S-1 1 d431087ds1.htm S-1 S-1
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As filed with the Securities and Exchange Commission on September 19, 2018

Registration No. 333-                

 

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

 

FORM S-1

REGISTRATION STATEMENT

UNDER

THE SECURITIES ACT OF 1933

 

 

Riley Exploration—Permian, LLC

to be converted as described herein into a corporation named

Riley Exploration Permian, Inc.

(Exact name of registrant as specified in its charter)

 

 

 

Delaware   1311   81-3910441

(State or other jurisdiction of

incorporation or organization)

 

(Primary Standard Industrial

Classification Code Number)

 

(IRS Employer

Identification No.)

29 E. Reno Avenue, Suite 500

Oklahoma City, Oklahoma 73104

(405) 415-8699

(Address, including zip code, and telephone number, including area code, of registrant’s principal executive offices)

 

 

Jeffrey M. Gutman

Chief Financial Officer

29 E. Reno Avenue, Suite 500

Oklahoma City, Oklahoma 73104

(405) 415-8677

(Name, address, including zip code, and telephone number, including area code, of agent for service)

 

 

Copies to:

 

Beth A. di Santo

di Santo Law PLLC

205 Hudson Street, 7th Floor

New York, New York 10013

(212) 766-2466

 

Joe Dannenmaier

Amy Curtis

Thompson & Knight LLP

1722 Routh Street, Suite 1500

Dallas, Texas 75201

(214) 969-1393

 

Thomas S. Levato

Goodwin Procter LLP

The New York Times Building

620 Eighth Avenue

New York, New York 10018

(212) 813-8800

 

 

Approximate date of commencement of proposed sale to the public: As soon as practicable after the effective date of this registration statement.

If any of the securities being registered on this Form are to be offered on a delayed or continuous basis pursuant to Rule 415 under the Securities Act of 1933, or the Securities Act, check the following box:  ☐

If this Form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, please check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.  ☐

If this Form is a post-effective amendment filed pursuant to Rule 462(c) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.  ☐

If this Form is a post-effective amendment filed pursuant to Rule 462(d) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.  ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company or an emerging growth company in Rule 12b-2 of the Exchange Act.

 

Large accelerated filer      Accelerated filer  
Non-accelerated filer   ☒  (Do not check if a smaller reporting company)    Smaller reporting company  
     Emerging growth company  

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 7(a)(2)(B) of the Securities Act.  ☐

 

 

CALCULATION OF REGISTRATION FEE

 

 

Title of Each Class of

Securities to be Registered

  

Proposed

Maximum

Aggregate

Offering Price (1)(2)

 

Amount of

Registration Fee

Common stock, par value $0.01 per share

   $115,000,000   $14,317.50

 

 

(1)

Includes shares issuable upon exercise of the underwriters’ option to purchase additional shares of common stock.

(2)

Estimated solely for the purpose of calculating the registration fee pursuant to Rule 457(o) under the Securities Act of 1933, as amended.

 

 

The registrant hereby amends this registration statement on such date or dates as may be necessary to delay its effective date until the registrant shall file a further amendment which specifically states that this registration statement shall thereafter become effective in accordance with Section 8(a) of the Securities Act of 1933, as amended, or until this registration statement shall become effective on such date as the Securities and Exchange Commission, acting pursuant to said Section 8(a), may determine.

 

 

 


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EXPLANATORY NOTE

Riley Exploration-Permian, LLC, the registrant whose name appears on the cover of this registration statement, is a Delaware limited liability company. Prior to the effectiveness of this registration statement, Riley Exploration-Permian, LLC will be converted into a Delaware corporation pursuant to a statutory conversion and be renamed Riley Exploration Permian, Inc. As a result of the statutory conversion, which we refer to as the “Corporate Conversion,” the members of Riley Exploration-Permian, LLC will become holders of shares of common stock of Riley Exploration Permian, Inc. In the Corporate Conversion, all of the outstanding common units and Series A Preferred Units of Riley Exploration-Permian, LLC will be converted into shares of common stock of Riley Exploration Permian, Inc. Except as disclosed in the prospectus, the consolidated financial statements and selected historical consolidated financial data and other financial information included in this registration statement are those of Riley Exploration-Permian, LLC and its subsidiaries and do not give effect to the Corporate Conversion. Shares of common stock of Riley Exploration Permian, Inc. are being offered by the prospectus.


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The information in this prospectus is not complete and may be changed. We may not sell these securities until the registration statement filed with the Securities and Exchange Commission is effective. This prospectus is not an offer to sell these securities and it is not soliciting an offer to buy these securities in any state or jurisdiction where the offer or sale is not permitted.

 

SUBJECT TO COMPLETION, DATED SEPTEMBER 19, 2018

PROSPECTUS

             Shares

 

 

LOGO

Riley Exploration Permian, Inc.

Common Stock

 

 

This is the initial public offering of the common stock of Riley Exploration Permian, Inc., a Delaware corporation. We are offering                shares of our common stock.

Prior to this offering, there has been no public market for our common stock. We anticipate that the initial public offering price will be between $                and $                per share. We have been cleared to apply to list our common stock on the NYSE American LLC under the symbol “REPX.”

We are an “emerging growth company” as the term is used in the Jumpstart Our Business Startups Act of 2012, or the JOBS Act, and as such, we have elected to take advantage of certain reduced public company reporting requirements for this prospectus and future filings. See “Risk Factors” and “Prospectus Summary— Emerging Growth Company Status.”

 

 

Investing in our common stock involves risks. Please see “Risk Factors” beginning on page 22.

 

     Per Share      Total  

Price to the public

   $                    $                

Underwriting discounts and commissions (1)

   $        $    

Proceeds to us (before expenses)

   $        $    

 

(1)

We refer you to “Underwriting (Conflicts of Interest)” beginning on page 166 of this prospectus for additional information regarding underwriting compensation.

To the extent that the underwriters sell more than                 shares of our common stock, the underwriters have the option to purchase up to an additional                 shares from us at the public offering price less the underwriting discount and commissions.

Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of these securities or determined if this prospectus is truthful or complete. Any representation to the contrary is a criminal offense.

The underwriters expect to deliver the shares on or about                , 2018.

 

 

Joint Book-Running Managers

 

SunTrust Robinson Humphrey    Seaport Global Securities

The date of this prospectus is                 , 2018.


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LOGO

Acreage Map

 

 

 

LOGO


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TABLE OF CONTENTS

 

PROSPECTUS SUMMARY

     1  

RISK FACTORS

     22  

CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

     58  

USE OF PROCEEDS

     60  

DIVIDEND POLICY

     62  

CORPORATE CONVERSION

     62  

CAPITALIZATION

     63  

DILUTION

     65  

SELECTED HISTORICAL FINANCIAL DATA

     67  

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

     69  

BUSINESS

     95  

PRO FORMA CONDENSED FINANCIAL DATA

     123  

MANAGEMENT

     136  

EXECUTIVE COMPENSATION

     141  

SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

     149  

CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

     152  

DESCRIPTION OF CAPITAL STOCK

     155  

SHARES ELIGIBLE FOR FUTURE SALE

     159  

MATERIAL U.S. FEDERAL INCOME TAX CONSIDERATIONS FOR NON-U.S. HOLDERS

     162  

UNDERWRITING (CONFLICTS OF INTEREST)

     166  

LEGAL MATTERS

     172  

EXPERTS

     172  

WHERE YOU CAN FIND MORE INFORMATION

     173  

INDEX TO FINANCIAL STATEMENTS

     F-1  

APPENDIX A—GLOSSARY OF OIL AND GAS TERMS

     A-1  

 

 

You should rely only on the information contained in this prospectus and any free writing prospectus prepared by us or on behalf of us or to the information to which we have referred you. Neither we nor the underwriters have authorized anyone to provide you with information different from that contained in this prospectus and any free writing prospectus. We take no responsibility for, and can provide no assurance as to the reliability of, any other information that others may give you. We and the underwriters are offering to sell shares of common stock and seeking offers to buy shares of common stock only in jurisdictions where offers and sales are permitted. The information in this prospectus is accurate only as of the date of this prospectus, regardless of the time of delivery of this prospectus or any sale of the common stock. Our business, financial condition, results of operations and prospects may have changed since that date.

This prospectus contains forward-looking statements that are subject to a number of risks and uncertainties, many of which are beyond our control. Please see “Risk Factors” and “Cautionary Note Regarding Forward-Looking Statements.”

Through and including                 , 2018 (the 25th day after the date of this prospectus), all dealers effecting transactions in our common stock, whether or not participating in this offering, may be required to deliver a prospectus. This requirement is in addition to the dealers’ obligation to deliver a prospectus when acting as an underwriter and with respect to an unsold allotment or subscription.

 

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Commonly Used Defined Terms

As used in this prospectus, unless the context indicates or otherwise requires, the terms listed below have the following meanings:

“Bluescape” refers to Bluescape Riley Exploration Acquisition, LLC, a holder of our common units and Series A Preferred Units and, if the context requires, together with Bluescape Riley Exploration Holdings, LLC, as a holder of our Series A Preferred Units.

“Boomer” refers to Boomer Petroleum, LLC.

“Champions Assets” refers to our oil and natural gas properties and related assets, which is located on large, contiguous blocks in Yoakum County, Texas, between the Wasson and Brahaney Fields.

“Contributors” refers, collectively, to REG, Boomer, Bluescape and DR/CM Group.

“Corporate Conversion” refers to the conversion of Riley Exploration-Permian, LLC from a Delaware limited liability company into Riley Exploration Permian, Inc., a Delaware corporation, immediately prior to the completion of the offering contemplated by this prospectus. See “Corporate Conversion.”

“DR/CM Group” or “DR/CM” refers, collectively, to each of the Stephen H. Dernick Trust, the David D. Dernick Trust, Dennis W. Bartoskewitz, Alan C. Buckner, the Robert Gary Dernick Trust, and Christopher M. Bearrow and/or their successors and assigns.

“Existing Owners” refers, collectively, to REG, Yorktown, Bluescape, Boomer, and the DR/CM Group, as the holders of our common units, and to Yorktown, Bluescape and Boomer, as the holders of our Series A Preferred Units, in each case issued and outstanding prior to the effectiveness of the Corporate Conversion.

“New Mexico Assets” refers to the oil and gas assets that we acquired from Rockcliff New Mexico Operating, LLC that are located in Chaves, Lea, and Roosevelt Counties, New Mexico consisting of 43,699 net mineral acres, one producing well, a salt water disposal well, and associated gathering lines.

“REG” refers to Riley Exploration Group, Inc.

“Riley Permian,” “the Company,” “we,” “our,” “us” or like terms refer to Riley Exploration-Permian, LLC and its subsidiary before the completion of our Corporate Conversion as described in “Corporate Conversion,” and to Riley Exploration Permian, Inc. and its subsidiary following the completion of our Corporate Conversion.

“Sponsors” refers, collectively, to Yorktown, Boomer and Bluescape.

“Yorktown” refers to certain investment funds managed by Yorktown Partners LLC.

“Yorktown Partners” refers to Yorktown Partners LLC, the investment manager of the Yorktown Partners group of funds.

This prospectus includes certain terms commonly used in the oil and natural gas industry, which are defined elsewhere in this prospectus in “Appendix A—Glossary of Oil and Gas Terms.”

 

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BASIS OF PRESENTATION OF FINANCIAL AND OPERATING DATA

The historical financial information presented in this prospectus is that of Riley Exploration-Permian, LLC (referred to as “we,” “us,” the “Company” or “Riley Permian”). We were initially formed as a wholly-owned subsidiary of Riley Exploration Group, Inc. (referred to as REG) in June 2016. On January 17, 2017, REG contributed its working interest in oil and natural gas properties and related assets in Yoakum County, Texas (referred to as the Champions Assets) to us, including working interests in the Champions Assets that REG had acquired from other parties on December 31, 2015, in exchange for our common units. On that date, Boomer Petroleum, LLC (referred to as Boomer) also contributed its working interest in oil and natural gas properties and related assets in the Champions Assets to us in exchange for our common units. On March 6, 2017, Bluescape and DR/CM contributed their respective working interests in oil and natural gas properties and related assets of the Champions Assets in exchange for our common units, respectively.

The contribution received from REG was considered a transfer of a business between entities under common control and accordingly, the Company has recorded the contributed business at historical cost and for the periods prior to January 17, 2017, the financial statements have been prepared on a “carve out” basis from REG’s accounts and reflect the historical accounts directly attributable to the Champions Assets owned by REG together with allocations of costs and expenses. The contributions from Boomer, Bluescape and DR/CM were accounted for as business combinations in accordance with ASC 805—Business Combinations and recorded at fair value. The Company’s financial statements reflect the operating results of the assets contributed by Boomer, Bluescape and DR/CM for the periods following the respective contributions. The earnings per common unit reflect the common units received by REG for all periods and the common units received by Boomer, Bluescape and DR/CM for the periods following their respective contributions. For more information, please see “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Overview.”

Unless another date is specified or the context otherwise requires, all acreage, reserve and operational data, well count, hedging and drilling location data is presented in this prospectus as of September 30, 2017. Unless otherwise noted, references to production volumes refer to sales volumes. Certain amounts and percentages included in this prospectus have been rounded. Accordingly, in certain instances, the sum of the numbers in a column of a table may not exactly equal the total figure for that column.

PERMIAN BASIN

References herein to the “Permian Basin” or the “Central Basin Platform” or the “Northwest Shelf” or the “San Andres Formation” refer to those areas defined by the Railroad Commission of Texas, or the TRRC. The TRRC defines the (i) Permian Basin as an oil-and-gas producing area located in West Texas and the adjoining area of southeastern New Mexico covering an area approximately 250 miles wide and 300 miles long, and encompasses several sub-basins, including the Delaware Basin, Midland Basin, Central Basin Platform and Northwest Shelf; (ii) Central Basin Platform as a sub-basin of the Permian Basin; (iii) Northwest Shelf as a sub-basin of the Permian Basin; and (iv) San Andres Formation as a shelf margin deposit composed of dolomitized carbonates.

INDUSTRY AND MARKET DATA

The market data and certain other statistical information used throughout this prospectus 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.

 

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TRADEMARKS AND TRADE NAMES

We have rights to various trademarks, service marks and trade names that we use in connection with the operation of our business. This prospectus 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 prospectus is not intended to, and does not imply a relationship with, or endorsement or sponsorship by us. Solely for convenience, the trademarks, service marks and trade names referred to in this prospectus 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 rights of the applicable licensor to these trademarks, service marks and trade names.

 

 

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PROSPECTUS SUMMARY

This summary highlights information contained elsewhere in this prospectus. You should read the entire prospectus carefully, including the information under the headings “Risk Factors,” “Cautionary Note Regarding Forward-Looking Statements” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the financial statements and the related notes thereto appearing elsewhere in this prospectus. References to our estimated reserves are derived from our reserve report as of September 30, 2017 prepared by Netherland, Sewell & Associates, Inc., or NSAI, and referred to as the NSAI Report.

Overview

We are a growth-oriented, independent oil and natural gas company focused on rapidly growing our reserves, production and cash flow through the acquisition, exploration, development and production of oil, natural gas, and natural gas liquids, or NGLs, reserves in the Permian Basin. This basin, which is one of the major producing basins in the United States, is characterized by an extensive production history, a favorable operating environment, established infrastructure, long reserve life, multiple producing horizons, significant oil in place and a large number of operators. Our activities are primarily focused on the San Andres Formation, a shelf margin deposit on the Central Basin Platform and Northwest Shelf, which accounts for approximately 24% of the nearly 30 billion barrels of oil historically produced from the Permian Basin and where horizontal production has increased by more than 425% since January 2014.

We were formed with the goal of building a premier Permian Basin pure-play acquisition, exploration and development company, focusing on opportunities (i) with favorable reservoir and geological characteristics primarily for oil development, (ii) that offer large contiguous acreage positions with significant untapped potential in terms of ultimate recoverable reserves and (iii) with a high degree of operational control, which allows us to execute our development plan based on projected well performance and commodity price forecasts in order to attempt to rapidly grow our cash flow and generate significant equity returns from our capital program. We believe these characteristics enhance our horizontal production capabilities, recoveries and commercial outcomes.

Our acreage is primarily located on large, contiguous blocks in Yoakum County, Texas and Lea, Roosevelt, and Chaves Counties, New Mexico, focused on the San Andres Formation on the Northwest Shelf. Our assets offset legacy Permian Basin San Andres fields, to include the Wasson and Brahaney Fields, which have produced more than 2.1 billion barrels of oil and 108 million barrels of oil, respectively, from the San Andres Formation since development in the area began in the 1930’s and 1940’s. Based on the close proximity to these productive fields, combined with the horizontal San Andres wells we have drilled to date and the wells drilled by offset operators, we believe we have significantly delineated our acreage.

Since we commenced operations, our management and technical teams have successfully executed our development program and expanded our acreage position from 19,893 as of September 30, 2017, to approximately 65,839 net acres as of June 30, 2018. We have grown our average net production from 308 BOE/d for our fiscal year ended September 30, 2016 to an average net production of 1,384 BOE/d for our fiscal year ended September 30, 2017, representing a 349% increase year over year. Our average net production for the first nine months of fiscal 2018 was approximately 3,136 BOE/d. The annual volume increase is primarily due to the development of our properties and, to a lesser extent, contributions of the Champions Assets during the second quarter of fiscal 2017. See “—Our Corporate History” for more information relating to these contributions. As we had no additional significant contributions or acquisitions after the second quarter of fiscal 2017, our production growth after the second quarter of fiscal 2017 is primarily due to the results of our development



 

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program. Both our production and our proved reserves as of and for the year ended September 30, 2017 consist of greater than 85% oil. The following table shows our growth in net production, with period averages, since fiscal 2016.

 

LOGO



 

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Our management has also been highly focused on operating efficiency. We made a strategic decision to construct and operate water disposal and electric infrastructure within our operating project areas which, together with our other efforts at efficiency, have resulted in significantly lower lease operating expenses, or LOEs. The following table shows our historic LOE per unit of oil-equivalent production which has declined from an average of $24.74 per BOE for our year ended September 30, 2016 to $9.50 per BOE for the first nine months of fiscal 2018, representing a decline of approximately 62%.

 

LOGO

We maintain operational control on approximately 66% of our net undeveloped acreage position which enables the horizontal drilling of long laterals, resulting in significant drilling efficiencies through strong operational and cost controls that we believe improve our returns on capital employed and enhance the economic development of our acreage position. We believe the ability to drill long-lateral wells improves our returns by (i) increasing our estimated ultimate recoveries, or EUR, per well, (ii) allowing us to contact more reservoir rock with fewer wellbores thereby reducing drilling and completion costs on a per unit basis and (iii) allowing us to hold more acreage per well drilled. Additionally, the contiguous nature of our acreage provides economies of scale by allowing us to better leverage our existing infrastructure. For the first nine months of fiscal 2018, our average net daily production was 3,136 BOE/d, of which approximately 94% was oil, 2% was natural gas and 4% was NGLs. The following table provides summary information regarding our proved, probable and possible reserves as of September 30, 2017, based on the NSAI Report.

 

Reserve Type

   Oil
(MBbls) (1)
     Natural Gas
(MMcf) (1)
     NGL
(MBbls) (1)
     Total
(MBoe) (1)
     % Oil      % Liquids (2)      % Developed  

Proved Reserves

     12,026        4,821        1,179        14,009        86        94        51  

Probable Reserves

     11,137        4,639        1,106        13,016        86        94     

Possible Reserves

     11,149        4,691        1,118        13,049        85        94     

 

(1)

Our estimated reserves were determined using the unweighted arithmetic average of the historical first-day-of-the-month prices for the prior 12 months as of September 30, 2017 of $46.27 per Bbl for oil and NGL volumes, and $3.00 per MMBtu for natural gas, at the average Henry Hub spot price. The WTI price for oil and NGL volumes is adjusted by lease for quality, transportation fees, and market differentials. The Henry Hub spot price for gas volumes is adjusted by lease for energy content, and market differentials. For



 

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  more information on the differences between the categories of proved, probable and possible reserve, see “Business—Oil and Natural Gas Data.”
(2)

Includes both oil and NGLs.

The following table presents data on EURs and production for our gross wells drilled and completed during the fiscal years ended September 30, 2016 and 2017, respectively. For our fiscal year ended September 30, 2017 in comparison to fiscal 2016, our average oil equivalent EURs per 1,000 foot lateral length increased by 35%. Please see “Business—Drilling Results” for more detail on our wells we have drilled to date and other information on wells drilled in our acreage.

 

Year of First Production

   Drilled &
Completed
Per Year (1)
     Averaged
Completed
Lateral Length
(feet)
     Average Oil
Equivalent EUR (1)
(MBoe)
     Average Oil
Equivalent EUR
per 1,000’ (1)(2)
(MBoe)
     Average Drilling &
Completions
Costs
($ in millions)
 

2016

     21        6,044        460        76      $ 2.1  

2017

     18        5,779        597        103      $ 2.4  

 

(1)

EUR represents the sum of total gross remaining proved reserves as of September 30, 2017, based on the NSAI Report and cumulative production as of such date. EUR information is given on a per year basis only for wells drilled and completed that year as listed in the third column of the above table. EUR is shown on a combined basis for oil, natural gas and NGLs.

(2)

The average completed lateral length at such date of our 1-mile equivalent wells was 4,461 feet and the 1.5-mile equivalent wells was 6,726 feet.

Our total well count was 53 gross producing (23 net) wells as of the fiscal year ended September 30, 2017, increasing from 33 gross (13 net) wells as of the fiscal year ended September 30, 2016. As of the fiscal year ended September 30, 2017, our average working interest was 43% in the total 53 gross producing wells. Of these 53 gross producing wells, we operated 20 gross wells, in which we had an average working interest of 95%. Our strategy is to increase the number of wells we operate in our undeveloped locations, and as a result increase our average working interest over time. As of June 30, 2018, our producing well count has increased by 27 gross (17 net) wells. See “—Recent Developments” below for further information regarding the increase in our well counts.

In addition to our 53 gross producing (23 net) wells, we identified a total of approximately 97 gross (67 net) drilling locations across our acreage as of September 30, 2017 identified as proved, probable or possible reserves in the NSAI Report. See “Business—Drilling Locations” for more information. Our gross and net remaining horizontal drilling locations as of September 30, 2017 relating to our proved, probable and possible reserves are as follows:

 

Reserve Type

   Gross Horizontal Drilling
Locations
     % by Reserve
Type
    Net Horizontal
Drilling Locations
     % by Reserve
Type
 

Proved

     25        26     14        21

Probable

     44        45     26        39

Possible

     28        29     27        40
  

 

 

    

 

 

   

 

 

    

 

 

 

Total

     97        100     67        100
  

 

 

    

 

 

   

 

 

    

 

 

 

As of June 30, 2018, management estimates the current remaining undrilled locations to be 381 gross (244 net), of which 242 gross (197 net) are operated locations. The increase in locations since our September 30, 2017 NSAI Report is in connection with acreage added in our Champions Assets, along with our acquisition of the New Mexico Assets. See “—Recent Developments” below for further information regarding the increase in our well counts.



 

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We have estimated our drilling locations based on well spacing assumptions and upon the evaluation of our horizontal drilling results and those of other offset operators, combined with our interpretation of available geologic and engineering data, in addition to what is credited in the NSAI Report. The drilling locations that we actually drill will depend on the availability of capital, regulatory approvals, commodity prices, costs, actual drilling results and other factors. Any drilling activities we are able to conduct on these identified locations may not be successful and may not result in additional proved reserves. Further, to the extent the drilling locations are associated with acreage that expires, we would lose our right to develop the related locations. See “Risk Factors—Risks Related to Our Business—Our identified drilling locations are scheduled over many years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling. In addition, we may not be able to raise the substantial amount of capital that would be necessary to drill such locations.”

Our Business Strategies

We plan to achieve our primary objective—to increase shareholder value—by executing the following business strategies:

 

   

Grow production, reserves and cash flow by developing our existing horizontal well inventory. We consider our inventory of horizontal drilling locations to have relatively low development risk because of the information gained from our operating experience on our acreage, industry activity by offset operators surrounding our acreage and historic activity on the San Andres Formation. We intend to economically grow production, reserves and cash flow by utilizing our technical expertise to develop our multi-year drilling inventory while efficiently allocating capital to maximize the value of our resource base.

 

   

Leverage our experience operating in the Permian Basin to maximize returns. We were an early entrant to the horizontal development of the San Andres Formation of the Permian Basin. Substantially all of our current properties are positioned in what we believe to be the core of the horizontal San Andres Formation play in Yoakum County, Texas and Lea, Roosevelt, and Chaves Counties, New Mexico, where horizontal production on the San Andres Formation has increased by more than 425% since January 2014. As of June 30, 2018, we have operated or participated in 80 gross horizontal San Andres Formation wells, which affords us keen insight and expertise on the reservoir characteristics of the play. We intend to leverage our management and technical teams’ experiences in applying unconventional drilling and completion techniques in the Permian Basin to maximize our returns.

 

   

Target contiguous acreage positions in prolific Permian Basin resource plays. We will seek to expand on our success in targeting contiguous acreage positions within the Northwest Shelf and particularly the San Andres Formation. Our leasing and acquisition strategies have been predicated on our belief that acquiring large contiguous acreage blocks with significant untapped potential in terms of ultimate recoverable reserves, or acquiring additional working interests from other operators in areas we believe to be located in the core of the play and our core drilling locations, provide us with favorable reservoir and geological characteristics primarily for oil development. We have developed internal geologic models that incorporate publicly available third-party data, including well results and drilling and completion reports, to confirm our geologic model and define the various core acreage positions of a play. Once we believe that we have identified a core location, we intend to aggressively execute on our acquisition strategy to establish a largely contiguous acreage position in proximity to the core. We believe our evaluation techniques uniquely-position us to better identify acquisition targets to grow our resource base and increase shareholder value.

 

   

Maintain a high degree of operational control to continuously drive our operating costs lower and capture efficiencies. We intend to maintain operational control of a substantial majority of our drilling inventory by owning in excess of 50% of the working interest in the associated locations. We believe



 

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that maintaining operating control enables us to increase our reserves while lowering our per unit development costs, and allows us to deploy our strategies regarding LOE cost reduction and infrastructure efficiencies. Our control over operations and our ownership and operation of associated infrastructure for salt water disposal systems and electricity distribution allows us to utilize what we believe to be cost-effective operating practices. These cost-effective practices include the selection of drilling locations, timing of development and associated capital expenditures and continuous improvement of drilling, completion and stimulation techniques.

 

   

Maintain financial flexibility and apply a disciplined approach to capital allocation. We seek a capital structure with sufficient liquidity to execute our growth plans, while maintaining conservative leverage, and providing financial and operational flexibility through the various commodity price cycles. To achieve more predictable cash flow and reduce volatility during commodity price cycles, we also enter into hedging arrangements for our crude oil production. We expect to fund our growth primarily through cash flow from operations, proceeds from this offering, availability under our revolving credit facility, and subsequent equity or debt offerings when appropriate. As we expect our cash flow to continue to grow over time, we believe we will be able to fund a larger percentage of our future growth from internally generated cash flow. We intend to continue allocating capital in a disciplined manner and aggressively managing our cost structure to achieve our financial objectives. Consistent with our disciplined approach to financial management, we have an active commodity hedging program that seeks to reduce our exposure to downside commodity price fluctuations.

Our Competitive Strengths

We believe that the following strengths will allow us to successfully execute our business strategies:

 

   

Large contiguous asset base in one of North America’s leading oil resource plays. Our acreage is primarily located on large, contiguous blocks in Yoakum County, Texas and Lea, Roosevelt, and Chaves Counties, New Mexico, producing from the San Andres Formation, which is one of the most active areas on the Northwest Shelf. This acreage is characterized by a multi-year, oil-weighted inventory of horizontal drilling locations that we believe provides attractive growth and return opportunities. As of September 30, 2017, we had approximately 19,893 net acres and 14,009 MBoe of proved reserves (86% oil, 6% natural gas and 8% NGLs), 13,016 MBoe of probable reserves (86% oil, 6% natural gas and 8% NGLs) and 13,049 MBoe of possible reserves (85% oil, 6% natural gas and 9% NGLs). We believe that our most recent well results demonstrate that many of the wells on our acreage are capable of producing single-well rates of return that are competitive with many of the top performing basins in the United States. As a result, we believe we are well-positioned to continue to grow our reserves, production and cash flows in the current commodity price environment.

 

   

Proven management team with substantial technical expertise. Our Chief Executive Officer, Bobby Riley, was one of the original designers of systems for down-hole data acquisition in gravel pack and frack pack operations and has more than 40 years of experience in the independent oil and gas sector. Our management and technical teams have a total of over 100 years of collective oil and gas experience, including significant experience in horizontal drilling in the Central Basin Platform and Northwest Shelf. This complements our team’s prior experience in horizontal drilling in the Eagle Ford Shale play in South Texas, Wolfcamp play in the Permian Basin, Bakken Shale location in North Dakota and Barnett Shale location in North Texas, among other locations. We believe our team’s technical capabilities and experience enhance our horizontal drilling and production capabilities and ultimate well recoveries.

 

   

High degree of operational control with reduced development costs. As of June 30, 2018, we maintained operational control on approximately 66% of our net undeveloped acreage, by owning in excess of 50% of the working interest in the associated locations. We believe that maintaining



 

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operating control enables us to increase our reserves while lowering our development costs. Our control over operations also allows us to determine the selection of drilling locations, timing of development and associated capital expenditures and continuous improvement of drilling, completion and stimulation techniques. For example, we have made the strategic decision to own and operate the salt water disposal systems and electricity distribution infrastructure necessary to support operations. This has allowed us to significantly reduce our operating costs and keep pace with our expected development program. In addition, all of the Champions Assets are dedicated to a third-party crude and natural gas gathering system with the contracts structured as acreage dedications, which allows us to avoid fees or penalties associated with minimum volume commitments. We believe these factors will contribute to our ability to grow production, reserves and cash flows even in lower commodity price environments.

 

   

Conservative balance sheet. We expect to maintain financial flexibility that will allow us to continue our development activities and selectively pursue acquisitions. We also have an active commodity hedging program that seeks to reduce our exposure to downside commodity price fluctuations as part of our maintenance of a conservative financial management program. After giving effect to this offering and the use of proceeds therefrom, we expect to have limited or no outstanding debt, available borrowing capacity under our revolving credit facility and cash on our balance sheet to provide us with sufficient liquidity to execute on our current capital program.

Capital Program

Our fiscal 2019 capital budget is $103.6 million, of which approximately $90.7 million is allocated for drilling and completion activity for an estimated 36 gross (27 net) wells, approximately $6.3 million for continued infrastructure buildout (e.g. saltwater disposal and electrical infrastructure), approximately $3.6 million for capitalized workovers, and approximately $3.0 million for leasehold acquisition and renewal efforts. Our capital budget excludes any amounts that may be paid for future acquisitions. During the fiscal year ended September 30, 2017, our aggregate capital expenditures were $52.6 million, of which approximately $36.8 million was for drilling and completion activity of which $24.1 million was for 18 gross (10 net) wells and the remaining $12.7 million was spent on drilling or completion activities associated with other wells such as saltwater disposal, drilled but uncompleted wells and other wells that were drilled in prior years and completed during fiscal year 2017, $11.1 million for infrastructure, $2.8 million for capitalized workovers, and $1.9 million for leasehold renewals and acquisitions. During the nine months ended June 30, 2018, our aggregate capital expenditures were $67.4 million, of which approximately $34.7 million was for drilling and completion activity, $4.3 million for capitalized workovers, $4.3 million for infrastructure, $4.4 million for leasehold acquisitions and renewal efforts, and $19.7 million for acquisition costs.

By maintaining operational control on approximately 66% of our net undeveloped acreage, the amount and timing of our capital expenditures 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 the success of our drilling activities, volatility in commodity prices, the availability of necessary equipment, infrastructure, personnel and capital, the receipt and timing of required regulatory permits and approvals, seasonal conditions and drilling and acquisition costs. Any reduction in our capital expenditure budget could have the effect of delaying or reducing our development program, which may negatively impact our ability to grow production and could materially and adversely affect our future business, financial condition, results of operations or liquidity. For further discussion of the risks we face, please read “Risk Factors—Risks Related to Our Business—Our exploration and development projects require substantial capital expenditures. We may be unable to obtain required capital or financing on satisfactory terms, which could lead to a decline in our reserves.”



 

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Our Corporate History

We were formed on June 13, 2016 as a wholly-owned subsidiary of REG. An affiliate of REG operated the acreage comprising the Champions Assets pursuant to a joint operating agreement by and among REG, that affiliate and other owners of the Champions Assets. On June 1, 2017, our wholly-owned subsidiary, Riley Permian Operating Company LLC (referred to as RPOC), became operator of record of the Champions Assets. In connection with the transfer of operator of record to RPOC, the joint operating agreement relating to the operations of the Champions Assets was terminated effective June 1, 2017.

We acquired the Champions Assets in a series of transactions in 2017. On January 17, 2017, each of REG and Boomer contributed to us their respective working interests and other oil and natural gas assets and related liabilities in the Champions Assets, in exchange for our common units. On March 6, 2017, each of Bluescape and DR/CM contributed to us their respective working interests and other oil and natural gas assets and related liabilities in the Champions Assets in exchange for our common units.

On September 8, 2017, as part of the final settlement related to Bluescape’s contribution of Champions Assets on March 6, 2017, we paid $200,000 to resolve outstanding claims related to net profits and overriding royalty interests associated with the Champions Assets contributed by Bluescape on March 6, 2017. On November 21, 2017, we terminated those net profits and overriding royalty interests.

In connection with the contribution transactions in March and September 2017, we issued our Series A Preferred Units to Yorktown, Boomer and Bluescape in exchange for aggregate capital contributions of approximately $50 million. See “—Our Sponsors” below for information on Yorktown, Boomer and Bluescape. As a result, Yorktown, Boomer and Bluescape owned, prior to the offering contemplated by this prospectus, approximately 43%, 14% and 43% of our Series A Preferred Units, respectively.

Prior to the effectiveness of the registration statement of which this prospectus forms a part, we will convert into a Delaware corporation pursuant to a statutory conversion and be renamed Riley Exploration Permian, Inc. See “Corporate Conversion.”

Recent Developments

Operations

For the nine months ended June 30, 2018, our average net daily production was 3,136 BOE/d, of which approximately 94% was oil, 2% was natural gas and 4% was NGLs. As of June 30, 2018, we produced from 80 gross (40 net) horizontal wells which included both our operated and non-operated wells combined. Since September 30, 2017, our producing well count has increased by 27 gross (17 net) wells. During the nine months ended June 30, 2018, we incurred capitalized costs of $67.4 million, of which approximately $34.7 million was allocated for drilling and completion activity, approximately $4.3 million for continued infrastructure buildout (e.g. saltwater disposal and electrical infrastructure), approximately $4.4 million for leasehold acquisition and renewal efforts, approximately $4.3 million for capitalized workovers, and $19.7 million for acquisition costs.

Revolving Credit Facility

In connection with the May 1 borrowing base redetermination date, we elected to increase the borrowing base from $60 million to $100 million effective as of May 25, 2018. On September 14, 2018, a scheduled borrowing base redetermination was initiated and we expect such redetermination to be completed in early October. In the event that such redetermination results in an increase to our borrowing base amount, the Company may elect to accept the increase at that time. Since June 30, 2018, we borrowed an additional $9.5 million. As of September 19, 2018, we had $53.6 million of outstanding borrowings and an additional $46.5 million available under our revolving credit facility and were in compliance with all applicable financial covenants.



 

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Rockcliff Acquisition

On May 15, 2018, we acquired a total of 43,699 net mineral acres in Chaves, Lea, and Roosevelt Counties, New Mexico, one producing well, a salt water disposal well, and associated gathering lines (the “New Mexico Assets”) for a total purchase price of $ 19.7 million, as adjusted in accordance with the terms of the purchase and sale agreement with Rockcliff Operating New Mexico LLC (the “Rockcliff Acquisition”). The New Mexico Assets, by itself, has the potential to support approximately 272 gross (171 net) additional undrilled horizontal locations based upon (4 wells per section). For the month ended June 30, 2018, the New Mexico Assets’ net daily production was 66 BOE/d, of which 71% was oil, 5% was natural gas and 24% was NGLs.

Our Equity Sponsors

Yorktown Partners, LLC

Yorktown Partners is a private investment manager founded in 1991 that invests exclusively in the energy industry with an emphasis on North American oil and gas production and midstream businesses. Yorktown Partners has raised 11 private equity funds totaling over $8 billion. The investors of Yorktown Partners’ funds include university endowments, foundations, families, insurance companies, and other institutional investors. Yorktown Partners’ investment professionals review a large number of potential energy investments and are actively involved in decisions relating to the acquisition and disposition of oil and natural gas assets by the various portfolio companies in which Yorktown Partners’ funds own interests. With their extensive investment experience in the oil and natural gas industry and their extensive network of industry relationships, we believe that Yorktown Partners’ funds are well positioned to assist us in identifying and evaluating acquisition opportunities and in making strategic decisions. Yorktown Partners’ funds are not obligated to sell any properties to us and they are not prohibited from competing with us to acquire oil and natural gas properties. Investment funds managed by Yorktown Partners manage numerous other portfolio companies that are engaged in the oil and natural gas industry and, as a result, Yorktown Partners and its funds may present acquisition opportunities to other Yorktown Partners portfolio companies that compete with us.

Bluescape Energy Partners, LLC

Bluescape is an affiliate of Bluescape Energy Partners LLC, which is a subsidiary of Bluescape Resources Company LLC (or Bluescape Resources), a private investment manager founded in 2007 that invests exclusively in the energy industry with an emphasis on North American oil and gas production and power businesses. Bluescape Resources and its affiliates have invested approximately $1.8 billion through 2017. The investors of Bluescape Resources’ funds include university endowments, corporate and government pensions, foundations, families, and other institutional investors. Bluescape Resources’ investment professionals review a large number of potential energy investments and are actively involved in decisions relating to the acquisition and disposition of oil and natural gas assets by the various portfolio companies in which Bluescape Resources’ funds own interests. Bluescape Resources’ funds are not obligated to sell any properties to us and they are not prohibited from competing with us to acquire oil and natural gas properties. Investment funds managed by Bluescape Resources manage numerous other portfolio companies that are engaged in the oil and natural gas industry and, as a result, Bluescape Resources and its funds may present acquisition opportunities to other Bluescape Resources’ portfolio companies that compete with us.

Boomer Petroleum, LLC

Boomer Petroleum, LLC (or Boomer) is a private investment firm based in Calgary in the Canadian province of Alberta formed in 2012 by the Alvin Libin family and the Antonie VandenBrink family to invest in oil and gas properties in Texas. Alvin Libin is an experienced businessman with investments in real estate and oil and gas companies. Antonie VandenBrink is a member of the Canadian Petroleum Hall of Fame and has over 50 years’ experience in the energy industry. He most recently served as Chairman of Bantrel Group Engineers Ltd.



 

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and as a member of the board of Banister Pipelines Ltd. Earlier in his career, he held leadership and operating roles with Bawden Drilling, Jennings International Drilling, Kenting Drilling, and Trimac Ltd.

As described in “—Our Corporate History,” REG and Boomer contributed Champions Assets to us in exchange for our common units, on January 17, 2017, as did Bluescape and DR/CM, on March 6, 2017. Yorktown, Boomer and Bluescape, each provided equity financing to us concurrent with the March transactions, in exchange for our Series A Preferred Units. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources” for information on the Series A Preferred Unit financings. Following our Corporate Conversion and the completion of this offering, REG, Yorktown, Boomer, Bluescape and DR/CM will directly own     %,     %,     %,     % and     %, respectively, of our common stock, or     %,     %,     %,     % and     %, respectively, if the underwriters’ option to purchase additional shares is exercised in full. Certain investment funds managed by Yorktown Partners also own an approximate     % interest in REG.

For more information about our principal shareholders, please see “Security Ownership of Certain Beneficial Owners and Management.”



 

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OWNERSHIP STRUCTURE

The following diagram indicates our ownership structure immediately after the transactions described in “Corporate Conversion” and this offering (assuming that the underwriters’ option to purchase additional shares is not exercised) and does not give effect to                  shares of common stock reserved for future issuance under the Riley Exploration Permian, Inc. 2018 Long Term Incentive Plan (or our LTIP) or our intended grant of                shares of common stock to certain officers and directors under the LTIP in connection with the successful completion of this offering. See “Executive Compensation—2018 Long Term Incentive Plan” for more information.

 

LOGO

 

(1)

Includes REG, Yorktown, Bluescape, Boomer and DR/CM, which will own approximately    %,    %,    %,     %, and    % of our common stock, respectively (or    %,    %,    %,     %, and    %, respectively, if the underwriter’s option to acquire additional shares of common stock is exercised in full). Certain investment funds managed by Yorktown Partners also own approximately    % of REG. See “Capitalization” and “Security Ownership of Certain Beneficial Owners and Management” as well as our pro forma financial information included elsewhere in this prospectus for more information on the ownership of our common stock.

Risk Factors

An investment in our common stock involves a high degree of risk, including a number of risks involving the speculative nature of oil and natural gas exploration, competition, volatile commodity prices and other material factors.

Importantly, due to an abundance of supply in the global crude oil market and the domestic natural gas market, oil and natural gas prices have been volatile since late 2014. While we continue to believe our inventory



 

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of drilling opportunities is repeatable and relatively low-risk, should oil and natural gas prices materially decrease, we may reevaluate our development drilling program. Any postponement or elimination of our development drilling program could result in a reduction of proved reserve volumes and related standardized measure.

You should consider and read carefully all of the risks and uncertainties described in “Risk Factors” beginning on page 22, together with all of the other information contained in this prospectus, including our historical and pro forma financial statements and related notes thereto appearing elsewhere in this prospectus, before investing in our common stock. These risks could materially affect our business, financial condition and results of operations and cause the trading price of our common stock to decline. You could lose part or all of your investment. You should bear in mind, in reviewing this prospectus, that past experience is no indication of future performance. You should read “Cautionary Note Regarding Forward-Looking Statements” for a discussion of what types of statements are forward-looking statements, as well as the significance of such statements in the context of this prospectus.

Emerging Growth Company Status

We are an “emerging growth company” as defined in the JOBS Act. For as long as we are an emerging growth company, unlike other public companies that are not emerging growth companies under the JOBS Act, we are not required to:

 

   

provide an auditor’s attestation report on management’s assessment of the effectiveness of our system of internal control over financial reporting pursuant to Section 404(b) of the Sarbanes-Oxley Act of 2002, or the Sarbanes-Oxley Act;

 

   

provide more than two years of audited financial statements and related management’s discussion and analysis of financial condition and results of operations nor more than two years of selected financial data in the initial public offering;

 

   

comply with any new requirements adopted by the Public Company Accounting Oversight Board, or the PCAOB, requiring mandatory audit firm rotation or a supplement to the auditor’s report in which the auditor would be required to provide additional information about the audit and the financial statements of the issuer;

 

   

provide certain disclosure regarding executive compensation required of larger public companies or hold shareholder advisory votes on executive compensation required by the Dodd-Frank Wall Street Reform and Consumer Protection Act, or the Dodd-Frank Act; or

 

   

obtain shareholder approval of any golden parachute payments not previously approved.

We will cease to be an emerging growth company upon the earliest of:

 

   

the last day of the fiscal year in which we have $1.07 billion or more in annual revenues;

 

   

the date on which we become a “large accelerated filer” (the fiscal year-end on which the total market value of our common equity securities held by non-affiliates is $700 million or more as of September 30);

 

   

the date on which we issue more than $1.0 billion of non-convertible debt over a three-year period; or

 

   

the last day of the fiscal year following the fifth anniversary of our initial public offering.

In addition, Section 107 of the JOBS Act provides that an emerging growth company can take advantage of the extended transition period provided in Section 7(a)(2)(B) of the Securities Act of 1933, as amended, or the Securities Act, for complying with new or revised accounting standards. We have elected to rely on this extended transition period.



 

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Corporate Information

Our principal executive offices are located at 29 E. Reno Avenue, Suite 500, Oklahoma City, Oklahoma 73104, and our telephone number at that address is (405) 415-8699. Our website is located at www.rileypermian.com. We expect to make our periodic reports and other information filed with or furnished to the SEC available free of charge through our website as soon as reasonably practicable after those reports and other information are electronically filed with or furnished to the SEC. Information on, or otherwise accessible through, our website or any other website is not incorporated by reference herein and does not constitute a part of this prospectus.



 

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The Offering

 

Common stock offered by us

            shares (or            shares, if the underwriters exercise in full their option to purchase additional shares).

 

Common stock to be outstanding after the offering

             shares (or             shares, if the underwriters exercise in full their option to purchase additional shares).

 

Option to purchase additional shares

We have granted the underwriters a 30-day option to purchase up to an aggregate of             additional shares of our common stock to cover over-allotments, if any.

 

Use of proceeds

Assuming the midpoint of the price range set forth on the cover of this prospectus, we expect to receive approximately $         million of net proceeds from this offering, or $        million if the underwriters exercise their option to purchase             additional shares in full, in each case, after deducting underwriting discounts and commissions and estimated offering expenses payable by us.

 

  We intend to use the net proceeds from this offering (i) to fund our fiscal 2019 capital program, (ii) for general corporate purposes, (iii) to fully repay our existing balance of approximately $         million under our revolving credit facility and (iv) to pay an aggregate of $2.1 million in one-time cash bonuses to our named executive officers and certain of our employees.

 

  Please see “Use of Proceeds.”

 

Conflicts of interest

We may use a portion of the net proceeds of this offering to repay indebtedness owed by us to affiliates of SunTrust Robinson Humphrey, Inc. that are lenders under our revolving credit facility. See “Use of Proceeds.” Because such repayment may constitute 5% or more of the net proceeds of this offering, this offering will be conducted in compliance with the applicable provisions of Rule 5121 of the Financial Industry Regulatory Authority, Inc., or FINRA. Accordingly, the appointment of a “qualified independent underwriter” is required in connection with this offering, and Seaport Global Securities has agreed to act as a qualified independent underwriter for this offering in accordance with Rule 5121 of FINRA. See “Underwriting (Conflicts of Interest)—Conflicts of Interest.”

 

Dividend policy

We do not anticipate paying any cash dividends on our common stock. In addition, our revolving credit facility places certain restrictions on our ability to pay cash dividends. See “Dividend Policy.”

 

Risk factors

You should carefully read and consider the information set forth under the heading “Risk Factors” and all other information set forth in this prospectus before deciding to invest in our common stock.


 

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Listing and trading symbol

We have been cleared to apply to list our common stock on the NYSE American LLC, or the NYSE American, under the symbol “REPX.”

Unless otherwise indicated, all information in this prospectus:

 

   

gives effect to the Corporate Conversion as described under “Corporate Conversion;”

 

   

assumes no exercise of the underwriters’ option to purchase additional shares; and

 

   

excludes                 shares of common stock reserved for issuance pursuant to our LTIP, which we intend to adopt in connection with the completion of this offering and does not include                shares of our common stock expected to be issued to certain officers and directors in connection with the successful completion of this offering pursuant to our LTIP. See “Executive Compensation—2018 Long Term Incentive Plan” and “Executive Compensation—Additional Narrative Disclosures—Employment, Severance or Change in Control Agreements” and “—2018 Long Term Incentive Plan for more information.



 

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SUMMARY HISTORICAL FINANCIAL AND OPERATING DATA

Historical Financial Data

The summary historical financial data as of June 30, 2018 and for the nine months ended June 30, 2018 and 2017 and the years ended September 30, 2017 and 2016, were derived from our unaudited and audited historical financial statements, respectively, included elsewhere in this prospectus.

In a series of contribution transactions, we acquired the Champions Assets in exchange for our common units, including a contribution on January 17, 2017 from REG. See “Prospectus Summary—Our Corporate History” for more information. The contribution received from REG was considered a transfer of a business between entities under common control and accordingly, we recorded the contributed business at historical cost and for the periods prior to January 17, 2017, the financial statements have been prepared on a “carve-out” basis from REG’s accounts and reflect the historical accounts directly attributable to the Champions Assets owned by REG together with allocations of costs and expenses. The contributions from Boomer, Bluescape and DR/CM were accounted for as business combinations in accordance with ASC 805—Business Combinations and recorded at fair value. Our financial statements reflect the operating results of the assets contributed by Boomer, Bluescape and DR/CM for the periods following the respective contributions. The earnings per common unit reflect the common units received by REG for all periods and the common units received from Boomer, Bluescape and DR/CM for the periods following their respective contributions. For more information, please see “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Overview.”



 

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You should read the following summary data in conjunction with “Use of Proceeds,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the historical financial statements included elsewhere in this prospectus.

 

     For the Nine Months Ended
June 30,
    For the Years Ended
September 30,
 
     (unaudited)              
     2018     2017     2017     2016  
     ($ in Thousands, Except Unit and Per Unit Amounts)  

Statement of Operations Data:

  

Revenues:

        

Oil sales

   $ 46,438     $ 11,360     $ 21,174     $ 4,081  

Natural gas sales

     252       135       203       29  

Natural gas liquids sales

     909       262       431       20  
  

 

 

   

 

 

   

 

 

   

 

 

 

Total Revenues

     47,599       11,757       21,808       4,130  

Operating Expenses:

        

Lease operating expenses

     8,135       3,831       5,796       2,779  

Production taxes

     2,191       641       1,206       194  

Exploration expenses

     5,523       1,107       10,739       45  

Depletion, depreciation, amortization, and accretion

     11,388       3,268       5,876       1,366  

General and administrative expenses

     10,596       4,616       5,806       3,863  

Transaction Costs

     790       1,233       1,766       —    
  

 

 

   

 

 

   

 

 

   

 

 

 

Total Operating Expenses

     38,623       14,696       31,189       8,247  
  

 

 

   

 

 

   

 

 

   

 

 

 

Income (loss) from Operations:

   $ 8,976     $ (2,939   $ (9,381   $ (4,117

Other Expenses:

        

Interest Expense

     (907     —         —         —    

Gain (loss) on derivatives

     (13,895     752       (1,450     —    
  

 

 

   

 

 

   

 

 

   

 

 

 

Loss before Income Tax Provision

   $ (5,826   $ (2,187   $ (10,831   $ (4,117

Income Tax Expense

     —         —         —         9  
  

 

 

   

 

 

   

 

 

   

 

 

 

Net Loss

   $ (5,826   $ (2,187   $ (10,831   $ (4,126
  

 

 

   

 

 

   

 

 

   

 

 

 

Dividends on Preferred Units

     (2,327     (772     (1,409     —    
  

 

 

   

 

 

   

 

 

   

 

 

 

Net Loss Attributable to Common Units

   $ (8,153   $ (2,959   $ (12,240   $ (4,126
  

 

 

   

 

 

   

 

 

   

 

 

 

Loss per common unit:

        

Basic and Diluted

   $ (5.44   $ (2.86   $ (10.63   $ (7.20

Weighted average common units outstanding

     1,500,000       1,033,816       1,151,320       573,408  

 

     At June 30, 2018  
     Actual      As Adjusted (1)      As Further
Adjusted (2)
 
     (unaudited)                
     ($ in Thousands)  

Statement of Balance Sheet Data:

  

Cash and cash equivalents

   $ 1,029      $ 1,029     

Total oil & gas properties

     227,914        227,914     

Total assets

     242,133        242,133     

Long-term debt, including current maturities

     44,113        44,113     

Series A Preferred Units

     52,739        —       

Total members’ / stockholders’ equity

     104,241        151,916     


 

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(1)

The as adjusted balance sheet data gives effect to the Corporate Conversion as described under “Corporate Conversion.”

(2)

The as adjusted balance sheet data gives further effect to our issuance and sale of                shares of our common stock offered in this offering at an assumed initial public offering price of $                per share, which is the midpoint of the price range set forth on the cover page of this prospectus, after deducting estimated underwriting discounts and commissions and estimated offering expenses payable by us. A $1.00 increase (decrease) in the assumed initial public offering price of $                per share of our common stock, which is the midpoint of the price range set forth on the cover page of this prospectus, would increase (decrease) the as adjusted amount of each of cash and cash equivalents, total assets and total stockholders’ equity by $                million, assuming that the number of shares offered by us, as set forth on the cover page of this prospectus, remains the same and after deducting estimated underwriting discounts and commissions. An increase (decrease) of 1.0 million shares in the number of shares of our common stock offered by us, as set forth on the cover page of this prospectus, would increase (decrease) the as adjusted amount of each of cash and cash equivalents, total assets and total stockholders’ equity by $                million, assuming no change in the assumed initial public offering price per share and after deducting estimated underwriting discounts and commissions.

 

    For the Nine Months
Ended June 30,
    For the Years Ended
September 30,
 
    (unaudited)              
    2018     2017     2017     2016  
    (in Thousands)  

Statement of Cash Flows Data:

 

Net cash provided by (used in) operating activities

  $ 22,093     $ (371   $ 3,289     $ (9,125

Net cash used in investing activities

  $ (67,444   $ (39,619   $ (54,781   $ (24,087

Net cash provided by financing activities

  $ 42,697     $ 45,210     $ 55,175     $ 33,212  

Adjusted EBITDAX (1)

  $ 21,028     $ 1,528     $ 7,407     $ (2,715

 

(1)

Adjusted EBITDAX is a non-GAAP financial measure. For a definition of Adjusted EBITDAX and a reconciliation of Adjusted EBITDAX to our net income (loss), see “—Non-GAAP Financial Measure” below.

Non-GAAP Financial Measure

Adjusted EBITDAX is not a measure of net income (loss) as determined by United States generally accepted accounting principles, or GAAP. Adjusted EBITDAX is a supplemental non-GAAP financial measure that is used by management and external users of financial statements, such as industry analysts, investors, lenders and rating agencies. We define Adjusted EBITDAX as net income (loss) adjusted for certain cash and non-cash items, including depreciation, depletion, amortization and accretion, or DD&A, impairment of long lived assets, provision for the carrying value of receivables and inventory, exploration expenses, commodity derivative (gain) loss, settlements on commodity derivatives, premiums paid for derivatives that settled during the period, unit-based compensation expense, interest expense, income taxes, and non-recurring charges.

Management believes Adjusted EBITDAX is useful because it allows us to more effectively evaluate our operating performance and compare the results of our operations from period to period without regard to our financing methods or capital structure. We exclude the items listed above from net income (loss) in arriving at Adjusted EBITDAX because these amounts can vary substantially from company to company within our industry depending upon accounting methods and book values of assets, capital structures and the method by which the assets were acquired. Adjusted EBITDAX should not be considered as an alternative to, or more meaningful than, net income (loss) as determined in accordance with GAAP or as an indicator of our operating performance. Certain items excluded from Adjusted EBITDAX are significant components in understanding and assessing a company’s financial performance, such as a company’s cost of capital, hedging strategy and tax



 

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structure, as well as the historic costs of depreciable assets, none of which are components of Adjusted EBITDAX. Our computations of Adjusted EBITDAX may not be comparable to other similarly titled measure of other companies. We believe that Adjusted EBITDAX is a widely followed measure of operating performance.

The following table presents a reconciliation of the GAAP financial measure of net income (loss) to Adjusted EBITDAX for each of the periods indicated.

 

     For the Nine Months
Ended June 30,
    For the Years Ended
September 30,
 
     (unaudited)              
     2018     2017     2017     2016  
     (in Thousands)  

Reconciliation of Net Income (Loss) to Adjusted EBITDAX

        

Net income (loss)

   $ (5,826   $ (2,187   $ (10,831   $ (4,126

Exploration expenses

     5,523       1,107       10,739       45  

Interest expense

     907       —         —         —    

Depletion, depreciation, amortization and accretion

     11,388       3,268       5,876       1,366  

(Gain) loss on unsettled derivatives

     9,036       (660     1,623       —    
  

 

 

   

 

 

   

 

 

   

 

 

 

Adjusted EBITDAX

   $ 21,028     $ 1,528     $ 7,407     $ (2,715

Summary Historical Operating and Reserve Data

Summary Reserve Data

The following table presents summary data with respect to our estimated proved oil and natural gas reserves as of the dates indicated. The reserve estimates at September 30, 2017 presented in the table below are based on the NSAI Report and were prepared consistent with the rules promulgated by the SEC regarding oil, natural gas and NGL reserve reporting.

Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Business—Reserve Data” in evaluating the material presented below.

 

     As of September 30, 2017 (1)  

Proved Reserves:

  

Oil (MBbls)

     12,026  

Natural Gas (MMcf)

     4,821  

Natural Gas Liquids (MBbls)

     1,179  

Total Proved Reserves (MBoe)

     14,009  

Proved Developed Reserves:

  

Oil (MBbls)

     7,064  

Natural Gas (MMcf)

     2,814  

Natural Gas Liquids (MBbls)

     692  

Proved Developed Reserves (MBoe)

     8,226  

Proved Developed Reserves as a % of Proved Reserves

     59%  

Proved Undeveloped Reserves:

  

Oil (MBbls)

     4,961  

Natural Gas (MMcf)

     2,006  

Natural Gas Liquids (MBbls)

     487  

Proved Undeveloped Reserves (MBoe)

     5,783  

Proved Undeveloped Reserves as a % of Proved Reserves

     41%  


 

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     As of September 30, 2017 (1)  

Probable Reserves (2):

  

Oil (MBbls)

     11,137  

Natural Gas (MMcf)

     4,639  

Natural Gas Liquids (MBbls)

     1,106  

Total Probable Reserves (MBoe)

     13,017  

Probable Developed Non-Producing Reserves (2):

  

Oil (MBbls)

     145  

Natural Gas (MMcf)

     14  

Natural Gas Liquids (MBbls)

     3  

Probable Developed Non-Producing Reserves (MBoe)

     151  

Probable Undeveloped Reserves (2):

  

Oil (MBbls)

     10,992  

Natural Gas (MMcf)

     4,625  

Natural Gas Liquids (MBbls)

     1,102  

Probable Undeveloped Reserves (MBoe)

     12,865  

Possible Reserves (3):

  

Oil (MBbls)

     11,149  

Natural Gas (MMcf)

     4,691  

Natural Gas Liquids (MBbls)

     1,118  

Total Possible Reserves (MBoe)

     13,049  

 

(1)

Our estimated reserves were determined using the unweighted arithmetic average of the historical first-day-of-the-month prices for the prior 12 months as of September 30, 2017 of $46.27 per Bbl for oil and NGL volumes, and $3.00 per MMBtu for natural gas, at the average Henry Hub spot price. The WTI price for oil (and NGL) volumes is adjusted by lease for quality, transportation fees, and market differentials. The Henry Hub spot price for gas volumes is adjusted by lease for energy content, and market differentials. For more information on the differences between the categories of proved, probable and possible reserve, see “Business—Oil and Natural Gas Data.”

(2)

Our estimated probable reserves are classified as both developed non-producing and as undeveloped.

(3)

All of our estimated possible reserves are classified as undeveloped.



 

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Production and Operating Data

The following table sets forth information regarding our production, realized prices and production costs as of and for the nine months ended June 30, 2018 and 2017 and the years ended September 30, 2017 and 2016. For additional information, please see “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

 

     For the Nine
Months Ended
June 30,
     For the Years
Ended
September 30,
 
     2018      2017      2017      2016  

Total Sales Volumes:

           

Oil sales (MBbls)

     801        251        470        108  

Natural gas sales (MMcf)

     126        50        76        16  

Natural gas liquids sales (MBbls)

     34        13        21        1  
  

 

 

    

 

 

    

 

 

    

 

 

 

Total (MBoe) (1)

     856        272        504        112  

Daily Sales Volumes:

           

Oil sales (Bbl/d)

     2,934        919        1,291        297  

Natural gas sales (Mcf/d)

     462        183        209        44  

Natural gas liquids sales (Bbl/d)

     125        48        58        3  
  

 

 

    

 

 

    

 

 

    

 

 

 

Total (BOE/d) (1)

     3,136        998        1,384        308  

Average sales prices (1):

           

Oil sales (per Bbl)

   $ 57.98      $ 45.26      $ 45.05      $ 37.65  

Oil sales with derivative settlements (per Bbl) (2)

     51.91        45.63        45.42        37.65  

Natural gas sales (per Mcf)

     2.00        2.70        2.67        1.82  

Natural gas sales with derivative settlements (per Mcf) (2)

     2.00        2.70        2.67        1.82  

Natural gas liquids sales (per Bbl)

     26.74        20.15        20.52        15.88  

Natural gas liquids sales with derivative settlements (per Bbl) (2)

     26.74        20.15        20.52        15.88  

Average price per BOE excluding derivative settlements (2)

     55.61        43.22        43.30        36.77  

Average price per BOE with derivative settlements (2)

     49.93        43.56        43.64        36.77  

Expense per BOE (1):

           

Lease operating expenses

   $ 9.50      $ 14.08      $ 11.51      $ 24.74  

Production and ad valorem taxes

     2.56        2.36        2.39        1.73  

Exploration expenses

     6.45        4.07        21.32        0.40  

Depletion, depreciation, amortization, and accretion

     13.30        12.01        11.67        12.16  

General and administrative expenses

     12.38        16.97        11.53        34.40  

Transaction Costs

     0.92        4.53        3.51        —    

 

(1)

One BOE is equal to six Mcf of natural gas or one Bbl of oil or NGL based on an approximate energy equivalency. This is an energy content correlation and does not reflect a value or price relationship between the commodities.

(2)

Average prices shown in the table reflect prices both before and after the effects of our settlements of our commodity derivative contracts. Our calculation of such effects includes both gains or losses on cash settlements for commodity derivatives.



 

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RISK FACTORS

Investing in our common stock involves risks. Investors should carefully consider each of the following risk factors and all of the other information set forth in this prospectus before making an investment decision. If any of the following risks actually occur, our business, financial condition, and results of operations could be materially and adversely affected and we may not be able to achieve our goals. We cannot assure you that any of the following risks will not occur. Further, the risks described below are not the only ones we face. Additional risks not presently known to us or that we currently deem immaterial also may materially affect our business. If any of the following risks or additional risks occur, you may lose all or part of your investment.

Risks Related to Our Business

Oil, natural gas and NGL prices are volatile. An extended decline in commodity prices may adversely affect our business, financial condition, or results of operations and our ability to meet our capital expenditure obligations and financial commitments. Additionally, the value of our reserves calculated using SEC pricing may be higher than the fair market value of our reserves calculated using current market prices.

The prices we receive for our oil, natural gas, and NGLs production heavily influence our revenue, profitability, access to capital, and future rate of growth. Oil, natural gas, and NGLs are commodities and, therefore, their prices are subject to wide fluctuations in response to relatively minor changes in supply and demand. Historically, the commodities market has been volatile. For example, during the period from January 1, 2014 to June 30, 2018, NYMEX West Texas Intermediate (referred to as WTI) oil prices ranged from a high of $107.95 per Bbl on June 20, 2014 to a low of $26.19 per Bbl on February 11, 2016. During 2017, WTI prices ranged from a high of $60.46 to a low of $42.48 per Bbl. Average daily prices for NYMEX Henry Hub gas ranged from a high of $3.71 per MMBtu to a low of $2.44 per MMBtu during the same period. If the prices of oil and natural gas continue to be volatile, reverse their recent increases, or decline, our operations, financial condition, cash flows and level of expenditures may be materially and adversely affected. Moreover, the duration and magnitude of any decline in oil, natural gas or NGL prices cannot be predicted with accuracy, and this market will likely continue to be volatile in the future. The prices we receive for our production, and the levels of our production, depend on numerous factors beyond our control. These factors include the following:

 

   

worldwide and regional economic conditions impacting the global supply and demand for oil, natural gas, and NGLs;

 

   

the price and quantity of foreign imports, including foreign oil;

 

   

the actions by members of the Organization of the Petroleum Exporting Countries, or OPEC, including the failure to comply with production cuts announced in November 2016;

 

   

political, economic, and military conditions in or affecting other producing countries, including embargoes or conflicts in the Middle East, Africa, South America and Russia;

 

   

the level of global oil and natural gas exploration and production activity;

 

   

the level of global oil and natural gas inventories;

 

   

prevailing prices on local price indices in the areas in which we operate;

 

   

the cost of producing and delivering oil and natural gas and conducting other operations;

 

   

the recovery rates of new oil, natural gas and NGL reserves;

 

   

lead times associated with acquiring equipment and products, and availability of qualified personnel;

 

   

late deliveries of supplies;

 

   

technical difficulties or failures;

 

   

the proximity, capacity, cost, and availability of gathering and transportation facilities;

 

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localized and global supply and demand fundamentals and transportation availability;

 

   

localized and global weather conditions;

 

   

technological advances affecting energy consumption, including advances in exploration, development and production technologies;

 

   

shareholder activism or activities by non-governmental organizations to restrict the exploration, development and production of oil, natural gas, and NGLs;

 

   

uncertainty in capital and commodities markets and the ability of companies in our industry to raise equity capital and debt financing;

 

   

the price and availability of alternative fuels; and

 

   

domestic, local, and foreign governmental regulation and taxes.

Lower commodity prices will reduce our cash flows and borrowing ability. We may be unable to obtain needed capital or financing on satisfactory terms, which could lead to a decline in the present value of our reserves and our ability to develop future reserves. Lower commodity prices may also reduce the amount of oil, natural gas and NGLs that we can produce economically. We have historically been able to hedge our oil and natural gas production at prices that are significantly higher than current strip prices. However, in the current commodity price environment, our ability to enter into comparable derivative arrangements may be limited, and, following this offering, we will not be under an obligation to hedge a specific portion of our oil or natural gas production.

Using lower prices in estimating proved reserves would likely result in a reduction in proved reserve volumes due to economic limits. While it is difficult to project future economic conditions and whether such conditions will result in impairment of proved property costs, we consider several variables including specific market factors and circumstances at the time of prospective impairment reviews, and the continuing evaluation of development plans, production data, economics and other factors. In addition, sustained periods with oil and natural gas prices at levels lower than current West Texas Intermediate strip prices and the resultant effect such prices may have on our drilling economics and our ability to raise capital may require us to re-evaluate and postpone or eliminate our development drilling, which could result in the reduction of some of our proved undeveloped reserves and related standardized measure. If we are required to curtail our drilling program, we may be unable to continue to hold leases that are scheduled to expire, which may further reduce our reserves. As a result, a substantial or extended decline in commodity prices may materially and adversely affect our future business, financial condition, results of operations, liquidity, or ability to finance planned capital expenditures.

Our development and exploratory drilling efforts and our well operations may not be profitable or achieve our targeted returns.

We have acquired significant amounts of unproved property in order to further our development efforts and expect to continue to undertake acquisitions in the future. Development and exploratory drilling and production activities are subject to many risks, including the risk that no commercially productive reservoirs will be discovered. We acquire unproved properties and lease undeveloped acreage that we believe will enhance our growth potential and increase our results of operations over time. However, we cannot assure you that all prospects will be economically viable or that we will not abandon our investments. Additionally, we cannot assure you that unproved property acquired by us or undeveloped acreage leased by us will be profitably developed, that wells drilled by us in prospects that we pursue will be productive, or that we will recover all or any portion of our investment in such unproved property or wells.

 

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Properties we acquire may not produce as projected, and we may be unable to determine reserve potential, identify liabilities associated with the properties that we acquire, or obtain protection from sellers against such liabilities.

Acquiring oil and natural gas properties requires us to assess reservoir and infrastructure characteristics, including recoverable reserves, development and operating costs, and potential liabilities, including environmental liabilities. Such assessments are inexact and inherently uncertain. For these reasons, the properties we have acquired or will acquire in the future may not produce as projected. In connection with the assessments, we perform a review of the subject properties, but such a review will not reveal all existing or potential problems. See “—We may be unable to make accretive acquisitions or successfully integrate acquired businesses or assets, and any inability to do so may disrupt our business and hinder our ability to grow” for a discussion of those factors. In the course of our due diligence, we may not review every well, pipeline or associated facility. We cannot necessarily observe structural and environmental problems, such as pipe corrosion or groundwater contamination, when a review is performed. We may be unable to obtain contractual indemnities from the seller for liabilities created prior to our purchase of the property. We may be required to assume the risk of the physical condition of the properties in addition to the risk that the properties may not perform in accordance with our expectations.

Our exploration and development projects require substantial capital expenditures. We may be unable to obtain required capital or financing on satisfactory terms, which could lead to a decline in our reserves.

The oil and natural gas industry is capital intensive. We make and expect to continue to make substantial capital expenditures for the exploitation, development, and acquisition of oil and natural gas reserves. We expect to fund our growth primarily through cash flow from operations, proceeds from this offering, availability under our revolving credit facility, and subsequent equity or debt offerings when appropriate. The actual amount and timing of our future capital expenditures may differ materially from our estimates as a result of, among other things, oil, natural gas and NGL prices, actual drilling results, the availability of drilling rigs and other services and equipment, and regulatory, technological and competitive developments. A reduction in commodity prices from current levels may result in a decrease in our actual capital expenditures, which would negatively impact our ability to grow production. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources.”

Our cash flow from operations and access to capital are subject to a number of variables, including:

 

   

our proved reserves;

 

   

the level of hydrocarbons we are able to produce from existing wells and the timing of such production;

 

   

the prices at which our production is sold;

 

   

operating costs and other expenses;

 

   

the availability of takeaway capacity;

 

   

our ability to acquire, locate and produce new reserves; and

 

   

our ability to borrow under our revolving credit facility.

If our revenues or the borrowing base under our revolving credit facility decreases as a result of lower oil, natural gas and NGL prices, operating difficulties, declines in reserves, or for any other reason, we may have limited ability to obtain the capital necessary to sustain our operations and growth at current levels. If additional capital is needed, we may not be able to obtain debt or equity financing on terms acceptable to us, if at all. If cash flow generated by our operations or available borrowings under our revolving credit facility are not sufficient to meet our capital requirements, the failure to obtain additional financing could result in a curtailment of our operations relating to development of our properties, which in turn could lead to a decline in our reserves and production, and would adversely affect our business, financial condition, and results of operations.

 

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

Our operations involve utilizing some of the latest available drilling and completion techniques as developed by us and our service providers.

The difficulties we face while drilling horizontal wells include:

 

   

landing our wellbore in the desired drilling zone;

 

   

staying in the desired drilling zone while drilling horizontally through the formation;

 

   

running our casing the entire length of the wellbore; and

 

   

being able to run tools and other equipment consistently through the horizontal wellbore.

The difficulties we face while completing our wells include:

 

   

the ability to fracture stimulate the planned number of stages;

 

   

the ability to run tools the entire length of the wellbore during completion operations; and

 

   

the ability to successfully clean out the wellbore after completion of the final fracture stimulation stage.

Additionally, certain of the new techniques we are adopting may cause irregularities or interruptions in production due to offset wells being shut in and the time required to drill and complete multiple wells before any such wells begin producing. If our drilling results in less production than anticipated, the return on our investment for a particular project may not be as attractive as we anticipated, we could incur material write-downs of unevaluated properties, and the value of our undeveloped acreage could decline in the future.

Drilling for and producing oil and natural gas are high risk activities with many uncertainties that could adversely affect our business, financial condition or results of operations.

Our future financial condition and results of operations will depend on the success of our exploitation, development, and acquisition activities, which are subject to numerous risks beyond our control, including the risk that drilling will not result in commercially viable oil and natural gas production.

Our decisions to purchase, explore, develop, or otherwise exploit prospects or properties will depend in part on the evaluation of data obtained through geophysical and geological analyses, production data, and engineering studies, the results of which are often inconclusive or subject to varying interpretations. For a discussion of the uncertainty involved in these processes, see “—Reserve estimates depend on many assumptions that may turn out to be inaccurate. Any material inaccuracies in reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.” In addition, our cost of drilling, completing, and operating wells is often uncertain before drilling commences.

Further, many factors may curtail, delay, or cancel our scheduled drilling projects, including the following:

 

   

delays imposed by or resulting from compliance with environmental and other regulatory requirements including limitations on or resulting from wastewater discharge and disposal, subsurface injections, greenhouse gas emissions, and hydraulic fracturing;

 

   

pressure or irregularities in geological formations;

 

   

increases in the cost of, or shortages or delays in availability of drilling rigs and qualified personnel for hydraulic fracturing activities;

 

   

shortages of or delays in obtaining water resources, suitable proppant, and chemicals in sufficient quantities for use in hydraulic fracturing activities;

 

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equipment failures or accidents;

 

   

lack of available gathering facilities or delays in construction of gathering facilities;

 

   

lack of available capacity on interconnecting transmission pipelines;

 

   

adverse weather conditions, such as tornadoes and ice storms;

 

   

issues related to compliance with environmental and other governmental regulations;

 

   

environmental hazards, such as oil and natural gas leaks, oil spills, pipeline and tank ruptures, encountering naturally occurring radioactive materials, and unauthorized discharges of brine, well stimulation and completion fluids, toxic gases or other pollutants into the surface and subsurface environment;

 

   

declines or volatility in oil, natural gas, and NGL prices;

 

   

limited availability of financing at acceptable terms;

 

   

title problems or legal disputes regarding leasehold rights; and

 

   

limitations in the market for oil, natural gas, and NGLs.

Our identified drilling locations are scheduled over many years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling. In addition, we may not be able to raise the substantial amount of capital that would be necessary to drill such locations.

Our management team has specifically identified and scheduled certain drilling locations as an estimation of our future multi-year drilling activities on our existing acreage. These locations represent a significant part of our growth strategy. Our ability to drill and develop these locations depends on a number of uncertainties, including oil, natural gas, and NGL prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, drilling results, lease expirations, gathering system and pipeline transportation constraints, access to and availability of water sourcing and distribution systems, regulatory approvals, and other factors. Because of these uncertain factors, we do not know if the numerous potential well locations we have identified will ever be drilled or if we will be able to produce natural gas or oil from these or any other potential locations. In addition, unless production is established within the spacing units covering the undeveloped acres on which some of the potential locations are obtained, the leases for such acreage will expire. As such, our actual drilling activities may materially differ from those presently identified.

Our undeveloped leasehold acreage must be developed or the lease renewed prior to the time the leases for such acreage expire. For more information, see “—Our undeveloped acreage must be drilled before lease expiration to hold the acreage by production. In highly competitive markets for acreage, failure to drill sufficient wells to hold acreage could result in a substantial lease renewal cost or, if renewal is not feasible, loss of our lease and prospective drilling opportunities.”

In addition, we will require significant additional capital over a prolonged period in order to pursue the development of these locations, and we may not be able to raise or generate the capital required to do so. Any drilling activities we are able to conduct on these potential locations may not be successful or result in our ability to add additional proved reserves to our overall proved reserves or may result in a downward revision of our estimated proved reserves, which could have a material adverse effect on our future business and results of operations.

Power outages, limited availability of electrical resources, and increased energy costs could have a material adverse effect on us.

Our operations are subject to electrical power outages, regional competition for available power, and increased energy costs. Power outages, which may last beyond our backup and alternative power arrangements, would harm our operations and our business.

 

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We also may be subject to risks and unanticipated costs associated with obtaining power from various utility companies. Such utilities may be dependent on, and sensitive to price increases for, a particular type of fuel, such as coal, oil or natural gas. The price of these fuels and the electricity generated from them could increase as a result of proposed legislative measures related to climate change or efforts to regulate carbon emissions.

Our indebtedness could reduce our financial flexibility.

We have a revolving line of credit in place for borrowings and letters of credit with SunTrust Bank, as administrative agent and issuing lender, and the lenders named therein, which provides for a revolving credit facility of up to $500 million (subject to an applicable borrowing base). In connection with the May 1 borrowing base redetermination date, we elected to increase the borrowing base from $60 million to $100 million effective as of May 25, 2018. On September 14, 2018, a scheduled borrowing base redetermination was initiated and we expect such redetermination to be completed in early October. In the event that such redetermination results in an increase to our borrowing base amount, the Company may elect to accept the increase at that time. Since June 30, 2018, we borrowed an additional $9.5 million. As of September 19, 2018, we had $53.6 million of outstanding borrowings and additional $46.5 million available under our revolving credit facility and were in compliance with all applicable financial covenants.

The level of our indebtedness could affect our operations in several ways, including the following:

 

   

a significant portion of our cash flow could be used to service the indebtedness;

 

   

a high level of debt would increase our vulnerability to general adverse economic and industry conditions;

 

   

the covenants contained in our revolving credit facility limit our ability to borrow additional funds, dispose of assets, pay dividends and make certain investments; and

 

   

a high level of debt could impair our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions, general corporate, or other purposes.

Our revolving credit facility contains various covenants that limit our management’s discretion in the operation of our business and can lead to an event of default that may adversely affect our business, financial condition and results of operations.

The operating and financial restrictions and covenants in our revolving credit facility may adversely affect our ability to finance future operations or capital needs or to engage in other business activities. Our credit agreement contains a number of significant covenants, including restrictive covenants that may limit our ability to, among other things:

 

   

incur additional indebtedness or certain types of preferred equity;

 

   

incur liens;

 

   

merge or consolidate with another entity or acquire subsidiaries;

 

   

make investments, loans or certain payments;

 

   

sell assets, or enter into or terminate hedging transactions;

 

   

enter into transactions with affiliates;

 

   

enter into sale and leaseback transactions;

 

   

make certain amendments to our material documents or make significant accounting changes; and

 

   

engage in certain other transactions without the prior consent of the lenders.

Related restrictive covenants under our credit agreement are described under “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Our Revolving Credit Facility.” Various risks, uncertainties and events beyond our control could affect our ability to comply with the covenants required by the credit agreement.

 

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The restrictions in our credit agreement may also limit our ability to obtain future financings to withstand a future downturn in our business or the economy in general or to otherwise conduct necessary corporate activities. We may also be prevented from taking advantage of business opportunities that arise because of the limitations that the restrictive covenants under our credit agreement impose on us.

A breach of any covenant in our credit agreement would result in a default under the applicable agreement after any applicable grace periods. A default, if not waived, could result in acceleration of the indebtedness outstanding under our credit agreement and in a default with respect to, and an acceleration of, the indebtedness outstanding under other debt agreements. The accelerated indebtedness would become immediately due and payable. If that occurs, we may not be able to make all of the required payments or borrow sufficient funds to refinance such indebtedness. Even if new financing were available at that time, it may not be on terms that are acceptable to us.

Any significant reduction in our borrowing base under our revolving credit facility as a result of the periodic borrowing base redeterminations or otherwise may negatively impact our ability to fund our operations.

Our revolving credit facility limits the amounts we can borrow up to a borrowing base amount, which the lenders, in their sole discretion, determine in accordance with the terms of the agreement. The borrowing base depends on, among other things, projected revenues from, and asset values of, the proved oil and natural gas properties securing our loan. The value of our proved reserves is dependent upon, among other things, the prevailing and expected market prices of the underlying commodities in our estimated reserves. A further reduction or sustained decline in oil, natural gas and NGL prices could adversely affect our business, financial condition and results of operations, and our ability to meet our capital expenditure obligations and financial commitments. Reserve estimates depend on many assumptions that may turn out to be inaccurate. Any material inaccuracies in reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves. We could be forced to repay a portion of our bank borrowings or transfer to the bank collateral due to redeterminations of our borrowing base. If we are forced to do so, we may not have sufficient funds to make such repayments or provide such collateral. If we do not have sufficient funds and are otherwise unable to negotiate renewals of our borrowings, provide collateral or arrange new financing, we may have to sell significant assets. Any such sale could have a material adverse effect on our business and financial results.

In the future, we may not be able to access adequate funding under our revolving credit facility as a result of a decrease in borrowing base due to the issuance of new indebtedness, the outcome of a subsequent borrowing base redetermination or an unwillingness or inability on the part of lending counterparties to meet their funding obligations and the inability of other lenders to provide additional funding to cover the defaulting lender’s portion. Declines in commodity prices could result in a determination to lower the borrowing base in the future and, in such a case, we could be required to repay any indebtedness in excess of the redetermined borrowing base. As a result, we may be unable to implement our drilling and development plan, make acquisitions or otherwise carry out business plans, which would have a material adverse effect on our financial condition and results of operations and impair our ability to service our indebtedness.

We may not be able to generate sufficient cash to service all of our indebtedness and may be forced to take other actions to satisfy our obligations under our debt arrangements, which may not be successful.

Our ability to make scheduled payments on or to refinance our indebtedness obligations depends on our financial condition and operating performance, which are subject to prevailing economic and competitive conditions and certain financial, business and other factors beyond our control. If our cash flows and capital resources are insufficient to fund debt service obligations, we may be forced to reduce or delay investments and capital expenditures, sell assets, seek additional capital, or restructure or refinance indebtedness. Our ability to restructure or refinance indebtedness will depend on the condition of the capital markets and our financial condition at such time. Any refinancing of indebtedness could be at higher interest rates and may require us to comply with more onerous covenants, which could further restrict business operations. The terms of our existing

 

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revolving credit facility or future debt arrangements may restrict us from adopting some of these alternatives. In addition, any failure to make payments of interest and principal on outstanding indebtedness on a timely basis could harm our ability to incur additional indebtedness. In the absence of sufficient cash flows and capital resources, we could face substantial liquidity problems and might be required to dispose of material assets or operations to meet debt service and other obligations. Our revolving credit facility currently restricts our ability to dispose of assets and our use of the proceeds from such disposition. We may not be able to consummate those dispositions, and the proceeds of any such disposition may not be adequate to meet any debt service obligations then due. These alternative measures may not be successful and may not permit us to meet scheduled debt service obligations.

In addition, we will require significant additional capital over a prolonged period in order to pursue the development of these locations, and we may not be able to raise or generate the capital required to do so. Any drilling activities we are able to conduct on these potential locations may not be successful or result in our ability to add additional proved reserves to our overall proved reserves or may result in a downward revision of our estimated proved reserves, which could have a material adverse effect on our future business and results of operations.

Our derivative activities could result in financial losses or could reduce our earnings.

To achieve more predictable cash flows and reduce our exposure to adverse fluctuations in the prices of oil, natural gas, and NGLs, we enter or may enter into commodity derivative contracts for a significant portion of our production, primarily consisting of swaps, put options and call options. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Overview—Sources of Our Revenues.” Accordingly, our earnings may fluctuate significantly as a result of changes in fair value of our derivative instruments.

Derivative instruments also can expose us to the risk of financial loss in some circumstances, including when:

 

   

production is less than the volume covered by the derivative instruments;

 

   

the counterparty to the derivative instrument defaults on its contractual obligations;

 

   

there is an increase in the differential between the underlying price in the derivative instrument and actual prices received; or

 

   

there are issues with regard to legal enforceability of such instruments.

The use of derivatives may, in some cases, require the posting of cash collateral with counterparties. If we enter into derivative instruments that require cash collateral and commodity prices or interest rates change in a manner adverse to us, our cash otherwise available for use in our operations would be reduced, which could limit our ability to make future capital expenditures and make payments on our indebtedness, and which could also limit the size of our borrowing base. Future collateral requirements will depend on arrangements with our counterparties, highly volatile oil, natural gas, and NGL prices and interest rates. In addition, derivative arrangements could limit the benefit we would receive from increases in the prices for oil, natural gas, and NGLs, which could also have an adverse effect on our financial condition.

Our commodity derivative contracts expose us to risk of financial loss if a counterparty fails to perform under a contract. Disruptions in the financial markets could lead to sudden decreases in a counterparty’s liquidity, which could make them unable to perform under the terms of the contract and we may not be able to realize the benefit of the contract. We are unable to predict sudden changes in a counterparty’s creditworthiness or ability to perform. Even if we do accurately predict sudden changes, our ability to negate the risk may be limited depending upon market conditions.

 

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During periods of declining commodity prices, our derivative contract receivable positions could generally increase, which increases our counterparty credit exposure. If the creditworthiness of our counterparties deteriorates and results in their nonperformance, we could incur a significant loss with respect to our commodity derivative contracts.

Reserve estimates depend on many assumptions that may turn out to be inaccurate. Any material inaccuracies in 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 current and future economic conditions and commodity prices. Any significant inaccuracies in these interpretations or assumptions could materially affect the estimated quantities and present value of our reserves.

In order to prepare reserve estimates, we must project production rates and timing of development expenditures. We must also analyze available geological, geophysical, production and engineering data. The extent, quality and reliability of this data can vary. The process also requires economic assumptions about matters such as oil, natural gas and NGL prices, drilling and operating expenses, capital expenditures, taxes, and availability of funds.

Actual future production, oil, natural gas and NGL prices, revenues, taxes, development expenditures, operating expenses, and quantities of recoverable oil and natural gas reserves will vary from our estimates. Any significant variance could materially affect the estimated quantities and present value of our reserves. In addition, we may revise reserve estimates to reflect production history, results of exploration and development, existing commodity prices and other factors, many of which are beyond our control.

You should not assume that the present value of future net revenues from our reserves is the current market value of our estimated reserves. We generally base the estimated discounted future net cash flows from reserves on prices and costs on the date of the estimate. Actual future prices and costs may differ materially from those used in the present value estimate. For example, our estimated proved reserves as of September 30, 2017 were calculated under SEC rules using the unweighted arithmetic average first-day-of-the-month prices for the prior 12 months of $46.27 per Bbl for oil and NGL volumes and $3.00 per MMBtu for natural gas volumes, which for certain periods of 2016 were substantially above the available spot oil and natural gas prices. Using lower prices in estimating proved reserves would likely result in a reduction in proved reserve volumes due to economic limits.

There is a limited amount of production data from horizontal wells completed in the Permian Basin and its San Andres Formation. As a result, reserve estimates associated with horizontal wells in this area are subject to greater uncertainty than estimates associated with reserves attributable to vertical wells in the same area.

Reserve engineers rely in part on the production history of nearby wells in establishing reserve estimates for a particular well or field. Horizontal drilling in the San Andres Formation of the Permian Basin is a relatively recent development, whereas vertical drilling has been utilized by producers in this area for over 50 years. As a result, the amount of production data from horizontal wells available to reserve engineers is relatively small compared to that of production data from vertical wells. Until a greater number of horizontal wells have been completed in the San Andres Formation, and a longer production history from these wells has been established, there may be a greater variance in our proved reserves on a year-over-year basis due to the transition from vertical to horizontal reserves in both the proved developed and proved undeveloped categories. We cannot assure you that any such variance would not be material and any such variance could have a material and adverse impact on our cash flows and results of operations.

 

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Part of our strategy involves drilling using the latest available horizontal drilling and completion techniques, which involve risks and uncertainties in their application.

Our operations involve utilizing the latest drilling and completion techniques as developed by us and our service providers. As of June 30, 2018, we have drilled and completed 33 gross operated horizontal wells on our Champions Assets, and therefore are subject to increased risks associated with horizontal drilling as compared to companies that have greater experience in horizontal drilling activities. Risks that we face while drilling include, but are not limited to, failing to land our wellbore in the desired drilling zone, not staying in the desired drilling zone while drilling horizontally through the formation, not running our casing the entire length of the wellbore and not being able to run tools and other equipment consistently through the horizontal wellbore. Risks that we face while completing our wells include, but are not limited to, not being able to fracture stimulate the planned number of stages, not being able to run tools the entire length of the wellbore during completion operations and not successfully cleaning out the wellbore after completion of the final fracture stimulation stage.

Ultimately, the success of these drilling and completion techniques can only be evaluated over time as more wells are drilled and production profiles are established over a sufficient time period. If our drilling results are less than anticipated or we are unable to execute our drilling program because of capital constraints, lease expirations, access to gathering systems, and/or commodity prices decline, the return on our investment in these areas may not be as attractive as we anticipate. Further, as a result of any of these developments we could incur material write-downs of our oil and natural gas properties and the value of our undeveloped acreage could decline in the future.

Approximately 81% of our net leasehold acreage is undeveloped and that acreage may not ultimately be developed or become commercially productive, which could cause us to lose rights under our leases as well as have a material adverse effect on our oil and natural gas reserves and future production and, therefore, our future cash flow and income.

Oil and natural gas leases generally must be drilled before the end of the lease term or the leaseholder will lose the lease and any capital invested therein. In addition, leases may also be lost due to legal issues relating to the ownership of leases. Any delays in drilling or legal issues causing us to lose leases on properties could have a material adverse effect on our results of operations and reserve growth.

As of June 30, 2018, approximately 81% of our net leasehold acreage was undeveloped or acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas regardless of whether such acreage contains proved reserves. Unless production is established on the undeveloped acreage covered by our leases, such leases will expire. See “Business—Developed and Undeveloped Acreage” for more information about our undeveloped acreage subject to expiration over the next five year period. Our future oil and natural gas reserves and production and, therefore, our future cash flow and income are highly dependent on successfully developing our undeveloped leasehold acreage.

Our drilling plans are subject to change based upon various factors, including factors that are beyond our control. Such factors include drilling results, oil and natural gas prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, gathering system and pipeline transportation constraints, and regulatory approvals. If our leases expire, we will lose our right to develop such properties.

Substantially all of our producing properties are located in the Northwest Shelf within the Permian Basin of West Texas, making us vulnerable to risks associated with operating in one major geographic area. Specifically, as the Permian Basin is an area of high industry activity, we may be unable to hire, train, or retain qualified personnel needed to manage and operate our assets.

Substantially all of our producing properties are geographically concentrated in the Northwest Shelf sub-basin within the Permian Basin of West Texas, an area in which industry activity has increased rapidly. At

 

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September 30, 2017, all of our total estimated proved reserves were attributable to properties located in this area. As a result of this concentration, a number of our properties could experience any of the same conditions at the same time and, when compared to other companies that have a more diversified portfolio of properties, we may be disproportionately exposed to the impact of regional supply and demand factors, delays or interruptions of production from wells in this area caused by governmental regulation, processing or transportation capacity constraints, market limitations, water shortages or other drought or extreme weather related conditions or interruption of the processing or transportation of oil, natural gas or NGLs.

Specifically, demand for qualified personnel in this area, and the cost to attract and retain such personnel, may increase substantially in the future. Moreover, our competitors, including those operating in multiple basins, may be able to offer better compensation packages to attract and retain qualified personnel than we are able to offer. Any delay or inability to secure the personnel necessary for us to continue or complete our current and planned development activities could have a negative effect on production volumes or significantly increase costs, which could have a material adverse effect on our results of operations, liquidity and financial condition.

In addition, the geographic concentration of our assets including our total estimated proved reserves as of September 30, 2017, exposes us to additional risks, such as changes in field-wide rules and regulations that could cause us to permanently or temporarily shut-in all of our wells within a field.

Our drilling and production programs may not be able to obtain access on commercially reasonable terms or otherwise to truck transportation, pipelines, gas gathering, transmission, storage and processing facilities to market our oil and gas production, certain of which we do not control, and our initiatives to expand our access to midstream and operational infrastructure may be unsuccessful.

The marketing of oil and natural gas production depends in large part on the capacity and availability of pipelines and storage facilities, trucks, gas gathering systems and other transportation, processing and refining facilities. Access to such facilities is, in many respects, beyond our control. If these facilities are unavailable to us on commercially reasonable terms or otherwise, we could be forced to shut in some production or delay or discontinue drilling plans and commercial production following a discovery of hydrocarbons. We rely (and expect to rely in the future) on facilities developed and owned by third parties in order to store, process, transmit, and sell our oil and gas production. Our plans to develop and sell our oil and gas reserves, the expected results of our drilling program and our cash flow and results of operations could be materially and adversely affected by the inability or unwillingness of third parties to provide sufficient facilities and services to us on commercially reasonable terms or otherwise. The amount of oil and gas that can be produced is subject to limitation in certain circumstances, such as pipeline interruptions due to scheduled and unscheduled maintenance, excessive pressure, damage to the gathering, transportation, refining or processing facilities, or lack of capacity on such facilities. For example, increases in activity in the Permian Basin could contribute to bottlenecks in processing and transportation that may negatively affect our results of operations, and these adverse effects could be disproportionately severe to us compared to our more geographically diverse competitors.

Similarly, the concentration of our assets within a small number of producing formations exposes us to risks, such as changes in field-wide rules, which could adversely affect development activities or production relating to those formations. In addition, in areas where exploration and production activities are increasing, as has been the case in recent years in the Permian Basin, we are subject to increasing competition for drilling rigs, oilfield equipment, services, supplies and qualified personnel, which may lead to periodic shortages or delays. The curtailments arising from these and similar circumstances may last from a few days to several months, and in many cases, we may be provided only limited, if any, notice as to when these circumstances will arise and their duration.

While we have undertaken initiatives to expand our access to midstream and operational infrastructure, these initiatives may be delayed or unsuccessful. As a result, our business, financial condition, and results of operations could be adversely affected.

 

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The prices we receive for our production may be affected by local and regional factors.

The prices we receive for our production will be determined to a significant extent by factors affecting the local and regional supply of and demand for oil and natural gas, including the adequacy of the pipeline and processing infrastructure in the region to process and transport our production and that of other producers. Those factors result in basis differentials between the published indices generally used to establish the price received for regional oil and natural gas production and the actual price we receive for our production, which may be lower than index prices. If the price differentials pursuant to which our production is subject were to widen due to oversupply or other factors, our revenue could be negatively impacted.

An increase in the differential between NYMEX WTI and the reference or regional index price used to price our oil and gas would reduce our cash flows from operations.

Our oil and gas is priced in the local markets where it is produced based on local or regional supply and demand factors. The prices we receive for our oil and gas are typically lower than the relevant benchmark prices, such as NYMEX WTI. The difference between the benchmark price and the price we receive is called a differential. Numerous factors may influence local pricing, such as pipeline capacity and processing infrastructure. Additionally, insufficient pipeline or transportation capacity, lack of demand in any given operating area or other factors may cause the differential to increase in a particular area compared with other producing areas. For example, production increases from competing Permian Basin producers, combined with limited pipeline and transportation capacity in the area, have gradually widened differentials in the Permian Basin.

For the nine months ended June 30, 2018, our realized crude oil differential to NYMEX WTI averaged ($4.23) per bbl of oil and our realized natural gas differential to NYMEX Henry Hub averaged ($0.94) per Mcf of gas. Our realized crude oil differential to NYMEX WTI averaged ($14.82) per bbl of oil for the month ended August 31, 2018, and our realized natural gas differential to NYMEX Henry Hub averaged ($0.95) per Mcf of gas for the month ended July 31, 2018. Given that 100% of our production is from the Permian Basin, if the price differential in the Permian Basin continues to increase, we expect that the effect of our price differential on our revenues will also increase. Increases in the differential between the benchmark prices for oil and gas, such as the NYMEX WTI and NYMEX Henry Hub, and the realized price we receive could significantly reduce our revenues and our cash flow from operations.

Extreme weather conditions could adversely affect our ability to conduct drilling activities in the areas where we operate.

Our exploration, exploitation and development activities and equipment could be adversely affected by extreme weather conditions, such as floods, lightening, ice and other storms, and tornadoes, which may cause a loss of production from temporary cessation of activity or lost or damaged facilities and equipment. Such extreme weather conditions could also impact other areas of our operations, including access to our drilling and production facilities for routine operations, maintenance and repairs and the availability of, and our access to, necessary third-party services, such as electrical power, gathering, processing, compression and transportation services. These constraints and the resulting shortages or high costs could delay or temporarily halt our operations and materially increase our operation and capital costs, which could have a material adverse effect on our business, financial condition and results of operations.

Changes in the legal and regulatory environment governing the oil and natural gas industry could have a material adverse effect on our business.

Our business is subject to various forms of government regulation, including laws and regulations concerning the location, spacing and permitting of the oil and natural gas wells we drill, among other matters. Changes in the legal and regulatory environment governing our industry, could result in increased compliance costs and adversely affect our business, financial condition and results of operations.

 

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SEC rules could limit our ability to book additional proved undeveloped reserves in the future.

SEC rules require that, subject to limited exceptions, proved undeveloped reserves, or PUDs, may only be booked if they relate to wells scheduled to be drilled within five years after the date of booking. This requirement has limited and may continue to limit our ability to book additional PUDs as we pursue our drilling program. Moreover, we may be required to write down our PUDs if we do not drill or plan on delaying those wells within the required five-year timeframe.

The development of our estimated proved undeveloped reserves may take longer and may require higher levels of capital expenditures than we currently anticipate. Therefore, our estimated proved undeveloped reserves may not be ultimately developed or produced.

At September 30, 2017, approximately 41% of our total estimated proved reserves were classified as proved undeveloped. Our approximately 5,783 MBoe of estimated proved undeveloped reserves are estimated to require an estimated $41 million of development capital over the next five years. Our approximately 13,016 MBoe of estimated probable reserves are estimated to require $82 million of development capital over the next five years. Our approximately 13,049 MBoe of possible reserves are estimated to require $85 million of development capital over the next five years. Our development of these reserves may take longer and require higher levels of capital expenditures than we currently anticipate. The actual amount and timing of our future capital expenditures may differ materially from our estimates as a result of, among other things, oil, natural gas and NGL prices, actual drilling results, the availability of drilling rigs and other services and equipment, and regulatory, technological and competitive developments. We expect to fund our growth primarily through cash flow from operations, proceeds from this offering, availability under our revolving credit facility, and subsequent equity or debt offerings when appropriate. Delays in the development of our reserves, increases in costs to drill and develop such reserves, or decreases in commodity prices will reduce the PV-10 value of our estimated proved undeveloped reserves and future net revenues estimated for such reserves and may result in some projects becoming uneconomic. In addition, delays in the development of reserves could cause us to have to reclassify our proved undeveloped reserves as unproved reserves.

We participate in oil and gas leases with third parties who may not be able to fulfill their commitments to our projects.

We own less than 100% of the working interest in the oil and gas leases on which we conduct operations, and other parties will own the remaining portion of the working interest. Financial risks are inherent in any operation where the cost of drilling, equipping, completing and operating wells is shared by more than one person. We could be held liable for joint activity obligations of other working interest owners, such as nonpayment of costs and liabilities arising from the actions of other working interest owners. In addition, declines in oil, natural gas and NGL prices may increase the likelihood that some of these working interest owners, particularly those that are smaller and less established, are not able to fulfill their joint activity obligations. A partner may be unable or unwilling to pay its share of project costs, may be unable to access debt or equity financing, and, in some cases, may declare bankruptcy. In the event any of our project partners do not pay their share of such costs, we would likely have to pay those costs, and we may be unsuccessful in any efforts to recover these costs from our partners, which could materially adversely affect our financial position.

We own non-operating interests in properties developed and operated by third parties, and as a result, we are unable to control the operation and profitability of such properties.

We participate in the drilling and completion of wells with third-party operators that exercise exclusive control over such operations. As a participant, we rely on the third-party operators to successfully operate these properties pursuant to joint operating agreements and other similar contractual arrangements.

As a participant in these operations, we may not be able to maximize the value associated with these properties in the manner we believe appropriate, or at all. For example, we cannot control the success of drilling

 

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and development activities on properties operated by third parties, which depend on a number of factors under the control of a third-party operator, including such operator’s determinations with respect to, among other things, the nature and timing of drilling and operational activities, the timing and amount of capital expenditures and the selection of suitable technology. In addition, the third-party operator’s operational expertise and financial resources and its ability to gain the approval of other participants in drilling wells will impact the timing and potential success of drilling and development activities in a manner that we are unable to control. A third-party operator’s failure to adequately perform operations, breach of the applicable agreements or failure to act in ways that are favorable to us could reduce our production and revenues, negatively impact our liquidity and cause us to spend capital in excess of our current plans, and have a material adverse effect on our financial condition and results of operations.

If commodity prices decrease to a level such that our future undiscounted cash flows from our properties are less than their carrying value for a significant period of time, we will be required to take write-downs of the carrying values of our properties, which may negatively affect the trading price of our common stock.

Accounting rules require that we periodically review the carrying value of our properties for possible impairment. Based on specific market factors and circumstances at the time of prospective impairment reviews, and the continuing evaluation of development plans, production data, economics and other factors, we may be required to write down the carrying value of our properties. A write down constitutes a non-cash charge to earnings. If market or other economic conditions deteriorate or if oil, natural gas and NGL prices decline, we may incur impairment charges, which may have a material adverse effect on our results of operations. It is also possible that the cumulative effect of a write-down could negatively impact the trading price of our common stock.

Unless we replace our reserves with new reserves and develop those reserves, our reserves and production will decline, which would adversely affect our future cash flows and results of operations.

Producing oil and natural gas reservoirs generally are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Unless we conduct successful ongoing exploitation, development and exploration activities or continually acquire properties containing proved reserves, our proved reserves will decline as those reserves are produced. Our future reserves and production, and therefore our future cash flow and results of operations, are highly dependent on our success in efficiently developing and exploiting our current reserves and economically finding or acquiring additional recoverable reserves. We may not be able to develop, exploit, find or acquire sufficient additional reserves to replace our current and future production. If we are unable to replace our current and future production, the value of our reserves will decrease, and our business, financial condition and results of operations would be adversely affected.

Conservation measures and technological advances could reduce demand for oil, natural gas and NGLs.

Our industry is characterized by rapid and significant technological advancements and introductions of new products and services using new technologies. Fuel conservation measures, alternative fuel requirements, increasing consumer demand for alternatives to oil, natural gas and NGLs, technological advances in fuel economy and energy generation devices could reduce demand for oil, natural gas and NGLs. As competitors and others use or develop new technologies or technologies comparable to ours in the future, we may lose market share or be placed at a competitive disadvantage. Further, we may face competitive pressure to implement or acquire certain new technologies at a substantial cost. Some of our competitors may have greater financial, technical and personnel resources than we do, which may allow them to gain technological advantages or implement new technologies before we can. Additionally, we may be unable to implement new technologies or services at all, on a timely basis or at an acceptable cost. Limits on our ability to effectively use, implement or adapt to new technologies may have a material adverse effect on our business, financial condition and results of operations. Similarly, the impact of the changing demand for oil and gas services and products may have a material adverse effect on our business, financial condition, results of operations and cash flows.

 

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We depend upon several significant purchasers for the sale of most of our oil and natural gas production. The loss of one or more of these purchasers could, among other factors, limit our access to suitable markets for the oil, natural gas and NGLs we produce.

The availability of a ready market for any oil, natural gas and NGLs we produce depends on numerous factors beyond the control of our management, including but not limited to the extent of domestic production and imports of oil, the proximity and capacity of pipelines, the availability of skilled labor, materials and equipment, the effect of state and federal regulation of oil and natural gas production and federal regulation of oil and gas sold in interstate commerce. In addition, we depend upon several significant purchasers for the sale of most of our oil and natural gas production. See “Business—Operations—Marketing and Customers.” We cannot assure you that we will continue to have ready access to suitable markets for our future oil and natural gas production.

We have exposure to credit risk through receivables from purchasers of our oil, natural gas and NGL production. Two purchasers accounted for more than 10% of our revenues in the year ended September 30, 2017, and one purchaser accounted for more than 10% of our revenues during the year ended September 30, 2016. See “Business—Operations—Marketing and Customers.” This concentration of purchasers may impact our overall credit risk in that these entities may be similarly affected by changes in economic conditions or commodity price fluctuations. We do not require our customers to post collateral. The inability or failure of our significant purchasers to meet their obligations to us or their insolvency or liquidation may materially adversely affect our financial condition and results of operations.

We may incur substantial losses and be subject to substantial liability claims as a result of our operations. Additionally, we may not be insured for, or our insurance may be inadequate to protect us against, these risks.

Our operations are subject to inherent risks, some of which are beyond our control. We are not insured against all risks. Losses and liabilities arising from uninsured and underinsured events could materially and adversely affect our business, financial condition or results of operations.

Our exploration and production activities are subject to all of the operating risks associated with drilling for and producing oil and natural gas, including the risk of fire, explosions, blowouts, surface cratering or other cratering, uncontrollable flows of natural gas, oil, well fluids and formation water, pipe or pipeline failures, abnormally pressured formations, casing collapses, reservoir damage and environmental hazards such as oil spills, natural gas leaks, ruptures or discharges of toxic gases.

Any of these risks could adversely affect our ability to conduct operations or result in substantial loss to us as a result of claims for:

 

   

injury or loss of life;

 

   

employee/employer liabilities and risks, including wrongful termination, discrimination, labor organizing, retaliation claims, and general human resource related matters;

 

   

damage to and destruction of property, natural resources and equipment;

 

   

pollution and other environmental hazards or damage;

 

   

abnormally pressured formations, fires or explosions or natural disasters;

 

   

mechanical difficulties, such as stuck oil field drilling and service tools and casing collapse;

 

   

regulatory investigations and penalties;

 

   

suspension of our operations; and

 

   

repair and remediation costs.

We may elect not to obtain insurance for any or all of these risks if we believe that the cost of available insurance is excessive relative to the risks presented. Claims for loss of oil and natural gas production and

 

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damage to formations can occur in our industry. Litigation arising from a catastrophic occurrence at a location where our systems are deployed may result in our being named as a defendant in lawsuits asserting large claims.

Moreover, insurance may not be available in the future at commercially reasonable costs and on commercially reasonable terms. Also, pollution and environmental risks generally are not fully insurable. The occurrence of an event that is not covered or fully covered by insurance and any delay in the payment of insurance proceeds for covered events could have a material adverse effect on our business, financial condition and results of operations.

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

Our prospects are in various stages of evaluation, ranging from prospects that are currently being drilled, to prospects that will require substantial additional seismic data processing and interpretation. Properties that we decide to drill that do not yield oil, natural gas or NGLs in commercially viable quantities will adversely affect our results of operations and financial condition. 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 micro-seismic data and other technologies and the study of producing fields in the same area will not enable us to know conclusively prior to drilling whether oil or natural gas will be present or, if present, whether oil or natural gas will be present in commercial quantities. We cannot assure you that the analogies we draw from available data from other wells, more fully explored prospects or producing fields will be applicable to our drilling prospects. Further, our drilling operations may be curtailed, delayed or cancelled as a result of numerous factors, including:

 

   

unexpected drilling conditions;

 

   

title problems;

 

   

pressure or lost circulation in formations;

 

   

equipment failure or accidents;

 

   

adverse weather conditions;

 

   

compliance with environmental and other governmental or contractual requirements; and

 

   

increase in the cost of, shortages or delays in the availability of, electricity, supplies, materials, drilling or workover rigs, equipment and services.

We may be unable to make accretive acquisitions or successfully integrate acquired businesses or assets, and any inability to do so may disrupt our business and hinder our ability to grow.

In the future we may make acquisitions of oil and gas properties or businesses that complement or expand our current business. The successful acquisition of oil and gas properties requires an assessment of several factors, including:

 

   

recoverable reserves;

 

   

future oil, natural gas and NGL prices and their applicable differentials;

 

   

estimates of operating costs;

 

   

estimates future development costs;

 

   

estimates of the costs and timing of plugging and abandonment; and

 

   

potential environmental and other liabilities.

The accuracy of these assessments is inherently uncertain, and we may not be able to identify accretive acquisition opportunities. In connection with these assessments, we perform a review of the subject properties

 

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that we believe to be generally consistent with industry practices. Our review will not reveal all existing or potential problems nor will it permit us to become sufficiently familiar with the properties to assess fully their deficiencies and capabilities. Reviews may not always be performed on every well, and environmental problems, such as groundwater contamination, are not necessarily observable even when a review is performed. Even when problems are identified, the seller may be unwilling or unable to provide effective contractual protection against all or part of the problems. We often are not entitled to contractual indemnification for environmental liabilities and acquire properties on an “as is” basis. Even if we do identify accretive acquisition opportunities, we may not be able to complete the acquisition or do so on commercially acceptable terms.

The success of any completed acquisition will depend on our ability to integrate effectively the acquired business into our existing operations. The process of integrating acquired businesses may involve unforeseen difficulties and may require a disproportionate amount of our managerial and financial resources. In addition, possible future acquisitions may be larger and for purchase prices significantly higher than those paid for earlier acquisitions. No assurance can be given that we will be able to identify additional suitable acquisition opportunities, negotiate acceptable terms, obtain financing for acquisitions on acceptable terms or successfully acquire identified targets. Our failure to achieve consolidation savings, to integrate the acquired businesses and assets into our existing operations successfully or to minimize any unforeseen operational difficulties could have a material adverse effect on our financial condition and results of operations.

In addition, our revolving credit facility imposes certain limitations on our ability to enter into mergers or combination transactions as well as limits our ability to incur certain indebtedness, which could indirectly limit our ability to engage in acquisitions.

We may incur losses as a result of title defects in the properties in which we invest.

It is our practice in acquiring oil and natural gas leases or interests not to incur the expense of retaining lawyers to examine the title to the mineral interest at the time of acquisition. Rather, we rely upon the judgment of lease brokers or land men who perform the fieldwork in examining records in the appropriate governmental office before attempting to acquire a lease in a specific mineral interest. The existence of a material title deficiency can render a lease worthless and can adversely affect our results of operations and financial condition. While we do typically obtain title opinions prior to commencing drilling operations on a lease or in a unit, the failure of title may not be discovered until after a well is drilled, in which case we may lose the lease and the right to produce all or a portion of the minerals under the property.

Our operations could be impacted by burdens and encumbrances on title to our properties.

Our leasehold and other acreage may be subject to existing oil and natural gas leases, liens for current taxes and other burdens, including other mineral encumbrances and restrictions customary in the oil and natural gas industry. Such liens and burdens could materially interfere with the use or otherwise affect the value of such properties. Additionally, any cloud on the title of the working interests, leases and other rights owned by us could have a material adverse effect on our operations.

We are subject to stringent federal, state and local laws and regulations related to environmental and occupational health and safety issues that could adversely affect the cost, manner or feasibility of conducting our operations or expose us to significant liabilities.

Our operations are subject to stringent federal, state and local laws and regulations governing occupational safety and health aspects of our operations, the discharge of materials into the environment and environmental protection. These laws and regulations may impose numerous obligations applicable to our operations including (i) the acquisition of a permit before conducting drilling and other regulated activities; (ii) the restriction of types, quantities and concentration of materials that may be released into the environment; (iii) the limitation or prohibition of drilling activities on certain lands lying within wilderness, wetlands and other protected areas;

 

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(iv) the application of specific health and safety criteria addressing worker protection; (v) the imposition of substantial liabilities for pollution resulting from our operations; (vi) the installation of costly emission monitoring and/or pollution control equipment; and (vii) the reporting of the types and quantities of various substances that are generated, stored, processed, or released in connection with our properties. Numerous governmental authorities, such as the U.S. Environmental Protection Agency, or EPA, and analogous state agencies have the power to enforce compliance with these laws and regulations and the permits issued under them. Such enforcement actions often involve taking difficult and costly compliance measures or corrective actions. Failure to comply with these laws and regulations may result in the assessment of sanctions, including administrative, civil or criminal penalties, the imposition of investigatory or remedial obligations, and the issuance of orders limiting or prohibiting some or all of our operations. In addition, we may experience delays in obtaining or be unable to obtain required permits, which may delay or interrupt our operations or specific projects and limit our growth and revenue.

There is inherent risk of incurring significant environmental costs and liabilities in the performance of our operations due to our handling of petroleum hydrocarbons and other hazardous substances and wastes, as a result of air emissions and wastewater discharges related to our operations, and because of historical operations and waste disposal practices at our leased and owned properties. Spills or other releases of regulated substances, including such spills and releases that occur in the future, could expose us to material losses, expenditures and liabilities under applicable environmental laws and regulations. Under certain of such laws and regulations, we could be subject to strict, joint and several liability for the removal or remediation of previously released materials or property contamination, regardless of whether we were responsible for the release or contamination and even if our operations met previous standards in the industry at the time they were conducted. We may not be able to recover some or any of these costs from insurance. Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent or costly well drilling, construction, completion or water management activities, air emissions control or waste handling, storage, transport, disposal or cleanup requirements could require us to make significant expenditures to attain and maintain compliance and may otherwise have a material adverse effect on our results of operations, competitive position or financial condition. For example, on October 1, 2015, the EPA issued a final rule under the Clean Air Act, lowering the National Ambient Air Quality Standard, or NAAQS, for ground-level ozone from the current standard of 75 parts per billion, or ppb, for the current 8-hour primary and secondary ozone standards to 70 ppb for both standards. States are expected to implement more stringent requirements as a result of this new final rule, which could apply to our operations. Compliance with this more stringent standard and other environmental regulations could delay or prohibit our ability to obtain permits for operations or require us to install additional pollution control equipment, the costs of which could be significant. See “Business—Regulation of Environmental and Occupational Safety and Health Matters” for a further description of the laws and regulations that affect us.

We are subject to complex laws that can affect the cost, manner or feasibility of doing business.

Exploration, development, production and sale of oil and natural gas are subject to extensive federal, state, local and international regulation. We may be required to make large expenditures to comply with governmental regulations. Matters subject to regulation include:

 

   

discharge permits for drilling operations;

 

   

drilling bonds;

 

   

reports concerning operations;

 

   

the spacing of wells;

 

   

the rates of production;

 

   

the plugging and abandoning of wells;

 

   

unitization and pooling of properties; and

 

   

taxation.

 

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Under these laws, we could be liable for personal injuries, property damage and other damages. Failure to comply with these laws also may result in the suspension or termination of our operations and subject us to administrative, civil and criminal penalties. Moreover, these laws could change in ways that substantially increase our costs. Any such liabilities, penalties, suspensions, terminations or regulatory changes could materially adversely affect our financial condition and results of operations. See “Business—Regulation of the Oil and Gas Industry—Regulation of Production” and “—Regulation of the Oil and Gas Industry” for a further description of the laws and regulations that affect us.

The unavailability or high cost of additional drilling rigs, equipment, supplies, personnel and oilfield services could adversely affect our ability to execute our exploration and development plans within our budget and on a timely basis.

We are highly dependent upon third-party services. The cost of oilfield services typically fluctuates based on demand for those services. There is no assurance that we will be able to contract for such services on a timely basis or that the cost of such services will remain at a satisfactory or affordable level. The demand for qualified and experienced field personnel to drill wells and conduct field operations, geologists, geophysicists, engineers and other professionals in the oil and natural gas industry can fluctuate significantly, often in correlation with oil, natural gas and NGL prices, causing periodic shortages. Historically, there have been shortages of drilling and workover rigs, pipe and other equipment as demand for rigs and equipment has increased along with the number of wells being drilled. We cannot predict whether these conditions will exist in the future and, if so, what their timing and duration will be. Such shortages could delay or cause us to incur significant expenditures that are not provided for in our capital budget, which could have a material adverse effect on our business, financial condition or results of operations.

We are responsible for the decommissioning, abandonment, and reclamation costs for our facilities.

We are responsible for compliance with all applicable laws and regulations regarding the decommissioning, abandonment, and reclamation of our facilities at the end of their economic life, the costs of which may be substantial. It is not possible to predict these costs with certainty since they will be a function of regulatory requirements at the time of decommissioning, abandonment, and reclamation. We may, in the future, determine it prudent or be required by applicable laws or regulations to establish and fund one or more decommissioning, abandonment, and reclamation reserve funds to provide for payment of future decommissioning, abandonment, and reclamation costs, which could decrease funds available to service debt obligations. In addition, such reserves, if established, may not be sufficient to satisfy such future decommissioning, abandonment, and reclamation costs and we will be responsible for the payment of the balance of such costs.

Should we fail to comply with all applicable regulatory agency administered statutes, rules, regulations and orders, we could be subject to substantial penalties and fines.

Under the Energy Policy Act of 2005, the Federal Energy Regulatory Commission (“FERC”), has civil penalty authority under the Natural Gas Act of 1938 (the “NGA”), to impose penalties for current violations of up to $1 million/d for each violation. FERC may also impose administrative and criminal remedies and disgorgement of profits associated with any violation. While our operations have not been regulated by FERC as a natural gas company under the NGA, FERC has adopted regulations that may subject certain of our otherwise non-FERC jurisdictional facilities to FERC annual reporting requirements. We also must comply with the anti-market manipulation rules enforced by FERC. Additional rules and regulations pertaining to those and other matters may be considered or adopted by FERC from time to time. Additionally, the Federal Trade Commission (the “FTC”) has regulations intended to prohibit market manipulation in the petroleum industry with authority to fine violators of the regulations civil penalties of up to $1 million per day, and the Commodity Futures Trading Commission (the “CFTC”), prohibits market manipulation in the markets regulated by the CFTC, including similar anti-manipulation authority with respect to oil swaps and futures contracts as that granted to the CFTC with respect to oil purchases and sales. The CFTC rules subject violators to a civil penalty of up to the greater of

 

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$1 million or triple the monetary gain to the person for each violation. Failure to comply with those regulations in the future could subject us to civil penalty liability, as described in “Business—Regulation of the Oil and Gas Industry.”

A change in the jurisdictional characterization of our natural gas assets by federal, state or local regulatory agencies or a change in policy by those agencies may result in increased regulation of our natural gas assets, which may cause our revenues to decline and operating expenses to increase.

Section 1(b) of the NGA exempts natural gas gathering facilities from the jurisdiction of FERC. We believe that our natural gas gathering pipelines meet the traditional test that FERC has used to determine whether a pipeline is a gathering pipeline and is, therefore, not subject to FERC jurisdiction. The distinction between FERC-regulated transmission services and federally unregulated gathering services, however, has been the subject of substantial litigation, and FERC determines whether facilities are gathering facilities on a case-by-case basis, so the classification and regulation of our gathering facilities is subject to change based on future determinations by FERC, the courts or Congress. If FERC were to consider the status of an individual facility and determine that the facility or services provided by it are not exempt from FERC regulation under the NGA and that the facility provides interstate service, the rates for, and terms and conditions of, services provided by such facility would be subject to regulation by FERC under the NGA or the Natural Gas Policy Act (“NGPA”).

Such regulation could decrease revenue and increase operating costs. In addition, if any of our facilities were found to have provided services or otherwise operated in violation of the NGA or NGPA, this could result in the imposition of substantial civil penalties, as well as a requirement to disgorge revenues collected for such services in excess of the maximum rates established by FERC.

Our natural gas gathering pipelines are exempt from the jurisdiction of FERC under the NGA, but FERC regulation may indirectly impact gathering services. FERC’s policies and practices across the range of its oil and natural gas regulatory activities, including, for example, its policies on interstate open access transportation, ratemaking, capacity release, and market center promotion may indirectly affect intrastate markets. In recent years, FERC has pursued procompetitive policies in its regulation of interstate oil and natural gas pipelines. However, we cannot assure you that FERC will continue to pursue this approach as it considers matters such as pipeline rates and rules and policies that may indirectly affect the natural gas gathering services.

Natural gas gathering may receive greater regulatory scrutiny at the state level; therefore, our natural gas gathering operations could be adversely affected should they become subject to the application of state regulation of rates and services. State regulation of gathering facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory take requirements and complaint-based rate regulation. Our gathering operations could also be subject to safety and operational regulations relating to the design, construction, testing, operation, replacement and maintenance of gathering facilities.

We may be involved in legal proceedings that could result in substantial liabilities.

Like many oil and gas companies, we are from time to time involved in various legal and other proceedings, such as title, royalty or contractual disputes, regulatory compliance matters and personal injury or property damage matters, in the ordinary course of our business. Such legal proceedings are inherently uncertain and their results cannot be predicted. Regardless of the outcome, such proceedings could have an adverse impact on us because of legal costs, diversion of management and other personnel and other factors. In addition, it is possible that a resolution of one or more such proceedings could result in liability, penalties or sanctions, as well as judgments, consent decrees or orders requiring a change in our business practices, which could materially and adversely affect our business, operating results and financial condition. Accruals for such liability, penalties or sanctions may be insufficient. Judgments and estimates to determine accruals or range of losses related to legal and other proceedings could change from one period to the next, and such changes could be material.

 

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Federal, state and local legislative and regulatory initiatives relating to hydraulic fracturing as well as governmental reviews of such activities could result in increased costs and additional operating restrictions or delays in the completion of oil and natural gas wells and adversely affect our production.

Hydraulic fracturing is an important and common practice that is used to stimulate production of natural gas and/or oil from dense subsurface rock formations. We regularly use hydraulic fracturing as part of our operations. Hydraulic fracturing involves the injection of water, sand or alternative proppant and chemicals under pressure into targeted geological formations to fracture the surrounding rock and stimulate production. Hydraulic fracturing is typically regulated by state oil and natural gas commissions. However, several federal agencies have asserted regulatory authority over certain aspects of the process.

For example, in February 2014, the EPA asserted regulatory authority pursuant to the U.S. Safe Drinking Water Act’s (“SDWA”) Underground Injection Control (“UIC”) program over hydraulic fracturing activities involving the use of diesel and issued guidance covering such activities. Also, beginning in 2012, the EPA issued a series of regulations under the federal Clean Air Act (“CAA”) that include New Source Performance Standards (“NSPS”), known as Subpart OOOO, for completions of hydraulically fractured natural gas wells and certain other plants and equipment and, in May 2016, published a final rule establishing new emissions standards, known as Subpart OOOOa, for methane and volatile organic compounds (“VOCs”) from certain new, modified and reconstructed equipment and processes in the oil and natural gas source category. However, in April 2017, the EPA announced that it would review the May 2016 methane rule and on June 16, 2017, the EPA issued a proposed rule that would stay subpart OOOOa for two years, pending the reconsideration proceedings. The rule remains in effect in the meantime although the EPA continues to evaluate the rule and in September 2018 proposed additional amendments. Legal uncertainty exists with respect to the future implementation of the methane rule; however, these rules could require a number of modifications to our operations, including the installation of new equipment to control methane and VOC emissions from certain hydraulic fracturing wells, which could result in significant costs, including increased capital expenditures and operating costs, and could adversely impact or delay oil and natural gas production activities, which could have a material adverse effect on our business

The federal Bureau of Land Management (“BLM”) published a final rule in March 2015 that established new or more stringent standards relating to hydraulic fracturing on federal and American Indian lands. However, following years of litigation, the BLM rescinded the rule in December 2017. The BLM and the Secretary of the U.S. Department of the Interior are now being sued for the decision to rescind the rule; thus, the future of the rule remains uncertain. Also, in December 2016, the EPA released its final report on the potential impacts of hydraulic fracturing on drinking water resources, concluding that “water cycle” activities associated with hydraulic fracturing may impact drinking water resources under certain circumstances.

From time to time, legislation has been introduced in Congress to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the hydraulic fracturing process but, to date, such legislation has not been adopted. At the state level, Texas, where we conduct our operations, is among the states that has adopted regulations that impose new or more stringent permitting, including the requirement for hydraulic-fracturing operators to complete and submit a list of chemicals used during the fracking process. We may incur significant additional costs to comply with such existing state requirements and, in the event additional state level restrictions relating to the hydraulic-fracturing process are adopted in areas where we operate, we may become subject to additional permitting requirements and experience added delays or curtailment in the pursuit of exploration, development, or production activities.

Moreover, we typically dispose of flowback and produced water or certain other oilfield fluids gathered from oil and natural gas producing operations in underground disposal wells. This disposal process has been linked to increased induced seismicity events in certain areas of the country, particularly in Oklahoma, Texas, Colorado, Kansas, New Mexico and Arkansas. These and other states have begun to consider or adopt laws and regulations that may restrict or otherwise prohibit oilfield fluid disposal in certain areas or underground disposal wells, and state agencies implementing these requirements may issue orders directing certain wells where seismic

 

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incidents have occurred to restrict or suspend disposal well operations or impose standards related to disposal well construction and monitoring. For example, in 2014, the Railroad Commission of Texas (“TRRC”) published a final rule governing permitting or re-permitting of disposal wells that would require, among other things, the submission of information on seismic events occurring within a specified radius of the disposal well location, as well as logs, geologic cross sections and structure maps relating to the disposal area in question. If the permittee or an applicant of a disposal well permit fails to demonstrate that the injected fluids are confined to the disposal zone or if scientific data indicates such a disposal well is likely to be or determined to be contributing to seismic activity, then the TRRC may deny, modify, suspend or terminate the permit application or existing operating permit for that well. Any one or more of these developments may result in our having to limit disposal well volumes, disposal rates or locations, or to cease disposal well activities, which could have a material adverse effect on our business, financial condition, and results of operations.

Increased regulation and attention given to the hydraulic fracturing process and associated processes could lead to greater opposition to, and litigation concerning, oil and natural gas production activities using hydraulic fracturing techniques. Additional legislation or regulation could also lead to operational delays or increased operating costs in the production of oil and natural gas, including from developing shale plays, or could make it more difficult to perform hydraulic fracturing. The adoption of any federal, state or local laws or the implementation of regulations regarding hydraulic fracturing could potentially cause a decrease in the completion of new oil and natural gas wells and an associated increase in compliance costs and time, which could have a material adverse effect on our liquidity, results of operations, and financial condition.

Limitation or restrictions on our ability to obtain water may have an adverse effect on our operating results.

Water is an essential component of shale oil and natural gas development during both the drilling and hydraulic fracturing processes. Our access to water to be used in these processes may be adversely affected due to reasons such as periods of extended drought, private, third party competition for water in localized areas or the implementation of local or state governmental programs to monitor or restrict the beneficial use of water subject to their jurisdiction for hydraulic fracturing to assure adequate local water supplies. In addition, treatment and disposal of water is becoming more highly regulated and restricted. Thus, our costs for obtaining and disposing of water could increase significantly. Our inability to locate or contractually acquire and sustain the receipt of sufficient amounts of water could adversely impact our exploration and production operations and have a corresponding adverse effect on our business, results of operations and financial condition.

Climate change legislation and regulations restricting or regulating emissions of greenhouse gases could result in increased operating costs and reduced demand for the oil, natural gas and NGLs that we produce while potential physical effects of climate change could disrupt our production and cause us to incur significant costs in preparing for or responding to those effects.

Climate change continues to attract considerable public and scientific attention. As a result, numerous proposals have been made and are likely to continue to be made at the international, national, regional, and state levels of government to monitor and limit emissions of greenhouse gases (“GHGs”). While no comprehensive climate change legislation has been implemented at the federal level, the EPA and states or groupings of states have pursued legal initiatives in recent years that seek to reduce GHG emissions through efforts that include consideration of cap-and-trade programs, carbon taxes, GHG reporting and tracking programs and regulations that directly limit GHG emissions from certain sources. In particular, the EPA has adopted rules under authority of the CAA that, among other things, establish certain permit reviews for GHG emissions from certain large stationary sources, which reviews could require securing permits at covered facilities emitting GHGs and meeting defined technological standards for those GHG emissions. The EPA has also adopted rules requiring the monitoring and annual reporting of GHG emissions from certain petroleum and natural gas system sources in the United States, including, among others, onshore production.

Federal agencies also have begun directly regulating emissions of methane, a GHG, from oil and natural gas operations. In June 2016, the EPA published a final rule establishing NSPS Subpart OOOOa, that requires certain

 

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new, modified or reconstructed facilities in the oil and natural gas sector to reduce these methane gas and VOC emissions. However, in April 2017, the EPA announced that it would review this 2016 methane rule and would initiate reconsideration proceedings to potentially revise or rescind portions of the rule. Subsequently, effective June 2, 2017, the EPA issued a 90-day stay of certain requirements under the methane rule, but this stay was vacated by a three-judge panel of the U.S. Court of Appeals for the D.C. Circuit on July 3, 2017 and on August 10, 2017, the D.C. Circuit rejected petitions for an en banc review of its July 3, 2017 ruling. In the interim, on July 16, 2017, the EPA issued a proposed rule that would stay subpart OOOOa for two years, but this proposed rule is not yet final and may be subject to legal challenges. In the meantime the rule remains in effect, but the EPA continues to evaluate the rule and proposed additional amendments on September 11, 2018. The BLM also finalized rules regarding the control of methane emissions in November 2016 that apply to oil and natural gas exploration and development activities on public and tribal lands. The rules seek to minimize venting and flaring of emissions from storage tanks and other equipment, and also impose leak detection and repair requirements. The U.S. Department of the Interior attempted to suspend this rule, however on February 22, 2018, a U.S. District Court blocked the suspension. The rule remains in place at this time, but the future status of the rule is unclear. Additionally, in December 2015, the United States joined the international community at the 21st Conference of the Parties of the United Nations Framework Convention on Climate Change in Paris, France that prepared an agreement requiring member countries to review and “represent a progression” in their intended nationally determined contributions, which set GHG emission reduction goals every five years beginning in 2020. This “Paris Agreement” was signed by the United States in April 2016 and entered into force in November 2016; however, this agreement does not create any binding obligations for nations to limit their GHG emissions. On June 1, 2017, President Trump announced that the United States plans to withdraw from the Paris Agreement and to seek negotiations either to re-enter the Paris Agreement on different terms or to establish a new framework agreement. The Paris Agreement provides for a four-year exit date of November 2020. The United States’ adherence to the exit process and/or the terms on which the United States may re-enter the Paris Agreement or a separately negotiated agreement are unclear at this time.

The adoption and implementation of any international, federal or state legislation or regulations that require reporting of GHGs or otherwise restrict emissions of GHGs could result in increased compliance costs or additional operating restrictions, and could have a material adverse effect on our business, financial condition, results of operations, and cash flows.

Finally, increasing concentrations of GHG in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, floods and other climatic events. If any such climatic events were to occur, they could have an adverse effect on our financial condition and results of operations and the financial condition and operations of our customers.

Competition in the oil and natural gas industry is intense, making it more difficult for us to acquire properties and market oil or natural gas.

Our ability to acquire additional prospects and to find and develop reserves in the future will depend on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment for acquiring properties, marketing oil and natural gas and securing trained personnel. Also, there is substantial competition for capital available for investment in the oil and natural gas industry. We may not be able to compete successfully in the future in acquiring prospective reserves, developing reserves, marketing hydrocarbons, and raising additional capital, which could have a material adverse effect on our business.

Our undeveloped acreage must be drilled before lease expirations to hold the acreage by production. In highly competitive markets for acreage, failure to drill sufficient wells to hold acreage could result in a substantial lease renewal cost or, if renewal is not feasible, loss of our lease and prospective drilling opportunities.

Unless production is established within the spacing units covering the undeveloped acres on which some of our drilling locations are identified, our leases for such acreage will expire. As of June 30, 2018, 32% of our net

 

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undeveloped acreage was set to expire in fiscal year 2019. We intend to extend or renew every material lease that is set to expire in fiscal year 2019 to the extent possible and expect to incur $3.0 million to extend or renew every material lease that is set to expire in fiscal year 2019, without taking into account the drilling of PUDs and holding leases by production. Where we do not have the option to extend a lease, however, we may not be successful in negotiating extensions or renewals. See “Business— Developed and Undeveloped Acreage” for more information about our undeveloped acreage subject to expiration over the next five year period. Our ability to drill and develop our acreage and establish production to maintain our leases depends on a number of uncertainties, including oil, natural gas and NGL prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, drilling results, lease expirations, gathering system and pipeline transportation constraints, access to and availability of water sourcing and distribution systems, regulatory approvals and other factors. The cost to renew such leases may increase significantly, and we may not be able to renew such leases on commercially reasonable terms or at all. As such, our actual drilling activities may differ materially from our current expectations, which could adversely affect our business. These risks are greater at times and in areas where the pace of our exploration and development activity slows.

Declining general economic, business or industry conditions may have a material adverse effect on our results of operations, liquidity and financial condition.

Concerns over global economic conditions, energy costs, geopolitical issues, inflation, the availability and cost of credit and the United States financial market have contributed to increased economic uncertainty and diminished expectations for the global economy. In addition, continued hostilities in the Middle East and the occurrence or threat of terrorist attacks in the United States or other countries could adversely affect the global economy. These factors, combined with volatile commodity prices, declining business and consumer confidence and increased unemployment, have precipitated an economic slowdown and a recession. Concerns about global economic growth have had a significant adverse impact on global financial markets and commodity prices. If the economic climate in the United States or abroad deteriorates, worldwide demand for petroleum products could diminish, which could impact the price at which we can sell our production, affect the ability of our vendors, suppliers and customers to continue operations and ultimately adversely impact our results of operations, liquidity and financial condition.

Our business and operations could be adversely affected if we lose key personnel.

We depend to a large extent on the services of our officers, including Bobby Riley, our Chief Executive Officer, Kevin Riley, our Chief Operating Officer, Jeffrey Gutman, our Chief Financial Officer, and James J. Doherty, our EVP of Engineering. These individuals have extensive experience and expertise in evaluating and analyzing producing oil and natural gas properties and drilling prospects, maximizing production from oil and natural gas properties and developing and executing financing strategies. The loss of any of these individuals could have a material adverse effect on our operations. We do not maintain key-man life insurance with respect to any management personnel. Our success will be dependent on our ability to continue to retain and utilize skilled technical personnel. The loss of the services of our senior management or technical personnel could have a material adverse effect on our business, financial condition and results of operations.

We are susceptible to the potential difficulties associated with rapid growth and expansion and have a limited operating history.

We have grown rapidly since we began operations in June 2016. Our management believes that our future success depends on our ability to manage the rapid growth that we have experienced and the demands from increased responsibility on management personnel. The following factors could present difficulties:

 

   

increased responsibilities for our executive level personnel;

 

   

increased administrative burden;

 

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increased capital requirements; and

 

   

increased organizational challenges common to large, expansive operations.

Our operating results could be adversely affected if we do not successfully manage these potential difficulties. The historical financial information incorporated herein is not necessarily indicative of the results that may be realized in the future. In addition, our operating history is limited and the results from our current producing wells are not necessarily indicative of success from our future drilling operations.

Increases in interest rates could adversely affect our business.

Our business and operating results can be harmed by factors such as the availability, terms and cost of capital, increases in interest rates or a reduction in credit rating. These changes could cause our cost of doing business to increase, limit our ability to pursue acquisition opportunities, reduce cash flow used for drilling, and place us at a competitive disadvantage. Potential disruptions and volatility in the global financial markets may lead to a contraction in credit availability impacting our ability to finance our operations. We require continued access to capital. A significant reduction in cash flows from operations or the availability of credit could materially and adversely affect our ability to achieve our planned growth and operating results.

Our use of 2-D and 3-D seismic data is subject to interpretation and may not accurately identify the presence of oil and natural gas, which could adversely affect the results of our drilling operations.

Even when properly used and interpreted, 2-D and 3-D seismic data and visualization techniques are only tools used to assist geoscientists in identifying subsurface structures and hydrocarbon indicators and do not enable the interpreter to know whether hydrocarbons are, in fact, present in those structures. In addition, the use of 3-D seismic and other advanced technologies requires greater predrilling expenditures than traditional drilling strategies, and we could incur losses as a result of such expenditures. As a result, our drilling activities may not be successful or economical.

Restrictions on drilling activities intended to protect certain species of wildlife may adversely affect our ability to conduct drilling activities in areas where we operate.

Oil and natural gas operations in our operating areas may be adversely affected by seasonal or permanent restrictions on drilling activities designed to protect various wildlife. Seasonal restrictions may limit our ability to operate in protected areas and can intensify competition for drilling rigs, oilfield equipment, services, supplies and qualified personnel, which may lead to periodic shortages when drilling is allowed. These constraints and the resulting shortages or high costs could delay our operations or materially increase our operating and capital costs. Permanent restrictions imposed to protect endangered species could prohibit drilling in certain areas or require the implementation of expensive mitigation measures. The designation of previously unprotected species in areas where we operate as threatened or endangered could cause us to incur increased costs arising from species protection measures or could result in limitations on our exploration and production activities that could have a material adverse impact on our ability to develop and produce our reserves.

The enactment of derivatives legislation could have an adverse effect on our ability to use derivative instruments to reduce the effect of commodity price, interest rate and other risks associated with our business.

The Dodd-Frank Act, enacted on July 21, 2010, established federal oversight and regulation of the over-the-counter derivatives market and of entities, such as us, that participate in that market. The Dodd-Frank Act requires the CFTC and the SEC to promulgate rules and regulations implementing the Dodd-Frank Act. In December 2016, the CFTC re-proposed regulations implementing limits on positions in certain core futures and equivalent swaps contracts for or linked to certain physical commodities, subject to exceptions for certain bona fide hedging transactions. The Dodd- Frank Act and CFTC rules also will require us, in connection with certain

 

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derivatives activities, to comply with clearing and trade-execution requirements (or to take steps to qualify for an exemption to such requirements). In addition, the CFTC and certain banking regulators have adopted final rules establishing minimum margin requirements for uncleared swaps. Although we expect to qualify for the end-user exception to the mandatory clearing, trade-execution and margin requirements for swaps entered to hedge our commercial risks, the application of such requirements to other market participants, such as swap dealers, may change the cost and availability of the swaps that we use for hedging. In addition, if any of our swaps do not qualify for the commercial end-user exception, posting of collateral could impact liquidity and reduce cash available to us for capital expenditures, therefore reducing our ability to execute hedges to reduce risk and protect cash flow. It is not possible at this time to predict with certainty the full effects of the Dodd-Frank Act and CFTC rules on us or the timing of such effects. The Dodd-Frank Act and any new regulations could significantly increase the cost of derivative contracts, materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks we encounter, and reduce our ability to monetize or restructure our existing derivative contracts. If we reduce our use of derivatives as a result of the Dodd-Frank Act and CFTC rules, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures. Finally, the Dodd-Frank Act was intended, in part, to reduce the volatility of oil, natural gas and NGL prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil, natural gas and NGLs. Our revenues could therefore be adversely affected if a consequence of the Dodd-Frank Act and CFTC rules is to lower commodity prices. Any of these consequences could have a material and adverse effect on us, our financial condition or our results of operations.

Certain U.S. federal income tax deductions currently available with respect to our business may be eliminated or significantly changed as a result of recently enacted and future legislation. Future federal, state or local legislation also may impose new or increased taxes or fees on oil and natural gas extraction.

On December 22, 2017, President Trump signed into law the Tax Cuts and Jobs Act (the “TCJA”). The TCJA will make significant changes to U.S. federal income tax laws. While past legislative proposals have included changes to certain key U.S. federal income tax provisions currently available to oil and gas companies including (i) the repeal of the percentage depletion allowance for oil and gas properties, (ii) the elimination of current deductions for intangible drilling and development costs, and (iii) an extension of the amortization period for certain geological and geophysical expenditures, these specific changes are not included in the TCJA. No accurate prediction can be made as to whether any such legislative changes will be proposed or enacted in the future or, if enacted, what the specific provisions or the effective date of any such legislation would be. However, the TCJA (i) eliminates the deduction for certain domestic production activities, (ii) imposes new limitations on the utilization of net operating losses, and (iii) provides for more general changes to the taxation of corporations, including changes to cost recovery rules and to the deductibility of interest expense, which may impact the taxation of oil and gas companies. This legislation or any future changes in U.S. federal income tax laws, as well as any similar changes in state law, could eliminate or postpone certain tax deductions that currently are available with respect to oil and gas development, or increase costs, and any such changes could have an adverse effect on our financial position, results of operations, and cash flows.

The TCJA also reduces the general tax rate on U.S. corporations, which could positively affect our financial position, results of operations, or cash flows. The impact of the TCJA on holders of our common stock is also uncertain and could be adverse. This prospectus does not discuss any such tax legislation or the manner in which it might affect purchasers of our common stock. We urge our stockholders, including purchasers of common stock in this offering, to consult with their legal and tax advisors with respect to such legislation and the potential tax consequences of investing in our common stock.

Additionally, future legislation could be enacted that increases the taxes or fees imposed on oil and natural gas extraction. Any such legislation could result in increased operating costs and/or reduced consumer demand for petroleum products, which in turn could affect the prices we receive for our oil, natural gas or NGLs.

 

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Our business could be negatively affected by security threats, including cybersecurity threats, and other disruptions.

The oil and natural gas industry has become increasingly dependent on digital technologies to conduct day-to-day operations. For example, the industry depends on digital technologies to interpret seismic data, manage drilling rigs, production equipment and gathering systems, conduct reservoir modeling and reserves estimation, and process and record financial and operating data. At the same time, cyber incidents, including deliberate attacks or unintentional events, have increased. As an oil and natural gas producer, our technologies, systems, networks, and those of our business partners, may become the target of cyberattacks or information security breaches that could result in the unauthorized release, misuse, loss or destruction of proprietary and other information, or other disruption of business operations that could lead to disruptions in critical systems, unauthorized release of confidential or otherwise protected information, and corruption of data. We face various security threats, including cybersecurity threats to gain unauthorized access to sensitive information or to render data or systems unusable; threats to the security of our facilities and infrastructure or third party facilities and infrastructure, such as processing plants and pipelines; and threats from terrorist acts. The potential for such security threats has subjected our operations to increased risks that could have a material adverse effect on our business. In particular, our implementation of various procedures and controls to monitor and mitigate security threats and to increase security for our information, facilities and infrastructure may result in increased capital and operating costs. Moreover, there can be no assurance that such procedures and controls will be sufficient to prevent security breaches from occurring. If any of these security breaches were to occur, they could lead to losses of sensitive information, critical infrastructure or capabilities essential to our operations and could have a material adverse effect on our reputation, financial position, results of operations or cash flows. Cybersecurity attacks in particular are becoming more sophisticated and include, but are not limited to, malicious software, attempts to gain unauthorized access to data and systems, and other electronic security breaches that could lead to disruptions in critical systems, unauthorized release of confidential or otherwise protected information, and corruption of data. These events could lead to financial losses from remedial actions, loss of business or potential liability.

Loss of our information and computer systems could adversely affect our business.

We are dependent on our information systems and computer-based programs, including our well operations information, seismic data, electronic data processing and accounting data. If any of such programs or systems were to fail or create erroneous information in our hardware or software network infrastructure, possible consequences include our loss of communication links, inability to find, produce, process and sell oil and natural gas and inability to automatically process commercial transactions or engage in similar automated or computerized business activities. Any such consequence could have a material adverse effect on our business.

We may not be able to keep pace with technological developments in our industry.

The oil and natural gas industry is characterized by rapid and significant technological advancements and introductions of new products and services using new technologies. As others use or develop new technologies, we may be placed at a competitive disadvantage or may be forced by competitive pressures to implement those new technologies at substantial costs. In addition, other oil and natural gas companies may have greater financial, technical and personnel resources that allow them to enjoy technological advantages and that may in the future allow them to implement new technologies before we can. We may not be able to respond to these competitive pressures or implement new technologies on a timely basis or at an acceptable cost. If one or more of the technologies we use now or in the future were to become obsolete, our business, financial condition or results of operations could be materially and adversely affected.

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

Negative public perception regarding us and/or our industry resulting from, among other things, concerns raised by advocacy groups about hydraulic fracturing, oil spills, seismic activity and explosions of natural gas

 

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transmission lines may lead to increased regulatory scrutiny, which may, in turn, lead to new state and federal safety and environmental laws, regulations, guidelines and enforcement interpretations. These actions may cause operational delays or restrictions, increased operating costs, additional regulatory burdens and increased risk of litigation. Moreover, governmental authorities exercise considerable discretion in the timing and scope of permit issuance and the public may engage in the permitting process, including through intervention in the courts. Negative public perception could cause the permits we need to conduct our operations to be withheld, delayed, or burdened by requirements that restrict our ability to profitably conduct our business.

Anti-indemnity provisions enacted by many states may restrict or prohibit a party’s indemnification of us.

We typically enter into agreements with our customers governing the use and operation of our systems, which usually include certain indemnification provisions for losses resulting from operations. Such agreements may require each party to indemnify the other against certain claims regardless of the negligence or other fault of the indemnified party; however, many states place limitations on contractual indemnity agreements, particularly agreements that indemnify a party against the consequences of its own negligence. Furthermore, certain states, including Louisiana, New Mexico, Texas and Wyoming have enacted statutes generally referred to as “oilfield anti-indemnity acts” expressly prohibiting certain indemnity agreements contained in or related to oilfield services agreements. Such anti-indemnity acts may restrict or void a party’s indemnification of us, which could have a material adverse effect on our business, financial condition, prospects and results of operations.

Risks Related to this Offering and our Common Stock

The requirements of being a public company, including compliance with the reporting requirements of the Exchange Act and the requirements of the Sarbanes-Oxley Act, may strain our resources, increase our costs and distract management, and we may be unable to comply with these requirements in a timely or cost-effective manner.

As a public company, we will need to comply with new laws, regulations and requirements, certain corporate governance provisions of the Sarbanes-Oxley Act, related regulations of the SEC and the requirements of the NYSE American, with which we are not required to comply as a private company. Complying with these statutes, regulations and requirements will occupy a significant amount of time of our board of directors and management and will significantly increase our costs and expenses. We will need to:

 

   

institute a more comprehensive compliance function;

 

   

comply with rules promulgated by the NYSE American;

 

   

continue to prepare and distribute periodic public reports in compliance with our obligations under the federal securities laws;

 

   

establish new internal policies, such as those relating to insider trading; and

 

   

involve and retain to a greater degree outside counsel and accountants in the above activities.

Furthermore, while we generally must comply with Section 404 of the Sarbanes Oxley Act after this offering, we are not required to have our independent registered public accounting firm attest to the effectiveness of our internal controls 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. Accordingly, we may not be required to have our independent registered public accounting firm attest to the effectiveness of our internal controls until as late as our annual report for the fiscal year ending September 30, 2023. See “—For as long as we are an emerging growth company, we will not be required to comply with certain reporting requirements, including those relating to accounting standards and disclosure about our executive compensation, that apply to other public companies” for a discussion of those requirements.

Once it is required to do so, our independent registered public accounting firm may issue a report that is adverse in the event it is not satisfied with the level at which our controls are documented, designed, operated or reviewed.

 

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Any failure to develop or maintain effective internal controls, or difficulties encountered in implementing or improving our internal controls, could harm our operating results or cause us to fail to meet our reporting obligations. Moreover, if we are not able to comply with the requirements of Section 404 in a timely manner, or if in the future we or our independent registered public accounting firm identifies deficiencies in our internal controls over financial reporting that are deemed to be material weaknesses, the market price of our stock could decline, and we could be subject to sanctions or investigations by the SEC or other regulatory authorities, which would require additional financial and management resources.

In addition, we expect that being a public company subject to these rules and regulations may make it more difficult and more expensive for us to obtain director and officer liability insurance and we may be required to accept reduced policy limits and coverage or incur substantially higher costs to obtain the same or similar coverage. As a result, it may be more difficult for us to attract and retain qualified individuals to serve on our board of directors or as executive officers. We are currently evaluating these rules, and we cannot predict or estimate the amount of additional costs we may incur or the timing of such costs.

The initial public offering price of our common stock may not be indicative of the market price of our common stock after this offering. In addition, an active, liquid and orderly trading market for our common stock may not develop or be maintained, and our stock price may be volatile.

Prior to this offering, our common stock was not traded on any market. An active, liquid and orderly trading market for our common stock may not develop or be maintained after this offering. Active, liquid and orderly trading markets usually result in less price volatility and more efficiency in carrying out investors’ purchase and sale orders. The market price of our common stock could vary significantly as a result of a number of factors, many of which are beyond our control. In the event of a drop in the market price of our common stock, you could lose a substantial part or all of your investment in our common stock. The initial public offering price was determined by negotiations between us and representatives of the underwriters, based on numerous factors which we discuss in “Underwriting (Conflicts of Interest),” and may not be indicative of the market price of our common stock after this offering. Consequently, you may not be able to sell shares of our common stock at prices equal to or greater than the price paid by you in this offering. For example, if our financial results are below the expectations of securities analysis and investors, the market prices of our common stock could decrease, perhaps significantly.

Other factors that could affect our stock price include:

 

   

our operating and financial performance and drilling locations, including reserve estimates;

 

   

actual or anticipated fluctuations in our quarterly results of operations, and financial indicators, such as net income, cash flow and revenues;

 

   

our failure to meet revenue, reserves or earnings estimates by research analysts or other investors;

 

   

sales of our common stock by us or other shareholders, or the perception that such sales may occur;

 

   

the public reaction to our press releases, our other public announcements and our filings with the SEC;

 

   

strategic actions by our competitors or competition for, among other things, capital, acquisition of reserves, undeveloped land and skilled personnel;

 

   

publication of research reports about us or the oil and natural gas exploration and production industry generally;

 

   

changes in revenue or earnings estimates, or changes in recommendations or withdrawal of research coverage, by equity research analysts;

 

   

speculation in the press or investment community;

 

   

the failure of research analysts to cover our common stock;

 

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increases in market interest rates or funding rates, which may increase our cost of capital;

 

   

changes in market valuations of similar companies to us;

 

   

changes in accounting principles, policies, guidance, interpretations or standards;

 

   

additions or departures of key management personnel;

 

   

actions by our shareholders;

 

   

commencement or involvement in litigation;

 

   

general market conditions, including fluctuations in commodity prices;

 

   

political conditions in oil and gas producing regions;

 

   

domestic and international economic, legal and regulatory factors unrelated to our performance; and

 

   

the realization of any risks describes under this “Risk Factors” section.

The stock markets in general have experienced significant price and volume fluctuations. These fluctuations that has often been unrelated to the operating performance of particular companies. These broad market fluctuations may adversely affect the trading price of our common stock. Any volatility or a significant decrease in the market price of our common stock could also negatively affect our ability to make acquisitions using our common stock. Securities class action litigation also has often been instituted against companies following periods of volatility in the overall market and in the market price of a company’s securities. Such litigation, if instituted against us, could result in very substantial costs, divert our management’s attention and resources and harm our business, operating results and financial condition.

For as long as we are an emerging growth company, we will not be required to comply with certain reporting requirements, including those relating to accounting standards and disclosure about our executive compensation, that apply to other public companies.

We are classified as an “emerging growth company” under the JOBS Act. For as long as we are an emerging growth company, which may be up to five full fiscal years, unlike other public companies, we will not be required to, among other things, (1) provide an auditor’s attestation report on management’s assessment of the effectiveness of our system of internal control over financial reporting pursuant to Section 404(b) of the Sarbanes-Oxley Act, (2) comply with any new requirements adopted by the PCAOB requiring mandatory audit firm rotation or a supplement to the auditor’s report in which the auditor would be required to provide additional information about the audit and the financial statements of the issuer, (3) provide certain disclosure regarding executive compensation required of larger public companies or (4) hold nonbinding advisory votes on executive compensation. We will remain an emerging growth company for up to five years, although we will lose that status sooner if we have more than $1.07 billion of revenues in a fiscal year, have more than $700 million in market value of our common stock held by non-affiliates, or issue more than $1.0 billion of non-convertible debt over a three-year period.

Under the JOBS Act, emerging growth companies can delay adopting new or revised accounting standards until such time as those standards apply to private companies. We have elected to rely on the extended transition period for complying with new or revised accounting standards that have different effective dates for public and private companies until the earlier of (i) the date we are no longer an emerging growth company or (ii) affirmatively and irrevocably opt out of the extended transition period.

Furthermore, under Section 404 of the Sarbanes Oxley Act of 2002 we are not required to have our independent registered public accounting firm attest to the effectiveness of our internal controls 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.

 

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To the extent that we rely on any of the exemptions available to emerging growth companies, you will receive less information about our executive compensation and internal control over financial reporting than issuers that are not emerging growth companies. If some investors find our common stock to be 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.

Although under the Sarbanes-Oxley Act we are not required to perform an evaluation of the effectiveness of our internal control over financial reporting, we have identified several material weaknesses in our internal control over financial reporting and may identify additional material weaknesses in the future, or otherwise fail to maintain an effective system of internal controls, which could result in a restatement of our financial statements or cause us to fail to meet our reporting obligations.

Prior to this offering, we were a private company with limited accounting personnel and other resources with which to address our internal controls and procedures. We have not completed an assessment of the effectiveness of our internal control over financial reporting, and as an emerging growth company, our independent registered public accounting firm is not required to, and has not conducted, an audit of our internal control over financial reporting. We and our independent registered public accounting firm have identified material weaknesses in our internal control over financial reporting as of September 30, 2017. A “material weakness” is a deficiency, or combination of deficiencies, in internal control over financial reporting such that there is a reasonable possibility that a material misstatement of the annual or interim financial statements will not be prevented or detected on a timely basis.

The material weakness identified relates to the lack of a sufficient complement of qualified personnel within our accounting and finance department who possess an appropriate level of expertise, experience and training commensurate with our corporate structure and financial reporting requirements to: (i) maintain effective controls over accounting for non-routine and/or complex transactions, and (ii) maintain effective controls over the financial statement close and reporting processes. We have begun to remediate and plan to further remediate this material weakness primarily by implementing additional review procedures within our accounting and finance department, hiring additional staff and, if appropriate, engaging external accounting experts with the appropriate knowledge to supplement our internal resources in our computation and review processes. These actions and planned actions are subject to ongoing management review. Although we believe we are addressing the internal control deficiencies that led to the material weakness, the measures we have taken and will take may not be effective. Consequently, if this or another material weakness or significant deficiencies occur in the future, it could affect the financial results that we report which could result in a restatement of our financial statements or cause us to fail to meet our reporting obligations.

We, and our independent registered public accounting firm, were not required to perform an evaluation of our internal control over financial reporting as of the fiscal years ended September 30, 2016 or 2017 in accordance with the provisions of the Sarbanes-Oxley Act. Accordingly, we cannot assure you that we have identified all, or that we will not in the future have additional, material weaknesses. Material weaknesses may still exist when we report on the effectiveness of our internal control over financial reporting as required by reporting requirements under Section 404 of the Sarbanes-Oxley Act after the completion of this offering.

If we fail to develop or maintain an effective system of internal controls, we may not be able to accurately report our financial results or prevent fraud. If one or more material weaknesses emerge related to financial reporting, or if we otherwise fail to establish and maintain effective internal control over financial reporting, our ability to accurately report our financial results could be adversely affected. As a result, current and potential shareholders could lose confidence in our financial reporting, which would harm our business and the trading price of our common stock.

Effective internal controls are necessary for us to provide reliable financial reports, prevent fraud and operate successfully as a public company. If we cannot provide reliable financial reports or prevent fraud, our

 

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reputation and operating results would be maintain adequate controls over our financial processes and reporting in the future or that we will be able to comply with our obligations. Furthermore, under Section 404 of the Sarbanes Oxley Act of 2002 we are not required to have our independent registered public accounting firm attest to the effectiveness of our internal controls 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. Accordingly, we may not be required to have our independent registered public accounting firm attest to the effectiveness of our internal controls until as late as our annual report for the fiscal year ending September 30, 2023. Once it is required to do so, our independent registered public accounting firm may issue a report that is adverse in the event it is not satisfied with the level at which our controls are documented, designed, operated or reviewed. Compliance with these requirements may strain our resources, increase our costs and distract management, and we may be unable to comply with these requirements in a timely or cost-effective manner. Any failure to develop or maintain effective internal controls, or difficulties encountered in implementing or improving our internal controls, could harm our operating results or cause us to fail to meet our reporting obligations. Ineffective internal controls could also cause investors to lose confidence in our reported financial information, which would likely have a negative effect on the trading price of our common stock.

Collectively, our Existing Owners will have the ability to direct the voting of a majority of our common stock, and their interests may conflict with those of our other stockholders.

Upon completion of this offering, our Existing Owners will beneficially own approximately     % of our outstanding common stock (or approximately     % if the underwriters’ over-allotment option is exercised in full). As a result, our Existing Owners will be able to control matters requiring stockholder approval, including the election of directors, changes to our organizational documents and significant corporate transactions. This concentration of ownership makes it unlikely that any other holder or group of holders of our common stock will be able to affect the way we are managed or the direction of our business. The interests of our Existing Owners with respect to matters potentially or actually involving or affecting us, such as future acquisitions, financings and other corporate opportunities and attempts to acquire us, may conflict with the interests of our other stockholders. Given this concentrated ownership, our Existing Owners would have to approve any potential acquisition of us. Moreover, our Existing Owners’ concentration of stock ownership may also adversely affect the trading price of our common stock to the extent investors perceive a disadvantage in owning stock of a company with significant stockholders.

Conflicts of interest could arise in the future between us, on the one hand, and certain of our stockholders and their respective affiliates, including its funds and their respective portfolio companies, on the other hand, concerning among other things, potential competitive business activities or business opportunities.

Investment funds managed by certain of our stockholders are in the business of making investments in entities in the U.S. energy industry. As a result, certain of our stockholders may, from time to time, acquire interests in businesses that directly or indirectly compete with our business, as well as businesses that are significant existing or potential customers. Certain of our stockholders and their respective portfolio companies may acquire or seek to acquire assets that we seek to acquire and, as a result, those acquisition opportunities may not be available to us or may be more expensive for us to pursue. Under our certificate of incorporation, certain of our stockholders and/or one or more of their respective affiliates are permitted to engage in business activities or invest in or acquire businesses which may compete with our business or do business with any client of ours. Any actual or perceived conflicts of interest with respect to the foregoing could have an adverse impact on the trading price of our common stock.

Our Sponsors and their affiliates are not limited in their ability to compete with us, and the corporate opportunity provisions in our certificate of incorporation could enable our Sponsors to benefit from corporate opportunities that might otherwise be available to us.

Our governing documents will provide that Yorktown, Boomer and Bluescape and their affiliates (including portfolio investments of Yorktown, Boomer and Bluescape and their affiliates) are not restricted from owning

 

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assets or engaging in businesses that compete directly or indirectly with us. In particular, subject to the limitations of applicable law, our certificate of incorporation will, among other things:

 

   

permit Yorktown, Boomer and Bluescape and their affiliates to conduct business that competes with us and to make investments in any kind of property in which we may make investments; and

 

   

provide that if Yorktown, Boomer and Bluescape or their affiliates or any director or officer of one of our affiliates, Yorktown, Boomer and Bluescape or their affiliates who is also one of our directors, becomes aware of a potential business opportunity, transaction or other matter, they will have no duty to communicate or offer that opportunity to us.

Yorktown, Boomer and Bluescape or their affiliates, may become aware, from time to time, of certain business opportunities (such as acquisition opportunities) and may direct such opportunities to other businesses in which they have invested, in which case we may not become aware of or otherwise have the ability to pursue such opportunity. Further, such businesses may choose to compete with us for these opportunities, possibly causing these opportunities to not be available to us or causing them to be more expensive for us to pursue. In addition, Yorktown, Boomer and Bluescape and their affiliates, may dispose of properties or other assets in the future, without any obligation to offer us the opportunity to purchase any of those assets. As a result, our renouncing our interest and expectancy in any business opportunity that may be from time to time presented to our Sponsors and their affiliates, could adversely impact our business or prospects if attractive business opportunities are procured by such parties for their own benefit rather than for ours. Please read “Description of Capital Stock.”

Yorktown, Boomer and Bluescape have resources greater than ours, which may make it more difficult for us to compete with any of them with respect to commercial activities as well as for potential acquisitions. We cannot assure you that any conflicts that may arise between us and any of such parties, on the other hand, will be resolved in our favor. As a result, competition from Yorktown, Boomer and Bluescape and their affiliates could adversely impact our results of operations.

Provisions in our certificate of incorporation and bylaws and Delaware law might discourage, delay or prevent a change of control or changes in our management and, therefore, depress the market price of our common stock.

Our certificate of incorporation and bylaws contain provisions that could depress the market price of our common stock by acting to discourage, delay or prevent a change in control or changes in our management our shareholders may deem advantageous. These provisions among other things:

 

   

establish a classified board of directors so that not all members of our board are elected at one time;

 

   

permit the board of directors to establish the number of directors;

 

   

at any time after Yorktown, Boomer, Bluescape, and their respective affiliates, no longer collectively beneficially own more than 50% of the outstanding shares of our common stock, provide that directors may only be removed “for cause” and only with the affirmative vote of the holders of 66 2/3 percent of our outstanding shares of common stock;

 

   

at any time after Yorktown, Boomer, Bluescape, and their respective affiliates, no longer collectively beneficially own more than 50% of the outstanding shares of our common stock, provide that our certificate of incorporation and bylaws may be amended by the affirmative vote of the holders of 66 2/3 percent of our outstanding shares of common stock;

 

   

authorize the issuance of “blank check” preferred stock that our board could use to implement a stockholder rights plan (also known as a “poison pill”);

 

   

at any time after Yorktown, Boomer, Bluescape, and their respective affiliates, no longer collectively beneficially own more than 50% of the outstanding shares of our common stock, eliminate the ability of our stockholders to call special meetings of stockholders;

 

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at any time after Yorktown, Boomer, Bluescape, and their respective affiliates, no longer collectively beneficially own more than 50% of the outstanding shares of our common stock, prohibit stockholder action by written consent, which requires all stockholder actions to be taken at a meeting of our stockholders;

 

   

provide that the board of directors is expressly authorized to make, alter or repeal our bylaws; and

 

   

establish advance notice requirements for nominations for election to our board or for proposing matters that can be acted upon by stockholders at annual stockholder meetings.

Investors in this offering will experience immediate and substantial dilution of $                 per share and additional stock offerings may further dilute shareholders.

The public offering price of the securities offered pursuant to this prospectus is substantially higher than the pro forma net tangible book value per share of our common stock. Based on an assumed initial public offering price of $                 per share (the midpoint of the range set forth on the cover of this prospectus), purchasers of our common stock in this offering will experience immediate and substantial dilution of $                 per share based on the difference between the as adjusted pro forma net tangible book value per share of common stock from the initial public offering price.

Given our plans and our expectation that we may need additional capital and personnel, we may need to issue additional shares of our common stock or securities convertible into or exercisable for shares of our common stock, including preferred stock, options or warrants. The issuance of such stock or securities may further dilute the ownership of our shareholders. Please see “Dilution.”

We do not intend to pay dividends on our common stock, and our revolving credit facility places certain restrictions on our ability to do so. Consequently, it is possible that your only opportunity to achieve a return on your investment will be if the price of our common stock appreciates from the price you bought it and you sell your shares at a price greater than you paid for it.

We do not plan to declare dividends on shares of our common stock in the foreseeable future. Additionally, our revolving credit facility restricts our ability to pay cash dividends. Consequently, it is possible that your only opportunity to achieve a return on your investment in us will be if you sell our common stock at a price greater than you paid for it. There is no guarantee that the price of our common stock that will prevail in the market will ever exceed the price that you pay in this offering.

Future sales of our common stock in the public market could reduce our stock price, and any additional capital raised by us through the sale of equity or convertible securities may dilute your ownership in us.

We may sell additional shares of common stock in subsequent public or private offerings. We may also issue additional shares of common stock or convertible securities. After the completion of this offering, we will have                  outstanding shares of common stock. This number excludes                  shares that we may sell in this offering if the underwriters’ option to purchase additional shares is fully exercised, which may be resold immediately in the public market.

Following the completion of this offering, assuming no exercise of the underwriters’ option to purchase additional shares, our Existing Owners will collectively own                  shares of our common stock, or approximately     % of our total outstanding shares, all of which are restricted from immediate resale under the federal securities laws and are subject to the lock-up agreements with the underwriters described in “Underwriting (Conflicts of Interest),” but may be sold into the market in the future. Yorktown, Boomer and Bluescape will be party to registration rights agreements with us which will require us to effect the registration of their shares (and shares of certain of their affiliates) in certain circumstances no earlier than the lock-up period end date. Please see “Shares Eligible for Future Sale—Registration Rights Agreement” and “Certain Relationships and Related Party Transactions—Agreements Entered Into in Connection with this Offering—Registration Rights Agreement.”

 

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In connection with this offering, we intend to file a registration statement with the SEC on Form S-8 providing for the registration of                 shares of our common stock issued or reserved for issuance under our equity incentive plan, when such registration is available to us. Subject to the satisfaction of vesting conditions, the expiration of lock-up agreements and the requirements of Rule 144, and our eligibility for such registration, shares registered under the registration statement on Form S-8 will be available for resale in the public market without restriction.

We cannot predict the size of future issuances of our common stock or securities convertible into common stock or the effect, if any, that future issuances and sales of shares of our common stock will have on the market price of our common stock. Sales of substantial amounts of our common stock (including shares issued in connection with an acquisition), or the perception that such sales could occur, may adversely affect prevailing market prices of our common stock.

We may issue preferred stock whose terms could adversely affect the voting power or value of our common stock.

Our certificate of incorporation authorizes us to issue, without the approval of our shareholders, one or more classes or series of preferred stock having such designations, preferences, limitations and relative rights, including preferences over our common stock respecting dividends and distributions, as our board of directors may determine. The terms of one or more classes or series of preferred stock could adversely impact the voting power or value of our common stock. For example, we might grant holders of preferred stock the right to elect some number of our directors in all events or on the happening of specified events or the right to veto specified transactions. Similarly, the repurchase or redemption rights or liquidation preferences we might assign to holders of preferred stock could affect the residual value of the common stock.

We may need to raise additional financing. Our ability to implement our business plan may depend on our ability to obtain additional financing in the future.

We cannot assure you that additional financing will be available on terms favorable to us. If adequate funds are not available on acceptable terms, our ability to grow our business would be dependent on the cash from your investment and the cash flow, if any, from our operations, which may not be sufficient. If we raise additional funds through the issuance of additional shares of common stock, then your percentage ownership interest in us may be reduced.

If securities or industry analysts do not publish research or reports about our business, if they adversely change their recommendations regarding our common stock or if our operating results do not meet their expectations, our stock price could decline.

The trading market for our common stock will be influenced by the research and reports that industry or securities analysts publish about us or our business. If one or more of these analysts cease coverage of our company or fail to publish reports on us regularly, we could lose visibility in the financial markets, which in turn could cause our stock price or trading volume to decline. Moreover, if one or more of the analysts who cover our company downgrades our common stock or if our operating results do not meet their expectations, our stock price could decline.

The underwriters of this offering may waive or release parties to the lock-up agreements entered into in connection with this offering, which could adversely affect the price of our common stock.

We, all of our directors and executive officers and each of our Existing Owners have entered or will enter into lock-up agreements pursuant to which we and they will be subject to certain restrictions with respect to the sale or other disposition of our common stock for a period of 180 days following the date of this prospectus. SunTrust Robinson Humphrey, Inc. and Seaport Global Securities, LLC, at any time and without notice, may

 

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release all or any portion of the common stock subject to the foregoing lock-up agreements. See “Underwriting (Conflicts of Interest)” for more information on these agreements. If the restrictions under the lock-up agreements are waived, then the common stock, subject to compliance with the Securities Act or exceptions therefrom, will be available for sale into the public markets, which could cause the market price of our common stock to decline and impair our ability to raise capital.

We have discretion in the use the net proceeds that we will receive from this offering and may not use them in a manner in which our shareholders would consider appropriate.

Our management will have discretion in the application of the net proceeds that we will receive from this offering. Our shareholders may not agree with the manner in which our management chooses to allocate and spend these funds. The failure by our management to apply these funds effectively could have a material adverse effect on our business.

A portion of the proceeds from this offering will be used to grant certain employees cash bonuses and will not be available to fund our operations.

As described in “Use of Proceeds,” we intend to use approximately $2.1 million of the proceeds from this offering to grant one-time cash bonuses to our named executive officers and certain of our employees. Consequently, such portion of the proceeds from this offering will not be available to fund our operations, capital expenditures or acquisition opportunities. See “Use of Proceeds.”

Our certificate of incorporation will designate the Court of Chancery of the State of Delaware as the sole and exclusive forum for certain types of actions and proceedings that may be initiated by our shareholders, which could limit our shareholders’ ability to obtain a favorable judicial forum for disputes with us or our directors, officers, employees or agents.

Our certificate of incorporation will provide that unless we consent in writing to the selection of an alternative forum, the Court of Chancery of the State of Delaware will, to the fullest extent permitted by applicable law, be the sole and exclusive forum for (i) any derivative action or proceeding brought on our behalf, (ii) any action asserting a claim for a breach of a fiduciary duty owed by any of our directors, officers, employees or agents to us or our shareholders, (iii) any action asserting a claim arising pursuant to any provision of the DGCL, our certificate of incorporation or our bylaws, or (iv) any action asserting a claim against us that is governed by the internal affairs doctrine, in each such case subject to such Court of Chancery having personal jurisdiction over the indispensable parties named as defendants therein. Any person or entity purchasing or otherwise acquiring any interest in shares of our capital stock will be deemed to have notice of, and consented to, the provisions of our certificate of incorporation described in the preceding sentence. This choice of forum provision may limit a shareholder’s ability to bring a claim in a judicial forum that it finds favorable for disputes with us or our directors, officers, employees or agents, which may discourage such lawsuits against us and such persons. Alternatively, if a court were to find these provisions of our certificate of incorporation inapplicable to, or unenforceable in respect of, one or more of the specified types of actions or proceedings, we may incur additional costs associated with resolving such matters in other jurisdictions, which could adversely affect our business, financial condition or results of operations.

 

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CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

The information discussed in this prospectus includes “forward-looking statements.” All statements, other than statements of historical facts, included herein concerning, among other things, planned capital expenditures, increases in oil and gas production, the number of anticipated wells to be drilled or completed after the date hereof, future cash flows and borrowings, pursuit of potential acquisition opportunities, our financial position, business strategy and other plans and objectives for future operations, are forward-looking statements. These forward- looking statements are identified by their use of terms and phrases such as “may,” “expect,” “estimate,” “project,” “plan,” “believe,” “intend,” “achievable,” “anticipate,” “will,” “continue,” “potential,” “should,” “could,” and similar terms and phrases. Although we believe that the expectations reflected in these forward-looking statements are reasonable, they do involve certain assumptions, risks and uncertainties, and we can give no assurance that those expectations will be achieved. We disclose important factors that could cause our actual results to differ materially from our expectations under “Risk Factors,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and elsewhere in this prospectus. These cautionary statements qualify all forward-looking statements attributable to us or persons acting on our behalf. Our results could differ materially from those anticipated in these forward-looking statements as a result of certain factors, including, among others:

 

   

federal and state regulations and laws;

 

   

capital requirements and uncertainty of obtaining additional funding on terms acceptable to us;

 

   

risks and restrictions related to our debt agreements;

 

   

our ability to use derivative instruments to manage commodity price risk;

 

   

realized oil, natural gas and NGL prices;

 

   

a decline in oil, natural gas and NGL production, and the impact of general economic conditions on the demand for oil, natural gas and NGL and the availability of capital;

 

   

unsuccessful drilling and completion activities and the possibility of resulting write-downs;

 

   

geographical concentration of our operations;

 

   

our ability to meet our proposed drilling schedule and to successfully drill wells that produce oil or natural gas in commercially viable quantities;

 

   

shortages of oilfield equipment, supplies, services and qualified personnel and increased costs for such equipment, supplies, services and personnel;

 

   

adverse variations from estimates of reserves, production, production prices and expenditure requirements, and our inability to replace our reserves through exploration and development activities;

 

   

incorrect estimates associated with properties we acquire relating to estimated proved reserves, the presence or recoverability of estimated oil and natural gas reserves and the actual future production rates and associated costs of such acquired properties;

 

   

hazardous, risky drilling operations, including those associated with the employment of horizontal drilling techniques, and adverse weather and environmental conditions;

 

   

limited control over non-operated properties;

 

   

title defects to our properties and inability to retain our leases;

 

   

our ability to successfully develop our large inventory of undeveloped operated and non-operated acreage;

 

   

our ability to retain key members of our senior management and key technical employees;

 

   

constraints in the Permian Basin in Texas with respect to gathering, transportation and processing facilities, and marketing;

 

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risks relating to managing our growth, particularly in connection with the integration of significant acquisitions;

 

   

impact of environmental, health and safety, and other governmental regulations, and of current or pending legislation;

 

   

changes in tax laws;

 

   

effects of competition;

 

   

seasonal weather conditions; and

 

   

the other factors discussed 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.

All forward-looking statements speak only as of the date of this prospectus. All forward-looking statements attributable to us or persons acting on our behalf, including any subsequent written or oral forward-looking statements, are expressly qualified in their entirety by the cautionary statements in this section and elsewhere in this prospectus. Except as required by applicable law, we disclaim and do not assume any duty to update any forward-looking statements, whether as a result of new information, subsequent events or circumstances, changes in expectations or otherwise.

 

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USE OF PROCEEDS

Assuming the midpoint of the price range set forth on the cover of the prospectus, we expect to receive approximately $         million of net proceeds from this offering, or $         million if the underwriters exercise their option to purchase                  additional shares in full, in each case, after deducting underwriting discounts and commissions and estimated offering expenses payable by us.

We intend to use the net proceeds from this offering (i) to fund our fiscal 2019 capital program, (ii) for general corporate purposes, (iii) to fully repay our existing balance of approximately $             million under our revolving credit facility and (iv) to pay an aggregate of $2.1 million in one-time cash bonuses to our named executive officers and certain of our employees. The following table illustrates our anticipated use of the net proceeds from this offering:

 

Sources of Funds

         

Use of Funds

      
(In millions)                   

Net proceeds from this offering

   $                  Fiscal 2019 capital program    $  
      General corporate purposes    $    
      Repayment of our revolving credit facility    $    
      Payment of cash bonuses to our named executive officers and certain of our employees(1)    $ 2.1  

Total sources of funds

   $                    Total uses of funds    $    

 

(1)

Represents cash bonuses payable to our named executive officers and certain of our employees upon consummation of this offering. See “Executive Compensation—Additional Narrative Disclosures—IPO Bonuses.”

A $1.00 increase or decrease in the assumed initial public offering price of $        per share (the midpoint of the price range set forth on the cover of this prospectus) 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 offered by us, as set forth on the cover page of this prospectus, remains the same. We may also increase or decrease the number of shares we are offering. Each increase or decrease of one million shares we are offering would increase or decrease, respectively, the net proceeds from this offering, by approximately $        million, after deducting the estimated underwriting discounts and estimated offering expenses payable by us, assuming the assumed public offering price stays the same. If the proceeds increase for any reason, we would use the additional net proceeds for general corporate purposes. If the proceeds decrease for any reason, then we would first reduce by a corresponding amount the net proceeds directed for general corporate purposes and then reduce the amount of net proceeds directed to repay borrowings under our revolving credit facility. Any change in proceeds retained by us as a result of any change in the initial public offering price would impact the amount of net proceeds that we could use for our general corporate purposes.

Amounts repaid under our revolving credit facility may be re-borrowed from time to time, subject to the terms of the credit agreement, and we intend to do so in the future to fund our capital program. The revolving credit facility stated maturity date is on September 28, 2021. In connection with the May 1 borrowing base redetermination date, we elected to increase the borrowing base from $60 million to $100 million effective as of May 25, 2018. On September 14, 2018, a scheduled borrowing base redetermination was initiated and we expect such redetermination to be completed in early October. In the event that such redetermination results in an increase to our borrowing base amount, the Company may elect to accept the increase at that time. Since June 30, 2018, we borrowed an additional $9.5 million. As of September 19, 2018, we had $53.6 million of outstanding borrowings and an additional $46.5 million available under our revolving credit facility and were in compliance with all applicable financial covenants. We borrowed under our revolving credit facility to fund our fiscal year 2018 capital program, including $19.7 million to fund the acquisition of the New Mexico Assets.

The foregoing sets forth our current intentions with respect to the net proceeds from this offering. We may reallocate such proceeds for other working capital and general corporate purposes that we deem to be in our best

 

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interests or due to unforeseen changes in circumstances or events, including without limitation, well results, economic conditions, and other acquisition opportunities.

Affiliates of SunTrust Robinson Humphrey, Inc. are lenders under our revolving credit facility and accordingly will receive a portion of the net proceeds from this offering. Accordingly, this offering is being made in compliance with FINRA Rule 5121. Please read “Underwriting (Conflict of Interest).”

 

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DIVIDEND POLICY

We 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 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. Additionally, our revolving credit facility places certain restrictions on our ability to pay cash dividends.

CORPORATE CONVERSION

We currently operate as a Delaware limited liability company under the name Riley Exploration—Permian, LLC. Prior to the effectiveness of the registration statement of which this prospectus forms a part, Riley Exploration—Permian, LLC will convert into a Delaware corporation pursuant to a statutory conversion and change its name to Riley Exploration Permian, Inc. In this prospectus, we refer to all of the transactions related to our conversion to a corporation described above as the Corporate Conversion.

In conjunction with the Corporate Conversion, all of our outstanding Series A Preferred Units will be converted into an aggregate of                shares of our common stock and all of our outstanding common units will be converted into an aggregate of                shares of our common stock. The number of shares of common stock issuable in connection with the Corporate Conversion will be determined pursuant to the applicable provisions of the plan of conversion.

In connection with the Corporate Conversion, Riley Exploration Permian, Inc. will continue to hold all property and assets of Riley Exploration—Permian, LLC and will assume all of the debts and obligations of Riley Exploration—Permian, LLC. Riley Exploration Permian, Inc. will be governed by a certificate of incorporation filed with the Delaware Secretary of State and bylaws, the material portions of which are described under the heading “Description of Capital Stock.” On the effective date of the Corporate Conversion, the members of the board of managers of Riley Exploration—Permian, LLC will become the members of Riley Exploration Permian, Inc.’s board of directors and the officers of Riley Exploration—Permian, LLC will become the officers of Riley Exploration Permian, Inc.

The purpose of the Corporate Conversion is to reorganize our corporate structure so that the top-tier entity in our corporate structure—the entity that is offering common stock to the public in this offering—is a corporation rather than a limited liability company and so that our existing investors will own our common stock rather than membership units in a limited liability company.

Except as otherwise noted herein, the consolidated financial statements included elsewhere in this prospectus are those of Riley Exploration—Permian, LLC and its combined operations. We do not expect that the Corporate Conversion will have a material effect on the results of our core operations.

 

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CAPITALIZATION

The following table sets forth our cash and cash equivalents and capitalization as of June 30, 2018 as follows:

 

   

on a historical basis as of June 30, 2018;

 

   

as adjusted to give effect to the Corporate Conversion; and

 

   

as further adjusted to give effect to the sale of shares of our common stock by us in this offering at an assumed initial public offering price of $        per share (the midpoint of the price range set forth on the cover of this prospectus) and the application of net proceeds therefrom as set forth under “Use of Proceeds.”

The information set forth in the table below is illustrative only and will be adjusted based on the actual initial public offering price and other final terms of this offering. This table should be read in conjunction with, and is qualified in its entirety by reference to, “Use of Proceeds,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our financial statements and related notes appearing elsewhere in this prospectus.

 

     As of June 30, 2018  
     Historical      As
Adjusted(1)
    As Further
Adjusted(2)
 
     (in Thousands, except for share data)  

Cash and cash equivalents

   $ 1,029      $ 1,029    
  

 

 

    

 

 

   

 

 

 

Debt obligations:

       

Revolving credit facility(3)

   $ 44,000      $ 44,000    

Notes payable(4)

     113        113    
  

 

 

    

 

 

   

 

 

 

Total debt obligations

     44,113        44,113       —    

Series A Preferred Units(5)(6)

   $ 52,739      $ —      

Equity

       

Member’s equity

   $ 104,241      $ —      

Common stock(7)—$0.01 par value; no shares authorized, issued or outstanding (actual);                 shares authorized and                 shares issued and outstanding (as adjusted);                 shares authorized and                 shares issued and outstanding (as further adjusted)

     —          —      

Additional paid-in capital

     —          170,165    

Accumulated deficit(6)(8)(9)

     —          (18,249  
  

 

 

    

 

 

   

 

 

 

Total Equity

     104,241        151,916       —    
  

 

 

    

 

 

   

 

 

 

Total capitalization

   $ 201,093      $ 196,029     $ —    
  

 

 

    

 

 

   

 

 

 

 

(1)

The as adjusted balance sheet data gives effect to the Corporate Conversion as described under “Corporate Conversion.”

(2)

The as adjusted balance sheet data gives further effect to our issuance and sale of                shares of our common stock offered in this offering at an assumed initial public offering price of $        per share, which is the midpoint of the price range set forth on the cover page of this prospectus, after deducting estimated underwriting discounts and commissions and estimated offering expenses payable by us. A $1.00 increase (decrease) in the assumed initial public offering price of $        per share of our common stock, which is the midpoint of the price range set forth on the cover page of this prospectus, would increase (decrease) the as adjusted amount of each of cash and cash equivalents, total assets and total stockholders’ equity by $        million, assuming that the number of shares offered by us, as set forth on the cover page of this

 

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  prospectus, remains the same and after deducting estimated underwriting discounts and commissions. An increase (decrease) of 1.0 million shares in the number of shares of our common stock offered by us, as set forth on the cover page of this prospectus, would increase (decrease) the as adjusted amount of each of cash and cash equivalents, total assets and total stockholders’ equity by $        million, assuming no change in the assumed initial public offering price per share and after deducting estimated underwriting discounts and commissions.
(3)

In connection with the May 1 borrowing base redetermination date, we elected to increase the borrowing base from $60 million to $100 million effective as of May 25, 2018. Since June 30, 2018, we borrowed an additional $9.5 million. As of September 19, 2018, we had $53.6 million of outstanding borrowings and an additional $46.5 million available under our revolving credit facility and were in compliance with all applicable financial covenants. After giving effect to the sale of shares of our common stock in this offering, the application of the anticipated net proceeds therefrom and the amendment and restatement of our revolving credit facility in connection therewith, we expect to have $        million of available borrowing capacity under our revolving credit facility.

(4)

Notes payable refers to notes payable for vehicles and related insurance. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Contractual Obligations” for more information on these notes payable.

(5)

The Series A Preferred Units of $52.9 million is recorded as mezzanine equity net of a discount of $0.2 million.

(6)

In connection with the Corporate Conversion as indicated above, we will issue                shares of common stock to holders of our Series A Preferred Units. The amount of our common stock issued as a result of the conversion is based on a conversion rate equal to (A) the quotient of the product of the number of Series A Preferred Units to be converted multiplied by the Series A preferred liquidation preference, divided by (B) the lesser of the Series A conversion price or a 20% discount to the IPO conversion price based on the midpoint of the range set forth on the cover page of this prospectus. The conversion results in a deemed preferred distribution of $13.2 million to the Series A Preferred Unit holders, which reduces income attributable to common units in the period in which the conversion occurs.

(7)

In connection with the Corporate Conversion as indicated above, we will issue                shares of common stock to holders of our common units.

(8)

Reflects the charge to recognize the net deferred tax liabilities of $5.1 million arising from the temporary differences between the historical cost basis and tax basis of our assets and liabilities as a result in the change in tax status to a subchapter C corporation. This amount is based on the U.S. Federal income tax rate in effect at June 30, 2018.

(9)

Reflects one time bonuses payable upon completion of the initial public offering consisting of cash bonuses in an aggregate amount of $2.1 million to be paid to our named executive officers and certain of our employees in a single lump sum cash payment upon the completion of the initial public offering.

 

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DILUTION

Purchasers of the common stock in this offering will experience immediate and substantial dilution in the net tangible book value per share of the common stock for accounting purposes. Our pro forma net tangible book value as of June 30, 2018, after giving effect to the Corporate Conversion, was $        million, or $        per share. Pro forma net tangible book value per share is determined by dividing our pro forma tangible net worth (tangible assets less total liabilities) by the total number of outstanding shares of common stock that will be outstanding immediately prior to the closing of this offering after giving effect to the Corporate Conversion. Assuming an initial public offering price of $        per share (which is the midpoint of the price range set forth on the cover page of this prospectus), 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), our adjusted pro forma net tangible book value as of June 30, 2018 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 shareholders and an immediate dilution (i.e., the difference between the offering price and the adjusted pro forma net tangible book value after this offering) to new investors purchasing shares in this offering of $        per share. The following table illustrates the per share dilution to new investors purchasing shares in this offering:

 

Assumed initial public offering price per share

      $              

Pro forma net tangible book value per share as of June 30, 2018

   $                 

Increase per share attributable to new investors in this offering

     
  

 

 

    

As adjusted pro forma net tangible book value per share after giving further effect to this offering

     
     

 

 

 

Dilution in pro forma net tangible book value per share to new investors 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 prospectus, would increase (decrease) our adjusted pro forma net tangible book value per share after the offering by $        per share and increase (decrease) 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 prospectus, remains the same, after deducting the estimated underwriting discounts and commissions and estimated offering expenses payable by us.

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 prospectus, would increase (decrease) our common stock issuable to our existing preferred unitholders, assuming our preferred unitholders are converted as a result of our initial public offering price rather than according to the alternative conversion formula provided in the terms of our Series A Preferred Units, by                shares and increase (decrease) the dilution to new investors in this offering by                shares, assuming the number of shares offered by us, as set forth on the cover page of this prospectus, remains the same.

The following table summarizes, on an adjusted pro forma basis as of June 30, 2018, the total number of shares of common stock owned by Existing Owners and to be owned by new investors, the total consideration paid, and the average price per share paid by our Existing Owners and to be paid by new investors in this offering at our assumed initial public offering price of $                per share (which is the midpoint of the price range set forth on the cover page of this prospectus), calculated before deduction of estimated underwriting discounts and commissions.

 

     Shares Acquired      Total Consideration  
       Number          Percent        Amount (in
  thousands)  
       Percent        Average
Price Per
    Share    
 

Existing Owners

         $                       $              

New Investors in this offering

         $           $    

Total

         $ —          —        $    
        

 

 

       

 

 

 

 

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The above tables and discussion are based on the number of shares of our common stock to be outstanding as of the closing of this offering.

The data in the table excludes                 vested shares of common stock expected to be issued to certain employees upon completion of this offering,                restricted shares of our common stock expected to be issued in connection with the successful completion of this offering pursuant to our LTIP and                 additional restricted shares of common stock reserved for future issuance under our LTIP (which amount may be increased each year in accordance with the terms of our LTIP). See “Executive Compensation—Additional Narrative Disclosures—IPO Bonuses,” “—Employment, Severance or Change in Control Agreements” and “—2018 Long Term Incentive Plan” for more information.

If the underwriters’ over-allotment option is exercised in full, the number of shares held by new investors will be increased to                , or approximately    % of the total number of shares of common stock.

 

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SELECTED HISTORICAL FINANCIAL DATA

The selected historical financial data as of June 30, 2018 and for the nine months ended June 30, 2018 and 2017 and the years ended September 30, 2017 and 2016, were derived from our unaudited and audited historical financial statements. You should read the following selected data in conjunction with “Use of Proceeds,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the financial statements included elsewhere in this prospectus. Please also see “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Overview” for a discussion of the accounting presentation of us and REG. Among other things, those historical financial statements of us and REG include more detailed information regarding the basis of presentation for the following information. The historical financial results of us and REG are not necessarily indicative of results to be expected for any future periods.

You should read the following selected historical financial data in conjunction with “Use of Proceeds,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the historical financial statements included elsewhere in this prospectus.

Consolidated Statements of Operations Information:

 

     For the Nine Months Ended
June 30,
    For the Years Ended
September 30,
 
     (unaudited)              
         2018             2017             2017             2016      
     ($ in Thousands, Except Unit and Per Unit Amounts)  

Statement of Operations Data:

        

Revenues:

        

Oil sales

   $ 46,438     $ 11,360     $ 21,174     $ 4,081  

Natural gas sales

     252       135       203       29  

Natural gas liquids sales

     909       262       431       20  
  

 

 

   

 

 

   

 

 

   

 

 

 

Total Revenues

     47,599       11,757       21,808       4,130  

Operating Expenses:

        

Lease operating expenses

     8,135       3,831       5,796       2,779  

Production taxes

     2,191       641       1,206       194  

Exploration expenses

     5,523       1,107       10,739       45  

Depletion, depreciation, amortization, and accretion

     11,388       3,268       5,876       1,366  

General and administrative expenses

     10,596       4,616       5,806       3,863  

Transaction Costs

     790       1,233       1,766       —    
  

 

 

   

 

 

   

 

 

   

 

 

 

Total Operating Expenses

     38,623       14,696       31,189       8,247  
  

 

 

   

 

 

   

 

 

   

 

 

 

Income (loss) from Operations:

   $ 8,976     $ (2,939   $ (9,381   $ (4,117

Other Expenses:

        

Interest Expense

     (907     —         —         —    

Gain (loss) on derivatives

     (13,895     752       (1,450     —    
  

 

 

   

 

 

   

 

 

   

 

 

 

Loss before Income Tax Provision

   $ (5,826   $ (2,187   $ (10,831   $ (4,117

Income Tax Expense

     —         —         —         9  
  

 

 

   

 

 

   

 

 

   

 

 

 

Net Loss

   $ (5,826   $ (2,187   $ (10,831   $ (4,126
  

 

 

   

 

 

   

 

 

   

 

 

 

Dividends on Preferred Units

     (2,327     (772     (1,409     —    
  

 

 

   

 

 

   

 

 

   

 

 

 

Net Loss Attributable to Common Units

   $ (8,153   $ (2,959   $ (12,240   $ (4,126
  

 

 

   

 

 

   

 

 

   

 

 

 

Loss per common unit:

        

Basic and Diluted

   $ (5.44   $ (2.86   $ (10.63   $ (7.20

Weighted average common units outstanding

     1,500,000       1,033,816       1,151,320       573,408  

 

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Consolidated Balance Sheet Information:

 

     As of
June 30,
     As of
September 30,
 
     (unaudited)                
     2018      2017      2016  
     (in Thousands)  

Statement of Balance Sheet Data:

        

Cash and cash equivalents

   $ 1,029      $ 3,683      $ —    

Total oil & gas properties

     227,914        167,739        42,530  

Total assets

     242,133        179,132        43,407  

Long-term debt, including current maturities

     44,113        218        —    

Total liabilities

     85,153        16,640        6,087  

Series A Preferred Units

     52,739        49,823        —    

Total members’ equity & parent net investment

     104,241        112,669        37,320  

Consolidated Statements of Cash Flow Information:

 

    For the Nine Months Ended
June 30,
    For the Years Ended
September 30,
 
    (unaudited)              
          2018                 2017           2017     2016  
    (in Thousands)  

Statement of Cash Flows Data:

       

Net cash provided by (used in) operating activities

  $ 22,093     $ (371   $ 3,289     $ (9,125

Net cash used in investing activities

  $ (67,444   $ (39,619   $ (54,781   $ (24,087

Net cash provided by financing activities

  $ 42,697     $ 45,210     $ 55,175     $ 33,212  

 

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL

CONDITION AND RESULTS OF OPERATIONS

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our historical financial statements and related notes included elsewhere in this prospectus. The following discussion contains “forward-looking statements” that reflect our future plans, estimates, beliefs and expected performance. The forward-looking statements are dependent upon events, risks and uncertainties that may be outside our control. Our actual results could differ materially from those discussed in these forward-looking statements. Factors that could cause or contribute to such differences include, but are not limited to, changes in prices for oil, natural gas and NGL, production volumes and forecasting production results, capital expenditures, availability of acquisitions, estimates of proved reserves, economic and competitive conditions, operational factors affecting the commencement or maintenance of producing wells, the condition of the capital markets generally, as well as our ability to access them, the proximity to and capacity of transportation facilities, and uncertainties regarding environmental regulations or litigation and other legal or regulatory developments affecting our business, as well as those factors discussed below and elsewhere in this prospectus, particularly in “Risk Factors” and “Cautionary Note Regarding Forward-Looking Statements,” all of which are difficult to predict. In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur. We do not undertake any obligation to publicly update any forward-looking statements except as otherwise required by applicable law.

Overview

We are a growth-oriented, independent oil and natural gas company focused on rapidly growing our reserves, production and cash flow through the acquisition, exploration, development and production of oil, natural gas, and natural gas liquids, or NGLs, reserves in the Permian Basin. This basin, which is one of the major producing basins in the United States, is characterized by an extensive production history, a favorable operating environment, established infrastructure, long reserve life, multiple producing horizons, significant oil in place and a large number of operators. Our activities are primarily focused on the San Andres Formation, a shelf margin deposit on the Central Basin Platform and Northwest Shelf, which accounts for approximately 24% of the nearly 30 billion barrels of oil historically produced from the Permian Basin and where horizontal production has increased by more than 425% since January 2014.

Our acreage is primarily located on large, contiguous blocks in Yoakum County, Texas and Lea, Roosevelt, and Chaves Counties, New Mexico, focused on the San Andres Formation on the Northwest Shelf. Our assets offset legacy Permian Basin San Andres fields, to include the Wasson and Brahaney Fields, which have produced more than 2.1 billion barrels of oil and 108 million barrels of oil, respectively, from the San Andres Formation since development in the area began in the 1930’s and 1940’s. Based on the close proximity to these productive fields, combined with the horizontal San Andres wells we have drilled to date and the wells drilled by offset operators, we believe we have significantly delineated our acreage.

We were formed on June 13, 2016 by REG, as its wholly-owned subsidiary. In a series of contribution transactions, we acquired the Champions Assets in exchange for our common units, including a contribution from REG on January 17, 2017. See “Prospectus Summary—Our Corporate History” for more information. The contribution received from REG was considered a transfer of a business between entities under common control and accordingly, we recorded the contributed business at historical cost and for the periods prior to January 17, 2017, the financial statements have been prepared on a “carve out” basis from REG’s accounts and reflect the historical accounts directly attributable to the Champions Assets owned by REG together with allocations of costs and expenses. The accompanying financial statements include expense allocations of the costs of certain functions provided by REG, including, but not limited to, general corporate expenses related to finance, legal, information technology, human resources, communications, insurance, utilities, and executive compensation through the date of the contribution to us on January 17, 2017. These expenses have been allocated on the basis of direct usage when identifiable, with the remainder allocated proportionately using oil and natural gas sales as the determining metric.

 

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The contributions from our other Existing Owners, Boomer, Bluescape and DR/CM, were accounted for as business combinations in accordance with ASC 805—Business Combinations and recorded at fair value. Our financial statements reflect the operating results of the assets contributed by Boomer, Bluescape and DR/CM for the periods following the respective contributions. The earnings per common unit reflect the common units received by REG for all periods and the common units received by Boomer, Bluescape and DR/CM for the periods following their respective contributions.

In connection with this offering, we will convert from a limited liability company to a Delaware corporation, and the Series A Preferred Units and common units held by our Existing Owners will be converted into shares of our common stock. For more information please see “Corporate Conversion.”

Market Conditions

The oil and natural 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. In general, the 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. 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. 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. Oil prices may also be affected by the strength of the U.S. dollar relative to other leading currencies, as oil prices can be dollar denominated. For example, when the U.S. dollar strengthened in recent years, oil prices weakened, which may have occurred in part because they are U.S. dollar-denominated. NGL prices generally correlate to the price of oil. Also adversely affecting the price for NGLs is the supply of NGLs in the United States, which has continued to grow due to an increase in industry participants targeting projects that produce NGLs in recent years. Prices for domestic natural gas began to decline during the third quarter of 2014 and have continued to be weak throughout 2015, 2016 and 2017. The declines in natural gas prices are primarily due to an abundance of supply relative to forecasted demand growth in North America among other factors. The duration and magnitude of commodity price declines cannot be accurately predicted.

Our revenue, profitability and future growth are highly dependent on the prices we receive for our oil, natural gas and NGL production. For the nine months ended June 30, 2018, as compared to the nine months ended June 30, 2017, our realized oil price increased 28% to $57.98 per barrel, and our realized prices for natural gas decreased 26% to $2.00 per Mcf, while NGLs increased 33% to $26.74 per barrel. Lower oil, natural gas and NGL prices not only may decrease our revenues, but also may reduce the amount of oil, natural gas and NGLs that we can produce economically and therefore, potentially lower our oil, natural gas and NGL reserves. Lower commodity prices in the future could result in impairments of our properties and may materially and adversely affect our future business, financial condition, results of operations, operating cash flows, liquidity and ability to finance planned capital expenditures. See “Risk Factors—Risks Related to Our Business—If commodity prices decrease to a level such that our future undiscounted cash flows from our properties are less than their carrying value for a significant period of time, we will be required to take write-downs of the carrying values of our properties, which may negatively affect the trading price of our common stock.” Lower oil, natural gas and NGL prices may also reduce the borrowing base under our credit agreement, which is determined at the discretion of the lenders and is based on the collateral value of our proved reserves that have been mortgaged to the lenders. See “Risk Factors—Risks Related to Our Business—Any significant reduction in our borrowing base under our revolving credit facility as a result of the periodic borrowing base redeterminations or otherwise may negatively impact our ability to fund our operations.”

Alternatively, higher oil and natural gas prices, which have occurred in our current 2018 fiscal year, may result in significant non-cash fair value losses being incurred on our derivatives, which could cause us to

 

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experience net losses. Further, our capital and operating costs have historically risen during periods of increasing oil, natural gas and NGL prices. These cost increases result from a variety of factors beyond our control, such as increases in the cost of electricity, steel and other raw materials that we and our vendors rely upon; increased demand for labor, services and materials as drilling activity increases; and increased taxes. Such costs may rise faster than increases in our revenue if commodity prices rise, thereby negatively impacting our profitability, cash flow and ability to complete development activities as scheduled and on budget. This impact may be magnified to the extent that our ability to participate in the commodity price increases is limited by our derivative activities. See “Risk Factors—Risks Related to Our Business—Our derivative activities could result in financial losses or could reduce our earnings.”

Our Properties

At June 30, 2018, our net acreage position in Yoakum County, Texas and Lea, Roosevelt, and Chaves Counties, New Mexico, consisted of 65,839 net acres. For the year ended September 30, 2017, we operated 71% of our horizontal production, and our total estimated proved, probable and possible reserves based on the NSAI Report were approximately 14,009, 13,016 and 13,049 MBoe, respectively. For more information about our properties and the risks associated with the comparability of proved, probable, and possible reserves, please read “Business—Our Properties” and “Business—Oil and Natural Gas Data.”

How We Evaluate Our Operations

We use a variety of financial and operational metrics to assess the performance of our oil and gas operations, including:

 

   

Sources of revenue;

 

   

Sales volumes;

 

   

Realized prices on the sale of oil, natural gas and NGL, including the effect of our commodity derivative contracts;

 

   

Lease operating expenses, or LOE;

 

   

Capital expenditures; and

 

   

Adjusted EBITDAX.

See “—Sources of Our Revenues”, “—Sales Volumes”, “—Realized Prices on the Sale of Crude Oil, Natural Gas and NGL” and “—Derivative Arrangements”, “—Principal Components of Our Cost Structure”,”—Adjusted EBITDAX” and “Summary—Summary Historical Financial Data—Non-GAAP Financial Measure—Adjusted EBITDAX” for a discussion of these metrics.

Sources of Our Revenues

Our revenues are derived primarily from the sale of our crude oil production. For the nine months ended June 30, 2018, our revenues were derived 97% from oil sales, 1% from natural gas sales and 2% from NGL sales. Our oil, natural gas and NGL revenues do not include the effects of derivatives. Our revenues may vary significantly from period to period as a result of changes in oil volumes of production sold or changes in oil prices.

 

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Sales Volumes

The following table presents historical sales volumes for our properties for the nine months ended June 30, 2018 and 2017 and for the years ended September 30, 2017 and 2016. For more information about our sales volumes, please read “—Historical Results of Operations and Operating Expenses.”

 

     For the Nine Months Ended
June 30,
     For the Years Ended
September 30,
 
     2018      2017      2017      2016  

Oil (MBbls)

     801        251        470        108  

Natural gas (MMcf)

     126        50        76        16  

NGL (MBbls)

     34        13        21        1  
  

 

 

    

 

 

    

 

 

    

 

 

 

Total (MBoe)

     856        272        504        112  
  

 

 

    

 

 

    

 

 

    

 

 

 

Average net sales (BOE/d)

     3,136        998        1,384        308  

Sales volumes directly impact our results of operations. As reservoir pressures decline, production from a given well or formation usually also decreases over time. Growth in our future production and reserves will depend on our ability to continue to add proved reserves in excess of our production. Accordingly, we plan to maintain our focus on adding reserves through organic drill-bit growth, as well as acquisitions. Our ability to add reserves through development projects and acquisitions is dependent on many factors, including takeaway capacity in our areas of operation and our ability to raise capital, geologic considerations, obtaining regulatory approvals, procuring third-party services and personnel and successfully identifying and consummating acquisitions. Please read “Risk Factors—Risks Related to Our Business” for a discussion of these and other risks affecting our reserves and production.

Realized Prices on the Sale of Crude Oil, Natural Gas and NGL

Oil, natural gas and NGL prices are among the most volatile of all commodity prices. For example, during the period from October 1, 2015 to June 30, 2018, the WTI spot price for oil has increased from $26.19 per Bbl to $74.15 per Bbl and the Henry Hub spot price for natural gas has increased from $1.49 per MMBtu to $6.24 per MMBtu.

The prices we receive for our oil, natural gas and NGLs production depend on numerous factors beyond our control, some of which are discussed in “Risk Factors—Risks Related to Our Business—Oil, natural gas and NGL prices are volatile. An extended decline in commodity prices may adversely affect our business, financial condition, or results of operations and our ability to meet our capital expenditure obligations and financial commitments. Additionally, the value of our reserves calculated using SEC pricing may be higher than the fair market value of our reserves calculated using current market prices.” These price variations can have a material impact on our financial results and capital expenditures. Volatility and declines in, and continued depression of, the price of oil and natural gas are due to a combination of factors, such as economic conditions impacting the global supply and demand for oil and political conditions in or affecting other producing countries, including member nations of OPEC. These price variations can have a material impact on our financial results and capital expenditures.

A $1.00 per barrel change in our realized oil price would have resulted in a $0.8 million and $0.5 million change in oil revenues for the nine months ending June 30, 2018 and the year ending September 30, 2017, respectively. A $0.15 per Mcf change in our realized natural gas price would have resulted in a de minimis change in our natural gas revenues for fiscal 2017. And likewise, a $1.00 per barrel change in NGL prices would have resulted in a de minimis change to our NGL revenue.

 

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The following table presents our average realized commodity prices, as well as the effects of derivative settlements.

 

     For the Nine Months Ended
June 30,
    For the Years Ended
September 30,
 
         2018           2017           2017           2016    

Oil

        

NYMEX WTI High ($/Bbl)

   $ 74.15     $ 54.45     $ 54.48     $ 51.23  

NYMEX WTI Low ($/Bbl)

   $ 49.29     $ 42.53     $ 42.48     $ 26.19  

NYMEX WTI Average ($/Bbl)

   $ 62.21     $ 49.77     $ 49.26     $ 41.50  

Average Realized Price ($/Bbl)

   $ 57.98     $ 45.26     $ 45.05     $ 37.65  

Average Realized Price, with derivative settlements ($/Bbl)

   $ 51.91     $ 45.63     $ 45.42     $ 37.65  

Averaged Realized Price as a % of Average NYMEX WTI(1)

     93%       91%       91%       91%  

Differential ($/Bbl) to Average NYMEX WTI

   $ (4.23   $ (4.51   $ (4.21   $ (3.85

Natural Gas

        

NYMEX Henry Hub High ($/MMBtu)

   $ 6.24     $ 3.80     $ 3.80     $ 3.19  

NYMEX Henry Hub Low ($/MMBtu)

   $ 2.49     $ 2.08     $ 2.08     $ 1.49  

NYMEX Henry Hub Average ($/MMBtu)

   $ 2.94     $ 3.04     $ 3.02     $ 2.29  

Average Realized Price ($/Mcf)

   $ 2.00     $ 2.70     $ 2.67     $ 1.82  

Average Realized Price, with derivative settlements ($/Mcf)

   $ 2.00     $ 2.70     $ 2.67     $ 1.82  

Averaged Realized Price as a % of Average NYMEX Henry Hub

     68%       89%       88%       80%  

Differential ($/Mcf) to Average NYMEX Henry Hub(1)

   $ (0.94   $ (0.34   $ (0.35   $ (0.47

Natural Gas Liquids

        

Average Realized Price ($/Bbl)

   $ 26.74     $ 20.15     $ 20.52     $ 15.88  

Averaged Realized Price as a % of Average NYMEX WTI

     43%       40%       42%       38%  

BOE (Barrel of Oil Equivalent)

        

Average price per BOE(1)

   $ 55.61     $ 43.22     $ 43.30     $ 36.77  

Average price per BOE with derivative settlements(1)(2)

   $ 49.93     $ 43.56     $ 43.64     $ 36.77  

 

(1)

One BOE is equal to six Mcf of natural gas or one Bbl of oil or NGL based on an approximate energy equivalency. This is an energy content correlation and does not reflect a value or price relationship between the commodities.

(2)

Average prices shown in the table reflect prices both before and after the effects of our settlements of our commodity derivative contracts. Our calculation of such effects includes both gains or losses on cash settlements for commodity derivatives.

While quoted NYMEX oil and natural gas prices are generally used as a basis for comparison within our industry, the prices we receive are affected by quality, energy content, location and transportation differentials for these products.

Derivative Arrangements

To achieve more predictable cash flow and to reduce our exposure to adverse fluctuations in commodity prices, from time to time we enter into derivative arrangements for our crude oil production. By removing a significant portion of price volatility associated with our production, we believe we can mitigate, but not eliminate, some of the potential negative effects of reductions in commodity prices on our cash flow from operations for those periods. However, in a portion of our current positions, our hedging activity may also reduce our ability to benefit from increases in oil prices. We will sustain losses to the extent our derivatives contract prices are lower than market prices and, conversely, we will sustain gains to the extent our derivatives contract prices are higher than market prices. In certain circumstances, where we have unrealized gains in our derivative

 

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portfolio, we may choose to restructure existing derivative contracts or enter into new transactions to modify the terms of current contracts in order to realize the current value of our existing positions. See “—Quantitative and Qualitative Disclosure About Market Risk—Commodity Price Risk” for information regarding our exposure to market risk, including the effects of changes in commodity prices, and our commodity derivative contracts.

We will continue to use commodity derivative instruments to hedge some of our price risk in the future. Subject to restrictions in our revolving credit agreement, our hedging strategy and future hedging transactions will be determined at our discretion and may be different than what we have done on a historical basis. Under our credit agreement, we are only permitted to hedge up to 85% of our reasonably anticipated production of each of oil, natural gas and NGLs for up to 24 months in the future, and up to 75% of our reasonably anticipated production of each of oil, natural gas and NGLs for 25 to 48 months in the future. We are currently required to hedge a minimum of 45% of our reasonably anticipated projected net oil and natural gas volumes from PDP reserves on a 24 month rolling basis. In respect to interest rate hedging from floating to a fixed rate, we are only permitted to hedge up to 75% of our then outstanding principal indebtedness for borrowed money that bears interest at a floating rate and the hedge transaction cannot have a maturity date beyond the maturity date of that indebtedness. See “—Liquidity and Capital Resources—Our Revolving Credit Facility” for more information.

As a result of recent volatility in the price of oil and natural gas, we have evaluated a variety of hedging strategies and instruments to hedge our future price risk. To date, we have utilized swaps to reduce the effect of price changes on a portion of our future oil production. We may also utilize put options, and call options, which in some instances require the payment of a premium, to reduce the effect of price changes on a portion of our future oil and natural gas production.

A swap has an established fixed price. When the settlement price is below the fixed price, the counterparty pays us an amount equal to the difference between the settlement price and the fixed price multiplied by the hedged contract volume. When the settlement price is above the fixed price, we pay our counterparty an amount equal to the difference between the settlement price and the fixed price multiplied by the hedged contract volume.

A put option has an established floor price. The buyer of the put option pays the seller a premium to enter into the put option. When the settlement price is below the floor price, the seller pays the buyer an amount equal to the difference between the settlement price and the strike price multiplied by the hedged contract volume. When the settlement price is above the floor price, the put option expires worthless.

A call option has an established ceiling price. The buyer of the call option pays the seller a premium to enter into the call option. When the settlement price is above the ceiling price, the seller pays the buyer an amount equal to the difference between the settlement price and the strike price multiplied by the hedged contract volume. When the settlement price is below the ceiling price, the call option expires worthless.

We may combine swaps, purchased put options, sold put options, and sold call options in order to achieve various hedging strategies. Some examples of our hedging strategies are collars which include purchased put options and sold call options, three-way collars which include purchased put options, sold put options, and sold call options, and enhanced swaps, which include either sold put options or sold call options with the associated premiums rolled into an enhanced fixed price swap.

We expect to use a variety of hedging strategies and instruments for the foreseeable future.

 

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This table presents our open hedge positions as of June 30, 2018:

 

Description & Production Period          
Crude Oil Swaps    Volumes (Bbl)    Swap Price (Bbl)(1)

July 2018

       59,600      $ 54.42

August 2018

       59,600      $ 54.42

September 2018

       58,000      $ 54.49

October 2018

       59,600      $ 54.42

November 2018

       58,000      $ 54.49

December 2018

       50,300      $ 54.88

January 2019

       40,300      $ 52.14

February 2019

       36,400      $ 52.14

March 2019

       40,300      $ 52.14

April 2019

       39,000      $ 52.14

May 2019

       40,300      $ 52.14

June 2019

       39,000      $ 52.14

July 2019

       40,300      $ 52.14

August 2019

       40,300      $ 52.14

September 2019

       33,000      $ 57.92

October 2019

       33,300      $ 57.92

November 2019

       33,000      $ 57.92

December 2019

       33,300      $ 57.92

Crude Oil Option Contracts

         

January 2020—Call Option

       1,000      $ 56.40

January 2020—Put Option

       1,000      $ 50.00

February 2020—Call Option

       1,000      $ 56.40

February 2020—Put Option

       1,000      $ 50.00

March 2020—Call Option

       1,000      $ 56.40

March 2020—Put Option

       1,000      $ 50.00

April 2020—Call Option

       1,000      $ 60.95

April 2020—Put Option

       1,000      $ 50.00

May 2020—Call Option

       1,000      $ 60.95

May 2020—Put Option

       1,000      $ 50.00

June 2020—Call Option

       1,000      $ 60.95

June 2020—Put Option

       1,000      $ 50.00

 

(1)

Reference Price is NYMEX WTI Price, referring to the West Texas Intermediate crude oil price on the New York Mercantile Exchange.

The following table summarizes our historical derivative positions and the settlement amounts for each of the periods indicated.

 

    Historical Derivative Positions and Settlement Amounts  
    For the Nine Months Ended
June 30,
    For the Year Ended
September 30,
 
    2018     2017     2017     2016  

NYMEX WTI Crude Swaps (1):

       

Notional volume (MBbl)

    438       15       107       —    

Weighted average fixed price ($/Bbl)

  $ 51.79     $ 51.32     $ 49.37     $ —    

Total Amounts Received/(Paid) from Settlement (in thousands)

  $ (4,859   $ 92     $ 173     $ —    

 

(1)

NYMEX WTI refers to West Texas Intermediate crude oil price on the New York Mercantile Exchange.

 

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Principal Components of Our Cost Structure

Lease Operating Expenses. All direct and allocated indirect costs of lifting hydrocarbons from a producing formation to the surface constituting part of the current operating expenses of a working interest. Such costs, which include payroll for field personnel, saltwater disposal, electricity, generator rentals, diesel fuel and other operating expenses, are expensed as incurred and included in lease operating expenses in our consolidated statements of operations. Expenses for utilities, direct labor, water injection and disposal, workover rigs and workover expenses, materials and supplies comprise the most significant portion of our LOE. Certain items, such as direct labor and materials and supplies, generally remain relatively fixed across broad production volume ranges, but can fluctuate depending on activities performed during a specific period. For instance, repairs to our pumping equipment or surface facilities result in increased LOE in periods during which they are performed. Certain of our operating cost components are variable and increase or decrease as the level of produced hydrocarbons and water increases or decreases. For example, we incur power costs in connection with various production-related activities, such as pumping to recover oil and natural gas and separation and treatment of water produced in connection with our oil and natural gas production.

We monitor our operations to ensure that we are incurring LOE at an acceptable level. For example, we monitor our LOE per BOE to determine if any wells or properties should be shut in, recompleted or sold. This unit rate also allows us to monitor these costs in certain fields and geographic areas to identify trends and to benchmark against other producers. Although we strive to reduce our LOE, these expenses can increase or decrease on a per unit basis as a result of various factors as we operate our properties or make acquisitions and dispositions of properties. For example, we may increase field-level expenditures to optimize our operations, incurring higher expenses in one quarter relative to another, or we may acquire or dispose of properties that have different LOE per BOE. These initiatives would influence our overall operating cost and could cause fluctuations when comparing LOE on a period to period basis.

Production Taxes. Production taxes are paid on produced oil and natural gas based on a percentage of revenues from production sold at fixed rates established by federal, state or local taxing authorities. In general, the production taxes we pay correlate to the changes in oil and natural gas revenues. We are also subject to ad valorem taxes in the counties where our production is located. Ad valorem taxes are generally based on the valuation of our oil and natural gas properties.

Exploration Expenses. Exploration expenses are comprised primarily of impairments and abandonment of unproved properties, geological and geophysical expenditures, the cost to carry and retain unproved properties and exploratory dry hole costs.

Depletion, Depreciation, Amortization and Accretion. We use the successful efforts method of accounting for oil and natural gas activities and, as such, we capitalize all costs associated with our acquisition and development efforts and all successful exploration efforts, which are then allocated to each unit of production using the unit of production method.

Impairment of Long Lived Assets. Impairment of long lived assets are comprised primarily of impairment of proved oil and gas properties. We review our proved properties for impairment whenever events and changes in circumstances indicate that a decline in the recoverability of their carrying value may have occurred. See “—Critical Accounting Policies and Estimates” for further discussion. We have not realized any impairment charges for the periods indicated.

General and Administrative Expenses. These are costs incurred for overhead, including payroll and benefits for our corporate staff, costs of maintaining our headquarters, costs of managing our production and development operations including numerous software applications, audit and other fees for professional services and legal compliance.

Transaction Costs. Transaction expenses consists of cash transaction costs associated with investment banking, legal, accounting and other due diligence costs associated with the contributions of oil and gas properties and other acquisitions.

 

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Gain (Loss) on Derivative Instruments. We utilize commodity derivative contracts to reduce our exposure to fluctuations in the price of oil. None of our derivative contracts are designated as hedges for accounting purposes. Consequently, our derivative contracts are marked-to-market each period with fair value gains and losses recognized currently as a gain or loss in our results of operations. The amount of future gain or loss recognized on derivative instruments is dependent upon future oil prices, which will affect the value of the contracts. Cash flow is only impacted to the extent the actual settlements under the contracts result in making a payment to or receiving a payment from the counterparty.

Adjusted EBITDAX

We define Adjusted EBITDAX as net income (loss) adjusted for certain cash and non-cash items, including depreciation, depletion, amortization and accretion, or DD&A, impairment of long lived assets, provision for the carrying value of assets, exploration expenses, transaction expenses, commodity derivative (gain) loss, settlements on commodity derivatives, premiums paid for derivatives that settled during the period, unit-based compensation expense, amortization of debt discount and debt issuance costs, interest expense, income taxes, and non-recurring charges. Adjusted EBITDAX should not be considered as an alternative to, or more meaningful than, net income as determined in accordance with GAAP or as an indicator of our operating performance. Certain items excluded from Adjusted EBITDAX are significant components in understanding and assessing a company’s financial performance, such as a company’s cost of capital and tax structure, as well as the historic costs of depreciable assets and exploration expenses, none of which are components of Adjusted EBITDAX. Our computations of Adjusted EBITDAX may not be comparable to other similarly titled measures of other companies. For further discussion, please read “Summary—Summary Historical Financial Data—Non-GAAP Financial Measure.”

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

Our historical financial condition and results of operations for the periods presented may not be comparable, either from period to period or going forward, for the following reasons:

Contribution Transactions

Our financial statements reflect the operating results of the assets contributed by Boomer, Bluescape and DR/CM. These contributions occurred on January 17, 2017 for Boomer and March 6, 2017 in respect of Bluescape and DR/CM. For the periods prior to January 17, 2017, the consolidated financial statements and financial information contained in this prospectus have been prepared on a “carve-out” basis from the accounts of REG and reflect the historical accounts directly attributable to the Champions Assets owned by REG together with allocations and costs and expenses. See “—Overview” and “Prospectus Summary—Our Corporate History.”

As a result, the historical financial information presented in this prospectus may not give you an accurate indication of what our actual results would have been if those transactions had been completed at the beginning of each of the periods presented.

Derivative Activities

For the nine months ended June 30, 2018 our commodity hedging activities resulted in our recognizing a net $13.9 million derivative loss, comprised of a realized $4.9 million loss, compounded by a $9.0 million loss on market-to-market on unrealized contracts, due primarily to an increase in the volume of contracts and increasing crude oil future prices during that period. As commodity prices fluctuate, so will the income or loss we recognize from our hedging activities. For more information regarding our historic hedging activities, please see “—Overview—Derivative Arrangements.”

 

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Public Company Expenses

General and administrative expenses related to being a publicly traded company include: Exchange Act reporting expenses; expenses associated with Sarbanes-Oxley compliance; expenses associated with our prospective listing on a national securities exchange, such as the NYSE American; incremental independent auditor fees; incremental legal fees; investor relations expenses; registrar and transfer agent fees; incremental director and officer liability insurance costs; and director compensation. As a publicly traded company at the closing of this offering, we expect that general and administrative expenses will increase in future periods.

Income Taxes

Prior to our conversion into a corporation in connection with this offering, we were organized as a Delaware limited liability company and were treated as a flow-through entity for U.S. federal and state income tax purposes. As a result, our net taxable income and any related tax credits were passed through to the members and were included in their tax returns even though such net taxable income or tax credits may not have actually been distributed.

Historical Results of Operations and Operating Expenses

Revenues and Operating Expenses

The following table provides the components of our revenues, operating expenses, other income (expense) and net income (loss) for the periods indicated:

 

     For the Nine Months Ended
June 30,
    For the Years Ended
September 30,
 
     (unaudited)              
     2018     2017     2017     2016  
     ($ in Thousands, Except Unit and Per Unit Amounts)  

Statement of Operations Data:

        

Revenues:

        

Oil sales

   $ 46,438     $ 11,360     $ 21,174     $ 4,081  

Natural gas sales

     252       135       203       29  

Natural gas liquids sales

     909       262       431       20  
  

 

 

   

 

 

   

 

 

   

 

 

 

Total Revenues

     47,599       11,757       21,808       4,130  

Operating Expenses:

        

Lease operating expenses

     8,135       3,831       5,796       2,779  

Production taxes

     2,191       641       1,206       194  

Exploration expenses

     5,523       1,107       10,739       45  

Depletion, depreciation, amortization, and accretion

     11,388       3,268       5,876       1,366  

General and administrative expenses

     10,596       4,616       5,806       3,863  

Transaction Costs

     790       1,233       1,766       —    
  

 

 

   

 

 

   

 

 

   

 

 

 

Total Operating Expenses

     38,623       14,696       31,189       8,247  
  

 

 

   

 

 

   

 

 

   

 

 

 

Income (loss) from Operations:

   $ 8,976     $ (2,939   $ (9,381   $ (4,117

Other Expenses:

        

Interest Expense

     (907     —         —         —    

Gain (loss) on derivatives

     (13,895     752       (1,450     —    
  

 

 

   

 

 

   

 

 

   

 

 

 

Loss before Income Tax Provision

     (5,826     (2,187     (10,831     (4,117

Income Tax Expense

     —         —         —         9  
  

 

 

   

 

 

   

 

 

   

 

 

 

Net Loss

   $ (5,826   $ (2,187   $ (10,831   $ (4,126
  

 

 

   

 

 

   

 

 

   

 

 

 

Dividends on Preferred Units

     (2,327     (772     (1,409     —    
  

 

 

   

 

 

   

 

 

   

 

 

 

Net Loss Attributable to Common Units

   $ (8,153   $ (2,959   $ (12,240   $ (4,126
  

 

 

   

 

 

   

 

 

   

 

 

 

Loss per common unit per common unit:

        

Basic and Diluted

   $ (5.44   $ (2.86   $ (10.63   $ (7.20

Weighted average common units outstanding

     1,500,000       1,033,816       1,151,320       573,408  

 

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Production and Operating Data

The following table provides a summary of our sales volumes, average prices and operating expenses on a per BOE basis for the periods indicated:

 

     For the Nine Months Ended
June 30,
     For the Years Ended
September 30,
 
        2018            2017            2017            2016     

Total Sales Volumes:

           

Oil sales (MBbls)

     801        251        470        108  

Natural gas sales (MMcf)

     126        50        76        16  

Natural gas liquids sales (MBbls)

     34        13        21        1  
  

 

 

    

 

 

    

 

 

    

 

 

 

Total (MBoe)(1)

     856        272        504        112  

Daily Sales Volumes:

           

Oil sales (Bbl/d)

     2,934        919        1,291        297  

Natural gas sales (Mcf/d)

     462        183        209        44  

Natural gas liquids sales (Bbl/d)

     125        48        58        3  
  

 

 

    

 

 

    

 

 

    

 

 

 

Total (BOE/d)(1)

     3,136        998        1,384        308  

Average sales prices (1):

           

Oil sales (per Bbl)

   $ 57.98      $ 45.26      $ 45.05      $ 37.65  

Oil sales with derivative settlements (per Bbl)(2)

     51.91        45.63        45.42        37.65  

Natural gas sales (per Mcf)

     2.00        2.70        2.67        1.82  

Natural gas sales with derivative settlements (per Mcf)(2)

     2.00        2.70        2.67        1.82  

Natural gas liquids sales (per Bbl)

     26.74        20.15        20.52        15.88  

Natural gas liquids sales with derivative settlements (per Bbl)(2)

     26.74        20.15        20.52        15.88  

Average price per BOE excluding derivative settlements(2)

     55.61        43.22        43.30        36.77  

Average price per BOE with derivative settlements(2)

     49.93        43.56        43.64        36.77  

Expense per BOE (1):

           

Lease operating expenses

   $ 9.50      $ 14.08      $ 11.51      $ 24.74  

Production and ad valorem taxes

     2.56        2.36        2.39        1.73  

Exploration expenses

     6.45        4.07        21.32        0.40  

Depletion, depreciation, amortization, and accretion

     13.30        12.01        11.67        12.16  

General and administrative expenses

     12.38        16.97        11.53        34.40  

Transaction Costs

     0.92        4.53        3.51        —    

 

(1)

One BOE is equal to six Mcf of natural gas or one Bbl of oil or NGL based on an approximate energy equivalency. This is an energy content correlation and does not reflect a value or price relationship between the commodities.

(2)

Average prices shown in the table reflect prices both before and after the effects of our settlements of our commodity derivative contracts. Our calculation of such effects includes both gains or losses on cash settlements for commodity derivatives.

Results of Operations for the Nine Months Ended June 30, 2018 Compared to Nine Months Ended June 30, 2017

Revenue. Our total revenues increased 305%, or $35.8 million, to $47.6 million for the nine months ended June 30, 2018 as compared to total revenues of $11.8 million for the nine months ended June 30, 2017. The increase was mainly attributable to increased production volumes from our drilling program and higher commodity prices. The increase was also related to the contribution of the Champions Assets in the second quarter of our fiscal year 2017. See “Prospectus Summary—Overview” for a description of our increase in production resulting from the contribution of the Champions Assets and from the development of those acquired and contributed properties and our existing properties during the first nine months of fiscal 2018.

 

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Our revenues are primarily from the sale of crude oil. For the nine months ended June 30, 2018 and 2017, crude oil contributed to 97% of our total revenue in both periods. Our total sales volumes for the nine months ended June 30, 2018 was 856 MBoe compared with 272 MBoe for the nine months ended June 30, 2017. This represents a period over period increase of 215%, or 584 MBoe. We have grown our average net production from 998 Boe/d for the nine months ended June 30, 2017 to an average net production of 3,136 Boe/d for the nine months ended June 30, 2018, representing a 214% increase year over year. The increase is primarily due to the development of our properties and, to a lesser extent, contributions of the working interest in the Champions Assets by Boomer, Bluescape and DR/CM in January and March of 2017, respectively.

Lease operating expenses. Our LOEs increased by 112%, or $4.3 million, to $8.1 million for the nine months ended June 30, 2018, from $3.8 million for the nine months ended June 30, 2017. The increase was primarily attributable to higher production volumes from the Champions Assets as described above. On a per unit basis, LOE decreased from $14.08 per BOE for the nine months ended June 30, 2017 to $9.50 per BOE for the nine months ended June 30, 2018. This decrease in LOE per unit of $4.58 is primarily the result of investment in power infrastructure necessary to replace costly rental generators previously used to electrify our field operations, as well as the spreading of fixed costs over substantially higher production volumes.

Production taxes. Production taxes increased $1.6 million to $2.2 million during the nine months ended June 30, 2018 from $0.6 million during the nine months ended June 30, 2017 due to increased revenues resulting from higher production volumes and commodity prices.

Exploration costs. Our exploration costs were $5.5 million for the nine months ended June 30, 2018, as compared to $1.1 million for the nine months ended June 30, 2017 primarily as a result of our election to let a portion of our undeveloped leases expire; however, we subsequently entered into new leases with a portion of these landholders in later periods. We are actively attempting to enter into new leases with the remaining landholders. This resulted in exploration costs associated with writing off approximately 1,825 net mineral acres, which had an average book value of $2,964 per net mineral acre and capitalizing the costs associated with the new leases in subsequent periods.

Depletion, depreciation, amortization and accretion expense. Our depletion, depreciation, amortization and accretion expense, or DD&A, increased $8.1 million to $11.4 million for the nine months ended June 30, 2018 as compared to $3.3 million for the nine months ended June 30, 2017. This increase was due to higher production volumes for the nine months ended June 30, 2018 as compared to the nine months ended June 30, 2017. On a per unit basis, DD&A expense increased from $12.01 per BOE for the nine months ended June 30, 2017 to $13.30 per BOE for the nine months ended June 30, 2018. The per BOE increase was primarily attributable to the contribution of the Champions Assets in the second quarter of our fiscal year 2017 as described above.

Impairment of long lived assets. For the nine months ended June 30, 2018 and 2017, respectively, we did not recognize any impairment expense.

General and administrative expense. General and administrative, or G&A, expense increased by $6.0 million to $10.6 million for the nine months ended June 30, 2018 as compared to $4.6 million for the nine months ended June 30, 2017. This increase is primarily due to an increase in professional fees, software costs, and other required expenses, as well as a one time $4.0 million bonus to certain of our named executive officers. On a per unit basis, G&A expense decreased from $16.97 per BOE for the nine months ended June 30, 2017 to $12.38 per BOE for the nine months ended June 30, 2018. This per unit decrease was primarily attributable to higher production volumes.

Transaction costs: Transaction costs were $0.8 million for the nine months ended June 30, 2018 compared to $1.2 million for the nine months ended June 30, 2017. The decrease was due to fewer transactions pursued during the nine months ended June 30, 2018.

 

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Results of Operations for the Year Ended September 30, 2017 Compared to Year Ended September 30, 2016

Revenue. Our total revenues increased 428%, or $17.7 million, to $21.8 million for the year ended September 30, 2017 as compared to total revenues of $4.1 million for the year ended September 30, 2016. Approximately 63% of the increase, or $11.1 million, was attributable to the Champions Assets contributed to us in the second quarter of our fiscal year, increased production volumes from our drilling program which accounted for approximately 28% of the increase, or $4.9 million, and the remaining 9% was from the positive impact of higher commodity prices during the fiscal year 2017. See “Prospectus Summary—Overview” for a description of our increase in production resulting from the contribution of the Champions Assets and resulting from development of those acquired and contributed properties and our existing properties during fiscal year 2017.

Our revenues are primarily from the sale of crude oil. For the years ended September 30, 2017 and 2016, crude oil contributed to 97% and 99%, respectively, of our total revenue. Our total sales volumes for the fiscal year ended 2017 was 504 MBoe compared with 112 MBoe for the fiscal year ended 2016. This represents a year over year increase of 350%, or 392 MBoe. We have grown our average net production from 308 BOE/d for our fiscal year ended September 30, 2016 to an average net production of 1,384 BOE/d for our fiscal year ended September 30, 2017, representing a 349% increase year over year. Our average net production for the fourth quarter of fiscal 2017 was approximately 2,515 BOE/d. The annual volume increase is primarily due to the combination of the development of our properties and, to a lesser extent, contributions of the working interest in the Champions Assets by Boomer, Bluescape and DR/CM during the second quarter of fiscal 2017. As we had no additional significant contributions or acquisitions after the second quarter of fiscal 2017, our production growth after the second quarter of fiscal 2017 is primarily due to the results of our development program.

Lease operating expenses. Our LOEs increased by 108%, or $3.0 million, to $5.8 million for the year ended September 30, 2017, from $2.8 million for the year ended September 30, 2016. The year over year increase was primarily attributable to higher production volumes from the Champions Assets as described above. On a per unit basis, LOE decreased from $24.74 per BOE for the year ended September 30, 2016 to $11.51 per BOE for the year ended September 30, 2017. This decrease in LOE per unit of $13.23 is primarily the result of investment in power infrastructure necessary to replace costly rental generators previously used to electrify our field operations, as well as the spreading of fixed costs over substantially higher production volumes.

Production taxes. Production taxes increased $1.0 million to $1.2 million during the year ended September 30, 2017 from $0.2 million during the year ended September 30, 2016 due to increased revenues resulting from higher production volumes and commodity prices.

Exploration costs. Our exploration costs were $10.7 million for the year ended September 30, 2017, as compared to $0.04 million for the year ended September 30, 2016 primarily as a result of our election to let a portion of our undeveloped leases expire; however, we subsequently entered into new leases with a portion of these landholders in later periods. We are actively attempting to enter into new leases with the remaining landholders. This resulted in exploration costs associated with writing off approximately 2,995 net mineral acres, which had an average book value of $3,579 per net mineral acre and capitalizing the costs associated with the new leases in subsequent periods.

Depletion, depreciation, amortization and accretion expense. Our depletion, depreciation, amortization and accretion expense, or DD&A, increased $4.5 million to $5.9 million for the year ended September 30, 2017 as compared to $1.4 million for the year ended September 30, 2016. This increase was due to substantially higher production volumes for the year ended September 30, 2017 as compared to fiscal year ended September 30, 2016. On a per unit basis, DD&A expense decreased from $12.16 per BOE for the year ended September 30, 2016 to $11.67 per BOE for the year ended September 30, 2017.

Impairment of long lived assets. For the years ended September 30, 2017 and 2016, respectively, we did not recognize any impairment expense.

 

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General and administrative expense. General and administrative, or G&A, expense increased by $1.9 million to $5.8 million for the year ended September 30, 2017 as compared to $3.9 million for the year ended September 30, 2016. This increase is primarily due to the separation of Riley Permian from REG, resulting in the hiring of new employees, standalone office administration and other required expenses. On a per unit basis, G&A expense decreased from $34.40 per BOE for the year ended September 30, 2016 to $11.53 per BOE for the year ended September 30, 2017. This per unit decrease was primarily attributable to higher production volumes. Additionally, for the year ended September 30, 2016, the accompanying financial statements include expense allocations for certain functions provided by REG. These expenses have been allocated on the basis of direct usage when identifiable, with the remainder allocated proportionately using oil and natural gas sales as the determining metric. Management considers the basis on which the expenses have been allocated to reasonably reflect the utilization of services provided to or the benefit received during the periods presented herein.

Transaction costs. As part of the contribution transaction for the year ended September 30, 2017, we incurred $1.8 million of transaction costs for investment banking, legal and accounting fees. For the year ended September 30, 2016, there we did not incur any contribution transaction costs.

Liquidity and Capital Resources

Our development and acquisition activities require us to make significant operating and capital expenditures. Our primary use of capital has been for the exploration and development of our oil and gas properties, the supporting infrastructure to include the design and construction of a private gathering and saltwater disposal system, and the power distribution network. Historically, our primary sources of revolving liquidity have been equity provided by investors and cash flows from operations, as well as borrowing under our revolving credit facility. Going forward, we expect that our primary sources of liquidity and capital resources after the consummation of this offering will be net proceeds from the offering, cash flows generated by operating activities, as well as borrowings under our revolving credit facility. We may also fund our growth through subsequent equity or debt offerings when appropriate.

From our inception through June 30, 2018, we have raised an aggregate of $50 million of capital in exchange for our Series A Preferred Units from our existing investors, consisting of contributions by Yorktown of approximately $21.4 million, Bluescape of approximately $21.4 million and Boomer of approximately $7.2 million. The Series A Preferred Units were entitled to receive dividends of 6.0% per year, payable quarterly in kind by the issuance of additional Series A Preferred Units. Pursuant to the terms of our Corporate Conversion that will be completed at or prior to the closing of this offering, the Series A Preferred Units held by the existing investors will be converted into shares of our common stock. For information about conversion of our outstanding common units and Series A Preferred Units, see “Corporate Conversion.”

We plan to continue our practice of entering into hedging arrangements to reduce the impact of commodity price volatility on our cash flow from operations. Under this strategy, we expect to maintain an active hedging program which we believe will provide more certainty around our cash flow, returns and our ability to fund our capital program while also securing a portion of our borrowing base under our revolving credit facility.

Our fiscal 2019 capital budget is $103.6 million, of which approximately $90.7 million is allocated for drilling and completion activity for an estimated 36 gross (27 net) wells, approximately $6.3 million for continued infrastructure buildout (e.g. saltwater disposal and electrical infrastructure), approximately $3.6 million for capitalized workovers, and approximately $3.0 million for leasehold acquisition and renewal efforts. Our capital budget excludes any amounts that may be paid for future acquisitions.

During the fiscal year ended September 30, 2017, our aggregate capital expenditures were $52.6 million, of which approximately $36.8 million was for drilling and completion activity of which $24.1 million was for 18 gross (10 net) wells and the remaining $12.7 million was spent on drilling or completion activities associated with other wells such as saltwater disposal, drilled but uncompleted wells and other wells that were drilled in prior years and completed during fiscal year 2017, $11.1 million for infrastructure, $2.8 million for capitalized

 

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workovers, and $1.9 million for leasehold renewals and acquisitions. During the nine months ended June 30, 2018, our aggregate capital expenditures were $67.4 million, of which approximately $34.7 million was for drilling and completion activity, $4.3 million for capitalized workovers, $4.3 million for infrastructure, $4.4 million for leasehold acquisitions and renewal efforts, and $19.7 million for acquisition costs.

Because we operate a high percentage of our acreage, capital expenditure amounts and timing are largely discretionary and within our control. We determine our capital expenditures depending on a variety of factors, including, but not limited to, 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 working interest owners. A deferral of planned capital expenditures, particularly with respect to drilling and completing new wells, could result in a reduction in anticipated production and cash flows. Additionally, if we curtail our drilling program, we may lose a portion of our acreage through lease expirations. See “Business—Oil and Natural Gas Production Prices and Costs—Developed and Undeveloped Acreage.” In addition, we may be required to reclassify some portion of our reserves currently booked as proved undeveloped reserves to no longer be proved reserves if such a deferral of planned capital expenditures means we will be unable to develop such reserves within five years of their initial booking.

As of June 30, 2018, the borrowing base under our revolving credit facility was $100 million and we had borrowings outstanding of $44 million under our revolving credit facility. On September 14, 2018, a scheduled borrowing base redetermination was initiated and we expect such redetermination to be completed by early October. In the event that such redetermination results in an increase to our borrowing base amount, the Company may elect to accept the increase at that time. We intend to make such election no later than October 1, 2018. As of September 19, 2018, we had $53.6 million of outstanding borrowings and an additional $46.5 million available under our revolving credit facility and were in compliance with all applicable financial covenants. We may use a portion of the net proceeds from this offering to repay outstanding borrowings under our revolving credit facility.

If cash flow from operations does not meet our expectations, we may reduce our expected level of capital expenditures and/or fund a portion of our capital expenditures using borrowings under our revolving credit facility, issuances of debt and equity securities or from other sources, such as asset sales. We cannot assure you that necessary capital will be available on acceptable terms or at all. Our ability to raise funds through the incurrence of additional indebtedness are limited by the covenants in our revolving credit facility. 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 maintain our production or proved reserves.

Based upon our current oil and natural gas price expectations for 2018, following the closing of this offering, we believe that a portion of the proceeds from this offering, our cash flow from operations and borrowings under our revolving credit facility will provide us with sufficient liquidity through fiscal 2019. However, future cash flows are subject to a number of variables, including the level of oil and natural gas production and prices, and significant additional capital expenditures will be required to more fully develop our properties. If we require additional capital for capital expenditures, acquisitions or other reasons, we may seek such capital through traditional reserve base borrowings, and subject to covenants in our revolving credit facility, joint venture partnerships, production payment financings, asset sales, offerings of debt and equity securities or other means. If we are unable to obtain funds when needed or on acceptable terms, we may be required to curtail our current drilling program, which could 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 maintain our production or replace our reserves.

Working Capital

Our working capital, which we define as current assets minus current liabilities, totaled a deficit of $30.0 million at June 30, 2018. At September 30, 2017, we had a working capital deficit of approximately

 

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$7.1 million. We may incur additional working capital deficits in the future due to the amounts that accrue related to our drilling program. Our collection of receivables has historically been timely, and losses associated with uncollectible receivables have historically not been significant. Our cash and cash equivalents balance totaled approximately $1.0 million at June 30, 2018 and was $3.7 million at September 30, 2017, respectively. We expect that our cash flows from operating activities, availability under our revolving credit facility and the estimated net proceeds from this offering as described under “Use of Proceeds” will be sufficient to fund our working capital needs through fiscal 2019. We expect that our pace of development, production volumes, commodity prices and differentials to NYMEX prices for our oil and natural gas production will be the largest variables affecting our working capital. Please see “—Liquidity and Capital Resources” above for factors relating to liquidity and current expectations.

Cash Flows

The following table summarizes our cash flows for the periods indicated:

 

     For the Nine Months Ended
June 30,
    For the Years Ended
September 30,
 
     (unaudited)              
             2018                     2017             2017     2016  
     (in Thousands)  

Statement of Cash Flows Data:

        

Net cash provided by (used in) operating activities

   $ 22,093     $ (371   $ 3,289     $ (9,125

Net cash used in investing activities

   $ (67,444   $ (39,619   $ (54,781   $ (24,087

Net cash provided by financing activities

   $ 42,697     $ 45,210     $ 55,175     $ 33,212  

Nine Months Ended June 30, 2018 Compared to the Nine Months Ended June 30, 2017

Net cash provided by operating activities. Our net cash position provided by operating activities increased by $22.5 million for the nine months ended June 30, 2018 as compared to the nine months ended June 30, 2017, primarily due to higher prices and volumes.

Net cash used in investing activities. For the nine months ended June 30, 2018 as compared to the nine months ended June 30, 2017, our net cash used in investing activities increased by $27.8 million, primarily due to the Rockcliff Acquisition and higher capital expenditures.

Net cash provided by financing activities. For the nine months ended June 30, 2018 as compared to the nine months ended June 30, 2017, our net cash provided by financing activities decreased by $2.5 million, primarily due to net proceeds raised from the revolving credit facility of $43.1 million compared to net proceeds from issuance of Series A Preferred Units of $40.0 million and parent net investment of $5.2 million. See “—Liquidity and Capital Resources” above for a discussion of our capital structure.

Year Ended September 30, 2017 Compared to the Year Ended September 30, 2016

Net cash provided by operating activities. Our net cash position provided by operating activities increased by $12.4 million, primarily due to higher prices and volumes and favorable working capital adjustments.

Net cash used in investing activities. For the year ended September 30, 2017 as compared to the year ended September 30, 2016, our net cash used in investing activities increased by $30.7 million, of which $44.5 million was primarily due to higher capital expenditures from our higher working interest ownership in fiscal year 2017 offset by $13.8 million decrease in acquisition costs of oil and gas properties. As disclosed in Note 4 -Oil and Natural Gas Properties of our audited consolidated financial statements for the year ended September 30, 2017 and 2016, in April and December 2015, we incurred aggregate acquisition costs of $14 million as compared to $0.2 million acquisition costs incurred during the year ended September 30, 2017.

Net cash provided by financing activities. For the year ended September 30, 2017 as compared to the year ended September 30, 2016, our net cash provided by financing activities increased by $22.0 million, primarily

 

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due to net proceeds raised from the offering of our Series A Preferred Units of $49.8 million compared to REG’s net investment in 2016 of $33.2 million. See “—Liquidity and Capital Resources” above for a discussion of our offering in fiscal 2017 of our Series A Preferred Units.

Our Revolving Credit Facility

On September 28, 2017, we entered into a credit agreement (or credit agreement) with SunTrust Bank, as administrative agent and issuing lender, and the lenders named therein, that provides for a revolving credit facility (or our revolving credit facility) of up to $500 million (subject to the borrowing base) secured by substantially all of the Company’s assets. As of June 30, 2018, the borrowing base under our revolving credit facility was $100 million and we had $44 million of outstanding borrowings under our revolving credit facility. Since June 30, 2018, we borrowed an additional $9.5 million. As of September 19, 2018, we had $53.6 million of outstanding borrowings and an additional $46.5 million available under our revolving credit facility and were in compliance with all applicable financial covenants. We intend to use a portion of the net proceeds of this offering to repay outstanding borrowings under our revolving credit facility. Our revolving credit facility’s stated maturity date is on September 28, 2021.

The amount available to be borrowed under our revolving credit facility is subject to a borrowing base that is redetermined semiannually each February 1 and August 1, and additionally during the initial year of the facility on May 1, 2018, by the lenders at their sole discretion. In connection with the May 1 borrowing base redetermination date, we elected to increase the borrowing base from $60 million to $100 million effective as of May 25, 2018. On September 14, 2018, a scheduled borrowing base redetermination was initiated and we expect such redetermination to be completed in early October. In the event that such redetermination results in an increase to our borrowing base amount, the Company may elect to accept the increase at that time. Additionally, at our option, we may request an additional redetermination each six-month period between each of February 1 and August 1. The borrowing base depends on, among other things, the volumes of our proved reserves and estimated cash flows from these reserves and our commodity hedge positions as well as any other outstanding debt. Upon a redetermination of the borrowing base, if borrowings in excess of the revised borrowing capacity are outstanding, we could be required to repay a portion of the debt outstanding or provide additional collateral under our credit agreement. We are also required to repay debt outstanding under our credit agreement to the extent that, following the application of cash used for specified circumstances, the amount of our consolidated cash balance exceeds the greater of $10 million and 15% of our borrowing base applicable at that time, for a period of five consecutive business days.

We pay a commitment fee on unused amounts of our revolving credit facility of between 0.375% and 0.500% per annum, depending on the utilization percentage of our borrowing base. We may repay any amounts borrowed prior to the maturity date without any premium or penalty other than customary LIBOR breakage costs.

Our credit agreement contains restrictive covenants that limit our ability to, among other things:

 

   

incur additional indebtedness and certain types of preferred equity;

 

   

incur liens;

 

   

merge or consolidate with another entity or acquire subsidiaries;

 

   

make investments;

 

   

make loans to others;

 

   

make certain payments;

 

   

sell assets;

 

   

terminate hedging transactions;

 

   

enter into transactions with affiliates;

 

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enter into restrictive agreements relating to subsidiaries or the incurrence of liens;

 

   

enter into sale and leaseback transactions;

 

   

hedge interest rates;

 

   

amend our material documents or make significant accounting changes;

 

   

enter into certain leases above $1 million on an annual basis (other than certain capital leases);

 

   

enter into certain contracts for the sale of hydrocarbons, or certain prepayments; and

 

   

engage in certain other transactions without the prior consent of the lenders.

Our credit agreement also requires us to maintain cash balances below certain specified threshold amounts and to maintain compliance with the following financial ratios:

 

   

a current ratio, which is the ratio of our consolidated current assets (including unused commitments under our revolving credit facility and excluding derivatives) to our consolidated current liabilities (excluding the current portion of long-term indebtedness required to be paid within one year and the aggregate principal balance of loans and letters of credit under our credit agreement and derivatives), as of the last day of each fiscal quarter, of not less than 1.0 to 1.0; and

 

   

a leverage ratio, which is the ratio of our consolidated total debt (as defined in our credit agreement) as of the last day of each fiscal quarter, less cash and cash equivalents of up to $5 million beginning April 1, 2018, subject to certain exclusions (as described in our credit agreement) to consolidated EBITDAX (as defined in our credit agreement) for the last four consecutive fiscal quarters ending on or immediately prior to the last day of that fiscal quarter, of not greater than 4.0 to 1.0.

Further, under our credit agreement, we are only permitted to hedge up to 85% of our reasonably anticipated production of each of oil, natural gas and NGLs for up to 24 months in the future, and up to 75% of our reasonably anticipated production of each of oil, natural gas and NGLs for 25 to 48 months in the future. We are also required to hedge a minimum of 45% of our projected oil and natural gas volumes from PDP reserves on a 24 month rolling basis. In respect of interest rate hedging from floating to a fixed rate, under our credit agreement, we are only permitted to hedge up to 75% of our then outstanding principal indebtedness for borrowed money that bears interest at a floating rate and that hedge transaction cannot have a maturity date beyond the indebtedness’ maturity date.

Contractual Obligations

A summary of our contractual obligations as of September 30, 2017 is provided in the following table (in thousands):

 

     Payments due by Period  
     Total      Less than 1
Year
     1-3
Years
     3-5
Years
     More than 5
Years
 
     (unaudited)  

Contractual Obligations

              

Office lease(1)

   $ 1,130.0      $ 229.2      $ 472.3      $ 428.5      $ —    

Notes Payable(2)

              

Insurance

   $ 76.7      $ 76.7      $ —        $ —        $ —    

Vehicles

   $ 142.1      $ 38.5      $ 77.1      $ 26.5      $ —    
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total

   $ 1,348.8      $ 344.4      $ 549.4      $ 455.0      $ —    
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

 

(1)

We lease office headquarters under a five-year operating lease agreement terminating in July 2022. Base rent is subject to a two percent (2%) escalation in each subsequent year.

(2)

We finance certain vehicles used in field operations and financed the premiums for certain components of our commercial insurance package. Vehicle notes payable of $142.1 are based on 48-month terms beginning

 

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  in May 2017, with an average interest rate of 4.83%. Vehicle notes were paid in full on July 16, 2018. Insurance notes payable of $76.7 is based on 10-month terms beginning in June 2017 and is subject to an interest rate of 4.19%.

As of June 30, 2018, we had $44 million of outstanding borrowings under our revolving credit facility. As of September 19, 2018, we had $53.6 million of outstanding borrowings and an additional $46.5 million available under our revolving credit facility. We intend to use a portion of the net proceeds from this offering to repay borrowings under our revolving credit facility. Please see “Use of Proceeds.”

The above contractual obligations schedule does not include this offering, future anticipated settlement of derivative contracts or estimated amounts expected to be incurred in the future associated with the abandonment of our oil and gas properties, as we cannot determine with accuracy the timing of such payments. For further discussion regarding our derivative contracts and estimated future costs associated with the abandonment of our oil and gas properties, please refer to Note 3—Summary of Significant Accounting Policies under section Derivative Contracts and Asset Retirement Obligations of our historical audited financial statements for the years ended September 30, 2017 and 2016 and to Note 9—Asset Retirement Obligations and Note 10—Derivative Contracts of our unaudited financial statements for the nine months ended June 30, 2018. Additionally, for further information regarding our contractual obligations as of June 30, 2018, please refer to Note 16—Commitments and Contingencies to our unaudited financial statements for the nine months ended June 30, 2018.

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, natural gas and NGL prices and interest rates. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. All of our market risk sensitive instruments were entered into for purposes other than speculative trading.

Commodity Price Risk

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

During the period from January 1, 2014 through June 30, 2018, 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 $8.15 per MMBtu on February 10, 2014 to a low of $1.49 per MMBtu on March 4, 2016. The prices we receive for our oil, natural gas and NGLs production depend on numerous factors beyond our control, some of which are discussed in “Risk Factors—Risks Related to Our Business—Oil, natural gas and NGL prices are volatile. An extended decline in commodity prices may adversely affect our business, financial condition, or results of operations and our ability to meet our capital expenditure obligations and financial commitments. Additionally, the value of our reserves calculated using SEC pricing may be higher than the fair market value of our reserves calculated using current market prices.”

As of June 30, 2018, a $1.00 per barrel change in our realized oil price would have resulted in a $0.8 million change in oil revenues and a $0.15 per Mcf change in our realized natural gas price would have resulted in a de minimis change in our natural gas revenues for fiscal 2018. And likewise, a $1.00 per barrel change in NGL prices would have resulted in a de minimis change to our NGL revenue. Oil sales contributed 97% of our total revenues, while natural gas sales contributed 1% and NGL sales contributed 2% of our total revenues for the nine months ended June 30, 2018. Our oil, natural gas and NGL revenues do not include the effects of derivatives.

 

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Due to this volatility, we have historically used, and we expect to continue to use, commodity derivative instruments, such as swaps, as well as collars and puts, to hedge price risk associated with a portion of our anticipated production. Our hedging instruments allow us to reduce, but not eliminate, the potential effects of the variability in cash flow from operations due to fluctuations in oil and natural gas prices and provide increased certainty of cash flows for our drilling program and debt service requirements. These instruments provide only partial price protection against declines in oil and natural gas prices and may partially limit our potential gains from future increases in prices. Under our credit agreement, we are only permitted to hedge up to 85% of our reasonably anticipated production of each of oil, natural gas and NGLs for up to 24 months in the future, and up to 75% of our reasonably anticipated production of each of oil, natural gas and NGLs for 25 to 48 months in the future. We are currently required to hedge a minimum of 45% of our reasonably anticipated projected net oil and natural gas volumes from PDP reserves on a 24 month rolling basis. See “—Liquidity and Capital Resources—Our Revolving Credit Facility” above, for more information.

The table below presents our open hedge positions as of June 30, 2018:

 

Description & Production Period              
Crude Oil Swaps    Volumes (Bbl)      Swap Price (Bbl)(1)  

July 2018

     59,600      $ 54.42  

August 2018

     59,600      $ 54.42  

September 2018

     58,000      $ 54.49  

October 2018

     59,600      $ 54.42  

November 2018

     58,000      $ 54.49  

December 2018

     50,300      $ 54.88  

January 2019

     40,300      $ 52.14  

February 2019

     36,400      $ 52.14  

March 2019

     40,300      $ 52.14  

April 2019

     39,000      $ 52.14  

May 2019

     40,300      $ 52.14  

June 2019

     39,000      $ 52.14  

July 2019

     40,300      $ 52.14  

August 2019

     40,300      $ 52.14  

September 2019

     33,000      $ 57.92  

October 2019

     33,300      $ 57.92  

November 2019

     33,000      $ 57.92  

December 2019

     33,300      $ 57.92  

Crude Oil Option Contracts

     

January 2020—Call Option

     1,000      $ 56.40  

January 2020—Put Option

     1,000      $ 50.00  

February 2020—Call Option

     1,000      $ 56.40  

February 2020—Put Option

     1,000      $ 50.00  

March 2020—Call Option

     1,000      $ 56.40  

March 2020—Put Option

     1,000      $ 50.00  

April 2020—Call Option

     1,000      $ 60.95  

April 2020—Put Option

     1,000      $ 50.00  

May 2020—Call Option

     1,000      $ 60.95  

May 2020—Put Option

     1,000      $ 50.00  

June 2020—Call Option

     1,000      $ 60.95  

June 2020—Put Option

     1,000      $ 50.00  

 

(1)

Reference Price is NYMEX WTI Price, referring to the West Texas Intermediate crude oil price on the New York Mercantile Exchange.

Counterparty and Customer Credit Risk

Our cash and cash equivalents are exposed to concentrations of credit risk. We manage and control this risk by investing these funds with major financial institutions. We often have balances in excess of the federally insured limits.

 

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Our derivative contracts expose us to credit risk in the event of nonperformance by counterparties. While we do not require counterparties to our derivative contracts to post collateral, we do evaluate the credit standing of such counterparties as we deem appropriate. The counterparties to our derivative contracts currently in place have investment grade ratings.

Our principal exposures to credit risk are through receivables resulting from joint interest receivables and receivables from the sale of our oil and natural gas production due to the concentration of our oil and natural gas receivables with several significant customers. 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.

Joint operations receivables arise from billings to entities that own partial interests in the wells we operate. These entities participate in our wells primarily based on their ownership in leases on which we intend to drill. We have little ability to control whether these entities will participate in our wells.

Interest Rate Risk

At June 30, 2018, we had $44 million outstanding under our revolving credit facility. Interest is calculated under the terms of our credit agreement based on the greatest of certain specified base rates plus an applicable margin that varies based on utilization. As referenced in “Use of Proceeds,” as of September 19, 2018, we had $53.6 million of outstanding borrowings and an additional $46.5 million available under our revolving credit facility. We do not currently have any derivative arrangements to protect against fluctuations in interest rates applicable to our indebtedness.

Critical Accounting Policies and Estimates

The discussion and analysis of our financial condition and results of operations are based upon our consolidated and combined financial statements, which have been prepared in accordance with GAAP. The preparation of financial statements requires us to make estimates and assumptions that affect the amounts reported in the consolidated financial statements and accompanying notes. These estimates and assumptions may also affect disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The consolidated financial statements are based on a number of significant estimates, including oil and natural gas revenues, accrued assets and liabilities, and oil and natural gas reserves. The estimates of oil and natural gas reserves quantities and future net cash flows are the basis for the calculation of depletion and impairment of oil and natural gas properties, as well as estimates of asset retirement obligations and certain tax accruals.

Changes in facts and assumptions or the discovery of new information may result in revised estimates. Actual results could differ from these estimates and assumptions used in preparation of our consolidated financial statements and it is at least reasonably possible these estimates could be revised in the near term, and these revisions could be material.

The preparation of our financial statements requires us to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and related disclosure of contingent assets and liabilities. Certain accounting policies involve judgments and uncertainties to such an extent that there is reasonable likelihood that materially different amounts could have been reported under different conditions, or if different assumptions had been used. We evaluate our estimates and assumptions on a regular basis. We base our estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Significant areas requiring the use of assumptions, judgments and estimates include (1) oil and gas reserves; (2) cash flow estimates used in impairment testing of oil and gas properties; (3) depreciation, depletion, amortization and accretion, or DD&A; (4) asset retirement obligations; (5) assigning fair value and allocating purchase price in connection with business combinations; (6) accrued revenue and related receivables; (7) valuation of commodity derivative instruments; (8) accrued

 

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liabilities; and (9) deferred income tax liabilities. Actual results may differ from these estimates and assumptions used in preparation of our consolidated and combined financial statements. See Note 3 of the notes to the audited financial statements for the year ended September 30, 2017 and the unaudited financial statements for the nine months ended June 30, 2018, respectively, included elsewhere in this prospectus for an expanded discussion of our significant accounting policies and estimates by our management.

Successful Efforts Method of Accounting

Our oil and natural gas exploration and developments costs are accounted for using the successful efforts method. Under the successful efforts method, all costs incurred related to the acquisition of oil and natural gas properties and the costs of drilling development wells and successful exploratory wells are capitalized, while the costs of unsuccessful exploratory wells are expensed if and when the well is determined not to have found reserves in commercial quantities. Other items charged to expenses generally include geological and geophysical costs, delay rentals and lease and well operating costs.

Capitalized leasehold costs attributable to proved properties are depleted using the units-of-production method based on proved reserves on a field basis. Capitalized well costs, including asset retirement obligations, are depleted based on proved developed reserves on a field basis.

Proved Oil and Natural Gas Properties. Capitalized leasehold costs attributable to proved properties are depleted using the units-of-production method based on proved reserves on a field basis. Capitalized well costs, including asset retirement obligations, are depleted based on proved developed reserves on a field basis.

Unproved Properties. Unproved oil and natural gas properties consist of costs to acquire undeveloped leases and unproved reserves and are capitalized when incurred. When a successful well is drilled on undeveloped leasehold or reserves are otherwise attributable to a property, unproved property costs are transferred to proved properties.

Exploration Costs. Exploration costs consist of costs incurred to identify and evaluate areas that are prospective for oil and natural gas reserves. Exploration costs include geological and geophysical costs, delay rentals, expired leasehold and unsuccessful exploratory wells.

Exploratory Well Costs. Exploratory well costs are capitalized as incurred pending determination of whether the well has discovered proved commercial reserves. If the exploratory well is determined to be unsuccessful, the cost of the well is transferred to expense.

Impairment of Oil and Natural Gas Properties

Proved oil and natural gas properties are reviewed for impairment when events and circumstances indicate a possible decline in the recoverability of the carrying amount of such property. We estimate the expected future cash flows of oil and natural gas properties and compare these undiscounted cash flows to the carrying amount of the oil and natural gas properties to determine if the carrying amount is recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, we will write down the carrying amount of the oil and natural gas properties to fair value. The factors used to determine fair value include, but are not limited to, estimates of reserves, future commodity prices, future production estimates, cash flow from commodity hedges, estimated future capital expenditures and a commensurate discount rate.

Unproved properties are periodically assessed for impairment on a property-by-property basis. We evaluate significant unproved properties for impairment based on remaining lease term, drilling results, reservoir performance, seismic interpretation or future plans to develop acreage, and record impairment expense for any decline in value.

Oil and Natural Gas Reserve Quantities

We engage NSAI, our independent petroleum engineer, to prepare our total estimated proved, probable and possible reserves. We expect reserve estimates will change as additional information becomes available and as

 

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commodity prices and operating and capital costs change. We evaluate and estimate our proved reserves each year-end. For purposes of depletion and impairment, reserve quantities are adjusted in accordance with GAAP for the impact of additions and dispositions. Reserve estimates are inherently imprecise. Accordingly, the estimates are expected to change as more current information becomes available. It is possible that, because of changes in market conditions or the inherent imprecision of reserve estimates, the estimates of future cash inflows, future gross revenue, the amount of oil and natural gas reserves, the remaining estimated lives of oil and natural gas properties or any combination of the above may be increased or reduced. Increases in recoverable economic volumes generally reduce per unit depletion rates while decreases in recoverable economic volumes generally increase per unit depletion rates.

Derivative Instruments

We utilize commodity derivative instruments to manage our exposure to commodity price volatility. All our commodity derivative instruments are utilized to manage price risk attributable to our expected production, and we do not enter into such instruments for speculative trading purposes. We do not designate any derivative instruments as cash flow hedges for financial reporting purposes. We record all derivative instruments on the balance sheet as either assets or liabilities measured at their estimated fair value. We record gains and losses from the change in fair value of derivative instruments in current earnings as they occur. We do not currently utilize any derivative instruments to manage exposure to variable interest rates but may do so in the future.

Depreciation, Depletion, Amortization and Accretion

Our rate of Depreciation, Depletion, Amortization and Accretion, or rate of DD&A, is dependent upon our estimates of total proved and proved developed reserves, which incorporate various assumptions and future projections. If our estimates of total proved or proved developed reserves decline, the rate at which we record DD&A expense increases, which in turn reduces our net income. Such a decline in reserves may result from lower commodity prices or other changes to reserve estimates, as discussed above, and we are unable to predict changes in reserve quantity estimates as such quantities are dependent on the success of our exploration and development program, as well as future economic conditions.

Asset Retirement Obligations

Our asset retirement obligations, or ARO, consist of estimated future costs associated with the plugging and abandonment of oil, natural gas and NGL wells, removal of equipment and facilities from leased acreage and land restoration in accordance with applicable local, state and federal laws. The fair value of an ARO liability is required to be recognized in the period in which it is incurred, with the associated asset retirement cost capitalized as part of the carrying cost of the oil and gas asset. The recognition of an ARO requires that management make numerous assumptions regarding such factors as the estimated probabilities, amounts and timing of settlements; the credit-adjusted risk-free discount rate to be used; inflation rates; and future advances in technology. In periods subsequent to the initial measurement of the ARO, we must recognize period-to-period changes in the liability resulting from the passage of time and revisions to either the timing or the amount of the original estimate of undiscounted cash flows. Increases in the ARO liability due to the passage of time impact net income as accretion expense. The related capitalized cost, including revisions thereto, is charged to expense through DD&A over the life of the oil and gas property.

Income Taxes

Prior to our conversion into a corporation in connection with this offering, we were organized as a Delaware limited liability company and were treated as a flow-through entity for U.S. federal and state income tax purposes. As a result, our net taxable income and any related tax credits were passed through to the members and were included in their tax returns even though such net taxable income or tax credits may not have actually been distributed.

 

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Recently Issued Accounting Pronouncements

The accounting standard-setting organizations frequently issue new or revised accounting rules. We regularly review new pronouncements to determine their impact, if any, on our financial statements.

The Company is an “emerging growth company,” as defined in Section 2(a) of the Securities Act of 1933, as amended, or the Securities Act, as modified by the JOBS Act, and it may take advantage of certain exemptions from various reporting requirements that are applicable to other public companies that are not emerging growth companies including, but not limited to, 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 its periodic reports and proxy statements, and exemptions from the requirements of holding a nonbinding advisory vote on executive compensation and shareholder approval of any golden parachute payments not previously approved.

Further, Section 102(b)(1) of the JOBS Act exempts emerging growth companies from being required to comply with new or revised financial accounting standards until private companies (that is, those that have not had a Securities Act registration statement declared effective or do not have a class of securities registered under the Exchange Act) are required to comply with the new or revised financial accounting standards. The JOBS Act provides that a company can elect to opt out of the extended transition period and comply with the requirements that apply to non-emerging growth companies but any such election to opt out is irrevocable. The Company has elected to rely on such extended transition period, which means that when a standard is issued or revised, and it has different application dates for public or private companies, the Company, as an emerging growth company, can adopt the new or revised standard at the time private companies adopt the new or revised standard. This may make comparison of the Company’s financial statements with another public company which is neither an emerging growth company nor an emerging growth company which has opted out of using the extended transition period difficult or impossible because of the potential differences in accounting standards used.

In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers (Topic 606) (“ASU 2014-09”). The new standard will replace most existing revenue recognition guidance in U.S. GAAP. The core principle of ASU 2014-09 requires companies to reevaluate when revenue is recorded on a transaction based upon newly defined criteria, either at a point in time or over time as goods or services are delivered. The ASU requires additional disclosure about the nature, amount, timing and uncertainty of revenue and cash flows arising from customer contracts, including significant judgments and estimates, and changes in those estimates. In early 2016, the FASB issued additional guidance: ASU No. 2016-10, 2016-11 and 2016-12 (and together with ASU 2014-09, “Revenue Recognition ASU”). These updates provide further guidance and clarification on specific items within the previously issued ASU 2014-09. As an emerging growth company, the Revenue Recognition ASU becomes effective for the Company for the annual period beginning after December 31, 2018, with the option to early adopt the standard for annual periods beginning on or after December 15, 2017 and allows for both retrospective and modified-retrospective methods of adoption. The Company does not plan to early adopt the standard. We are continuing to evaluate the impact of this new standard and are in the process of implementing our plan.

In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842) (“ASU 2016-02”), which amends the accounting standards for leases. ASU 2016-02 retains a distinction between finance leases and operating leases. The primary change is the recognition of lease assets and lease liabilities by lessees for those leases classified as operating leases on the balance sheet. The classification criteria for distinguishing between finance leases and operating leases are substantially similar to the classification criteria for distinguishing between capital leases and operating leases in the previous guidance. Certain aspects of lease accounting have been simplified and additional qualitative and quantitative disclosures are required along with specific quantitative disclosures required by lessees and lessors to meet the objective of enabling users of financial statements to assess the amount, timing, and uncertainty of cash flows arising from leases. In transition, lessees and lessors are required to recognize and measure leases at the beginning of the earliest period presented using a modified retrospective approach. As an emerging growth company, the amendments are effective for fiscal years beginning after December 15, 2019, including interim periods within fiscal years beginning after December 15,

 

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2020, with early application permitted. We are required to use a modified retrospective approach for leases that exist or are entered into after the beginning of the earliest comparative period presented in the financial statements. Assuming adoption October 1, 2020, we expect that leases in effect on October 1, 2020 and leases entered into after such date will be reflected in accordance with the new standard in the audited consolidated financial statements for the year ended September 30, 2021, including comparative financial statements presented in such report. We are in the preliminary stages of our gap assessment. We are continuing to evaluate the impact of this new standard and are in the process of developing our implementation plan.

In June 2016, the FASB issued ASU No. 2016-13, Financial Instruments—Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments (“ASU 2016-13”) related to the calculation of credit losses on financial instruments. All financial instruments not accounted for at fair value will be impacted, including our trade and partner receivables. Allowances are to be measured using a current expected credit loss model as of the reporting date which is based on historical experience, current conditions and reasonable and supportable forecasts. This is significantly different from the current model which increases the allowance when losses are probable. As an emerging growth company, this change is effective for fiscal years beginning after December 15, 2020, and for interim periods within fiscal years beginning after December 15, 2021 and will be applied with a cumulative-effect adjustment to retained earnings as of the beginning of the first reporting period in which the guidance is effective. We are currently evaluating the provisions of ASU 2016-13 and are assessing its potential impact on our financial position, results of operations, cash flows and related disclosures.

In August 2016, the FASB issued ASU No. 2016-15, Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments (“ASU 2016-15”) related to how certain cash receipts and payments are presented and classified in the statement of cash flows. These cash flow issues include debt prepayment or extinguishment costs, settlement of zero-coupon debt, contingent consideration payments made after a business combination, proceeds from the settlement of insurance claims, distributions received from equity method investees, beneficial interests in securitization transactions, and separately identifiable cash flows. As an emerging growth company, ASU 2016-15 is effective for fiscal years beginning after December 15, 2018, and interim periods within fiscal years beginning after December 15, 2019. We are currently evaluating the provisions of this guidance and are assessing its potential impact on our cash flows and related disclosures. Due to the nature of this accounting standards update, this may have an impact on items reported in our statements of cash flows, but no impact is expected on our financial position, results of operations or related disclosures as a result of implementation.

In January 2017, the FASB issued ASU No. 2017-01, Business Combinations (Topic 805): Clarifying the Definition of a Business (ASU 2017-01”). The purpose of the amendment is to clarify the definition of a business with the objective of adding guidance to assist entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. As an emerging growth company, the amendments in ASU 2017-01 are effective for annual reporting periods beginning after December 15, 2018, and interim periods with annual periods beginning after December 15, 2019. The amendments in this update are to be applied prospectively to acquisitions and disposals completed on or after the effective date, with no disclosures required at transition. The adoption of ASU 2017-01 could have a material impact on our financial position, results of operations, cash flows and related disclosures. The Company elected to early adopt this ASU in connection with the Rockcliff Acquisition and has accounted for the transaction as an asset acquisition. See Note 4 – Acquisitions of the unaudited financial statements for the nine months ended June 30, 2018 included elsewhere in this prospectus for further detail.

In February 2017, the FASB issued ASU No. 2017-05, which provided clarification regarding the guidance on accounting for the derecognition of nonfinancial assets. For public entities, the new guidance is effective for fiscal years beginning after December 15, 2017, including interim reporting periods within that fiscal year. The Company is currently evaluating the impact of adopting this ASU, however it is not expected to have a significant effect on its consolidated financial statements and related disclosures.

In May 2017, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2017-09, which provides clarification and reduces both (1) diversity in practice and (2) cost and

 

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complexity when applying the guidance in Topic 718 Compensation—Stock Compensation, to a change to the terms or conditions of a share-based payment award. For public entities, the new guidance is effective for fiscal years beginning after December 15, 2017, including interim reporting periods within that reporting period. Early adoption is permitted for fiscal years beginning after December 15, 2016, including the interim reporting periods within that fiscal year. The Company is currently evaluating the impact of adopting this ASU, however it is not expected to have a significant effect on its consolidated financial statements and related disclosures.

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.

We and our independent registered public accounting firm have identified material weaknesses in our internal control over financial reporting as of September 30, 2017. A “material weakness” is a deficiency, or combination of deficiencies, in internal control over financial reporting such that there is a reasonable possibility that a material misstatement of the annual or interim financial statements will not be prevented or detected on a timely basis.

The material weakness identified relates to the lack of a sufficient complement of qualified personnel within our accounting and finance department who possess an appropriate level of expertise, experience and training commensurate with our corporate structure and financial reporting requirements to: (i) maintain effective controls over accounting for non-routine and/or complex transactions, and (ii) maintain effective controls over the financial statement close and reporting processes. We have begun to remediate and plan to further remediate this material weakness primarily by implementing additional review procedures within our accounting and finance department, hiring additional staff and, if appropriate, engaging external accounting experts with the appropriate knowledge to supplement our internal resources in our computation and review processes. These actions and planned actions are subject to ongoing management review. Although we believe we are addressing the internal control deficiencies that led to the material weakness, the measures we have taken and will take may not be effective. Consequently, if this or another material weakness or significant deficiencies occur in the future, it could affect the financial results that we report which could result in a restatement of our financial statements or cause us to fail to meet our reporting obligations.

Inflation

Inflation in the United States has been relatively low in recent years and did not have a material impact on our results of operations for the nine months ended June 30, 2018 or the year ended September 30, 2017. Although the impact of inflation has been insignificant in recent years, it is still a factor in the United States economy and we tend to experience inflationary pressure on the cost of oilfield services and equipment as increasing oil and natural gas prices increase drilling activity in our areas of operations.

Off-Balance Sheet Arrangements

We lease our office headquarters under a five-year operating lease agreement terminating in July 2022. Base rent for the first year of the lease is $0.2 million annually, with each subsequent year being subject to a two percent (2%) escalation. Additionally, we lease certain common office equipment of nominal amounts.

 

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BUSINESS

The following discussion should be read in conjunction with the “Selected Historical Financial Data” and the accompanying financial statements and related notes included elsewhere in this prospectus.

References to our estimated reserves are derived from our reserve report as of September 30, 2017 prepared by Netherland, Sewell & Associates, Inc., or NSAI, and referred to as the NSAI Report.

Overview

We are a growth-oriented, independent oil and natural gas company focused on rapidly growing our reserves, production and cash flow through the acquisition, exploration, development and production of oil, natural gas, and natural gas liquids, or NGLs, reserves in the Permian Basin. This basin, which is one of the major producing basins in the United States, is characterized by an extensive production history, a favorable operating environment, established infrastructure, long reserve life, multiple producing horizons, significant oil in place and a large number of operators. Our activities are primarily focused on the San Andres Formation, a shelf margin deposit on the Central Basin Platform and Northwest Shelf, which accounts for approximately 24% of the nearly 30 billion barrels of oil historically produced from the Permian Basin and where horizontal production has increased by more than 425% since January 2014.

We were formed with the goal of building a premier Permian Basin pure-play acquisition, exploration and development company, focusing on opportunities (i) with favorable reservoir and geological characteristics primarily for oil development, (ii) that offer large contiguous acreage positions with significant untapped potential in terms of ultimate recoverable reserves and (iii) with a high degree of operational control, which allows us to execute our development plan based on projected well performance and commodity price forecasts in order to attempt to rapidly grow our cash flow and generate significant equity returns from our capital program. We believe these characteristics enhance our horizontal production capabilities, recoveries and commercial outcomes.

Our acreage is primarily located on large, contiguous blocks in Yoakum County, Texas and Lea, Roosevelt, and Chaves Counties, New Mexico, focused on the San Andres Formation on the Northwest Shelf. Our assets offset legacy Permian Basin San Andres fields, to include the Wasson and Brahaney Fields, which have produced more than 2.1 billion barrels of oil and 108 million barrels of oil, respectively, from the San Andres Formation since development in the area began in the 1930’s and 1940’s. Based on the close proximity to these productive fields, combined with the horizontal San Andres wells we have drilled to date and the wells drilled by offset operators, we believe we have significantly delineated our acreage.

Since we commenced operations, our management and technical teams have successfully executed our development program and expanded our acreage position from 19,893 as of September 30, 2017, to approximately 65,839 net acres as of June 30, 2018. We have grown our average net production from 308 BOE/d for our fiscal year ended September 30, 2016 to an average net production of 1,384 BOE/d for our fiscal year ended September 30, 2017, representing a 349% increase year over year. Our average net production for the first nine months of fiscal 2018 was approximately 3,136 BOE/d. The annual volume increase is primarily due to the development of our properties and, to a lesser extent, contributions of the Champions Assets during the second quarter of fiscal 2017. See “Prospectus Summary—Our Corporate History” for more information relating to these contributions. As we had no additional significant contributions or acquisitions after the second quarter of fiscal 2017, our production growth after the second quarter of fiscal 2017 is primarily due to the results of our

 

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development program. Both our production and our proved reserves as of September 30, 2017 consist of greater than 85% oil. The following table shows our growth in net production, with period averages, since fiscal 2016.

 

 

LOGO

Our management has also been highly focused on operating efficiency. We made a strategic decision to construct and operate water disposal and electric infrastructure within our operating project areas which, together with our other efforts at efficiency, have resulted in significantly lower lease operating expenses, or LOEs. The following table shows our historic LOE per unit of oil-equivalent production which has declined from an average of $24.74 per BOE for our year ended September 30, 2016 to $9.50 per BOE for the first nine months of fiscal 2018, representing a decline of approximately 62%.

 

 

LOGO

 

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We maintain operational control on approximately 66% of our net undeveloped acreage position which enables the horizontal drilling of long laterals, resulting in significant drilling efficiencies through strong operational and cost controls that we believe improve our returns on capital employed and enhance the economic development of our acreage position. We believe the ability to drill long-lateral wells improves our returns by (i) increasing our estimated ultimate recoveries, or EUR, per well, (ii) allowing us to contact more reservoir rock with fewer wellbores thereby reducing drilling and completion costs on a per unit basis and (iii) allowing us to hold more acreage per well drilled. Additionally, the contiguous nature of our acreage provides economies of scale by allowing us to better leverage our existing infrastructure. For the nine months ended June 30, 2018, our average net daily production was 3,136 BOE/d, of which approximately 94% was oil, 2% was natural gas and 4% was NGLs. The following table provides summary information regarding our proved, probable and possible reserves as of September 30, 2017, based on the NSAI Report.

 

Reserve Type

   Oil
(MBbls) (1)
     Natural
Gas
(MMcf) (1)
     NGL
(MBbls) (1)
     Total
(MBoe) (1)
     % Oil      % Liquids (2)      %
Developed
 

Proved Reserves

     12,026        4,821        1,179        14,009        86        94        51  

Probable Reserves

     11,137        4,639        1,106        13,016        86        94     

Possible Reserves

     11,149        4,691        1,118        13,049        85        94     

 

(1)

Our estimated reserves were determined using the unweighted arithmetic average of the historical first-day-of-the-month prices for the prior 12 months as of September 30, 2017 of $46.27 per Bbl for oil and NGL volumes, at the average West Texas Intermediate (WTI) posted price, and $3.00 per MMBtu for natural gas, at the average Henry Hub spot price. The WTI price for oil (and NGL) volumes is adjusted by lease for quality, transportation fees, and market differentials. The Henry Hub spot price for gas volumes is adjusted by lease for energy content, transportation fees, and market differentials. For more information on the differences between the categories of proved, probable and possible reserve, see “—Oil and Natural Gas Data.”

(2)

Includes both oil and NGLs.

The following table presents data on EURs and production for our gross wells drilled and completed during the fiscal years ended September 30, 2016 and 2017, respectively. For our fiscal year ended September 30, 2017 in comparison to fiscal 2016, our average oil equivalent EURs per 1,000 foot lateral length increased by 35%. Please see “—Drilling Results” for more detail on our wells we have drilled to date and other information on wells drilled in our acreage.

 

Year of First Production

   Drilled &
Completed
Per Year (1)
     Averaged
Completed
Lateral Length
(feet)
     Average Oil
Equivalent EUR
(1) (MBoe)
     Average Oil
Equivalent EUR
per 1,000’ (1)(2)
(MBoe)
     Average Drilling
& Completions
Costs
($ in millions)
 

2016

     21        6,044        460        76      $ 2.1  

2017

     18        5,779        597        103      $ 2.4  

 

(1)

EUR represents the sum of total gross remaining proved reserves as of September 30, 2017, based on the NSAI Report, and cumulative production as of such date. EUR information is given on a per year basis only for wells drilled and completed that year as listed in the third column of the above table. EUR is shown on a combined basis for oil, natural gas and NGLs.

(2)

The average completed lateral length at such date of our 1-mile equivalent wells was 4,461 feet and the 1.5-mile equivalent wells was 6,726 feet.

Our total well count was 53 gross producing (23 net) wells as of the fiscal year ended September 30, 2017, increasing from 33 gross (13 net) wells as of the fiscal year ended September 30, 2016. As of the fiscal year ended September 30, 2017, our average working interest was 43% in the total 53 gross producing wells. Of these 53 gross producing wells, we operated 20 gross wells, in which we had an average working interest of 95%. Our strategy is to increase the number of wells we operate in our undeveloped locations, and as a result increase our

 

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average working interest over time. As of June 30, 2018, our producing well count has increased by 27 gross (17 net) wells. See “Prospectus Summary—Recent Developments” above for further information regarding the increase in our well counts.

In addition to our 53 gross producing (23 net) wells, we identified a total of approximately 97 gross (67 net) drilling locations across our acreage as of September 30, 2017 identified as proved, probable or possible reserves in the NSAI Report. See “—Drilling Locations” for more information. Our gross and net remaining horizontal drilling locations as of September 30, 2017 relating to our proved, probable and possible reserves are as follows:

 

Reserve Type

   Gross Horizontal
Drilling Locations
     % by Reserve
Type
    Net Horizontal
Drilling Locations
     % by Reserve
Type
 

Proved

     25        26     14        21

Probable

     44        45     26        39

Possible

     28        29     27        40
  

 

 

    

 

 

   

 

 

    

 

 

 

Total

     97        100     67        100
  

 

 

    

 

 

   

 

 

    

 

 

 

As of June 30, 2018, management estimates the current remaining undrilled locations to be 381 gross (244 net), of which 242 gross (197 net) are operated locations. The increase in locations since our September 30, 2017 NSAI Report is in connection with acreage added in our Champions Assets, along with our acquisition of the New Mexico Assets. See “Prospectus Summary—Recent Developments” above for further information regarding the increase in our well counts.

We have estimated our drilling locations based on well spacing assumptions and upon the evaluation of our horizontal drilling results and those of other offset operators, combined with our interpretation of available geologic and engineering data, in addition to what is credited in the NSAI Report. The drilling locations that we actually drill will depend on the availability of capital, regulatory approvals, commodity prices, costs, actual drilling results and other factors. Any drilling activities we are able to conduct on these identified locations may not be successful and may not result in additional proved reserves. Further, to the extent the drilling locations are associated with acreage that expires, we would lose our right to develop the related locations. See “Risk Factors—Risks Related to Our Business—Our identified drilling locations are scheduled over many years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling. In addition, we may not be able to raise the substantial amount of capital that would be necessary to drill such locations.”

Our Business Strategies

We plan to achieve our primary objective—to increase shareholder value—by executing the following business strategies:

 

   

Grow production, reserves and cash flow by developing our existing horizontal well inventory. We consider our inventory of horizontal drilling locations have relatively low development risk because of the information gained from our operating experience on our acreage, industry activity by offset operators surrounding our acreage and historic activity on the San Andres Formation. We intend to economically grow production, reserves and cash flow by utilizing our technical expertise to develop our multi-year drilling inventory while efficiently allocating capital to maximize the value of our resource base.

 

   

Leverage our experience operating in the Permian Basin to maximize returns. We were an early entrant to the horizontal development of the San Andres Formation of the Permian Basin. Substantially all of our current properties are positioned in what we believe to be the core of the horizontal San Andres Formation play in Yoakum County, Texas and Lea, Roosevelt, and Chaves Counties, New Mexico, where horizontal production on the San Andres Formation has increased by more than 425% since January 2014. As of June 30, 2018, we have operated or participated in 80 gross horizontal San

 

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Andres Formation wells, which affords us keen insight and expertise on the reservoir characteristics of the play. We intend to leverage our management and technical teams’ experiences in applying unconventional drilling and completion techniques in the Permian Basin to maximize our returns.

 

   

Target contiguous acreage positions in prolific Permian Basin resource plays. We will seek to expand on our success in targeting contiguous acreage positions within the Northwest Shelf and particularly the San Andres Formation. Our leasing and acquisition strategies have been predicated on our belief that acquiring large contiguous acreage blocks with significant untapped potential in terms of ultimate recoverable reserves, or acquiring additional working interests from other operators in areas we believe to be located in the core of the play and our core drilling locations, provide us with favorable reservoir and geological characteristics primarily for oil development. We have developed internal geologic models that incorporate publicly available third-party data, including well results and drilling and completion reports, to confirm our geologic model and define the various core acreage positions of a play. Once we believe that we have identified a core location, we intend to aggressively execute on our acquisition strategy to establish a largely contiguous acreage position in proximity to the core. We believe our evaluation techniques uniquely-position us to better identify acquisition targets to grow our resource base and increase shareholder value.

 

   

Maintain a high degree of operational control to continuously drive our operating costs lower and capture efficiencies. We intend to maintain operational control of a substantial majority of our drilling inventory, by owning in excess of 50% of the working interest in the associated locations. We believe that maintaining operating control enables us to increase our reserves while lowering our per unit development costs, and allows us to deploy our strategies regarding LOE cost reduction and infrastructure efficiencies. Our control over operations and our ownership and operation of associated infrastructure for salt water disposal systems and electricity distribution allows us to utilize what we believe to be cost-effective operating practices. These cost-effective practices include the selection of drilling locations, timing of development and associated capital expenditures and continuous improvement of drilling, completion and stimulation techniques.

 

   

Maintain financial flexibility and apply a disciplined approach to capital allocation. We seek a capital structure with sufficient liquidity to execute our growth plans, while maintaining conservative leverage, and providing financial and operational flexibility through the various commodity price cycles. To achieve more predictable cash flow and reduce volatility during commodity price cycles, we also enter into hedging arrangements for our crude oil production. We expect to fund our growth primarily through cash flow from operations, proceeds from this offering, availability under our revolving credit facility, and subsequent equity or debt offerings when appropriate. As we expect our cash flow to continue to grow over time, we believe we will be able to fund a larger percentage of our future growth from internally generated cash flow. We intend to continue allocating capital in a disciplined manner and aggressively managing our cost structure to achieve our financial objectives. Consistent with our disciplined approach to financial management, we have an active commodity hedging program that seeks to reduce our exposure to downside commodity price fluctuations.

Our Competitive Strengths

We believe that the following strengths will allow us to successfully execute our business strategies:

 

   

Large contiguous asset base in one of North America’s leading oil resource plays. Our acreage is primarily located on large, contiguous blocks in Yoakum County, Texas and Lea, Roosevelt, and Chaves Counties, New Mexico, producing from the San Andres Formation, which is