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 one of the most active areas in 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%

 

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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 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.

Our Properties

As of September 30, 2017, all of our properties were located in Yoakum County, Texas on the Northwest Shelf sub-basin of the Permian Basin. Our acreage is primarily located on large, contiguous blocks in Yoakum County, Texas on the San Andres Formation, which is a shelf margin deposit on the Central Basin Platform and Northwest Shelf. As of September 30, 2017, our acreage position consisted of 19,893 net acres, all of which target the San Andres Formation. Additionally, approximately 31% of our net acreage is held by production. Unless production is established within the spacing units covering the remaining acreage or the lease is renewed or extended under continuous drilling provisions prior to the primary term expiration dates, the leases will expire in accordance with their respective terms. See “—Developed and Undeveloped Acreage” below.

Our estimated total proved, probable and possible reserves at September 30, 2017 based on the NSAI Report were approximately 14,009, 13,016 and 13,049 MBoe, respectively. As of September 30, 2017, we had a total of

 

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53 gross producing (23 net) wells, of which all were horizontal wells. Our estimated average net daily production during the nine months ended June 30, 2018 was approximately 3,136 BOE/d. As of September 30, 2017, we had an average working interest of 43% in 53 total gross producing wells and an average working interest of 95% in 20 operated gross wells. Our strategy is to operate wells in our undeveloped locations, and as result our average working interest is expected to increase further over time.

We continue to expand our proved reserves in this area by drilling undeveloped horizontal locations. As of September 30, 2017, we had an identified drilling inventory of approximately 97 gross (67 net) undeveloped horizontal drilling locations of which 25 are PUDs with varying lateral lengths on our acreage with average well costs of $2.7 million ($2.3 million normalized to 4,400 foot lateral length). During fiscal 2016 and 2017, we drilled and completed 21 and 18 gross operated horizontal wells, respectively.

Permian Basin and Sub-Basin References

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.

Drilling Locations

As of September 30, 2017, we have identified a total of 97 gross (67 net) identified drilling locations, 85 gross (65 net) locations are on acreage for which we maintain operational control, by owning in excess of 75% of the working interest in the associated locations. Approximately 26% of our gross identified drilling locations are attributable to proved undeveloped reserves. Our identified drilling locations are based upon drilling 4 wells per section across our Champions Assets. The locations have been identified based on our review of structure as well as production data from offsetting wells. Information incorporated into this process includes both our own proprietary information as well as publicly available industry data. Specifically, open hole logging data, production statistics from operated and non-operated wells, and petrophysical data from cores taken from wellbores has provided the technical basis from which we identified the potential locations. These data have allowed us to determine areas for each reservoir that may produce commercial quantities of hydrocarbons and the viability of the potential locations.

Production Status

For our fiscal year ended September 30, 2017, our average net daily production was 1,384 BOE/d, of which approximately 93% was oil, 3% was natural gas and 4% was NGLs. As of September 30, 2017 our producing well count was 53 gross producing (23 net) wells.

Facilities

Our land-based oil and gas processing facilities are typical of those found in the Permian Basin. Our facilities located at well locations or centralized lease locations include salt water disposal wells and associated gathering lines, storage tank batteries, oil/gas/water separation equipment and pumping equipment. In addition, we own a substantial majority of the electrical power infrastructure on our acreage position, which include power distribution lines and equipment.

 

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Recent and Future Activity

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 that included both our operated and non-operated wells combined. This represented an increase of 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.

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. The wells are expected to be drilled to approximately 11,000 feet measured depth at an estimated average drilling and completion gross well cost of $3.0 million to $3.8 million per horizontal well with completed lateral lengths ranging from 4,500 to 7,300 feet. In this prospectus, we define identified potential drilling locations as locations specifically identified by management based on evaluation of applicable geologic and engineering data accrued over our multi-year historical drilling activities, in addition to what is credited in the NSAI Report. The availability of local infrastructure, drilling support assets and other factors as management may deem relevant are considered in determining such locations. The drilling locations on which we actually drill wells will ultimately depend upon the availability of capital, regulatory approvals, seasonal restrictions, oil and natural gas prices, costs, actual drilling results and other factors.

Oil and Natural Gas Data

Evaluation and Review of Reserves. Our historical reserve estimates as of September 30, 2017 were prepared based on a report by NSAI, our independent petroleum engineers, which we refer to as the NSAI Report. Within NSAI, the technical person primarily responsible for preparing the estimates set forth in the NSAI reserves report incorporated herein is Mr. James E. Ball. Mr. Ball, a Licensed Professional Engineer in the State of Texas (No. 57700), has been practicing consulting petroleum engineering at NSAI since 1998 and has over 17 years of prior industry experience. He graduated from Texas A&M University in 1980 with a Bachelor of Science Degree in Petroleum Engineering. The technical principal meets or exceeds the education, training, and experience requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers; he is proficient in judiciously applying industry standard practices to engineering and geoscience evaluations as well as applying SEC and other industry reserves definitions and guidelines. NSAI does not own an interest in any of our properties, nor is it employed by us on a contingent basis.

Internal Controls. We maintain an internal staff of petroleum engineers and geoscience professionals who worked closely with our independent reserve engineers to ensure the integrity, accuracy and timeliness of the data used to calculate our reserves relating to our assets in the Permian Basin. Our internal technical team members meet with our independent reserve engineers periodically during the period covered by the NSAI Report to discuss the assumptions and methods used in the proved reserve estimation process. We provide historical information to the independent reserve engineers for our properties, such as ownership interest, oil and natural gas production, well test data, commodity prices, and operating and development costs.

 

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The preparation of our reserve estimates is completed in accordance with our internal control procedures. These procedures, which are intended to ensure reliability of reserve estimations, include the following:

 

   

review and verification of historical production data, which data is based on actual production as reported by us;

 

   

preparation of reserve estimates; and

 

   

verification of property ownership by our land department.

Estimation of Proved Reserves. Under SEC rules, proved reserves are those quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs and under existing economic conditions, operating methods and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. If deterministic methods are used, the SEC has defined reasonable certainty for proved reserves as a “high degree of confidence that the quantities will be recovered.” All of our proved reserves as of September 30, 2017 were estimated using a deterministic method. The estimation of reserves involves two distinct determinations. The first determination results in the estimation of the quantities of recoverable oil and natural gas and the second determination results in the estimation of the uncertainty associated with those estimated quantities in accordance with the definitions established under SEC rules. The process of estimating the quantities of recoverable oil and natural gas reserves relies on the use of certain generally accepted analytical procedures. These analytical procedures fall into four broad categories or methods: (1) production performance-based methods; (2) material balance-based methods; (3) volumetric-based methods; and (4) analogy. These methods may be used singularly or in combination by the reserve evaluator in the process of estimating the quantities of reserves. Reserves for proved developed producing wells were estimated using production performance methods for the vast majority of properties. Certain new producing properties with very little production history were forecast using a combination of production performance and analogy to similar production, both of which are considered to provide a relatively high degree of accuracy. Non-producing reserve estimates, for developed and undeveloped properties, were forecast using either volumetric or analogy methods, or a combination of both. These methods provide a relatively high degree of accuracy for predicting proved developed non-producing and proved undeveloped reserves for our properties, due to the mature nature of the properties targeted for development and an abundance of subsurface control data.

To estimate economically recoverable proved reserves and related future net cash flows, NSAI considered many factors and assumptions, including the use of reservoir parameters derived from geological and engineering data which cannot be measured directly, economic criteria based on current costs and the SEC pricing requirements and forecasts of future production rates.

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

Estimation of Probable and Possible Reserves. Estimates of probable reserves are inherently imprecise and are more uncertain than proved reserves, but have not been adjusted for risk due to that uncertainty, and therefore they may not be comparable with each other. When producing an estimate of the amount of oil, natural gas and NGLs that is recoverable from a particular reservoir, an estimated quantity of probable reserves is an estimate of

 

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those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered. Estimates of probable reserves are also continually subject to revisions based on production history, results of additional exploration and development, price changes and other factors.

When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. When probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates. Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion. Probable reserves may be assigned to areas that are structurally higher than the proved area if these areas are in communication with the proved reservoir. Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves.

Estimates of possible reserves are also inherently imprecise and are more uncertain than proved reserves, but have not been adjusted for risk due to that uncertainty, and therefore they may not be comparable with each other. When producing an estimate of the amount of oil, natural gas and NGLs that is recoverable from a particular reservoir, an estimated quantity of possible reserves is an estimate that might be achieved, but only under more favorable circumstances than are likely. Estimates of possible reserves are also continually subject to revisions based on production history, results of additional exploration and development, price changes and other factors.

When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves. When probabilistic methods are used, there should be at least a 10% probability that the total quantities ultimately recovered will equal or exceed the proved plus probable plus possible reserves estimates. Possible reserves may be assigned to areas of a reservoir adjacent to probable reserve where data control and interpretations of available data are progressively less certain. Frequently, this will be in areas where geoscience and engineering data are unable to define clearly the area and vertical limits of commercial production from the reservoir. Possible reserves also include incremental quantities associated with a greater percentage of recovery of the hydrocarbons in place than the recovery quantities assumed for probable reserves.

Possible reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoir within the same accumulation that may be separated from proved areas by faults with displacement less than formation thickness or other geological discontinuities and that have not been penetrated by a wellbore, and we believe that such adjacent portions are in communication with the known (proved) reservoir. Possible reserves may be assigned to areas that are structurally higher or lower than the proved area if these areas are in communication with the proved reservoir.

 

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Summary of Oil, Natural Gas and NGL Reserves. The following table summarizes our estimated proved, probable and possible reserves at September 30, 2017 from the NSAI Report and based on SEC pricing.

 

     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%  

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, 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.

 

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(2)

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

(3)

All of our estimated possible reserves are classified as undeveloped.

Reserve engineering is and must be recognized as a subjective process of estimating volumes of economically recoverable oil and natural gas that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation. As a result, the estimates of different engineers often vary. In addition, the results of drilling, testing and production may justify revisions of such estimates. Accordingly, reserve estimates often differ from the quantities of oil and natural gas that are ultimately recovered. Estimates of economically recoverable oil and natural gas and of future net revenues are based on a number of variables and assumptions, all of which may vary from actual results, including geologic interpretation, prices and future production rates and costs. Please read “Risk Factors” appearing elsewhere in this prospectus.

Additional information regarding our reserves can be found in the notes to our financial statements included elsewhere in this prospectus.

Proved Undeveloped Reserves (PUDs)

As of September 30, 2017, our proved undeveloped reserves were composed of 4,961 MBbls of oil, 2,006 MMcf of natural gas and 487 MBbls of NGL, for a total of 5,783 MBoe. PUDs will be converted from undeveloped to developed as the applicable wells begin production.

The following table summarizes our changes in our estimated PUDs during the year ended September 30, 2017 (in MBoe):

 

Proved undeveloped reserves at September 30, 2016

     1,635  

Conversions into proved developed reserves

     (674

Extensions and discoveries

     1,351  

Acquisitions

     2,742  

Revisions

     729  
  

 

 

 

Proved undeveloped reserves at September 30, 2017

     5,783  
  

 

 

 

During the year ended September 30, 2017, we incurred costs of approximately $8.3 million to convert 674 MBoe of proved undeveloped reserves to proved developed reserves.

During the year ended September 30, 2017, extensions were comprised of 1,351 MBoe. The increase was primarily the result of drilling successful wells and booking PUD offsets to such wells.

During the year ended September 30, 2017, acquisitions were comprised of 2,742 MBoe. The increase was the result of contributions to us described in “Prospectus Summary—Our Corporate History” particularly contributions from DR/CM.

As of September 30, 2017, we revised the decline curves for the proved undeveloped reserves to conform with the continuous development and performance of wells in the immediate offset areas.

As of September 30, 2017, we had no proved undeveloped reserves that had remained undeveloped for more than five years since initial booking.

Estimated future development costs relating to the development of our proved undeveloped reserves at September 30, 2017 are approximately $40 million, over the next five years, which we expect to finance through cash flow from operations, borrowings under our revolving credit facility and other sources of capital. All of our

 

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proved undeveloped reserves are expected to be developed within five years of initial booking. Please see “Risk Factors—Risks Related to Our Business—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.”

Oil, Natural Gas and NGL Production Prices and Production Costs

Production and Operating Data

The following table sets forth information regarding our production, realized prices and production costs for the nine months ended June 30, 2018 and June 30, 2017, as well as for the years ended September 30, 2017 and September 30, 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 NGLs 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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Productive Wells

As of June 30, 2018, we owned an average 50% working interest in 80 gross (40 net) productive wells.

 

     Wells      Avg. WI  

Proved Developed Producing

     

Operated

     37        94

Non-Operated

     43        13
  

 

 

    

 

 

 

Total

     80        50
  

 

 

    

 

 

 

Productive wells consist of producing wells and wells capable of production, including oil wells awaiting connection to production facilities. Gross wells are the total number of producing wells in which we have an interest, operated and non-operated, and net wells are the sum of our fractional working interests owned in gross wells.

Developed and Undeveloped Acreage

The following tables set forth information as of June 30, 2018 relating to our leasehold acreage. Developed acreage is acres spaced or assigned to productive wells and does not include undrilled acreage held by production under the terms of the lease. Undeveloped acreage is acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil or natural gas, regardless of whether such acreage contains proved reserves. A gross acre is an acre in which a working interest is owned. The number of gross acres is the total number of acres in which a working interest is owned. A net acre is deemed to exist when the sum of the fractional ownership working interests in gross acres equals one. The number of net acres is the sum of the fractional working interests owned in gross acres expressed as whole numbers and fractions thereof.

The following table sets forth our gross and net acres of developed and undeveloped oil and gas leases as of June 30, 2018:

 

Developed Acreage (1)

 

Undeveloped Acreage (2)

 

Total Acreage

Gross (3)

 

Net (4)

 

Gross (3)

 

Net (4)

 

Gross (3)

 

Net (4)

19,367

 

12,804

 

80,390

 

53,035

 

99,757

  65,839

 

(1)

Developed acreage is acres spaced or assigned to productive wells and does not include undrilled acreage held by production under the terms of the lease.

(2)

Undeveloped acreage are acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil or natural gas, regardless of whether such acreage contains proved reserves.

(3)

A gross acre is an acre in which a working interest is owned. The number of gross acres is the total number of acres in which a working interest is owned.

(4)

A net acre is deemed to exist when the sum of the fractional ownership working interests in gross acres equals one. The number of net acres is the sum of the fractional working interests owned in gross acres expressed as whole numbers and fractions thereof.

Many of the leases comprising the undeveloped acreage set forth in the table above will expire at the end of their respective primary terms unless production from the leasehold acreage has been established prior to such date, in which event the lease will remain in effect until the cessation of production. Substantially all of the leases governing our acreage have continuous development clauses that permit us to continue to hold the acreage under such leases after the expiration of the primary term if we initiate additional development within 120 to 180 days after the completion of the last well drilled on such lease, without the requirement of a lease extension payment. Thereafter, the lease is held with additional development every 120 to 240 days, and generally 180 days, until the

 

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entire lease is held by production. None of our horizontal drilling locations associated with proved undeveloped reserves are scheduled for drilling outside of a lease term that is not accounted for with a continuous development schedule or primary term. The following table sets forth the net undeveloped acreage, as of June 30, 2018 that will expire over the next five years unless production is established within the spacing units covering the acreage or the lease is renewed or extended under continuous drilling provisions prior to the primary term expiration dates.

 

Net Undeveloped Acreage (1)

2018

 

2019

 

2020

 

2021+

699

 

16,361

 

3,652

 

32,323

 

(1)

All acreage represented is as of June 30, 2018.

Based on our current development plans, we expect to maintain substantially all of the acreage that would otherwise expire during fiscal 2019 either through drilling and establishing production, making lease extension payments, or lease renewal efforts. We intend to extend or renew all of our material leases referenced above 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, and therefore we do not expect a material reduction in our proved undeveloped reserves as a result of leases expirations. Given our currently planned drilling activities, we do not expect the amount of any such lease extension payments to be material.

Drilling Results

The following table sets forth information with respect to the number of wells completed by us during the periods indicated. The information should not be considered indicative of future performance, nor should it be assumed that there is necessarily any correlation between the number of productive wells drilled, quantities of reserves found or economic value. Productive wells are those that produce commercial quantities of hydrocarbons, whether or not they produce a reasonable rate of return.

 

     For the Nine
Months Ended
     Year Ended  
     June 30,      September 30,  
     2018      2017      2016  
     Gross      Net      Gross      Net      Gross      Net  

Development Wells:

                 

Productive (1)

     22        13        21        11        18        10  

Dry (2)

     —          —          —          —          —          —    

Exploratory Wells:

                 

Productive (1)

     —          —          —          —          —          —    

Dry (2)

     —          —          —          —          —          —    

Total Wells:

                 
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Productive (1)

     22        13        21        11        18        10  

Dry (2)

     —          —          —          —          —          —    

 

(1)

Although a well may be classified as productive upon completion, future changes in oil, natural gas and NGL prices, operating costs and production may result in the well becoming uneconomical, particularly exploratory wells where there is no production history.

(2)

Does not include a wellbore temporarily abandoned due to mechanical failure.

As of September 30, 2017 we had 3 gross (3 net) drilled, non-producing wells of varying lateral lengths waiting on gas connect or commencement of completion activities.

 

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Operations

General

We operated 81% of our horizontal production for the nine months ended June 30, 2018. As operator, we design and manage the development of a well and supervise operation and maintenance activities on a day-to-day basis. Independent contractors engaged by us provide all of the equipment and personnel associated with these activities. We employ petroleum engineers, geologists and land professionals who work to improve production rates, increase reserves and lower the cost of operating our oil and natural gas properties. For more information about our properties and the risks associated with the comparability of proved, probable, and possible reserves, please read “—Our Properties” and “—Oil and Natural Gas Data.”

Marketing and Customers

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

We sell our production to purchasers at market prices. For the nine months ended June 30, 2018, one purchaser accounted for more than 10% of our revenue: Stakeholder Crude Oil Marketing, LLC (91%). For the year ended September 30, 2017, two purchasers accounted for more than 10% of our revenue: Sunoco Partners Marketing & Terminals LP (31%) and Stakeholder Crude Oil Marketing, LLC (60%). For the year ended September 30, 2016, one purchaser accounted for more than 10% of our revenue: Sunoco Partners Marketing & Terminals LP (98%). During such periods, no other purchaser accounted for 10% or more of our revenue. The loss of any of these purchasers could materially and adversely affect our revenues in the short-term. However, based on the current demand for oil and natural gas and the availability of other purchasers, we believe that the loss of any of our purchasers would not have a long-term material adverse effect on our financial condition and results of operations because crude oil and natural gas are fungible products with well-established markets.

Transportation

During the initial development of our fields, we consider all gathering and delivery infrastructure in the areas of our production. Our oil is collected from the wellhead to our tank batteries and then transported by the purchaser by truck or pipeline to a tank farm, another pipeline or a refinery. A portion of our natural gas is transported from the wellhead to the purchaser’s meter and pipeline interconnection point.

In addition, we move substantially all of our produced water by pipeline connected to company-owned salt water disposal wells rather than by truck. Given the amount of disposal water volume, the connection to salt water disposal wells help us reduce our lease operating expenses.

We are currently a party to a crude oil pipeline transportation agreement that commenced in August 2016 and has a 10-year term. This agreement does not include any volume commitments for us. As a result, we benefit from relatively low take-away costs as compared to transportation by truck. In addition, since a volume commitment is not applicable, we achieve greater operational flexibility. In September 2017, we entered into a long-term natural gas gathering and processing agreement, with a 10-year term and no volume commitments for us. We expect to begin selling natural gas under this agreement in the fourth quarter of fiscal 2018.

Competition

The oil and natural gas industry is intensely competitive, and we compete with other companies that have greater resources. Many of these companies not only explore for and produce oil and natural gas, but also carry on midstream and refining operations and market petroleum and other products on a regional, national or worldwide basis. These companies may be able to pay more for productive oil and natural gas properties and exploratory prospects or to define, evaluate, bid for and purchase a greater number of properties and prospects

 

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than our financial or human resources permit. In addition, these companies may have a greater ability to continue exploration activities during periods of low oil, natural gas and NGL market prices. Our larger or more integrated competitors may be able to absorb the burden of existing, and any changes to, federal, state, and local laws and regulations more easily than we can, which would adversely affect our competitive position. Our ability to acquire additional properties and to discover reserves in the future will be dependent upon our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. In addition, because we have fewer financial and human resources than many companies in our industry, we may be at a disadvantage in bidding for exploratory prospects and producing oil and natural gas properties.

There is also competition between oil and natural gas producers and other industries producing energy and fuel. Furthermore, competitive conditions may be substantially affected by various forms of energy legislation and/or regulation considered from time to time by the governments of the United States and the jurisdictions in which we operate. It is not possible to predict the nature of any such legislation or regulation which may ultimately be adopted or its effects upon our future operations. Such laws and regulations may substantially increase the costs of exploring for, developing or producing oil and natural gas and may prevent or delay the commencement or continuation of a given operation. Our larger competitors may be able to absorb the burden of existing, and any changes to, federal, state and local laws and regulations more easily than we can, which would adversely affect our competitive position.

Title to Properties

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

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

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

Seasonality of Business

Weather conditions affect the demand for, and prices of, oil, natural gas and NGLs. Demand for oil, natural gas and NGLs is typically higher in the fourth and first quarters resulting in higher prices. Due to these seasonal

 

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fluctuations, results of operations for individual quarterly periods may not be indicative of the results that may be realized on an annual basis.

Oil and Natural Gas Leases

The typical oil and natural gas lease agreement covering our properties provides for the payment of royalties to the mineral owner for all oil and natural gas produced from any wells drilled on the leased premises. The lessor royalties and other leasehold burdens on our properties generally range from 22.5% to 25.0%, resulting in a net revenue interest to us generally ranging from 75.0% to 77.5%.

Regulation of the Oil and Gas Industry

Our operations are substantially affected by federal, state and local laws and regulations. In particular, natural gas production and related operations are, or have been, subject to price controls, taxes and numerous other laws and regulations. All of the jurisdictions in which we own or operate producing oil and natural gas properties have statutory provisions regulating the development and production of oil and natural gas, including provisions related to permits for the drilling of wells, bonding requirements to drill or operate wells, the location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled, sourcing and disposal of water used in the drilling and completion process and the abandonment of wells. Our operations are also subject to various conservation laws and regulations. These include the regulation of the size of drilling and spacing units or proration units, the number of wells which may be drilled in an area and the unitization or pooling of crude oil or natural gas wells, as well as regulations that generally prohibit the venting or flaring of natural gas and impose certain requirements regarding the ratability or fair apportionment of production from fields and individual wells. State laws including in Texas govern a number of conservation matters, including provisions for the unitization or pooling of oil and natural gas properties, the establishment of maximum allowable rates of production from oil and natural gas wells, the regulation of well spacing or density, and plugging and abandonment of wells. The effect of these regulations is to limit the amount of oil and natural gas that we can produce from our wells and to limit the number of wells or the locations at which we can drill, although we can apply for exceptions to such regulations or to have reductions in well spacing or density. Moreover, Texas imposes a production or severance tax with respect to the production and sale of oil, natural gas and NGLs within its jurisdiction.

Failure to comply with applicable laws and regulations can result in substantial penalties. The regulatory burden on the industry increases the cost of doing business and affects profitability. Although we believe we are in substantial compliance with all applicable laws and regulations, such laws and regulations are frequently amended or reinterpreted. Therefore, we are unable to predict the future costs or impact of compliance. Additional proposals and proceedings that affect the oil and natural gas industry are regularly considered by Congress, the states, FERC and the courts. We cannot predict when or whether any such proposals may become effective. We do not believe that we would be affected by any such action materially differently than similarly situated competitors.

Regulation Affecting Production

The production of oil and natural gas is subject to United States federal and state laws and regulations, and orders of regulatory bodies under those laws and regulations, governing a wide variety of matters. All of the jurisdictions in which we own or operate producing oil and natural gas properties have statutory provisions regulating the exploration for and production of oil and natural gas, including provisions related to permits for the drilling of wells, bonding requirements to drill or operate wells, the location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled, sourcing and disposal of water used in the drilling and completion process, and the abandonment of wells. Our operations are also subject to various conservation laws and regulations. These include the regulation of the size of drilling and spacing units or proration units, the number of wells which may be drilled in an area, and the unitization or

 

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pooling of oil or natural gas wells, as well as regulations that generally prohibit the venting or flaring of natural gas, and impose certain requirements regarding the ratability or fair apportionment of production from fields and individual wells. These laws and regulations may limit the amount of oil and gas we can drill. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, NGLs and gas within its jurisdiction. States do not regulate wellhead prices or engage in other similar direct regulation, but there can be no assurance that they will not do so in the future. The effect of such future regulations may be to limit the amounts of oil and gas that may be produced from our wells, negatively affect the economics of production from these wells or limit the number of locations we can drill.

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

Regulation of Sales and Transportation of Oil

Sales of oil, condensate and NGLs are not currently regulated and are made at negotiated prices. Although prices of these energy commodities are currently unregulated, the United States Congress historically has been active in their regulation. We cannot predict whether new legislation to regulate oil and NGLs, or the prices charged for these commodities might be proposed, what proposals, if any, might actually be enacted by the United States Congress or the various state legislatures and what effect, if any, the proposals might have on the our operations. Additionally, such sales may be subject to certain state, and potentially federal, reporting requirement.

Our sales of oil are affected by the availability, terms and cost of transportation. The transportation of oil in common carrier pipelines is also subject to rate and access regulation. FERC regulates interstate transportation of oil, including natural gas liquids, under the Interstate Commerce Act (“ICA”). Prices received from the sale of oil liquids may be affected by the cost of transporting those products to market. The ICA requires that pipelines maintain a tariff on file with FERC. The tariff sets forth the established rates as well as the rules and regulations governing the service. The ICA requires, among other things, that rates and terms and conditions of service on interstate common carrier pipelines be “just and reasonable.” In general, interstate oil pipeline rates must be cost-based, although settlement rates agreed to by all shippers are permitted and market based rates may be permitted in certain circumstances. Such pipelines must also provide jurisdictional service in a manner that is not unduly discriminatory or unduly preferential. Shippers have the power to challenge new and existing rates and terms and conditions of service before FERC.

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

Regulation of Transportation and Sales of Natural Gas

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

 

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transportation and wholesale sales of natural gas may also be affected directly or indirectly by laws enacted by Congress and by FERC regulations.

The EP Act of 2005 is a comprehensive compilation of tax incentives, authorized appropriations for grants and guaranteed loans and significant changes to the statutory policy that affects all segments of the energy industry. Among other matters, the EP Act of 2005 amends the NGA to add an anti-market manipulation provision which makes it unlawful for any entity to engage in prohibited behavior to be prescribed by FERC, and furthermore provides FERC with additional civil penalty authority. The EP Act of 2005 provides FERC with the power to assess civil penalties of up to $1,000,000 per day for violations of the NGA and increases FERC’s civil penalty authority under the NGPA from $5,000 per violation per day to $1,000,000 per violation per day. The civil penalty provisions are applicable to entities that engage in the sale of natural gas for resale in interstate commerce. On January 19, 2006, FERC issued Order No. 670, a rule implementing the anti-market manipulation provision of the EP Act of 2005, and subsequently denied rehearing. The rules make it unlawful to: (i) in connection with the purchase or sale of natural gas subject to the jurisdiction of FERC, or the purchase or sale of transportation services subject to the jurisdiction of FERC, for any entity, directly or indirectly, to use or employ any device, scheme or artifice to defraud; (ii) to make any untrue statement of material fact or omit to make any such statement necessary to make the statements made not misleading; or (iii) to engage in any act or practice that operates as a fraud or deceit upon any person. The new anti-market manipulation rule does not apply to activities that relate only to intrastate or other non-jurisdictional sales or gathering, but does apply to activities of natural gas pipelines and storage companies that provide interstate services, as well as otherwise non-jurisdictional entities to the extent the activities are conducted “in connection with” natural gas sales, purchases or transportation subject to FERC jurisdiction, which now includes the annual reporting requirements under Order 704, described below. The anti-market manipulation rule and enhanced civil penalty authority reflect an expansion of FERC’s NGA enforcement authority.

On December 26, 2007, FERC issued Order 704, a final rule on the annual natural gas transaction reporting requirements, as amended by subsequent orders on rehearing. Under Order 704, any market participant that engages in wholesale sales or purchases of natural gas that equal or exceed 2.2 million MMBtus of physical natural gas in the previous calendar year, including natural gas producers, gatherers and marketers, are required to report, on May 1 of each year, aggregate volumes of natural gas purchased or sold at wholesale in the prior calendar year to the extent such transactions utilize, contribute to, or may contribute to the formation of price indices to FERC on Form No. 552. It is the responsibility of the reporting entity to determine which individual transactions should be reported based on the guidance of Order 704. Order 704 also requires market participants to indicate whether they report prices to any index publishers, and if so, whether their reporting complies with FERC’s policy statement on price reporting.

Gathering service, which occurs upstream of jurisdictional transmission services, is regulated by the states onshore and in state waters. Section 1(b) of the NGA exempts natural gas gathering facilities from regulation by FERC as a natural gas company under the NGA. Although FERC has set forth a general test for determining whether facilities perform a non-jurisdictional gathering function or a jurisdictional transmission function, FERC’s determinations as to the classification of facilities are done on a case by case basis. To the extent that FERC issues an order that reclassifies certain jurisdictional transmission facilities as non-jurisdictional gathering facilities, and depending on the scope of that decision, our costs of getting natural gas to point of sale locations may increase. We believe that the natural gas pipelines in the gathering systems we use meet the traditional tests FERC has used to establish a pipeline’s status as a gatherer not subject to regulation as a natural gas company. However, the distinction between FERC-regulated transmission services and federally unregulated gathering services is the subject of ongoing litigation, so the classification and regulation of the gathering facilities we use are subject to change based on future determinations by FERC, the courts or Congress. State regulation of natural gas gathering facilities generally includes various occupational safety, environmental and, in some circumstances, nondiscriminatory-take requirements. Although such regulation has not generally been affirmatively applied by state agencies, natural gas gathering may receive greater regulatory scrutiny in the future.

 

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The price at which we sell natural gas is not currently subject to federal rate regulation and, for the most part, is not subject to state regulation. However, with regard to our physical sales of these energy commodities, we are required to observe anti-market manipulation laws and related regulations enforced by FERC under the EP Act of 2005 and under the Commodity Exchange Act (“CEA”), and regulations promulgated thereunder by the CFTC. The CEA prohibits any person from manipulating or attempting to manipulate the price of any commodity in interstate commerce or futures on such commodity. The CEA also prohibits knowingly delivering or causing to be delivered false or misleading or knowingly inaccurate reports concerning market information or conditions that affect or tend to affect the price of a commodity. Should we violate the anti-market manipulation laws and regulations, we could also be subject to related third-party damage claims by, among others, sellers, royalty owners and taxing authorities.

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

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

Regulation of Environmental and Occupational Safety and Health Matters

Our oil and natural gas development operations are subject to numerous stringent federal, regional, state and local statutes and regulations governing occupational safety and health, the discharge of materials into the environment or otherwise relating to environmental protection, some of which carry substantial administrative, civil and criminal penalties for failure to comply. These laws and regulations may (i) require the acquisition of a permit before drilling or other regulated activity commences; (ii) restrict the types, quantities and concentrations of various substances that can be released into the environment in connection with drilling, production and transporting through pipelines; (iii) govern the sourcing and disposal of water used in the drilling and completion process; (iv) limit or prohibit drilling activities in certain areas and on certain lands lying within wilderness, wetlands, frontier and other protected areas; (v) require some form of remedial action to prevent or mitigate pollution from former operations such as plugging abandoned wells or closing earthen pits; (vi) establish specific safety and health criteria addressing worker protection; (vii) impose substantial liabilities for pollution resulting from operations or failure to comply with regulatory filings; (viii) require the installation of costly emission monitoring and/or pollution control equipment; and (ix) require the reporting of the types and quantities of various substances that are generated, stored, processed, or released in connection with our properties. In addition, these laws and regulations may restrict the rate of production.

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

 

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Hazardous Substances and Waste Handling

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

The Resource Conservation and Recovery Act (“RCRA”) and analogous state laws, impose detailed requirements for the generation, handling, storage, treatment and disposal of nonhazardous and hazardous solid wastes. RCRA specifically excludes drilling fluids, produced waters and other wastes associated with the development or production of crude oil, natural gas or geothermal energy from regulation as hazardous wastes. However, these wastes may be regulated by the EPA or state agencies under RCRA’s less stringent nonhazardous solid waste provisions, state laws or other federal laws. Moreover, it is possible that these particular oil and natural gas development and production wastes now classified as nonhazardous solid wastes could be classified as hazardous wastes in the future. For example, in December 2016, the EPA and environmental groups entered into a consent decree to address EPA’s alleged failure to timely assess RCRA Subtitle D criteria regulations exempting certain exploration and production related oil and gas wastes from regulation as hazardous wastes under RCRA. The consent decree requires EPA to propose a rulemaking no later than March 15, 2019 for revision of the Subtitle D criteria regulations pertaining to oil and gas wastes or to sign a determination that revision of the regulations is not necessary. If EPA proposes a rulemaking for revised oil and natural gas waste regulation, the consent decree requires that EPA take final action following notice and comment rulemaking no later than July 15, 2021. A loss of the RCRA exclusion for drilling fluids, produced waters and related wastes could result in an increase in our costs to manage and dispose of generated wastes, which could have a material adverse effect on our results of operations and financial position. In addition, in the course of our operations, we generate some amounts of ordinary industrial wastes, such as paint wastes, waste solvents, laboratory wastes and waste compressor oils that may be regulated as hazardous wastes if such wastes have hazardous characteristics.

We currently own, lease or operate numerous properties that have been used for oil and natural gas development and production activities for many years. Although we believe that we have utilized operating and waste disposal practices that were standard in the industry at the time, hazardous substances, wastes or petroleum hydrocarbons may have been released on, under or from the properties owned or leased by us, or on, under or from other locations, including off-site locations, where such substances have been taken for recycling, treatment or disposal. In addition, some of our properties have been operated by third parties or by previous owners or operators whose treatment and disposal of hazardous substances, wastes or petroleum hydrocarbons was not under our control. These properties and the substances disposed or released on, under or from them may be subject to CERCLA, RCRA and analogous state laws. Under such laws, we could be required to undertake response or corrective measures, which could include investigation of the nature and extent of contamination, removal of previously disposed substances and wastes, cleanup of contaminated property or performance of remedial plugging or pit closure operations to prevent future contamination.

 

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Water Discharges

The Federal Water Pollution Control Act, also known as Clean Water Act (“CWA”) and comparable state laws impose restrictions and strict controls regarding the discharge of pollutants, including produced waters and other oil and natural gas wastes, into or near navigable waters. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or the state. The discharge of dredge and fill material in regulated waters, including wetlands, is also prohibited, unless authorized by a permit issued by the U.S. Army Corps of Engineers (the “Corps”). In May 2015, the EPA and the Corps issued a new rule to revise the definition of “waters of the United States” for all Clean Water Act Programs. The 2015 rule made additional waters expressly “waters of the United States” and, therefore, subject to the jurisdiction of the Clean Water Act, rather than subject to a case-specific evaluation. Legal challenges to this rule followed and the rule was stayed nationwide by the U.S. Sixth Circuit Court of Appeals in October 2015. In response to this decision, the EPA and the Corps resumed nationwide use of the agencies’ prior regulations defining the term “waters of the United States.” On February 1, 2018, the EPA officially delayed implementation of the 2015 rule until early 2020. The EPA and the Corps also issued a supplemental rulemaking in July 2018 requesting additional comment on the proposed repeal of the 2015 rule’s definition of “waters of the United States.” However, as the result of an order by the U.S. District Court for the District of South Carolina on August 16, 2018, the 2015 rule is currently in effect in 26 states, including in Texas. Meanwhile, the U.S. Army Corps of Engineers and the EPA could initiate rulemaking to revise the definition of “waters of the United States.” To the extent the rule expands the scope of the Clean Water Act’s jurisdiction, we could face increased costs and delays with respect to obtaining permits for dredge and fill activities in wetland areas. Obtaining permits has the potential to delay the development of oil and natural gas projects. These laws and any implementing regulations provide for administrative, civil and criminal penalties for any unauthorized discharges of oil and other substances in reportable quantities and may impose substantial potential liability for the costs of removal, remediation and damages.

Pursuant to these laws and regulations, we may be required to obtain and maintain approvals or permits for the discharge of wastewater or storm water. Spill prevention, control and countermeasure (“SPCC”) imposed under the CWA require operators of certain oil and natural gas facilities that store oil in more than threshold quantities, the release of which could reasonably be expected to reach jurisdictional waters, to develop, implement, and maintain SPCC plans. We are currently undertaking a review of our properties to determine the need for new or updated SPCC plans and, where necessary, we will be developing or upgrading such plans implementing the physical and operation controls imposed by these plans, the costs of which are not expected to be substantial.

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

Subsurface Injections

In the course of our operations, we produce water in addition to oil and natural gas. Water that is not recycled may be disposed of in disposal wells, which inject the produced water into non-producing subsurface formations. Underground injection operations are regulated pursuant to the Underground Injection Control (“UIC”) program established under the Safe Drinking Water Act (“SDWA”) and analogous state laws. The UIC program requires permits from the EPA or an analogous state agency for the construction and operation of disposal wells, establishes minimum standards for disposal well operations, and restricts the types and quantities of fluids that may be disposed. A change in UIC disposal well regulations or the inability to obtain permits for new disposal wells in the future may affect our ability to dispose of produced water and ultimately increase the cost of our operations. For example, in response to recent seismic events belowground near disposal wells used

 

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for the injection of oil and natural gas-related wastewaters, regulators in some states, including Texas, have imposed more stringent permitting and operating requirements for produced water disposal wells. In 2014, the 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. Additionally, legal disputes may arise based on allegations that disposal well operations have caused damage to neighboring properties or otherwise violated state or federal rules regulating waste disposal. These developments could result in additional regulation, restriction on the use of injection wells by us or by commercial disposal well vendors whom we may use from time to time to dispose of wastewater, and increased costs of compliance, which could have a material adverse effect on our capital expenditures and operating costs, financial condition, and results of operations.

Air Emissions

The Federal Clean Air Act (“CAA”) and comparable state laws restrict the emission of air pollutants from many sources, such as compressor stations, through air emissions standards, construction and operating permitting programs and the imposition of other compliance requirements. These laws and regulations may require us to obtain pre-approval for the construction or modification of certain projects or facilities expected to produce or significantly increase air emissions, obtain and strictly comply with stringent air permit requirements or utilize specific equipment or technologies to control emissions of certain pollutants. Over the next several years, we may be required to incur certain capital expenditures for air pollution control equipment or other air emissions related issues. For example, in October 2015, the EPA lowered the National Ambient Air Quality Standard (“NAAQS”) for ozone from 75 to 70 parts per billion. State implementation of the revised NAAQS could result in stricter permitting requirements, delay or prohibit our ability to obtain such permits and result in increased expenditures for pollution control equipment, the costs of which could be significant. In addition, the EPA has adopted new rules under the Clean Air Act that require the reduction of volatile organic compound emissions from certain fractured and refractured natural gas wells for which well completion operations are conducted and further require that most wells use reduced emission completions, also known as “green completions.” These regulations also establish specific new requirements regarding emissions from production-related wet seal and reciprocating compressors and from pneumatic controllers and storage vessels. More recently, in May 2016, the EPA finalized rules regarding criteria for aggregating multiple small surface sites into a single source for air-quality permitting purposes applicable to the oil and natural gas industry. This rule could cause small facilities, on an aggregate basis, to be deemed a major source, thereby triggering more stringent air permitting processes and requirements. See also “—Regulation of GHG Emissions.” Compliance with these and other air pollution control and permitting requirements has the potential to delay the development of oil and natural gas projects and increase our costs of development, which costs could be significant.

Regulation of GHG Emissions

In response to findings that emissions of carbon dioxide, methane and other GHGs present an endangerment to public health and the environment, the EPA has adopted regulations pursuant to the federal Clean Air Act that, among other things, require preconstruction and operating permits for certain large stationary sources. Facilities required to obtain preconstruction permits for their GHG emissions are also required to meet “best available control technology” standards that are being established by the states or, in some cases, by the EPA on a case-by-case basis. These regulatory requirements could adversely affect our operations and restrict or delay our ability to obtain air permits for new or modified sources. In addition, the EPA has adopted rules requiring the monitoring and reporting of GHG emissions from specified onshore and offshore oil and natural gas production sources in the United States on an annual basis, which include certain of our operations. Furthermore, in May 2016, the EPA finalized the New Source Performance Standards (“NSPS”) Subpart OOOOa standards that

 

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establish new controls for emissions of methane from new, modified or reconstructed sources in the oil and natural gas source category, including production, processing, transmission and storage activities. The rules include first-time standards to address emissions of methane from equipment and processes across the source category, including hydraulically fractured oil and natural gas well completions. In addition, the rules impose leak detection and repair requirements intended to address methane leaks known as “fugitive emissions” from equipment, such as valves, connectors, open ended lines, pressure-relief devices, compressors, instruments and meters. However, in April 2017, the EPA announced that it would review this methane rule for new, modified and reconstructed sources and initiated reconsideration proceedings to potentially revise or rescind portions of the rule. In June 2017, the EPA also proposed a two-year stay of certain requirements of the methane rule, pending the reconsideration proceedings; however, the rule remains in effect in the meantime. The EPA continues to evaluate the 2016 rules, and in September 2018 proposed additional amendments. The EPA has also announced that it intends to impose methane emission standards for existing sources as well but, to date, has not yet issued a proposal. Compliance with these rules will require enhanced record-keeping practices, the purchase of new equipment such as optical gas imaging instruments to detect leaks and increased frequency of maintenance and repair activities to address emissions leakage. The rules will also likely require hiring additional personnel to support these activities or the engagement of third party contractors to assist with and verify compliance. The BLM also finalized similar 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. These new and proposed rules could result in increased compliance costs on our operations.

While Congress has from time to time considered legislation to reduce emissions of GHGs, there has not been significant legislative activity at the federal level in recent years. In the absence of such federal climate legislation, a number of state and regional efforts have emerged that are aimed at tracking and/or reducing GHG emissions by means of cap and trade programs. These programs typically require major sources of GHG emissions to acquire and surrender emission allowances in return for emitting those GHGs.

Although it is not possible at this time to predict how legislation or new regulations that may be adopted to address GHG emissions would impact our business, any such future laws and regulations imposing reporting obligations on, or limiting emissions of GHGs from, our equipment and operations could require us to incur costs to reduce emissions of GHGs associated with our operations. Demand for our products may also be adversely affected by conservation plans and efforts undertaken in response to global climate change, including plans developed in connection with the recent Paris climate conference in December 2015. While the U.S. ratified plans associated with such conference in September 2016, the U.S. has recently opted not to continue governance under those plans. The Paris Agreement provides for a four-year exit process beginning when it took effect in November 2016, which would result in an effective exit date of November 2020. Many governments also provide, or may in the future provide, tax advantages and other subsidies to support the use and development of alternative energy technologies. Substantial limitations on GHG emissions could adversely affect demand for the oil and natural gas we produce and lower the value of our reserves.

Finally, increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods and other climatic events; if any such effects were to occur, they could have a material adverse effect on our operations. At this time, we have not developed a comprehensive plan to address the legal, economic, social or physical impacts of climate change on our operations.

Hydraulic Fracturing Activities

Hydraulic fracturing is an important and common practice that is used to stimulate production of oil and/or natural gas from dense subsurface rock formations. The hydraulic fracturing process involves the injection of water, proppants and chemicals under pressure into targeted subsurface formations to fracture the surrounding

 

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rock and stimulate production. We regularly use hydraulic fracturing as part of our operations. Hydraulic fracturing is typically regulated by state oil and natural gas commissions, but federal agencies have asserted jurisdiction over certain aspects of the process. The EPA has asserted federal regulatory authority pursuant to the SDWA over certain hydraulic fracturing activities involving the use of diesel fuels and published permitting guidance in February 2014 addressing the performance of such activities using diesel fuels. The EPA has also taken the following actions: issued final regulations under the federal Clean Air Act establishing performance standards, including standards for the capture of air emissions released during hydraulic fracturing; issued an advanced notice of proposed rulemaking under the Toxic Substances Control Act to require companies to disclose information regarding the chemicals used in hydraulic fracturing; and, in June 2016, published an effluent limitation guideline final rule prohibiting the discharge of wastewater from onshore unconventional oil and natural gas extraction facilities to publicly owned wastewater treatment plants. In addition, the Bureau of Land Management finalized rules in March 2015 that impose new or more stringent standards for performing hydraulic fracturing on federal and American Indian lands. 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. In addition, Congress has from time to time considered legislation to provide for federal regulation of hydraulic fracturing under the SDWA and to require disclosure of the chemicals used in the hydraulic fracturing process. It is unclear how any additional federal regulation of hydraulic fracturing activities may affect our operations.

Certain governmental reviews are either underway or being proposed that focus on environmental aspects of hydraulic fracturing practices. For example, in December 2016, the EPA released its final report on the potential impacts of hydraulic fracturing on drinking water resources. The final report concluded that “water cycle” activities associated with hydraulic fracturing may impact drinking water resources “under some circumstances”, noting that the following hydraulic fracturing water cycle activities and local- or regional-scale factors are more likely than others to result in more frequent or more severe impacts: water withdrawals for fracturing in times or areas of low water availability; surface spills during the management of fracturing fluids, chemicals or produced water; injection of fracturing fluids into wells with inadequate mechanical integrity; injection of fracturing fluids directly into groundwater resources; discharge of inadequately treated fracturing wastewater to surface waters; and disposal or storage of fracturing wastewater in unlined pits. Since the report did not find a direct link between hydraulic fracturing itself and contamination of groundwater resources, this years-long study report does not appear to provide any basis for further regulation of hydraulic fracturing at the federal level. These ongoing or proposed studies could spur initiatives to further regulate hydraulic fracturing under the federal SDWA or other regulatory mechanisms.

At the state level, several states have adopted or are considering legal requirements that could impose more stringent permitting, disclosure and well construction requirements on hydraulic fracturing activities. For example, in May 2013, the Railroad Commission of Texas issued a “well integrity rule”, which updates the requirements for drilling, putting pipe down and cementing wells. The rule also includes new testing and reporting requirements, such as (i) the requirement to submit cementing reports after well completion or after cessation of drilling, whichever is later, and (ii) the imposition of additional testing on wells less than 1,000 feet below usable groundwater. The well integrity rule took effect in January 2014. Local governments also may seek to adopt ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular.

Compliance with existing related laws has not had a material adverse effect on our operations or financial position, but if new or more stringent federal, state or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where we operate, we could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of development activities, and perhaps even be precluded from drilling wells.

 

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ESA and Migratory Birds

The Endangered Species Act (“ESA”) and (in some cases) comparable state laws were established to protect endangered and threatened species. Pursuant to the ESA, if a species is listed as threatened or endangered, restrictions may be imposed on activities adversely affecting that species or that species’ habitat. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act. We may conduct operations on oil and natural gas leases in areas where certain species that are listed as threatened or endangered are known to exist and where other species that potentially could be listed as threatened or endangered under the ESA may exist. The U.S. Fish and Wildlife Service may designate critical habitat and suitable habitat areas that it believes are necessary for survival of a threatened or endangered species. A critical habitat or suitable habitat designation could result in further material restrictions to federal land use and may materially delay or prohibit land access for oil and natural gas development. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act. In the past, the federal government has issued indictments under the Migratory Bird Treaty Act to several oil and natural gas companies after dead migratory birds were found near reserve pits associated with drilling activities. While the Department of Interior under the Trump administration has determined that such “incidental takes” of migratory birds do not violate the Act, this position has been challenged in a court action filed by environmental groups. The identification or designation of previously unprotected species as threatened or endangered in areas where underlying property operations are conducted could cause us to incur increased costs arising from species protection measures or could result in limitations on our development activities that could have an adverse impact on our ability to develop and produce reserves. If we were to have a portion of our leases designated as critical or suitable habitat, it could adversely impact the value of our leases.

OSHA

We are subject to the requirements of the Occupational Safety and Health Act (“OSHA”) and comparable state statutes whose purpose is to protect the health and safety of workers. In addition, the OSHA hazard communication standard, the Emergency Planning and Community Right-to-Know Act and comparable state statutes and any implementing regulations require that we organize and/or disclose information about hazardous materials used or produced in our operations and that this information be provided to employees, state and local governmental authorities and citizens.

Related Permits and Authorizations

Many environmental laws require us to obtain permits or other authorizations from state and/or federal agencies before initiating certain drilling, construction, production, operation, or other oil and natural gas activities, and to maintain these permits and compliance with their requirements for on-going operations. These permits are generally subject to protest, appeal, or litigation, which can in certain cases delay or halt projects and cease production or operation of wells, pipelines, and other operations.

Related Insurance

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

Employees

As of June 30, 2018, we employed 38 people. We are not a party to any collective bargaining agreements with our employees. We believe our relations with our employees to be satisfactory.

From time to time we utilize the services of independent contractors to perform various field and other services.

 

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Facilities

Our corporate headquarters is located in Oklahoma City, Oklahoma at 29 E. Reno Avenue, Suite 500, Oklahoma City, Oklahoma 73104.

Legal Proceedings

We are party to lawsuits arising in the ordinary course of our business. We cannot predict the outcome of any such lawsuits with certainty, but management believes it is remote that pending or threatened legal matters will have a material adverse impact on our financial condition.

Due to the nature of our business, we are, from time to time, involved in other routine litigation or subject to disputes or claims related to our business activities, including workers’ compensation claims and employment related disputes. In the opinion of our management, none of these other pending litigation, disputes or claims against us, if decided adversely, will have a material adverse effect on our financial condition, cash flows or results of operations.

 

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PRO FORMA CONDENSED FINANCIAL STATEMENTS

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 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.”

The earnings per common unit reflect the common units received by REG for all periods and the common units received by our other shareholders for the periods following their respective contributions.

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.

The unaudited pro forma balance sheet of the Company is based on the historical balance sheet as of June 30, 2018 and includes pro forma adjustments to give effect to the following transactions as if they occurred on June 30, 2018:

 

   

The Corporate Conversion which includes (i) our conversion from a Delaware limited liability company into Riley Exploration Permian, Inc., a Delaware corporation and (ii) the conversion of the common units and Series A Preferred Units into shares of our common stock; and

 

   

The initial public offering of                  shares of the Company’s common stock and use of net proceeds therefrom as described in “Use of Proceeds” (the “Offering”). The net proceeds are expected to be approximately $                 million, net of underwriting discounts and commissions of approximately $                 million and other offering costs of approximately $                 million.

The unaudited pro forma statement of operations of the Company for the nine months ended June 30, 2018 reflects the historical statement of operations of the Company for the entire period.

The unaudited pro forma statement of operations of the Company for the year ended September 30, 2017 is based on the audited historical statement of operations of the Company for the year ended September 30, 2017 and the unaudited statements of operation of the businesses acquired from October 1, 2016 to their respective acquisition dates. The statement includes pro forma adjustments to give effect to the following transactions as if they occurred on October 1, 2016.

 

   

The acquisition of Boomer’s 28% working interest in the Champions Assets on January 17, 2017 and the acquisition of Bluescape and DR/CM’s combined 29.3% working interest in the Champions Assets on March 6, 2017.

 

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The following pro forma adjustments are made to the unaudited pro forma statements of operations for the nine months ended June 30, 2018 and year ended September 30, 2017, to give effect to the following transactions as if they occurred on October 1, 2016:

 

   

The Corporate Conversion which includes (i) the conversion of Riley Permian from a Delaware limited liability company into Riley Exploration Permian, Inc., a Delaware corporation and (ii) the conversion of the common units and Series A Preferred Units of the Company into our common stock.

The pro forma data presented reflects events directly attributable to the above described transactions and certain assumptions we believe are reasonable. The pro forma adjustments are based on currently available information and certain estimates and assumptions. Therefore, the actual adjustments may differ from the pro forma adjustments. However, management believes that the pro forma assumptions provide a reasonable basis for presenting the significant effects of the transactions as contemplated and that the pro forma adjustments give appropriate effect to those assumptions and are properly applied in the unaudited pro forma combined financial statements.

Our unaudited pro forma statements of operations and related notes are presented for illustrative purposes only. If this offering had occurred in the past, our operating results might have been materially different from those presented in the unaudited pro forma combined financial statements. The unaudited pro forma statements of operations should not be relied upon as an indication of the operating results that we would have achieved if this offering or any of the transactions described above had taken place on another specified date. In addition, future results may vary significantly from the results reflected in the unaudited pro forma statements of operations and should not be relied on as an indication of our future results.

The unaudited pro forma statements of operations should be read in conjunction with the notes thereto and with our historical financial statements and related notes contained elsewhere in this prospectus.

 

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Unaudited Pro Forma Consolidated Balance Sheet

As of June 30, 2018

(in thousands)

 

     Company
Historical
     Corporate
Conversion
         Offering          Pro forma  

Assets

               

Current assets

               

Cash and cash equivalents

   $ 1,029      $ —          $ (2,100   (e)    $    

Accounts receivable

     7,174        —            —            7,174  

Other accounts receivable

     9        —            —            9  

Prepaid expenses and other current assets

     372        —            —            372  
  

 

 

    

 

 

      

 

 

      

 

 

 

Total current assets

     8,584        —              

Non-current assets

               

Oil and gas properties, net

     227,914        —            —            227,914  

Other property and equipment

     1,843        —            —            1,843  

Other non-current assets

     3,792        —            (1,975   (f)   
  

 

 

    

 

 

      

 

 

      

 

 

 

Total non-current assets

     233,549        —            —            233,549  
  

 

 

    

 

 

      

 

 

      

 

 

 

Total assets

   $ 242,133      $ —          $          $    
  

 

 

    

 

 

      

 

 

      

 

 

 

Liabilities and Members’ equity

               

Current liabilities

               

Accounts payable

   $ 5,448      $ —          $ —          $ 5,448  

Accrued liabilities

     19,474        —            (4,000  

(e)

     15,474  

Revenue payable

     4,098        —            —            4,098  

Advances from joint interest owners

     534        —            —            534  

Notes payable—current

     113        —            —            113  

Derivative liabilities

     8,907        —            —            8,907  
  

 

 

    

 

 

      

 

 

      

 

 

 

Total current liabilities

     38,574        —            (4,000        34,574  

Notes payable—non-current

     —          —            —            —    

Non-current derivative liabilities

     1,753        —            —            1,753  

Asset retirement obligations

     826        —            —            826  

Revolving credit facility

     44,000        —            (g)   

Deferred tax liability

     —          5,064     (a)      —            5,064  
  

 

 

    

 

 

      

 

 

      

 

 

 

Total liabilities

     85,153        5,064          (4,000     

Series A Preferred Units

     52,739        (52,739   (c)      —            —    

Members’ / Stockholders’ equity

               

Members’ equity

     104,241        (104,241   (b)      —            —    

Common stock, par value $0.01

     —          —       (b)(c)      —       (e)      —    

Additional paid -in capital

     —          170,165     (b)(c)      2,025     (d)(e)(f)   

Retained earnings

     —          (18,249   (a)(c)      (2,100   (e)      (20,349
  

 

 

    

 

 

      

 

 

      

 

 

 

Total Members’ / Stockholders’ equity

     104,241        47,675            
  

 

 

    

 

 

      

 

 

      

 

 

 

Total liabilities and Members’ / Stockholders’ equity

   $ 242,133      $ —          $          $    
  

 

 

    

 

 

      

 

 

      

 

 

 

The accompanying notes are an integral part of these unaudited pro forma consolidated financial statements.

 

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Unaudited Pro Forma Consolidated Statement of Operations

For the Nine Months Ended June 30, 2018

(in thousands, except per unit and per share data)

 

     Company
Historical
    Corporate
Conversion
           Pro forma        

Revenues:

           

Oil sales

   $ 46,438     $ —          $ 46,438    

Natural gas sales

     252       —            252    

Natural gas liquids sales

     909       —            909    
  

 

 

   

 

 

      

 

 

   

Total revenues

     47,599       —            47,599    
  

 

 

   

 

 

      

 

 

   

Operating expenses:

           

Lease operating expenses

     8,135       —            8,135    

Production taxes

     2,191       —            2,191    

Exploration costs

     5,523       —            5,523    

Depletion, depreciation, amortization and accretion

     11,388       —            11,388    

General administrative expenses

     10,596       —            10,596    

Stock compensation expense

     —            (l    

Transaction costs

     790       —            790    
  

 

 

   

 

 

      

 

 

   

Total operating expenses

     38,623       —            38,623    
  

 

 

   

 

 

      

 

 

   

Income from operations

     8,976       —            8,976    

Other expenses:

           

Interest expense

     (907     —            (907  

Loss on derivatives

     (13,895     —            (13,895  
  

 

 

   

 

 

      

 

 

   

Loss before income tax benefit

     (5,826     —            (5,826  

Income tax benefit

     —         1,450        (m     1,450    
  

 

 

   

 

 

      

 

 

   

Net loss

     (5,826     1,450          (4,376  

Dividends on preferred units

     (2,327     2,327        (n    
  

 

 

   

 

 

      

 

 

   

Net loss attributable to common units

   $ (8,153   $ 3,777        $ (4,376  
  

 

 

   

 

 

      

 

 

   

Loss per unit

           

Basic and diluted

   $ (5.44         
  

 

 

          

Weighted average units outstanding

     1,500           
  

 

 

          

Basic pro forma net income per common share

              (o
         

 

 

   

Diluted pro forma net income per common share

              (o
         

 

 

   

Pro Forma weighted common shares outstanding

          (p       (p
    

 

 

      

 

 

   

The accompanying notes are an integral part of these unaudited pro forma consolidated financial statements.

 

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Unaudited Pro Forma Consolidated Statement of Operations

For the Year Ended September 30, 2017

(in thousands, except per unit and per share data)

 

     Company
Historical
    Boomer
acquisition
          Bluescape
DR/CM
acquisition
          Corporate
Conversion
           Pro forma        

Revenues:

                   

Oil sales

   $ 21,174     $ 1,499       (h   $ 2,409       (i   $          $ 25,082    

Natural gas sales

     203       26       (h     38       (i          267    

Natural gas liquids sales

     431       50       (h     73       (i          554    

Other revenue

     —         —           —                —      
  

 

 

   

 

 

     

 

 

     

 

 

      

 

 

   

Total revenues

     21,808       1,575         2,520         —            25,903    
  

 

 

   

 

 

     

 

 

     

 

 

      

 

 

   

Operating expenses:

                   

Lease operating expenses

     5,796       559       (h     930       (i          7,285    

Production taxes

     1,206       120       (h     176       (i          1,502    

Exploration costs

     10,739       —           4       (i          10,743    

Depletion, depreciation, amortization and accretion

     5,876       400       (j     652       (j          6,928    

General administrative expenses

     5,806       —           —                5,806    

Stock compensation expense

     —         —           —              (l    

Transaction costs

     1,766       (883     (k     (883     (k          —      
  

 

 

   

 

 

     

 

 

     

 

 

      

 

 

   

Total operating expenses

     31,189       196         879         —            32,264    
  

 

 

   

 

 

     

 

 

     

 

 

      

 

 

   

Loss from operations

     (9,381     1,379         1,641         —            (6,361  

Other expenses:

                   

Loss on derivatives

     (1,450     —           —                (1,450  
  

 

 

   

 

 

     

 

 

     

 

 

      

 

 

   

Loss before income tax benefit

     (10,831     1,379         1,641         —            (7,811  

Income tax benefit

     —         —           —           2,624        (m     2,624    
  

 

 

   

 

 

     

 

 

     

 

 

      

 

 

   

Net loss

     (10,831     1,379         1,641         —            (5,187  

Dividends on preferred units

     (1,409     —           —           1,409        (n     —      
  

 

 

   

 

 

     

 

 

     

 

 

      

 

 

   

Net loss attributable to common units

   $ (12,240   $ 1,379       $ 1,641       $ 4,033        $ (5,187  
  

 

 

   

 

 

     

 

 

     

 

 

      

 

 

   

Loss per unit

                   

Basic and diluted

   $ (10.63                 
  

 

 

                  

Weighted average units outstanding

     1,151                   
  

 

 

                  

Pro forma net loss per common share

                      (o
                 

 

 

   

Pro Forma weighted common shares outstanding

                  (p       (p
         

 

 

      

 

 

   

The accompanying notes are an integral part of these unaudited pro forma consolidated financial statements.

 

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Notes to Unaudited Pro Forma Consolidated Financial Statements

Note 1 Basis of presentation

Our unaudited pro forma financial information is derived from our financial statements included elsewhere in this prospectus and from the unaudited statements of operations of the businesses acquired from October 1, 2016 to their respective acquisition dates. The unaudited pro forma financial statements were prepared in accordance with GAAP and pursuant to Regulation S-X Article 11.

The pro forma data presented reflects events directly attributable to the described transactions and certain assumptions we believe are reasonable. The pro forma data are not necessarily indicative of financial results that would have been attained had the described transactions occurred on the dates indicated or which could be achieved in the future because they necessarily exclude various operating expenses, such as incremental general and administrative expenses. The adjustments are based on currently available information and certain estimates and assumptions. However, management believes that the assumptions provide a reasonable basis for presenting the significant effects of the transactions as contemplated and that the pro forma adjustments give appropriate effect to those assumptions and are properly applied in the unaudited pro forma financial statements.

The unaudited pro forma financial statements have been prepared on the basis that we will be taxed as a corporation, and as a result, will become a tax-paying entity subject to U.S. federal and state income taxes, and should be read in conjunction with “Corporate Conversion,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and with the historical financial statements and related notes of the Company, included elsewhere in this prospectus.

Upon the closing of the offering contemplated by this prospectus, we expect to incur direct, incremental general and administrative expenses as a result of being a publicly traded company, including, but not limited to, costs associated with annual and quarterly reports to stockholders, tax return preparation, incremental independent auditor fees, investor relations activities, registrar and transfer agent fees, incremental director and officer liability insurance costs, and independent director compensation. Such costs are not reflected in these pro forma financial statements.

Note 2 Pro forma adjustments and assumptions

We made the following adjustments and assumptions in the preparation of the unaudited pro forma balance sheet as of June 30, 2018.

 

  a)

Reflects the pro forma net deferred tax liability of $5.1 million as of June 30, 2018 arising from the temporary differences between the historical cost and tax basis of the Company’s assets and liabilities as a result of the change in the Company’s tax status to a subchapter C corporation. As a result of the enactment of the Tax Cuts and Jobs Act on December 22, 2017, the corporate income tax rate was reduced from 35% to 21%. The pro forma deferred tax liabilities reflect the rates expected to be in effect when the temporary differences reverse in the future, which is 21%. A charge to establish such net deferred tax liabilities will be recognized in the period when the change in the status occurs but has not been reflected in the pro forma consolidated statement of operations.

 

  b)

Reflects the issuance of                million shares of common stock in exchange for all of our common units.

 

  c)

Reflects the conversion of Riley Permian’s Series A Preferred Units into                million shares of our common stock. The amount of our common stock issued as a result of the conversion of Series A Preferred Units 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

 

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  will result in a deemed preferred distribution to the Series A Preferred Unit holders of $13.2 million, which will reduce income attributable to common units in the period in which the conversion occurs. This reduction has not been reflected in the pro forma consolidated statement of operations.

 

  d)

Reflects the issuance of                million shares of common stock in connection with this offering. The net proceeds are expected to be approximately $                million, net of underwriting discounts and commissions of approximately $                million and other offering costs of approximately $                million.

 

  e)

Reflects one time bonuses consisting of: (1) 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 in connection with the IPO and (2) the payment of a bonus to executives earned and accrued as of June 30, 2018 in common stock instead of in cash, consisting of                vested shares of common stock, which represents approximately $4.0 million (assuming the value of each share is equal to $                (which represents the midpoint of the price range set forth on the cover of this prospectus with respect to a share of our common stock)). The $2.1 million of one-time cash bonuses has not been reflected in the pro forma consolidated statement of operations, but will be recorded as compensation expense in the period in which the IPO occurs.

 

  f)

Reflects existing balance of $2.0 million in deferred IPO costs to be netted against the proceeds from this offering with a corresponding reduction to additional paid-in capital upon completion of this offering.

 

  g)

Reflects existing balance of approximately $                 million under our revolving credit facility to be repaid upon completion of this offering.

After the Corporate Conversion, and giving effect to this offering and the vested LTIP shares, the total number of our authorized and outstanding common stock will be                  and                 , respectively.

We made the following adjustments and assumptions in the preparation of the unaudited pro forma statement of operations for the nine months ended June 30, 2018 and/or the year ended September 30, 2017:

 

  h)

Reflects the historical revenues and direct operating expenses from the assets acquired and liabilities assumed in the acquisition of Boomer’s working interest in the Champions Assets for the period from October 1, 2016 to the date of acquisition closing, January 17, 2017. No such adjustment was required for the nine months ended June 30, 2018 as the operating results of the acquired businesses were already included for the full period.

 

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Index to Financial Statements
    3-05 Financial
statements
    Less Bluescape     Boomer     Less Boomer     Boomer     Boomer     Pro forma
adjustment
 
    Year ended
December 31,
2016
    Year ended
December 31,
2016
    Year ended
December 31,
2016
    Period from
January 1 to
September 30,
2016
    Three Months
ended
December 31,
2016
    Period from
January 1,
2017 to
January 17,
2017
    Boomer  
    a     b     c=a-b     d     e=c-d     f     e+f  

Revenue

             

Oil

  $ 8,855     $ (4,526   $ 4,329     $ (3,080   $ 1,249     $ 250     $ 1,499  

Gas

    114       (58     56       (14     42       (16     26  

NGL

    91       (47     44       (21     23       27       50  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total revenues

    9,060       (4,631     4,429       (3,115     1,314       261       1,575  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Lease operating expenses

    (3,172     1,621       (1,551     1,124       (427     (173     (600

Workovers

    (1,822     931       (891     891       —         —         —    
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total lease operating expenses

    (4,994     2,552       (2,432     2,015       (427     (173     (600
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Exploration expense

    (21     21       —         —         —         —         —    

Production tax

    (432     221       (211     145       (66     (54     (120

 

  i)

Reflects the historical revenues and direct operating expenses from the assets acquired and liabilities assumed in the acquisition of Bluescape and DR/CM’s working interest in the Champions Assets for the period from October 1, 2016 to the date of acquisition closing, March 6, 2017. No such adjustment was required for the nine months ended June 30, 2018 as the operating results of the acquired business were already included for the full period.

 

    3-05 Financial
statements
    Less Boomer     Bluescape
DR/CM
    Less Bluescape
DR/CM
    Bluescape
DR/CM
    Bluescape
DR/CM
    Pro forma
adjustment
 
    Year ended
December 31,
2016
    Year ended
December 31,
2016
    Year ended
December 31,
2016
    Period from
January 1 to
September 30,
2016
    Three Months
ended
December 31,
2016
    Period from
January 1,
2017 to
March 7,
2017
    Bluescape
DR/CM
 
    a     b     c=a-b     d     e=c-d     f     e+f  

Revenue

             

Oil

  $ 8,855     $ (4,329   $ 4,526     $ (3,220   $ 1,306     $ 1,103     $ 2,409  

Gas

    114       (56     58       (14     44       (6     38  

NGL

    91       (44     47       (22     25       48       73  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total revenues

    9,060       (4,429     4,631       (3,256     1,375       1,145       2,520  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Lease operating expenses

    (3,172     1,550       (1,622     1,176       (446     (485     (931

Workovers

    (1,822     891       (931     931       —         —         —    
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total lease operating expenses

    (4,993     2,441       (2,552     2,107       (446     (485     (931
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Exploration expense

    (21     —         (21     17       (4     —         (4

Production tax

    (432     211       (221     151       (70     (106     (176

 

  j)

Reflects the adjustment to depletion, depreciation, amortization and accretion expense that would have been recorded had the Boomer, Bluescape and DR/CM’s acquisitions occurred on October 1, 2016. We utilized reserve reports to estimate the useful life of acquired wells and depleted the capitalized costs on a units-of-production basis over the remaining life of the proved and proved developed reserves.

 

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Index to Financial Statements
  The depletion rate used was approximately $11.60 per MBoe for the year ended September 30, 2017. No such adjustment was required for the nine months ended June 30, 2018 as the operating results of the acquired businesses were already included for the full period.

 

  k)

Reflects the elimination of the transaction costs related to the Boomer, Bluescape and DR/CM acquisitions during the year ended September 30, 2017. No such adjustment was required for the nine months ended June 30, 2018 as the operating results of the acquired businesses were already included for the full period.

 

  l)

Reflects the estimated compensation expense associated with the granting of equity based awards under the LTIP, consisting of            unvested shares of common stock which will be subject to a three-year vesting, had such awards been granted on October 1, 2016. The estimated grant date fair value of these awards, based on the midpoint of the price range set forth on the cover of this prospectus with respect to a share of our common stock is $        million.

 

  m)

Reflects the estimated income tax benefit associated with our pro forma results of operations assuming our earnings had been subject to federal and state income tax as a sub-chapter C corporation using a combined federal and state tax rate of approximately 23.6% and 33.6% based on the estimated US federal income tax rate during the nine months ended June 30, 2018 and the year ended September 30, 2017, respectively. The decrease in the estimated US federal income tax rate during the nine months ended June 30, 2018 reflects the impact of the Tax Cuts and Jobs Act which was enacted on December 22, 2017 and reduced the corporate income tax rate, effective January 1, 2018, to 21%.

 

  n)

Reflects the reversal of the dividend accrued related to the Series A Preferred Units which are assumed to have been converted as of their issuance dates.

 

  o)

Reflects the basic and diluted loss per common share for the issuance of shares of common stock in the Corporate Conversion as if the Corporate Conversion had occurred on October 1, 2016.

 

  p)

Reflects the number of common shares issued in connection with the Corporate Conversion which includes the exchange of common units for                common shares and the conversion of the Series A Preferred Units for                common shares as if the exchange of common units had occurred on October 1, 2016 and the conversion of preferred units had occurred on their issuance dates.

Note 3 Supplementary disclosure of oil and gas operations

The following pro forma standardized measure of the discounted net future cash flows and changes applicable to our proved reserves reflect the effect of income taxes assuming our standardized measure had been subject to federal and state income tax as a subchapter C corporation. The future cash flows are discounted at 10% per year and assume continuation of existing economic conditions.

The standardized measure of discounted future net cash flows, in management’s opinion, should be examined with caution. The basis for this table is the reserve studies prepared by independent petroleum engineering consultants, which contain imprecise estimates of quantities and rates of production of reserves. Revisions of previous year estimates can have a significant impact on these results. Also, exploration costs in one year may lead to significant discoveries in later years and may significantly change previous estimates of proved reserves and their valuation. Therefore, the standardized measure of discounted future net cash flow is not necessarily indicative of the fair value of our proved oil and gas properties. The data presented should not be viewed as representing the expected cash flow from or current value of, existing proved reserves since the computations are based on a large number of estimates and arbitrary assumptions. Reserve quantities cannot be measured with precision and their estimation requires many judgmental determinations and frequent revisions. Actual future prices and costs are likely to be substantially different from the prices and costs utilized in the computation of reported amounts.

 

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Index to Financial Statements

The following table provides a pro forma roll forward of total proved reserves for the year ended September 30, 2017, as well as pro forma proved developed producing and proved undeveloped reserves at the beginning and end of the year as if the January 17, 2017 acquisition of the Champions Assets from Boomer and the March 6, 2017 acquisition from Bluescape and DR/CM occurred on October 1, 2016. Specifically, had the acquisition of each occurred on October 1, 2016, rather than all of the reserves being proved at the date of acquisitions, certain of the reserves would have been unproved at such date, but added to our proved reserves through “extensions, discoveries and additions” during the period from the applicable date of acquisition through September 30, 2017. Similarly, had both acquisitions occurred on October 1, 2016, we would have acquired more reserves attributable to the forecasted production between October 1, 2016 and the date of each acquisition, such that our “acquisition” total would be increased with an equal amount reflected as additional “production”.

 

     Year Ended September 30, 2017  
     Company
Historical
    Boomer
acquisition
    Bluescape
DR/CM
acquisition
    Pro Forma
Adjustments (a)
    Pro Forma  
     (MBoe)     (MBoe)     (MBoe)     (MBoe)     (MBoe)  

Proved Developed and Undeveloped Reserves:

          

Beginning of Year

     3,354.6       —         —         —         3,354.6  

Extensions, discoveries and additions

     2,942.5       512.4       530.1       —         3,985.0  

Acquisitions

     5,464.5       —         —         (1,328.1     4,136.4  

Revisions

     2,750.5       183.7       196.0       —         3,130.2  

Production

     (503.5     (35.4     (58.7     —         (597.6

Sales of reserves-in-place

     —         (660.7     (667.4     1,328.1       —    
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

End of Year

     14,008.6       —         —         —         14,008.6  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Proved Developed Reserves:

          

Beginning of Year

     1,719.2       —         —         —         1,719.2  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

End of Year

     8,225.5       —         —         —         8,225.5  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Proved Undeveloped Reserves:

          

Beginning of Year

     1,635.4       —         —         —         1,635.4  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

End of Year

     5,783.1       —         —         —         5,783.1  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

 

(a)

To adjust the amount of purchases of reserves for the Boomer and Bluescape and DR/CM acquisitions already included within the Company’s historical information.

For the year ended September 30, 2017, the Company had upward revisions of previous estimates of 3,130.2 MBoe. These upward revisions are comprised of 2,784.2 MBoe increase attributable to better well performance on new wells that exceeded previous estimates, and 346.0 MBoe is attributable to a decrease in LOE which extended the life of the wells. The Company also began breaking the LOE assumptions into a fixed well, and variable basis to minimize over-estimating fixed well costs. This change in LOE modeling added economic life to a number of wells and locations. As a result of ongoing drilling and completion activities during the fiscal year ended in 2017, the Company reported extensions, discoveries, and other additions of 3,985.0 MBoe, which included adding 7 PUD locations based on offset development. Additionally, the Company purchased reserves of 4,136.4 MBoe on October 1, 2016 in connection with the Boomer, Bluescape and DR/CM acquisitions.

 

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Index to Financial Statements

The following table provides a pro forma roll forward of total proved reserves of crude oil for the year ended September 30, 2017, as well as pro forma proved developed and proved undeveloped reserves at the beginning and end of the year as if the January 2017 acquisition of Boomer and March 2017 acquisition of Bluescape and DR/CM occurred on October 1, 2016.

 

     Company
Historical
    Boomer
acquisition
    Bluescape
DR/CM
acquisition
    Pro Forma
Adjustments
(a)
    Pro Forma  
     Crude Oil
Mbbls
    Crude Oil
Mbbls
    Crude Oil
Mbbls
    Crude Oil
Mbbls
    Crude Oil
Mbbls
 

Proved developed and undeveloped reserves:

          

Beginning of Year

     2,904.3       —         —         —         2,904.3  

Extensions, discoveries and additions

     2,575.4       444.0       459.0       —         3,478.4  

Acquisitions

     4,732.2       —         —         (826.7     3,905.5  

Revisions

     2,283.5       2.3       6.5       —         2,292.3  

Production

     (469.5     (31.9     (53.2     —         (554.6

Sales of reserves-in-place

     —         (414.4     (412.3     826.7       —    
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

End of Year

     12,025.9       —         —         —         12,025.9  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Proved developed reserves:

          

Beginning of Year

     1,484.4       —         —         —         1,484.4  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

End of Year

     7,064.4       —         —         —         7,064.4  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Proved undeveloped reserves:

          

Beginning of Year

     1,419.9       —         —         —         1,419.9  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

End of Year

     4,961.4       —         —         —         4,961.4  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

 

(a)

To adjust the amount of purchases of reserves for the Boomer and Bluescape and DR/CM acquisitions already included within the Company’s historical information.

The following table provides a pro forma roll forward of total proved reserves of natural gas for the year ended September 30, 2017, as well as pro forma proved developed and proved undeveloped reserves at the beginning and end of the year as if the January 2017 acquisition of Boomer and March 2017 acquisition of Bluescape and DR/CM occurred on October 1, 2016.

 

     Company
Historical
    Boomer
acquisition
    Bluescape
DR/CM
acquisition
    Pro Forma
Adjustments
(a)
    Pro Forma  
     Natural Gas
MMcf
    Natural Gas
MMcf
    Natural Gas
MMcf
    Natural Gas
MMcf
    Natural Gas
MMcf
 

Proved developed and undeveloped reserves:

          

Beginning of Year

     1,030.8       —         —         —         1,030.8  

Extensions, discoveries and additions

     967.8       157.8       164.4       —         1,290.0  

Acquisitions

     1,677.0       —         —         (292.2     1,384.8  

Revisions

     1,222.2       0.6       (2.4     —         1,220.4  

Production

     (77.4     (11.4     (16.8     —         (105.6

Sales of reserves-in-place

     —         (147.0     (145.2     292.2       —    

End of Year

     4,820.4       —         —         —         4,820.4  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Proved developed reserves:

          

Beginning of Year

     537.2       —         —         —         537.2  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

End of Year

     2,814.4       —         —         —         2,814.4  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Proved undeveloped reserves:

          

Beginning of Year

     493.6       —         —         —         493.6  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

End of Year

     2,006.2       —         —         —         2,006.2  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

 

(a)

To adjust the amount of purchases of reserves for the Boomer and Bluescape and DR/CM acquisitions already included within the Company’s historical information.

 

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Index to Financial Statements

The following table provides a pro forma roll forward of total proved reserves of NGL for the year ended September 30, 2017, as well as pro forma proved developed and proved undeveloped reserves at the beginning and end of the year as if the January 2017 acquisition of Boomer and March 2017 acquisition of Bluescape and DR/CM occurred on October 1, 2016.

 

     Company
Historical
    Boomer
acquisition
    Bluescape
DR/CM
acquisition
    Pro Forma
Adjustments
(a)
    Pro
Forma
 
     NGL
Mbbls
    NGL
Mbbls
    NGL
Mbbls
    NGL
Mbbls
    NGL
Mbbls
 

Proved developed and undeveloped reserves:

          

Beginning of Year

     278.5       —         —         —         278.5  

Extensions, discoveries and additions

     205.8       42.1       43.7       —         291.6  

Acquisitions

     452.8       —         —         (452.7     0.1  

Revisions

     263.3       181.3       189.9       —         634.5  

Production

     (21.1     (1.6     (2.7     —         (25.4

Sales of reserves-in-place

     —         (221.8     (230.9     452.7       —    

End of Year

     1,179.3       —         —         —         1,179.3  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Proved developed reserves:

          

Beginning of Year

     145.1       —         —         —         145.1  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

End of Year

     692.1       —         —         —         692.1  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Proved undeveloped reserves:

          

Beginning of Year

     133.4       —         —         —         133.4  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

End of Year

     487.2       —         —         —         487.2  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

 

(a)

To adjust the amount of purchases of reserves for the Boomer and Bluescape and DR/CM acquisitions already included within the Company’s historical information.

The pro forma standardized measure of discounted estimated future net cash flows was as follows as of September 30, 2017 (in thousands):

 

     Company
Historical
    Corporate
Conversion (a)
    Pro Forma (b)  

Future crude oil, natural and NGL Sales

   $ 562,349     $ —       $ 562,349  

Future production costs

     (156,563     —         (156,563

Future development costs

     (42,849     —         (42,849

Future income tax expense

     (2,953     (76,091     (79,044
  

 

 

   

 

 

   

 

 

 

Future net cash flows

     359,984       (76,091     283,893  

10% annual discount

     (216,797     47,261       (169,536
  

 

 

   

 

 

   

 

 

 

Standardized measure of discounted future net cash flows

   $ 143,187     $ (28,830     114,357  
  

 

 

   

 

 

   

 

 

 

 

(a)

Represents an adjustment to include future tax expense associated with the Corporate Conversion.

(b)

The pro forma standardized measure includes the Boomer, Bluescape and DR/CM acquisitions.

 

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Index to Financial Statements

The changes in the pro forma standardized measure of discounted estimated future net cash flows were as follows for the year ended September 30, 2017 (in thousands):

 

     Company
Historical
    Boomer
Acquisition
    Bluescape
DR/CM
Acquisition
    Corporate
Conversion (a)
    Pro forma
Adjustments (b)
    Pro forma  

Balance at beginning of period

     19,124       —         —         —         —         19,124  

Sales of crude oil, natural gas and natural gas liquids, net

     (14,806     (1,411     (2,301     —         —         (18,518

Net change in prices and production costs

     18,074       282       2,797       —         —         21,153  

Net change in future development costs

     (1,307     67       491       —         —         (749

Extensions, discoveries, and other additions

     29,241       3,938       4,692       —         —         37,871  

Acquisition of reserves

     43,718       —         —         —         (16,217     27,501  

Revisions of previous quantity estimates

     28,676       1,293       1,750       —         —         31,719  

Previously estimated development costs incurred

     4,491       112       117       —         —         4,720  

Net change in income taxes

     81       (47     (80     (28,830     —         (28,876

Accretion of discount

     4,792       334       583       —         —         5,709  

Sales of reserves-in-place

     —         (5,419     (10,798     —         16,217       —    

Other

     11,103       851       2,749       —         —         14,703  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Balance at end of period

     143,187       —         —         (28,830     —         114,357  

 

(a)

Represents an adjustment to reflect the Corporate Conversion into a taxable entity.

(b)

To adjust the amount of acquisition of reserves for the Boomer and Bluescape and DR/CM acquisitions already included within the Company’s historical information.

 

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Index to Financial Statements

MANAGEMENT

The following table sets forth the names, ages and positions of our executive officers and directors as of the date of this prospectus.

 

Name

   Age  

Position(s) Held

Bobby D. Riley

   62   Chairman of the Board, President and Chief Executive Officer

Kevin Riley

   37   Executive Vice President and Chief Operating Officer

James J. Doherty, Jr.

   61   Executive Vice President of Engineering

Jeffrey M. Gutman

   52   Executive Vice President, Chief Financial Officer and Treasurer

Bryan H. Lawrence

   76   Director

Philip Riley

   44   Director

Antonie VandenBrink

   89   Director

Nelson M. Haight

   53   Director Nominee

E. Wayne Nordberg

   80   Director Nominee

Bobby D. Riley was appointed as the Chairman of our board of directors, President and Chief Executive Officer in June 2016. Mr. Riley also serves as the Chief Executive Officer of REG since it was founded in 2012. Prior to joining the Company, Mr. Riley was the Chairman and Chief Executive Officer of Riley Exploration, LLC, or REX, since he founded REX in 2007 through 2012. Mr. Riley has nearly 40 years of experience in the independent oil and gas sector, in North America, South America, Europe, Africa and Asia. He has an extensive background in all aspects of oil and gas management and operations, including drilling, completion, work-over and production. In addition to his management and operational expertise, he has designed and patented specialized completion equipment that was licensed to Baker-Hughes and participated in the design, development and testing of Intelligent Well Bore Systems, which was sold to Weatherford International in 2000. In 2009, Mr. Riley created a joint venture with a private equity group to invest in unconventional oil and gas plays and deployed over $350 million of debt and equity capital in the Eagle Ford Shale and the Permian Basin. The joint venture acquired approximately 50,000 acres of prime leasehold acreage, drilled and completed over 40 wells and reached peak production of 4,000 BOE/d. From 2005 to 2007 Mr. Riley was Vice President of Operations at Activa Resources, Inc., or Activa, a publicly-traded exploration and production company. From 2002 to 2005, he was Managing Partner of Tuleta Energy Partners, LLC, a privately-held exploration and production company, until it was acquired by Activa Resources, Inc. From 1991 to 2001 Mr. Riley was President of an oil and gas service company specializing in well design and reservoir data acquisition, that was active in Nigeria, Venezuela, and Norway. He founded his first independent exploration and production company, Durango Energy, Inc., in 1984, and operated up to 150 wells in Oklahoma. Prior to that he was District Manager of Monitoring Systems Inc., a drilling and well control instrumentation company, installing equipment on jack-up rigs and semi-submersibles in the U.S., Brazil and Korea. Mr. Riley began his oil and gas career with Cameron Iron Works in Houston, Texas, in 1974. Mr. Riley has a bachelor’s degree in Business, Accounting and Finance from the University of Science & Arts of Oklahoma and completed the Advanced Drilling Operations and Well Control program at Murchison Drilling Schools. He is a member of the American Petroleum Institute and the Society of Professional Engineers and is IADC / MMS Well-Cap Certified. We believe Mr. Riley’s experience founding and leading our growth as our Chief Executive Officer and his extensive experience working with various oil and gas companies qualifies him to serve on our board of directors.

Kevin Riley was appointed as our Executive Vice President and Chief Operating Officer in June 2016. Mr. Kevin Riley manages all oil and gas exploration and production activities. Prior to joining the Company, Mr. Kevin Riley has been the Chief Operating Officer of REG since it was founded in 2012 and was the Chief Operating Officer of REX since REX was founded in 2007 through 2012. He has led the successful acquisition and development of REG’s +50,000 acres located across three active operating areas: the Permian Basin, Eagle Ford Shale and Arkoma-Woodford Shale. Mr. Kevin Riley co-founded REG in 2007, which developed early entrant positions into the Wolfberry trend of the Permian Basin and the Eagle Ford Shale in Karnes County and thereafter served as Chief Operating Officer of REG until his appointment as Chief Operating Officer of the Company in 2016. He had direct oversight of the company’s land, drilling, completion and production activities,

 

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which included more than 70,000 acres under lease and +50 operated horizontal wells via a multi-rig drilling program. Ultimately, Mr. Kevin Riley positioned the company to successfully develop the assets full-cycle—from geological concepts through divestiture. Mr. Kevin Riley holds a degree in Business Administration from the University of Central Oklahoma and a MBA with emphasis in Energy from the University of Oklahoma. He is a member of the Independent Petroleum Association of America, American Association of Petroleum Landmen and the Society of Petroleum Engineers.

James J. Doherty, Jr. has served as the Executive Vice President of Engineering of Riley Permian since June 2016. Prior to joining the Company, Mr. Doherty was the Executive Vice President of Engineering of REG beginning in 2013 was the Executive Vice President of Engineering of REX from 2009 through 2012. Mr. Doherty has over 35 years experience working with both major and independent oil and gas companies, including reservoir and operations engineering, acquisitions and divestments, corporate planning, management and executive leadership positions. He has worked across most of the major North American hydrocarbon basins, including Mid-Continent, Rockies, Gulf Coast, California, Michigan, Appalachia, South Texas, Louisiana and Western Canada, with extensive experience in secondary and tertiary recovery projects, as well as in unconventional oil and gas plays in shales, tight sands and coalbed methane formations. As Executive Vice President of Engineering of Riley Permian Mr. Doherty oversees all aspects of engineering in drilling, completions, operations, reservoir analysis and optimization, as well as reserve reporting and reserve analysis. He is also heavily involved in prospect generation, reviews, acquisitions and economic analysis of new investments. Prior to joining REX, from 2007 to 2009, Mr. Doherty served as Chief Operating Officer and then Chief Executive Officer of Windsor Exploration Group, a private equity-backed oil and gas company. From 2004 to 2007, he was Manager Unconventional Resources for Southwestern Energy Company. Prior to that he held various engineering and management positions at Devon Energy Corp from 1996 to 2004 and was Manager New Ventures—U.S. Onshore for Kerr-McGee Corporation from 1995 to 1996. Mr. Doherty started his oil and gas career in 1977, working 18 years for Oryx Energy (Sun Oil Co.) in multiple engineering, management & corporate assignments. Mr. Doherty has a B.S. degree in Petroleum Engineering from the University of Oklahoma. He is a Registered Professional Engineer in Texas and a member of the Society of Petroleum Engineers.

Jeffrey M. Gutman served as a Consultant to the Company as our Acting Chief Financial Officer as of January 2018 and later joined the Company as our Executive Vice President, Chief Financial Officer and Treasurer in May 2018. Prior to joining Riley, Mr. Gutman served as a Consultant and Acting Chief Financial Officer for H20 Midstream Partners, Co-Founder, Chief Financial Officer, and Board Member for Sabinal Energy, LLC and Chief Financial Officer for Jefferson Energy Companies from March 2015 through September 2017 collectively. From February 2013 through October 2014, Mr. Gutman served as Senior Vice President and Chief Corporate Development Officer with Chaparral Energy. From March 2008 through September 2012, Mr. Gutman served as Senior Vice President, Chief Financial Officer, and Treasurer for Oxford Resource Partners, and held numerous executive roles during a 17-year career with The Williams Companies from April 1991 through March 2008. Mr. Gutman is an accomplished financial leader with over 25 years of experience in the oil and gas industry, serving in various leadership positions with startups, turnarounds, M&A, debt and equity financing, and capital markets in both public and private company executive roles. Mr. Gutman started his career with Deloitte & Touche in their Tulsa office and is a CPA in the state of Oklahoma. Mr. Gutman holds a BBA with a specialization in Accounting from Oklahoma State University.

Bryan H. Lawrence was appointed as a member of our board of directors in June 2016. Mr. Lawrence is a founder and senior manager of Yorktown Partners LLC, the investment manager of the Yorktown Partners group of investment funds, which make investments in companies engaged in the energy industry and has served in such in positions since 1983. The Yorktown Partners investment funds were formerly affiliated with the investment firm of Dillon, Read & Co. Inc. where Mr. Lawrence had been employed since 1966, serving as a Managing Director until the merger of Dillon Read with SBC Warburg in September 1997. Mr. Lawrence also serves as a director of Carbon Natural Gas Company, Hallador Energy Company, Ramaco Resources and Star Group, L.P. (each a United States publicly traded company) and certain non-public companies in the energy industry in which Yorktown Partners investment funds hold equity interests. Mr. Lawrence is a graduate of Hamilton College and also has an M.B.A. from Columbia University. We believe Mr. Lawrence’s extensive

 

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experience in investing in companies engaged in the energy industry and his service as director of public and private companies in the energy industry qualifies him for service on our board of directors.

Philip Riley was appointed as a member of our board of directors in March 2017. Mr. Philip Riley is a Managing Director of Bluescape Energy Partners and a Director of Parallel Resource Partners, both energy-focused private investment firms. Mr. Philip Riley has 20 years of industry experience, including direct involvement in the energy industry during three separate down cycles. Mr. Philip Riley is responsible for formulating investment strategies and sourcing investment opportunities, where he leads the group’s E&P investment efforts. Additionally, Mr. Philip Riley serves on the board of directors of portfolio companies to oversee strategy, capital allocation and performance management. Prior to his employment with Bluescape Energy Partners, Mr. Philip Riley was employed with Imperial Capital, LLC, Lazard Ltd. and Petrie Parkman & Co. Mr. Philip Riley earned a bachelor’s degree in business administration from The University of Texas at Austin, with majors in the Business Honors Program and Finance. We believe Mr. Philip Riley’s extensive experience advising companies in the energy industry and his experience in the financial industry qualifies him for service on our board of directors.

Antonie VandenBrink was appointed as a member of our board of directors in January 2017. Mr. VandenBrink is a member of the Canadian Petroleum Hall of Fame and has over 50 years of experience in the energy industry. He most recently served as Chairman of Bantrel Group Engineers Ltd. and as a member of the board of Banister Pipelines Ltd. Earlier in his career, he held various leadership and operating roles with Bawden Drilling, Jennings International Drilling, Kenting Drilling, and Trimac Ltd. In addition, Mr. VandenBrink has been an active participant in many charitable organizations, including the advisory board of the Salvation Army. We believe Mr. VandenBrink’s extensive experience in the energy industry, including board and other leadership roles at companies in the energy industry, qualifies him for service on our board of directors. Mr. VandenBrink will resign from his position on our board of directors effective immediately prior to, and contingent upon, the effectiveness of the registration statement of which this prospectus is a part.

Nelson M. Haight has been nominated to serve as a member of our board of directors, effective concurrently with this offering. Mr. Haight is a qualified finance and accounting executive with over 25 years of experience managing and consulting with the finance, planning, treasury and accounting departments of public and private companies. From 2017 to 2018, he served as Chief Executive Officer of Castleton Resources LLC, a privately held exploration and production company. From 2011 to 2017, Mr. Haight served in various capacities including Vice President, Chief Accounting Officer and Controller, Executive Vice President, Chief Financial Officer, and Principal Accounting Officer at Midstates Petroleum Company, Inc., a publicly traded exploration and production company. Prior to that he was engagement partner for the audit of publicly-traded companies with a particular focus on exploration and production and oilfield service clients at GBH CPAs, PC and engagement partner for the audit of publicly-traded companies in the oil and gas, biotechnology, and business services industries at Malone & Bailey, PC. Prior to those positions, Mr. Haight served in a variety of public accounting and finance roles and began his career in 1988 at Arthur Anderson and Co. Mr. Haight received an M.P.A. and B.B.A. from University of Texas, Austin, Texas and is a Certified Public Accountant and member of the American Institute of Certified Public Accountants. We believe Mr. Haight’s extensive experience in the energy industry and his finance and audit experience qualifies him for service on our board of directors.

E. Wayne Nordberg has been nominated to serve as a member of our board of directors, effective concurrently with this offering. Mr. Nordberg has work with Hollow Brook Associates LLC, a private investment management firm serving family offices, foundations, charities and pensions since 1998. From 1998 to 2002, he served as Vice Chairman of the Board of KBW Asset Management, Inc., an affiliate of Keefe, Bruyette, & Woods, Inc., a registered investment advisor offering investment management services to institutions and high net worth individuals. From 1988 to 1998, Mr. Nordberg served in various capacities for Lord, Abbett & Co., a mutual fund company, including partner and director of their family of funds. He is a member of the Financial Analysts Federation and The New York Society of Security Analysts. Mr. Nordberg received a Bachelor of Art in Economics from Lafayette College, Easton, Pennsylvania, where he is a Trustee Emeritus. We believe Mr. Norberg’s extensive experience in investment management qualifies him for service on our board of directors.

 

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There is a family relationship between Mr. Bobby Riley and our Chief Operating Officer, Mr. Kevin Riley, as father and son. Our director, Mr. Philip Riley, is not related to any of our other officers or directors.

Board of Directors

Board Composition

Our board of directors currently consists of four members, including our Chief Executive Officer, who serves as Chairman.

Initially, our board of directors will be divided into three classes of directors, with each class as equal in number as possible, serving staggered three year terms. At each annual meeting of stockholders held after the initial classification, directors will be elected to succeed the class of directors whose terms have expired. This classification of our board of directors could have the effect of increasing the length of time necessary to change the composition of a majority of the board of directors. In general, at least two annual meetings of stockholders will be necessary for stockholders to effect a change in a majority of the members of the board of directors. Messrs.                      will be assigned to Class I, Messrs.                      will be assigned to Class II, and Messrs.                      will be assigned to Class III.

For so long as Yorktown, Boomer and Bluescape collectively beneficially own or control more than 50% of the voting power of our issued and outstanding common stock, such directors will generally be removable at any time, either for or without “cause”, upon the affirmative vote of the holders of a majority of the outstanding shares of our issued and outstanding common stock entitled to vote generally for the election of directors. After Yorktown, Boomer and Bluescape no longer collectively beneficially own or control more than 50% of the voting power of our issued and outstanding common stock, such directors will be removable only for “cause” upon the affirmative vote of the holders of at least 66 2/3% of the outstanding shares of our issued and outstanding common stock entitled to vote generally for the election of directors.

In evaluating director candidates, we will assess whether a candidate possesses the integrity, judgment, knowledge, experience, skills and expertise that are likely to enhance the board of directors’ ability to manage and direct our affairs and business, including, when applicable, to enhance the ability of the committees of the board of directors to fulfill their duties. Each of our directors holds office for the term for which he was elected, and until his successor shall have been elected and qualified or until the earlier of his death, resignation or removal.

Director Independence

We intend to appoint independent directors to our board of directors contemporaneously with and following the completion of this offering to the extent required under the independence standards of the NYSE American.

Committees of the Board of Directors

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

Audit Committee

We will establish an audit committee prior to the completion of this offering. We anticipate that following completion of this offering, our audit committee will consist of Nelson M. Haight, E. Wayne Nordberg, and Philip Riley, each of whom will be independent under the rules of the SEC. As required by the rules of the SEC and listing standards of the NYSE American, the audit committee will consist solely of independent directors. SEC rules also require that a public company disclose whether or not its audit committee has an “audit committee financial expert” as a member. An “audit committee financial expert” is defined as a person who, based on his or

 

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her experience, possesses the attributes outlined in such rules. We anticipate that Nelson M. Haight will satisfy the definition of “audit committee financial expert.”

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

Compensation Committee

We will establish a compensation committee prior to completion of this offering. We anticipate that the compensation committee will consist of at least one director who will be “independent” under the rules of the SEC. This committee will establish salaries, incentives and other forms of compensation for officers and other employees. Our compensation committee will also administer our incentive compensation and benefit plans. We expect to adopt a compensation committee charter defining the committee’s primary duties in a manner consistent with the rules of the SEC and applicable stock exchange or market standards. We anticipate that our compensation committee will initially consist of Nelson M. Haight, E. Wayne Nordberg, and Philip Riley, who are each independent under the rules of the SEC.

Nominating and Corporate Governance Committee

We will establish a nominating and corporate governance committee prior to completion of this offering. We anticipate that the nominating and corporate governance committee will consist of at least one director who will be “independent” under the rules of the SEC. This committee will identify, evaluate and recommend qualified nominees to serve on our board of directors; develop and oversee our internal corporate governance processes; and maintain a management succession plan. We expect to adopt a nominating and corporate governance committee charter defining the committee’s primary duties in a manner consistent with the rules of the SEC and applicable stock exchange or market standards. We anticipate that our nominating and corporate governance committee will initially consist of Bryan Lawrence and E. Wayne Nordberg, who is independent under the rules of the SEC.

Compensation Committee Interlocks and Insider Participation

Except for Bobby Riley, none of our executive officers serve on the board of directors or compensation committee of a company in which has an executive officer that serves on our board or compensation committee. Except for Bobby Riley, no member of our board is an executive officer of a company in which one of our executive officers serves as a member of the board of directors or compensation committee of that company.

Code of Business Conduct and Ethics

Prior to the completion of this offering, our board of directors will adopt a code of business conduct and ethics applicable to our employees, directors and officers, in accordance with applicable U.S. federal securities laws and the corporate governance rules of the NYSE American. We will also adopt a code of ethics for senior financial officers that applies to our chief executive officer, president, chief financial officer, chief accounting officer, controller, treasurer and all persons performing similar functions. The code of business conduct and ethics and the code of ethics for senior financial officers will be publicly available on our website. Any substantive amendments or waivers of the code of business conduct and ethics or code of ethics for senior financial officers may be made only by our board of directors and will be promptly disclosed as required by applicable U.S. federal securities laws and the corporate governance rules of the NYSE American.

Corporate Governance Guidelines

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

 

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EXECUTIVE COMPENSATION

The following compensation discussion and analysis contains statements regarding our future performance goals and measures. These goals and measures are disclosed in the limited context of our executive compensation program and are not statements of management’s expectations or estimates of results or other guidance. We specifically caution investors not to apply these statements to other contexts.

Overview and Objectives

We believe our success depends on the continued contributions of our named executive officers. As a private company, we established our executive compensation program to attract, motivate, and retain our key employees in order to enable us to maximize our profitability and value over the long term. Our policies are also intended to support the achievement of our strategic objectives by aligning the interests of our executive officers with those of our shareholders through operational and financial performance goals and equity-based compensation. Following this offering, we expect that the compensation committee of our board of directors may recommend changes to our executive compensation program. Nonetheless, we expect that our compensation program will continue to be focused on building long-term shareholder value by attracting, motivating and retaining talented, experienced executives and other key employees.

Named Executive Officers

We are currently considered an “emerging growth company,” within the meaning of the Securities Act, for purposes of the SEC’s executive compensation disclosure rules. In accordance with such rules, we are required to provide a Summary Compensation Table and an Outstanding Equity Awards at Fiscal Year End Table, as well as limited narrative disclosures regarding executive compensation for our last completed fiscal year. Further, our reporting obligations extend only to our “named executive officers,” who are the individuals who served as our principal executive officer, our next two other most highly compensated officers at the end of the last completed fiscal year and up to two additional individuals who would have been considered one of our next two most highly compensated officers except that such individuals did not serve as executive officers at the end of the last completed fiscal year. Accordingly, our named executive officers are:

 

Name

  

Principal Position

Bobby D. Riley

   Chairman of the Board, President, and CEO

Kevin Riley

   Executive Vice President and Chief Operating Officer

Jeffrey M. Gutman

   Executive Vice President, Chief Financial Officer and Treasurer

James J. Doherty, Jr.

   Executive Vice President of Engineering

 

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Summary Compensation Table

The following table summarizes the total compensation awarded to, earned by or paid to our named (current and former) executive officers, Bobby D. Riley, Kevin M. Riley, David LaLonde, Jeffrey M. Gutman, and James J. Doherty, Jr., for services performed in the years ended September 30, 2016 and 2017. The information set forth in this section is presented pursuant to the reduced disclosure rules applicable to emerging growth companies. Please see “Prospectus Summary—Emerging Growth Company Status.”

 

    Year      Salary ($)      Bonus
($) (1)
     Restricted
Stock
Awards
($)
     All Other
Compensation
($) (2)(3)
     Total ($)  

Bobby D. Riley

    2017      $ 392,275      $ 70,000         $ 52,197      $ 514,473  

    Chairman of the Board, President & CEO

    2016      $ 332,852      $ 375,000         $ 19,509      $ 727,361  

Kevin M. Riley

    2017      $ 333,333      $ 64,000         $ 14,640      $ 411,973  

    EVP and Chief Operating Officer

    2016      $ 304,999      $ 1,000         $ 17,848      $ 323,848  

David LaLonde

    2017      $ 319,999      $ 129,000         $ 14,052      $ 463,052  

    Former Chief Financial Officer (4)

    2016      $ 180,717      $ —           $ 6,455      $ 187,173  

Jeffrey M. Gutman

    2017      $ —        $ —           $ —        $ —    

    EVP, Chief Financial Officer and Treasurer (5)

    2016      $ —        $ —           $ —        $ —    

James J. Doherty, Jr.

    2017      $ 291,666      $ 56,000         $ 12,197      $ 359,863  

    EVP Reservoir Engineering

    2016      $ 280,000      $ 1,000         $ 14,200      $ 295,200  

 

(1)

Amounts shown represent the target annual bonuses for the applicable year. For a description of annual bonuses for 2018 see the “—Additional Narrative Disclosures—Cash Bonuses” section below.

(2)

Of the other compensation reported for Bobby D. Riley, $37,500 represents a fee paid to him as a director of REG.

(3)

Amounts in this column reflect (a) matching contributions to the 401(k) Plan (as defined below) made on behalf of our named executive officers and (b) health and welfare premiums paid for the benefit of our named executives. See “—Additional Narrative Disclosures—Pension Benefits” below for more information on matching contributions to the 401(k) Plan.

(4)

Mr. LaLonde resigned on November 6, 2017.

(5)

Mr. Gutman served as our Acting Chief Financial Officer since January 2018 and joined the Company as Executive Vice President, Chief Financial Officer and Treasurer as of May 2018.

Additional Narrative Disclosures

Elements of Compensation

Historically, we have compensated our named executive officers with annual base salaries, annual cash incentive bonuses and employee benefits. Additionally, in connection with this offering, we anticipate that our named executive officers will be awarded long-term equity incentives in the form of restricted stock awards and stock options. Following the consummation of this offering, we expect that these elements will continue to constitute the primary elements of our compensation program, although the relative proportions of each element, and the specific plan and award designs, will likely evolve as we become a more established public company.

Base Salary

Base salary is the fixed annual compensation we pay to each of our named executive officers for carrying out their specific job responsibilities. Base salaries are a major component of the total annual cash compensation paid to our named executive officers. Base salaries are determined after taking into account many factors,

 

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including (a) the responsibilities of the officer, the level of experience and expertise required for the position and the strategic impact of the position; (b) the need to recognize each officer’s unique value and demonstrated individual contribution, as well as future contributions; (c) the performance of the company and each officer; and (d) salaries paid for comparable positions in similarly-situated companies.

For the amounts of base salary that our named executive officers received in 2016 and 2017, see “Executive Compensation—Summary Compensation Table.”

Our board of directors reviews the base salaries for each named executive officer periodically as well as at the time of any promotion or significant change in job responsibilities and, in connection with each review, our board of directors considers individual and company performance over the course of the relevant time period. The board of directors has historically made adjustments to base salaries for named executive officers upon consideration of any factors that it deems relevant, including but not limited to: (a) any increase or decrease in the named executive officer’s responsibilities, (b) the named executive officer’s job performance, and (c) the level of compensation paid to senior executives of other companies with whom we compete for executive talent, as estimated based on publicly available information and the experience of members of our board of directors.

Cash Bonuses

We do not maintain a formal bonus program for our named executive officers. Going forward, our board of directors (or a committee thereof) will determine each named executive officer’s eligibility for an annual cash bonus (whether discretionary or pursuant to a bonus plan we later implement), and the amount of such bonus (if any).

Other Benefits

We offer participation in broad-based retirement, health and welfare plans to all of our employees.

Employment, Severance or Change in Control Agreements

We intend to enter into employment agreements with each of our named executive officers, under the terms of which each will serve in their respective officer positions. The following description of the employment agreements is based on the form we anticipate adopting, but the form has not yet been adopted and the provisions discussed below remain subject to change. As a result, the following description is qualified in its entirety by reference to the final form of the employment agreements once adopted.

The initial terms of the employment agreements will be three years, each with automatic annual renewals thereafter. Each of these employment agreements will set forth the initial terms and conditions of employment of each named executive officer, including base salary, target annual bonus opportunity, standard employee benefit plan participation, severance and change in control benefits. Each employment agreement will also include certain restrictive covenants that generally prohibit our named executive officers from (i) competing against us, (ii) disclosing information that is confidential to us and our subsidiaries and (iii) from soliciting or hiring our employees and those of our subsidiaries or soliciting our customers.

IPO Bonuses

We intend to grant our named executive officers and certain of our employees cash bonuses in connection with a successful completion of this offering. Such bonuses will consist of a one-time lump sum cash bonus in an aggregate amount of $2.1 million dollars.

 

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Impact of Financial Reporting and Tax Accounting Rules

Historically, we have recognized compensation cost relating to share-based payments measured based on the fair value of our common stock as determined by the company in good faith. Going forward, we will recognize compensation costs relating to any share-based payments, which will be measured based on the fair value of the equity issued. We anticipate that recognition of this compensation cost will result from equity grants under our long term incentive plans and that the fair market value of these awards will be based in part on the closing price of our common stock as reported by the NYSE American.

Section 162(m) of the Code limits the deductibility of certain compensation expenses in excess of $1,000,000 to any one individual in any fiscal year. Following the initial public offering of our common stock, we will rely on a transition exemption from Section 162(m) for our Long Term Incentive Plan that applies to compensation plans adopted prior to an initial public offering. The transition exemption for the plan will terminate at the time of our annual meeting that occurs after the third calendar year following the year of our initial public offering or, if earlier, at the time we materially modify the plan or all the shares available under the plan are issued.

Outstanding Equity Awards at June 30, 2018

None of our named executive officers held outstanding equity-based awards as of June 30, 2018.

Upon a successful completion of this offering, or January 2, 2019, whichever occurs first, we will issue a bonus to our named executives (excluding Mr. Gutman), consisting of, at the Board’s discretion, either cash or                  vested shares of common stock, which represents approximately $4.0 million (assuming the value of each share is equal to $         (which represents the midpoint of the price range set forth on the cover of this prospectus with respect to a share of our common stock)). The bonus was fully earned on June 26, 2018. The bonus has been accrued as of June 30, 2018.

Additionally, upon successful completion of the offering, we intend to grant equity-based awards pursuant to our LTIP consisting of                unvested shares of common stock that will be subject to a three-year graded vesting schedule, which in the aggregate represents approximately $        million (assuming the value of each share is equal to $        (which represents the midpoint of the price range set forth on the cover of this prospectus with respect to a share of our common stock)). However, our LTIP has not yet been adopted and such awards have not yet been granted. As a result, the foregoing remains subject to change and is qualified in its entirety by reference to the final awards once granted.

Pension Benefits

We have not maintained and do not currently maintain a defined benefit pension plan or a supplemental executive retirement plan. Instead, our employees, including our named executive officers, may participate in a retirement plan intended to provide benefits under section 401(k) of the Code (the “401(k) Plan”) pursuant to which employees are allowed to contribute a portion of their base compensation to a tax-qualified retirement account. We provide matching contributions equal to 100% of the first 5% of employees’ eligible compensation contributed to the 401(k) Plan.

Non-Qualified Defined Contribution and Other Non-Qualified Deferred Compensation Plans

We have not had and do not currently have any defined contribution or other plan that provides for the deferral of compensation on a basis that is not tax-qualified.

 

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2018 Long Term Incentive Plan

In connection with this offering, we intend to adopt an omnibus equity incentive plan, the Riley Exploration Permian, Inc. 2018 Long Term Incentive Plan, or the LTIP, for the employees, consultants and the directors of the Company and its affiliates who perform services for us. The following description of the LTIP is based on the form we anticipate adopting, but the LTIP has not yet been adopted and the provisions discussed below remain subject to change. As a result, the following description is qualified in its entirety by reference to the final form of the LTIP once adopted.

The LTIP will provide for potential grants of: (i) incentive stock options qualified as such under U.S. federal income tax laws, or Incentive Options; (ii) stock options that do not qualify as incentive stock options, or Non-statutory Options, and together with Incentive Options, Options); (iii) stock appreciation rights, or SARs; (iv) restricted stock awards, or Restricted Stock Awards; (v) restricted stock units, or Restricted Stock Units or simply RSUs; (vi) stock awards; (vii) performance awards, or Performance Awards; (viii) dividend equivalents; (ix) other stock-based awards; (x) cash awards; and (xi) substitute awards, all of which (i) through (xi) are referred to collectively herein as the Awards.

Eligibility

Our employees, consultants, and non-employee directors, and employees, consultants, and non-employee directors of our affiliates, will be eligible to receive the Awards under the LTIP.

Administration

Our board of directors, or a committee thereof (as applicable, referred to as the Administrator), will administer the LTIP pursuant to its terms and all applicable state, federal or other rules or laws. The Administrator will have the power to determine to whom and when awards will be granted, determine the amount of awards (measured in cash or in shares of our common stock), proscribe and interpret the terms and provisions of each award agreement (the terms of which may vary), accelerate the vesting or exercisability of an award, delegate duties under the LTIP, and execute all other responsibilities permitted or required under the LTIP.

Securities to be Offered

Subject to adjustment in the event of any distribution, recapitalization, split, merger, consolidation or similar corporate event,                shares of our common stock will be available for delivery pursuant to awards under the LTIP. If an award under the LTIP is forfeited, settled for cash or expires without the actual delivery of shares, any shares subject to such award will again be available for new awards under the LTIP.

Types of Awards

Options — We may grant options to eligible persons including: (i) incentive options (only to our employees or those of our subsidiaries) which comply with section 422 of the Code; and (ii) nonstatutory options. The exercise price of each option granted under the LTIP will be stated in the option agreement and may vary; however, the exercise price for an option must not be less than the fair market value per share of common stock as of the date of grant (or 110% of the fair market value for certain incentive options), nor may the option be re-priced without the prior approval of our shareholders. Options may be exercised as the Administrator determines, but not later than ten years from the date of grant. The Administrator will determine the methods and form of payment for the exercise price of an option (including, in the discretion of the Administrator, payment in common stock, other awards or other property) and the methods and forms in which common stock will be delivered to a participant.

 

 

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SARs — A SAR is the right to receive a share of common stock, or an amount equal to the excess of the fair market value of one share of the common stock on the date of exercise over the grant price of the SAR, as determined by the Administrator. The exercise price of a share of common stock subject to the SAR shall be determined by the Administrator, but in no event shall that exercise price be less than the fair market value of the common stock on the date of grant. The Administrator will have the discretion to determine other terms and conditions of a SAR award.

Restricted Stock Awards — A restricted stock award is a grant of shares of common stock subject to a risk of forfeiture, performance conditions, restrictions on transferability and any other restrictions imposed by the Administrator in its discretion. Restrictions may lapse at such times and under such circumstances as determined by the Administrator. Except as otherwise provided under the terms of the LTIP or an award agreement, the holder of a restricted stock award will have rights as a shareholder, including the right to vote the common stock subject to the restricted stock award or to receive dividends on the common stock subject to the restricted stock award during the restriction period. The Administrator shall provide, in the restricted stock award agreement, whether the restricted stock will be forfeited upon certain terminations of employment. Unless otherwise determined by the Administrator, common stock distributed in connection with a stock split or stock dividend, and other property distributed as a dividend, will be subject to restrictions and a risk of forfeiture to the same extent as the restricted stock award with respect to which such common stock or other property has been distributed.

Restricted Stock Units — RSUs are rights to receive common stock, cash, or a combination of both at the end of a specified period. The Administrator may subject RSUs to restrictions (which may include a risk of forfeiture) to be specified in the RSU award agreement, and those restrictions may lapse at such times determined by the Administrator. Restricted stock units may be settled by delivery of common stock, cash equal to the fair market value of the specified number of shares of common stock covered by the RSUs, or any combination thereof determined by the Administrator at the date of grant or thereafter. Dividend equivalents on the specified number of shares of common stock covered by RSUs may be paid on a current, deferred or contingent basis, as determined by the Administrator on or following the date of grant.

Stock Awards — The Administrator will be authorized to grant common stock as a bonus stock award. The Administrator will determine any terms and conditions applicable to grants of common stock, including performance criteria, if any, associated with a bonus stock award.

Performance Awards — The vesting, exercise or settlement of awards may be subject to achievement of one or more performance criteria specified by the Administrator.

Dividend Equivalents — Dividend equivalents entitle a participant to receive cash, common stock, other awards or other property equal in value to dividends paid with respect to a specified number of shares of our common stock, or other periodic payments at the discretion of the Administrator. Dividend equivalents may be granted on a free-standing basis or in connection with another award (other than a restricted stock award or a bonus stock award).

Other Stock-Based Awards — Other stock-based awards are awards denominated or payable in, valued in whole or in part by reference to, or otherwise based on or related to, the value of our common stock.

Cash Awards — Cash awards may be granted on a free-standing basis, as an element of or a supplement to, or in lieu of any other award.

Substitute Awards — Awards may be granted in substitution or exchange for any other award granted under the LTIP or under another equity incentive plan or any other right of an eligible person to receive payment from us. Awards may also be granted under the LTIP in substitution for similar awards held for individuals who

 

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become participants as a result of a merger, consolidation or acquisition of another entity by or with the Company or one of our affiliates.

Certain Transactions. If any change is made to our capitalization, such as a stock split, stock combination, stock dividend, exchange of shares or other recapitalization, merger or otherwise, which results in an increase or decrease in the number of outstanding shares of common stock, appropriate adjustments will be made by the Administrator in the shares subject to an award under the LTIP. The Administrator will also have the discretion to make certain adjustments to awards in the event of a change in control, such as accelerating the vesting or exercisability of awards, requiring the surrender of an award, with or without consideration, or making any other adjustment or modification to the award that the Administrator determines is appropriate in light of such transaction.

Plan Amendment and Termination. The Administrator may amend or terminate the LTIP at any time; however, shareholder approval will be required for any amendment to the extent necessary to comply with applicable law or exchange listing standards. The LTIP will remain in effect for a period of ten years (unless earlier terminated by the Administrator).

Awards To Be Granted Following This Offering. Following the closing of this offering, we anticipate that the Administrator will grant additional awards under our LTIP to existing employees, new hires, and consultants during the remainder of fiscal 2018.

Clawback. All awards under the LTIP will be subject to any clawback or recapture policy adopted by the Company, as in effect from time to time.

Director Compensation

No obligations with respect to compensation for directors were accrued or paid during fiscal years 2016 or 2017.

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

Under the director compensation policy we expect to adopt in connection with this offering, we anticipate that each non-employee director will receive an annual cash retainer of $65,000, a cash payment of $1,500 for each board meeting attended and $10,000 for each committee meeting attended, and an annual equity grant of $50,000 that will vest on the one-year anniversary of the grant date. In addition, the chairman of the audit committee will receive an additional cash retainer of $15,000.

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

Indemnification

Our certificate of incorporation and bylaws provide indemnification rights to the fullest extent permitted by Delaware law to the members of our board of directors and permit us to purchase insurance on behalf of any officer, director, employee or other agent for any liability arising out of that person’s actions as our officer, director, employee or agent, regardless of whether Delaware law would permit indemnification. After completion of this offering, we will evaluate our existing director and officer liability insurance coverage and make such

 

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adjustments as we deem appropriate. Additionally, we have entered into separate indemnification agreements with each of our directors and executive officers. These agreements provide that we will indemnify and hold harmless each indemnitee for certain losses and expenses (including attorneys’ fees) to the fullest extent permitted by our certificate, our bylaws, the DGCL and other applicable law. See “Certain Relationships and Related Party Transactions—Limitation of Liability and Indemnification Matters.” We believe that the limitation of liability provision in our certificate of incorporation and the indemnification agreements will facilitate our ability to continue to attract and retain qualified individuals to serve as directors and executive officers.

 

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SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

The following table sets forth the beneficial ownership of our common stock that, upon the consummation of this offering and the transactions related thereto, will be owned by:

 

  1)

each person known to us beneficially own more than 5% of any class of our outstanding common stock;

 

  2)

each member of our board of directors;

 

  3)

each of our named executive officers; and

 

  4)

all of our directors, director nominees and executive officers as a group.

Except as otherwise noted, the person or entities listed below have sole voting and investment power with respect to all shares of our common stock beneficially owned by them, except to the extent this power may be shared with a spouse. All information with respect to beneficial ownership has been furnished by the respective 5% or more shareholders, directors, director nominees or executive officers, as the case may be. Each holder’s percentage ownership before this offering is based on            shares of common stock outstanding as of                    , 2018, after giving effect to the Corporate Conversion. Unless otherwise noted, the mailing address of each listed beneficial owner is c/o Riley Exploration Permian, Inc., 29 E. Reno Avenue, Suite 500, Oklahoma City, Oklahoma 73104.

To the extent that the underwriters sell more than            shares of common stock, the underwriters have the option to purchase up to an additional            shares from us. However, the table below assumes no exercise of such option.

 

     Shares Beneficially
Owned Before this
Offering
     Shares Beneficially
Owned After this
Offering (Assuming No
Exercises of
Underwriters’ Over-
Allotment Option)
     Shares Beneficially
Owned After this
Offering (Assuming the
Underwriters’ Over-
Allotment Option is
Exercised in Full)
 

Name of Beneficial Owner (1)

   Number      Percentage      Number      Percentage      Number      Percentage  

5% Stockholders:

                 

Riley Exploration Group, Inc. (2)

                 

Yorktown Energy Partners XI, L.P. (3)

                 

Boomer Petroleum, LLC (4)

                 

Bluescape Riley Exploration Acquisition, LLC (5)

                 

Bluescape Riley Exploration Holdings LLC (5)

                 

Directors and Named Executive Officers

                 

Bobby D. Riley (6)(7)

                 

Kevin M. Riley (6)(7)

                 

Jeffrey M. Gutman (6)

                 

James J. Doherty, Jr. (6)(7)

                 

Bryan H. Lawrence (3)

                 

Antonie VandenBrink (4)

                 

Philip Riley (5)

                 

E. Wayne Nordberg (6)

                 

Nelson M. Haight (6)

                 
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Directors and Named Executive Officers as a Group (         Total )

                 
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

 

(1)

The amounts and percentages of common stock beneficially owned are reported on the bases of regulations of the SEC governing the determination of beneficial ownership of securities. Under the rules of the SEC, a

 

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  person is deemed to be a “beneficial owner” of a security if that person has or shares voting power, which includes the power to vote or direct the voting of such security, or investment power, which includes the power to dispose of or to direct the disposition of such security. Securities that can be so acquired are deemed to be outstanding for purposes of computing such person’s ownership percentage, but not for purposes of computing any other person’s percentage. Under these rules, more than one person may be deemed beneficial owner of the same securities, and a person may be deemed to be a beneficial owner of securities as to which such person has no economic interest. Except as otherwise indicated in these footnotes, each of the beneficial owners has, to our knowledge, sole voting and investment power with respect to the indicated shares of common stock, except to the extent this power may be shared with a spouse.
(2)

Certain investment funds managed by Yorktown Partners own an aggregate of approximately     % of REG. The address of REG is 2008 North Council Avenue, Blanchard, OK 73010.

(3)

Yorktown XI Company LP is the sole general partner of Yorktown Energy Partners XI, L.P. Yorktown XI Associates LLC is the sole general partner of Yorktown XI Company LP. The managers of Yorktown XI Associates LLC, who act by majority approval, are Bryan H. Lawrence, W. Howard Keenan, Jr., Peter A. Leidel, Tomás R. LaCosta, Robert A. Signorino, Bryan R. Lawrence and James C. Crain. As a result, Yorktown XI Associates LLC may be deemed to share the power to vote or direct the vote or to dispose or direct the disposition of the common stock owned by Yorktown Energy Partners XI, L.P. Yorktown XI Company LP and Yorktown XI Associates LLC disclaim beneficial ownership of the common stock held by Yorktown Energy Partners XI, L.P. in excess of their pecuniary interest therein. The managers of Yorktown XI Associates LLC disclaim beneficial ownership of the common stock held by Yorktown Energy Partners XI, L.P. The address of such funds is 410 Park Avenue, 19th Floor, New York, New York 10022.

(4)

Boomer Petroleum, LLC is a Delaware limited liability company that is owned 50% by Texel Resources Inc., a Canadian corporation, and 50% by Balmon California, Inc., a California corporation. The President of Boomer Petroleum, LLC is Alvin Libin and Antonie VandenBrink is the Vice President. The address of Boomer Petroleum, LLC is 3200 255 5th Avenue SW, Calgary, Alberta, Canada T2P 3G6.

(5)

Bluescape Riley Exploration Acquisition LLC is a Delaware limited liability company and beneficially owns our common stock. Bluescape Riley Exploration Holdings LLC is a Delaware limited liability company and beneficially owns our common stock, and prior to the conversion of our Series A Preferred Units into common shares immediately prior to this offering was a beneficial owner of shares of our Series A Preferred Units in Riley Exploration—Permian, LLC. Bluescape Riley Exploration Acquisition LLC is a wholly owned subsidiary of Bluescape Riley Exploration Holdings LLC. Bluescape Energy Recapitalization and Restructuring Fund III LP has voting and dispositive power over our shares held by Bluescape Riley Exploration Acquisition LLC and Bluescape Riley Exploration Holdings LLC and therefore may also be deemed to be the beneficial owner of these shares. Bluescape Energy Partners III GP LLC may be deemed to share voting and dispositive power over these shares and therefore may also be deemed to be the beneficial owner of these shares by virtue of Bluescape Energy Partners III GP LLC being the sole general partner of Bluescape Energy Recapitalization and Restructuring Fund III LP. Bluescape Resources GP Holdings LLC may be deemed to share voting and dispositive power over these shares and therefore may also be deemed to be the beneficial owner of these shares by virtue of Bluescape Resources GP Holdings LLC being the manager of Bluescape Energy Partners III GP LLC. Charles John Wilder, Jr. may be deemed to share voting and dispositive power over these shares and therefore may also be deemed to be the beneficial owner of these shares by virtue of Charles John Wilder, Jr. being the manager of Bluescape Resources GP Holdings LLC. Each of Bluescape Riley Exploration Acquisition LLC, Bluescape Riley Exploration Holdings LLC, Bluescape Energy Recapitalization and Restructuring Fund III LP, Bluescape Energy Partners III GP LLC, Bluescape Resources GP Holdings LLC, and Charles John Wilder, Jr. disclaims beneficial ownership of the shares reported as held by Bluescape Riley Exploration Holdings LLC in excess of its respective pecuniary interest in such shares. The address of Bluescape Riley Exploration Acquisition LLC and Bluescape Riley Exploration Holdings LLC and mailing address of each listed beneficial owner is 200 Crescent Court, Suite 1900, Dallas, Texas 75201.

 

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(6)

Does not include                shares of restricted stock granted to such person in connection with the consummation of this offering under the LTIP. See “Executive Compensation—Additional Narrative Disclosures.”

(7)

Does not include                shares of stock granted to such person in connection with the consummation of this offering. See “Executive Compensation—Additional Narrative Disclosures.”

 

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CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

Review, Approval or Ratification of Transactions with Related Persons

A “Related Party Transaction” is a transaction, arrangement or relationship in which we or any of our future subsidiaries was, is or will be a participant, the amount of which involved exceeds $120,000, and in which any Related Person had, has or will have a direct or indirect material interest. A “Related Person” means:

 

  1)

any person who is, or at any time during the applicable period was, one of our executive officers or one of our directors;

 

  2)

any person who is known by us to be the beneficial owner of more than 5% of our common stock;

 

  3)

any immediate family member of any of the foregoing persons, which means any child, stepchild, parent, stepparent, spouse, sibling, mother-in-law, father-in-law, son-in- law, daughter-in-law, brother-in-law or sister-in-law of a director, executive officer or a beneficial owner of more than 5% of our common stock, and any person (other than a tenant or employee) sharing the household of such director, executive officer or beneficial owner of more than 5% of our common stock; and

 

  4)

any firm, corporation or other entity in which any of the foregoing persons is a partner or principal or in a similar position or in which such person has a 10% or greater beneficial ownership interest.

Our board of directors will adopt a written related party transactions policy prior to the completion of this offering. Pursuant to this policy, we expect that our audit committee will review all material facts of all Related Party Transactions.

Historical Transactions with Affiliates

Contribution Transactions—Our Company History

We were formed on June 13, 2016 by REG, as its wholly-owned subsidiary, and our affiliate operated the acreage comprising the Champions Assets. In a series of contribution transactions, we acquired the Champions Assets, in exchange for our common units, from owners of the Champions Assets including REG as well as other owners. Upon issuance of our common units in exchange for those assets, those owners became members, and currently are, our shareholders. Our wholly-owned subsidiary also acquired the operations of the Champions Assets. See “Prospectus Summary—Our Corporate History” for more information.

In connection with the acquisition of the Champions Assets, REG entered into a joint operating agreement, for the operation of the Champions Assets, by an affiliate of REG. Pursuant to the joint operating agreement, this affiliate served as the operator of record of the Champions Assets until operatorship was transferred to our wholly-owned subsidiary, RPOC, effective as of June 1, 2017. 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.

Our board of directors has been composed of representatives from REG, Yorktown, Boomer and Bluescape. See “Prospectus Summary—Our Corporate History” for more information on the contribution.

Corporate Conversion

In connection with our Corporate Conversion from a limited liability company to a corporation immediately prior to the offering contemplated by this prospectus, we engaged in certain share transactions with our shareholders. See “Corporate Conversion.”

 

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Other Affiliate Matters

Mr. Bobby Riley is the chairman of our board of directors, President and Chief Executive Officer. Mr. Riley also serves as Chief Executive Officer and a member of the board of directors of our shareholder REG. Given Mr. Riley’s roles with both the Company and REG, a conflict of interest could arise which could adversely affect the interests of our stockholders, including conflicts involving payment or performance under prior agreements with REG or agreements we may enter into in the future with REG or its subsidiaries or affiliates. Please see “Management” for more information.

From October 10, 2016 through June 2017, we reimbursed REG for certain personnel and general and administrative expenses at cost. The expenses included payroll, general and administrative, software licensing fees and accounting and bookkeeping services. In addition, we reimbursed REG for an overhead allocated including office space and utilities. As of the year ended September 30, 2017, the aggregate amount of such actual costs reimbursed by us to REG was approximately, $1.6 million. In June 2017, we terminated the expense reimbursement arrangement with REG and have thereafter operated independently.

There is a family relationship between Mr. Bobby Riley and our Chief Operating Officer, Mr. Kevin Riley, as father and son. Our director, Mr. Philip Riley, is not related to any of our other officers or directors.

IPO Bonuses

We intend to grant certain of our named executive officers and certain of our employees cash bonuses and equity-based awards upon successful completion of this offering. See “Executive Compensation—Additional Narrative Disclosures—IPO Bonuses” for more information.

Agreements Entered Into in Connection with this Offering

Registration Rights Agreement

In connection with the closing of this offering, we intend to enter into a second amended and restated registration rights agreement (the “Registration Rights Agreement”) with Yorktown, Boomer and Bluescape. The Registration Rights Agreement will provide for customary rights for these shareholders to demand that we file a resale shelf registration statement and certain piggyback rights in connection with the registration of securities. In addition, the agreement will grant these shareholders customary rights to participate in certain underwritten offerings of our common stock that we may conduct.

Shelf Registration Rights

Subject to certain limitations described below, we have agreed no later than the expiration of the lock-up period to prepare and file a registration statement registering the offer and sale of their shares of our common stock. Subject to certain limitations in the Registration Rights Agreement, parties to the agreement holding more than 15% of the then-currently registrable securities under the agreement can require the Company to participate in a firm underwritten resale of the securities; provided that we will not be obligated to participate in more than two such underwritten resales per year.

Piggyback Rights

Subject to certain exceptions, if at any time we propose to register an offering of equity securities or conduct an underwritten offering, whether or not for our own account, then we must notify the equity holders party to the Registration Rights Agreement of such proposal to allow them to include a specified number of their shares of our common stock in that registration statement or underwritten offering, as applicable.

 

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Conditions and Limitations; Expenses

These registration rights will be subject to certain conditions and limitations, including the right of the underwriters to limit the number of shares to be included in a registration and our right to suspend use of a prospectus under a registration statement under certain circumstances, including if the Company is pursuing a bona fide material acquisition, merger, reorganization, disposition or other similar transaction and the Board determines in good faith that the Company’s ability to pursue or consummate such a transaction would be materially and adversely affected by any required disclosure of such transaction in the registration statement (and such disclosure is then-required therein by applicable law, rule or regulation to permit offers and sales thereunder), the Company has experienced some other material non-public event the disclosure of which in the registration statement at such time, in the good faith judgment of the Board, would materially and adversely affect the Company (and such disclosure therein is then-required by applicable law, rule or regulation to permit offers and sales thereunder), or the Board shall have determined in good faith, upon the advice of counsel, that it is required by law, rule or regulation to file a post-effective amendment to such registration statement to reflect certain updated information of the type described in the Registration Rights Agreement. The Registration Rights Agreement provides certain time limitations on how long such delays may be implemented. We will generally pay all registration expenses in connection with our obligations under the Registration Rights Agreement, regardless of whether a registration statement is filed or becomes effective.

Limitation of Liability and Indemnification Matters

Our certificate of incorporation limits the liability of our directors for monetary damages for breach of their fiduciary duty as directors, except for liability that cannot be eliminated under the DGCL. Delaware law provides that directors of a company will not be personally liable for monetary damages for breach of their fiduciary duty as directors, except for liabilities:

 

   

for any breach of their duty of loyalty to us or our stockholders;

 

   

for acts or omissions not in good faith or which involve intentional misconduct or a knowing violation of law;

 

   

for unlawful payment of dividend or unlawful stock repurchase or redemption, as provided under Section 174 of the DGCL; or

 

   

for any transaction from which the director derived an improper personal benefit.

Any amendment, repeal or modification of these provisions will be prospective only and would not affect any limitation on liability of a director for acts or omissions that occurred prior to any such amendment, repeal or modification.

Our bylaws also provide that we will indemnify our directors and officers to the fullest extent permitted by Delaware law. Our bylaws also permit us to purchase insurance on behalf of any officer, director, employee or other agent for any liability arising out of that person’s actions as our officer, director, employee or agent, regardless of whether Delaware law would permit indemnification. We intend to enter into indemnification agreements with each of our current and future directors and executive officers. These agreements will require us to indemnify these individuals to the fullest extent permitted under Delaware law against liability that may arise by reason of their service to us, and to advance expenses incurred as a result of any proceeding against them as to which they could be indemnified. We believe that the limitation of liability provision that will be in our certificate of incorporation and the indemnification agreements will facilitate our ability to continue to attract and retain qualified individuals to serve as directors and officers.

 

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DESCRIPTION OF CAPITAL STOCK

The following description is intended as a summary of our certificate of incorporation and our bylaws, each of which will become effective prior to the effectiveness of the registration statement of which this prospectus forms a part and which will be filed as exhibits to the registration statement of which this prospectus forms a part, and to the applicable provisions of the Delaware General Corporation Law. The description of our common stock and preferred stock reflects the completion of the Corporate Conversion.

Upon completion of this offering the authorized capital stock of Riley Exploration Permian, Inc. will consist of            shares of common stock, $0.01 par value per share, of which            shares will be issued and outstanding assuming the underwriters do not exercise their option to purchase additional shares of our common stock, and no shares of preferred stock outstanding.

The following summary of the capital stock and certificate of incorporation and bylaws of Riley Exploration Permian, Inc. does not purport to be complete and is qualified in its entirety by reference to the provisions of applicable law and to our certificate of incorporation and bylaws, which are filed as exhibits to the registration statement of which this prospectus is a part.

Common Stock

Except as provided by law or in a preferred stock designation, holders of common stock are entitled to one vote for each share held of record on all matters submitted to a vote of the stockholders, will have the exclusive right to vote for the election of directors and do not have cumulative voting rights. Except as otherwise required by law, holders of common stock are not entitled to vote on any amendment to the certificate of incorporation (including any certificate of designations relating to any series of preferred stock) that relates solely to the terms of any outstanding series of preferred stock if the holders of such affected series are entitled, either separately or together with the holders of one or more other such series, to vote thereon pursuant to our certificate of incorporation (including any certificate of designations relating to any series of preferred stock) or pursuant to the DGCL. Subject to prior rights and preferences that may be applicable to any outstanding shares or series of preferred stock, holders of common stock are entitled to receive ratably in proportion to the shares of common stock held by them such dividends (payable in cash, stock or otherwise), if any, as may be declared from time to time by our board of directors out of funds legally available for dividend payments. All outstanding shares of common stock are fully paid and non-assessable, and the shares of common stock to be issued upon completion of this offering will be fully paid and non-assessable.

The holders of common stock have no preferences or rights of conversion, exchange, pre-emption or other subscription rights. There are no redemption or sinking fund provisions applicable to common stock. In the event of any voluntary or involuntary liquidation, dissolution or winding-up of our affairs, holders of common stock will be entitled to share ratably in our assets in proportion to the shares of common stock held by them that are remaining after payment or provision for payment of all of our debts and obligations and after distribution in full of preferential amounts to be distributed to holders of outstanding shares of preferred stock, if any.

We do not anticipate declaring or paying any cash dividends to holders of our common stock in the foreseeable future. See “Dividend Policy.”

Preferred Stock

Our certificate of incorporation will authorize our board of directors, subject to any limitations prescribed by law, without further stockholder approval, to establish and to issue from time to time one or more classes or series of preferred stock, covering up to an aggregate of            shares of preferred stock. Each class or series of preferred stock will cover the number of shares and will have the powers, preferences, rights, qualifications, limitations and restrictions determined by the board of directors, which may include, among others, dividend

 

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rights, liquidation preferences, voting rights, conversion rights, preemptive rights and redemption rights. Except as provided by law or in a preferred stock designation, the holders of preferred stock will not be entitled to vote at or receive notice of any meeting of stockholders.

Anti-Takeover Effects of Provisions of Our Certificate of Incorporation, Our Bylaws and Delaware Law

Some provisions of Delaware law contain, and our certificate of incorporation and our bylaws will contain, provisions that could make the following transactions more difficult: acquisitions of us by means of a tender offer, a proxy contest or otherwise or removal of our incumbent officers and directors. These provisions may also have the effect of preventing changes in our management. It is possible that these provisions could make it more difficult to accomplish or could deter transactions that stockholders may otherwise consider to be in their best interest or in our best interests, including transactions that might result in a premium over the market price for our shares.

These provisions are expected to discourage coercive takeover practices and inadequate takeover bids. These provisions are also designed to encourage persons seeking to acquire control of us to first negotiate with us. We believe that the benefits of increased protection and our potential ability to negotiate with the proponent of an unfriendly or unsolicited proposal to acquire or restructure us outweigh the disadvantages of discouraging these proposals because, among other things, negotiation of these proposals could result in an improvement of their terms.

Delaware Law

Section 203 of the DGCL prohibits a Delaware corporation, including those whose securities are listed for trading on the NYSE American, from engaging in any business combination with any interested stockholder for a period of three years following the date that the stockholder became an interested stockholder, unless:

 

   

the transaction is approved by the board of directors before the date the interested stockholder attained that status;

 

   

upon consummation of the transaction that resulted in the stockholder becoming an interested stockholder, the interested stockholder owned at least 85% of the voting stock of the corporation outstanding at the time the transaction commenced; or

 

   

on or after such time the business combination is approved by the board of directors and authorized at a meeting of stockholders by at least two-thirds of the outstanding voting stock that is not owned by the interested stockholder.

We have elected to not be subject to the provisions of Section 203 of the DGCL in our certificate of incorporation for so long as Yorktown, Boomer, Bluescape and their respective affiliates own in the aggregate more than 15% of our outstanding common stock.

Our Certificate of Incorporation and Our Bylaws

Provisions of our certificate of incorporation and our bylaws, which will become effective upon the closing of this offering, may delay or discourage transactions involving an actual or potential change in control or change in our management, including transactions in which stockholders might otherwise receive a premium for their shares, or transactions that our stockholders might otherwise deem to be in their best interests. Therefore, these provisions could adversely affect the price of our common stock.

Among other things, upon the completion of this offering, our certificate of incorporation and bylaws will:

 

   

establish advance notice procedures with regard to stockholder proposals relating to the nomination of candidates for election as directors or new business to be brought before meetings of our stockholders.

 

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These procedures provide that notice of stockholder proposals must be timely given in writing to our corporate secretary prior to the meeting at which the action is to be taken. Generally, to be timely, notice must be received at our principal executive offices not less than 90 days nor more than 120 days prior to the first anniversary date of the annual meeting for the preceding year. Our bylaws will specify the requirements as to form and content of all stockholders’ notices. These requirements may preclude stockholders from bringing matters before the stockholders at an annual or special meeting;

 

   

provide our board of directors the ability to authorize undesignated preferred stock. This ability makes it possible for our board of directors to issue, without stockholder approval, preferred stock with voting or other rights or preferences that could impede the success of any attempt to change control of the Company. These and other provisions may have the effect of deferring hostile takeovers or delaying changes in control or management of our company;

 

   

provide that the authorized number of directors may be changed only by resolution of the board of directors;

 

   

provide that, 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, all vacancies, including newly created directorships, may, except as otherwise required by law or, if applicable, the rights of holders of a series of preferred stock, be filled by the affirmative vote of a majority of directors then in office, even if less than a quorum;

 

   

provide for our board of directors to be divided into three classes of directors, with each class as nearly equal in number as possible, serving staggered three year terms, other than directors which may be elected by holders of preferred stock, if any. This system of electing and removing directors may tend to discourage a third party from making a tender offer or otherwise attempting to obtain control of us, because it generally makes it more difficult for stockholders to replace a majority of the directors;

 

   

provide that our bylaws can be amended by the board of directors;

 

   

provide that, at any time after Yorktown, Boomer and Bluescape and their respective affiliates no longer collectively beneficially own more than 50% of the outstanding shares of our common stock, any action required or permitted to be taken by the stockholders must be effected at a duly called annual or special meeting of stockholders and may not be effected by any consent in writing in lieu of a meeting of such stockholders, subject to the rights of the holders of any series of preferred stock with respect to such series (prior to such time, such actions may be taken without a meeting by written consent of holders of common stock having not less than the minimum number of votes that would be necessary to authorize such action at a meeting);

 

   

provide that, at any time after Yorktown, Boomer and Bluescape and their respective affiliates no longer collectively beneficially own more than 50% of the outstanding shares of our common stock, our certificate of incorporation and bylaws may be amended by the affirmative vote of the holders of at least two-thirds of our then outstanding common stock (prior to such time, our certificate of incorporation and bylaws may be amended by the affirmative vote of the holders of a majority of our then outstanding common stock);

 

   

provide that we renounce any interest in existing and future investments in other entities by, or the business opportunities of, Yorktown, Boomer, Bluescape, or any of their officers, directors, agents, stockholders, members, partners, affiliates and subsidiaries (other than our directors that are presented business opportunities in their capacity as our directors) and that they have no obligation to offer us those investments or opportunities;

 

   

provide that, 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, special meetings of our stockholders may only be called by the board of directors, the chief executive officer, the chairman of the board, or the board (prior to such time, a special meeting may also be called at the request of stockholders holding a majority of the outstanding stock entitled to vote); and

 

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provide that, 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, the affirmative vote of the holders of at least two-thirds of the voting power of all then-outstanding common stock entitled to vote generally in the election of directors, voting together as a single class, shall be required to remove any or all of the directors from office and such removal may only be for cause (prior to such time, directors may be removed either with or without cause by the affirmative vote of holders of a majority of our outstanding stock entitled to vote).

Forum Selection

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:

 

   

any derivative action or proceeding brought on our behalf;

 

   

any action asserting a claim of breach of a fiduciary duty owed by any of our directors, officers, employees or agents to us or our stockholders;

 

   

any action asserting a claim against us arising pursuant to any provision of the DGCL, our certificate of incorporation or our bylaws; or

 

   

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.

Our certificate of incorporation will also provide that any person or entity purchasing or otherwise acquiring any interest in shares of our capital stock will be deemed to have notice of, and to have consented to, this forum selection provision. Although we believe these provisions will benefit us by providing increased consistency in the application of Delaware law for the specified types of actions and proceedings, the provisions may have the effect of discouraging lawsuits against our directors, officers, employees and agents. The enforceability of similar exclusive forum provisions in other companies’ certificates of incorporation has been challenged in legal proceedings, and it is possible that, in connection with one or more actions or proceedings described above, a court could rule that this provision in our certificate of incorporation is inapplicable or unenforceable.

Transfer Agent and Registrar

The transfer agent and registrar for our common stock is            .

Listing

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

 

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SHARES ELIGIBLE FOR FUTURE SALE

Prior to this offering, there has been no public market for our common stock. Future sales of our common stock in the public market, or the availability of such shares for sale in the public market, could adversely affect the market price of our common stock prevailing from time to time. As described below, only a limited number of shares of our common stock will be available for sale shortly after this offering due to contractual and legal restrictions on resale. Nevertheless, sales of a substantial number of shares of our common stock in the public market after such restrictions lapse, or the perception that those sales may occur, could adversely affect the prevailing market price of our common stock at such time and our ability to raise equity-related capital at a time and price we deem appropriate.

Sales of Restricted Shares

After giving effect to the Corporate Conversion, upon completion of this offering, we will have outstanding an aggregate of            shares of common stock. Of these shares, all of the            shares of common stock to be sold in this offering (or            shares assuming the underwriters exercise the option to purchase additional shares in full) will be freely tradable without restriction or further registration under the Securities Act, unless the shares are held by any of our “affiliates” as such term is defined in Rule 144 under the Securities Act. All remaining shares of common stock will be deemed “restricted securities” as such term is defined under Rule 144. The restricted securities were, or will be, issued and sold by us in private transactions and are eligible for public sale only if registered under the Securities Act or if they qualify for an exemption from registration under Rule 144 or Rule 701 under the Securities Act, which rules are summarized below.

As a result of the lock-up agreements described below and the provisions of Rule 144 and Rule 701 under the Securities Act, the shares of our common stock (excluding the shares to be sold in this offering) that will be available for sale in the public market are as follows:

 

   

no shares will be eligible for sale on the date of this prospectus or prior to 180 days after the date of this prospectus; and

 

   

shares will be eligible for sale upon the expiration of the lock-up agreements beginning 180 days after the date of this prospectus and when permitted under Rule 144 or Rule 701.

Lock-up Agreements

We and all of our directors and executive officers and our Existing Owners have agreed not to sell any common stock or securities convertible into or exchangeable for shares of common stock for a period of 180 days from the date of this prospectus, subject to certain exceptions. Please see “Underwriting (Conflicts of Interest)” for a description of these lock-up provisions.

Rule 144

In general, under Rule 144 under the Securities Act as currently in effect, a person (or persons whose shares are aggregated) who is not deemed to have been an affiliate of ours at any time during the three months preceding a sale, and who has beneficially owned restricted securities within the meaning of Rule 144 for a least nine months (including any period of consecutive ownership of preceding non-affiliated holders) would be entitled to sell those shares, subject only to the availability of current public information about us. A non-affiliated person who has beneficially owned restricted securities within the meaning of Rule 144 for at least one year would be entitled to sell those shares without regard to the provisions of Rule 144.

A person (or persons whose shares are aggregated) who is deemed to be an affiliate of ours and who has beneficially owned restricted securities within the meaning of Rule 144 for at least six months would be entitled to sell within any three-month period a number of shares that does not exceed the greater of one percent of the

 

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then outstanding shares of our common stock or the average weekly trading volume of our common stock reported through the NYSE American during the four calendar weeks preceding the filing of notice of the sale. Such sales are also subject to certain manner of sale provisions, notice requirements and the availability of current public information about us.

Rule 701

In general, under Rule 701 under the Securities Act, any of our employees, directors, officers, consultants or advisors who purchases shares from us in connection with a compensatory stock or option plan or other written agreement before the effective date of this offering is entitled to sell such shares 90 days after the effective date of this offering in reliance on Rule 144, without having to comply with the holding period requirement of Rule 144 and, in the case of non-affiliates, without having to comply with the public information, volume limitation or notice filing provisions of Rule 144. The SEC has indicated that Rule 701 will apply to typical stock options granted by an issuer before it becomes subject to the reporting requirements of the Exchange Act, along with the shares acquired upon exercise of such options, including exercises after the date of this prospectus.

Stock Issued Under Employee Plans

We intend to file a registration statement on Form S-8 under the Securities Act to register            shares of common stock issuable under our LTIP. This registration statement on Form S-8 is expected to be filed following the effective date of the registration statement of which this prospectus is a part and will be effective upon filing. Accordingly, shares registered under such registration statement will be available for sale in the open market following the effective date, unless such shares are subject to vesting restrictions with us, Rule 144 restrictions applicable to our affiliates or the lock-up restrictions described above. Following the completion of this offering, we expect to grant awards under our LTIP to certain existing employees, new hires and consultants. See “Executive Compensation—2018 Long Term Incentive Plan”

Registration Rights Agreement

In connection with the closing of this offering, we expect to enter into the Registration Rights Agreement with Yorktown, Boomer and Bluescape. The Registration Rights Agreement will provide for customary rights for these shareholders to demand that we file a resale shelf registration statement and certain piggyback rights in connection with the registration of securities. In addition, the agreement will grant these shareholders customary rights to participate in certain underwritten offerings of our common stock that we may conduct.

Shelf Registration Rights

Subject to certain limitations described below, we have agreed no later than the expiration of the lock-up period to prepare and file a registration statement registering the offer and sale of their shares of our common stock. Subject to certain limitations in the Registration Rights Agreement, parties to the agreement holding more than 15% of the then-currently registrable securities under the agreement can require the Company to participate in a firm underwritten resale of the securities; provided that we will not be obligated to participate in more than two such underwritten resales per year.

Piggyback Rights

Subject to certain exceptions, if at any time we propose to register an offering of equity securities or conduct an underwritten offering, whether or not for our own account, then we must notify the equity holders party to the Registration Rights Agreement of such proposal to allow them to include a specified number of their shares of our common stock in that registration statement or underwritten offering, as applicable.

 

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Conditions and Limitations; Expenses

These registration rights will be subject to certain conditions and limitations, including the right of the underwriters to limit the number of shares to be included in a registration and our right to suspend use of a prospectus under a registration statement under certain circumstances, including if the Company is pursuing a bona fide material acquisition, merger, reorganization, disposition or other similar transaction and the Board determines in good faith that the Company’s ability to pursue or consummate such a transaction would be materially and adversely affected by any required disclosure of such transaction in the registration statement (and such disclosure is then-required therein by applicable law, rule or regulation to permit offers and sales thereunder), the Company has experienced some other material non-public event the disclosure of which in the registration statement at such time, in the good faith judgment of the Board, would materially and adversely affect the Company (and such disclosure therein is then-required by applicable law, rule or regulation to permit offers and sales thereunder), or the Board shall have determined in good faith, upon the advice of counsel, that it is required by law, rule or regulation to file a post-effective amendment to such registration statement to reflect certain updated information of the type described in the Registration Rights Agreement. The Registration Rights Agreement provides certain time limitations on how long such delays may be implemented. We will generally pay all registration expenses in connection with our obligations under the Registration Rights Agreement, regardless of whether a registration statement is filed or becomes effective.

 

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

The following is a summary of the material U.S. federal income tax considerations related to the purchase, ownership and disposition of our common stock by a non-U.S. holder (as defined below), that holds our common stock as a “capital asset” (generally property held for investment). This summary is based on the provisions of the Internal Revenue Code of 1986, as amended, or the Code, U.S. Treasury regulations, administrative rulings and judicial decisions, all as in effect on the date hereof, and all of which are subject to change, possibly with retroactive effect. We have not sought any ruling from the Internal Revenue Service, or IRS, with respect to the statements made and the conclusions reached in the following summary, and there can be no assurance that the IRS or a court will agree with such statements and conclusions.

This summary does not address all aspects of U.S. federal income taxation that may be relevant to non-U.S. holders in light of their personal circumstances. In addition, this summary does not address the Medicare tax on certain investment income, U.S. federal estate or gift tax laws, any state, local or non-U.S. tax laws or any tax treaties. This summary also does not address tax considerations applicable to investors that may be subject to special treatment under the U.S. federal income tax laws, such as:

 

   

banks, insurance companies or other financial institutions;

 

   

tax-exempt or governmental organizations;

 

   

qualified foreign pension funds (and entities all of the interests of which are owned by qualified foreign pension funds);

 

   

dealers in securities or foreign currencies;

 

   

traders in securities that use the mark-to-market method of accounting for U.S. federal income tax purposes;

 

   

persons subject to the alternative minimum tax;

 

   

partnerships or other pass-through entities for U.S. federal income tax purposes or holders of interests therein;

 

   

persons deemed to sell our common stock under the constructive sale provisions of the Code;

 

   

persons that acquired our common stock through the exercise of employee stock options or otherwise as compensation or through a tax-qualified retirement plan;

 

   

certain former citizens or long-term residents of the United States; and

 

   

persons that hold our common stock as part of a straddle, appreciated financial position, synthetic security, hedge, conversion transaction or other integrated investment or risk reduction transaction.

PROSPECTIVE INVESTORS ARE ENCOURAGED TO CONSULT THEIR TAX ADVISORS WITH RESPECT TO THE APPLICATION OF THE U.S. FEDERAL INCOME TAX LAWS, INCLUDING RECENTLY ENACTED TAX REFORM LEGISLATION, TO THEIR PARTICULAR SITUATION, AS WELL AS ANY TAX CONSEQUENCES OF THE PURCHASE, OWNERSHIP AND DISPOSITION OF OUR COMMON STOCK ARISING UNDER THE U.S. FEDERAL ESTATE OR GIFT TAX LAWS OR UNDER THE LAWS OF ANY STATE, LOCAL, NON- U.S. OR OTHER TAXING JURISDICTION OR UNDER ANY APPLICABLE INCOME TAX TREATY.

 

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Non- U.S. Holder Defined

For purposes of this discussion, a “non-U.S. holder” is a beneficial owner of our common stock that is not for U.S. federal income tax purposes a partnership or any of the following:

 

   

an individual who is a citizen or resident of the United States;

 

   

a corporation (or other entity treated as a corporation for U.S. federal income tax purposes) created or organized in or under the laws of the United States, any state thereof or the District of Columbia;

 

   

an estate the income of which is subject to U.S. federal income tax regardless of its source; or

 

   

a trust (i) whose administration is subject to the primary supervision of a U.S. court and which has one or more United States persons who have the authority to control all substantial decisions of the trust or (ii) which has made a valid election under applicable U.S. Treasury regulations to be treated as a United States person.

If a partnership (including an entity or arrangement treated as a partnership for U.S. federal income tax purposes) holds our common stock, the tax treatment of a partner in the partnership generally will depend upon the status of the partner, upon the activities of the partnership and upon certain determinations made at the partner level. Accordingly, we urge partners in partnerships (including entities or arrangements treated as partnerships for U.S. federal income tax purposes) considering the purchase of our common stock to consult their tax advisors regarding the U.S. federal income tax considerations of the purchase, ownership and disposition of our common stock by such partnership.

Distributions

As described above under “Dividend Policy,” we do not plan to make any distributions on our common stock in the foreseeable future. However, in the event we do make distributions of cash or other property on our common stock, such distributions will constitute dividends for U.S. federal income tax purposes to the extent paid from our current or accumulated earnings and profits, as determined under U.S. federal income tax principles. To the extent those distributions exceed our current and accumulated earnings and profits, the distributions will be treated as a non-taxable return of capital to the extent of the non-U.S. holder’s tax basis in our common stock and thereafter as capital gain from the sale or exchange of such common stock. See “—Gain on Disposition of Common Stock.” Subject to the withholding requirements under FATCA (as defined below) and except as with respect to effectively connected dividends, each of which is discussed below, dividends paid to a non-U.S. holder on our common stock generally will be subject to U.S. withholding tax at a rate of 30% of the gross amount of the distribution unless an applicable income tax treaty provides for a lower rate. To receive the benefit of a reduced treaty rate, a non-U.S. holder must provide the applicable withholding agent with an IRS Form W-8BEN or IRS Form W-8BEN-E (or other applicable or successor form) certifying qualification for the reduced rate.

Dividends paid to a non-U.S. holder that are effectively connected with a trade or business conducted by the non-U.S. holder in the United States (and, if required by an applicable income tax treaty, are treated as attributable to a permanent establishment maintained by the non-U.S. holder in the United States) generally will be taxed on a net income basis at the rates and in the manner generally applicable to United States persons (as defined under the Code). Such effectively connected dividends will not be subject to U.S. withholding tax if the non-U.S. holder satisfies certain certification requirements by providing the applicable withholding agent with a properly executed IRS Form W-8ECI certifying eligibility for exemption. If the non-U.S. holder is a corporation for U.S. federal income tax purposes, it may also be subject to a branch profits tax (at a 30% rate or such lower rate as specified by an applicable income tax treaty) on its effectively connected earnings and profits (as adjusted for certain items), which will include effectively connected dividends.

 

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Gain on Disposition of Common Stock

Subject to the discussion below under “—Backup Withholding and Information Reporting” and “—Additional Withholding Requirements under FATCA,” a non-U.S. holder generally will not be subject to U.S. federal income tax on any gain realized upon the sale or other disposition of our common stock unless:

 

   

the non-U.S. holder is an individual who is present in the United States for a period or periods aggregating 183 days or more during the calendar year in which the sale or disposition occurs and certain other conditions are met;

 

   

the gain is effectively connected with a trade or business conducted by the non-U.S. holder in the United States (and, if required by an applicable income tax treaty, is attributable to a permanent establishment maintained by the non-U.S. holder in the United States); or

 

   

our common stock constitutes a U.S. real property interest by reason of our status as a United States real property holding corporation, or USRPHC, for U.S. federal income tax purposes during the shorter of the five-year period ending on the date of the disposition or the non-U.S. holder’s holding period for our common stock.

A non-U.S. holder described in the first bullet point above will be subject to U.S. federal income tax at a rate of 30% (or such lower rate as specified by an applicable income tax treaty) on the amount of such gain, which generally may be offset by U.S. source capital losses.

A non-U.S. holder whose gain is described in the second bullet point above or, subject to the exceptions described in the next paragraph, the third bullet point above generally will be taxed on a net income basis at the rates and in the manner generally applicable to United States persons (as defined under the Code) unless an applicable income tax treaty provides otherwise. If the non-U.S. holder is a corporation for U.S. federal income tax purposes, whose gain is described in the second bullet point above, then such gain would also be included in its effectively connected earnings and profits (as adjusted for certain items), which may be subject to a branch profits tax (at a 30% rate or such lower rate as specified by an applicable income tax treaty).

Generally, a corporation is a USRPHC if the fair market value of its U.S. real property interests equals or exceeds 50% of the sum of the fair market value of its worldwide real property interests and its other assets used or held for use in a trade or business. We believe that we currently are, and expect to remain for the foreseeable future, a USRPHC for U.S. federal income tax purposes. However, as long as our common stock is and continues to be regularly traded on an established securities market, only a non-U.S. holder that actually or constructively owns, or owned at any time during the shorter of the five-year period ending on the date of the disposition or the non-U.S. holder’s holding period for the common stock, more than 5% of our common stock will be taxable on gain realized on the disposition of our common stock as a result of our status as a USRPHC. If our common stock ceased to be regularly traded on an established securities market prior to the beginning of the calendar year in which the relevant disposition occurred, all non-U.S. holders (regardless of the percentage of stock owned) generally would be subject to U.S. federal income tax on a taxable disposition of our common stock (as described in the preceding paragraph), and a 15% withholding tax would apply to the gross proceeds from the sale of our common stock by such non- U.S. holders.

Non-U.S. holders should consult their tax advisors with respect to the application of the foregoing rules to their ownership and disposition of our common stock.

Backup Withholding and Information Reporting

Any dividends paid to a non-U.S. holder must be reported annually to the IRS and to the non-U.S. holder. Copies of these information returns may be made available to the tax authorities in the country in which the non-U.S. holder resides or is established. Payments of dividends to a non-U.S. holder generally will not be subject to backup withholding if the non-U.S. holder establishes an exemption by properly certifying its non-U.S. status on an IRS Form W-8BEN, IRS Form W-8BEN-E or other applicable or successor form.

 

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Payments of the proceeds from a sale or other disposition by a non-U.S. holder of our common stock effected by or through a U.S. office of a broker generally will be subject to information reporting and backup withholding (at the applicable rate) unless the non-U.S. holder establishes an exemption by properly certifying its non-U.S. status on an IRS Form W-8BEN, IRS Form W- 8BEN-E or other applicable or successor form and certain other conditions are met. Information reporting and backup withholding generally will not apply to any payment of the proceeds from a sale or other disposition of our common stock effected outside the United States by a non-U.S. office of a broker. However, unless such broker has documentary evidence in its records that the non-U.S. holder is not a United States person and certain other conditions are met, or the non-U.S. holder otherwise establishes an exemption, information reporting will apply to a payment of the proceeds of the disposition of our common stock effected outside the United States by such a broker if it has certain relationships within the United States.

Backup withholding is not an additional tax. Rather, the U.S. income tax liability (if any) of persons subject to backup withholding will be reduced by the amount of tax withheld. If withholding results in an overpayment of taxes, a refund may be obtained, provided that the required information is timely furnished to the IRS.

Additional Withholding Requirements under FATCA

Sections 1471 through 1474 of the Code, and the Treasury regulations and administrative guidance issued thereunder, or FATCA, impose a 30% withholding tax on any dividends paid on our common stock and on the gross proceeds from a disposition of our common stock (if such disposition occurs after December 31, 2018), in each case if paid to a “foreign financial institution” or a “non-financial foreign entity” (each as defined in the Code) (including, in some cases, when such foreign financial institution or non-financial foreign entity is acting as an intermediary), unless (i) in the case of a foreign financial institution, such institution enters into an agreement with the U.S. government to withhold on certain payments, and to collect and provide to the U.S. tax authorities substantial information regarding U.S. account holders of such institution (which includes certain equity and debt holders of such institution, as well as certain account holders that are non-U.S. entities with U.S. owners), (ii) in the case of a non-financial foreign entity, such entity certifies that it does not have any “substantial United States owners” (as defined in the Code) or provides the applicable withholding agent with a certification (generally on an IRS Form W-8BEN-E) identifying the direct and indirect substantial United States owners of the entity, or (iii) the foreign financial institution or non-financial foreign entity otherwise qualifies for an exemption from these rules and provides appropriate documentation (such as an IRS Form W-8BEN-E). Foreign financial institutions located in jurisdictions that have an intergovernmental agreement with the United States governing these rules may be subject to different rules. Under certain circumstances, a holder might be eligible for refunds or credits of such taxes.

The rules under FATCA are complex. Non-U.S. holders are encouraged to consult with their own tax advisor regarding the effects of FATCA on an investment in our common stock.

INVESTORS CONSIDERING THE PURCHASE OF OUR COMMON STOCK ARE URGED TO CONSULT THEIR OWN TAX ADVISORS REGARDING THE APPLICATION OF THE U.S. FEDERAL INCOME TAX LAWS TO THEIR PARTICULAR SITUATIONS AND THE APPLICABILITY AND EFFECT OF U.S. FEDERAL ESTATE AND GIFT TAX LAWS AND ANY STATE, LOCAL OR NON-U.S. TAX LAWS AND TAX TREATIES.

 

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UNDERWRITING (CONFLICTS OF INTEREST)

SunTrust Robinson Humphrey, Inc. and Seaport Global Securities LLC are acting as the joint book-running managers and as the representatives of the underwriters named below. Under the terms and subject to the conditions contained in an underwriting agreement, which will be filed as an exhibit to the registration statement of which this prospectus forms a part, we have agreed to sell to each of the underwriters named below the following number of shares of common stock shown opposite its name:

 

Underwriters

   Number of
Shares
 

SunTrust Robinson Humphrey, Inc.

  

Seaport Global Securities LLC

  
  

 

 

 

Total

  
  

 

 

 

The underwriting agreement provides that the underwriters are obligated to purchase all of the shares of common stock in this offering if they are purchased, other than those shares covered by the underwriters’ option to purchase additional shares described below, subject to the satisfaction of the conditions contained in the underwriting agreement, including that:

 

   

the representations and warranties made by us to the underwriters are true;

 

   

there is no material change in our business or the financial markets; and

 

   

we deliver customary closing documents to the underwriters.

The representatives of the underwriters have advised us that the underwriters propose to offer the shares of common stock directly to the public at the public offering price on the cover of this prospectus and to selected dealers, which may include the underwriters, at such offering price less a selling concession not in excess of $            per share. After the offering, the representatives may change the offering price and other selling terms. Sales of shares made outside of the United States may be made by affiliates of the underwriters.

Discounts, Commissions and Expenses

The following table summarizes the underwriting discounts and commissions we will pay to the underwriters in connection with this offering. These amounts are shown assuming both no exercise and full exercise of the underwriters’ option to purchase additional shares. The underwriting fee is the difference between the initial price to the public and the amount the underwriters pay to us for the shares.

 

     Per Share      Total  
     With
No Exercise
     With
Full Exercise
     With
No Exercise
     With
Full Exercise
 

Underwriting Discounts and Commissions paid by us

   $           

We estimate that the expenses of the offering, not including underwriting discounts and commissions, will be approximately $                .

In addition to the underwriting discounts and commissions to be paid by us, we have agreed to reimburse the underwriters for certain of their out-of-pocket expenses incurred in connection with this offering, including, among other things, the reasonable fees and disbursements of counsel for the underwriters as set forth in the underwriting agreement and in connection with any required review of the offering by FINRA (including any filing fees in connection therewith), in an amount not greater than $                .

 

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Option to Purchase Additional Shares

We have granted the underwriters an option exercisable for 30 days after the date of the underwriting agreement, to purchase up to                 additional shares at the public offering price less underwriting discounts and commissions. This option may be exercised only to cover any overallotments of common stock. To the extent that this option is exercised, each underwriter will be obligated, subject to certain conditions, to purchase its pro rata portion of these additional shares based on the underwriter’s underwriting commitment in the offering as indicated in the table at the beginning of this “Underwriting (Conflicts of Interest)” section.

Lock-Up Agreements

We and all of our directors and executive officers, and our Existing Owners, have agreed that, without the prior written consent of SunTrust Robinson Humphrey, Inc. and Seaport Global Securities LLC, we and they will not directly or indirectly, (1) offer for sale, sell, issue, contract to sell, pledge or otherwise dispose of (or enter into any transaction or device that is designed to, or could be expected to, result in the disposition by any person at any time in the future of) any shares of our common stock or other securities or securities convertible into or exchangeable for our common stock or other securities (other than shares sold in this offering), or with respect to us, sell or grant options, rights or warrants with respect to any shares of our common stock or other securities or securities convertible into or exchangeable for our common stock or other securities, (2) enter into any swap or other derivatives transaction that transfers to another, in whole or in part, any of the economic benefits or risks of ownership of such shares of our common stock or other securities, whether any such transaction described in clause (1) or (2) above is to be settled by delivery of our common stock or other securities, in cash or otherwise, (3) offer to purchase, purchase or contract to purchase or grant any option, right or warrant to purchase our common stock or other securities or securities convertible, exercisable or exchangeable into our common stock or other securities, (4) file or cause to be filed a registration statement, including any amendments, with respect to the registration of any shares of our common stock or other securities or securities convertible, exercisable or exchangeable into our common stock or other securities (other than with respect to the Company, any registration statement on Form S-8), (5) establish or increase a put equivalent position or liquidate or decrease a call equivalent position in securities of the Company or (6) publicly disclose the intention to do any of the foregoing for a period of 180 days after the date of this prospectus.

SunTrust Robinson Humphrey, Inc. and Seaport Global Securities LLC, in their sole discretion, may release the common stock and other securities subject to the lock-up agreements described above in whole or in part at any time with or without notice. When determining whether or not to release common stock and other securities from lock-up agreements, SunTrust Robinson Humphrey, Inc. and Seaport Global Securities LLC will consider, among other factors, the holder’s reasons for requesting the release, the number of shares of common stock and other securities for which the release is being requested and market conditions at the time.

Offering Price Determination

Prior to the completion of this offering, there will have been no public market for our common stock. The initial public offering price will be determined by negotiations between the underwriters and us. In determining the initial public offering price of our common stock, the principal factors that will be considered include the following:

 

   

the information included in this prospectus and otherwise available to the underwriters;

 

   

market conditions for initial public offerings;

 

   

the history and prospects of our business and for the industry in which we compete;

 

   

our past and present earnings and operations and current financial position;

 

   

an assessment of our management and our future business prospects;

 

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the general condition of the securities markets at the time of this offering; and

 

   

the recent market prices of, and the demand for, publicly traded shares of companies in businesses similar to ours.

Indemnification

We have agreed to indemnify the underwriters against certain liabilities, including liabilities under the Securities Act, and to contribute to payments that the underwriters may be required to make for these liabilities.

Stabilization, Short Positions and Penalty Bids

In connection with this offering, the underwriters may engage in stabilizing transactions, overallotment transactions, syndicate covering transactions and penalty bids or purchases for the purpose of pegging, fixing or maintaining the price of the common stock, in accordance with Regulation M under the Exchange Act.

 

   

Stabilizing transactions permit bids to purchase the underlying security under specified circumstances.

 

   

Overallotment transactions involve sales by the underwriters of shares in excess of the number of shares the underwriters are obligated to purchase in the offering, which creates the syndicate short position. This short position may be either a covered short position or a naked short position. In a covered short position, the number of shares involved in the sales made by the underwriters in excess of the number of shares they are obligated to purchase is not greater than the number of shares that they may purchase by exercising their option to purchase additional shares. In a naked short position, the number of shares involved is greater than the number of shares in their option to purchase additional shares. The underwriters may close out any short position by either exercising their option to purchase additional shares and/or purchasing shares in the open market. In determining the source of shares to close out the short position, the underwriters will consider, among other things, the price of shares available for purchase in the open market as compared to the price at which they may purchase shares through their option to purchase additional shares. A naked short position is more likely to be created if the underwriters are concerned that there could be downward pressure on the price of the shares in the open market after pricing that could adversely affect investors who purchase in the offering.

 

   

Syndicate covering transactions involve purchases of the common stock in the open market after the distribution has been completed in order to cover syndicate short positions.

 

   

Penalty bids permit the representatives to reclaim a selling concession from a syndicate member when the common stock originally sold by the syndicate member is purchased in a stabilizing or syndicate covering transaction to cover syndicate short positions.

These stabilizing transactions, syndicate covering transactions and penalty bids may have the effect of raising or maintaining the market price of our common stock or preventing or retarding a decline in the market price of our common stock. As a result, the price of our common stock may be higher than the price that might otherwise exist in the open market. These transactions may be effected on the NYSE American or otherwise and, if commenced, may be discontinued at any time. Neither we nor any of the underwriters make any representation or prediction as to the direction or magnitude of any effect that the transactions described above may have on the price of the common stock. In addition, neither we nor any of the underwriters make any representation that the underwriters will engage in these stabilizing transactions or that any transaction, once commenced, will not be discontinued without notice.

NYSE American Listing

We have been cleared to apply to list our common stock on the NYSE American under the symbol “REPX.” In order to meet the requirements for listing on that exchange, the underwriters have undertaken to sell a minimum number of shares to a minimum number of beneficial owners as required by that exchange.

 

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An active trading market for the shares may not develop. It is also possible that after the offering the shares will not trade in the public market at or above the initial public offering price.

Electronic Distribution

A prospectus in electronic format may be made available on websites or through other online services maintained by one or more of the underwriters and/or selling group members participating in this offering, or by their affiliates. In those cases, prospective investors may view offering terms online and, depending upon the particular underwriter or selling group member, prospective investors may be allowed to place orders online. In addition, one or more of the underwriters participating in this offering may distribute prospectuses electronically. The underwriters may agree with us to allocate a specific number of shares for sale to online brokerage account holders. Any such allocation for online distributions will be made by the representatives on the same basis as other allocations. Other than the prospectus in electronic format, the information on any underwriter’s or selling group member’s website and any information contained in any other website maintained by an underwriter or selling group member is not part of the prospectus or the registration statement of which this prospectus forms a part, has not been approved and/or endorsed by us or any underwriter or selling group member in its capacity as underwriter or selling group member and should not be relied upon by investors.

Discretionary Sales

The underwriters have informed us that they do not expect sales to accounts over which the underwriters have discretionary authority to exceed 5% of the total number of shares offered by them.

Relationships with Underwriters (Conflicts of Interest)

An affiliate of SunTrust Robinson Humphrey, Inc. is a lender under our revolving credit facility and may receive 5% or more of the net proceeds of this offering due to the repayment of borrowings thereunder. Therefore, SunTrust Robinson Humphrey, Inc. is deemed to have a conflict of interest within the meaning of FINRA Rule 5121. Accordingly, this offering is being conducted in accordance with Rule 5121, which requires, among other things, that a “qualified independent underwriter” participate in the preparation of, and exercise the usual standards of “due diligence” with respect to, the registration statement and this prospectus. Seaport Global Securities, LLC has agreed to act as a qualified independent underwriter for this offering pursuant to Rule 5121 and to undertake the legal responsibilities and liabilities of an underwriter under the Securities Act. Seaport Global Securities, LLC will not receive any additional fees for serving as a qualified independent underwriter in connection with this offering; provided, however, that we have agreed to reimburse Seaport Global Securities, LLC an amount up to $25,000 for its expenses incurred as a result of its engagement as a qualified independent underwriter; and provided further, that we have also agreed to indemnify Seaport Global Securities, LLC against certain liabilities incurred in connection with acting as a qualified independent underwriter, including liabilities under the Securities Act.

Pursuant to Rule 5121, SunTrust Robinson Humphrey, Inc. will not confirm any sales to any account over which it exercises discretionary authority without the specific written approval of the account holder.

Other Relationships

Some of the underwriters and their affiliates have engaged in and may, from time to time in the future engage, in transactions with and perform services for us, such as other commercial banking services, investment banking and financial advisory services, fairness opinions and other similar services, including those that may be provided in connection with any acquisitions or investments we may make, for which they have received, or may in the future receive customary compensation. Additionally, in the ordinary course of their various business activities, the underwriters and their respective affiliates may make or hold a broad array of investments and actively trade debt and equity securities (or related derivative securities) and financial instruments (including

 

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bank loans) for their own account and for the accounts of their customers and may at any time hold long and short positions in such securities and instruments. Such investment and securities activities may involve our securities and instruments.

Notice to Canadian Residents

This prospectus constitutes an “exempt offering document” as defined in and for the purposes of applicable Canadian securities laws. No prospectus has been filed with any securities commission or similar regulatory authority in Canada in connection with the offer and sale of the shares. No securities commission or similar regulatory authority in Canada has reviewed or in any way passed upon this prospectus or on the merits of the shares and any representation to the contrary is an offence.

Canadian investors are advised that this prospectus has been prepared in reliance on section 3A.3 of National Instrument 33-105 Underwriting Conflicts (“NI 33-105”). Pursuant to section 3A.3 of NI 33-105, this prospectus is exempt from the requirement that the Company and the underwriters provide Canadian investors with certain conflicts of interest disclosure pertaining to “connected issuer” and/or “related issuer” relationships that may exist between the Company and the underwriters as would otherwise be required pursuant to subsection 2.1(1) of NI 33-105.

Resale Restrictions

The offer and sale of the shares in Canada is being made on a private placement basis only and is exempt from the requirement that the Company prepares and files a prospectus under applicable Canadian securities laws. Any resale of shares acquired by a Canadian investor in this offering must be made in accordance with applicable Canadian securities laws, which may vary depending on the relevant jurisdiction, and which may require resales to be made in accordance with Canadian prospectus requirements, pursuant to a statutory exemption from the prospectus requirements, in a transaction exempt from the prospectus requirements or otherwise under a discretionary exemption from the prospectus requirements granted by the applicable local Canadian securities regulatory authority. These resale restrictions may under certain circumstances apply to resales of the shares outside of Canada.

Representations of Purchasers

Each Canadian investor who purchases the shares will be deemed to have represented to the Company, the underwriters and to each dealer from whom a purchase confirmation is received, as applicable, that the investor is (i) purchasing as principal, or is deemed to be purchasing as principal in accordance with applicable Canadian securities laws, for investment only and not with a view to resale or redistribution; (ii) an “accredited investor” as such term is defined in section 1.1 of National Instrument 45-106 Prospectus Exemptions or, in Ontario, as such term is defined in section 73.3(1) of the Securities Act (Ontario); and (iii) is a “permitted client” as such term is defined in section 1.1 of National Instrument 31-103 Registration Requirements, Exemptions and Ongoing Registrant Obligations.

Taxation and Eligibility for Investment

Any discussion of taxation and related matters contained in this prospectus does not purport to be a comprehensive description of all of the tax considerations that may be relevant to a Canadian investor when deciding to purchase the shares and, in particular, does not address any Canadian tax considerations. No representation or warranty is hereby made as to the tax consequences to a resident, or deemed resident, of Canada of an investment in the shares or with respect to the eligibility of the shares for investment by such investor under relevant Canadian federal and provincial legislation and regulations.

 

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Rights of Action for Damages or Rescission

Securities legislation in certain of the Canadian jurisdictions provides certain purchasers of securities pursuant to an offering memorandum (such as this prospectus), including where the distribution involves an “eligible foreign security” as such term is defined in Ontario Securities Commission Rule 45-501 Ontario Prospectus and Registration Exemptions and in Multilateral Instrument 45-107 Listing Representation and Statutory Rights of Action Disclosure Exemptions, as applicable, with a remedy for damages or rescission, or both, in addition to any other rights they may have at law, where the offering memorandum, or other offering document that constitutes an offering memorandum, and any amendment thereto, contains a “misrepresentation” as defined under applicable Canadian securities laws. These remedies, or notice with respect to these remedies, must be exercised or delivered, as the case may be, by the purchaser within the time limits prescribed under, and are subject to limitations and defences under, applicable Canadian securities legislation. In addition, these remedies are in addition to and without derogation from any other right or remedy available at law to the investor.

Language of Documents

Upon receipt of this document, each Canadian investor hereby confirms that it has expressly requested that all documents evidencing or relating in any way to the sale of the securities described herein (including for greater certainty any purchase confirmation or any notice) be drawn up in the English language only. Par la réception de ce document, chaque investisseur canadien confirme par les présentes qu’il a expressément exigé que tous les documents faisant foi ou se rapportant de quelque manière que ce soit à la vente des valeurs mobilières décrites aux présentes (incluant, pour plus de certitude, toute confirmation d’achat ou tout avis) soient rédigés en anglais seulement.

 

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LEGAL MATTERS

The validity of our common stock offered by this prospectus will be passed upon for us by di Santo Law PLLC. Certain legal matters in connection with this offering will be passed upon for the underwriters by Goodwin Procter LLP, New York, New York.

EXPERTS

The financial statements of Riley Exploration—Permian, LLC as of September 30, 2017 and September 30, 2016 and for the years then ended, included in this prospectus, have been so included in reliance on the report of BDO USA, LLP, an independent registered public accounting firm appearing elsewhere herein, given on the authority of said firm as experts in auditing and accounting.

The statements of revenues and direct operating expenses for properties acquired by Riley Exploration—Permian, LLC for the years ended December 31, 2016 and 2015, included in this prospectus have been so included in reliance on the report of BDO USA, LLP, an independent registered public accounting firm, appearing elsewhere herein, given on the authority of said firm as experts in auditing and accounting.

The information included in this prospectus regarding estimated quantities of reserves of Riley Exploration—Permian, LLC, the future net revenues from those reserves and their present value as of September 30, 2017 is based on the reserve reports prepared by Netherland, Sewell & Associates, Inc., or NSAI, our independent petroleum engineers. These estimates are included in this prospectus in reliance upon the authority of such firm as an expert in these matters.

 

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WHERE YOU CAN FIND MORE INFORMATION

We have filed with the SEC a registration statement on Form S-1 (including the exhibits, schedules and amendments thereto) under the Securities Act, with respect to the shares of our common stock offered hereby. This prospectus does not contain all of the information set forth in the registration statement and the exhibits and schedules thereto. For further information with respect to the common stock offered hereby, we refer you to the registration statement and the exhibits and schedules filed therewith. Statements contained in this prospectus as to the contents of any contract, agreement or any other document are summaries of the material terms of such contract, agreement or other document and are not necessarily complete. With respect to each of these contracts, agreements or other documents filed as an exhibit to the registration statement, reference is made to the exhibits for a more complete description of the matter involved. A copy of the registration statement, and the exhibits and schedules thereto, may be inspected without charge at the public reference facilities maintained by the SEC at 100 F Street NE, Washington, D.C. 20549. Copies of these materials may be obtained, upon payment of a duplicating fee, from the Public Reference Room of the SEC at 100 F Street NE, Washington, D.C. 20549. Please call the SEC at 1-800-SEC-0330 for further information on the operation of the Public Reference Room. The SEC maintains a website that contains reports, proxy and information statements and other information regarding registrants that file electronically with the SEC. The address of the SEC’s website is www.sec.gov.

As a result of the offering, we will become subject to full information requirements of the Exchange Act. We will fulfill our obligations with respect to such requirements by filing periodic reports and other information with the SEC. We intend to furnish our shareholders with annual reports containing financial statements certified by an independent public accounting firm.

 

 

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INDEX TO FINANCIAL STATEMENTS

 

Pro Forma Financial Statements (Unaudited)   

Introduction

     F-2  

Unaudited Pro Forma Consolidated Balance Sheet as of June 30, 2018

     F-3  

Unaudited Pro Forma Consolidated Statement of Operations for the nine months ended June 30, 2018

     F-4  

Unaudited Pro Forma Consolidated Statement of Operations for the year ended September 30, 2017

     F-5  

Notes to Unaudited Pro Forma Consolidated Financial Statements

     F-6  
Historical Financial Statements   

Condensed Consolidated Financial Statements of Riley Exploration—Permian, LLC

  

Condensed Consolidated Balance Sheets as of June 30, 2018, and September 30, 2017

     F-15  

Condensed Consolidated Statements of Operations for the Nine Months Ended June 30, 2018 and 2017

     F-16  

Condensed Consolidated Statements of Changes in Members’ Equity for the Nine Months Ended June 30, 2018

     F-17  

Condensed Consolidated Statements of Cash Flows for the Nine Months Ended June 30, 2018 and 2017

     F-18  

Notes to Condensed Consolidated Financial Statements

     F-19  

Consolidated Financial Statements of Riley Exploration—Permian, LLC

  

Report of Independent Registered Public Accounting Firm

     F-30  

Consolidated Balance Sheets as of September 30, 2017 and 2016

     F-31  

Consolidated Statements of Operations for the years ended September  30, 2017 and 2016

     F-32  

Consolidated Statements of Changes in Parent Net Investment/Members’ Equity

     F-33  

Consolidated Statements of Cash Flows for the years ended September  30, 2017 and 2016

     F-34  

Notes to the Financial Statements

     F-35  

Combined Statements of Revenues and Direct Operating Expenses

  

Independent Auditor’s Report

     F-56  

Combined Statements of Revenues and Direct Operating Expenses of the Oil and Gas Properties Acquired and to be acquired by Riley Exploration—Permian, LLC for the years ended December 31, 2016 and 2015

     F-58  

Notes to Financial Statements

     F-59  

 

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Index to Financial Statements

Pro Forma Financial Statements (Unaudited)

Introduction

Riley Exploration Permian, Inc. (the “Company”), will be formed upon the conversion of Riley Exploration-Permian, LLC, a Delaware limited liability company (“Riley Permian”), into a Delaware corporation in connection with this offering. Riley Permian was formed to engage in the acquisition, development and production of oil, natural gas and natural gas liquids reserves in the Permian Basin.

Riley Permian was 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, 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.

Riley Permian acquired the Champions Assets in a series of transactions in 2017. On January 17, 2017, each of REG and Boomer Petroleum, LLC (referred to as Boomer), each an Existing Owner, contributed to us their respective leasehold 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, certain other of our Existing Owners, Bluescape and DR/CM contributed to us their respective interests in the Champions Assets in exchange for our common units.

The unaudited pro forma balance sheet of the Company is based on the historical balance sheet as of June 30, 2018 and includes pro forma adjustments to give effect to the following transactions as if they occurred on June 30, 2018:

 

   

The Corporate Conversion (referred to as the “Corporate Conversion”) which includes (i) the conversion of Riley Permian from a Delaware limited liability company into the Company, Riley Exploration Permian, Inc., a Delaware corporation and (ii) the conversion of the common units and Series A Preferred Units of the Company into our common stock; and

 

   

The initial public offering of              shares of the Company’s common stock and use of net proceeds therefrom as described in “Use of Proceeds” (the “Offering”). The net proceeds are expected to be approximately $         million, net of underwriting discounts and commissions of approximately $         million and other offering costs of approximately $         million.

The unaudited pro forma statement of operations of the Company for the nine months ended June 30, 2018 reflects the historical statement of operations of the Company for the entire period.

The unaudited pro forma statement of operations of the Company for the year ended September 30, 2017 is based on the audited historical statement of operations of the Company for the year ended September 30, 2017 and the unaudited statements of operation of the businesses acquired from October 1, 2016 to their respective acquisition dates as reflected below.

 

   

The acquisition of Boomer’s 28% working interest in the Champions Assets on January 17, 2017 and the acquisition of Bluescape and DR/CM’s combined 29.3% working interest in the Champions Assets on March 6, 2017.

The following pro forma adjustments are additional adjustments made to both the unaudited pro forma statements of operations for the nine months ended June 30, 2018 and year ended September 30, 2017, to give effect to the following transactions as if they occurred on October 1, 2017 and October 1, 2016, respectively:

 

   

The Corporate Conversion which includes (i) the conversion of Riley Permian from a Delaware limited liability company into the Company, Riley Exploration Permian, Inc., a Delaware corporation and (ii) the conversion of the common units and Series A Preferred Units of the Company into our common stock.

 

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Unaudited Pro Forma Consolidated Balance Sheet

As of June 30, 2018

(in thousands)

 

     Company
Historical
     Corporate
Conversion
         Offering          Pro forma  

Assets

               

Current assets

               

Cash and cash equivalents

   $ 1,029      $ —          $ (2,100   (e)    $    

Accounts receivable

     7,174        —            —            7,174  

Other accounts receivable

     9        —            —            9  

Prepaid expenses and other current assets

     372        —            —            372  
  

 

 

    

 

 

      

 

 

      

 

 

 

Total current assets

     8,584        —              

Non-current assets

               

Oil and gas properties, net

     227,914        —            —            227,914  

Other property and equipment

     1,843        —            —            1,843  

Other non-current assets

     3,792        —            (1,975   (f)   
  

 

 

    

 

 

      

 

 

      

 

 

 

Total non-current assets

     233,549        —            —            233,549  
  

 

 

    

 

 

      

 

 

      

 

 

 

Total assets

   $ 242,133      $ —          $          $    
  

 

 

    

 

 

      

 

 

      

 

 

 

Liabilities and Members’ equity

               

Current liabilities

               

Accounts payable

   $ 5,448      $ —          $ —          $ 5,448  

Accrued liabilities

     19,474        —            (4,000  

(e)

     15,474  

Revenue payable

     4,098        —            —            4,098  

Advances from joint interest owners

     534        —            —            534  

Notes payable—current

     113        —            —            113  

Derivative liabilities

     8,907        —            —            8,907  
  

 

 

    

 

 

      

 

 

      

 

 

 

Total current liabilities

     38,574        —            (4,000        86,217  

Notes payable—non-current

     —          —            —            —    

Non-current derivative liabilities

     1,753        —            —            1,753  

Asset retirement obligations

     826        —            —            826  

Revolving credit facility

     44,000        —            (g)   

Deferred tax liability

     —          5,064     (a)      —            5,064  
  

 

 

    

 

 

      

 

 

      

 

 

 

Total liabilities

     83,153        5,064          (4,000     

Series A Preferred Units

     52,739        (52,739   (c)      —            —    

Members’ / Stockholders’ equity

               

Members’ equity

     104,241        (104,241   (b)      —            —    

Common stock, par value $0.01

     —          —       (b)(c)      —       (e)      —    

Additional paid -in capital

     —          170,165     (b)(c)      2,025     (d)(e)(f)   

Retained earnings

     —          (18,249   (a)(c)      (2,100   (e)      (20,349
  

 

 

    

 

 

      

 

 

      

 

 

 

Total Members’ / Stockholders’ equity

     104,241        47,675            
  

 

 

    

 

 

      

 

 

      

 

 

 

Total liabilities and Members’ / Stockholders’ equity

   $ 242,133      $ —          $          $    
  

 

 

    

 

 

      

 

 

      

 

 

 

The accompanying notes are an integral part of these unaudited pro forma consolidated financial statements.

 

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Unaudited Pro Forma Consolidated Statement of Operations

For the Nine Months Ended June 30, 2018

(in thousands, except per unit and per share data)

 

     Company
Historical
    Corporate
Conversion
           Pro forma        

Revenues:

           

Oil sales

   $ 46,438     $ —          $ 46,438    

Natural gas sales

     252       —            252    

Natural gas liquids sales

     909       —            909    
  

 

 

   

 

 

      

 

 

   

Total revenues

     47,599       —            47,599    
  

 

 

   

 

 

      

 

 

   

Operating expenses:

           

Lease operating expenses

     8,135       —            8,135    

Production taxes

     2,191       —            2,191    

Exploration costs

     5,523       —            5,523    

Depletion, depreciation, amortization and accretion

     11,388       —            11,388    

General administrative expenses

     10,596       —            10,596    

Stock compensation expense

     —            (l    

Transaction costs

     790       —            790    
  

 

 

   

 

 

      

 

 

   

Total operating expenses

     38,623       —            38,623    
  

 

 

   

 

 

      

 

 

   

Income from operations

     8,976       —            8,976    

Other expenses:

           

Interest expense

     (907     —            (907  

Loss on derivatives

     (13,895     —            (13,895  
  

 

 

   

 

 

      

 

 

   

Loss before income tax benefit

     (5,826     —            (5,826  

Income tax benefit

     —         1,450        (m     1,450    
  

 

 

   

 

 

      

 

 

   

Net loss

     (5,826     1,450          (4,376  

Dividends on preferred units

     (2,327     2,327        (n    
  

 

 

   

 

 

      

 

 

   

Net loss attributable to common units

   $ (8,153   $ 3,777        $ (4,376  
  

 

 

   

 

 

      

 

 

   

Loss per unit

           

Basic and diluted

   $ (5.44         
  

 

 

          

Weighted average units outstanding

     1,500           
  

 

 

          

Basic pro forma net income per common share

              (o
         

 

 

   

Diluted pro forma net income per common share

              (o
         

 

 

   

Pro Forma weighted common shares outstanding

          (p       (p
    

 

 

      

 

 

   

The accompanying notes are an integral part of these unaudited pro forma consolidated financial statements.

 

F-4


Table of Contents
Index to Financial Statements

Unaudited Pro Forma Consolidated Statement of Operations

For the Year Ended September 30, 2017

(in thousands, except per unit and per share data)

 

     Company
Historical
    Boomer
acquisition
          Bluescape
DR/CM
acquisition
          Corporate
Conversion
           Pro forma        

Revenues:

                   

Oil sales

   $ 21,174     $ 1,499       (h   $ 2,409       (i   $          $ 25,082    

Natural gas sales

     203       26       (h     38       (i          267    

Natural gas liquids sales

     431       50       (h     73       (i          554    

Other revenue

     —         —           —                —      
  

 

 

   

 

 

     

 

 

     

 

 

      

 

 

   

Total revenues

     21,808       1,575         2,520         —            25,903    
  

 

 

   

 

 

     

 

 

     

 

 

      

 

 

   

Operating expenses:

                   

Lease operating expenses

     5,796       559       (h     930       (i          7,285    

Production taxes

     1,206       120       (h     176       (i          1,502    

Exploration costs

     10,739       —           4       (i          10,743    

Depletion, depreciation, amortization and accretion

     5,876       400       (j     652       (j          6,928    

General administrative expenses

     5,806       —           —                5,806    

Stock compensation expense

     —         —           —              (l    

Transaction costs

     1,766       (883     (k     (883     (k          —      
  

 

 

   

 

 

     

 

 

     

 

 

      

 

 

   

Total operating expenses

     31,189       196         879         —            32,264    
  

 

 

   

 

 

     

 

 

     

 

 

      

 

 

   

Loss from operations

     (9,381     1,379         1,641         —            (6,361  

Other expenses:

                   

Loss on derivatives

     (1,450     —           —                (1,450  
  

 

 

   

 

 

     

 

 

     

 

 

      

 

 

   

Loss before income tax benefit

     (10,831     1,379         1,641         —            (7,811  

Income tax expense (benefit)

     —         —           —           2,624        (m     2,624    
  

 

 

   

 

 

     

 

 

     

 

 

      

 

 

   

Net loss

     (10,831     1,379         1,641         —            (5,187  

Dividends on preferred units

     (1,409     —           —           1,409        (n     —      
  

 

 

   

 

 

     

 

 

     

 

 

      

 

 

   

Net loss attributable to common units

   $ (12,240   $ 1,379       $ 1,641       $ 4,033        $ (5,187  
  

 

 

   

 

 

     

 

 

     

 

 

      

 

 

   

Loss per unit

                   

Basic and diluted

   $ (10.63                 
  

 

 

                  

Weighted average units outstanding

     1,151                   
  

 

 

                  

Pro forma net loss per common share

                      (o
                 

 

 

   

Pro Forma weighted common shares outstanding

                  (p       (p
         

 

 

      

 

 

   

The accompanying notes are an integral part of these unaudited pro forma consolidated financial statements.

 

F-5


Table of Contents
Index to Financial Statements

Notes to Unaudited Pro Forma Consolidated Financial Statements

Note 1 Basis of presentation

Our unaudited pro forma financial information is derived from our financial statements included elsewhere in this prospectus and from the unaudited statements of operations of the businesses acquired from October 1, 2016 to their respective acquisition dates. The unaudited pro forma financial statements were prepared in accordance with GAAP and pursuant to Regulation S-X Article 11.

The pro forma data presented reflects events directly attributable to the described transactions and certain assumptions we believe are reasonable. The pro forma data are not necessarily indicative of financial results that would have been attained had the described transactions occurred on the dates indicated or which could be achieved in the future because they necessarily exclude various operating expenses, such as incremental general and administrative expenses. The adjustments are based on currently available information and certain estimates and assumptions. However, management believes that the assumptions provide a reasonable basis for presenting the significant effects of the transactions as contemplated and that the pro forma adjustments give appropriate effect to those assumptions and are properly applied in the unaudited pro forma financial statements.

The unaudited pro forma financial statements have been prepared on the basis that we will be taxed as a corporation, and as a result, will become a tax-paying entity subject to U.S. federal and state income taxes, and should be read in conjunction with “Corporate Conversion,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and with the audited historical financial statements and related notes of the Company, included elsewhere in this prospectus.

Upon the closing of the offering contemplated by this prospectus, we expect to incur direct, incremental general and administrative expenses as a result of being a publicly traded company, including, but not limited to, costs associated with annual and quarterly reports to stockholders, tax return preparation, incremental independent auditor fees, investor relations activities, registrar and transfer agent fees, incremental director and officer liability insurance costs, and independent director compensation. Such costs are not reflected in these pro forma financial statements.

Note 2 Pro forma adjustments and assumptions

We made the following adjustments and assumptions in the preparation of the unaudited pro forma balance sheet as of June 30, 2018.

 

  a)

Reflects the pro forma net deferred tax liability of $5.1 million as of June 30, 2018 arising from the temporary differences between the historical cost and tax basis of the Company’s assets and liabilities as a result of the change in the Company’s tax status to a subchapter C corporation. As a result of the enactment of the Tax Cuts and Jobs Act on December 22, 2017, the corporate income tax rate was reduced from 35% to 21%. The pro forma deferred tax liabilities reflect the rates expected to be in effect when the temporary differences reverse in the future, which is 21%. A charge to establish such net deferred tax liabilities will be recognized in the period which the change in the status occurs but has not been reflected in the pro forma consolidated statement of operations.

 

  b)

Reflects the issuance of            million shares of common stock in exchange for all of our common units.

 

  c)

Reflects the conversion of Riley Permian’s Series A Preferred Units into            million shares of our common stock. The amount of our common stock issued as a result of the conversion of Series A Preferred A Units is based on a conversion rate equal to (A) the quotient of the product of the number of Series 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

 

F-6


Table of Contents
Index to Financial Statements
  will result in a deemed preferred distribution to the Series A Preferred Unit holders of $13.2 million, which will reduce income attributable to common units in the period in which the conversion occurs. This reduction has not been reflected in the pro forma consolidated statement of operations.

 

  d)

Reflects the issuance of            million common stock in connection with this offering. The net proceeds are expected to be approximately $            million, net of underwriting discounts and commissions of approximately $            million and other offering costs of approximately $            million.

 

  e)

Reflects one time bonuses consisting of: (1) cash bonuses in an aggregate amount of $2.1 million to be paid to certain of our named executive officers and certain of our employees in a single lump sum cash payment in connection with the IPO and (2) the payment of a bonus to executives earned and accrued as of June 30, 2018 in common stock instead of in cash, consisting of             vested shares of common stock, which represents approximately $ 4.0 million (assuming the value of each share is equal to $                     (which represents the midpoint of the price range set forth on the cover of this prospectus with respect to a share of our common stock)). The $2.1 million of one-time cash bonuses has not been reflected in the pro forma consolidated statement of operations, but will be recorded as compensation expense in the period in which the IPO occurs.

 

  f)

Reflects existing balance of $2.0 million in deferred IPO costs to be netted against the proceeds from this offering with a corresponding reduction to additional paid-in capital upon completion of this offering.

 

  g)

Reflects existing balance of approximately $                 million under our revolving credit facility to be repaid upon completion of this offering.

After the Corporate Conversion, giving effect to this offering and the vested LTIP shares, the total number of our authorized and outstanding common stock will be             million and             million, respectively.

We made the following adjustments and assumptions in the preparation of the unaudited pro forma statement of operations for the nine months ended June 30, 2018 and/or the year ended September 30, 2017:

 

  h)

Reflects the historical revenues and direct operating expenses from the assets acquired and liabilities assumed in the acquisition of Boomer’s Champions Assets for the period from October 1, 2016 to the date of acquisition closing, January 17, 2017. No such adjustment was required for the nine months ended June 30, 2018 as the operating results of the acquired businesses were already included for the full period.

 

F-7


Table of Contents
Index to Financial Statements
    3-05 Financial
statements
    Less
Bluescape
    Boomer     Less Boomer     Boomer     Boomer     Pro forma
adjustment
 
Boomer   Year ended
December 31,
2016
    Year ended
December 31,
2016
    Year ended
December 31,
2016
    Period from
January 1 to
September 30,
2016
    Three
Months
ended
December 31,
2016
    Period
from
January 1,
2017 to
January 17,
2017
    Boomer  
    a     b     c=a-b     d     e=c-d     f     e+f  

Revenue

             

Oil

  $ 8,855     $ (4,526   $ 4,329     $ (3,080   $ 1,249     $ 250     $ 1,499  

Gas

    114       (58     56       (14     42       (16     26  

NGL

    91       (47     44       (21     23       27       50  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total revenues

    9,060       (4,631     4,429       (3,115     1,314       261       1,575  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Lease operating expenses

    (3,171     1,621       (1,550     1,124       (426     (173     (599

Workovers

    (1,822     931       (891     891       —         —         —    

Exploration expense

    21       (11     10       (10     —         —         —    
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total lease operating expenses

    (4,972     2,541       (2,431     2,005       (426     (173     (599
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Production tax

    (432     221       (211     145       (66     (54     (120

Exploration expense

    (21     21       —         —         —         —         —    

 

  i)

Reflects the historical revenues and direct operating expenses from the assets acquired and liabilities assumed in the acquisition of each of Bluescape’s and DR/CM’s Champions Assets for the period from October 1, 2016 to the date of acquisition closing, March 6, 2017. No such adjustment was required for the nine months ended June 30, 2018 as the operating results of the acquired business were already included for the full period.

 

    3-05
Financial
statements
    Less Boomer     Bluescape
DR/CM
    Less
Bluescape
DR/CM
    Bluescape
DR/CM
    Bluescape
DR/CM
    Pro forma
adjustment
 
Bluescape /DR/CM   Year ended
December 31,
2016
    Year ended
December 31,
2016
    Year ended
December 31,
2016
    Period from
January 1 to
September 30,
2016
    Three
Months
ended
December 31,
2016
    Period
from
January 1,
2017 to
March 7,
2017
    Bluescape
DR/CM
 
    a     b     c=a-b     d     e=c-d     f     e+f  

Revenue

             

Oil

  $ 8,855     $ (4,329   $ 4,526     $ (3,220   $ 1,306     $ 1,103     $ 2,409  

Gas

    114       (56     58       (14     44       (6     38  

NGL

    91       (44     47       (22     25       48       73  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total revenues

    9,060       (4,429     4,631       (3,256     1,375       1,145       2,520  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Lease operating expenses

    (3,171     1,550       (1,621     1,176       (445     (485     (930

Workovers

    (1,822     891       (931     931       —         —         —    

Exploration expense

    21       (10     11       (11     —         —         —    
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total lease operating expenses

    (4,972     2,431       (2,541     2,096       (445     (485     (930
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Production tax

    (432     211       (221     151       (70     (106     (176

Exploration expense

    (21     —         (21     17       (4     —         (4

 

  j)

Reflects the adjustment to depletion, depreciation, amortization and accretion expense that would have been recorded had the Boomer, Bluescape and DR/CM’s acquisitions occurred on October 1, 2016. We

 

F-8


Table of Contents
Index to Financial Statements
  utilized reserve reports to estimate the useful life of acquired wells and depleted the capitalized costs on a units-of-production basis over the remaining life of the proved and proved developed reserves. The depletion rate used was approximately $11.60 per MBoe for the year ended September 30, 2017. No such adjustment was required for the nine months ended June 30, 2018 as the operating results of the acquired businesses were already included for the full period.

 

  k)

Reflects the elimination of the transaction costs related to the Boomer, Bluescape and DR/CM acquisitions during the year ended September 30, 2017. No such adjustment was required for the nine months ended June 30, 2018 as the operating results of the acquired businesses were already included for the full period.

 

  l)

Reflects the estimated compensation expense associated with the granting of equity based awards under the LTIP, consisting of    unvested shares of common stock which will be subject to a three-year vesting, had such awards been granted on October 1, 2016. The estimated grant date fair value of these awards, based on the midpoint of the price range set forth on the cover of this prospectus with respect to a share of our common stock is $                million.

 

  m)

Reflects the estimated income tax benefit associated with our pro forma results of operations assuming our earnings had been subject to federal and state income tax as a sub-chapter C corporation using a combined federal and state tax rate of approximately 23.63% and 33.6% based on the estimated US federal income tax rate during the nine months ended June 30, 2018 and the year ended September 30, 2017, respectively. The decrease in the estimated US federal income tax rate during the nine months ended June 30, 2018 reflects the impact of the Tax Cuts and Jobs Act which was enacted on December 22, 2017 and reduced the corporate income tax rate, effective January 1, 2018, to 21%.

 

  n)

Reflects the reversal of the dividend accrued related to the Series A Preferred Units which are assumed to have been converted as of their issuance dates.

 

  o)

Reflects the basic and diluted loss per common share for the issuance of shares of common stock in the Corporate Conversion as if the Corporate Conversion had occurred on October 1, 2016.

 

  p)

Reflects the number of common shares issued in connection with the Corporate Conversion which includes the exchange of common units for            common shares and the conversion of the Series A Preferred Units for            common shares as if the exchange of common units had occurred on October 1, 2016 and the conversion of preferred units had occurred on their issuance dates.

Note 3 Supplementary disclosure of oil and gas operations

The following pro forma standardized measure of the discounted net future cash flows and changes applicable to our proved reserves reflect the effect of income taxes assuming our standardized measure had been subject to federal and state income tax as a subchapter C corporation. The future cash flows are discounted at 10% per year and assume continuation of existing economic conditions.

The standardized measure of discounted future net cash flows, in management’s opinion, should be examined with caution. The basis for this table is the reserve studies prepared by independent petroleum engineering consultants, which contain imprecise estimates of quantities and rates of production of reserves. Revisions of previous year estimates can have a significant impact on these results. Also, exploration costs in one year may lead to significant discoveries in later years and may significantly change previous estimates of proved reserves and their valuation. Therefore, the standardized measure of discounted future net cash flow is not necessarily indicative of the fair value of our proved oil and gas properties. The data presented should not be viewed as representing the expected cash flow from or current value of, existing proved reserves since the computations are based on a large number of estimates and arbitrary assumptions. Reserve quantities cannot be measured with precision and their estimation requires many judgmental determinations and frequent revisions. Actual future prices and costs are likely to be substantially different from the prices and costs utilized in the computation of reported amounts.

 

F-9


Table of Contents
Index to Financial Statements

The following table provides a pro forma roll forward of total proved reserves for the year ended September 30, 2017, as well as pro forma proved developed and proved undeveloped reserves at the beginning and end of the year as if the January 17, 2017 acquisition of Boomer’s Champions Assets and the March 6, 2017 acquisition of each of Bluescape’s and DR/CM’s Champions Assets occurred on October 1, 2016. Specifically, had the acquisitions occurred on October 1, 2016, rather than all of the reserves being proved at the date of acquisitions, certain reserves would have been unproved at such date, but added to our proved reserves through “extensions, discoveries and additions” during the period from the applicable date of acquisition through September 30, 2017. Similarly, had both acquisitions occurred on October 1, 2016, we would have acquired more reserves attributable to the forecasted production between October 1, 2016 and the date of each acquisition, such that our “acquisition” total would be increased with an equal amount reflected as additional “production”.

 

    Year Ended September 30, 2017  
    Company
Historical
    Boomer
acquisition
    Bluescape
DR/CM
acquisition
    Pro Forma
Adjustments (a)
    Pro Forma  
    (MBoe)     (MBoe)     (MBoe)     (MBoe)     (MBoe)  

Proved Developed and Undeveloped Reserves:

         

Beginning of Year

    3,354.6       —         —         —         3,354.6  

Extensions, discoveries and additions

    2,942.5       512.4       530.1       —         3,985.0  

Acquisitions

    5,464.5       —         —         (1,328.1     4,136.4  

Revisions

    2,750.5       183.7       196.0       —         3,130.2  

Production

    (503.5     (35.4     (58.7     —         (597.6

Sales of reserves-in-place

    —         (660.7     (667.4     1,328.1       —    
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

End of Year

    14,008.6       —         —         —         14,008.6  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Proved Developed Reserves:

         

Beginning of Year

    1,719.2       —         —         —         1,719.2  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

End of Year

    8,225.5       —         —         —         8,225.5  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Proved Undeveloped Reserves:

         

Beginning of Year

    1,635.4       —         —         —         1,635.4  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

End of Year

    5,783.1       —         —         —         5,783.1  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

(a) To adjust the amount of purchases of reserves for the Boomer and Bluescape and DR/CM acquisitions already included within the Company’s historical information.

For the year ended September 30, 2017, the Company had upward revisions of previous estimates of 3,130.2 MBoe. These upward revisions are comprised of 2,784.2 MBoe increase attributable to better well performance on new wells that exceeded previous estimates, and 346.0 MBoe is attributable to a decrease in LOE which extended the life of the wells. As a result of ongoing drilling and completion activities during the fiscal year ended in 2017, the Company reported extensions, discoveries, and other additions of 3,985.0 MBoe, which included adding 7 PUD locations based on offset development. Additionally, the Company purchased reserves of 4,136.4 MBoe on October 1, 2016 in connection with the Boomer, Bluescape and DR/CM acquisitions.

 

F-10


Table of Contents
Index to Financial Statements

The following table provides a pro forma roll forward of total proved reserves of crude oil for the year ended September 30, 2017, as well as pro forma proved developed and proved undeveloped reserves at the beginning and end of the year as if the January 2017 acquisition of Boomer and March 2017 acquisition of Bluescape and DR/CM occurred on October 1, 2016.

 

     Company
Historical
    Boomer
acquisition
    Bluescape
DR/CM
acquisition
    Pro Forma
Adjustments
(a)
    Pro
Forma
 
     Crude Oil
Mbbls
    Crude Oil
Mbbls
    Crude Oil
Mbbls
    Crude Oil
Mbbls
    Crude Oil
Mbbls
 

Proved developed and undeveloped reserves:

          

Beginning of Year

     2,904.3       —         —         —         2,904.3  

Extensions, discoveries and additions

     2,575.4       444.0       459.0       —         3,478.4  

Acquisitions

     4,732.2       —         —         (826.7     3,905.5  

Revisions

     2,283.5       2.3       6.5       —         2,292.3  

Production

     (469.5     (31.9     (53.2     —         (554.6

Sales of reserves-in-place

     —         (414.4     (412.3     826.7       —    
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

End of Year

     12,025.9       —         —         —         12,025.9  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Proved developed reserves:

          

Beginning of Year

     1,484.4       —         —         —         1,484.4  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

End of Year

     7,064.4       —         —         —         7,064.4  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Proved undeveloped reserves:

          

Beginning of Year

     1,419.9       —         —         —         1,419.9  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

End of Year

     4,961.4       —         —         —         4,961.4  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

 

(a)

To adjust the amount of purchases of reserves for the Boomer and Bluescape and DR/CM acquisitions already included within the Company’s historical information.

 

F-11


Table of Contents
Index to Financial Statements

The following table provides a pro forma roll forward of total proved reserves of natural gas for the year ended September 30, 2017, as well as pro forma proved developed and proved undeveloped reserves at the beginning and end of the year as if the January 2017 acquisition of Boomer and March 2017 acquisition of Bluescape and DR/CM occurred on October 1, 2016.

 

     Company
Historical
    Boomer
acquisition
    Bluescape
DR/CM
acquisition
    Pro Forma
Adjustments
(a)
    Pro Forma  
     Natural Gas
MMcf
    Natural Gas
MMcf
    Natural Gas
MMcf
    Natural Gas
MMcf
    Natural Gas
MMcf
 

Proved developed and undeveloped reserves:

          

Beginning of Year

     1,030.8       —         —         —         1,030.8  

Extensions, discoveries and additions

     967.8       157.8       164.4       —         1,290.0  

Acquisitions

     1,677.0       —         —         (292.2     1,384.8  

Revisions

     1,222.2       0.6       (2.4     —         1,220.4  

Production

     (77.4     (11.4     (16.8     —         (105.6

Sales of reserves-in-place

     —         (147.0     (145.2     292.2       —    

End of Year

     4,820.4       —         —         —         4,820.4  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Proved developed reserves:

          

Beginning of Year

     537.2       —         —         —         537.2  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

End of Year

     2,814.4       —         —         —         2,814.4  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Proved undeveloped reserves:

          

Beginning of Year

     493.6       —         —         —         493.6  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

End of Year

     2,006.2       —         —         —         2,006.2  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

 

(a)

To adjust the amount of purchases of reserves for the Boomer and Bluescape and DR/CM acquisitions already included within the Company’s historical information.

 

F-12


Table of Contents
Index to Financial Statements

The following table provides a pro forma roll forward of total proved reserves of NGL for the year ended September 30, 2017, as well as pro forma proved developed and proved undeveloped reserves at the beginning and end of the year as if the January 2017 acquisition of Boomer and March 2017 acquisition of Bluescape and DR/CM occurred on October 1, 2016.

 

     Company
Historical
    Boomer
acquisition
    Bluescape
DR/CM
acquisition
    Pro Forma
Adjustments
(a)
    Pro
Forma
 
     NGL
Mbbls
    NGL
Mbbls
    NGL
Mbbls
    NGL
Mbbls
    NGL
Mbbls
 

Proved developed and undeveloped reserves:

          

Beginning of Year

     278.5       —         —         —         278.5  

Extensions, discoveries and additions

     205.8       42.1       43.7       —         291.6  

Acquisitions

     452.8       —         —         (452.7     0.1  

Revisions

     263.3       181.3       189.9       —         634.5  

Production

     (21.1     (1.6     (2.7     —         (25.4

Sales of reserves-in-place

     —         (221.8     (230.9     452.7       —    

End of Year

     1,179.3       —         —         —         1,179.3  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Proved developed reserves:

          

Beginning of Year

     145.1       —         —         —         145.1  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

End of Year

     692.1       —         —         —         692.1  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Proved undeveloped reserves:

          

Beginning of Year

     133.4       —         —         —         133.4  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

End of Year

     487.2       —         —         —         487.2  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

 

(a)

To adjust the amount of purchases of reserves for the Boomer and Bluescape and DR/CM acquisitions already included within the Company’s historical information.

The pro forma standardized measure of discounted estimated future net cash flows was as follows as of September 30, 2017 (in thousands):

 

     Company
Historical
    Corporate
Conversion (a)
    Pro Forma (b)  

Future crude oil, natural and NGL Sales

   $ 562,349     $ —       $ 562,349  

Future production costs

     (156,563     —         (156,563

Future development costs

     (42,849     —         (42,849

Future income tax expense

     (2,953     (76,091     (79,044
  

 

 

   

 

 

   

 

 

 

Future net cash flows

     359,984       (76,091     283,893  

10% annual discount

     (216,797     47,261       (169,536
  

 

 

   

 

 

   

 

 

 

Standardized measure of discounted future net cash flows

   $ 143,187     $ (28,830   $ 114,357  
  

 

 

   

 

 

   

 

 

 

 

(a)

Represents an adjustment to include future tax expense associated with the Corporate Conversion.

(b)

The pro forma standardized measure includes the Boomer, Bluescape and DR/CM acquisitions.

 

F-13


Table of Contents
Index to Financial Statements

The changes in the pro forma standardized measure of discounted estimated future net cash flows were as follows for the year ended September 30, 2017 (in thousands):

 

    Company
Historical
    Boomer
Acquisition
    Bluescape
DR/CM
Acquisition
    Corporate
Conversion (a)
    Pro forma
Adjustments (b)
    Pro forma  

Balance at beginning of period

  $ 19,124     $ —       $ —       $ —       $ —       $ 19,124  

Sales of crude oil, natural gas and natural gas liquids, net

    (14,806     (1,411     (2,301     —         —         (18,518

Net change in prices and production costs

    18,074       282       2,797       —         —         21,153  

Net change in future development costs

    (1,307     67       491       —         —         (749

Extensions, discoveries, and other additions

    29,241       3,938       4,692       —         —         37,871  

Acquisition of reserves

    43,718       —         —         —         (16,217     27,501  

Revisions of previous quantity estimates

    28,676       1,293       1,750       —         —         31,719  

Previously estimated development costs incurred

    4,491       112       117       —         —         4,720  

Net change in income taxes

    81       (47     (80     (28,830     —         (28,876

Accretion of discount

    4,792       334       583       —         —         5,709  

Sales of reserves-in-place

    —         (5,419     (10,798     —         16,217       —    

Other

    11,103       851       2,749       —         —         14,703  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Balance at end of period

  $ 143,187     $ —       $ —       $ (28,830   $ —       $ 114,357  

 

(a)

Represents an adjustment to reflect the Corporate Conversion into a taxable entity.

(b)

To adjust the amount of acquisition of reserves for the Boomer and Bluescape and DR/CM acquisitions already included within the Company’s historical information.

 

F-14


Table of Contents
Index to Financial Statements

Riley Exploration—Permian, LLC

Condensed Consolidated Balance Sheets

(Unaudited)

 

     June 30,      September 30,  
     2018      2017  
     (in Thousands)  

Assets

     

Current assets:

     

Cash and cash equivalents

   $ 1,029      $ 3,683  

Accounts receivable

     7,174        4,819  

Other accounts receivable

     9        144  

Prepaid expenses and other current assets

     372        184  
  

 

 

    

 

 

 

Total current assets

     8,584        8,830  

Non-current assets:

     

Oil and natural gas properties, net (successful efforts)

     227,914        167,739  

Other property and equipment, net

     1,843        1,870  

Other non-current asset

     3,792        693  
  

 

 

    

 

 

 

Total non-current assets

     233,549        170,302  
  

 

 

    

 

 

 

Total assets

   $ 242,133      $ 179,132  
  

 

 

    

 

 

 

Liabilities and Members’ Equity

     

Current liabilities:

     

Accounts payable

   $ 5,448      $ 7,034  

Accrued liabilities

     19,474        5,303  

Revenue payable

     4,098        2,338  

Advances from joint interest owners

     534        48  

Notes payable - current

     113        115  

Derivative liabilities

     8,907        1,139  
  

 

 

    

 

 

 

Total current liabilities

     38,574        15,977  

Notes payable - non-current

     —          103  

Non-current derivative liabilities

     1,753        484  

Asset retirement obligations

     826        76  

Revolving credit facility

     44,000        —    
  

 

 

    

 

 

 

Total liabilities

     85,153        16,640  

Series A Preferred Units

     52,739        49,823  

Members’ equity:

     

Members’ equity

     104,241        112,669  
  

 

 

    

 

 

 

Total members’ equity

     104,241        112,669  
  

 

 

    

 

 

 

Total liabilities and members’ equity

   $ 242,133      $ 179,132  
  

 

 

    

 

 

 

See accompanying notes to condensed consolidated financial statements.

 

F-15


Table of Contents
Index to Financial Statements

Riley Exploration—Permian, LLC

Condensed Consolidated Statements of Operations

(Unaudited)

 

    

Nine Months Ended

June 30,

 
     2018     2017  
     (in Thousands, except per unit
and per share amounts)
 

Revenues:

  

Oil sales

   $ 46,438     $ 11,360  

Natural gas sales

     252       135  

Natural gas liquids sales

     909       262  
  

 

 

   

 

 

 

Total revenues

     47,599       11,757  

Operating expenses:

    

Lease operating expenses

     8,135       3,831  

Production taxes

     2,191       641  

Exploration costs

     5,523       1,107  

Depletion, depreciation, amortization and accretion

     11,388       3,268  

General administrative expenses

     10,596       4,616  

Transaction costs

     790       1,233  
  

 

 

   

 

 

 

Total operating expenses

     38,623       14,696  
  

 

 

   

 

 

 

Income (loss) from operations

   $ 8,976     $ (2,939

Other expenses:

    

Interest expense

     (907     —    

Gain/(loss) on derivatives

     (13,895     752  
  

 

 

   

 

 

 

Loss before income tax provision

   $ (5,826   $ (2,187

Income tax expense

     —         —    
  

 

 

   

 

 

 

Net loss

   $ (5,826   $ (2,187

Dividends on preferred units

     (2,327     (772
  

 

 

   

 

 

 

Net loss attributable to common units

   $ (8,153   $ (2,959
  

 

 

   

 

 

 

Net loss per common unit

   $ (5.44   $ (2.86

Weighted average common units outstanding

     1,500       1,034  

Pro forma information (unaudited)

    

Loss before income tax benefit

   $ (5,826   $ (2,187

Pro forma income tax benefit

     1,375       735  
  

 

 

   

 

 

 

Pro forma net loss

   $ (4,451   $ (1,452
  

 

 

   

 

 

 

Pro forma net loss per common share

    

Weighted average pro forma common shares outstanding

    

See accompanying notes to condensed consolidated financial statements.

 

F-16


Table of Contents
Index to Financial Statements

Riley Exploration—Permian, LLC

Condensed Consolidated Statements of Changes in Members’ Equity

(Unaudited)

(in Thousands)

 

     Common Units      Amount  

Balance, September 30, 2017

     1,500      $ 112,669  

Distribution to REG

     —          (275

Dividends on preferred units

     —          (2,327

Net loss, nine months ended June 30, 2018

     —          (5,826
  

 

 

    

 

 

 

Balance, June 30, 2018

     1,500      $ 104,241  
  

 

 

    

 

 

 

See accompanying notes to condensed consolidated financial statements.

 

F-17


Table of Contents
Index to Financial Statements

Riley Exploration—Permian, LLC

Condensed Consolidated Statements of Cash Flows

(Unaudited)

 

    

Nine Months Ended

June 30,

 
     2018     2017  
     (in Thousands)  

Cash flows from operating activities:

    

Net loss

   $ (5,826   $ (2,187

Adjustments to reconcile net loss to net cash (used in) provided by operating activities:

    

Expired leases

     5,368       1,088  

Depletion, depreciation, amortization and accretion

     11,388       3,268  

(Gain)/loss on derivative contracts

     13,895       (752

Cash settlements on derivative contracts

     (4,859     92  

Amortization of deferred financing costs

     200       —    

Changes in operating assets and liabilities

    

Accounts receivable

     (2,220     (986

Other non-current assets

     (1,995     28  

Prepaid expenses and other current assets

     (188     (30

Accounts payable and accrued liabilities

     4,084       (1,689

Revenue payable

     1,760       —    

Advances from other joint interest owners

     486       797  
  

 

 

   

 

 

 

Net cash (used in) provided by operating activities

     22,093       (371

Cash flows from investing activities:

    

Additions to oil and natural gas properties

     (47,580     (38,124

Acquisition of oil and natural gas properties

     (19,683     —    

Additions to other property and equipment

     (181     (1,495
  

 

 

   

 

 

 

Net cash used in investing activities

     (67,444     (39,619

Cash flows from financing activities:

    

Additional issuance costs of Series A Preferred Units

     (30     —    

Proceeds from issuance of Series A Preferred Units-net

     —         40,000  

Net investment from parent

     —         5,210  

Distribution to REG

     (275     —    

Net proceeds from revolving credit facility

     43,107       —    

Payments of notes payable

     (105     —    
  

 

 

   

 

 

 

Net cash provided by financing activities

     42,697       45,210  

Net increase (decrease) in cash and cash equivalents

     (2,654     5,220  

Cash and cash equivalents, beginning of period

     3,683       —    
  

 

 

   

 

 

 

Cash and cash equivalents, end of period

   $ 1,029     $ 5,220  
  

 

 

   

 

 

 

Supplemental disclosure of cash flow information

    

Cash paid for:

    

Interest

   $ 562     $ —    

Noncash investing and financing activities:

    

Changes in accrued capital expenditures

   $ 9,120     $ 866  

Changes in asset retirement obligations incurred

     742       18  

Preferred unit dividends paid in kind

     2,946       —    

Accrued preferred unit dividends

     2,327       772  

Contribution of net assets in exchange for common units

     —         82,379  

See accompanying notes to condensed consolidated financial statements.

 

F-18


Table of Contents
Index to Financial Statements

Riley Exploration—Permian, LLC

Notes to Condensed Consolidated Financial Statements

(Amounts in Thousands, except for common and preferred units)

1. Nature of Business and Organization

Riley Exploration-Permian, LLC (“Riley Permian” or “Company”) is an independent energy company focused on the acquisition, development and production of unconventional oil and natural gas reserves. The Company was initially formed as Riley Exploration-Permian, Inc., a wholly-owned subsidiary of Riley Exploration Group, Inc. (“REG”) in June 2016. On August 8, 2016, Riley Exploration-Permian, Inc. was converted to a limited liability company, Riley Permian. The Company owns producing wells and undeveloped acreage in Yoakum County, Texas. The Company also owns and operates waste water gathering and disposal facilities and electricity grid facilities providing power to its wells.

REG is an independent energy company focused on the acquisition, development and production of unconventional oil and natural gas resources. On April 30, 2015, REG acquired a 32% working interest in oil and natural gas properties, substantially all of which were unproved, in Yoakum County, Texas (the “Champions Assets”) that targets the horizontal San Andres play in the Permian Basin. Concurrent with acquisition of its working interest in the Champions Assets, REG, Boomer Petroleum, LLC (“Boomer”), Dernick Encore, LLC (“Dernick Encore”), Murfin Drilling Company, Inc. (“Murfin”) and Pacesetter Energy Permian Basin, LLC (“Pacesetter”), collectively referred to as the “Original AMI Partners”, entered into a joint exploration agreement to establish an area of mutual interest for exploration and development, which is referred to herein as the “Champions AMI”. The Original AMI Partners also entered into a joint operating agreement with Riley Exploration Operating Company, LLC (“REOC”), a wholly-owned subsidiary of REG, to operate substantially all of the Champions AMI. REOC continued to operate the Champions Assets until May 31, 2017, at which time operation responsibilities were transferred to Riley Permian Operating Company LLC (“RPOC”), a wholly-owned subsidiary of Riley Permian. 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.

In June 2016, REG formed the Company as a subsidiary owning 100% of its membership interests. On January 17, 2017, Boomer contributed its 28% working interest in oil and natural gas properties and related assets of the Champions Assets to the Company in exchange for 360,000 common units in the Company and REG’s 100% membership interest in the Company was reclassified into 573,408 common units in the Company.

On March 6, 2017, each of Bluescape Riley Exploration Acquisition, LLC (“Bluescape”) and DR/CM contributed their combined 29.3% working interest in oil and natural gas properties and related assets of the Champions Assets, respectively, in exchange for 499,092 and 67,500 common units in the Company, respectively.

Upon completion of all contribution transactions, Riley Permian held an 89.3% working interest in the Champions Assets.

2. Basis of Presentation

The unaudited condensed consolidated financial statements include the accounts of Riley Permian and its wholly-owned subsidiary RPOC and have been prepared in accordance with accounting principles generally accepted in the United States (“U.S. GAAP”) and the Securities and Exchange Commission rules and regulations for interim financial reporting. Therefore, they do not include all of the information and footnotes required by generally accepted accounting principles for complete financial statements. These unaudited condensed consolidated financial statements should be read in conjunction with our audited financial statements and footnotes for the years ended September 30, 2017 and 2016 included in this prospectus. All intercompany balances and transactions have been eliminated upon consolidation. In the opinion of management, all adjustments, consisting primarily of normal recurring accruals that are considered necessary for a fair presentation of the condensed

 

F-19


Table of Contents
Index to Financial Statements

consolidated financial statements, have been included. However, operating results for the period presented are not necessarily indicative of the results that may be expected for a full year.

For the periods prior to January 17, 2017, the accompanying unaudited condensed consolidated 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 and costs and expenses. The financial statements may not be indicative of the future performance of the Company and may not necessarily reflect what the results of operations, financial position and cash flows would have been had the Champions Assets been operated as an independent company for periods prior to January 17, 2017.

The accompanying condensed consolidated financial statements for the nine months ended June 30, 2017 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 the Company 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. Following the contribution date, the Company incurred these expenses on a stand-alone basis.

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 presented the historical operations of the contributed business on a retrospective basis for all periods presented. 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 their respective contributions.

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. These allocations may not, however, reflect the expenses the Company would have actually incurred for the periods presented. Actual costs that may have been incurred if the Company had been a stand-alone entity would depend on a number of factors, including the organizational structure, whether functions were outsourced or performed by employees and strategic decisions made in areas such as information technology and infrastructure.

3. Summary of Significant Accounting Policies

The significant accounting policies followed by the Company are set forth in Note 3 to the Company’s audited consolidated financial statements for the years ended September 30, 2017 and 2016 and are supplemented by the notes to the unaudited condensed consolidated financial statements herein. These unaudited condensed consolidated financial statements should be read in conjunction with the audited consolidated financial statements and notes included in this prospectus.

Transaction Costs

During the nine months ended June 30, 2018, the Company incurred $790 of transaction costs related to attempted acquisitions that did not occur. During the nine months ended June 30, 2017, the Company incurred $1,233 of transaction costs related to the contributions of oil and gas properties.

Unaudited Pro Forma Income Taxes

These financial statements have been prepared in anticipation of a proposed initial public offering (the “Offering”) of the common stock of Riley Exploration Permian, Inc. In connection with the Offering the Company will convert from a Delaware limited liability company into a Delaware corporation, which will be taxed as a corporation under the Internal Revenue Code of 1986, as amended. Accordingly, a pro forma income

 

F-20


Table of Contents
Index to Financial Statements

tax impact for the nine months ended June 30, 2018 and 2017 has been disclosed as if the Company was a taxable corporation. The Company has computed pro forma entity-level income tax impact using an estimated income tax rate of 23.6% and 33.6% for the nine months ended June 30, 2018 and 2017, respectively, based on the U.S. Federal income tax rate during those periods.

The Tax Cuts and Jobs Act, which was enacted on December 22, 2017, reduced the corporate income tax rate effective January 1, 2018 to 21%. A charge to establish deferred tax liabilities associated with the converting to a taxable entity will be recognized in the period in which the change in the tax status occurs but has not been reflected within the pro forma income taxes on the Company’s condensed consolidated statements of operations.

Unaudited Pro Forma Earnings Per Share

The Company has presented pro forma earnings per share for the nine months ended June 30, 2018 and 2017. Pro forma basic and diluted income per share was computed by dividing pro forma net income attributable to the Company by the number of shares of common stock to be issued in the Corporate Conversion, in which all Series A Preferred Units and the common units are to be converted into common stock, as if such shares were issued and outstanding for the nine months ended June 30, 2018. The weighted average pro forma common shares outstanding for the nine months ended June 30, 2017 reflects the exchange ratio for the number of shares of common stock to be issued in the Corporate Conversion as if the preferred units were converted into common stock as of the date the preferred units were issued.

New Accounting Pronouncements

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. The amendments in ASU 2017-01 are effective for public business entities for fiscal years beginning after December 15, 2017, and interim periods within those periods. As an emerging growth company, the Company will not be required to adopt this ASU until October 1, 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 acquisition from Rockcliff Operating New Mexico LLC and has accounted for the transaction as an asset acquisition. See Note 4 – Acquisitions for further detail.

4. Acquisitions

On January 17, 2017, Boomer contributed their 28% working interest in oil and natural gas properties and related assets and liabilities of the Champions Assets to the Company for 360,000 common units of the Company. On March 6, 2017, Bluescape and DR/CM contributed their combined 29.3% working interest in oil and natural gas properties and related assets and liabilities of the Champions Assets to the Company for 499,092 and 67,500 common units, respectively of the Company. The net assets contributed were recorded at their fair values at the dates of their respective contributions as summarized below:

 

     Boomer      Bluescape and
DR/CM
     Total  

Oil & gas properties:

        

Proved

   $ 26,962      $ 26,590      $ 53,552  

Unproved

     17,695        17,075        34,770  
  

 

 

    

 

 

    

 

 

 
     $44,657      $43,665      $88,322  

Revenue receivables

     1,411        2,408        3,819  

JIB payables

     (4,336      (5,393      (9,729

ARO liability

     (16      (17      (33
  

 

 

    

 

 

    

 

 

 

Net assets contributed

   $ 41,716      $ 40,663      $ 82,379  
  

 

 

    

 

 

    

 

 

 

 

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Pro Forma Financial Information (Unaudited)

The following unaudited pro forma financial information represents the combined results of the Company and working interests acquired from Boomer, Bluescape and DR/CM as if the acquisitions had occurred as of October 1, 2016.

The pro forma results reflect the results of combining our condensed consolidated results of operations with the revenues and direct operating expenses of the working interests acquired from Boomer and DR/CM and adjusted for the depletion expense applied to the adjusted basis of the oil and gas properties. The pro forma results do not include any cost savings or other synergies that may have resulted from the acquisition or any costs incurred by the Company to integrate the contributed properties. The pro forma results for the nine months ended June 30, 2017 are not necessarily indicative of what actually would have occurred if the contributions had been completed as of October 1, 2016 nor are they necessarily indicative of future results, including the effect of the Corporate Conversion or the conversion of the Series A Preferred Units.

 

     Nine Months Ended  
   June 30, 2017  
     (in Thousands,
except per unit
amounts)
 

Revenues

   $ 15,863  

Net loss

     (1,082

Net loss attributable to common units

     (1,854

Loss per common unit (Basic and Diluted)

   $ (1.79

The amount of revenues in excess of direct operating expenses included in the Company’s consolidated statements of operations for the nine months ended June 30, 2017 for the Boomer and Bluescape / DR/CM acquisitions are shown in the table below. Direct operating expenses include lease operating expenses and production and ad valorem taxes:

 

     For the Nine Months
Ended

June 30, 2017
 

Revenues

   $ 4,984  

Excess of revenues over direct operating expenses

     3,185  

On May 15, 2018, we closed on an acquisition that included a total of 44,133 net mineral acres (unaudited) in Chaves, Lea, and Roosevelt Counties, New Mexico, 12 total wells, only 1 of which was producing, including a salt water disposal well, and associated gathering lines 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 effective date of the transaction is April 1, 2018. The transaction was accounted for as an asset acquisition in accordance with ASU 2017-01, therefore, the acquisition was recorded based on the consideration paid, with value assigned to unproved and proved oil and natural gas properties and ARO. As of June 30, 2018, the acquisition resulted in additional ARO liability of $534.

5. Accounts Receivable

Accounts receivable are reviewed periodically and the carrying amount is reduced by a valuation allowance that reflects the best estimate of the amount that may not be collectible. No allowance for uncollectible amounts was required as of June 30, 2018 and September 30, 2017, respectively.

 

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Accounts receivable is summarized below:

 

     As of June 30,      As of September 30,  
     2018      2017  
     (unaudited)         

Oil and natural gas sales

   $ 6,867      $ 3,801  

Joint interest accounts receivable

     307        1,018  
  

 

 

    

 

 

 

Total accounts receivable

   $ 7,174      $ 4,819  
  

 

 

    

 

 

 

6. Oil and Natural Gas Properties, Other Property and Equipment

Oil and natural gas properties are summarized below:

 

     As of June 30,      As of September 30,  
     2018      2017  
     (unaudited)         

Unproved properties

   $ 46,968      $ 41,862  

Proved properties

     193,914        114,849  

Work-in-progress

     5,350        18,174  
  

 

 

    

 

 

 
     246,232      174,885  

Accumulated depletion and amortization

     (18,318      (7,146
  

 

 

    

 

 

 

Net oil and natural gas properties

   $ 227,914      $ 167,739  
  

 

 

    

 

 

 

Depletion and amortization expenses for proved oil and natural gas properties for the nine months ended June 30, 2018 and 2017 were $11,172 and $3,216, respectively.

Impairment of Oil and Natural Gas Properties

Based on our analysis, no impairments occurred during the nine months ended June 30, 2018 or 2017.

Other Property and Equipment, net

Depreciation expense for other property and equipment amounted to $208 and $35 for the nine months ended June 30, 2018 and 2017, respectively. Capitalized costs related to leasehold improvements are depreciated over the life of the lease.

7. Other Non-Current Assets

Other non-current assets consisted of the following:

 

     As of June 30,      As of September 30,  
     2018      2017  
     (unaudited)         

Deferred credit facility costs

   $ 1,376      $ 683  

Deferred IPO costs

     1,975        —    

Prepayments to outside operators

     250        —    

Title defect escrow deposit

     161        —    

Other deposits

     30        10  
  

 

 

    

 

 

 

Total other non-current assets

   $ 3,792      $ 693  
  

 

 

    

 

 

 

 

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8. Accrued Liabilities

Accrued liabilities consisted of the following:

 

     As of June 30,      As of September 30,  
     2018      2017  
     (unaudited)         

Accrued capital expenditures

   $ 11,181      $ 2,061  

Accrued dividends on preferred units

     790        1,409  

Accrued lease operating expenses

     1,239        748  

Accrued general administrative expenses

     6,025        911  

Accrued interest expense

     144        —    

Accrued ad valorem tax

     84        139  

Other accrued expenditures

     11        35  
  

 

 

    

 

 

 

Total accrued liabilities

   $ 19,474      $ 5,303  
  

 

 

    

 

 

 

Accrued general administrative expenses as of June 30, 2018 includes a one-time incentive compensation bonus to certain executives of $4,000 that was fully earned on June 26, 2018 and is payable in cash or Company units at the Board’s discretion upon a successful completion of this offering or January 2, 2019, whichever occurs first.

9. Asset Retirement Obligations

The following table reflects the changes in the ARO during the nine months ended June 30, 2018 and year ended September 30, 2017:

 

     As of June 30,      As of September 30,  
     2018      2017  
     (unaudited)         

ARO, beginning balance

   $ 76      $ 21  

Liabilities incurred

     208        19  

Liabilities acquired

     534        —    

Liabilities contributed

     —          33  

Accretion

     8        3  
  

 

 

    

 

 

 

ARO, ending balance

   $ 826      $ 76  
  

 

 

    

 

 

 

10. Derivative Contracts

As of June 30, 2018 and September 30, 2017, the Company had $10,660 and $1,623 of derivative liabilities, respectively.

Balance Sheet Presentation. The following table presents the location and fair value of Riley Permian’s derivative contracts included in the accompanying condensed consolidated balance sheets as of June 30, 2018 and September 30, 2017:

 

     As of June 30,
2018
     As of September 30,
2017
 
     (unaudited)         

Balance sheet location

     

Derivative liabilities

   $ 8,907      $ 1,139  

Non-current derivative liabilities

     1,753        484  
  

 

 

    

 

 

 

Total

   $ 10,660      $ 1,623  
  

 

 

    

 

 

 

 

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Gains and Losses. The following table presents the cash settlements and mark-to-market (“MTM”) gains and losses presented as a gain or loss on derivatives in the condensed consolidated statements of operations for the nine months ended June 30, 2018 and 2017:

 

     Nine Months Ended June 30,  
         2018              2017      
     (unaudited)         

Gain/(loss) on settled derivatives

   $ (4,859    $ 92  

Gain/(loss) on unsettled derivatives

     (9,036      660  
  

 

 

    

 

 

 

Total gain/(loss) on derivative contracts

   $ (13,895    $ 752  
  

 

 

    

 

 

 

For the nine months ended June 30, 2018 and 2017, Riley Permian had not designated its derivative contracts as hedges for accounting purposes. Cash settlements of contracts are included in cash flows from operating activities in the condensed consolidated statement of cash flows. Derivative contracts are settled on a monthly basis.

The following table summarizes the open financial derivative positions as of June 30, 2018 related to crude oil production:

 

     2018      2019      2020  

Crude Oil Price Swaps:

        

Notional volume (Bbl)

     345,100        448,500        —    

Weighted average fixed price ($/Bbl)

   $ 54.51      $ 53.85        —    

Crude Oil Option Contracts:

        

Call Options Sold

        

Notional volume (Bbl)

     —          —          6,000  

Weighted average fixed price ($/Bbl)

   $ —        $ —        $ 58.68  

Put Options Purchased

        

Notional volume (Bbl)

     —          —          6,000  

Weighted average fixed price ($/Bbl)

   $ —        $ —        $ 50.00  

11. Transactions with Related Parties

The Original AMI Partners entered into a joint exploration agreement to establish the Champions AMI, and also entered into a joint operating agreement with REOC, an affiliate of REG, to operate substantially all of the Champions AMI. Prior to May 2017, the Company had no employees. 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. As of June 30, 2018 and September 30, 2017, Riley Permian did not owe REOC any amounts under the joint operating agreement.

Oakspring option

Pursuant to a purchase and sale agreement dated September 1, 2017, REG sold its fifty percent (50%) interest to Oakspring Energy Holdings, LLC (“Oakspring”), resulting in Oakspring owning a one hundred percent (100%) interest, in approximately 16,000 gross acres (unaudited) in the “Saddle Tramp” and “Eagle Eye” prospects, which are located in Lea County, New Mexico (collectively, the “Kachina Assets”). Oakspring is a portfolio company of Yorktown Partners, certain managed funds of which have investments in REG and Riley Permian (all deemed to be related parties).

In October 2017, Oakspring, REG and Riley Permian entered into an option agreement (the “Option”), pursuant to which Riley Permian would have the right to purchase a fifty percent (50%) interest in the Kachina Assets

 

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Index to Financial Statements

from Oakspring. In connection with services performed by REG to structure, negotiate and document the Option on behalf of Riley Permian, Riley Permian paid REG $275 as an option fee in October 2017. The Company recorded the option at REG’s historical basis, which was $0, therefore the amount paid to REG was recorded as a reduction to members’ equity during the first three months of fiscal 2018. The Company had until March 31, 2018 to exercise the option to purchase the Kachina Assets from Oakspring.

On March 20, 2018, the Company elected not to exercise the Oakspring option.

12. Revolving Credit Facility

On September 28, 2017, the Company and SunTrust Robinson Humphrey, Inc., as lead arranger and administrative agent, entered a $500 million revolving credit facility. The senior secured revolving credit facility had an initial borrowing base of $25 million. The revolving credit facility matures on September 28, 2021 and is secured by substantially all the Company’s assets.

Effective February 27, 2018, we amended our credit facility to increase the borrowing base from $25 million to $60 million.

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.

The borrowing base is subject to periodic redeterminations, mandatory reductions and further adjustments from time to time. The facility requires quarterly redetermination of the borrowing base on November 1, 2017, February 1, 2018, May 1, 2018 and August 1, 2018, and semi-annually on February 1 and August 1 beginning on February 1, 2019. During these redetermination periods, the Company’s borrowing base may be increased and may also be reduced in certain circumstances. The revolving credit facility allows for Eurodollar Loans and Base Rate Loans (each as defined in the credit agreement). The interest rate on each Eurodollar Loan will be the adjusted LIBOR for the applicable interest period plus a margin between 2.50% and 3.50% (depending on the borrowing base utilization percentage). The annual interest rate on each Base Rate Loan is (a) the greatest of (i) the administrative agent’s prime lending rate, (ii) the federal funds rate plus 0.5% per annum or the (iii) adjusted LIBOR determined on a daily basis for an interest period of one-month, plus 1.00% per annum, plus (b) a margin between 1.50% and 2.50% (depending on the borrowing base utilization percentage). The Company is also subject to an unused commitment fee of between 0.375% and 0.50% (depending on the borrowing base utilization percentage).

The credit agreement contains certain covenants, which, among other things, require the maintenance of (i) a total leverage ratio of not more than 4.0 to 1.0, (ii) a minimum current ratio of 1.0 to 1.0 and (iii) total capital expenditures in an aggregate amount cannot be greater than (a) during the fiscal quarter ending September 30, 2017, $24 million and (b) during the fiscal quarter ending December 31, 2017, $22 million. These covenants expired December 31, 2017. The credit agreement also contains other customary affirmative and negative covenants and events of default.

As of June 30, 2018, the Company was in compliance with all covenants contained in the credit agreement and had $44 million of outstanding borrowings and an additional $56 million available under the revolving credit facility at a weighted average interest rate of 4.81%.

13. Preferred Units

In March of 2017, Riley Permian closed a private offering of convertible preferred securities, or the Series A Preferred Units, to Yorktown Energy Partners XI, L.P. (“Yorktown XI”), Bluescape Riley Exploration Holdings, LLC (“BREH”), and Boomer that resulted in proceeds of approximately $40 million to fund general business purposes. Series A Preferred Units are entitled to distributions at the rate of 6% per annum of the Series A

 

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Index to Financial Statements

outstanding principal amount and shall accrue from day to day, whether or not declared, and shall be cumulative. Dividends on Series A Preferred Units shall be payable in kind by the issuance of additional Series A Preferred Units, however, the Board of Managers may determine in its sole discretion to pay Series A Preferred dividends in cash. The Company shall not declare, pay or set aside any distributions on any other membership interest (other than distributions made to the members for tax distributions pursuant to Section 4.3(b) of the Second Amended and Restated Limited Liability Company dated as of March 6, 2017) without the consent of a majority of the holders of the Series A Preferred Units.

On September 7, 2017, Riley Permian closed a follow-on offering of the Series A Preferred Units to Yorktown XI, BREH and Boomer that resulted in proceeds of $10 million to fund general business purposes.

As disclosed in the “Corporate Conversion”, the outstanding Series A Preferred Units will be converted into shares of common stock of the Company upon closing of the offering.

On December 31, 2022, the Company is required to redeem all the outstanding Series A Preferred Units in cash in an amount equal to the Series A preferred liquidation preference for such Series A Preferred Units on the date of redemption. At any time prior to an IPO and at such holder’s sole discretion, a holder of Series A Preferred Units may elect to convert such Series A Preferred Units to a number of common units in an amount equal to the quotient of (A) 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 Series A conversion price then in effect by the delivery of written notice to the Company. Immediately prior to any conversion, all accrued and undeclared but unpaid dividends on the Series A Preferred Units shall be paid in kind to such holder of Series A Preferred Units electing to convert its units. The Series A Preferred conversion price is $120 per unit, as adjusted to reflect any subdivision, stock split, recapitalization, reclassification or consolidation of the common units.

Immediately following the execution of an underwriting agreement, but prior to the closing of an IPO, all outstanding Series A Preferred Units shall be automatically converted into IPO shares at 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 will result in a deemed preferred distribution to the Series A Preferred Unit holders, which will reduce income attributable to common units in the period in which the conversion occurs.

The holders of the Series A Preferred Units have the same voting rights as if such Series A Preferred Units were converted into common units in accordance with the Series A conversion price then in effect and shall vote with the common units as a single class. The affirmative vote or consent of at least 70% of the outstanding Series A Preferred Units, voting together as a single class, shall be necessary for effecting or validating any amendment, alteration or repeal of the certificate of formation or the Second Amended and Restated Limited Liability Company Agreement, which materially and adversely affects the rights or preferences of the holders of the Series A Preferred Units, issuance or reclassification of membership interests ranking pari passu or senior to the Series A Preferred Units, any transaction between the Company and any of its officers, holders of its units, directors of Affiliates, any increase in indebtedness for money borrowed by the Company, a call for capital contributions from holders of the Series A Preferred Units and any company event in which the holders of the Series A Preferred Units do not receive, upon the consummation of the company event of an amount in cash equal to the greater of (A) the Series A preferred issue amount with respect to each outstanding Series A Preferred Unit, multiplied by 1.35 plus any accrued but unpaid dividends on the Series A Preferred Units as of such date or (B) an amount sufficient to cause the internal rate of return of each Series A Preferred Unit held by such holder to equal 17.5% plus any accrued but unpaid dividends on the Series A Preferred Units. In the event a majority of the outstanding Series A Preferred Units, voting together as a single class, do not approve a company event, the Company may elect to redeem the outstanding Series A Preferred Units in cash.

 

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The following summarizes the change in Series A Preferred Units during the nine months ended June 30, 2018:

 

     Units      Amount  
     (unaudited)  

Balance, September 30, 2017

     416,667      $ 49,823  

Dividends paid in kind

     24,555        2,946  

Deferred financing costs

     —          (30
  

 

 

    

 

 

 

Balance, June 30, 2018

     441,222      $ 52,739  
  

 

 

    

 

 

 

While it was the Company’s intention to pay the accrued Series A Preferred dividends in-kind, this required an increase in the number of authorized Series A Preferred Units which was approved by the Board of Managers on December 27, 2017. Paid in kind dividends accrued since inception through March 31, 2018 totaled $2,946 and were paid during the nine months ended June 30, 2018, through the issuance of 24,555 Series A Preferred Units. At June 30, 2018 and September 30, 2017, the Company had accrued dividends payable on the Series A Preferred Units of $790 and $1,409, respectively, which are currently included in accrued liabilities in the condensed consolidated balance sheet.

In accordance with ASC 480-10-S99 (Distinguishing Liabilities From Equity), equity securities are required to be classified outside of permanent equity in temporary equity if they are redeemable or may become redeemable for cash or other assets. As the Company is not considered to have sole control over the contractually mandated redemption in 2022, the Series A Preferred Units have been classified as mezzanine equity.

14. Members’ Equity

On December 27, 2017, our Board of Managers approved an amendment to our Limited Liability Company Agreement (the LLC Agreement) which authorized the increase in the Common and Series A Preferred Units from 1,804,334 to 2,777,867 units and designated 2,265,200 of the total number of units authorized for issuance as Common Units and 512,667 as Series A Preferred Units. As of June 30, 2018, the Company had 1,500,000 of Common Units and 441,222 Series A Preferred Units outstanding.

15. Earnings (Loss) Per Unit

Basic earnings (loss) per unit is computed by dividing income (loss) attributable to unitholders by the weighted average number of units outstanding during each period. Diluted earnings per unit reflects potential dilutive impact of dilutive securities.

The table below sets forth the computation of basic and diluted net income (loss) per unit for the nine months ended June 30, 2018 and 2017 (in thousands, except per unit data):

 

     Nine Months Ended June 30,  
     2018      2017  
     (unaudited)         

Net loss attributable to common units

   $ (8,153    $ (2,959

Weighted average common units outstanding

     1,500        1,034  

Basic and diluted loss per common unit

   $ (5.44    $ (2.86

As of June 30, 2018, the Company has 441,222 units of Series A Preferred Units outstanding. The Preferred Units are convertible upon the closing of the IPO (see Note 13 Preferred Units). The Company excluded the common unit equivalents of the Series A Preferred Units from the calculation of earnings per unit because the effect of conversion was antidilutive as a result of the net loss for the nine months ended June 30, 2018 and 2017.

 

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16. Commitments and Contingencies

Pursuant to the terms of the definitive agreement between us and REG, any claims, litigation or disputes pending as of the effective date, October 1, 2016, and any matters arising in connection with ownership of the Champions Assets prior to the effective date are retained by REG. Notwithstanding this indemnification, management is not aware of any legal, environmental or other commitments or contingencies that would have a material effect on its business.

Legal Matters. In the ordinary course of business, Riley Permian may at times be subject to claims and legal actions. Riley Permian accrues liabilities when it is probable that future costs will be incurred, and such costs can be reasonably estimated. Such accruals are based on developments to date and Riley Permian’s estimates of the outcomes of these matters. Riley Permian did not recognize any material liabilities as of June 30, 2018 and September 30, 2017. Management believes it is remote that the impact of such matters will have a materially adverse effect on Riley Permian’s financial position, results of operations, or cash flows.

Environmental Matters. Riley Permian is subject to various federal, state and local laws and regulations relating to the protection of the environment. These laws, which are often changing, regulate the discharge of materials into the environment and may require Riley Permian to remove or mitigate the environmental effects of the disposal or release of petroleum or chemical substances at various sites. Riley Permian accounts for environmental contingencies in accordance with the accounting guidance related to accounting for contingencies. Environmental expenditures that relate to current operations are expensed or capitalized as appropriate. Expenditures that relate to an existing condition caused by past operations, which do not contribute to current or future revenue generation, are expensed. Liabilities are recorded when environmental assessments and/or clean-ups are probable, and the costs can be reasonably estimated. As of June 30, 2018 and September 30, 2017, the Company recorded no environmental liabilities.

Leases. Riley Permian leases its office headquarters under a five-year operating lease agreement terminating in July 2022. Base rent for the first year of the lease is $228 annually, with each subsequent year being subject to a two percent (2%) escalation. Additionally, Riley Permian leases certain common office equipment of nominal amounts.

Notes Payable. Riley Permian financed certain vehicles used in field operations. Vehicle notes payable of $113 as of June 30, 2018 are based on 48-month terms beginning in May 2017, with an average interest rate of 4.83%. The notes were paid in full on July 16, 2018.

17. Subsequent Events

We have evaluated subsequent events through August 31, 2018, the date on which these financial statements were issued and there are no further subsequent events to report, other than the following:

Kizer SWD Lightning Strike

On August 8, 2018, a lightning strike destroyed one of the Company’s tank batteries, causing a minimal release of liquids from adjoining oil and water tanks. The cost for site remediation is estimated at $150 and replacement of the tank battery is estimated at $515. The Company notified its insurance carrier and both the site remediation and replacement of the tank battery are fully insured except for a deductible of $20. The Company has been in contact with the New Mexico Oil Conservation Division regarding remediation and has not received any notice of violation or citation.

 

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Report of Independent Registered Public Accounting Firm

Riley Exploration—Permian, LLC

Oklahoma City, Oklahoma

We have audited the accompanying consolidated balance sheets of Riley Exploration—Permian, LLC as of September 30, 2017 and 2016 and the related consolidated statements of operations, changes in parent net investment/members’ equity, and cash flows for each of the two years in the period ended September 30, 2017. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the auditing standards of the Public Company Accounting Oversight Board (United States) and in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Riley Exploration—Permian, LLC at September 30, 2017 and 2016, and the results of its operations and its cash flows for each of the two years in the period ended September 30, 2017, in conformity with accounting principles generally accepted in the United States of America.

/s/ BDO USA, LLP

Houston, Texas

February 9, 2018

 

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Riley Exploration—Permian, LLC

Consolidated Balance Sheets

 

     September 30,      September 30,  
     2017      2016  
     (in Thousands)  

Assets

     

Current assets:

     

Cash and cash equivalents

   $ 3,683      $ —    

Accounts receivable

     4,819        849  

Other accounts receivable

     144        —    

Prepaid expenses and other current assets

     184        28  
  

 

 

    

 

 

 

Total current assets

     8,830        877  

Non-current assets:

     

Oil and natural gas properties, net (successful efforts)

     167,739        42,530  

Other property and equipment, net

     1,870        —    

Other non-current asset

     693        —    
  

 

 

    

 

 

 

Total non-current assets

     170,302        42,530  
  

 

 

    

 

 

 

Total assets

   $ 179,132      $ 43,407  
  

 

 

    

 

 

 

Liabilities and Parent Net Investment/Members’ Equity

     

Current liabilities:

     

Accounts payable

   $ 7,034      $ 202  

Accounts payable—Related Parties

     —          957  

Accrued liabilities

     5,303        4,907  

Revenue payable

     2,338        —    

Advances from joint interest owners

     48        —    

Notes payable—current

     115        —    

Derivative liabilities

     1,139        —    
  

 

 

    

 

 

 

Total current liabilities

     15,977        6,066  

Notes payable—non-current

     103        —    

Non-current derivative liabilities

     484        —    

Asset retirement obligation

     76        21  
  

 

 

    

 

 

 

Total liabilities

     16,640        6,087  

Series A Preferred Units

     49,823        —    

Parent Net Investment/Members’ equity:

     

Parent Net Investment

     —          37,320  

Members’ equity

     112,669        —    
  

 

 

    

 

 

 

Total members’ equity

     112,669        37,320  
  

 

 

    

 

 

 

Total liabilities and members’ equity

   $ 179,132      $ 43,407  
  

 

 

    

 

 

 

See accompanying notes to consolidated financial statements.

 

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Riley Exploration—Permian, LLC

Consolidated Statements of Operations

 

     Years Ended
September 30,
 
     2017     2016  
     (In Thousands except
per unit and per share
amounts)
 

Revenues:

    

Oil sales

   $ 21,174     $ 4,081  

Natural gas sales

     203       29  

Natural gas liquids sales

     431       20  
  

 

 

   

 

 

 

Total revenues

     21,808       4,130  

Operating expenses:

    

Lease operating expenses

     5,796       2,779  

Production taxes

     1,206       194  

Exploration costs

     10,739       45  

Depletion, depreciation, amortization and accretion

     5,876       1,366  

General administrative expenses

     5,806       3,863  

Transaction costs

     1,766       —    
  

 

 

   

 

 

 

Total operating expenses

     31,189       8,247  
  

 

 

   

 

 

 

Loss from operations

   $ (9,381   $ (4,117

Other expenses:

    

Loss on derivatives

     (1,450     —    
  

 

 

   

 

 

 

Loss before income tax provision

     (10,831     (4,117

Income tax expense

     —         9  
  

 

 

   

 

 

 

Net loss

     (10,831     (4,126

Dividends on preferred units

     1,409       —    
  

 

 

   

 

 

 

Net loss attributable to common units

   $ (12,240   $ (4,126
  

 

 

   

 

 

 

Net loss per common unit

   $ (10.63   $ (7.20

Weighted average common units outstanding

     1,151       573  

Pro forma information (unaudited)

    

Loss before income tax benefit

   $ (10,831  

Pro forma income tax benefit

     3,639    
  

 

 

   

Pro forma net loss

   $ (7,192  
  

 

 

   

Pro forma net loss per common share

    

Weighted average pro forma common shares outstanding

    

See accompanying notes to consolidated financial statements.

 

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Riley Exploration—Permian, LLC

Consolidated Statements of Changes in Parent Net Investment/Members’ Equity

(in Thousands)

 

     Members’ Equity              
     Common
Units
     Amount     Parent Net
Investment
    Total  

Balance, September 30, 2015

     —        $ —       $ 8,234     $ 8,234  

Change in parent net investment

     —          —         33,212       33,212  

Net loss, year ended September 30, 2016

     —          —         (4,126     (4,126
  

 

 

    

 

 

   

 

 

   

 

 

 

Balance, September 30, 2016

     —          —       $ 37,320       37,320  

Change in parent net investment

     —          —         5,210       5,210  

Contribution of net assets of REG in exchange for common units

     573        41,574       (41,574     —    

Other contributions of net assets in exchange for common units

     927        82,379       —         82,379  

Dividends on preferred units

        (1,409     —         (1,409

Net loss, year ended September 30, 2017

     —          (9,875     (956     (10,831
  

 

 

    

 

 

   

 

 

   

 

 

 

Balance, September 30, 2017

     1,500      $ 112,669     $ —       $ 112,669  
  

 

 

    

 

 

   

 

 

   

 

 

 

See accompanying notes to consolidated financial statements.

 

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Riley Exploration—Permian, LLC

Consolidated Statements of Cash Flows

 

     For the Years Ended
September 30,
 
     2017     2016  
     (in Thousands )  

Cash flows from operating activities:

    

Net loss

   $ (10,831   $ (4,126

Adjustment to reconcile net loss to net cash (used in) provided by operating activities:

    

Expired leases

     10,719       —    

Depletion, depreciation, amortization and accretion

     5,876       1,366  

Loss on derivative contracts

     1,450       —    

Cash settlements on derivative contracts

     173       —    

Changes in operating assets and liabilities

    

Accounts receivable

     (295     (766

Other non-current assets

     (693     —    

Prepaid expenses and other current assets

     (80     (28

Accounts payable and accrued liabilities

     (5,416     (5,571

Revenue payable

     2,338       —    

Advances from other joint interest owners

     48       —    
  

 

 

   

 

 

 

Net cash (used in) provided by operating activities

     3,289       (9,125

Cash flows from investing activities:

    

Acquisition of oil and natural gas properties

     (200     (14,021

Additions to oil and natural gas properties

     (52,613     (10,066

Additions to other property and equipment

     (1,968     —    
  

 

 

   

 

 

 

Net cash used in investing activities

     (54,781     (24,087

Cash flows from financing activities:

    

Proceeds from issuance of Series A Preferred Units-net

     49,823       —    

Net investment by parent

     5,210       33,212  

Proceeds from notes payable

     154       —    

Payments of notes payable

     (12     —    
  

 

 

   

 

 

 

Net cash provided by financing activities

     55,175       33,212  

Net increase (decrease) in cash and cash equivalents

     3,683       —    

Cash and cash equivalents, beginning of period

     —         —    
  

 

 

   

 

 

 

Cash and cash equivalents, end of period

   $ 3,683     $ —    
  

 

 

   

 

 

 

Supplemental disclosure of cash flow information

    

Cash paid for:

    

Interest

   $ 3     $ —    

Income taxes

     —         —    

Noncash investing and financing activities:

    

Changes in accrued capital expenditures

     549       1,657  

Changes in asset retirement obligations incurred

     19       10  

Accrued preferred unit dividends

     1,409       —    

Contribution of net assets in exchange for common units

     82,379       —    

See accompanying notes to consolidated financial statements.

 

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Riley Exploration—Permian, LLC

Notes to Consolidated Financial Statements

(Amounts in Thousands, except for common and preferred units)

1. Nature of Business and Organization

Riley Exploration-Permian, LLC (“Riley Permian” or “Company”) is an independent energy company focused on the acquisition, development and production of unconventional oil and natural gas reserves. The Company was initially formed as Riley Exploration-Permian, Inc., a wholly-owned subsidiary of Riley Exploration Group, Inc. (“REG”) in June 2016. On August 8, 2016, Riley Exploration-Permian, Inc. was converted to a limited liability company, Riley Permian. The Company owns producing wells and undeveloped acreage in Yoakum County, Texas. The Company also owns and operates waste water gathering and disposal facilities and electricity grid facilities providing power to its wells.

REG is an independent energy company focused on the acquisition, development and production of unconventional oil and natural gas resources. On April 30, 2015, REG acquired a 32% working interest in oil and natural gas properties, substantially all of which were unproved, in Yoakum County, Texas (the “Champions Assets”) that targets the horizontal San Andres play in the Permian Basin. Concurrent with acquisition of its working interest in the Champions Assets, REG, Boomer Petroleum, LLC (“Boomer”), Dernick Encore, LLC (“Dernick Encore”), Murfin Drilling Company, Inc. (“Murfin”) and Pacesetter Energy Permian Basin, LLC (“Pacesetter”), collectively referred to as the “Original AMI Partners”, entered into a joint exploration agreement to establish an area of mutual interest for exploration and development, which is referred to herein as the “Champions AMI”. The Original AMI Partners also entered into a joint operating agreement with Riley Exploration Operating Company, LLC (“REOC”), a wholly-owned subsidiary of REG, to operate substantially all of the Champions AMI.

On December 31, 2015, REG acquired Murfin’s approximately 3% working interest, and on January 22, 2016 acquired Pacesetter’s approximately 8% working interest in the Champions AMI for approximately $2,034 and $6,463, respectively.

On January 17, 2017, REG contributed its 32% working interests in oil and natural gas properties and related assets and liabilities of the Champions Assets to the Company in exchange for a 100% membership interest in the Company. On January 17, 2017, Boomer contributed its interests in oil and natural gas properties and related assets of the Champions Assets to the Company in exchange for 360,000 common units in the Company and REG’s 100% membership interest in the Company was reclassified into 573,408 common units in the Company. On March 6, 2017, Bluescape Riley Exploration Acquisition, LLC (“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 499,092 and 67,500 common units in the Company, respectively.

On September 8, 2017, as part of the final settlement related to the contribution of net assets, the Company paid $200,000 to resolve outstanding claims related to certain net profits and overriding royalty interests associated with the working interests contributed by Bluescape.

REOC continued to operate the Champions Assets until May 31, 2017, at which time operation responsibilities were transferred to Riley Permian Operating Company, LLC (“RPOC”), a wholly-owned subsidiary of Riley Permian. 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.

2. Basis of Presentation

The consolidated financial statements include the accounts of Riley Permian and its wholly-owned subsidiary RPOC and have been prepared in accordance with accounting principles generally accepted in the United States

 

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of America (“U.S. GAAP”). All intercompany balances and transactions have been eliminated upon consolidation. For the periods prior to January 17, 2017, the accompanying consolidated 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 and costs and expenses. The financial statements may not be indicative of the future performance of the Company and do not necessarily reflect what the results of operations, financial position and cash flows would have been had the Champions Assets been operated as an independent company for periods prior to January 17, 2017.

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 the Company 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.

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 presented the historical operations of the contributed business on a retrospective basis for all periods presented. 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.

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. These allocations may not, however, reflect the expenses the Company would have actually incurred for the periods presented. Actual costs that may have been incurred if the Company had been a stand-alone entity would depend on a number of factors, including the organizational structure, whether functions were outsourced or performed by employees and strategic decisions made in areas such as information technology and infrastructure.

3. Summary of Significant Accounting Policies

Significant Estimates

The preparation of financial statements in conformity with U.S. GAAP requires management 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.

While management believes these estimates are reasonable, changes in facts and assumptions or the discovery of new information may result in revised estimates. Actual results could differ from these estimates and it is at least reasonably possible these estimates could be revised in the near term, and these revisions could be material.

Cash and Cash Equivalents

The Company considers all highly liquid investments with an original maturity of three months or less to be cash equivalents for purposes of the statement of cash flows. The Company maintains cash at financial institutions which may at times exceed federally insured amounts. The Company has not experienced any losses in such accounts and believes it is not exposed to any significant credit risk on cash and cash equivalents.

 

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Accounts Receivable

Our receivables arise primarily from the sale of oil and natural gas and joint interest owner receivables for properties in which we serve as the operator. This concentration of customers may impact our overall credit risk, either positively or negatively, in that these entities may be similarly affected by changes in economic or other conditions affecting the oil and natural gas industry. Accounts receivable are generally not collateralized. We may have the ability to withhold future revenue disbursements to recover non-payment of joint interest billings on properties of which we are the operator. Accounts receivable from joint interest owners are stated at amounts due, net of an allowance for doubtful accounts.

The oil and natural gas production are sold to various purchasers. In addition, industry partners may participate in the drilling, completion, and operation of Riley Permian’s oil and natural gas wells. Likewise, Riley Permian may participate with industry partners in the drilling, completion and operation of their wells. Substantially all of our accounts receivable are due from either purchasers of oil and natural gas or industry partners for our share of oil and natural gas revenues from their operated wells. Accounts receivable from oil and natural gas sales are generally due within 30 to 60 days after the last day of each production month. No interest is charged on past-due balances. Payments made on all accounts receivable are applied to the earliest unpaid items.

To the extent actual volumes and prices of oil and natural gas are unavailable for a given reporting period because of timing or information not received from third parties, the expected sales volume and prices for these properties are estimated and recorded within accounts receivable in the accompanying consolidated balance sheets. Crude oil is priced on the delivery date based upon prevailing prices published by purchasers with certain adjustments related to oil quality and physical location. Natural gas contracts’ pricing provisions are tied to a market index, with certain adjustments based on, among other factors, whether a well delivers to a gathering or transmission line, quality and heat content of natural gas, and prevailing supply and demand conditions. These market indices are determined on a monthly basis.

Accounts receivable are reviewed periodically and the carrying amount is reduced by a valuation allowance that reflects the best estimate of the amount that may not be collectible. No allowance for uncollectible amounts were required as of September 30, 2017 and 2016, respectively.

Accounts receivable is summarized below:

 

     As of September 30,  
     2017      2016  

Oil and natural gas sales

   $ 3,801      $ 832  

Advances paid

     —          17  

Joint interest accounts receivable

     1,018        —    
  

 

 

    

 

 

 

Total accounts receivable

   $ 4,819      $ 849  
  

 

 

    

 

 

 

Proved Oil and Natural Gas Properties

The successful efforts method of accounting is used to account for the oil and natural gas producing activities of the Company. Under this method, all property acquisition costs and cost of development wells are capitalized as incurred. The costs of development wells are capitalized whether productive or non-productive. Costs to drill exploratory wells are capitalized pending the determination of whether proved reserves are found. If an exploratory well is determined to be non-productive, the costs of drilling the unsuccessful exploratory well are charged to expense.

Geological and geophysical costs, including seismic studies and costs of carrying and retaining unproved oil and natural gas properties, are charged to exploration expense as incurred. Expenditures incurred to operate and for maintenance, repairs and minor renewals necessary to maintain our oil and natural gas properties in operating

 

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condition are charged to expense as incurred. Major betterments, replacements, and renewals are capitalized to the appropriate property and equipment accounts.

We capitalize interest on expenditures for significant exploration and development projects that require significant time to complete while activities are in progress to bring the assets to their intended use. During the years ended September 30, 2017 and 2016, no interest was capitalized.

Capitalized costs of proved oil and natural gas properties are amortized using the units-of-production method based on production and estimates of proved reserves quantities. Acquisition costs of proved properties are depleted over total estimated proved reserves, and capitalized development costs of wells and related equipment and facilities are depleted over estimated proved developed reserves. Depletion and amortization expenses for proved oil and natural gas properties amounted to $5,775 and $1,361 for the years ended September 30, 2017 and 2016, respectively.

On the sale or retirement of a complete unit of a proved property or field, the cost and related accumulated depletion, depreciation and amortization are eliminated from the property accounts, and the resulting gain (or loss) is recognized. On the retirement or sale of a partial unit of proved property, the unamortized cost of the property is apportioned to the interest sold and the interest retained on the basis of the fair value of those interests and gain or loss is recognized.

Unproved Oil and Natural Gas Properties

Unproved oil and natural gas properties consist of costs incurred to acquire unproved leases. Unproved lease acquisition costs are capitalized until the leases expire or when we specifically identify leases that will revert to the lessor, at which time we expense the associated unproved lease acquisition costs to impairment. Lease acquisition costs related to successful drilling are reclassified to proved oil and natural gas properties. During the years ended September 30, 2017 and 2016, the Company expensed $10,719 and $0, respectively, related to the expiration of leases which were included as exploration costs in the consolidated statements of operations.

On the sale of an entire interest in an unproved property for cash or cash equivalents, a gain or loss is recognized to the extent of the difference between the proceeds received and the net carrying value of the property. Proceeds from the sale of partial interests in unproved oil and natural gas properties are accounted for as a recovery of costs unless the proceeds exceed the entire cost of the property.

Impairment of Oil and Natural Gas Properties

The cost of proved oil and natural gas properties are assessed for impairment whenever events and circumstances indicate that a decline in the recoverability of their carrying value may have occurred. The expected undiscounted future cash flows of the contributed oil and natural gas properties are compared 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, the carrying amount of the oil and natural gas properties is adjusted to estimated fair value. Assumptions associated with discounted cash flow models or valuations used in the impairment evaluation include estimates of future crude oil and natural gas prices, production costs, development expenditures, anticipated production of proved reserves, appropriate risk-adjusted discount rates and other relevant data. An evaluation is performed on a field-by-field basis at least annually or whenever changes in facts and circumstances indicate that our oil and natural gas properties may be impaired. See further discussion in Note 3—Fair Value Measurements. The unproved oil and natural gas properties are assessed periodically for impairment on a property-by-property basis based on remaining lease terms, drilling results, or future plans to develop acreage and record impairment expense for any decline in value. Based on our analysis, no impairments occurred during the years ending September 30, 2017 or 2016.

 

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Other Property and Equipment, net

Property and equipment are capitalized and recorded at cost, while maintenance and repairs are expensed. Depreciation of such property and equipment is computed using the straight-line method over the estimated useful lives of the assets, which range from 3 to 39 years. Depreciation expense for other property and equipment amounted to $98 and $0 for the years ended September 30, 2017 and 2016, respectively. Capitalized costs related to leasehold improvements are depreciated over the life of the lease.

Accrued Liabilities

Accrued liabilities consisted of the following:

 

     As of September 30,  
     2017      2016  

Accrued capital expenditures

   $ 2,061      $ 2,610  

Accrued lease operating expenses

     748        410  

Accrued general administrative expenses

     911        —    

Other accrued expenditures

     35        —    

Accrued ad valorem tax

     139        25  

Lease acquisition obligation

     —          1,835  

State margin tax

     —          27  

Accrued dividends on preferred units

     1,409        —    
  

 

 

    

 

 

 

Total accrued liabilities

   $ 5,303      $ 4,907  
  

 

 

    

 

 

 

Asset Retirement Obligations

Asset retirement obligations (“ARO”) consist of future plugging and abandonment expenses on oil and natural gas properties. The fair value of the ARO is recorded in the period in which wells are drilled with a corresponding increase in the carrying amount of oil and natural gas properties. The liability is accreted for the change in its present value each period and the capitalized cost is depreciated using the units-of-production method. The liability is adjusted for changes resulting from revisions to the timing or the amount of the original estimate when deemed necessary. If the liability is settled for an amount other than the recorded amount, a gain or loss is recognized in earnings to lease operating expense.

The following table reflects the changes in the ARO during the years ended September 30, 2017 and 2016:

 

     As of September 30,  
     2017      2016  

ARO, beginning of year

   $ 21      $ 6  

Liabilities incurred

     19        2  

Liabilities contributed

     33        8  

Accretion

     3        5  
  

 

 

    

 

 

 

ARO, end of year

   $ 76      $ 21  
  

 

 

    

 

 

 

Revenue Recognition

Revenue is recognized when it is realized or realizable and earned. Revenues are considered realized or realizable and earned when: (i) persuasive evidence of an arrangement exists, (ii) delivery has occurred or services have been rendered, (iii) the seller’s price to the buyer is fixed or determinable, and (iv) collectability is reasonably assured.

 

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Revenues for oil and natural gas production are recognized when the quantities are delivered to or collected by the respective purchaser, using the sales method. The sales prices for such production, net of transportation costs, are defined in sales contracts and are readily determinable based on certain publicly available indices. If our excess takes of natural gas were to exceed our estimated remaining proved reserves for a property, a natural gas imbalance liability would be recorded in the consolidated balance sheet. A gas imbalance receivable (payable) can also result from imbalances acquired in conjunction with the acquisition of oil and gas properties. As of September 31, 2017 and 2016, there were no such imbalance liabilities.

Production Costs

Production costs, including 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.

Transaction Costs

The Company incurred $1,766 of transaction costs related to the contributions of oil and gas properties and other acquisitions during the year ended September 30, 2017.

Concentration of Credit Risk

Our financial condition, results of operations, and capital resources are highly dependent upon the prevailing market prices of, and supply and demand for, oil and natural gas. These commodity prices are subject to wide fluctuations and market uncertainties due to a variety of factors that are beyond our control. These factors include the level of global and regional supply and demand for petroleum products, the establishment of and compliance with production quotas by oil-exporting countries, weather conditions, the price and availability of alternative fuels, and overall economic conditions, both foreign and domestic.

We cannot predict future oil and natural gas prices with any degree of certainty. Sustained weakness in oil and natural gas prices may adversely affect our financial condition and results of operations, and may also reduce the amount of net oil and natural gas reserves that we can produce economically. Similarly, any improvement in oil and natural gas prices can have a favorable impact on our financial condition, results of operations and capital resources.

Our customer concentration may impact our overall credit risk, either positively or negatively, in that these entities may be similarly affected by changes in economic or other conditions affecting the oil and natural gas industry.

We manage credit risk related to accounts receivable through credit approvals, credit limits and monitoring procedures. We routinely assess the financial strength of our customers, and based upon factors surrounding the credit risk, establish an allowance, if required, for uncollectible accounts. As a result, we believe that our accounts receivable credit risk exposure beyond such allowance is limited.

In the exploration, development and production business, production is normally sold to relatively few customers. Substantially all of our customers are concentrated in the oil and natural gas industry and revenue can be materially affected by current economic conditions, the price of certain commodities, such as crude oil and natural gas, and the availability of alternate purchasers. The loss of any of our major purchasers would not have a long-term material adverse effect on our operations.

Environmental and Other Issues

We are engaged in oil and natural gas exploration and production, and may become subject to certain liabilities as they relate to environmental cleanup of well sites or other environmental restoration procedures. In connection with our acquisition of existing or previously drilled well bores, we may not be aware of what environmental

 

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Index to Financial Statements

safeguards were taken at the time such wells were drilled or during such time the wells were operated. Should it be determined that a liability exists with respect to any environmental cleanup or restoration, we would be responsible for curing such a violation. No claim has been made, nor are we aware of any material liability that exists, as it relates to any environmental cleanup, restoration, or the violation of any rules or regulations relating thereto.

Fair Value Measurements

Certain of the Company’s assets and liabilities are measured at fair value. Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. This price is commonly referred to as the “exit price.” We use market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated, or generally unobservable. FASB ASC 820 establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and lowest priority to unobservable inputs (Level 3 measurement). The three levels of fair value hierarchy defined by ASC 820 are as follows:

 

   

Level 1—Quoted prices are available in active markets for identical assets or liabilities as of the reporting date.

 

   

Level 2—Pricing inputs are other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reporting date. Level 2 includes those financial instruments that are valued using models or other valuation methodologies. These models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors, and current market and contractual prices for the underlying instruments, as well as other relevant economic measures.

 

   

Level 3—Pricing inputs include significant inputs that are generally less observable from objective sources. These inputs may be used with internally-developed methodologies that result in management’s best estimate of fair value.

We classify financial assets and liabilities based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels.

Financial Instruments

The carrying value of financial instruments including accounts receivables, accounts payable and accrued liabilities approximate fair value due to the short maturity of these instruments as of September 30, 2017 and 2016.

Derivative Contracts

Riley Permian uses derivative contracts to reduce exposure to fluctuations in commodity prices. The current transactions are in the form of fixed price swaps for crude oil. While the use of these contracts limits the downside risk for adverse price changes, their use may also limit future revenues from favorable price changes.

The use of derivatives involves the risk that the counterparties to such contracts will be unable to meet their obligations under the terms of the agreement. By using derivative instruments that are not traded on an exchange, the Company is exposed to the credit risk from its counterparty. Credit risk is the risk of loss from the counterparty not performing under the terms of the derivative contract. When the fair value of a derivative

 

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instrument is positive, the counterparty is expected to owe a cash settlement to the Company, which creates credit risk. To minimize the credit risk with derivative instruments, it is the Company’s policy to enter into derivative contracts only with counterparties that are creditworthy financial institutions. Under the terms of the current counterparty’s contract, the Company is not required to provide credit support or collateral, nor is the counterparty required to provide credit support to the Company.

Riley Permian receives a fixed price for the contract and pays a floating market price to the counterparty over a specified period for a contracted volume. Riley Permian reports the fair value of derivatives on the consolidated balance sheet in derivative assets and derivative liabilities as either current or noncurrent based on the timing of expected future cash flows of individual trades. The Company nets derivative assets and liabilities whenever it has a legally enforceable master netting agreement with the counterparty to a derivative contract. As of September 30, 2017 and 2016, the Company did not net any derivative assets and liabilities.

For the year ended September 30, 2017, Riley Permian has not designated its derivative contracts as hedges for accounting purposes. Cash settlements of contracts are included in cash flows from operating activities in the consolidated statement of cash flows. Derivative contracts are settled on a monthly basis.

The Company had no derivative contracts as of September 30, 2016 or for the year then ended. The following table summarizes the open financial derivative positions as of September 30, 2017 related to crude oil production:

 

     2017      2018      2019  

Crude Oil Price Swaps:

        

Notional volume (Bbl)

     119,600        465,200        243,000  

Weighted average fixed price ($/Bbl)

     $49.37        $49.32        $50.43  

Balance Sheet Presentation. The following table presents the location and fair value of Riley Permian’s derivative contracts included in the accompanying consolidated balance sheet as of September 30, 2017:

 

Balance sheet location

   As of September 30,
2017
 

Derivatives liabilities

   $ 1,139  

Non-current derivatives liabilities

     484  
  

 

 

 

Total

   $ 1,623  
  

 

 

 

Gains and Losses. The following table presents the cash settlements and mark-to-market (“MTM”) gains and losses presented as a gain or loss on derivatives in the consolidated statements of operations for the years ended September 30, 2017 and 2016:

 

     Years Ended
September 30,
 
     2017      2016  

Gain/(loss) on settled derivatives

   $ 173      $ —    

Gain/(loss) on unsettled derivatives

     (1,623      —    
  

 

 

    

 

 

 

Total gain (loss) on derivative contracts, net

   $ (1,450    $ —    
  

 

 

    

 

 

 

Unaudited Pro Forma Income Taxes

These financial statements have been prepared in anticipation of a proposed initial public offering (the “Offering”) of the common stock of Riley Exploration Permian, Inc. In connection with the Offering the

 

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Company will convert from a Delaware limited liability company into a Delaware corporation, which will be taxed as a corporation under the Internal Revenue Code of 1986, as amended. Accordingly, a pro forma income tax provision for the year ended September 30, 2017 has been disclosed as if the Company was a taxable corporation. The Company has computed pro forma entity-level income tax expense using an estimated effective rate of 33.6%, based on the U.S. Federal income tax rate in effect during that period, inclusive of all applicable U.S. federal, state and local income taxes.

Unaudited Pro Forma Earnings Per Share

The Company has presented pro forma earnings per share for the year ended September 30, 2017. Pro forma basic and diluted income per share was computed by dividing pro forma net income attributable to the Company by the number of shares of common stock to be issued in the Corporate Conversion, in which all Series A Preferred Units and the common units are to be converted into common stock, as if such shares were issued and outstanding for the year ended September 30, 2017.

New Accounting Pronouncements

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 is not expected to have a material 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 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.

 

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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, 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, 2018, we expect that leases in effect on October 1, 2017 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, 2019, 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 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.

4. Oil and Natural Gas Properties

Our oil and natural gas properties consisted of the following:

 

     As of September 30,  
     2017      2016  

Unproved properties

   $ 41,862      $ 19,655  

Proved properties

     114,849        21,666  

Work-in-progress

     18,174        2,580  
  

 

 

    

 

 

 

Total oil and natural gas properties

     174,885        43,901  

Accumulated depletion and amortization

     (7,146      (1,371
  

 

 

    

 

 

 

Net oil and natural gas properties

   $ 167,739      $ 42,530  
  

 

 

    

 

 

 

During the year ended September 30, 2017 our oil and natural gas properties increased by $131.0 million due primarily from the acquisition of oil and natural properties of $82.4 million in exchange for common units of the Company, as discussed below, and $48.6 million, net of accruals, for capital expenditures related to the

 

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acquisition of unproved property, development drilling, completion and workover activities and infrastructure investment in our Champions Assets.

Acquisition of Oil and Natural Gas Properties

In April 2015, REG entered into an agreement to acquire unproved properties in Yoakum County, Texas for an initial consideration of $5,000 and had options to make additional payments of $3,650, $3,650 and $4,920 no later than December 31, 2015, April 30, 2016 and October 31, 2016. As of September 30, 2016, REG exercised and made payment on the first and second purchase options. As permitted by the purchase agreement, REG and the seller negotiated the final option payment due to acreage adjustments resulting from title defects and lease expirations. Subsequent to year end, REG and the seller came to a definitive agreement on this final option payment and the amount was paid in March 2017. Approximately $1,835 was accrued as of September 30, 2016 relating to the above option payments, which is included in accrued liabilities on our consolidated balance sheet. This acquisition was accounted for as an asset acquisition under ASC 360.

On December 31, 2015, REG acquired approximately 3% working interest in the Champions AMI from Murfin for $2,034. The acquisition from Murfin qualifies as a business combination under ASC 805—Business Combinations. The total purchase price was allocated to the assets purchased and the liabilities assumed based upon their fair values on the date of the acquisition as follows:

 

Proved oil and gas properties

   $ 265  

Unproved oil and gas properties

     1,771  

Asset retirement obligations assumed

     (2
  

 

 

 

Fair value of net assets acquired

   $ 2,034  
  

 

 

 

On January 20, 2016, REG acquired approximately 8% working interest in the Champions AMI from Pacesetter for $6,463. The acquisition from Pacesetter qualifies as a business combination under ASC 805—Business Combinations. The total purchase price was allocated to the assets purchased and the liabilities assumed based upon their fair values on the date of the acquisition as follows:

 

Proved oil and gas properties

   $ 741  

Unproved oil and gas properties

     5,728  

Asset retirement obligations assumed

     (6
  

 

 

 

Fair value of net assets acquired

   $ 6,463  
  

 

 

 

Our nonfinancial assets and liabilities that are initially measured at fair value are comprised primarily of assets acquired in business combinations and asset retirement obligations. These assets and liabilities are recorded at fair value when acquired but not re-measured at fair value in subsequent periods.

 

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On January 17, 2017, Boomer contributed their 28% working interest in oil and natural gas properties and related assets and liabilities of the Champions Assets to the Company for 360,000 common units of the Company. On March 6, 2017, Bluescape and DR/CM contributed their combined 29.3% working interest in oil and natural gas properties and related assets and liabilities of the Champions Assets to the Company for 499,092 and 67,500 common units, respectively of the Company. The net assets contributed were recorded at their fair values at the dates of their respective contributions as summarized below:

 

     Boomer      Bluescape
and DR/CM
     Total  

Oil & gas properties:

        

Proved

   $ 26,962      $ 26,590      $ 53,552  

Unproved

     17,695        17,075        34,770  
  

 

 

    

 

 

    

 

 

 
   $ 44,657      $ 43,665      $ 88,322  

Revenue receivables

     1,411        2,408        3,819  

Joint interest payables

     (4,336      (5,393      (9,729

ARO liability

     (16      (17      (33
  

 

 

    

 

 

    

 

 

 

Net assets contributed

   $ 41,716      $ 40,663      $ 82,379  
  

 

 

    

 

 

    

 

 

 

On September 8, 2017, as part of the final settlement related to the contribution of net assets, the Company paid $200 to resolve outstanding claims related to certain net profits and overriding royalty interests associated with the working interests contributed by Bluescape.

Pro Forma Financial Information (Unaudited)

The following unaudited pro forma financial information represents the combined results of the Company and working interests acquired from Murfin, Pacesetter, Boomer, Bluescape and DR/CM which commenced operations during the year ended September 30, 2016 as if the acquisitions had occurred as of October 1, 2015.

The pro forma results reflect the results of combining our consolidated results of operations with the revenues and direct operating expenses of the working interests acquired from Murfin, Pacesetter, Boomer and DR/CM and adjusted for the depletion expense applied to the adjusted basis of the oil and gas properties. The pro forma results do not include any cost savings or other synergies that may result from the acquisition or any estimated costs that have been or will be incurred by the Company to integrate the contributed properties. The pro forma results for the years ended September 30, 2017 and 2016 are not necessarily indicative of what actually would have occurred if the contributions had been completed as of October 1, 2015 nor are they necessarily indicative of future results.

 

     Years Ended
September 30,
 
     2017      2016  
     (in Thousands except per
unit amounts)
 

Revenues

   $ 25,903      $ 9,666  

Net loss

     (9,577      (4,466

Net loss attributable to common units

     (10,986      (4,466

Loss per common unit (Basic and Diluted)

   $ (7.32    $ (2.98

 

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The amount of revenues in excess of direct operating expenses for the year ended September 30, 2016 for the Murfin and Pacesetter acquisitions was not material. The amounts of revenue and revenues in excess of direct operating expenses included in the Company’s consolidated statements of operations for the year ended September 30, 2017 for the Boomer and Bluescape / DR/CM acquisitions are shown in the table below. Direct operating expenses include lease operating expenses and production and ad valorem taxes:

 

     Year Ended
September 30,
 
     2017  

Revenues

   $ 10,741  

Direct operating expenses

     3,247  
  

 

 

 

Excess of revenues over direct operating expenses

   $ 7,494  

5. Fair Value Measurements

Assets and Liabilities Measured at Fair Value on a Non-Recurring Basis

Assets and liabilities accounted for at fair value on a non-recurring basis in accordance with the fair value hierarchy include the initial recognition of asset retirement obligations, the fair value of oil and natural gas properties when acquired or assessed for impairment, and share-based compensation.

In January and March 2017, the Company acquired working interests in oil and gas properties and other assets in exchange for common units. These assets were recorded by the Company at their respective fair values using the income approach for oil and natural gas reserves. Significant inputs used to determine the fair value include estimates of: (i) reserves; (ii) future commodity prices; (iii) operating and development costs; and (iv) a market-based weighted average cost of capital rate. The underlying commodity prices embedded in the Company’s estimated cash flows are the product of a process that begins with NYMEX forward curve pricing, adjusted for estimated location and quality differentials, as well as other factors that the Company’s management believes will impact realizable prices. The inputs used by management for the fair value measurements utilized in this review include significant unobservable inputs, and therefore, the fair value measurements employed are classified as “Level 3” inputs.

The fair value of asset retirement obligations incurred and contributed during the year ended September 30, 2017 totaled approximately $52. The fair value of additions to the asset retirement obligation liabilities is measured using valuation techniques consistent with the income approach, which converts future cash flows to a single discounted amount. Significant inputs to the valuation include: (i) estimated plug and abandonment cost per well based on our experience and information from third-party vendors; (ii) estimated remaining life per well; (iii) future inflation factors; and (iv) our average credit-adjusted risk-free rate. These assumptions represent “Level 3” inputs.

If the carrying amount of our oil and natural gas properties exceeds the estimated undiscounted future cash flows, we will adjust the carrying amount of the oil and natural gas properties to fair value. The fair value of our oil and natural gas properties is determined using valuation techniques consistent with the income and market approach. The factors used to determine fair value are subject to management’s judgment and expertise and include, but are not limited to, recent sales prices of comparable properties, the present value of future cash flows, net of estimated operating and development costs using estimates of proved reserves, future commodity pricing, future production estimates, anticipated capital expenditures, and various discount rates commensurate with the risk and current market conditions associated with the expected cash flow projected. These assumptions represent “Level 3” inputs.

6. Transactions with Related Parties

The Original AMI Partners entered into a joint exploration agreement to establish the Champions AMI, and also entered into a joint operating agreement with REOC, an affiliate of REG, to operate substantially all of the

 

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Champions AMI. Prior to May 2017, the Company had no employees. As of September 30, 2017 and 2016, Riley Permian owed REOC $0 and $957, respectively, which is included in Accounts Payable—Related Parties on our consolidated balance sheets.

7. Revolving Credit Facility

On September 28, 2017, the Company and SunTrust Robinson Humphrey, Inc., as lead arranger and administrative agent, entered into a credit agreement. The senior secured revolving credit facility has an initial borrowing base of $25 million with a maximum borrowing amount of $500 million. The credit facility matures on September 28, 2021, and is secured by substantially all of the Company’s assets.

The borrowing base is subject to periodic redeterminations, mandatory reductions and further adjustments from time to time. The facility requires quarterly redetermination of the borrowing base on November 1, 2017, February 1, 2018, May 1, 2018 and August 1, 2018, and semi-annually on February 1 and August 1 beginning on February 1, 2019. The borrowing base will also be reduced in certain circumstances such as the sale or disposition of certain oil and natural gas properties of the Company or its subsidiaries and cancellation of certain hedging positions. The revolving credit facility allows for Eurodollar Loans and Base Rate Loans (each as defined in the credit agreement). The interest rate on each Eurodollar Loan will be the adjusted LIBOR for the applicable interest period plus a margin between 2.50% and 3.50% (depending on the borrowing base utilization percentage). The annual interest rate on each Base Rate Loan is (a) the greatest of (i) the administrative agent’s prime lending rate, (ii) the federal funds rate plus 0.5% per annum or the (iii) adjusted LIBOR determined on a daily basis for an interest period of one-month, plus 1.00% per annum, plus (b) a margin between 1.50% and 2.50% (depending on the borrowing base utilization percentage). The Company is also subject to an unused commitment fee of between 0.375% and 0.50% (depending on the borrowing base utilization percentage).

The credit agreement contains certain covenants, which, among other things, require the maintenance of (i) a total leverage ratio of not more than 4.0 to 1.0, (ii) a minimum current ratio of 1.0 to 1.0 and (iii) total capital expenditures in an aggregate amount cannot be greater than (a) during the fiscal quarter ending September 30, 2017, $24 million and (b) during the fiscal quarter ending December 31, 2017, $22 million. The credit agreement also contains other customary affirmative and negative covenants and events of default. As of September 30, 2017, the Company was in compliance with all covenants contained in the credit agreement with no funds drawn on the credit facility.

There was no change in the borrowing base as a result of the redetermination on November 1, 2017.

8. Preferred Units

In March of 2017, Riley Permian closed a private offering of convertible preferred securities, or the Series A Preferred Units, to Yorktown Energy Partners XI, L.P. (“Yorktown XI”), Bluescape Riley Exploration Holdings, LLC (“BREH”), and Boomer that resulted in proceeds of approximately $40 million to fund general business purposes. Series A Preferred Units are entitled to distributions at the rate of 6% per annum of the Series A outstanding principal amount and shall accrue from day to day, whether or not declared, and shall be cumulative. Dividends on Series A Preferred Units shall be payable in kind by the issuance of additional Series A Preferred units, however, the Board of Managers may determine in its sole discretion to pay Series A Preferred dividends in cash. The Company shall not declare, pay or set aside any distributions on any other membership interest (other than distributions made to the members for tax distributions pursuant to Section 4.3(b) of the Second Amended and Restated Limited Liability Company dated as of March 6, 2017) without the consent of a majority of the holders of the Series A Preferred Units. At September 30, 2017 the Company had accrued dividends on the Preferred Units of $1,409 which are currently included in accrued liabilities in the consolidated balance sheet.

On September 7, 2017, the Company closed a follow-on offering of the Series A Preferred Units to Yorktown XI, BREH and Boomer that resulted in proceeds of $10 million to fund general business purposes.

 

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On December 31, 2022, the Company is required to redeem all of the outstanding Series A Preferred Units in cash in an amount equal to the Series A preferred liquidation preference for such Series A Preferred Units on the date of redemption. At any time prior to an IPO and at such holder’s sole discretion, a holder of Series A Preferred Units may elect to convert such Series A Preferred Units to a number of common units in an amount equal to the quotient of (A) the product of the number of Series A Preferred Units to be converted by the Series A preferred liquidation preference, divided by (B) the Series A conversion price then in effect by the delivery of written notice to the Company. Immediately prior to any conversion, all accrued and undeclared but unpaid dividends on the Series A Preferred Units shall be paid in kind to such holder of Series A Preferred Units electing to convert its units. The Series A Preferred conversion price is $120 per unit, as adjusted to reflect any subdivision, stock split, recapitalization, reclassification or consolidation of the common units.

Immediately following the execution of an underwriting agreement, but prior to the closing of an IPO, all outstanding Series A Preferred Units shall be automatically converted into IPO shares at 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 holders of the Series A Preferred Units have the same voting rights as if such Series A Preferred Units were converted into common units in accordance with the Series A conversion price then in effect and shall vote with the common units as a single class. The affirmative vote or consent of at least 70% of the outstanding Series A Preferred Units, voting together as a single class, shall be necessary for effecting or validating any amendment, alteration or repeal of the certificate of formation or the Second Amended and Restated Limited Liability Company Agreement, which materially and adversely affects the rights or preferences of the holders of the Series A Preferred Units, issuance or reclassification of membership interests ranking pari passu or senior to the Series A Preferred Units, any transaction between the Company and any of its officers, holders of its units, directors of Affiliates, any increase in indebtedness for money borrowed by the Company, a call for capital contributions from holders of the Series A Preferred Units and any company event in which the holders of the Series A Preferred Units do not receive, upon the consummation of the company event of an amount in cash equal to the greater of (A) the Series A preferred issue amount with respect to each outstanding Series A Preferred Unit, multiplied by 1.35 plus any accrued but unpaid dividends on the Series A Preferred Units as of such date or (B) an amount sufficient to cause the internal rate of return of each Series A Preferred Unit held by such holder to equal 17.5% plus any accrued but unpaid dividends on the Series A Preferred Units. In the event a majority of the outstanding Series A Preferred Units, voting together as a single class, do not approve a company event, the Company may elect to redeem the outstanding Series A Preferred units in cash.

The following summarizes the change in Series A Preferred Units during the year ended September 30, 2017:

 

     Units      Amount  

Issuance of Series A Preferred Units

     416,667      $ 50,000  

Deferred financing costs

     —          (177
  

 

 

    

 

 

 

Total Preferred units—end of year

     416,667      $ 49,823  
  

 

 

    

 

 

 

In accordance with ASC 480-10-S99 (Distinguishing Liabilities From Equity), equity securities are required to be classified outside of permanent equity in temporary equity if they are redeemable or may become redeemable for cash or other assets. As the Company is not considered to have sole control over the contractually mandated redemption in 2022, the Series A Preferred Units have been classified as mezzanine equity.

9. Members’ Equity

Common Units. As of September 30, 2017, the Company’s operations were governed by the provisions of the Second Amended and Restated Limited Liability Company Agreement, effective March 6, 2017, as amended by Amendment No. 1 thereto effective as of September 7, 2017, and as further amended by Amendment No. thereto

 

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effective as of December 27, 2017, which authorized the issuance of 2,265,200 units, designated as common units. In connection with the net assets contributed by REG, Boomer, Bluescape and DR/CM (see Note 4—Oil and Natural Gas Properties), a total of 1,500,000 common units were issued.

The table below summarizes common unit issuances as of September 30, 2017:

 

     Common
Units
 

Riley Exploration Group, Inc.

     573,408  

Boomer Petroleum, LLC

     360,000  

Bluescape Riley Exploration Acquisition LLC

     470,092  

Bluescape Riley Exploration Holdings LLC

     29,000  

DR/CM

     67,500  
  

 

 

 
     1,500,000  
  

 

 

 

10. Earnings (Loss) Per Unit

Basis earnings (loss) per unit is computed by dividing income (loss) attributable to unitholders by the weighted average number of units outstanding during each period. Diluted earnings per unit reflects the potential dilutive impact of dilutive securities, of which there were none at September 30, 2017. In periods of net loss, potentially dilutive units are excluded from the calculation because they are anti-dilutive.

The table below sets forth the computation of basic and diluted net income (loss) per unit for the years ended September 30, 2017 and 2016 (in thousands, except per unit data):

 

     Years Ended
September 30,
 
     2017      2016  

Net income (loss) attributable to common units

   $ (12,240    $ (4,126

Weighted average basis common units outstanding

     1,151        573  

Basic and diluted income (loss) per common unit

   $ (10.63    $ (7.20

11. Commitments and Contingencies

Pursuant to the terms of the definitive agreement between us and REG, any claims, litigation or disputes pending as of the effective date, October 1, 2016, and any matters arising in connection with ownership of the Champions Assets prior to the effective date are retained by REG. Notwithstanding this indemnification, management is not aware of any legal, environmental or other commitments or contingencies that would have a material effect on its business.

Legal Matters. In the ordinary course of business, Riley Permian may at times be subject to claims and legal actions. Riley Permian accrues liabilities when it is probable that future costs will be incurred and such costs can be reasonably estimated. Such accruals are based on developments to date and Riley Permian’s estimates of the outcomes of these matters. Riley Permian did not recognize any material liability as of September 30, 2017 or 2016. Management believes it is remote that the impact of such matters will have a materially adverse effect on Riley Permian’s financial position, results of operations, or cash flows.

Environmental Matters. Riley Permian is subject to various federal, state and local laws and regulations relating to the protection of the environment. These laws, which are often changing, regulate the discharge of materials into the environment and may require Riley Permian to remove or mitigate the environmental effects of the disposal or release of petroleum or chemical substances at various sites. Riley Permian accounts for environmental contingencies in accordance with the accounting guidance related to accounting for contingencies.

 

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Environmental expenditures that relate to current operations are expensed or capitalized as appropriate. Expenditures that relate to an existing condition caused by past operations, which do not contribute to current or future revenue generation, are expensed. Liabilities are recorded when environmental assessments and/or clean-ups are probable, and the costs can be reasonably estimated. As of September 30, 2017 and 2016, the Company recorded no environmental liabilities.

Leases. Riley Permian leases its office headquarters under a five-year operating lease agreement terminating in July 2022. Base rent for the first year of the lease is $228 annually, with each subsequent year being subject to a two percent (2%) escalation. Additionally, Riley Permian leases certain common office equipment of nominal amounts.

Notes Payable. Riley Permian financed certain vehicles used in field operations and financed the premiums for certain components of its commercial insurance package. Vehicle notes payable of $142 are based on 48 month terms beginning in May 2017, with an average interest rate of 4.83%. Insurance notes payable of $76 are based on 10-month terms beginning in June 2017, and are subject to an interest rate of 4.19%.

12. Subsequent Events

We have evaluated subsequent events through December 27, 2017, the date on which these financial statements were available for issuance and again through February 9, 2018, when these financial statements were reissued and there are no further subsequent events to report, other than the following:

Oakspring option

Pursuant to a purchase and sale agreement dated September 1, 2017, REG sold its fifty percent (50%) interest to Oakspring Energy Holdings, LLC (“Oakspring”), resulting in Oakspring owning a one hundred percent (100%) interest, in approximately 16,000 gross acres (unaudited) in the “Saddle Tramp” and “Eagle Eye” prospects, which are located in Lea County, New Mexico (collectively, the “Kachina Assets”). Oakspring is a portfolio company of Yorktown Partners, certain managed funds of which have investments in REG and Riley Permian (all deemed to be related parties).

Subsequent to year-end, Oakspring, REG and Riley Permian entered into an option agreement (the “Option”), pursuant to which Riley Permian would have the right to purchase a fifty percent interest in the Kachina Assets from Oakspring. In connection with services performed by REG to structure, negotiate and document the Option on behalf of Riley Permian, Riley Permian paid REG $275 as an option fee in October 2017. The Company recorded the option at REG’s historical basis, which was $0, therefore the amount paid to REG will be recorded as a reduction to members’ equity during the first three months of fiscal 2018. The Company has until March 31, 2018 to exercise the option to purchase the Kachina Assets from Oakspring.

13. Supplemental Oil and Gas Information (Unaudited)

Capitalized Costs

Capitalized costs include the cost of properties, equipment, and facilities for oil and natural gas producing activities. Capitalized costs for proved properties include costs for oil and natural gas leaseholds where proved reserves have been identified, development wells, and related equipment and facilities, including development wells in progress. Capitalized costs for unproved properties include costs for acquiring oil and natural gas leaseholds where no proved reserves have been identified, including costs of exploratory wells that are in the process of drilling or in active completion, and costs of exploratory wells suspended or waiting on completion. For a summary of these costs, please refer to Note 4—“Oil and Natural Gas Properties.”

 

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Costs Incurred for Property Acquisition, Exploration, and Development

Amounts reported as costs incurred include both capitalized costs and costs charged to expense when incurred for oil and natural gas property acquisition, exploration, and development activities. Costs incurred also include new AROs established in the current year as well as increases or decreases to ARO resulting from changes to cost estimates during the year. Exploration costs presented below include the costs of drilling and equipping successful and unsuccessful exploration wells during the year, geological and geophysical expenses, and the costs of retaining undeveloped leaseholds. Development costs include the costs of drilling and equipping development wells, and construction of related production facilities.

The following summarizes the costs incurred for oil and natural gas property acquisition, exploration, and development activities for the years ended September 30, 2017 and 2016:

 

     2017      2016  

Acquisition of properties

     

Proved

   $ 53,552      $ 1,006  

Unproved

     34,770        7,499  

Exploration costs

     10,739        45  

Development costs

     51,871        16,063  
  

 

 

    

 

 

 

Total costs incurred

   $ 150,932      $ 24,613  
  

 

 

    

 

 

 

Oil, Natural Gas and NGL Quantities

The reserves at September 30, 2017 presented below were prepared by Netherland, Sewell & Associates, Inc. (“NSAI”). All reserves are located within the continental United States. Proved oil, natural gas and NGL reserves are the estimated quantities of oil natural gas and NGLs that geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under economic and operating conditions existing at the time the estimate is made. Proved developed oil, natural gas and NGL reserves are proved reserves that can be expected to be recovered through existing wells and equipment in place and under operating methods being utilized at the time the estimates were made. A variety of methodologies are used to determine our proved reserve estimates. The principal methodologies employed are decline curve analysis, advance production type curve matching, petro physics/log analysis and analogy. Some combination of these methods is used to determine reserve estimates in substantially all of our fields. The Company emphasizes that reserve estimates are inherently imprecise and that estimates of new discoveries and undeveloped locations are more imprecise than estimates of established proved producing oil and gas properties. Accordingly, these estimates are expected to change as future information becomes available.

The following unaudited supplemental reserve information summarizes the proved reserves of oil and natural gas and the standardized measure thereof. All of the reserves are located in the United States. The tables below reflect the reserves attributable to the Acquired Properties with the removal of the Murfin and Pacesetter reserves when their interests were acquired by REG in 2015 and 2016. Proved oil, natural gas liquids (“NGLs”) and natural gas reserve quantities are derived from estimates prepared by Netherland, Sewell & Associates, Inc. and from information provided by management for the fiscal year ended September 30, 2017 and for the periods prior, they were prepared by qualified petroleum engineers on our staff and are reflective of the carved-out stand-alone interest of the properties contributed by REG. The estimates have been prepared in accordance with the definitions and regulations of the U.S. Securities and Exchange Commission (SEC) and, with the exception of the exclusion of future income taxes, conform to the FASB Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas.

 

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The following table sets forth information for the years ended September 30, 2017 and 2016 with respect to changes in the Company’s proved (i.e. proved developed and undeveloped) reserves:

 

     Crude Oil      Natural Gas      NGLs      Total  
     (Mbbl)      (MMcf)      (Mbbl)      (MBoe)  

September 30, 2015

     934.0        747.0        —          1,058.5  

Extensions, discoveries and other additions

     1,419.0        507.0        138.0        1,641.5  

Acquisitions

     372.0        131.0        35.0        428.8  

Revisions

     288.0        (338.0      107.0        338.7  

Production

     (108.7      (16.2      (1.5      (112.9
  

 

 

    

 

 

    

 

 

    

 

 

 

September 30, 2016

     2,904.3        1,030.8        278.5        3,354.6  

Extensions, discoveries and other additions

     2,575.4        967.6        205.8        2,942.5  

Acquisitions

     4,732.2        1,677.1        452.8        5,464.5  

Revisions

     2,283.5        1,221.4        263.4        2,750.5  

Production

     (469.5      (76.4      (21.2      (503.5
  

 

 

    

 

 

    

 

 

    

 

 

 

September 30, 2017

     12,025.9        4,820.5        1,179.3        14,008.6  
  

 

 

    

 

 

    

 

 

    

 

 

 

Proved Developed Reserves, included above

           

September 30, 2016

     1,484.6        537.2        145.1        1,719.2  

September 30, 2017

     7,064.4        2,814.3        692.1        8,225.5  

Proved Undeveloped Reserves, included above

           

September 30, 2016

     1,419.7        493.6        133.4        1,635.4  

September 30, 2017

     4,961.5        2,006.2        487.2        5,783.1  

As of September 30, 2017 and 2016, the reserves were comprised of 85.8% crude oil, 5.7% natural gas, and 8.5% NGL. The following values for the 2017 proved 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 following values for the 2016 proved 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, 2016 of $38.17 per Bbl for oil and NGL volumes, and $2.28 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 the year ended September 30, 2017, the Company had upward revisions of previous estimates of 2,750.5 MBoe. These upward revisions are comprised of 2,404.5 MBoe increase attributable to better well performance on new wells that exceeded previous estimates, and 346.0 MBoe is attributable to a decrease in LOE which extended the life of the wells. As a result of ongoing drilling and completion activities during the year ended September 30, 2017, the Company reported extensions, discoveries, and other additions of 2,942.5 MBoe. Additionally, during the year ended September 30, 2017, the Company purchased reserves of 5,464.5 MBoe in connection with the Boomer, Bluescape and DR/CM acquisitions.

For the year ended September 30, 2016, the Company had upward revisions of previous estimates of approximately 338.7 MBOE. These revisions are the result of better well performance from new wells that exceeded previous estimates. As a result of ongoing drilling and completion activities during the year ended September 30, 2016, the Company reported extensions, discoveries, and other additions of 1,641.5 MBoe. Additionally, during the year ended September 30, 2016, the Company purchased reserves of approximately 428.8 MBoe.

 

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Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil, Natural Gas and NGL Reserves

The Company follows the guidelines prescribed in ASC Topic 932, Extractive Activities—Oil and Gas for computing a standardized measure of future net cash flows and changes therein relating to estimated proved reserves. The following summarizes the policies used in the preparation of the accompanying oil, natural gas and NGL reserve disclosures, standardized measures of discounted future net cash flows from proved oil, natural gas and NGL reserves and the reconciliations of standardized measures from year to year.

The standardized measure of discounted future net cash flows from production of proved reserves was developed as follows: (1) estimates are made of quantities of proved reserves and future periods during which they are expected to be produced based on year-end economic conditions; (2) estimated future cash flows are compiled by applying the twelve month average of the first of the month prices of crude oil and natural gas relating to the Company’s proved reserves to the year-end quantities of those reserves for reserves; (3) future cash flows are reduced by estimated production costs and costs to develop and produce the proved reserves, all based on year-end economic conditions, plus Company overhead incurred; (4) future income tax expenses are based on year-end statutory tax rates giving effect to the remaining tax basis in the oil and natural gas properties, other deductions, credits and allowances relating to the Company’s proved oil and natural gas reserves; and, (5) future net cash flows are discounted to present value by applying a discount rate of 10%.

The assumptions used to compute the standardized measure are those prescribed by the FASB and the SEC. These assumptions do not necessarily reflect the Company’s expectations of actual revenues to be derived from those reserves, nor their present value. The limitations inherent in the reserve quantity estimation process, as discussed previously, are equally applicable to the standardized measure computations, since these reserve quantity estimates are the basis for the valuation process. The Company emphasizes that reserve estimates are inherently imprecise and that estimates of new discoveries and undeveloped locations are more imprecise than estimates of established proved producing oil and gas properties. The standardized measure of discounted future net cash flows does not purport, nor should it be interpreted, to present the fair value of the Company’s oil and natural gas reserves. An estimate of fair value would also take into account, among other things, the recovery of reserves not presently classified as proved, anticipated future changes in prices and costs and a discount factor more representative of the time value of money and the risks inherent in reserve estimates.

The following summary sets forth the Company’s future net cash flows relating to proved oil, natural gas and NGL reserves based on the standardized measure prescribed in ASC Topic 932:

 

     As of September 30,  
     2017      2016  

Future crude oil, natural gas and NGLs sales

   $ 562,349      $ 114,836  

Future production costs

     (156,563      (45,446

Future development costs

     (42,849      (14,299

Future income tax expense (1)

     (2,953      (4,993
  

 

 

    

 

 

 

Future net cash flows

     359,984        50,098  
  

 

 

    

 

 

 

10% annual discount

     (216,797      (30,974
  

 

 

    

 

 

 

Standardized measure of discounted future net cash flows

   $ 143,187      $ 19,124  
  

 

 

    

 

 

 

 

(1)

The Company’s calculations of the standardized measure of discounted future net cash flows as of September 30, 2017 includes the Company’s obligation for Texas Margin Tax, but excludes the effect of estimated future income tax expenses as the Company is a limited liability company and not subject to income taxes. The standardized measure of discounted future net cash flows as of September 30, 2016 (the Company’s predecessor fiscal year end) includes estimated income tax and Texas Margin Tax as the Company’s predecessor was a taxable entity under provisions of the Internal Revenue Code.

 

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The following are the principal sources of change in the Standardized Measure:

 

    

Years Ended

September 30,

 
     2017      2016  

Balance at beginning of period

   $ 19,124      $ 11,813  

Sales of crude oil, natural gas and NGLs, net

     (15,223      (1,158

Net change in prices and production costs

     18,491        (8,349

Net changes in future development costs

     (1,307      802  

Extensions, discoveries, and other additions

     29,241        7,250  

Acquisition of reserves

     43,718        3,294  

Revisions of previous quantity estimates

     28,676        2,623  

Previously estimated development costs incurred

     4,491        2,539  

Net change in income taxes

     81        (1,217

Accretion of discount

     4,792        1,220  

Other

     11,103        307  
  

 

 

    

 

 

 

Balance at end of period

   $ 143,187      $ 19,124  
  

 

 

    

 

 

 

 

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Independent Auditor’s Report

Riley Exploration—Permian, LLC

Oklahoma City, Oklahoma

We have audited the accompanying combined statements of revenues and direct operating expenses of the working interests acquired by Riley Exploration—Permian, LLC from Boomer Petroleum LLC, Dernick Encore, LLC, Murfin Drilling Company, Inc. and Pacesetter Energy Permian Basin, LLC (the “Acquired Properties”), as defined in Note 1, for the years ended December 31, 2016 and 2015, and the related notes to the combined statements of revenues and direct operating expenses.

Management’s Responsibility for the Financial Statements

Management is responsible for the preparation and fair presentation of the statements of revenues and direct operating expenses in accordance with accounting principles generally accepted in the United States of America; this includes the design, implementation, and maintenance of internal control relevant to the preparation and fair presentation of the combined statements of revenues and direct operating expenses that are free from material misstatement, whether due to fraud or error.

Auditor’s Responsibility

Our responsibility is to express an opinion on the combined statements of revenues and direct operating expenses based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the combined statements of revenues and direct operating expenses are free from material misstatement.

An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the statement of revenues and direct operating expenses. The procedures selected depend on the auditor’s judgment, including the assessment of the risks of material misstatement of the statement of revenues and direct operating expenses, whether due to fraud or error. In making those risk assessments, the auditor considers internal control relevant to the entity’s preparation and fair presentation of the statement of revenues and direct operating expenses in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the entity’s internal control. Accordingly, we express no such opinion. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of significant accounting estimates made by management, as well as evaluating the overall presentation of the statement of revenues and direct operating expenses.

We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our audit opinion.

Opinion

In our opinion, the combined statements of revenues and direct operating expenses referred to above present fairly, in all material respects, the revenues and direct operating expenses of the Acquired Properties for the years ended December 31, 2016 and 2015 in conformity with accounting principles generally accepted in the United States of America.

Emphasis of Matter

The accompanying combined statements of revenues and direct operating expenses were prepared for the purpose of complying with the rules and regulations of the Securities and Exchange Commission and are not

 

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intended to be a complete presentation of the results of the operations of the Acquired Properties. Our opinion is not modified with respect to this matter.

/s/ BDO USA, LLP

Houston, Texas

September 22, 2017

 

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Combined Statements of Revenues and Direct Operating

Expenses of the Oil and Natural Gas Properties Acquired and to be Acquired by

Riley Exploration—Permian, LLC

 

     Years Ended
December 31,
 
     2016      2015  
     (In Thousands)  

Revenues:

  

Oil sales

   $ 8,855      $ 793  

Natural gas sales

     114        18  

Natural gas liquid sales

     91        —    
  

 

 

    

 

 

 

Total revenues

     9,060        811  

Direct operating expenses:

     

Lease operating expenses

     4,994        840  

Exploration expense

     21        643  

Production taxes

     432        39  
  

 

 

    

 

 

 

Total direct operating expenses

     5,447        1,522  
  

 

 

    

 

 

 

Excess (deficit) of revenues over direct operating expenses

   $ 3,613      $ (711
  

 

 

    

 

 

 

The accompanying notes are an integral part of this statement of revenues and direct operating expenses.

 

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Combined Statements of Revenues and Direct Operating

Expenses of the Oil and Natural Gas Properties Acquired and to be Acquired by

Riley Exploration—Permian, LLC

(Amounts in thousands)

Note 1. The Properties

In April 2015, Riley Exploration Group Inc. (“REG”) acquired a 32% working interest in certain leases located in Yoakum County, Texas and established an area of mutual interest (the “Champions AMI”) with various companies including, Boomer Petroleum LLC (“Boomer”), Dernick Encore, LLC (“Dernick”), Murfin Drilling Company, Inc. (“Murfin”) and Pacesetter Energy Permian Basin, LLC (“Pacesetter”). On December 31, 2015, REG acquired Murfin’s approximately 3% working interest, and on January 22, 2016 REG acquired Pacesetter’s approximately 8% working interest in the Champions AMI for approximately $2,034 and $6,463, respectively. On January 17, 2017, REG and Boomer contributed their respective 42.7% and 28.0% working interests in oil and natural gas properties and related assets and liabilities of the Champions Assets to Riley Exploration—Permian, LLC (“Riley Permian”), a newly-formed subsidiary of REG. In addition, on March 6, 2017, Bluescape and Dernick contributed their combined 29.3% working interests in the oil and natural gas properties and related assets and liabilities of the Champions Assets to the Company in exchange for our common units.

The Combined Statements of Revenue and Direct Operating Expenses for the years ended December 31, 2016 and 2015 include the revenues and direct operating expenses for: (i) Murfin and Pacesetter’s working interests in the Champions AMI from January 1, 2015 until the dates that REG acquired them, and (ii) Boomer and Dernick’s working interests in the Champions AMI for the years ended December 31, 2016 and 2015. These working interests acquired by Riley Permian from Murfin, Pacesetter, Boomer and Dernick, are herein referenced as the “Acquired Properties.”

Note 2. Summary of Significant Accounting Policies

Basis of Presentation

The revenues and direct operating expenses presented herein are on the accrual basis of accounting, and reflect only the interests in the Acquired Properties. During the periods presented, the financial statements of the Acquired Properties were never prepared on a stand-alone basis. Certain costs, such as depreciation, depletion and amortization, accretion, general and administrative expenses, interest and corporate income taxes were not allocated to the individual properties. The financial statements presented are not indicative of the results of operations of the properties described above going forward due to the omission of these various operating expenses.

The accompanying audited statements are prepared in conformity with accounting principles generally accepted in the United States, which requires management to make estimates and assumptions that affect the amounts reported in the Combined Statement of Revenues and Direct Operating Expenses. Actual results could be different from those estimates.

Revenue Recognition

Revenue is recognized when it is realized or realizable and earned. Revenues are considered realized or realizable and earned when: (i) persuasive evidence of an arrangement exists, (ii) delivery has occurred or services have been rendered, (iii) the seller’s price to the buyer is fixed or determinable, and (iv) collectability is reasonably assured.

Revenue is recognized for oil and natural gas production when the quantities are delivered to or collected by the purchaser, using the sales method. The sales prices for such production, net of transportation costs, are defined in sales contracts and are readily determinable based on certain publicly available indices. All transportation costs are included in lease operating expense.

 

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To the extent actual volumes and prices of oil and natural gas are unavailable for a given reporting period because of timing or information not received from third parties, the expected sales volume and prices for these properties are estimated and recorded within revenue in the accompanying combined statement of revenues and direct operating expenses. Crude oil is priced on the delivery date based upon prevailing prices published by purchasers with certain adjustments related to oil quality and physical location. Natural gas contracts’ pricing provisions are tied to a market index, with certain adjustments based on, among other factors, whether a well delivers to a gathering or transmission line, quality and heat content of natural gas, and prevailing supply and demand conditions. These market indices are determined on a monthly basis.

Direct Operating Expenses

Direct operating expenses are recognized when incurred and consist of direct expenses of operating the Acquired Properties. The direct operating expenses include lease operating, production taxes, processing and transportation expenses. Lease operating expenses include lifting costs, well repair expenses, facility maintenance expenses, well workover costs, and other field-related expenses. Lease operating expenses also include expenses directly associated with support personnel, support services, equipment, and facilities directly related to oil and gas production activities.

New accounting pronouncement

In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers (Topic 256). 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. The update allows for both retrospective and modified-retrospective methods of adoption. We are currently evaluating the impact of this new standard.

Note 3. Commitments and Contingencies

Pursuant to the terms of the definitive agreements among Riley Permian, REG, Boomer and Dernick, any claims, litigation or disputes pending as of the effective date of the acquisitions of Boomer and Dernick by Riley Permian, October 1, 2016, and any matters arising in connection with ownership of the Champions AMI prior to the effective date are retained by REG, Boomer and Dernick, as the case may be. Notwithstanding this indemnification, Management is not aware of any legal, environmental or other commitments or contingencies that would have a material effect on the Combined Statement of Revenue and Direct Operating Expenses.

Note 4. Subsequent Events

Management has evaluated subsequent events through September 22, 2017, the date on which these financial statements were available for issuance, and there are no further subsequent events to report at this time.

Supplementary Oil and Gas Disclosures (Unaudited)

Supplemental reserve information

The following unaudited supplemental reserve information summarizes the proved reserves of oil and natural gas and the standardized measure thereof. All of the reserves are located in the United States. The tables below reflect the reserves attributable to the Acquired Properties with the removal of the Murfin and Pacesetter reserves

 

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when their interests were acquired by REG in 2015 and 2016. Proved oil, natural gas liquids (“NGLs”) and natural gas reserve quantities are derived from estimates prepared by Netherland, Sewell & Associates, Inc. and from information provided by management for the fiscal year ended September 30, 2017 and for the periods prior, they were prepared by qualified petroleum engineers on our staff and are reflective of the carved-out stand-alone interest of the properties contributed by REG. The estimates have been prepared in accordance with the definitions and regulations of the U.S. Securities and Exchange Commission (SEC) and, with the exception of the exclusion of future income taxes, conform to the FASB Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas.

The oil volumes shown include crude oil only. Oil and natural gas liquids (NGL) volumes are expressed in thousands of barrels (MBBL); a barrel is equivalent to 42 United States gallons. Gas volumes are expressed in millions of cubic feet (MMCF) at standard temperature and pressure bases. Oil equivalent volumes shown in this report are expressed in thousands of barrels of oil equivalent (MBOE), determined using the ratio of 6 MCF of gas to 1 barrel of oil.

There are numerous uncertainties inherent in estimating quantities and values of proved reserves and in projecting future rates of production and the amount and timing of development expenditures, including many factors beyond management’s control. Reserve engineering is a subjective process of estimating the recovery from underground accumulations of oil and gas that cannot be measured in an exact manner, and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Because all reserve estimates are to some degree subjective, the quantities of oil and gas that are ultimately recovered, production and operating costs, the amount and timing of future development expenditures and future oil and gas sales prices may each differ from those assumed in these estimates. In addition, the different reserve engineers may make different estimates of reserve quantities and cash flows based upon the same available data. The standardized measure shown below represents estimates only and should not be construed as the current market value of the estimated oil and gas reserves attributable to the Acquired Properties. In this regard, the information set forth in the following tables includes revisions of reserve estimates attributable to proved properties included in the preceding year’s estimates. Such revisions reflect additional information from subsequent development activities, production history of the Acquired Properties and any adjustments in the projected economic life of such property resulting from changes in product prices.

 

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Oil and Natural Gas Reserve Information

The following table sets forth certain data pertaining to the Acquired Properties’ proved reserves with the removal of the Murfin and Pacesetter reserves when their interests were acquired by REG in 2015 and 2016.

 

     Crude Oil
(MBbl)
    Natural Gas
(MMcf)
    Natural Gas
Liquids
(Mbbl)
    Total
(MBOE)
 

TOTAL PROVED RESERVES:

        

January 1, 2015

     —         —         —         —    

Extensions and discoveries

     2,036       1,572       —         2,298  

Revisions of previous estimates

     —         —         —         —    

Purchases of minerals in place

     —         —         —         —    

Sales of minerals in place

     (93     (33     —         (98

Production

     (21     (12     —         (23
  

 

 

   

 

 

   

 

 

   

 

 

 

December 31, 2015

     1,922       1,527       —         2,177  

Extensions and discoveries

     2,168       770       218       2,514  

Revisions of previous estimates

     256       (777     191       318  

Purchases of minerals in place

     —         —         —         —    

Sales of minerals in place

     (279     (98     (35     (330

Production

     (224     (59     (5     (239
  

 

 

   

 

 

   

 

 

   

 

 

 

December 31, 2016

     3,843       1,363       369       4,440  
  

 

 

   

 

 

   

 

 

   

 

 

 

PROVED DEVELOPED RESERVES

        

December 31, 2015

        

Proved developed producing

     680       471       —         759  

Proved developed non-producing

     —         —         —         —    
  

 

 

   

 

 

   

 

 

   

 

 

 

Total

     680       471       —         759  
  

 

 

   

 

 

   

 

 

   

 

 

 

December 31, 2016

        

Proved developed producing

     1,227       414       114       1,410  

Proved developed non-producing

     713       287       77       838  
  

 

 

   

 

 

   

 

 

   

 

 

 

Total

     1,940       701       191       2,248  
  

 

 

   

 

 

   

 

 

   

 

 

 

For the year ended December 31, 2015, the Company reported extensions and discoveries of 2,298 MBoe due to non-operated offset development in the core area. New drilling activity led to additional PUDs being booked and an increase in the initial type curve for the area. Additionally, during 2015 the Acquired Properties sold reserves of 98 MBoe.

For the year ended December 31, 2016, the Acquired Properties had upward revisions of previous estimates of 318 MBoe. These revisions are the result of actual well performance from new wells that exceeded previous estimates. Along with the gas sales, the Company received revenue for plant products and was able to add NGL volumes to proved reserves. As a result of ongoing drilling and completion activities during 2016, the Acquired Properties reported extensions and discoveries of 2,514 MBoe. Additionally, during 2016 the Acquired Properties sold reserves of 330 MBoe.

 

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Standardized Measure of Discounted Future Net Cash Flows

The Standardized Measure of Discounted Future Net Cash Flows relating to the Acquired Properties’ proved crude oil and gas reserves with the removal of the Murfin and Pacesetter reserves when their interests were acquired by REG in 2015 and 2016 is presented below:

 

     As of December 31,  
     2016      2015  

Future cash inflows

   $ 153,130      $ 86,547  

Future production costs (Prod Tax, LOE, Taxes and Other)

     (60,127      (22,811

Future development costs (Net Total Inv)

     (18,508      (12,247

Future income tax expense

     (574      (387
  

 

 

    

 

 

 

Future net cash flows

     73,921        51,102  

10% annual discount for estimated timing of cash flows

     (46,045      (29,030
  

 

 

    

 

 

 

Standardized measure of discounted future net cash flows

   $ 27,876      $ 22,072  
  

 

 

    

 

 

 

Future income tax expense presented in the table above represents future state margin tax.

The following are the principal sources of change in the standardized measures of discounted future cash flows for the years ended December 31, 2016 and 2015:

 

     Years ended December 31,  
         2016              2015      

Beginning Balance

   $ 22,072      $ —    

Net changes in prices and production costs

     (10,189      —    

Net changes in future development costs

     1,307        —    

Sales of oil and gas produced, net of production costs

     (3,634      68  

Revisions of previous quantity estimates

     2,537        —    

Extensions, discoveries and improved recovery

     11,300        21,762  

Sales of minerals in place

     (1,017      (653

Previously estimated development costs incurred

     4,440        —    

Net change in income taxes

     (71      (177

Accretion of discount

     2,084        1,072  

Other

     (953      —    
  

 

 

    

 

 

 

Ending Balance

   $ 27,876      $ 22,072  
  

 

 

    

 

 

 

 

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APPENDIX A—GLOSSARY OF OIL AND GAS TERMS

The terms defined in this section are used with or without capitalization throughout this prospectus:

“Bbl” means one stock tank barrel, or 42 U.S. gallons liquid volume, used in reference to oil or other liquid hydrocarbons.

“Bbl/d” means Bbl per day.

“BOE” means barrels of oil equivalent. Oil equivalents are determined using the ratio of six Mcf of gas (including gas liquids) to one Bbl of oil.

“BOE/d” means BOE per day.

“Btu” means one British thermal unit—a measure of the amount of energy required to raise the temperature of a one-pound mass of water one degree Fahrenheit at sea level.

“Completion” means the installation of permanent equipment for the production of oil or natural gas.

“Developed acreage” means acres spaced or assigned to productive wells and does not include undrilled acreage held by production under the terms of the lease.

“Development well” means a well drilled to a known producing formation in a previously discovered field, usually offsetting a producing well on the same or an adjacent oil and natural gas lease.

“Dry hole” means a well found to be incapable of producing either oil or gas in sufficient quantities to justify completion as an oil or gas well.

“Exploratory well” means a well drilled either (a) in search of a new and as yet undiscovered pool of oil or gas or (b) with the hope of significantly extending the limits of a pool already developed (also known as a “wildcat well”).

“EUR” means estimated ultimate recovery based on an approximation of the quantity of oil or gas that is potentially recoverable or has already been recovered from a reserve or well.

“Field” means an area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature or stratigraphic condition.

“Fracturing” means mechanically inducing a crack or surface of breakage within rock not related to foliation or cleavage in metamorphic rock in order to enhance the permeability of rocks greatly by connecting pores together.

“Gas” or “Natural gas” means the lighter hydrocarbons and associated non-hydrocarbon substances occurring naturally in an underground reservoir, which under atmospheric conditions are essentially gases but which may contain liquids.

“Gross Acres” or “Gross Wells” means the total acres or wells, as the case may be, in which we have a working interest.

“Hydraulic fracturing” means a procedure to stimulate production by forcing a mixture of fluid and proppant (usually sand) into the formation under high pressure. This creates artificial fractures in the reservoir rock, which increases 1 permeability and porosity.

“Horizontal drilling” means a wellbore that is drilled laterally.

“Leases” means full or partial interests in oil or gas properties authorizing the owner of the lease to drill for, produce and sell oil and natural gas in exchange for any or all of rental, bonus and royalty payments. Leases are generally acquired from private landowners (fee leases) and from federal and state governments on acreage held by them.

 

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“MBbl” One thousand barrels of oil, condensate or NGLs.

“MBoe” One thousand barrels of oil equivalent. Oil equivalents are determined using the ratio of six Mcf of gas (including gas liquids) to one Bbl of oil.

“MBoe/d” means MBoe per day.

“Mcf” is an abbreviation for “1,000 cubic feet,” which is a unit of measurement of volume for natural gas.

“MMBbl” One million barrels of oil, condensate or NGLs.

“MMBtu” One million Btus.

“MMcf” is an abbreviation for “1,000,000 cubic feet,” which is a unit of measurement of volume for natural gas.

“Net Acres” or “Net Wells” is the sum of the fractional working interests owned in gross acres or wells, as the case may be, expressed as whole numbers and fractions thereof.

“Net revenue interest” means all of the working interests less all royalties, overriding royalties, non-participating royalties, net profits interest or similar burdens on or measured by production from oil and natural gas.

“NGL” means natural gas liquids.

“NYMEX” means New York Mercantile Exchange.

“Overriding royalty” means an interest in the gross revenues or production over and above the landowner’s royalty carved out of the working interest and also unencumbered with any expenses of operation, development or maintenance.

“Operator” means the individual or company responsible to the working interest owners for the exploration, development and production of an oil or natural gas well or lease.

“Play” or “play” means a regionally distributed oil and natural gas accumulation. Resource plays are characterized by continuous, aerially extensive hydrocarbon accumulations in tight sand, shale and coal reservoirs.

“Possible Reserves” means reserves that are less certain to be recovered than probable reserves.

“Prospect” means a geological area which is believed to have the potential for oil and natural gas production.

“Productive well” means a well that is producing oil or gas or that is capable of production.

“Probable Reserves” means reserves that are less certain to be recovered than proved reserves but that, together with proved reserves, are as likely as not to be recovered.

“Proved developed reserves” means reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.

“Proved reserves” means the estimated quantities of oil, gas and gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions.

“Proved undeveloped reserves” means reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

 

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“PV-10 value” means the present value of estimated future gross revenue to be generated from the production of estimated net proved reserves, net of estimated production and future development costs, using prices and costs in effect as of the date indicated (unless such prices or costs are subject to change pursuant to contractual provisions), without giving effect to non-property related expenses such as general and administrative expenses, debt service and future income tax expenses or to depreciation, depletion and amortization, discounted using an annual discount rate of 10 percent. While this measure does not include the effect of income taxes as it would in the use of the standardized measure calculation, it does provide an indicative representation of the relative value of the Company on a comparative basis to other companies and from period to period.

“Recompletion” means the completion for production from an existing wellbore in a formation other than that in which the well has previously been completed.

“Reservoir” means a porous and permeable underground formation containing a natural accumulation of producible natural gas and/or oil that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.

“Royalty” means the share paid to the owner of mineral rights, expressed as a percentage of gross income from oil and natural gas produced and sold unencumbered by expenses relating to the drilling, completing and operating of the affected well.

“Royalty interest” means an interest in an oil and natural gas property entitling the owner to shares of oil and natural gas production, free of costs of exploration, development and production operations.

“SEC pricing” means the price per Bbl for oil or per MMBtu for natural gas as calculated from the unweighted arithmetic average first-day-of-the-month prices for the prior 12 months, as adjusted by lease for quality, transportation fees, geographical differentials, marketing bonuses or deductions and other factors affecting the price received at the wellhead.

“Section” means 640 acres.

“Seismic Data” means an exploration method of sending energy waves or sound waves into the earth and recording the wave reflections to indicate the type, size, shape and depth of a subsurface rock formation. 2-D seismic provides two-dimensional information and 3-D seismic provides three-dimensional views.

“Spacing” means the distance between wells producing from the same reservoir. Spacing is often expressed in terms of acres, e.g., 40-acre spacing, and is often established by regulatory agencies.

“Undeveloped acreage” means lease acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and gas regardless of whether or not such acreage contains proved reserves.

“Undeveloped leasehold acreage” means the leased 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 estimated net proved reserves.

“Unit” means the joining of all or substantially all interests in a reservoir or field, rather than a single tract, to provide for development and operation without regard to separate property interests. Also, the area covered by a unitization agreement.

“Working interest” means an interest in an oil and natural gas lease entitling the holder at its expense to conduct drilling and production operations on the leased property and to receive the net revenues attributable to such interest, after deducting the landowner’s royalty, any overriding royalties, production costs, taxes and other costs.

WTI” means the price of West Texas Intermediate oil on the NYMEX.

 

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Part II

INFORMATION NOT REQUIRED IN PROSPECTUS

Item 13. Other expenses of issuance and distribution

The following table sets forth an itemized statement of the amounts of all expenses (excluding underwriting discounts and commissions) payable by us in connection with the registration of the common stock offered hereby. With the exception of the SEC registration fee, FINRA filing fee and NYSE American listing fee, the amounts set forth below are estimates.

 

SEC Registration Fee

   $ 14,317.50  

FINRA Filing Fee

     17,750  

NYSE American Listing Fee

     *  

Accountants’ fees and expenses

     *  

Legal fees and expenses

     *  

Printing and Engraving Expenses

     *  

Transfer agent and registrar expenses

     *  

Miscellaneous

     *  
  

 

 

 

Total

   $ *  
  

 

 

 

 

*

To be provided by amendment.

Item 14. Indemnification of Directors and Officers

Our certificate of incorporation will provide that, to the fullest extent permitted by the DGCL, a director will not be liable to the corporation or its stockholders for monetary damages or for breach of fiduciary duty as a director, except to the extent such exemption from liability or limitation thereof is not permitted under the DGCL as it now exists. In addition, if the DGCL is amended to authorize the further elimination or limitation of the liability of directors, then the liability of a director of the corporation, in addition to the limitation on personal liability provided for in our certificate of incorporation, will be limited to the fullest extent permitted by the amended DGCL. Our bylaws will provide that the corporation will indemnify, and advance expenses to, any officer or director to the fullest extent authorized by the DGCL.

Section 145 of the DGCL provides that a corporation may indemnify directors and officers as well as other employees and individuals against expenses, including attorneys’ fees, judgments, fines and amounts paid in settlement in connection with specified actions, suits and proceedings whether civil, criminal, administrative, or investigative, other than a derivative action by or in the right of the corporation, if they acted in good faith and in a manner they reasonably believed to be in or not opposed to the best interests of the corporation and, with respect to any criminal action or proceeding, had no reasonable cause to believe their conduct was unlawful. A similar standard is applicable in the case of derivative actions, except that indemnification extends only to expenses, including attorneys’ fees, incurred in connection with the defense or settlement of such action and the statute requires court approval before there can be any indemnification where the person seeking indemnification has been found liable to the corporation. The statute provides that it is not exclusive of other indemnification that may be granted by a corporation’s certificate of incorporation, bylaws, disinterested director vote, shareholder vote, agreement or otherwise.

Our bylaws will also contain indemnification rights for our directors and our officers. Specifically, our bylaws will provide that we shall indemnify our officers and directors to the fullest extent authorized by the DGCL. Further, we shall maintain insurance on behalf of our officers and directors against expense, liability or loss asserted incurred by them in their capacities as officers and directors.

After completion of our initial public offering, we will evaluate our existing directors’ and officers’ liability insurance coverage and make such adjustments as we deem appropriate.

 

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Upon completion of this offering, we intend to enter into indemnification agreements with each of our directors and executive officers. Under these agreements, if an executive officer or director makes a claim of indemnification to us, either a majority of disinterested directors or independent legal counsel selected by the board of directors must review the relevant facts and make a determination whether the officer or director has met the standards of conduct under Delaware law that would permit (under Delaware law) and require (under the indemnification agreement) us to indemnify the officer or director within 45 days of the request for indemnification. In making a determination with respect to entitlement to indemnification, the indemnitee shall be presumed to be entitled to full indemnification thereunder, and we shall have the burden of proof in the making of any determination contrary to such presumption. If our board of directors or the independent counsel, as applicable, shall have failed to make a determination as to entitlement to indemnification within 45 days after receipt by us of such request for indemnification, the requisite determination of entitlement to indemnification shall be deemed to have been made and the indemnitee shall be absolutely entitled to such indemnification, absent actual and material fraud in the request for indemnification, a prohibition of indemnification under applicable law in effect as of the date of the indemnification agreement, or a subsequent determination that such indemnification is prohibited by applicable law.

Our indemnification agreements will also provide that in the event that the indemnitee is an affiliate of or associated with one of our shareholders (an “Affiliated Stockholder”), then such Affiliated Stockholder and its officers, directors, managers, partners, employees, agents, representatives and controlling persons (collectively, the “Affiliated Stockholder Parties” and individually, an “Affiliated Stockholder Party”) shall be indemnified and held harmless by us from and against any and all losses, claims, damages, liabilities, joint or several, judgments, fines, penalties, interest, settlements and other amounts arising from any and all claims, demands, actions or proceedings in which any such Affiliated Stockholder Party may be involved, or is threatened to be involved, as a party or otherwise, by reason of such person’s status as an Affiliated Stockholder Party or otherwise by virtue of the fact that the Affiliated Stockholder is a shareholder or former shareholder or other equity owner of us or any of our direct or indirect subsidiaries or our or their predecessors (regardless, in the case of a subsidiary of whether it was a subsidiary of us at the time the facts relating to such proceeding arose) (the “Related Entities”) or by virtue of actions taken or omissions by the Affiliated Stockholder or any Affiliated Stockholder Party related to the Company or any of the Related Entities.

The underwriting agreement provides for indemnification by the underwriters of us and our officers and directors, and by us of the underwriters, for certain liabilities arising under the Securities Act or otherwise in connection with this offering.

Item 15. Recent Sales of Unregistered Securities

In connection with the completion of this offering, Riley Exploration—Permian, LLC will merge with and into us and we will be the surviving entity to such merger, with the equity holders in Riley Exploration—Permian, LLC, including the holders of restricted units and incentive units, if any, receiving shares of our common stock using an implied equity valuation for us prior to the offering based on the initial public offering price for our common stock set forth on the cover page of the prospectus forming a part of this registration statement and the current relative levels of ownership in Riley Exploration—Permian, LLC, pursuant to the terms of the governing documents including the limited liability company agreement of Riley Exploration—Permian, LLC.

The issuance of such shares of our common stock will not involve any underwriters, underwriting discounts or commissions or a public offering, and we believe that such issuance will be exempt from registration requirements pursuant to Section 4(a)(2) of the Securities Act of 1933, as amended.

Item 16. Exhibits and financial statement schedules

 

  (a)

See the Exhibit Index on the page immediately preceding the signature page and exhibits for a list of exhibits filed as part of this registration statement, which Exhibit Index is incorporated herein by reference.

 

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  (b)

Financial Statement Schedules. Financial statement schedules are omitted because the required information is not applicable, not required or included in the financial statements or the notes thereto included in the prospectus that forms a part of this registration statement.

Item 17. Undertakings

The undersigned registrant hereby undertakes to provide to the underwriters at the closing specified in the underwriting agreement certificates in such denominations and registered in such names as required by the underwriters to permit prompt delivery to each purchaser.

Insofar as indemnification for liabilities arising under the Securities Act may be permitted to directors, officers and controlling persons of the registrant pursuant to the foregoing provisions, or otherwise, the registrant has been advised that in the opinion of the SEC such indemnification is against public policy as expressed in the Securities Act and is, therefore, unenforceable. In the event that a claim for indemnification against such liabilities s (other than the payment by the registrant of expenses incurred or paid by a director, officer or controlling person of the registrant in the successful defense of any action, suit or proceeding) is asserted by such director, officer or controlling person in connection with the securities being registered, the registrant will, unless in the opinion of its counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction the question whether such indemnification by it is against public policy as expressed in the Securities Act and will be governed by the final adjudication of such issue.

The undersigned registrant hereby undertakes that:

 

1)

For purposes of determining any liability under the Securities Act, the information omitted from the form of prospectus filed as part of this registration statement in reliance upon Rule 430 A and contained in a form of prospectus filed by the registrant pursuant to Rule 424(b)(1) or (4) or 497(h) under the Securities Act shall be deemed to be part of this registration statement as of the time it was declared effective.

 

2)

For the purpose of determining any liability under the Securities Act, each post-effective amendment that contains a form of prospectus shall be deemed to be a new registration statement relating to the securities offered therein, and the offering of such securities at that time shall be deemed to be the initial bona fide offering thereof.

 

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INDEX TO EXHIBITS

 

Exhibit

Number

 

Description

      *1.1   Form of Underwriting Agreement
    **2.1   Form of Plan of Conversion
    **2.2   Form of Certificate of Conversion
    **3.1   Form of Certificate of Incorporation of Riley Exploration Permian, Inc.
    **3.2   Form of Bylaws of Riley Exploration Permian, Inc.
      *4.1   Form of Second Amended and Restated Registration Rights Agreement
      *4.2   Form of Common Stock Certificate
      *5.1   Opinion of di Santo Law PLLC as to the legality of the securities being registered
  **10.1   Credit Agreement, dated as of September 28, 2017, by and among Riley Exploration—Permian, LLC, as borrower, SunTrust Bank, as administrative agent, and the lenders party thereto
  **10.2   Amendment No. 1, dated as of February 27, 2018 to Credit Agreement, dated as of September  28, 2017, by and among Riley Exploration—Permian, LLC, as borrower, SunTrust Bank, as administrative agent, and the lenders party thereto
    *10.3   Form of Riley Exploration Permian, Inc. 2018 Long Term Incentive Plan
  **10.4   Purchase and Sale Agreement, dated as of March 27, 2018, by and between Riley Exploration—Permian, LLC and Rockcliff Operating New Mexico LLC
  **10.5   Purchase and Sale Agreement, dated as of April 12, 2018, by and between Riley Exploration—Permian, LLC and Tierra Oil Company, LLC
  **10.6   Purchase and Sale Agreement, dated as of April 12, 2018, by and between Riley Exploration—Permian, LLC and Energex, LLC
  **10.7   Purchase and Sale Agreement, dated as of May 1, 2018, by and between Riley Exploration—Permian, LLC and Pedregosa Partners, LLC
    *10.8   Form of Indemnification Agreement
  **10.9   Borrowing Base Notification dated as of May 24, 2018 and effective as of 2018, pursuant to Credit Agreement, dated as of September 28, 2017, by and among Riley Exploration—Permian, LLC, as borrower, SunTrust Bank, as administrative agent, and the lenders party thereto
    *10.10   Form of Restricted Stock Agreement
    *10.11   Form of Employment Agreement
  **21.1   List of subsidiaries of Riley Exploration Permian, Inc.
  **23.1   Consent of BDO USA, LLP
  **23.2   Consent of Netherland, Sewell & Associates, Inc.
    *23.3   Consent of di Santo Law PLLC (included as part of Exhibit 5.1 hereto)
  **23.4   Consent of BDO USA, LLP
  **24.1   Power of Attorney (included on the signature page of this Registration Statement)
  **99.1   Report of Netherland, Sewell & Associates, Inc. for reserves as of September 30, 2017
  **99.2   Consent of Director Nominee—Nelson M. Haight
  **99.3   Consent of Director Nominee—E. Wayne Nordberg

 

*

To be filed by amendment.

**

Filed herewith.

 

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SIGNATURES

Pursuant to the requirements of the Securities Act of 1933, the registrant has duly caused this registration statement to be signed on its behalf by the undersigned, thereunto duly authorized, in Oklahoma City, State of Oklahoma, on September 19, 2018.

 

Riley Exploration—Permian, LLC
By:  

/s/ Bobby D. Riley

  Bobby D. Riley
  Chief Executive Officer

Each person whose signature appears below appoints Bobby D. Riley and Jeffrey M. Gutman and each of them, any of whom may act without the joinder of the other, as his or her true and lawful attorneys-in-fact and agents, with full power of substitution and resubstitution, for him or her and in his name, place and stead, in any and all capacities, to sign any and all amendments (including post-effective amendments) to this Registration Statement and any Registration Statement (including any amendment thereto) for this offering that is to be effective upon filing pursuant to Rule 462(b) under the Securities Act, and to file the same, with all exhibits thereto, and all other documents in connection therewith, with the SEC, granting unto said attorneys-in-fact and agents full power and authority to do and perform each and every act and thing requisite and necessary to be done, as fully to all intents and purposes as he or she might or would do in person, hereby ratifying and confirming all that said attorneys-in-fact and agents or any of them or their or his substitute or substitutes, may lawfully do or cause to be done by virtue hereof.

Pursuant to the requirements of the Securities Act, this Registration Statement has been signed below by the following persons in the capacities and the dates indicated.

 

Name

  

Title

 

Date

/s/ Bobby D. Riley

Bobby D. Riley

   Chief Executive Officer, President and Chairman (Principal Executive Officer)   September 19, 2018

/s/ Jeffrey M. Gutman

Jeffrey M. Gutman

   Executive Vice President, Chief Financial Officer and Treasurer (Principal Financial Officer and Principal Accounting Officer)   September 19, 2018

/s/ Bryan H. Lawrence

Bryan H. Lawrence

   Director   September 19, 2018

/s/ Philip Riley

Philip Riley

   Director   September 19, 2018

/s/ Antonie VandenBrink

Antonie VandenBrink

   Director   September 19, 2018

 

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