are frequently amended or reinterpreted. Therefore, 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, Federal Energy Regulatory Commission (“FERC”) and the courts. We cannot predict when or whether any such proposals may become effective.

We believe we are in substantial compliance with currently applicable laws and regulations and that continued substantial compliance with existing requirements will not have a material adverse effect on our financial position, cash flows or results of operations. However, current regulatory requirements may change, currently unforeseen environmental incidents may occur or past non-compliance with environmental laws or regulations may be discovered.

Regulation of Production of Oil and Natural Gas

The production of oil and natural gas is subject to regulation under a wide range of local, state and federal statutes, rules, orders and regulations. Federal, state and local statutes and regulations require permits for drilling operations, drilling bonds and reports concerning operations. We own interests in properties located in Texas, which regulates

drilling and operating activities by, among other things, requiring permits for the drilling of wells, maintaining bonding requirements in order to drill or operate wells, and regulating the location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled and the plugging and abandonment of wells. The laws of Texas also govern a number of conservation matters, including provisions for the unitization or pooling of oil and natural gas properties, the establishment of maximum allowable rates of production from oil and natural gas wells, the regulation of well spacing or density, and plugging and abandonment of wells. The effect of these regulations is to limit the amount of oil and natural gas that we will be able to produce and to limit the number of wells or the locations at which we can drill, although we can apply for exceptions to such regulations or to have reductions in well spacing or density. Moreover, Texas imposes a production or severance tax with respect to the production and sale of oil, natural gas and NGLs within its jurisdiction.

The failure to comply with these rules and regulations can result in substantial penalties. Our competitors in the oil and natural gas industry are generally subject to the same regulatory requirements and restrictions that affect our operations.

Regulation of Sales and Transportation of Oil

Sales of oil, condensate and NGLs are not currently regulated and are made at negotiated prices. Nevertheless, Congress could reenact price controls in the future.

Our future sales of oil are affected by the availability, terms and cost of transportation. The transportation of oil in common carrier pipelines is also subject to rate and access regulation. FERC regulates interstate oil pipeline transportation rates under the Interstate Commerce Act. In general, interstate oil pipeline rates must be cost-based, although settlement rates agreed to by all shippers are permitted and market-based rates may be permitted in certain circumstances.

Intrastate oil pipeline transportation rates are subject to regulation by state regulatory commissions. The basis for intrastate oil pipeline regulation, and the degree of regulatory oversight and scrutiny given to intrastate oil pipeline rates, varies from state to state. Insofar as effective interstate and intrastate rates and regulations regarding access are equally applicable to all comparable shippers, we believe that the regulation of oil transportation will not affect our operations in any way that is of material difference from those of our competitors who are similarly situated.

Regulation of Transportation and Sales of Natural Gas

Historically, the transportation and sale for resale of natural gas in interstate commerce have been regulated by agencies of the U.S. federal government, primarily FERC. In the past, the federal government has regulated the prices at which natural gas could be sold. While sales by producers of natural gas can currently be made at uncontrolled market prices, Congress could reenact price controls in the future. Deregulation of wellhead natural gas sales began with the enactment of the National Gas Policy Act (“NGPA”), and culminated in adoption of the Natural Gas Wellhead Decontrol Act which removed controls affecting wellhead sales of natural gas effective January 1, 1993. The transportation and sale for resale of natural gas in interstate commerce is regulated primarily under the Natural Gas Act of 1938 (“NGA”), and by regulations and orders promulgated under the NGA by FERC. In certain limited circumstances, intrastate transportation and wholesale sales of natural gas may also be affected directly or indirectly by laws enacted by Congress and by FERC regulations.

The Energy Policy Act of 2005 (“EP Act”) is a comprehensive compilation of tax incentives, authorized appropriations for grants and guaranteed loans, and significant changes to the statutory policy that affects all segments of the energy industry. Among other matters, the EP Act amends the NGA to add an anti-market manipulation provision which makes it unlawful for any entity to engage in prohibited behavior to be prescribed by FERC, and furthermore provides FERC with additional civil penalty authority. The EP Act provides FERC with the power to assess civil penalties of up to $1,000,000 per day for violations of the NGA and increases FERC’s civil penalty authority under the NGPA from $5,000 per violation per day to $1,000,000 per violation per day. The civil penalty provisions are applicable to entities that engage in the sale of natural gas for resale in interstate commerce. On January 19, 2006, FERC issued Order No. 670, a rule implementing the anti-market manipulation provision of the EP Act, and subsequently denied rehearing. The rules make it unlawful, in connection with the purchase or sale of natural 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: (i) use or employ any device, scheme or artifice to defraud; (ii) make any untrue statement of material fact or omit to make any such statement necessary to make the statements made not misleading; or (iii) engage in any act or practice that operates as a fraud or deceit upon any

person. The new anti-market manipulation rule does not apply to activities that relate only to intrastate or other non-jurisdictional sales or gathering, but does apply to activities of gas pipelines and storage companies that provide interstate services, as well as otherwise non-jurisdictional entities to the extent the activities are conducted “in connection with” gas sales, purchases or transportation subject to FERC jurisdiction, which now includes the annual reporting requirements under Order 704, described below. The anti-market manipulation rule and enhanced civil penalty authority reflect an expansion of FERC’s NGA enforcement authority.

On December 26, 2007, FERC issued Order 704, a final rule on the annual natural gas transaction reporting requirements, as amended by subsequent orders on rehearing. Under Order 704, wholesale buyers and sellers of more than 2.2 million MMBtus of physical natural gas in the previous calendar year, including natural gas producers, gatherers and marketers, are now required to report, on May 1 of each year, aggregate volumes of natural gas purchased or sold at wholesale in the prior calendar year to the extent such transactions utilize, contribute to, or may contribute to the formation of price indices. It is the responsibility of the reporting entity to determine which individual transactions should be reported based on the guidance of Order 704. Order 704 also requires market participants to indicate whether they report prices to any index publishers, and if so, whether their reporting complies with FERC’s policy statement on price reporting.

Gathering service, which occurs upstream of jurisdictional transmission services, is regulated by the states onshore and in state waters. Section 1(b) of the NGA exempts natural gas gathering facilities from regulation by FERC as a natural gas company under the NGA. Although FERC has set forth a general test for determining whether facilities perform a non-jurisdictional gathering function or a jurisdictional transmission function, FERC’s determinations as to the classification of facilities are done on a case-by-case basis. To the extent that FERC issues an order that reclassifies certain jurisdictional transmission facilities as non-jurisdictional gathering facilities, and depending on the scope of that decision, our costs of getting gas to point of sale locations may increase.

The price at which we will sell natural gas is not currently subject to federal rate regulation and, for the most part, is not subject to state regulation. However, with regard to our physical sales of these energy commodities, we will be required to observe anti-market manipulation laws and related regulations enforced by FERC under the EP Act and under the Commodity Exchange Act (“CEA”), and regulations promulgated thereunder by the Commodity Futures Trading Commission. The CEA prohibits any person from manipulating or attempting to manipulate the price of any commodity in interstate commerce or futures on such commodity. The CEA also prohibits knowingly delivering or causing to be delivered false or misleading or knowingly inaccurate reports concerning market information or conditions that affect or tend to affect the price of a commodity. Should we violate the anti-market manipulation laws and regulations, we could also be subject to related third-party damage claims by, among others, sellers, royalty owners and taxing authorities.

Intrastate natural gas transportation is also subject to regulation by state regulatory agencies. The basis for intrastate regulation of natural gas transportation and the degree of regulatory oversight and scrutiny given to intrastate natural gas pipeline rates and services varies from state to state. Insofar as such regulation within a particular state will generally affect all intrastate natural gas shippers within the state on a comparable basis, we believe that the regulation of similarly situated intrastate natural gas transportation in any states in which we operate and ship natural gas on an intrastate basis will not affect our operations in any way that is of material difference from those of our competitors. Like the regulation of interstate transportation rates, the regulation of intrastate transportation rates affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas.

Changes in law and to FERC or state policies and regulations may adversely affect the availability and reliability of firm and/or interruptible transportation service on interstate and intrastate pipelines, and we cannot predict what future action FERC or state regulatory bodies will take. We do not believe, however, that any regulatory changes will affect us in a way that materially differs from the way they would affect other natural gas producers and marketers with which we compete.

Regulation of Environmental and Occupational Safety and Health Matters

Our current and anticipated oil and natural gas development operations are and will be subject to numerous stringent federal, regional, state and local statutes and regulations governing occupational safety and health, the discharge of materials into the environment or otherwise relating to environmental protection, some of which carry substantial administrative, civil and criminal penalties for failure to comply. These laws and regulations may require the acquisition of a permit before construction, drilling or other regulated activity commences; restrict the types, quantities and concentrations of various substances that can be released into the environment in connection with

drilling, production and transporting through pipelines; govern the sourcing and disposal of water used in the drilling and completion process; limit or prohibit drilling activities in certain areas and on certain lands lying within wilderness, wetlands, endangered species habitat, frontier and other protected areas; require some form of remedial action to prevent or mitigate pollution from former operations such as plugging abandoned wells or closing earthen pits; establish specific safety and health criteria addressing worker protection; and impose substantial liabilities for pollution resulting from operations or failure to comply with regulatory filings. In addition, these laws and regulations may restrict the rate of production.

The following is a summary of the more significant existing environmental and occupational health and safety laws and regulations, as amended from time to time, to which our business operations are subject and for which compliance may have a material adverse impact on our capital expenditures, results of operations or financial position.

Hazardous Substances and Waste Handling

The Comprehensive Environmental Response, Compensation, and Liability Act of 1980 (“CERCLA”), also known as the “Superfund” law, and comparable state laws impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons that are considered to have contributed to the release of a “hazardous substance” into the environment. These persons include the current and past owner or operator of the disposal site or the site where the release occurred and companies that disposed or arranged for the disposal of the hazardous substances at the site where the release occurred. Under CERCLA, such persons may be subject to joint and several strict liability for the costs of cleaning up the hazardous substances that have been released into the environment and for damages to natural resources, and it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. We will be able to control directly the operation of only those wells with respect to which we act as operator. Notwithstanding our lack of direct control over wells operated by others, the failure of an operator other than us to comply with applicable environmental regulations may, in certain circumstances, be attributed to us. We generate materials in the course of our operations that may be regulated as hazardous substances but we are unaware of any liabilities for which we may be held responsible that would materially and adversely affect us.

The Resource Conservation and Recovery Act (“RCRA”) and analogous state laws, impose detailed requirements for the generation, handling, storage, treatment and disposal of nonhazardous and hazardous solid wastes. RCRA specifically excludes drilling fluids, produced waters and other wastes associated with the development or production of crude oil, natural gas or geothermal energy from regulation as hazardous wastes. However, these wastes may be regulated by the EPA or state agencies under RCRA’s less stringent nonhazardous solid waste provisions, state laws or other federal laws. Moreover, it is possible that these particular oil and natural gas development and production wastes now classified as nonhazardous solid wastes could be classified as hazardous wastes in the future. For example, from time to time various environmental groups have challenged the EPA’s exemption of certain oil and gas wastes from RCRA. A loss of the RCRA exclusion for drilling fluids, produced waters and related wastes could result in an increase in our costs to manage and dispose of generated wastes, which could have a material adverse effect on our results of operations and financial position. In addition, in the course of our operations, we generate some amounts of ordinary industrial wastes, such as paint wastes, waste solvents, laboratory wastes and waste compressor oils that may be regulated as hazardous wastes if such wastes are listed as hazardous by the EPA or have hazardous characteristics. Although the costs of managing hazardous waste may be significant, we do not believe that our costs in this regard are materially more burdensome than those for similarly situated companies.

We currently own and operate properties that have been used for oil and natural gas development and production activities for many years. Although we believe that prior operators 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 recycling 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.

Water Discharges

The federal Clean Water Act and comparable state laws impose restrictions and strict controls regarding the discharge of pollutants, including produced waters and other oil and natural gas wastes, into or near navigable waters. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or the state. The discharge of dredge and fill material in regulated waters, including wetlands, is also prohibited, unless authorized by a permit issued by the U.S. Army Corps of Engineers (the “Corps”). In September 2015, the EPA and the Corps issued new rules defining the scope of the EPA’s and the Corps’ jurisdiction under the Clean Water Act with respect to certain types of waterbodies and classifying these waterbodies as regulated Waters of the United States (“WOTUS rule”). To the extent the WOTUS rule expands the scope of the Clean Water Act’s jurisdiction, we could face increased costs and delays with respect to obtaining permits for dredge and fill activities in wetland areas. The WOTUS rule has been challenged in court on the grounds that it unlawfully expands the reach of the Clean Water Act, and implementation of the rule has been stayed pending resolution of the court challenge. In addition, President Trump issued an Executive Order in February 2017 directing that the WOTUS rule be reviewed and revised. In July 2017, the EPA and the Corps issued a proposed rule which would rescind the 2015 WOTUS rule. Obtaining permits has the potential to delay the development of oil and natural gas projects. These laws and any implementing regulations provide for administrative, civil and criminal penalties for any unauthorized discharges of oil and other substances in reportable quantities and may impose substantial potential liability for the costs of removal, remediation and damages.

Pursuant to these laws and regulations, we may be required to obtain and maintain approvals or permits for the discharge of wastewater or storm water and are required to develop and implement spill prevention, control and countermeasure plans, also referred to as “SPCC plans,” in connection with on-site storage of significant quantities of oil. We believe that we maintain all required discharge permits necessary to conduct our operations, and further believe we are in substantial compliance with the terms thereof. We are currently undertaking a review of recently acquired oil properties to determine the need for new or updated SPCC plans and, where necessary, we will be developing or upgrading such plans implementing the physical and operation controls imposed by these plans, the costs of which are not expected to be substantial.

The primary federal law related specifically to oil spill liability is the Oil Pollution Act of 1990 (“OPA”), which amends and augments the oil spill provisions of the Clean Water Act and imposes certain duties and liabilities on certain “responsible parties” related to the prevention of oil spills and damages resulting from such spills in or threatening waters of the United States or adjoining shorelines. For example, operators of certain oil and natural gas facilities must develop, implement and maintain facility response plans, conduct annual spill training for certain employees and provide varying degrees of financial assurance. Owners or operators of a facility, vessel or pipeline that is a source of an oil discharge or that poses the substantial threat of discharge is one type of “responsible party” who is liable. The OPA applies joint and several liability, without regard to fault, to each liable party for oil removal costs and a variety of public and private damages. Although defenses exist, they are limited. As such, a violation of the OPA has the potential to adversely affect our operations.

Air Emissions

The federal Clean Air Act and comparable state laws restrict the emission of air pollutants from many sources, such as, for example, compressor stations and tank batteries, through air emissions standards, construction and operating permitting programs and the imposition of other compliance requirements. 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. Over the next several years, we may be required to incur certain capital expenditures for air pollution control equipment or other air emissions related issues. For example, in October 2015, the EPA lowered the National Ambient Air Quality Standard (“NAAQS”) for ozone from 75 to 70 parts per billion. State implementation of the revised NAAQS could result in stricter permitting requirements, delay or prohibit our ability to obtain such permits, and result in increased expenditures for pollution control equipment, the costs of which could be significant. In addition, the EPA has adopted new rules under the Clean Air Act that require the reduction of volatile organic compound emissions from certain fractured and refractured natural gas wells for which well completion operations are conducted and further require that most wells use reduced emission completions, also known as “green completions.” These regulations also establish specific new requirements regarding emissions from production-related wet seal and reciprocating compressors, and from pneumatic controllers and storage vessels. In May 2016, the EPA finalized rules 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 air permitting processes and requirements. Compliance with these and other air pollution control and permitting requirements has the potential to delay the development of oil and natural gas projects and increase our costs of development, which costs could be significant. However, we do not believe that compliance with such requirements will have a material adverse effect on our operations.

A suit challenging the EPA’s ozone NAAQS, Murray Energy Corp. v. EPA, is currently pending in the D.C. Circuit. However, on April 11, 2017, the D.C. Circuit granted EPA’s motion to indefinitely delay any decision on the challenges. In its motion, the EPA cited President Trump’s March 2017 Executive Order that directed the EPA to review for possible reconsideration any rule that could potentially burden the development of domestic energy sources.

Regulation of Greenhouse Gas (“GHG”) Emissions

In response to findings that emissions of carbon dioxide, methane and other GHGs present an endangerment to public health and the environment, the EPA has adopted regulations pursuant to the federal Clean Air Act that, among other things, require preconstruction and operating permits for certain large stationary sources. Facilities required to obtain preconstruction permits for their GHG emissions are also required to meet “best available control technology” standards that are being established by the states or, in some cases, by the EPA on a case-by-case basis. These regulatory requirements could adversely affect our operations and restrict or delay our ability to obtain air permits for new or modified sources. In addition, the EPA has adopted rules requiring the monitoring and reporting of GHG emissions from specified onshore and offshore oil and natural gas production sources in the United States on an annual basis, which include certain of our operations. Furthermore, in June 2016, the EPA issued rules that establish new controls for emissions of methane from new, modified or reconstructed sources in the oil and natural gas source category, including production, processing, transmission and storage activities. The rule includes first-time standards to address emissions of methane from equipment and processes across the source category, including hydraulically fractured oil and natural gas well completions. The EPA has also announced that it intends to impose methane emission standards for existing sources as well but, to date, has not yet issued a proposal. Compliance with these rules will require enhanced record-keeping practices, the purchase of new equipment such as optical gas imaging instruments to detect leaks, and increased frequency of maintenance and repair activities to address emissions leakage. The rules will also likely require hiring additional personnel to support these activities or the engagement of third party contractors to assist with and verify compliance. In March 2017, President Trump issued an executive order which among other things, directed the EPA to review, rescind, suspend and revise these rules. In response to this executive order the new administrator of the EPA stayed implementation of portions of the final rule. This administrative stay was vacated by the D.C. Circuit as being arbitrary, capricious and in excess of statutory authority on July 3, 2017. Thus, relief from the requirements imposed by these rules will be dependent upon further court action or a new rule making proceeding. These new rules could result in increased compliance costs on our operations.

While Congress has from time to time considered legislation to reduce emissions of GHGs, there has not been significant activity in the form of adopted legislation to reduce GHG emissions at the federal level in recent years. In the absence of such federal climate legislation, a number of state and regional efforts have emerged that are aimed at tracking and/or reducing GHG emissions by means of cap and trade programs. These programs typically require major sources of GHG emissions to acquire and surrender emission allowances in return for emitting those GHGs. In addition, efforts have been made and continue to be made in the international community toward the adoption of international treaties or protocols that would address global climate change issues. In April 2016, the United States was one of 175 countries to ratify the Paris Agreement, which requires 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. More recently, on June 1, 2017, the Trump administration announced that the U.S. will withdraw from the Paris Agreement. Nevertheless, numerous U.S. governors, mayors and businesses have pledged their commitments to the goals of the Paris Agreement. These commitments could further reduce demand and prices for our hydrocarbons or result in additional operational and capital costs necessary to control GHG emissions.

Although it is not possible at this time to predict how federal, state, or local legislation or new regulations that may be adopted to address GHG emissions would impact our business, any such future laws and regulations imposing reporting obligations on, or limiting emissions of GHGs from, our equipment and operations could require us to incur costs to reduce emissions of GHGs associated with our operations. Substantial limitations on GHG emissions could adversely affect demand for the oil and natural gas we produce. Finally, it should be noted that climate change may

cause more extreme weather conditions and increased volatility in seasonal temperatures. Extreme weather conditions could have a material adverse effect on our operations and damage resulting from extreme weather may not be fully insured.

Hydraulic Fracturing Activities

Hydraulic fracturing is an important and common practice that is used to stimulate production of oil and/or natural gas from dense subsurface rock formations. The hydraulic fracturing process involves the injection of water, proppants (a solid material designed to keep the fracture open) and chemicals under pressure into targeted subsurface formations to fracture the surrounding rock and stimulate production. We intend to regularly use hydraulic fracturing as part of our operations.

Hydraulic fracturing is typically regulated by state oil and natural gas commissions, but the EPA has asserted federal regulatory authority pursuant to the Safe Drinking Water Act (“SDWA”) over certain hydraulic fracturing activities involving the use of diesel fuels and published permitting guidance in February 2014 addressing the performance of such activities using diesel fuels.

The EPA has also issued final regulations under the federal Clean Air Act establishing performance standards, including standards for the capture of air emissions released during hydraulic fracturing, and advanced notice of proposed rulemaking under the Toxic Substances Control Act to require companies to disclose information regarding the chemicals used in hydraulic fracturing, and also finalized rules in June 2016 that prohibit the discharge of wastewater from hydraulic fracturing operations to publicly owned wastewater treatment plants. In addition, the Bureau of Land Management finalized rules in March 2015 that impose new or more stringent standards for performing hydraulic fracturing on federal and American Indian lands. In June 2016, the U.S. District Court of Wyoming struck down implementation of the Bureau of Land Management’s rules. This rule was also the subject of an executive order issued by President Trump requiring the Department of Interior to review, rescind, suspend and revise the rule. On July 25, 2017, the Bureau of Land Management proposed a rule rescinding the rules regulating hydraulic fracturing. In addition, Congress has from time to time considered legislation to provide for federal regulation of hydraulic fracturing under the SDWA and to require disclosure of the chemicals used in the hydraulic fracturing process. It is unclear how any additional federal regulation of hydraulic fracturing activities may affect our operations.

At the state level, several states have adopted or are considering legal requirements that could impose more stringent permitting, disclosure and well construction requirements on hydraulic fracturing activities. For example, in May 2013, the Railroad Commission of Texas issued a “well integrity rule,” which updates the requirements for drilling, putting pipe down and cementing wells. The rule also includes new testing and reporting requirements, such as (i) the requirement to submit cementing reports after well completion or after cessation of drilling, whichever is later, and (ii) the imposition of additional testing on wells less than 1,000 feet below usable groundwater. The well integrity rule took effect in January 2014. Local governments also may seek to adopt ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular. We believe that we will be following applicable standard industry practices and legal requirements for groundwater protection in our hydraulic fracturing activities. Nonetheless, if new or more stringent federal, state or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where we operate, we could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of development activities, and perhaps even be precluded from drilling wells.

ESA and Migratory Birds

The Endangered Species Act (“ESA”) and (in some cases) comparable state laws were established to protect endangered and threatened species. Pursuant to the ESA, if a species is listed as threatened or endangered, restrictions may be imposed on activities adversely affecting that species’ habitat. Similar protections are offered to migratory 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. The U.S. Fish and Wildlife Service may designate critical habitat and suitable habitat areas that it believes are necessary for survival of a threatened or endangered species. A critical habitat or suitable habitat designation could result in further material restrictions to federal land use and may materially delay or prohibit land access for oil and natural gas development. Moreover, as a result of a settlement approved by the U.S. District Court for the District of Columbia in September

2011, the U.S. Fish and Wildlife Service is required to make a determination on listing of more than 250 species as endangered or threatened under the ESA by no later than completion of the agency’s 2017 fiscal year. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act. The federal government recently issued indictments under the Migratory Bird Treaty Act to several oil and natural gas companies after dead migratory birds were found near reserve pits associated with drilling activities. 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 or could result in limitations on our development 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 Act (“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. We believe that we are in substantial compliance with all applicable laws and regulations relating to worker health and safety.

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 have not experienced any material adverse effect from compliance with environmental requirements; however, there is no assurance that this will continue. We did not have any material capital or other non-recurring expenditures in connection with complying with environmental laws or environmental remediation matters, nor do we anticipate that such expenditures will be material in 2017.

Related Insurance

We anticipate maintaining certain types of insurance against some risks associated with above or underground contamination that may occur as a result of our development activities. However, this type of insurance is limited to activities at the well site and there can be no assurance that this insurance will continue to be commercially available or that this insurance will be available at premium levels that justify its purchase by us. The occurrence of a significant event that is not fully insured or indemnified against could have a materially adverse effect on our financial condition and operations. Further, we have no coverage for gradual, long-term pollution events.

Formation

We were incorporated in the State of Delaware on May 11, 2016.

Employees

As of June 30, 2017, we have eight full-time employees, of which four were executive officers. None of our employees are represented by a union. Management considers our relations with employees to be very good.

Facilities

As of June 30, 2017, our principal executive offices are located at 5005 Riverway Drive, Suite 160, Houston, Texas 77056, where we lease approximately 1,500 square feet of office space.

Website Access

Our website is www.energyhunter.energy. Upon completion of this offering, you may access the documents we file with the Commission at our website free of charge as soon as reasonably practicable after they are electronically filed with, or furnished to, the Commission. Information contained on our website is not a part of this Offering Circular and the inclusion of our website address in this Offering Circular is an inactive textual reference only.

MANAGEMENT

The following table sets forth the names, ages and titles of our directors and executive officers.

Gary C. Evans, Chairman of the Board and Chief Executive Officer. Mr. Evans previously led Magnum Hunter Resources Corporation, a public energy company specializing in unconventional resource plays predominately in the Appalachian Basin, for seven years, from 2009 to May 2016. Mr. Evans was also founder and CEO of Eureka Hunter Holdings, LLC, a mid-stream gas gathering company transporting and managing up to 1 Bcf of daily natural gas volumes from production in West Virginia and Ohio on approximately 200 miles of newly constructed pipeline during the similar seven-year period. Additionally, Mr. Evans previously founded and served as the Chairman and Chief Executive Officer of Magnum Hunter Resources Inc. (MHRI), a NYSE listed company, for 20 years before MHRI was acquired by Cimarex Energy for approximately $2.2 billion in June 2005. Later that year, Mr. Evans formed Wind Hunter Energy, LLC, a renewable energy company which was subsequently acquired in December 2006 by GreenHunter Energy, Inc., an emerging water resource company focusing on oil field water management and clean water technologies active in the Marcellus and Utica resource plays in Appalachia. As founder, Mr. Evans served as Chairman and Chief Executive Officer of GreenHunter Energy, Inc. from December 2006 until May 2016. Its assets were sold to a private equity fund. Mr. Evans serves as an Individual Trustee of TEL Offshore Trust, a publicly listed oil and gas trust, and is a Director of Novavax Inc., a NASDAQ listed clinical-stage vaccine biotechnology company, where he previously served as Chairman, CEO and Lead Director. Mr. Evans was recognized by Ernst & Young as the Southwest Area 2004 Entrepreneur of the Year for the Energy Sector and was subsequently inducted into the World Hall of Fame for Ernst & Young Entrepreneurs. Mr. Evans was also recognized as the Energy Industry Leader of the year in 2013 and chosen by Finance Monthly in 2013 as one of the most respected CEOs. Mr. Evans was chosen as the Best CEO in the “Large Company” category by Texas Top Producers in 2013. He additionally won the Deal Maker of the Year Award in 2013 by Finance Monthly. Mr. Evans serves on the board of the Maguire Energy Institute at Southern Methodist University and speaks regularly at energy industry conferences around the world and on national television networks on the current affairs of the oil and gas industry.

Joe L. McClaugherty, Lead Independent Director. Mr. McClaugherty previously served as a director of Magnum Hunter Resources Corporation from 2006 through 2016 where he served as Lead Director during the last three years of his tenure. Mr. McClaugherty is a senior partner of McClaugherty & Silver, P.C., a full service firm engaged in the practice of civil law, located in Santa Fe, New Mexico. He has practiced law for 40 years and has had a Martindale-Hubbell rating of AV Preeminent for over 20 years and is a Fellow of the International Academy of Trial Lawyers. Prior to founding McClaugherty & Silver, P.C. in 1992, he was the Managing Partner of the Santa Fe office of Kemp, Smith, Duncan & Hammond, and, earlier, of Rodey, Dickason, Sloan, Akin & Robb. Mr. McClaugherty has served on numerous boards of both international and domestic companies. He received a BBA with Honors from the University of Texas in 1973 and a JD with Honors from the University of Texas School of Law in 1976. He is admitted to the Bars of the State of New Mexico, Texas and Colorado, as well as the Federal Bars of the Districts of New Mexico and Colorado, the Tenth Circuit Court of Appeals and the United States Supreme Court. The Company believes that it will benefit from Mr. McClaugherty’s business and law degrees from the University of Texas at Austin, his approximately 40 years of legal experience in a broad-based civil practice and his extensive business experience on boards of both international and domestic companies.

Victor G. Carrillo, Director. Mr. Carrillo is currently Chief Executive Officer of Zion Oil & Gas Inc., a position he has held since June 2015. Prior to being appointed Chief Executive Officer, Mr. Carrillo served as that company’s President and Chief Operating Officer from October 2011. From January through October 2011, Mr. Carrillo served

as Executive Vice President. Since 2010, he has also been a director of Zion Oil & Gas. Mr. Carrillo previously served as a director of Magnum Hunter Resources Corporation from January 2011 to March 2016. Mr. Carrillo currently serves on the Board of Directors for the Texas-Israel Chamber of Commerce and the Maguire Energy Institute at Southern Methodist University. Mr. Carrillo is a petroleum geologist, geophysicist, and attorney. He has also served as Councilman for the City of Abilene, Texas and County Judge for Taylor County, Texas. From February 2003 to January 2011, Mr. Carrillo served as a commissioner of the Railroad Commission of Texas, where he held the position of chairman of the three-member statewide elected board from 2009-2010. Mr. Carrillo holds a law degree from the University of Houston Law Center, a Master of Science degree in geology from Baylor University, and a Bachelor of Science degree in geology from Hardin-Simmons University. Mr. Carrillo also received an honorary doctorate degree from Hardin-Simmons University in May 2006. The Company believes that Mr. Carrillo’s background in petroleum geology and geophysics along with his legal, policy and regulatory experience as Chairman of the Railroad Commission of Texas provides us with a valuable combination of extensive experience as well as important insight into the interplay between law, policy, regulation, and petroleum science.

Rajiv I. Modi, Ph.D, Director. Dr. Modi is Managing Director of Cadila Pharmaceuticals, Ltd. (“Cadila”), a company organized in India, since 1995. Dr. Modi was elected to the Company’s board based upon his relationship with the Company’s second largest stockholder. As of July 31, 2017, Satellite Overseas (Holdings) Limited, a subsidiary of Cadila, holds approximately 35% of the Company’s outstanding Common Stock. Dr. Modi serves as a member of the boards of other Cadila group companies. Dr. Modi is also on the board of directors of Novavax, Inc., a NASDAQ listed clinical-stage vaccine biotechnology company. Dr. Modi received a bachelor’s degree of technology in chemical engineering from the Indian Institute of Technology, a master’s degree in biological engineering from University College, London, and a Ph.D. in biological science from the University of Michigan. The Company believes that Dr. Modi is well-suited to serve on our board of directors due to Dr. Modi’s extensive leadership experience.

H.C. “Kip” Ferguson III, Executive Vice President, Exploration / Development. Mr. Ferguson brings more than 28 years of exploration, development and operational experience in many of the major oil and gas basins within the U.S. Mr. Ferguson uses his broad oil and gas experience to assess opportunities within our core Eagle Ford and Permian focus. Mr. Ferguson has a proven management track record of successful grassroots development and execution within unconventional plays. Mr. Ferguson most recently served as Executive Vice President of Exploration for MHRC from 2009 to July 2016, where he managed the Eagle Ford Shale division and was in charge of the exploration and development of its Eagle Ford Shale properties. This led to the successful divestment of those properties for $401 million. Prior to that, Mr. Ferguson was President and Director of Sharon Resources, Inc. and Sharon Energy Ltd., which was acquired by MHRC in 2009 as its entry point into the Eagle Ford Shale play. Mr. Ferguson has a Bachelor’s of Science in Geology, with a minor in Petroleum Engineering, from the University of Texas. Additionally, Mr. Ferguson has co-authored and written case studies, papers and articles for SPE International magazine, Unconventional Resources Technology Conference, and E&P magazine regarding successful uses of different unconventional technologies. The Company believes Mr. Ferguson’s extensive experience in the Eagle Ford Shale, as well as other major U.S. basins, will be an important asset as it embarks on its drilling program and identification of future acquisitions.

Brian Burgher, Senior Vice President, Land. Mr. Burgher has more than 30 years of experience in the oil and gas industry. He was previously SVP of Land for MHRC from 2009 to 2015, where he served as land manager for its Eagle Ford assets, which were assembled, developed and sold under his oversight. Across his time at MHRC, Mr. Burgher personally oversaw the acquisition, due diligence and subsequent divesture of over $1.0 billion of leases and wells. The Company believes Mr. Burgher’s intimate knowledge of all facets of field operations and management will be well-suited to growing the Company’s acreage position.

Deirdre M. Sanborn, Interim Chief Financial Officer, Vice President of Finance and Business Development. Ms. Sanborn is a corporate finance executive with 25 years of experience in lending, corporate finance, capital markets and investment banking, with a particular focus on the upstream and midstream sectors within the energy industry. From 1992 to 1997, Ms. Sanborn was a credit analyst in the capital markets group at Citicorp North America. From 1997 to 2009, Ms. Sanborn served as the director of corporate lending and senior relationship manager at Fortis Bank. From 2009 to 2014, Ms. Sanborn served as an executive director of investment banking and senior relationship manager at UBS Investment Bank, where she focused on the firm’s energy lending portfolio. From

2014 to 2017, she was founder and owner of Deirdre Sanborn & Associates, a strategic consulting firm focused on business coaching and financial management support. Ms. Sanborn is a registered financial advisor with the American Securities Administration Association and has a B.A in Economics from the College of the Holy Cross.

Jason Wilson, Manager, Geology. Mr. Wilson has more than 20 years of experience in geology and operations across all of our target areas. From 2009 to 2013 he was a member of the MHRC Eagle Ford operations team that successfully executed the grassroots development of the Gonzales/Lavaca county acreage in South Texas that was eventually sold for $401 million. After leaving MHRC, Mr. Wilson worked for one year as a senior geologist for New Standard Energy. Following his post at New Standard Energy until joining the Company, Mr. Wilson worked as an independent consultant for EnCap Investments, L.P. Mr. Wilson also worked previously in similar capacities for Anadarko Petroleum and Sharon Resources. Mr. Wilson has a Bachelor’s of Science and a Master’s of Science degree in Geology from Texas A&M University.

Brada Wilson, Controller and Corporate Secretary. Ms. Wilson presently serves as our Controller and Corporate Secretary. Prior to joining our company, Ms. Wilson worked for MHRC for five years. Ms. Wilson also served as Controller for CWF Energy, Inc. in Dallas and Henry Energy Corporation, a public company based in Arlington, Texas. Ms. Wilson holds a Master of Professional Accounting degree from the University of Texas at Arlington and a Bachelor of Science degree from Texas Tech University. Ms. Wilson brings over 20 years of experience in all phases of oil and gas accounting.

Roger D. Burks, Financial Consulting Advisor. Mr. Burks is Executive Managing Director/CEO of WG Consulting, a full-service oil and gas consulting firm headquartered in Houston, Texas focused on the energy industry, which he co-founded in January 2012. Pursuant to an agreement between WG Consulting and us, Mr. Burks served as our Interim Chief Financial Officer from November 1, 2016 through June 6, 2017. From June 2008 until January 2012, Mr. Burks was CEO of SVG Advisors, a consulting firm focused on the energy industry. From December 2006 until April 2008, Mr. Burks served as Executive Vice President and Chief Financial and Administrative Officer of Superior Offshore International, Inc., at that time, a leading provider of subsea construction and commercial diving services to the crude oil and natural gas exploration and production and gathering and transmission industries on the outer continental shelf of the Gulf of Mexico. Mr. Burks was a co-founder of Sirius Solutions, LLP, a financial consulting services firm, where he served as Managing Partner from August 2002 until June 2006. From January 1982 until August 2002, Mr. Burks worked at Deloitte & Touche, LLP, where he served as Partner-in-Charge of the firm’s Gulf Coast Energy Practice. During his time with Sirius Solutions and Deloitte & Touche, Mr. Burks worked with numerous energy companies. Mr. Burks is a Certified Public Accountant and a National Association of Corporate Director – Board Leadership Fellow. Mr. Burks has a Bachelor of Science in Accounting from Northeast Missouri State University. Mr. Burks brings more than 35 years of experience in accounting, finance, mergers and acquisitions, risk management, Sarbanes-Oxley compliance and financial reporting to the Company.

Involvement in Certain Legal Proceedings

In March 2016, during Mr. Evans’ tenure as interim CEO of GreenHunter Resources, Inc. that company and certain of its subsidiaries (namely, GreenHunter Water, LLC; Hunter Disposal, LLC; Ritchie Hunter Water Disposal, LLC; Hunter Hauling, LLC; White Top Oilfield Construction, LLC; Blackwater Services, LLC; Virco Realty, LLC; Little Muskingum Drilling, LLC; Blue Water Energy Solutions, LLC; GreenHunter Wheeling Barge, LLC; GreenHunter Environmental Solutions, LLC; and MAG Tank Hunter, LLC) filed for bankruptcy protection under Chapter 11 of the Bankruptcy Code. Similar to Magnum Hunter Resources Corporation discussed immediately below, GreenHunter Resources, Inc. sought protection in large part because of the cyclical downturn in the commodity prices of both oil and natural gas. GreenHunter Resources, Inc.’s assets were subsequently sold to a private equity group, which allowed predominately all secured indebtedness to be fully repaid.

In December 2015, during Mr. Evans’ tenure as CEO of Magnum Hunter Resources Corporation, that company filed for bankruptcy protection under Chapter 11 of the Bankruptcy Code in Delaware (In re Magnum Hunter Resources Corporation, et al., included the following debtors in addition to Magnum Hunter Resources Corporation, each of which was a directly or indirectly owned subsidiary of Magnum Hunter Resources Corporation: Alpha Hunter Drilling, LLC; Bakken Hunter Canada, Inc.; Bakken Hunter, LLC; Energy Hunter Securities, Inc.; Hunter Aviation, LLC; Hunter Real Estate, LLC; Magnum Hunter Marketing, LLC; Magnum Hunter Production, Inc.; Magnum Hunter Resources GP, LLC; Magnum Hunter Resources, LP; Magnum Hunter Services, LLC; NGAS Gathering, LLC; NGAS Hunter, LLC; PRC Williston LLC; Shale Hunter, LLC; Triad Holdings, LLC; Triad Hunter, LLC; Viking International Resources Co., Inc.; and Williston Hunter ND, LLC). This filing was due in large part to the

precipitous commodity cycle downturn which saw the price of natural gas and crude oil reach lows not seen for over a decade. Magnum Hunter Resources Corporation subsequently emerged from bankruptcy with no indebtedness in May 2016 under Mr. Evans’ leadership. At the time of the bankruptcy filing, Mr. Carrillo was a Director and Mr. McClaugherty was Lead Director of Magnum Hunter Resources Corporation. In addition, at the time of the bankruptcy filing, Mr. Ferguson and Ms. Wilson were employees of Magnum Hunter Resources Corporation.

On April 24, 2008, shortly after Mr. Burks resigned as Executive Vice President and Chief Financial and Administrative Officer of Superior Offshore International, Inc., Superior Offshore filed a voluntary petition under Chapter 11 of the Bankruptcy Code. On January 28, 2009, the United States Bankruptcy Court for the Southern District of Texas confirmed a liquidation plan for the company.

Other than disclosed above, during the past ten years, none of our officers, directors, promoters or control persons have been involved in any legal proceedings as described in Item 401(f) of Regulation S-K.

Committees of the Board of Directors

Upon the conclusion of this offering, we intend to organize an audit committee, nominating and corporate governance committee, and compensation committee of our board of directors, and may have such other committees as the board of directors shall determine from time to time. We anticipate that each of the standing committees of the board of directors will have the composition and responsibilities described below.

Audit Committee

We will establish an audit committee prior to the completion of this offering. A minimum of two individuals will serve as the members of our audit committee. As required by the rules of the Commission and listing standards of the NASDAQ, where we have applied to have our Common Stock listed, the audit committee will consist solely of independent directors within one year of the listing date. Commission rules also require that a public company disclose whether or not its audit committee has an “audit committee financial expert” as a member. Commission rules also require that a public company disclose whether or not its audit committee has an “audit committee financial expert” as a member. An “audit committee financial expert” is defined as a person who, based on his or her experience, possesses the attributes outlined in such rules. Our board of directors has determined that Dr. Modi satisfies the definition of “audit committee financial expert” and we anticipate that he will be a member of the audit committee.

The audit committee will oversee, review, act on and report on various auditing and accounting matters to our board of directors, including: the selection of our independent registered public accounting firm, the scope of our annual audits, fees to be paid to the independent registered public accounting firm, the performance of our independent registered public accounting firm and our accounting practices. In addition, the audit committee will oversee our compliance programs relating to legal and regulatory requirements. We have adopted an audit committee charter defining the committee’s primary duties in a manner consistent with the rules of the Commission and the NASDAQ.

Compensation Committee

We will establish a compensation committee prior to the completion of this offering. A minimum of three individuals will serve as members of our compensation committee. Our compensation committee will review and recommend policies relating to compensation and benefits of our directors and employees and will be responsible for approving the compensation of our Chief Executive Officer and other executive officers. We have adopted a compensation committee charter defining the committee’s primary duties in a manner consistent with the rules of the Commission and NASDAQ.

Nominating and Corporate Governance

We will establish a nominating and corporate governance committee prior to the completion of this offering. A minimum of three individuals will serve as members of our nominating and corporate governance committee. Our nominating and corporate governance committee will select or recommend that the board of directors select candidates for election to our board of directors, develop and recommend to the board of directors corporate governance guidelines that will be applicable to us and oversee board of director and management evaluations. We have adopted a nominating and corporate governance committee charter defining the committee’s primary duties in a manner consistent with the rules of the Commission and NASDAQ.

Code of Business Conduct and Ethics

Prior to the completion of this offering, our board of directors will adopt a code of business conduct and ethics applicable to our employees, directors and officers, in accordance with applicable U.S. federal securities laws and the corporate governance rules of the NASDAQ. Any waiver of this code may be made only by our board of directors and will be promptly disclosed as required by applicable U.S. federal securities laws and the corporate governance rules of the NASDAQ.

Our board of directors has undertaken a review of the independence of each director. Based on information provided by each director concerning his or her background, employment and affiliations, our board of directors has determined that each of Mr. McClaugherty, Mr. Carrillo and Dr. Modi does not have a material relationship with us that could compromise his or her ability to exercise dependent judgment in carrying out his or her responsibilities and that each of these directors is “independent” as that term is defined under the listing standards of NASDAQ.

Lead Independent Director

If at any time after the completion of this offering, the offices of Chairman of the Board and Chief Executive Officer are held by the same person, we intend that the independent members of the board of directors will elect on an annual basis with a majority vote an independent director to serve in a lead capacity (the “Lead Independent Director”). The Lead Independent Director will coordinate the activities of the other independent directors and perform such other duties and responsibilities as the board of directors may determine. We have adopted a Lead Independent Director Charter defining the Lead Independent Director’s primary duties in a manner consistent with the rules of the Commission and NASDAQ.

In July 2017, Mr. McClaugherty was elected by a unanimous vote of the board of directors to serve as Lead Independent Director.

Corporate Governance Guidelines

Prior to the completion of this offering, our board of directors will adopt corporate governance guidelines in accordance with the corporate governance rules of the NASDAQ.

EXECUTIVE COMPENSATION

Named Executive Officers

We are an emerging growth company for purposes of the Commission’s executive compensation disclosure rules. In accordance with such rules, we are required to provide a Summary Compensation Table and an Outstanding Equity Awards at Fiscal Year End Table, as well as limited narrative disclosures regarding executive compensation for our last completed fiscal year. Further, our reporting obligations extend only to our “named executive officers,” who are those individuals serving as our principal executive officer and our two other most highly compensated executive officers who were serving as executive officers at the end of the last completed fiscal year. We began operations on May 11, 2016, therefore, we do not have prior fiscal year data.

Narrative Disclosures

Employment, Severance or Change in Control Agreements

Other than with Mr. Evans and Mr. Burks, we currently do not maintain any employment, severance or change in control agreements with our named executive officers. In addition, our named executive officers are not entitled to any payments or other benefits in connection with a termination of employment or a change in control.

Gary C. Evans

On July 11, 2017, the Company and Gary C. Evans entered into an employment agreement, effective retroactively to January 1, 2017. The employment agreement with Mr. Evans provides that Mr. Evans will serve as the Company’s Chief Executive Officer and Chairman of the Board. The agreement has an initial term of three years, and continues thereafter on a year to year basis. Mr. Evans’s base salary is $360,000 per annum, and he is eligible to participate in the Company’s bonus plans on the same terms that generally apply to the Company’s executive officers. Mr. Evans is also eligible for an additional bonus as determined by the Company’s Compensation Committee. Further, subject to the sole discretion of the Company’s Compensation Committee, Mr. Evans will be eligible to participate in the Company’s 2016 Omnibus Incentive Plan. The agreement also includes, among other things, non-competition and non-solicitations covenants by Mr. Evans that in the event of termination of employment he will not hire or solicit any employees of the Company or compete with the Company for a period of two years following cessation of employment. If Mr. Evans is terminated without cause or if Mr. Evans terminates his employment for good reason, he is entitled to a lump sum payment equal to 12 months of his then effective salary, and, subject to certain conditions, reimbursement for a portion of the monthly cost of the COBRA coverage premiums for the 12-month period following Mr. Evans’ termination. Each party is required to give 30 days’ notice of termination of employment.

Roger D. Burks

Effective November 1, 2016, the Company and WG Consulting, LLC (“WG Consulting”), of which Mr. Burks is the Executive Managing Director/CEO, entered into that certain engagement letter (the “Burks Engagement Letter”), pursuant to which the Company formalized Mr. Burks’ services as Interim Chief Financial Officer of the Company until June 6, 2017. Pursuant to the Burks Engagement Letter, Mr. Burks oversaw all of the Company’s accounting and related matters as a reporting company. WG Consulting was compensated for Mr. Burks’ services at a rate of $300 per hour. The Company and WG Consulting have also entered into a separate agreement pursuant to which Mr. Burks will continue serving the Company as a Financial Consulting Advisor and WG Consulting will provide certain consulting and outsourced accounting services to the Company. See “Certain Relationships and Related Party Transactions—WG Consulting Engagement Letter.”

Retirement Benefits

We have not maintained, and do not currently intend to maintain, a defined benefit pension plan or nonqualified deferred compensation plan.

Compensation of Named Executive Officers

The following table contains compensation data for our named executive officers for the fiscal year ending December 31, 2016 and for the current fiscal year.

Compensation of Directors

Our board of directors was initially formed in July 2016 and expanded in October 2016. No obligations with respect to cash compensation for non-employee directors have been accrued or paid for any periods prior to such formation date, in 2016, or to date in 2017. Each of the non-employee directors was granted 2,500 restricted stock units in 2017 pursuant to our 2016 Omnibus Incentive Plan. This equates to an award of $   , which assumes awards of shares of Common Stock at $    per share, which is the midpoint of the price range set forth on the cover page of this Offering Circular.

Going forward, our board of directors believes that attracting and retaining qualified non-employee directors will be critical to the future value growth and governance of our company. Our board of directors also believes that a significant portion of the total compensation package for our non-employee directors should be equity-based to align the interest of these directors with our stockholders.

Directors who are also our employees will not receive any additional compensation for their service on our board of directors.

We expect that each director will be reimbursed for (i) travel and miscellaneous expenses to attend meetings and activities of our board of directors or its committees; (ii) travel and miscellaneous expenses related to such director’s participation in general education and orientation programs for directors; and (iii) travel and miscellaneous expenses for each director’s spouse who accompanies a director to attend meetings and activities of our board of directors or any of our committees.

2016 Omnibus Incentive Plan

2016 Omnibus Incentive Plan

Our board of directors adopted our 2016 Omnibus Incentive Plan on November 16, 2016, which our stockholders approved on November 30, 2016. Unless otherwise amended or terminated by our board of directors, the 2016 Omnibus Incentive Plan shall have a ten-year term.