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EX-99.3 - EX-99.3 - Remora Royalties, Inc.d579098dex993.htm
EX-99.2 - EX-99.2 - Remora Royalties, Inc.d579098dex992.htm
EX-99.1 - EX-99.1 - Remora Royalties, Inc.d579098dex991.htm
EX-23.14 - EX-23.14 - Remora Royalties, Inc.d579098dex2314.htm
EX-23.13 - EX-23.13 - Remora Royalties, Inc.d579098dex2313.htm
EX-23.12 - EX-23.12 - Remora Royalties, Inc.d579098dex2312.htm
EX-23.11 - EX-23.11 - Remora Royalties, Inc.d579098dex2311.htm
EX-23.10 - EX-23.10 - Remora Royalties, Inc.d579098dex2310.htm
EX-23.9 - EX-23.9 - Remora Royalties, Inc.d579098dex239.htm
EX-23.7 - EX-23.7 - Remora Royalties, Inc.d579098dex237.htm
EX-23.6 - EX-23.6 - Remora Royalties, Inc.d579098dex236.htm
EX-23.5 - EX-23.5 - Remora Royalties, Inc.d579098dex235.htm
EX-23.4 - EX-23.4 - Remora Royalties, Inc.d579098dex234.htm
EX-23.3 - EX-23.3 - Remora Royalties, Inc.d579098dex233.htm
EX-23.2 - EX-23.2 - Remora Royalties, Inc.d579098dex232.htm
EX-23.1 - EX-23.1 - Remora Royalties, Inc.d579098dex231.htm
EX-21.1 - EX-21.1 - Remora Royalties, Inc.d579098dex211.htm
EX-16.1 - EX-16.1 - Remora Royalties, Inc.d579098dex161.htm
EX-5.1 - EX-5.1 - Remora Royalties, Inc.d579098dex51.htm
EX-3.2 - EX-3.2 - Remora Royalties, Inc.d579098dex32.htm
EX-3.1 - EX-3.1 - Remora Royalties, Inc.d579098dex31.htm
Table of Contents
Index to Financial Statements

As filed with the Securities and Exchange Commission on July 13, 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

 

 

Remora Royalties, Inc.

(Exact name of registrant as specified in its charter)

 

 

 

Delaware

(State or other jurisdiction

of incorporation or organization)

 

1311

(Primary standard industrial

classification code number)

 

82-5502778

(I.R.S. Employer

Identification Number)

 

807 Las Cimas Parkway, Suite 275

Austin, Texas 78746

(512) 579-3590

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

 

 

George B. Peyton V

Chief Executive Officer

807 Las Cimas Parkway, Suite 275

Austin, Texas 78746

(512) 579-3590

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

 

 

Copies to:

 

George J. Vlahakos   Ryan J. Maierson
Jon W. Daly   John M. Greer
Sidley Austin LLP   Latham & Watkins LLP
1000 Louisiana Street, Suite 6000   811 Main Street, Suite 3700
Houston, Texas 77002   Houston, Texas 77002
(713) 495-4500   (713) 546-5400

 

 

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, 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, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.  ☐


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Index to Financial Statements

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, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer”, “smaller reporting company” and “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

Class A common stock, par value $0.01 per share

  $100,000,000   $12,450.00

 

 

(1)   Includes shares of Class A common stock issuable upon exercise of the underwriters’ over-allotment option to purchase additional shares of Class A 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 that 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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Index to Financial Statements

The information in this prospectus is not complete and may be changed. These securities may not be sold 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 jurisdiction where the offer or sale is not permitted.

 

SUBJECT TO COMPLETION, DATED JULY 13, 2018

             Shares

 

 

LOGO

Remora Royalties, Inc.

Class A Common Stock

 

 

This is the initial public offering of our Class A common stock. We are offering      shares of our Class A common stock in this offering. Prior to this offering, there has been no public market for our Class A common stock. We currently expect the initial public offering price to be between $     and $     per share. We have applied to list our Class A common stock on the Nasdaq Global Market (“NASDAQ”) under the symbol “RRI.” We are an “emerging growth company” as that term is used in the Jumpstart Our Business Startups Act.

Investing in our Class A common stock involves a high degree of risk. Before buying any shares of Class A common stock, you should carefully read the discussion of material risks of investing in our Class A common stock in “Risk Factors” beginning on page 29.

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.

 

 

 

     Per Share      Total  

Initial public offering price

   $                   $               

Underwriting discount(1)

   $      $  

Proceeds to Remora Royalties, Inc.
(before expenses)

   $      $  

 

(1)   Excludes an aggregate structuring fee equal to         % of the gross proceeds of this offering payable by us to RBC Capital Markets, LLC and Wells Fargo Securities, LLC. Please read “Underwriting.”

The underwriters may purchase up to an additional      shares of Class A common stock from us at the public offering price, less the underwriting discount, within 30 days from the date of this prospectus solely to cover over-allotments.

The underwriters expect to deliver the shares of Class A common stock to purchasers on or about     , 2018 through the book-entry facilities of The Depository Trust Company.

 

 

Joint Book-Running Managers

 

RBC Capital Markets  

Wells Fargo Securities

  UBS Investment Bank

Prospectus dated                         , 2018


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Index to Financial Statements

[Cover art to come]


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Index to Financial Statements

TABLE OF CONTENTS

 

 

 

 

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 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 Class A common stock and seeking offers to buy shares of Class A 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 Class A 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 read “Risk Factors” and “Forward-Looking Statements.”

Until             , 2018 (25 days after commencement of this offering), all dealers that effect transactions in these securities, whether or not participating in this offering, may be required to deliver a prospectus. This is in addition to the dealer’s obligation to deliver a prospectus when acting as an underwriter and with respect to unsold allotments or subscriptions.

 

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Index to Financial Statements

PRESENTATION OF FINANCIAL AND OPERATING DATA

Unless otherwise indicated, the historical financial information presented in this prospectus is that of our predecessor for accounting purposes, Remora Petroleum, L.P. (our “predecessor”). The pro forma financial information in this prospectus is derived from the unaudited pro forma condensed combined financial statements included elsewhere in this prospectus which reflect, among other things, (1) the financial statements of our predecessor; (2) the acquisition of assets to be contributed to our subsidiary, Remora Holdings, LLC, by Vendera Resources II, LLC and its affiliates, Vendera Resources III, L.P. and its affiliates and AVAD Energy Partners, LLC, which make up a portion of the Contributing Parties (as defined herein), (3) the acquisition by our predecessor of oil and natural gas properties in South Texas on December 19, 2017 (the “2017 South Texas Assets”) and (4) the retention by our predecessor of certain oil and natural gas properties and all other assets, liabilities and operations that will not be acquired by us in connection with this offering. Please read the unaudited pro forma condensed combined financial statements included elsewhere in this prospectus.

In addition, unless otherwise indicated, the reserve and operational data presented in this prospectus is with respect to all the assets that will be contributed to us by the Contributing Parties. Please read “Formation Transactions.”

INDUSTRY AND MARKET DATA

This prospectus includes industry data and forecasts that we obtained from internal company sources, publicly available information and industry publications and surveys. Our internal research and forecasts are based on management’s understanding of industry conditions, and such information has not been verified by independent sources. Industry publications, surveys and forecasts generally state that the information contained therein has been obtained from sources believed to be reliable. There can be no assurance as to the accuracy or completeness of the information presented herein derived from third party sources. Statements as to the industry or operator estimates and future activity are based on independent industry publications, government publications, third-party forecasts, public statements by the operators of our properties, management’s estimates and assumptions about our markets and our internal research. While we are not aware of any misstatements regarding such estimates or the market, industry, or similar data presented herein, such estimates and data involve risks and uncertainties and are subject to change based on various factors, including those discussed under the headings “Risk Factors” and “Forward-Looking Statements” in this prospectus, most of which are not within our control.

 

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SUMMARY

This summary highlights selected information contained elsewhere in this prospectus. It does not contain all the information you should consider before investing in our Class A common stock. You should carefully read the entire prospectus, including “Risk Factors” and the historical and unaudited pro forma condensed combined financial statements and related notes included elsewhere in this prospectus before making an investment decision. The information presented in this prospectus assumes an initial public offering price of $     per share (the mid-point of the price range set forth on the cover page of this prospectus) and, unless otherwise indicated, that the underwriters do not exercise their option to purchase additional shares of our Class A common stock.

Unless the context otherwise requires, references in this prospectus to the “Company,” “we,” “our,” “us” or like terms, when used in a historical context, refer to Remora Petroleum, L.P., our predecessor for accounting purposes, also referred to as “our Predecessor,” and when used in the present tense or prospectively, refer to Remora Royalties, Inc. and its subsidiaries (including Remora Holdings, LLC). References to “our Operating Affiliate”, when used in the present tense or prospectively, refer to Remora Petroleum, L.P. References to “Remora Holdings” or “RH” refer to Remora Holdings, LLC. References to the “Contributing Parties” refer to all entities, including our Operating Affiliate and its affiliates, that are contributing certain royalty interests to us. References to the “Other Principal Contributing Parties” refer to all entities that are contributing certain royalty interests to us, except our Operating Affiliate and its affiliates.

Remora Royalties, Inc.

Overview

We are a growth-oriented Delaware corporation formed to own and acquire overriding royalty, mineral and royalty interests in oil and natural gas properties. We refer to these non-cost-bearing interests, which entitle us to a portion of the revenues received from the production of oil, natural gas and associated natural gas liquids (“NGLs”) from the acreage underlying our interests, net of post-production expenses and taxes, collectively as our “royalty interests.” Our royalty interests are located in 12 states and in 13 major onshore basins across the continental United States and include ownership in approximately 3,600 gross producing wells, predominantly in the Midcontinent, South Texas/Gulf Coast, East Texas/North Louisiana and Permian Basin, which are among the most historically prolific oil and natural gas regions in the United States. The geographic breadth of our assets gives us exposure to potential production and reserves from new and existing plays.

As an owner of royalty interests, we benefit from the continued development of the properties in which we own an interest without the need for investment of additional capital by us. We are not obligated to fund drilling and completion costs, lease operating expenses, plugging and abandonment costs at the end of a well’s productive life, or any environmental liability costs. Our primary business objective is to provide increasing dividends to stockholders resulting from acquisitions and from organic growth through the continued development of the properties in which we own an interest.

As of December 31, 2017, on a pro forma basis, we owned royalty interests in approximately 593,000 gross acres (43,000 net acres), of which over 97% was held by production. For the year ended December 31, 2017, on a pro forma basis, approximately 75% of the net production underlying our royalty interests was from the Midcontinent, South Texas/Gulf Coast, East Texas/North Louisiana and Permian Basin. For the same period, the Contributing Parties operated approximately 46% of our net production, 788



 

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Index to Financial Statements

of our gross wells and approximately 57% of our net acreage. The Contributing Parties, which includes our largest operator by proved reserves, Remora Petroleum, L.P. (our Operating Affiliate), were formed in part to acquire and develop mature oil and natural gas properties. We expect further development on our acreage by the Contributing Parties and other working interest owners through recompletions, infill drilling, horizontal drilling, hydraulic fracturing and secondary and tertiary recovery methods.

We believe our Operating Affiliate’s significant ownership interest in us will incentivize it to sell us additional royalty interests at attractive prices from its current and future inventory of properties. We also believe our Operating Affiliate, through its continued ownership in the working interests of the underlying properties and significant ownership interest in us, will be further incentivized to pursue the development of its current and future properties that would benefit us directly through increased production. Our Operating Affiliate operated 541 of our wells as of December 31, 2017 and approximately 29% of our net production during 2017. Additionally, our Operating Affiliate operates 85% of our Proved Developed Non Producing (“PDNP”) reserves. Our Operating Affiliate was formed in 2011 by its management team and affiliates of NGP Energy Capital Management (“NGP”), a family of energy-focused private equity investment funds. Our Operating Affiliate is currently focused on the acquisition, development and exploitation of both conventional and unconventional oil and natural gas reserves in multiple onshore U.S. basins. Since inception, our Operating Affiliate has evaluated over 250 acquisition candidates, and has completed 43 property acquisitions and expects to continue acquiring properties for the benefit of itself and the Company. Our Operating Affiliate targets assets with a decline profile indicative of mature wells. We believe, based on publicly available data, that, as of December 31, 2017, there was production of approximately 34 Bcfe/d from wells in the lower 48 states that meet the decline profile targeted by our Operating Affiliate. We believe that operators are motivated to sell these mature and undervalued assets. As of December 31, 2017, on a pro forma basis, our Operating Affiliate owned approximately 123,000 net acres (97% held by production). For the year ended December 31, 2017, and on a pro forma basis, our Operating Affiliate had net production of 31.3 MMcfe/d and estimated proved reserves of 206 Bcfe (57.0% proved developed), according to Cawley, Gillespie & Associates, Inc. (“Cawley”), our independent petroleum engineering firm.

As of December 31, 2017, on a pro forma basis, the estimated proved oil, natural gas and NGL reserves attributable to our interests in our underlying acreage were 107.8 Bcfe (22.3% liquids, consisting of 12.3% oil and 10.0% NGLs) based on the reserve report prepared by Cawley. Of these reserves, 84.8% were classified as Proved Developed Producing (“PDP”) reserves, 6.1% were classified as PDNP reserves and 9.1% were classified as Proved Undeveloped (“PUD”) reserves. Our PDNP reserves included in this estimate are derived from 57 recompletion and workover projects, primarily located in the South Texas/Gulf Coast and East Texas/North Louisiana regions. Our PUD reserves included in this estimate are from 173 gross PUD locations, primarily located in the Arkoma STACK play. Additionally, the estimated probable oil, natural gas and NGL reserves attributable to our interests in our underlying acreage were 30.8 Bcfe (29.8% liquids), derived from 29 recompletion opportunities and 412 gross undeveloped locations. The producing properties underlying our royalty interests typically have low estimated decline rates. Our PDP reserves have an average estimated initial five-year decline rate of approximately 9.9%. For the year ended December 31, 2017, our average daily net production was 26.2 MMcfe/d.

For the year ended December 31, 2017, on a pro forma basis, our revenues were derived     % from oil sales,     % from natural gas sales and     % from NGL sales. Our revenues are derived from royalty payments we receive from the Contributing Parties and other operators of our properties based on the sale of oil and natural gas production, as well as the sale of NGLs that are extracted from natural gas during processing. As of December 31, 2017, on a pro forma basis, we had over 250 operators on our acreage, with the Contributing Parties operating approximately 46% of our net production during 2017. Our top five



 

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operators are our Operating Affiliate, AVAD Energy Partners, LP, Linn Energy LLC, SK Plymouth, LLC and Exco Operating Company, LP, and together account for approximately 66% of our net production during 2017. We have acreage in counties where there were 16 rigs operating and approximately 500 active permits as of April 2018.

We believe that one of our key strengths is our management team’s extensive experience in acquiring and managing mature oil and natural gas properties. Our management team and board of directors, which includes our founders George B. Peyton V and Grant W. Livesay, have a long history of creating value. We expect that our management team’s extensive experience in acquiring and integrating oil and natural gas properties will allow us to efficiently integrate significant acquisitions into our existing organizational structure. Furthermore, we expect the Contributing Parties to operate a significant portion of our future production and undeveloped reserves. In connection with this offering, we will enter into a management services agreement with our Operating Affiliate, pursuant to which it will identify, evaluate and recommend to us acquisition opportunities and negotiate the terms of such acquisitions. Please read “Certain Relationships and Related Party Transactions—Agreements and Transactions with Affiliates in Connection with this Offering—Management Services Agreement.”

Upon completion of this offering, the Contributing Parties will own              shares of our Class B common stock representing 100% of our outstanding Class B common stock and              units representing limited liability company interests in Remora Holdings (“RH Units”) representing a     % interest in Remora Holdings. Each share of Class B common stock has no economic rights but entitles its holder to one vote on all matters to be voted on by shareholders generally. The Contributing Parties expect to retain a diverse portfolio of oil and natural gas properties with production and reserve characteristics similar to the assets we will own at the closing of this offering. In connection with this offering and pursuant to the contribution agreement that we will enter into with the Contributing Parties, certain of the Contributing Parties will grant us a right of first offer for a period of three years after the closing of this offering with respect to certain oil and natural gas properties in their portfolio, including properties located in the Permian, Anadarko, Arkoma, Appalachia, Uinta and Williston Basins. These oil and natural gas interests, many of which overlap with our royalty interests, include ownership in approximately 5,000 gross producing wells and approximately 600,000 gross acres across major producing basins in the United States. We believe the Contributing Parties will be incentivized through their continued ownership in the working interests in the underlying properties and ownership of our Class B common stock and RH Units to (i) offer us the opportunity to acquire additional royalty interests from them in the future and (ii) develop and grow production on the properties in which we own interests. Such Contributing Parties, however, have no obligation to sell any assets to us or to accept any offer that we may make for such assets, and we may decide not to acquire such assets even if such Contributing Parties offer them to us. Please read “Certain Relationships and Related Party Transactions—Remora Holdings LLC Agreement.”

Our Assets

We categorize our assets into two groups: overriding royalty interests and mineral interests.

Overriding Royalty Interests

We primarily own overriding royalty interests, which are royalty interests that burden the working interests of a lease and represent the right to receive a fixed, cost-free percentage of production or revenue from production from a lease for as long as the lease is effective. Overriding royalty interests typically remain in effect until the associated lease expires, and because substantially all of the underlying leases are



 

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perpetual so long as production in paying quantities perpetuates the leasehold, substantially all of our overriding royalty interests are likewise perpetual as long as production continues. Overriding royalty interests generate over 95% of our revenue and are also the assets over which our Operating Affiliate will have the most influence. The Contributing Parties operated approximately 46% of the net production associated with these interests for the year ended December 31, 2017. Approximately 97% of our overriding royalty interests are held by production.

Mineral Interests

In addition to overriding royalty interests, we also own mineral interests, which are real property interests that are typically perpetual and grant ownership to all of the oil and natural gas lying below the surface of the property, as well as the right to explore, drill and produce oil and natural gas on that property or to lease such rights to a third party. Mineral owners typically grant oil and natural gas leases to operators for an initial three-year term with an upfront cash payment to the mineral owners known as a lease bonus. Once a well is producing, the mineral owner retains a royalty interest entitling it to a cost-free percentage of production or revenue from production. When production or drilling ceases on the leased property, the lease is terminated, subject to certain exceptions, and all mineral rights revert back to the mineral owner who can then lease the exploration and development rights to another party. We also own royalty interests that have been carved out of mineral interests and are known as nonparticipating royalty interests. Nonparticipating royalty interests are typically perpetual and have rights similar to mineral interests, including the right to a cost-free percentage of production revenues for minerals extracted from the acreage, without the associated executive right to lease and the right to receive lease bonuses.

We combine our mineral and nonparticipating royalty assets into one category because they share many of the same characteristics due to the nature of the underlying interest. For example, we receive similar royalties from operators with respect to our mineral interests and nonparticipating royalty interests as long as such interests are subject to an oil and natural gas lease. As of December 31, 2017, on a pro forma basis, approximately 73% of the acreage subject to our mineral and nonparticipating royalty interests was leased. Less than 5% of our revenue for the year ended December 31, 2017, on a pro forma basis, was generated from such interests. When evaluating our business, our management team does not distinguish between mineral and nonparticipating royalty interests on leased acreage due to the similarity of the royalties received in respect to each.



 

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Production

The following charts provide information regarding the production of oil, natural gas and NGLs for the properties underlying our royalty interests on a pro forma basis for the year ended December 31, 2017.

 

LOGO    LOGO

 

(1)   “Btu-equivalent” production volumes are presented on a “natural gas-equivalent” basis using a conversion factor of six Mcf of natural gas per barrel of oil, which is based on approximate energy equivalency and does not reflect the price or value relationship between oil and natural gas.

 

(2)   “Value-equivalent” production volumes are presented on a “natural gas-equivalent” basis using a conversion factor of 20 Mcf of natural gas per barrel of oil, which is the conversion factor we use in our business. For a discussion of the 20-to-1 conversion factor, please read footnote three to the Royalty Interests table under “—Key Producing Regions—Royalty Interests.”

Key Producing Regions

The following tables present information about our royalty interest acreage, production and well count by basin. We may own more than one type of interest in the same tract of land. Consequently, some of the acreage shown for one type of interest below may also be included in the acreage shown for another type of interest.



 

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Royalty Interests

The following table sets forth information about the properties underlying our royalty interests on a pro forma basis as of and for the year ended December 31, 2017:

 

     As of December 31, 2017     Average Daily Production
For the Year Ended
December 31, 2017
(Mcfe/d)
 

Basin or Producing Region

   Gross Acres      Net Acres      Percent HBP     6:1(2)      20:1(3)  

Midcontinent

     260,184        11,020        89     8,400        15,286  

South Texas / Gulf Coast

     72,486        19,732        100     6,443        9,889  

East Texas / North Louisiana

     63,516        2,331        100     4,366        4,759  

Permian Basin

     9,903        1,331        100     506        1,585  

Other(1)

     187,108        8,616        100     6,455        8,337  
  

 

 

    

 

 

    

 

 

   

 

 

    

 

 

 

Total

     593,197        43,030        97     26,170        39,856  
  

 

 

    

 

 

    

 

 

   

 

 

    

 

 

 

 

(1)   “Other” producing regions include multiple producing basins or plays across the United States, including the DJ Basin, San Juan Basin, Black Warrior Basin, Uinta Basin, onshore California and the western Gulf Coast (onshore) Basin.

 

(2)   “Btu-equivalent” production volumes are presented on a “natural gas-equivalent” basis using a conversion factor of six Mcf of natural gas per barrel of oil, which is based on approximate energy equivalency and does not reflect the price or value relationship between oil and natural gas.

 

(3)   “Value-equivalent” production volumes are presented on a “natural gas-equivalent” basis using a conversion factor of 20 Mcf of natural gas per barrel of oil, which is the conversion factor we use in our business. We are providing this measure supplementally because we believe this conversion factor represents an estimation of value equivalence over time and better correlates with the respective contribution of natural gas and oil to our revenues. We use the 20-to-1 conversion factor as we assess our business, including analysis of our financial and production performance, strategic decisions to purchase additional properties and budgeting. We do not adjust the 20-to-1 ratio to reflect current pricing, because the significant volatility in the conversion ratio makes it difficult for us to compare results across periods. By reviewing our aggregate production on a constant 20-to-1 basis, which removes the variability of price fluctuations but generally approximates price equivalence over recent periods, we are able to compare production data from period to period as well as the relative contribution of natural gas and oil to our revenues. The 20-to-1 conversion factor approximates the mean ratio of the average monthly price of WTI oil to the average monthly price of Henry Hub natural gas from January 1, 2008 to December 31, 2017, as reported by the U.S. Energy Information Agency (“EIA”). During this period, the ratio of the price of oil to the price of natural gas ranged from 53.0-to-1 to 7.1-to-1. The mean ratios of the price of oil to the price of natural gas were 17.1-to-1 and 17.6-to-1 for the years ended December 31, 2017 and December 31, 2016, respectively. Due to the variability of the prices of natural gas and oil, there is no standard conversion ratio for value equivalence, and the 20-to-1 ratio presented here may not accurately reflect the ratio of oil prices to natural gas prices for a given period.


 

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Wells

The following table sets forth information about the wells in which we have a royalty interest as of December 31, 2017, on a pro forma basis:

 

Basin or Producing Region

   Well Count  

Midcontinent

     1,949  

South Texas / Gulf Coast

     222  

East Texas / North Louisiana

     592  

Permian Basin

     28  

Other(1)

     819  
  

 

 

 

Total

     3,610  
  

 

 

 

 

(1)   “Other” producing regions include multiple producing basins or plays across the United States, including the DJ Basin, San Juan Basin, Black Warrior Basin, Uinta Basin, onshore California and the western Gulf Coast (onshore) Basin.

Material Basins and Producing Regions

The following is an overview of the U.S. basins and producing regions we consider most material to our current and future business.

 

    Midcontinent. The Midcontinent is a broad area containing hundreds of fields in Arkansas, Kansas, New Mexico, Oklahoma, Nebraska and Texas, and includes the Granite Wash, Cleveland, Woodford, Meramec, Osage and Mississippi Lime formations, among many others. The Anadarko and Arkoma Basins within the Midcontinent are among the most prolific and largest onshore producing oil and natural gas basins in the United States, having multiple producing horizons and extensive well control demonstrated over seven decades of development. The Anadarko Basin is a structural basin centered in the western part of Oklahoma and the Texas Panhandle, extending into southwestern Kansas and southeastern Colorado. Our interests contain diversified exposure to the STACK, Woodford, Mississippi Lime, Granite Wash, Hunton and other liquids-rich plays across the Anadarko Basin. As of April 2018, there were 12 active rigs and approximately 370 active permits in the counties in which we own royalty interests. The Arkoma Basin is a structural basin that spans across west-central Arkansas into southeastern Oklahoma along the northern side of the Ouachita orogenic belt. A significant portion of our Midcontinent acreage lies in the Arkoma STACK play, which is primarily targeting the liquids-rich Woodford formation and secondarily targeting the Mayes shale and Caney shale formations. As of December 31, 2017, the number of active rigs increased by 100% and permitting activity increased approximately 53% compared to the prior year on and around our Arkoma Basin acreage, which is operated by multiple high-quality operators. Also, included in the Midcontinent region are our royalty interests in approximately 165 gross long-lived conventional oil wells located in the western Fort Worth Basin. These properties are operated by our Operating Affiliate and produce primarily from the Canyon, Caddo, Marble Falls, Duffer and Ellenburger formations.

 

   

South Texas/Gulf Coast. Our South Texas/Gulf Coast interests are diversified across 222 gross wells located in 22 counties and are primarily producing from prolific, long-lived natural gas-weighted reservoirs including the Wilcox, Vicksburg, Frio and Edwards Lime. Approximately 80.0% of our 18.0 Bcfe total proved reserves in South Texas/Gulf Coast are operated by our



 

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Operating Affiliate, which has identified 32 recompletion cases and more than 100 additional workover/reactivation opportunities across our acreage position. We believe the South Texas/Gulf Coast region represents an attractive opportunity for further consolidation of predictable, conventional oil and natural gas properties producing from high-quality reservoirs with substantial geologic support of in-place hydrocarbons.

 

    East Texas/North Louisiana. Our East Texas/North Louisiana interests are primarily located in Desoto, Bienville, Webster and Jackson Parishes in Louisiana and Rusk County, Texas, as well as eight additional counties and parishes. Our Operating Affiliate operates approximately 153 wells, representing 52.0% of our 15.7 Bcfe total proved reserves in East Texas/North Louisiana and primarily producing from the Hosston, Cotton Valley and Haynesville formations. Beyond our PDP reserves, we believe our interests in this area contain longer-term upside potential in a higher gas price environment, particularly in the Lower Cotton Valley, Haynesville and Bossier plays across the region.

 

    Permian Basin. The Permian Basin extends from southeastern New Mexico into west Texas and is currently one of the most active drilling regions in the United States. It includes three geologic provinces: the Midland Basin to the east, the Delaware Basin to the west and the Central Basin Platform in between. The Permian Basin consists of mature legacy onshore oil and liquids-rich natural gas reservoirs and has been actively drilled over the past 90 years. The extensive operating history, favorable operating environment, mature infrastructure, long reserve life, multiple producing horizons, horizontal development potential and liquids-rich reserves make the Permian Basin one of the most prolific oil-producing regions in the United States. Our proved reserves in the Permian Basin are primarily located in Crockett County, Texas and are operated by one of the Contributing Parties. There are a number of uphole redevelopment projects, including eight Wolfcamp recompletions, that such Contributing Party intends to pursue in the near future, which we believe will directly benefit our royalty interests.

 

    Other. Our other assets consist of interests in 819 gross wells and are located in multiple other producing basins across the United States, including the DJ Basin, San Juan Basin, Black Warrior Basin, Uinta Basin, onshore California and the western Gulf Coast (onshore) Basin.

Our Relationship with our Operating Affiliate

Our Operating Affiliate is a privately-held Texas limited partnership focused on the acquisition, development and exploitation of both conventional and unconventional oil and natural gas reserves in multiple onshore US basins. Our Operating Affiliate was formed in 2011 by its management team and affiliates of NGP.

As of December 31, 2017, on a pro forma basis, our Operating Affiliate owned approximately 123,000 net acres (97% held by production). For the year ended December 31, 2017, on a pro forma basis, our Operating Affiliate had net production of 31.3 MMcfe/d and estimated proved reserves of 206 Bcfe (57.0% proved developed), according to Cawley. Our Operating Affiliate expects to enter into hedging contracts covering approximately 75% of its estimated proved developed production for at least three years following this offering.

We believe our Operating Affiliate, through its ownership of our Class B common stock and RH Units, will be incentivized to sell us additional royalty interests from its existing inventory of properties in the future as they become mature, though it will have no obligation to do so following this offering. Furthermore, our Operating Affiliate has the ability to own operated and non-operated properties, and although our Operating



 

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Affiliate is not limited in its ability to compete against us, we expect it to pursue acquisitions of such properties with the intention of creating additional royalty interests for us to acquire. Finally, our Operating Affiliate can pursue development of current and future properties that would benefit us directly through increased production, and would likewise benefit our Operating Affiliate through its continued ownership in the working interests of the underlying properties and ownership of our Class B common stock and RH Units.

We expect our Operating Affiliate to reinvest a substantial portion of the dividends it receives from us in the development of its properties. For example, on our royalty acreage, our Operating Affiliate has a portfolio of 57 PDNP recompletion projects (75% operated) to grow production, with the top 20 identified near term operated projects having an anticipated payback period of less than two years. Our Operating Affiliate also has an additional 29 probable recompletion projects (100% operated) in its portfolio and over 100 additional operated reactivation candidates, which could restore production in inactive wells for minimal costs. Additionally, our Operating Affiliate has advised us that it has identified a multi-year inventory of 173 gross PUD locations (99% non-operated) on acreage where we own royalty interests, primarily located in the Arkoma STACK play. Further, our Operating Affiliate has identified an additional 412 gross horizontal drilling locations (99% non-operated) included in our probable reserve estimates. We believe our Operating Affiliate’s current recompletion/workover, PUD and probable locations and reactivation projects are capable of growing the production from the acreage underlying our interests through December 2021 without acquiring incremental reserves.

Business Strategies

Our primary business objective is to provide increasing dividends to stockholders resulting from acquisitions from the Contributing Parties and third parties and from organic growth through the continued development by the Contributing Parties and other working interest owners of the properties in which we own an interest. We intend to accomplish this objective by executing the following strategies:

 

    Acquire additional royalty interests from the Contributing Parties. Following the completion of this offering, certain of the Contributing Parties will continue to own significant interests in mature producing oil and natural gas properties, as well as undeveloped acreage that we expect the Contributing Parties will drill and convert to production in the near future. We believe certain of the Contributing Parties view the Company as a key part of their growth strategy. In addition, we believe their ownership in us will incentivize them to offer us additional royalty interests from their existing asset portfolios in the future. In connection with this offering and pursuant to the contribution agreement that we will enter into with the Contributing Parties, certain of the Contributing Parties will grant us a right of first offer for a period of three years after the closing of this offering with respect to certain oil and natural gas properties in their portfolio, including properties located in the Permian, Anadarko, Arkoma, Appalachia, Uinta and Williston Basins. These oil and natural gas interests subject to such right of first offer include ownership in approximately 5,000 gross producing wells and approximately 600,000 gross acres across the major producing basins in the United States. Such Contributing Parties, however, have no obligation to sell any assets to us or to accept any offer that we may make for such assets, and we may decide not to acquire such assets even if such Contributing Parties offer them to us.

 

   

Participate with our Operating Affiliate in third-party acquisitions. Our Operating Affiliate, as well as the other Contributing Parties, were formed in part to acquire and develop mature oil and natural gas properties. Some of these properties will meet our acquisition criteria, which include (i) a sufficient, stable current production profile to create near-term accretion for our stockholders, (ii) significant amounts of recoverable oil and natural gas in place with geologic support for future



 

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production and reserve growth, (iii) a geographic footprint complementary to our diverse portfolio and (iv) targeted acreage positions in resource and conventional plays that maximize our potential for reserve and production upside. More specifically, through our relationship with our Operating Affiliate, we expect to acquire royalty interests in mature properties concurrently with our Operating Affiliate’s acquisition of such property, although our Operating Affiliate is under no obligation to include us in any acquisitions it makes. Through this participation with our Operating Affiliate in acquisitions, we expect to significantly increase the size and scope of potential acquisition targets available to us. Through our relationships with the Contributing Parties, we have access to each of their management teams and industry networks, which we believe provide us with a competitive advantage in pursuing potential third-party acquisitions. Further, we may have opportunities to work together with certain of the Contributing Parties to acquire properties that may not otherwise be attractive candidates for us or the Contributing Party individually.

Our Operating Affiliate and its affiliates have significant experience in identifying, evaluating and completing strategic acquisitions of mature producing oil and natural gas properties. In connection with the closing of this offering, we will enter into a management services agreement with our Operating Affiliate pursuant to which it will identify, evaluate and recommend to us acquisition opportunities and negotiate the terms of such acquisitions. We believe that these individuals’ knowledge of the oil and natural gas industry, relationships within the industry and experience in identifying, evaluating and completing acquisitions will provide us opportunities to grow through strategic and accretive acquisitions that complement or expand our asset portfolio.

 

    Benefit from reserve, production and cash flow growth through organic production growth and development of our royalty interests to grow dividends. Our initial assets consist of diversified royalty interests. Over the long term, we expect working interest owners will continue to develop our acreage through recompletions, infill drilling, horizontal drilling, hydraulic fracturing and secondary and tertiary recovery methods. As an owner of royalty interests, we are entitled to a portion of the revenues received from the production of oil, natural gas and associated NGLs from the acreage underlying our interests, net of post-production expenses and taxes. We are not obligated to fund drilling and completion costs, lease operating expenses or plugging and abandonment costs at the end of a well’s productive life. As such, we benefit from the continued development of the properties we own a royalty interest in without the need for investment of additional capital by us, which we expect to increase our dividends over time. For the year ended December 31, 2017, approximately 46% of our net production was operated by the Contributing Parties, who have advised us that they have identified a multi-year inventory of recompletion projects and drilling locations on our acreage. We believe the Contributing Parties will be incentivized through their ownership of Class B common stock and RH Units to develop and grow production on the properties in which we own interests.

 

    Maintain a conservative capital structure and prudently manage our business for the long term. We are committed to maintaining a conservative capital structure that will afford us the financial flexibility to execute our business strategies on an ongoing basis. Though not required pursuant to our amended and restated certificate of incorporation or amended and restated bylaws (respectively, our “certificate of incorporation” and our “bylaws”), our board of directors intends to adopt a written policy whereby we limit our incurrence of borrowings up to 2.5 times our debt to Adjusted EBITDA ratio for the preceding four quarters. Additionally, we expect to maintain a conservative hedging strategy. Our strategy includes entering into commodity derivative contracts covering approximately 20% to 30% of our estimated production from total PDP reserves underlying our royalty interests for at least two years, although we may increase this percentage if debt levels rise as a result of acquisitions.


 

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Competitive Strengths

We believe that the following competitive strengths will allow us to successfully execute our business strategies and achieve our primary business objective:

 

    Significant diversified portfolio of royalty interests in mature producing basins and exposure to undeveloped opportunities. We have a diversified, low decline asset base with exposure to high-quality conventional and unconventional plays. As of December 31, 2017, we owned royalty interests in approximately 593,000 gross acres and approximately 43,000 net acres, of which approximately 57% is operated by the Contributing Parties. As of December 31, 2017, over 97% of the acreage subject to our royalty interests were held by production. The geographic breadth of our assets gives us exposure to potential production and reserves from new and existing plays without further required investment on our behalf. We believe that we will continue to benefit from these cost-free additions to production and reserves for the foreseeable future as a result of technological advances and continuing interest by the Contributing Parties and third-party producers in development activities on our acreage.

 

    The Contributing Parties have significant operational control over our properties. At the completion of this offering and on a pro forma basis, the Contributing Parties will operate approximately 46% of our 2017 net production, 50% of our total proved reserves and approximately 57% of our net acreage. The Contributing Parties operate approximately 98% of our PDNP reserves and have advised us they intend to develop such reserves in the near future. Given the Contributing Parties will own 100% of our Class B common stock,              RH Units representing a     % interest in Remora Holdings, and will have continued ownership in the working interests in the underlying properties, we believe they are strongly incentivized to maximize production and development of the properties underlying our royalty interests. Further, we believe we have greater visibility into the Contributing Parties’ multi-year development programs than we would otherwise have with an unaffiliated third-party operator.

 

    Ability to acquire additional royalty interests from the Contributing Parties. We believe our relationship with the Contributing Parties will provide us with opportunities to acquire additional royalties at attractive valuations. Following the completion of this offering, the Contributing Parties will continue to own significant interests in mature producing oil and natural gas properties, as well as undeveloped acreage that we expect them to develop and convert to production in the near future. We believe the Contributing Parties view the Company as a key part of their growth strategy and that their ownership in us will incentivize them to offer us additional royalty interests from their asset portfolios over time.

 

    Exposure to leading plays in the United States, particularly in the Midcontinent region. We expect the operators of our properties to continue to drill new wells on our acreage, which we believe should more than offset the natural production declines from our existing wells through the year ending December 31, 2021. We believe that our operators have significant drilling inventory remaining on the acreage underlying our royalty interests in multiple plays. Our royalty interests are located in 12 states and in 13 major onshore basins across the continental United States and include ownership in approximately 3,600 gross producing wells, including over 1,900 wells in the Midcontinent. In the Midcontinent, and as of April 2018, there were 12 active rigs and approximately 370 active permits in the counties in which we own royalty interests. For the year ended December 31, 2017, approximately 75% of our net production was from the Midcontinent, South Texas/Gulf Coast, East Texas/North Louisiana and Permian Basin, which are among the most historically prolific oil and natural gas regions in the country.


 

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    Financial flexibility to fund expansion. We believe our conservative capital structure after this offering will permit us to maintain the financial flexibility to allow us to opportunistically purchase strategic royalty interests. We anticipate entering into a new $     million secured revolving credit facility prior to the completion of this offering. We expect to have a borrowing base under our secured revolving credit facility of $             million and to have $         million drawn at the closing of this offering.

 

    Experienced and proven management team with a track record of making acquisitions. The members of our management team and board of directors have a combined total of over 150 years of oil and natural gas experience. Our management team and board of directors, which includes our founders, have a long history of buying mature oil and natural gas properties in high-quality producing acreage throughout the United States. Since inception, our Operating Affiliate has evaluated over 250 acquisition candidates, and has completed 43 oil and natural gas property acquisitions and expects to continue acquiring properties for the benefit of itself and the Company.

Management Services Agreement

In connection with the closing of this offering, we and Remora Holdings will enter into a management services agreement with our Operating Affiliate pursuant to which our Operating Affiliate will provide management and administrative services to us and Remora Holdings. Neither we, Remora Holdings, nor our other subsidiaries will have any employees. Although certain of the employees that conduct our business will be employed by our Operating Affiliate, we sometimes refer to these individuals in this prospectus as our employees. In addition, certain of our executive officers and directors currently serve as executive officers or directors of our Operating Affiliate. Please read “Management” and “Certain Relationships and Related Party Transactions.”

Risk Factors

An investment in our Class A common stock involves a high degree of risk. You should carefully consider the risks described in “Risk Factors” and the other information in this prospectus, before deciding whether to invest in our Class A common stock. If any of these risks were to occur, our financial condition, results of operations, cash flows and ability to pay dividends to our stockholders would be adversely affected, and you could lose all or part of your investment.

Risks Related to Our Business

 

    We may not have sufficient available cash to pay dividends on shares of our Class A common stock and we are not required to pay dividends by any law, our certificate of incorporation or our bylaws.

 

    The assumptions underlying the forecast of cash available to make dividend payments that we include in “Dividend Policy—Estimated Cash Available to Make Dividend Payments for the Twelve Months Ending June 30, 2019” are inherently uncertain and are subject to significant business, economic, financial, regulatory, environmental and competitive risks and uncertainties that could cause actual results to differ materially from those forecasted.

 

    Our business is difficult to evaluate because we have a limited financial history.

 

    The amount of our quarterly dividend payment, if any, may vary significantly both quarterly and annually and will be directly dependent on the performance of our business.


 

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    All of our revenues are derived from royalty payments that are based on the price at which oil, natural gas and NGLs produced from the acreage underlying our interests is sold. The volatility of these prices due to factors beyond our control greatly affects our business, financial condition, results of operations and cash available to make dividend payments.

Risks Inherent in an Investment in Us

 

    Our board of directors may modify or revoke our dividend policy at any time at its discretion, including in such a manner that would result in an elimination of cash dividends regardless of the amount of available cash we generate. Our certificate of incorporation and bylaws do not require us to make any dividends at all.

 

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

 

    Neither we nor our subsidiaries have any employees, and we rely solely on our Operating Affiliate to manage and operate, or arrange for the management and operation of, our business. The management team of our Operating Affiliate, which includes the individuals who will manage us, will also provide substantially similar services to other entities and thus will not be solely focused on our business.

 

    Increases in interest rates may cause the market price of our Class A common stock to decline.

 

    Stockholders will incur immediate and substantial dilution of $     per share of our Class A common stock.

Formation Transactions

We were incorporated by our Operating Affiliate as a Delaware corporation in May 2018. Following this offering and the transactions related thereto, we will be a holding company whose sole material asset will consist of              RH Units. After the consummation of the transactions contemplated by this prospectus, we will be the managing member of Remora Holdings and will be responsible for all operational, management and administrative decisions relating to Remora Holdings’ business and will consolidate the financial results of Remora Holdings and its subsidiaries. The Limited Liability Company Agreement of Remora Holdings will be amended and restated as the Amended and Restated Limited Liability Company Agreement of Remora Holdings (the “Remora Holdings LLC Agreement”) to, among other things, admit us as the sole managing member of Remora Holdings.

In connection with this offering, (a) the Contributing Parties will contribute certain royalty interests to Remora Holdings in exchange for              RH Units and Remora Holdings’ assumption of approximately $         million of our Operating Affiliate’s indebtedness that burdens the royalty interests to be contributed by our Operating Affiliate, (b) we will contribute approximately $         of the net proceeds of this offering to Remora Holdings in exchange for              RH Units, (c) we will purchase              RH Units from the Contributing Parties in exchange for approximately $         of the net proceeds of this offering, and (d) each of the Contributing Parties will purchase from us one share of Class B common stock at par value for each RH Unit such Contributing Party holds.

After giving effect to these transactions and the offering contemplated by this prospectus, we will own an approximate     % interest in Remora Holdings (or     % if the underwriters’ option to purchase additional shares is exercised in full) and the Contributing Parties will own an approximate     % interest in Remora



 

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Holdings (or     % if the underwriters’ option to purchase additional shares is exercised in full) and all of the outstanding Class B common stock.

Each share of the Class B common stock has no economic rights but entitles its holder to one vote on all matters to be voted on by shareholders generally. Holders of Class A common stock and Class B common stock will vote together as a single class on all matters presented to our shareholders for their vote or approval, except as otherwise required by applicable law or by our certificate of incorporation. We do not intend to list Class B common stock on any stock exchange.

Following this offering, under the Remora Holdings LLC Agreement, the Contributing Parties will, subject to certain limitations, have the right to cause Remora Holdings to redeem (the “Redemption Right”) all or a portion of their RH Units (together with a corresponding number of shares of Class B common stock) for Class A common stock (or cash at our or Remora Holdings’ election (the “Cash Option”)) at a redemption ratio of one share of Class A common stock for each RH Unit (and corresponding share of Class B common stock) redeemed as described under “Certain Relationships and Related Party Transactions—Remora Holdings LLC Agreement.” Alternatively, upon the exercise of the Redemption Right, Remora Royalties, Inc. (instead of Remora Holdings) will have the right (the “Call Right”) to, for administrative convenience, acquire each tendered RH Unit directly from the redeeming holder of RH Units for, at its election, (x) one share of Class A common stock or (y) an equivalent amount of cash. In addition, upon a change of control of Remora Royalties, Inc., Remora Royalties, Inc. has the right to require each holder of RH Units (other than Remora Royalties, Inc.) to exercise its Redemption Right with respect to some or all of such unitholder’s RH Units. In connection with any redemption of RH Units pursuant to the Redemption Right or our Call Right, the corresponding number of shares of Class B common stock will be cancelled. In addition, the Contributing Parties will have the right, under certain circumstances, to cause us to register the offer and sale of their shares of Class A common stock as described under “Certain Relationships and Related Party Transactions—Registration Rights Agreement.”

Following the completion of this offering and our corporate reorganization, our Contributing Parties will in the aggregate own 100% of our Class B common stock, representing approximately     % of the voting power of Remora Royalties, Inc.



 

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The following diagram indicates our simplified ownership structure immediately following this offering and the transactions related thereto (assuming that the underwriters’ option to purchase additional shares is not exercised):

 

LOGO

Emerging Growth Company Status

We are an “emerging growth company” as defined in the Jumpstart Our Business Startups Act (“JOBS Act”). For as long as we are an emerging growth company, we may take advantage of specified exemptions from reporting and other regulatory requirements that are otherwise generally applicable to other public companies. These exemptions include:

 

    an exemption from providing an auditor’s attestation report on the effectiveness of our system of internal control over financial reporting pursuant to Section 404(b) of the Sarbanes-Oxley Act of 2002 (the “Sarbanes-Oxley Act”);

 

    an exemption from compliance with any new requirements adopted by the Public Company Accounting Oversight Board (“PCAOB”), requiring mandatory audit firm rotation or 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;

 

    an exemption from compliance with any other new auditing standards adopted by the PCAOB after April 5, 2012, unless the Securities and Exchange Commission (“SEC”) determines otherwise; and

 

    reduced disclosure of executive compensation.

In addition, Section 102 of the JOBS Act also provides that an emerging growth company can use the extended transition period provided in Section 7(a)(2)(B) of the Securities Act of 1933, as amended (the



 

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“Securities Act”), for complying with new or revised accounting standards. This permits an emerging growth company to delay the adoption of certain accounting standards until those standards would otherwise apply to private companies. We have elected to take advantage of all of the applicable JOBS Act provisions.

We will cease to be an “emerging growth company” upon the earliest of (i) the last day of the first fiscal year when we have $1.07 billion or more in annual revenues; (ii) the date on which we have issued more than $1.0 billion of non-convertible debt over a three-year period; (iii) the last day of the fiscal year following the fifth anniversary of our initial public offering; or (iv) the date on which we have qualified as a “large accelerated filer” under the Securities Exchange Act of 1934, as amended (the “Exchange Act”).

Principal Executive Offices

Our principal executive offices are located at 807 Las Cimas Parkway, Suite 275, Austin, Texas 78746 and our telephone number is (512) 579-3590. Our website address will be www.remoraroyalties.com. We intend 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 our website is not incorporated by reference into this prospectus and does not constitute a part of this prospectus.



 

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The Offering

 

Issuer

Remora Royalties, Inc.

 

Class A common stock offered to the public

     shares of Class A common stock (     shares of Class A common stock if the underwriters exercise in full their option to purchase additional shares of Class A common stock from us).

 

Option to purchase additional shares of Class A common stock

We have granted the underwriters a 30-day option to purchase up to an additional      shares of Class A common stock.

 

Class A common stock to be outstanding after this offering

     shares of Class A common stock (            shares of Class A common stock if the underwriters exercise in full their option to purchase additional shares of Class A common stock from us).

 

Class B common stock to be outstanding immediately after completion of this offering

     shares of Class B common stock, or one share for each RH Unit held by the Contributing Parties immediately following this offering. Class B shares are non-economic. In connection with any redemption of RH Units pursuant to the Redemption Right or our Call Right, the corresponding number of shares of Class B common stock will be cancelled.

 

Use of proceeds

We will receive net proceeds of approximately $     million from this offering (based on an assumed initial public offering price of $         per share of Class A common stock, the mid-point of the price range set forth on the cover page of this prospectus), after deducting the underwriting discounts, the structuring fee and the estimated offering expenses payable by us in connection with this offering. We intend to use the net proceeds of this offering to (1) make a contribution of $         to Remora Holdings in exchange for RH Units representing a     % membership interest in Remora Holdings and (2) purchase RH Units representing a     % membership interest in Remora Holdings from the Contributing Parties for $        . Remora Holdings will use the proceeds of the contribution to repay in full approximately $         of our Operating Affiliate’s indebtedness that burdens the royalty interests to be contributed to Remora Holdings by our Operating Affiliate that Remora Holdings will assume in connection with the formation transactions. If the proceeds of the offering increase due to a higher initial public offering price or decrease due to a lower initial offering price, the amount used to purchase RH Units from the Contributing Parties will increase or decrease, as applicable, by a corresponding amount.

 

 

If the underwriters exercise their option to purchase additional shares of Class A common stock in full, the additional net proceeds



 

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to us would be approximately $     million (based on an assumed initial offering price of $     per share, the mid-point of the price range set forth on the cover page of this prospectus), after deducting the underwriting discount and structuring fee. We will use any net proceeds from the exercise of the underwriters’ option to purchase additional RH Units and Class B shares, on a pro rata basis, from the Contributing Parties. Please read “Use of Proceeds.”

 

Voting Power of Class A common stock after giving effect to this offering

    % (or 100% if all outstanding RH Units held by the Contributing Parties are redeemed, along with a corresponding number of shares of our Class B common stock, for newly-issued shares of Class A common stock on a one-for-one basis).

 

Voting Power of Class B common stock after giving effect to this offering

    % (or 0% if all outstanding RH Units held by the Contributing Parties are redeemed, along with a corresponding number of shares of our Class B common stock, for newly-issued shares of Class A common stock on a one-for-one basis).
 

 

Voting rights

Each share of our Class A common stock entitles its holder to one vote on all matters to be voted on by shareholders generally. Each share of our Class B common stock entitles its holder to one vote on all matters to be voted on by shareholders generally. Holders of our Class A common stock and Class B common stock vote together as a single class on all matters presented to our shareholders for their vote or approval, except as otherwise required by applicable law or by our certificate of incorporation. See “Description of Capital Stock.”

 

Dividend policy

Though we will not be required by any law, our certificate of incorporation or our bylaws to pay dividends, our board of directors expects to adopt a written policy whereby we intend to make a dividend of all of our cash on hand to our Class A common stockholders at the end of each quarter in an amount equal to our available cash for such quarter, beginning with the quarter ending             , 2018.

 

 

We do not currently intend to retain cash from our operations for capital expenditures necessary to replace our existing oil and natural gas reserves or otherwise maintain our asset base (replacement capital expenditures), primarily due to our expectation that the continued development of our properties by working interest owners will offset the natural production declines from our existing wells through 2021. Our board of directors may change our dividend policy and decide to withhold replacement capital expenditures from cash available to make dividend payments, which would reduce the amount of cash available to



 

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make dividend payments in the quarter(s) in which any such amounts are withheld. Over the long term, if our reserves are depleted and our Operating Affiliate and other operators become unable to maintain production on our existing properties and we have not been retaining cash for replacement capital expenditures, the amount of cash generated from our existing properties will decrease and we may have to reduce the amount of dividends payable to our Class A common stockholders.

 

  It is our intent, subject to market conditions, to finance acquisitions of royalty interests that increase our asset base largely through external sources, such as borrowings under our secured revolving credit facility and the issuance of equity and debt securities, although our board of directors may choose to reserve a portion of cash generated from operations to finance such acquisitions as well.

 

  Because we expect to pay out an amount equal to all available cash we generate each quarter pursuant to our dividend policy, our Class A common stockholders will have direct exposure to fluctuations in the amount of cash generated by our business. We expect that the amount of our quarterly cash dividends, if any, will fluctuate based on variations in, among other factors, (i) the performance of our Operating Affiliate and the other operators of our properties, (ii) earnings caused by, among other things, fluctuations in the price of oil, natural gas and NGLs, changes to working capital or capital expenditures and (iii) cash reserves deemed appropriate by our board of directors. Such variations in the amount of our quarterly dividends may be significant and could result in our not making any dividends for any particular quarter.

 

  Based upon our forecast for the full twelve months ending June 30, 2019, we expect to generate approximately $             million in cash available to make dividend payments for the twelve months ending June 30, 2019, or $             per share of Class A common stock. Please read “Dividend Policy—Estimated Cash Available to Make Dividend Payments for the Twelve Months Ending June 30, 2019.” Unanticipated events may occur which could materially adversely affect the actual results we achieve during the forecast period. Consequently, our actual results of operations, cash reserve requirements and financial condition during the forecast period may vary from the forecast, and such variations may be material. Prospective investors are cautioned not to place undue reliance on our forecast and should make their own independent assessment of our future results of operations and financial condition. In addition, our board of directors may be required to, or may elect to, eliminate our dividends for various reasons, including reduced commodity prices or demand for oil and natural gas. Please read “Risk Factors.”


 

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  For a calculation of our ability to pay dividends to our Class A common stockholders based on our pro forma results of operations for the year ended December 31, 2017 and the twelve months ended March 31, 2018, please read “Dividend Policy—Unaudited Pro Forma Cash Available for Dividend Payments for the Year Ended December 31, 2017 and the Twelve Months Ended March 31, 2018.” Our pro forma cash available for dividend payments generated during the year ended December 31, 2017 and the twelve months ended March 31, 2018 would have been $25.7 million and $23.2 million, respectively. However, the pro forma cash available for dividend payments information for the year ended December 31, 2017 and the twelve months ended March 31, 2018 that we include in this prospectus does not necessarily reflect the actual cash that would have been available for dividend payments with respect to each of these periods.

 

Exchange listing

We have applied to list our Class A common stock on the NASDAQ under the symbol “RRI.”

 

Risk factors

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

 

Redemption rights of holders of RH Units

Following this offering, under the Remora Holdings LLC Agreement, the Contributing Parties will, subject to certain limitations, have the right, pursuant to the Redemption Right, to cause Remora Holdings to redeem all or a portion of their RH Units for Class A common stock (or, at our or Remora Holding’s election, the Cash Option) at a redemption ratio of one share of Class A common stock for each RH Unit redeemed. Alternatively, upon the exercise of the Redemption Right, Remora Royalties, Inc. (instead of Remora Holdings) will have a Call Right to, for administrative convenience, acquire each tendered RH Unit directly from the redeeming holder of RH Units for, at its election, (x) one share of Class A common stock or (y) an equivalent amount of cash. In addition, upon a change of control of Remora Royalties, Inc., Remora Royalties, Inc. has the right to require each holder of RH Units (other than Remora Royalties, Inc.) to exercise its Redemption Right with respect to some or all of such unitholder’s RH Units. In connection with any redemption of RH Units pursuant to the Redemption Right or our Call Right, the corresponding number of shares of Class B common stock will be cancelled. Please read “Certain Relationships and Related Party Transactions—Remora Holdings LLC Agreement.”

The information above excludes              shares of Class A common stock reserved for issuance under our stock and incentive plan.



 

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Index to Financial Statements

Summary Historical and Unaudited Pro Forma Condensed Combined Financial Data

Remora Royalties, Inc. was formed in May 2018 and does not have historical financial statements. In this prospectus, we present the historical financial statements of Remora Petroleum, L.P., our predecessor for accounting purposes. We refer to this entity as “our predecessor.” The following table presents summary historical financial data of our predecessor as of the dates and for the periods indicated and summary unaudited pro forma financial data of Remora Royalties, Inc. as of March 31, 2018 and for the three months ended March 31, 2018 and the year ended December 31, 2017.

The summary historical financial data of our predecessor presented as of and for the years ended December 31, 2017 and 2016 are derived from the audited historical financial statements of our predecessor included elsewhere in this prospectus. The summary historical financial data of our predecessor presented as of March 31, 2018 and for the three months ended March 31, 2018 and 2017 are derived from the unaudited historical financial statements of our predecessor included elsewhere in this prospectus.

The summary unaudited pro forma financial data presented as of March 31, 2018 and for the three months ended March 31, 2018 and the year ended December 31, 2017 are derived from our unaudited pro forma financial statements included elsewhere in this prospectus and give effect to the following transactions:

 

    Remora Holdings’ acquisition of assets to be contributed by our Operating Affiliate and the Other Principal Contributing Parties in exchange for an aggregate of         RH Units and the purchase of             shares of Class B common stock for par value by our Operating Affiliate and the Other Principal Contributing Parties and the purchase of         RH Units from our Operating Affiliate and the Other Principal Contributing Parties in exchange for $         million in cash from the net proceeds of this offering, as further described under “Formation Transactions.” The unaudited pro forma financial statements do not reflect the issuance of         RH Units (and the purchase of an equivalent number of shares of Class B common stock) and the purchase of         RH Units for $         in cash for the assets not reflected in the unaudited pro forma financial statements;

 

    The retention by our Operating Affiliate of certain oil and natural gas properties and all other assets, liabilities and operations that will not be acquired by Remora Holdings;

 

    Remora Holdings’ assumption of approximately $         million of indebtedness of our Operating Affiliate that burdens the assets to be contributed to Remora Holdings by our Operating Affiliate;

 

    Our acquisition of the 2017 South Texas Assets;

 

    The issuance by us of         of the                 shares of Class A common stock being offered to the public in this offering at an assumed initial public offering price of $         per share, which is the mid-point of the price range set forth on the cover of this prospectus, reflecting that number of shares of common stock issued to the public the proceeds of which are deemed to (1) be contributed to Remora Holdings in exchange for              RH Units and (2) purchase              RH Units from our Operating Affiliate and the Other Principal Contributing Parties. The unaudited pro forma financial statements do not reflect the issuance of                 shares of Class A common stock issued to the public deemed to fund the acquisition of assets from the other Contributing Parties;

 

    The use of the net proceeds from this offering as set forth in “Use of Proceeds”;

 

    A provision for corporate income taxes at an effective rate of     %, inclusive of all U.S. federal, state and local income taxes;


 

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Index to Financial Statements
    Remora Holdings’ entrance into a new $         million secured revolving credit facility, pursuant to which we expect to borrow approximately $         at the closing of this offering to repay the indebtedness assumed from our Operating Affiliate; and

 

    Our entrance into a management services agreement with our Operating Affiliate.

The unaudited pro forma balance sheet data assumes the events described above occurred as of March 31, 2018. The unaudited pro forma statement of operations data for the three months ended March 31, 2018 and the year ended December 31, 2017 assume the events described above occurred as of January 1, 2017.

We have not given pro forma effect to our acquisition of assets to be contributed by the Contributing Parties other than our predecessor, Vendera Resources II, LLC and its affiliates, Vendera Resources III, L.P. and its affiliates and AVAD Energy Partners, LLC, which excludes assets representing approximately 12% of our future undiscounted cash flows, based on the reserve report prepared by Cawley as of December 31, 2017.

We have not given pro forma effect to incremental general and administrative expenses of approximately $             million that we expect to incur annually as a result of operating as a publicly traded company, such as expenses associated with SEC reporting requirements, including annual and quarterly reports to stockholders, tax return and dividend expenses, Sarbanes-Oxley Act compliance expenses, expenses associated with listing on the NASDAQ, independent auditor fees, independent reserve engineer fees, legal fees, investor relations expenses, registrar and transfer agent fees, director and officer insurance expenses and director and officer compensation expenses.

For a detailed discussion of the summary historical financial data contained in the following table, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations.” The following table should also be read in conjunction with “Use of Proceeds” and the audited historical financial statements of our predecessor and our pro forma condensed combined financial statements included elsewhere in this prospectus. Among other things, the historical financial statements include more detailed information regarding the basis of presentation for the information in the following table.

The following table presents Adjusted EBITDA, a financial measure that is not presented in accordance with U.S. generally accepted accounting principles (“GAAP”). We use Adjusted EBITDA in our business as we believe it is an important supplemental measure of our operating performance and liquidity. For a definition of and a reconciliation of Adjusted EBITDA to net income and net cash provided by operating activities, its most directly comparable financial measures in accordance with GAAP, please read “—Non-GAAP Financial Measures.” For a discussion of how we use Adjusted EBITDA to evaluate our operating performance and liquidity, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Adjusted EBITDA.”



 

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Index to Financial Statements
    Remora Royalties, Inc.
Pro Forma
    Predecessor
Historical
 
    Three Months
Ended March 31,
2018
    Year Ended
December 31,

2017
    Three Months
Ended March 31,
    Year Ended December 31,  
        2018     2017     2017     2016  

Statement of Operations Data:

           

Revenue:

           

Oil, natural gas and NGL revenue

  $                  $                  $ 9,934,187     $ 11,436,818     $ 36,059,114     $ 12,438,637  

Cost and expenses:

           

Lease operating expenses

        3,367,645       2,889,744       10,608,592       5,712,571  

Workover expense

        286,250       761,359       2,588,007       870,282  

Production taxes

        604,228       488,218       1,527,684       427,193  

Marketing and other direct operating expenses

        1,493,494       1,427,614       5,426,373       1,171,845  

Depletion, depreciation and amortization

        1,779,265       1,743,568       6,703,123       3,329,649  

Accretion expense

        176,440       143,545       426,925       157,950  

Impairment of oil and natural gas properties

                          30,115,350  

General and administrative expenses

        1,497,060       718,968       3,446,096       1,662,289  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total operating expenses

        9,204,382       8,173,016       30,726,800       43,447,129  

Income (loss) from operations

        729,805       3,263,802       5,332,314       (31,008,492

Net gain (loss) on derivative instruments

        (751,902     7,169,487       5,134,256       (6,280,818

Interest expense

        (1,273,697     (1,449,243     (5,348,882     (2,835,300

Other income (expenses)

        17,128       1,503       1,533,756       (1,180
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total other income (loss)

        (2,008,471     5,721,747       1,319,130       (9,117,298

Income tax expenses (benefit)

                           
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Net income (loss)

  $     $     $ (1,278,666   $ 8,985,549     $ 6,651,444     $ (40,125,790
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Statement of Cash Flows Data:

           

Net cash provided by (used in):

           

Operating activities

      $ 356,960     $ 1,510,260     $ 9,954,122     $ 2,102,807  

Investing activities

      $ 950,149     $ 172,291     $ 8,822,602     $ (40,583,418

Financing activities

      $ (1,359,100   $ 1,163,879     $ (17,518,999   $ 33,728,402  

Other Financial Data:

           

Adjusted EBITDA(1)

  $     $     $ 2,249,734     $ 5,185,596     $ 16,563,317     $ 6,623,770  

Selected Balance Sheet Data:

           

Cash and cash equivalents

  $                        $ 2,481,770     $ 4,122,466     $ 2,533,761     $ 1,276,036  

Total assets

  $       $ 63,072,228     $ 69,363,122     $ 66,185,399     $ 61,863,679  

Long-term debt

  $       $ 47,950,317     $ 67,530,376     $ 49,186,099     $ 66,254,924  

Total liabilities

  $       $ 78,831,327     $ 81,500,350     $ 80,656,732     $ 82,986,456  

Shareholders’ equity / Partners’ deficit

  $       $ (15,759,099   $ (12,137,228   $ (14,471,333   $ (21,122,777

 

(1)   For more information, please read “—Non-GAAP Financial Measures.”

Non-GAAP Financial Measures

Adjusted EBITDA

Adjusted EBITDA is used as a supplemental non-GAAP financial measure by management and external users of our financial statements, such as industry analysts, investors, lenders and rating agencies.



 

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Index to Financial Statements

We believe Adjusted EBITDA is useful because it allows us to more effectively evaluate our operating performance and compare the results of our operations period to period without regard to our financing methods or capital structure. In addition, management uses Adjusted EBITDA to evaluate cash flow available to pay dividends to our stockholders.

We define Adjusted EBITDA as net income (loss) plus depreciation, depletion and accretion expenses, interest expense, non-cash equity compensation, impairment of oil and natural gas properties, income tax expense and unrealized net (gain) loss on derivative instruments. Adjusted EBITDA is not a measure of net income (loss) or net cash provided by operating activities as determined by GAAP. We exclude the items listed above from net income (loss) in arriving at Adjusted EBITDA 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. Certain items excluded from Adjusted EBITDA 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 historic costs of depreciable assets, none of which are components of Adjusted EBITDA.

Adjusted EBITDA should not be considered an alternative to net income, oil, natural gas and NGL revenues, net cash provided by operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP. Our computations of Adjusted EBITDA may not be comparable to other similarly titled measures of other companies.



 

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Index to Financial Statements

The following tables present a reconciliation of Adjusted EBITDA to net income and net cash provided by operating activities, our most directly comparable GAAP financial measures for the periods indicated.

 

    Remora Royalties, Inc.
Pro Forma
    Predecessor Historical  
    Three Months
Ended
March 31,
2018
    Year Ended
December 31,
2017
    Three Months
Ended March 31,
    Year Ended
December 31,
 
      2018     2017     2017     2016  

Reconciliation of net income (loss) to Adjusted EBITDA:

           

Net income (loss)

  $                          $     $ (1,278,666   $ 8,985,549     $ 6,651,444     $ (40,125,790

Depreciation, depletion and accretion expenses

        1,955,705       1,887,113       7,130,048       3,487,599  

Interest expense

        1,273,697       1,449,243       5,348,882       2,835,300  

Income tax expense

                           
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

EBITDA

        1,950,736       12,321,905       19,130,374       (33,802,891

Impairment of oil and natural gas properties

                          30,115,350  

Unrealized net (gain) loss on derivative instruments

        298,998       (7,136,309     (2,567,057     10,311,311  

Equity Compensation

                           
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Adjusted EBITDA

  $     $                          $ 2,249,734     $ 5,185,596     $ 16,563,317     $ 6,623,770  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Reconciliation of net cash provided by operating activities to Adjusted EBITDA:

           

Net cash provided by operating activities

  $     $     $ 356,960     $ 1,510,260     $ 9,954,122     $ 2,102,807  

Interest expense

        1,273,697       1,449,243       5,348,882       2,835,300  

Income tax expense

                           

Impairment of oil and natural gas properties

                          (30,115,350

Unrealized net gain (loss) on derivative instruments

        (298,998     7,136,309       2,567,057       (10,311,311

Equity Compensation

                           

Amortization of debt issuance costs

        (114,219     (111,574     (450,174     (231,793

Settlements on asset retirement obligations

        37,305       5,847       212,313       149,658  

Changes in operating assets and liabilities:

           

Accounts receivable

        1,038,067       2,645,472       914,855       1,314,114  

Prepaid expenses and deposits

        256,105       (103,168     (83,325     356,381  

Accounts payable and accrued expenses

        (598,181     (210,484     666,644       97,303  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

EBITDA

  $     $     $ 1,950,736     $ 12,321,905     $ 19,130,374     $ (33,802,891

Add:

           

Impairment of oil and natural gas properties

                          30,115,350  

Unrealized net (gain) loss on derivative instruments

        298,998       (7,136,309     (2,567,057     10,311,311  

Equity Compensation

                           
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Adjusted EBITDA

  $     $                          $ 2,249,734     $ 5,185,596     $ 16,563,317     $ 6,623,770  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 


 

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Summary Reserve Data

The following table presents our estimated proved and probable oil and natural gas reserves as of December 31, 2017 based on the reserve report prepared by Cawley, Gillespie & Associates, Inc. of the assets to be contributed to us by the Contributing Parties, on a pro forma basis, in connection with the formation transactions. The reserve report was prepared in accordance with the rules and regulations of the SEC. You should refer to “Risk Factors—Risks Related to Our Business—.” Our estimated reserves are based on many assumptions that may prove to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves” and the other risks set forth in “Risk Factors,” “Business—Oil and Natural Gas Data—Proved Reserves,” “Business—Oil and Natural Gas Production Prices and Production Costs—Production and Price History” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in evaluating the material presented below.

 

     Remora Royalties, Inc.
Pro Forma Reserves
 
     As of
December 31, 2017(1)
 

Estimated proved developed reserves:

  

Oil (MBbls)

     2,100  

Natural gas (MMcf)

     76,805  

Natural gas liquids (MBbls)

     1,431  
  

 

 

 

Total (MMcfe)(2)

     97,991  
  

 

 

 

Estimated proved undeveloped reserves:

  

Oil (MBbls)

     107  

Natural gas (MMcf)

     7,014  

Natural gas liquids (MBbls)

     362  
  

 

 

 

Total (MMcfe)(2)

     9,828  
  

 

 

 

Estimated proved reserves:

  

Oil (MBbls)

     2,206  

Natural gas (MMcf)

     83,819  

Natural gas liquids (MBbls)

     1,793  
  

 

 

 

Total (MMcfe)(2)

     107,813  
  

 

 

 

Percent proved developed

     91

Estimated probable developed reserves:

  

Oil (MBbls)

     192  

Natural gas (MMcf)

     6,362  

Natural gas liquids (MBbls)

     0  
  

 

 

 

Total (MMcfe)(2)

     7,514  
  

 

 

 

Estimated probable undeveloped reserves:

  

Oil (MBbls)

     274  

Natural gas (MMcf)

     15,242  

Natural gas liquids (MBbls)

     1,065  
  

 

 

 

Total (MMcfe)(2)

     23,276  
  

 

 

 

Estimated probable reserves:

  

Oil (MBbls)

     466  

Natural gas (MMcf)

     21,604  

Natural gas liquids (MBbls)

     1,065  
  

 

 

 

Total (MMcfe)(2)

     30,790  
  

 

 

 


 

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(1)   Estimates of reserves as of December 31, 2017 were prepared using an average price equal to the unweighted arithmetic average of hydrocarbon prices received on a field-by-field basis on the first day of each month within the year ended December 31, 2017, in accordance with SEC guidelines applicable to reserve estimates as of the end of such period. The unweighted arithmetic average first day of the month prices were $51.34 per Bbl for oil and $2.976 per MMBtu for natural gas at December 31, 2017. The price per Bbl for NGLs was modeled as a percentage of oil price, which was derived from historical accounting data. The reserve estimates do not include any value for possible reserves that may exist, nor do they include any value for undeveloped acreage. The reserve estimates represent our net revenue interest in our properties. Although we believe these estimates are reasonable, actual future production, cash flows, taxes, development expenditures, production costs and quantities of recoverable oil and natural gas reserves may vary substantially from these estimates.

 

(2)   Estimated proved and probable reserves are presented on a “natural gas-equivalent” basis using a conversion of six Mcf per barrel of oil, which is the conversion factor we use in our business. This conversion is based on energy equivalence and not price or value equivalence. If a price equivalent conversion based on the twelve-month average prices for the year ended December 31, 2017 was used, the conversion factor would be approximately 17.1-to-1 Mcf per Bbl of oil. In this prospectus, we supplementally provide “value-equivalent” production information or volumes presented on a “natural gas-equivalent” basis using a conversion factor of 20 Mcf of natural gas per barrel of oil, which is the conversion factor we use in our business. For a discussion of the 20-to-1 conversion factor, please read footnote 3 to the Royalty Interests table under “Business—Key Producing Regions—Royalty Interests.”


 

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Summary Production Data

The following table sets forth information regarding production of oil and natural gas and certain price and cost information for each of the periods indicated:

 

    Remora Royalties, Inc.
Pro Forma(1)
    Predecessor  
    Three Months
Ended March 31,
2018
    Year Ended
December 31,
2017
    Three Months
Ended March 31,
    Year Ended December 31,
 
        2018     2017     2017     2016  

Production Data:

             

Oil and condensate (Bbls)

          49,108       59,429       200,814       146,320  

Natural gas (Mcf)

          2,080,535       1,942,289       6,747,492       2,437,883  

Natural gas liquids (Bbls)

          70,753       162,183       404,393       78,485  

Total (Mcfe)(6:1)(2)

          2,799,702       3,271,961       10,378,734       3,786,713  

Average daily production
(Mcfe/d)(6:1)(2)

          31,108       36,355       28,435       10,346  

Total (Mcfe) (20:1)(2)

          4,477,755       6,374,529       18,851,632       6,933,983  

Average daily production
(Mcfe/d)(20:1)(2)

          49,753       70,828       51,648       18,945  

Average Realized Prices:

             

Oil and condensate (per Bbl)

        $ 63.13     $ 48.30     $ 47.16     $ 39.47  

Natural gas (per Mcf)

        $ 2.27     $ 2.84     $ 2.81     $ 2.26  

Natural gas liquids (per Bbl)

        $ 28.21     $ 18.32     $ 17.64     $ 14.28  

 

(1)   Does not include historical production from oil and natural gas properties to be contributed by the Contributing Parties other than our predecessor, Vendera Resources II, LLC and its affiliates, Vendera Resources III, L.P. and its affiliates and AVAD Energy Partners, LLC, which excludes assets representing approximately 12% of our future undiscounted cash flows, based on the reserve report prepared by Cawley as of December 31, 2017.

 

(2)   “Btu-equivalent” production volumes are presented on a “natural-gas equivalent” basis using a conversion factor of six Mcf of natural gas per barrel of oil, which is based on approximate energy equivalency and does not reflect the price or value relationship between oil and natural gas. In this prospectus, we supplementally provide “value-equivalent” production information or volumes presented on a natural gas-equivalent basis using a conversion factor of 20 Mcf of natural gas per barrel of oil, which is the conversion factor we use in our business. For a discussion of the 20-to-1 conversion factor, please read footnote 3 to the Royalty Interests table under “Business—Key Producing Regions—Royalty Interests.”


 

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RISK FACTORS

Investing in our Class A common stock involves risks. You 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, results of operations and cash available to make dividends could be materially and adversely affected and we may not be able to achieve our goals. We cannot assure you that any of the events discussed in the risk factors below will not occur. Further, the risks and uncertainties described below are not the only ones we face. Additional risks not presently known to us or that we currently deem immaterial may also materially affect our business. If any of these risks occur, the trading price of our Class A common stock could decline and you may lose all or part of your investment.

Risks Related to Our Business

We may not have sufficient available cash to pay dividends on shares of our Class A common stock and we are not required to pay dividends by any law, our certificate of incorporation or our bylaws, and we may change our dividend policy at any time and for any reason.

We intend to declare and pay regular cash dividends on our shares of Class A common stock, although we are not required by any law, our certificate of incorporation, or our bylaws to do so, and we may change our dividend policy at any time and for any reason. Furthermore, we may not have sufficient available cash each quarter to enable us to pay any cash dividends to our stockholders. Our expected aggregate annual cash dividends amount for the full twelve months ending June 30, 2019 is based on the price and production assumptions set forth in “Dividend Policy—Estimated Cash Available to Make Dividend Payments for the Twelve Months Ending June 30, 2019—Assumptions and Considerations.” If our price or production assumptions prove to be inaccurate, our actual dividend payments for the twelve months ending June 30, 2019 may be significantly lower than our forecasted dividend payments and we may not be able to pay dividends at all. Substantially all of the cash we have available to make dividend payments each quarter depends upon the amount of oil, natural gas and NGL revenues we generate, which is dependent upon the prices that the operators of our properties realize from the sale of oil and natural gas production. In addition, the actual amount of our available cash to make dividend payments each quarter will be reduced by replacement capital expenditures we make, if any, payments in respect of our debt instruments and other contractual obligations, general and administrative expenses and fixed charges and reserves for future operating or capital needs that the board of directors may determine are appropriate.

Our dividend policy is subject to the discretion of our board of directors and will depend on, among other things, cash available to make dividend payments, general economic and business conditions, our strategic plans and prospects, our financial results and condition, contractual, legal and regulatory restrictions on the declaration and payment of cash dividends by us and such other factors as our board of directors considers to be relevant.

For a description of additional restrictions and factors that may affect our ability to pay cash dividends, please read “Dividend Policy.”

 

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The assumptions underlying the forecast of cash available to make dividend payments that we include in “Dividend Policy—Estimated Cash Available to Make Dividend Payments for the Twelve Months Ending June 30, 2019” are inherently uncertain and are subject to significant business, economic, financial, regulatory, environmental and competitive risks and uncertainties that could cause actual results to differ materially from those forecasted.

The forecast of cash available to make dividend payments set forth in “Dividend Policy—Estimated Cash Available to Make Dividend Payments for the Twelve Months Ending June 30, 2019” includes our forecast of results of operations, Adjusted EBITDA and cash available to make Dividend Payments for the full twelve months ending June 30, 2019. We estimate that our total cash available to make dividend payments for the full twelve months ending June 30, 2019 will be approximately $         million as compared to approximately $26.3 million for the year ended December 31, 2017 and approximately $23.6 million for the twelve months ended March 31, 2018, respectively, on a pro forma basis. The forecast has been prepared by our management. Neither our independent registered public accounting firm nor any other independent registered public accounting firm has compiled, examined or performed any procedures with respect to the forecast, expressed any opinion or given any other form of assurance on such information or its achievability or assumed any responsibility for the forecast. The assumptions underlying the forecast are inherently uncertain and are subject to significant business, economic, financial, regulatory, environmental and competitive risks and uncertainties that could cause actual results to differ materially from those forecasted. If the forecasted results are not achieved, we would not be able to pay the forecasted annual cash dividends, in which event the market price of our Class A common stock may decline materially. Our actual results may differ materially from the forecasted results presented in this prospectus. Investors should review the forecast of our results of operations for the twelve months ending June 30, 2019 together with the other information included elsewhere in this prospectus, including “Risk Factors” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations.” The pro forma available cash information for the year ended December 31, 2017 and for the twelve months ended March 31, 2018 do not reflect the actual cash that we would have generated over the course of those periods.

The amount of cash we have available to make dividend payments to holders of our Class A common stock depends primarily on our cash flow and not solely on profitability, which may prevent us from paying dividends during periods when we record net income.

The amount of cash we have available to make dividend payments depends primarily upon our cash flow and not solely on profitability, which will be affected by non-cash items. For example, we may have significant capital expenditures in the future. While these items may not affect our profitability in a quarter, they would reduce the amount of cash available to make dividend payments with respect to such quarter. As a result, we may pay cash dividends during periods in which we record net losses for financial accounting purposes and may be unable to pay cash dividends during periods in which we record net income.

Our business is difficult to evaluate because we have a limited financial history.

Remora Royalties, Inc. was formed in May 2018 and does not have historical financial statements. Our predecessor, Remora Petroleum, L.P., was formed in July 2011. We do not have historical financial statements with respect to our royalty interests for periods prior to their acquisition by the Contributing Parties. As a result, with respect to some of our assets, there is only limited historical financial information available upon which to base your evaluation of our performance.

 

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The amount of our quarterly dividend payment, if any, may vary significantly both quarterly and annually and will be directly dependent on the performance of our business.

Investors who are looking for an investment that will pay regular and predictable quarterly cash dividends should not invest in our Class A common stock. Our future business performance may be volatile, and our cash flows may be unstable. Please read “—All of our revenues are derived from royalty payments that are based on the price at which oil, natural gas and NGLs produced from the acreage underlying our interests is sold. The volatility of these prices due to factors beyond our control greatly affects our business, financial condition, results of operations and cash available to make dividend payments.” Because our quarterly dividend payments will significantly correlate to the cash we generate each quarter after payment of our fixed and variable expenses, future quarterly dividend payments paid to our stockholders may vary significantly from quarter to quarter and may be zero. Please read “Dividend Policy.”

All of our revenues are derived from royalty payments that are based on the price at which oil, natural gas and NGLs produced from the acreage underlying our interests is sold. The volatility of these prices due to factors beyond our control greatly affects our business, financial condition, results of operations and cash available to make dividend payments.

Our revenues, operating results, cash available to make dividend payments and the carrying value of our oil and natural gas properties depend significantly upon the prevailing prices for oil, natural gas and NGLs. Historically, oil, natural gas and NGL prices have been volatile and are subject to fluctuations in response to changes in supply and demand, market uncertainty and a variety of additional factors that are beyond our control, including:

 

    the domestic and foreign supply of and demand for oil, natural gas and NGLs;

 

    the level of prices and expectations about future prices of oil, natural gas and NGLs;

 

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

 

    the cost of exploring for, developing, producing and delivering oil and natural gas;

 

    the price and quantity of foreign imports;

 

    the level of U.S. domestic production;

 

    political and economic conditions in oil producing regions, including the Middle East, Africa, South America and Russia;

 

    the ability of members of the Organization of Petroleum Exporting Countries to agree to and maintain oil price and production controls;

 

    speculative trading in crude oil, natural gas and NGL derivative contracts;

 

    the level of consumer product demand;

 

    weather conditions and other natural disasters;

 

    risks associated with operating drilling rigs;

 

    technological advances affecting energy consumption;

 

    domestic and foreign governmental regulations and taxes;

 

    the continued threat of terrorism and the impact of military and other action;

 

    the proximity, cost, availability and capacity of oil and natural gas pipelines and other transportation facilities;

 

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    the price and availability of alternative fuels; and

 

    overall domestic and global economic conditions.

These factors and the volatility of the energy markets make it extremely difficult to predict future oil and natural gas price movements with any certainty. For example, during the past five years, the posted price for WTI has ranged from a low of $26.19 per Bbl in February 2016 to a high of $110.62 per Bbl in September 2013, and the Henry Hub spot market price of natural gas has ranged from a low of $1.49 per MMBtu in March 2016 to a high of $8.15 per MMBtu in February 2014. On December 29, 2017, the WTI posted price for crude oil was $60.46 per Bbl and the Henry Hub spot market price of natural gas was $3.69 per MMBtu. Additionally, NGL prices have fluctuated from approximately $30.48 per Boe in January 2015 to $46.92 per Boe in December 2017. The reduction in prices has been caused by many factors, including increases in oil and natural gas production and reserves from unconventional (shale) reservoirs, without an offsetting increase in demand, as well as actions by the Organization of Petroleum Exporting Countries to maintain or raise production levels. The International Energy Agency forecasts continued low global demand growth in 2018. This environment could cause prices to remain at current levels or to fall to lower levels. Any substantial decline in the price of oil, natural gas and NGLs or prolonged period of low commodity prices will materially adversely affect our business, financial condition, results of operations and cash available to make dividend payments. We may choose to use various derivative instruments to minimize the impact of commodity price fluctuations. However, we cannot hedge the entire exposure of our operations from commodity price volatility. To the extent we do not hedge against commodity price volatility, or our hedges are not effective, our results of operations and financial position may be diminished.

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, or if we were to experience sufficient downward adjustments to our estimated proved reserves or the present value of estimated future net revenues, we will be required to take write-downs of the carrying values of our properties.

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. The net capitalized costs of proved oil and natural gas properties are subject to a full cost ceiling limitation for which the costs are not allowed to exceed their related estimated future net revenues discounted at 10%. To the extent capitalized costs of evaluated oil and natural gas properties, net of accumulated depreciation, depletion, amortization and impairment, exceed estimated discounted future net revenues of proved oil, natural gas and NGL reserves, the excess capitalized costs are charged to expense. The risk that we will be required to recognize impairments of our oil and natural gas properties increases during periods of low commodity prices. In addition, impairments would occur if we were to experience sufficient downward adjustments to our estimated proved reserves or the present value of estimated future net revenues. An impairment recognized in one period may not be reversed in a subsequent period even if higher oil and natural gas prices increase the cost center ceiling applicable to the subsequent period. Our predecessor did not incur any impairment for the year ended December 31, 2017 or the three months ended March 31, 2018. Impairments totaled $30.1 million for the year ended December 31, 2016 primarily due to changes in reserve values resulting from depressed commodity prices in 2016. We may incur impairment charges in the future, which could materially adversely affect our results of operations for the periods in which such charges are taken.

 

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We expect to enter into hedging transactions, which may not be effective in reducing the volatility of our cash flows.

We expect to enter into hedging transactions with the intent of reducing volatility in our cash flows due to fluctuations in the price of oil, natural gas and NGLs. However, these hedging activities may not be as effective as we intend in reducing the volatility of our cash flows and, if entered into, are subject to the risks that the terms of the derivative instruments will be imperfect, a counterparty may not perform its obligations under a derivative contract, there may be a change in the expected differential between the underlying commodity price in the derivative instrument and the actual price received, our hedging policies and procedures may not be properly followed and the steps we take to monitor our derivative financial instruments may not detect and prevent violations of our risk management policies and procedures, particularly if deception or other intentional misconduct is involved. Further, we may be limited in receiving the full benefit of increases in oil, natural gas and NGL prices as a result of these hedging transactions. The occurrence of any of these risks could prevent us from realizing the benefit of a derivative contract.

The development of our proved undeveloped reserves may take longer and may require higher levels of capital expenditures from the operators of our properties than we or they currently anticipate.

As of December 31, 2017, 9.1% of our total estimated proved reserves were proved undeveloped reserves and may not be ultimately developed or produced by the operators of our properties. Recovery of proved undeveloped reserves requires significant capital expenditures and successful drilling operations by the operators of our properties. The reserve data included in the reserve report of our independent petroleum engineer assume that substantial capital expenditures by the operators of our properties are required to develop such reserves. We typically do not have access to the estimated costs of development of these reserves or the scheduled development plans of our third-party operators. We take into consideration the estimated costs of development or the scheduled development plans from any development provisions in the relevant lease agreement and the historical drilling activity, rig locations, production data and permit trends, as well as investor presentations and other public statements of our Operating Affiliate and our other operators. The development of such reserves may take longer and may require higher levels of capital expenditures from the operators than we anticipate. Delays in the development of our reserves, increases in costs to drill and develop such reserves or decreases or continued volatility in commodity prices will reduce the future net revenues of our estimated proved undeveloped reserves and may result in some projects becoming uneconomical for the operators of our properties. In addition, delays in the development of reserves could force us to reclassify certain of our proved reserves as unproved reserves.

Our future success depends on replacing reserves through acquisitions and the exploration and development activities of the operators of our properties.

Our future success depends upon our ability to acquire additional oil, natural gas and NGL reserves that are economically recoverable. Our proved reserves will generally decline as reserves are depleted, except to the extent that successful exploration or development activities are conducted on our properties or we acquire properties containing proved reserves, or both. Aside from acquisitions, we have no control over the exploration and development of our properties. In addition, we do not currently intend to retain cash from our operations for capital expenditures necessary to replace our existing oil, natural gas and NGL reserves or otherwise maintain an asset base. To increase reserves and production, we would need the operators of our properties to undertake replacement activities or use third parties to accomplish these activities.

 

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Our failure to successfully identify, complete and integrate acquisitions of properties or businesses would slow our growth and could materially adversely affect our results of operations and cash available to make dividend payments.

We depend in part on acquisitions to grow our reserves, production and cash generated from operations. Our decision to acquire a property will depend in part on the evaluation of data obtained from production reports and engineering studies, geophysical and geological analyses and seismic data and other information, the results of which are often inconclusive and subject to various interpretations. The successful acquisition of properties requires an assessment of several factors, including:

 

    recoverable reserves;

 

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

 

    development plans;

 

    operating costs; and

 

    potential environmental and other liabilities.

The accuracy of these assessments is inherently uncertain and we may not be able to identify attractive acquisition opportunities. In connection with these assessments, we perform a review of the subject properties that we believe to be generally consistent with industry practices, given the nature of our interests. 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. Inspections are often not performed on every well, and environmental problems, such as groundwater contamination, are not necessarily observable even when an inspection is undertaken. Even when problems are identified, the seller may be unwilling or unable to provide effective contractual protection against all or part of the problems. Even if we do identify attractive acquisition opportunities, we may not be able to complete the acquisition or do so on commercially acceptable terms. Unless our Operating Affiliate and our other operators further develop our existing properties, we will depend on acquisitions to grow our reserves, production and cash flow.

There is intense competition for acquisition opportunities in our industry. Competition for acquisitions may increase the cost of, or cause us to refrain from, completing acquisitions. Our ability to complete acquisitions is dependent upon, among other things, our ability to obtain debt and equity financing and, in some cases, regulatory approvals. Further, these acquisitions may be in geographic regions in which we do not currently hold assets, which could result in unforeseen operating difficulties. In addition, if we acquire interests in new states, we may be subject to additional and unfamiliar legal and regulatory requirements. Compliance with regulatory requirements may impose substantial additional obligations on us and our management, cause us to expend additional time and resources in compliance activities and increase our exposure to penalties or fines for non-compliance with such additional legal requirements. Further, the success of any completed acquisition will depend on our ability to integrate effectively the acquired business into our existing business. 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 suitable acquisition opportunities, negotiate acceptable terms, obtain financing for acquisitions on acceptable terms or successfully acquire identified targets. Our failure to minimize any unforeseen difficulties could materially adversely affect our financial condition and cash available to make dividend payments. The inability to effectively manage these

 

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acquisitions could reduce our focus on subsequent acquisitions, which, in turn, could negatively impact our growth and cash available to make dividend payments.

Any acquisitions of additional royalty interests that we complete will be subject to substantial risks.

Even if we do make acquisitions that we believe will increase our cash generated from operations, these acquisitions may nevertheless result in a decrease in our cash dividends per share. Any acquisition involves potential risks, including, among other things:

 

    the validity of our assumptions about estimated proved reserves, future production, prices, revenues, capital expenditures and production costs;

 

    a decrease in our liquidity by using a significant portion of our cash generated from operations or borrowing capacity to finance acquisitions;

 

    a significant increase in our interest expense or financial leverage if we incur debt to finance acquisitions;

 

    the assumption of unknown liabilities, losses or costs for which we are not indemnified or for which any indemnity we receive is inadequate;

 

    mistaken assumptions about the overall cost of equity or debt;

 

    our ability to obtain satisfactory title to the assets we acquire;

 

    an inability to hire, train or retain qualified personnel to manage and operate our growing business and assets; and

 

    the occurrence of other significant changes, such as impairment of oil and natural gas properties, goodwill or other intangible assets, asset devaluation or restructuring charges.

If we are unable to make acquisitions on economically acceptable terms from the Contributing Parties or third parties, our future growth will be limited.

Our ability to grow depends in part on our ability to make acquisitions that increase our cash generated from our royalty interests. The acquisition component of our strategy is based, in large part, on our expectation of ongoing acquisitions from industry participants, including the Contributing Parties. While we believe the Contributing Parties will be incentivized through their ownership of Class B common stock and RH Units to offer us the opportunity to acquire additional royalty interests, including with respect to certain assets for which certain of the Contributing Parties will grant us a right of first offer for a period of three years after the closing of this offering, should they choose to sell such assets, there can be no assurance that any such offer will be made, and there can be no assurance we will reach agreement on the terms with respect to the assets or any other acquisition opportunities offered to us by any of the Contributing Parties or be able to obtain financing for such acquisition opportunities. Furthermore, many factors could impair our access to future acquisitions, including a change in control of any of the Contributing Parties. A material decrease in the sale of oil and natural gas properties by the Contributing Parties or by third parties would limit our opportunities for future acquisitions and could materially adversely affect our business, results of operations, financial condition and ability to pay quarterly cash dividends to our stockholders.

 

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We depend on unaffiliated operators for a significant portion of the exploration, development and production on the properties in which we own royalty interests. A reduction in the expected number of wells to be drilled on the acreage underlying our interests by these operators or the failure of these operators to adequately and efficiently develop and operate the underlying acreage could materially adversely affect our results of operations and cash available to make dividend payments.

Because we depend on our third party operators for a significant portion of the exploration, development and production on our properties, we have no control over the operations related to our properties. For the year ended December 31, 2017 and the three months ended March 31, 2018, we received revenue from over 250 unaffiliated operators. On a pro forma basis for the year ended December 31, 2017 and the three months ended March 31, 2018, we received     % and     % of our revenue from the unaffiliated operators, respectively. If these operators do not adequately and efficiently perform operations or act in ways that are beneficial to us, our production and revenues could decline. The operators of our properties are often not obligated to undertake any development activities. In the absence of a specific contractual obligation, any development and production activities will be subject to their sole discretion (subject, however, to certain implied obligations to develop imposed by state law). The operators of our properties could determine to drill and complete fewer wells on our acreage than we currently expect. The success and timing of drilling and development activities on our properties, and whether the operators elect to drill any additional wells on our acreage, depends on a number of factors that will be largely outside of our control, including:

 

    the capital costs required for drilling activities by the operators of our properties, which could be significantly more than anticipated;

 

    the ability of the operators of our properties to access capital;

 

    prevailing commodity prices;

 

    the availability of suitable drilling equipment, production and transportation infrastructure and qualified operating personnel;

 

    the operators’ expertise, operating efficiency and financial resources;

 

    approval of other participants in drilling wells;

 

    the operators’ expected return on investment in wells drilled on our acreage as compared to opportunities in other areas;

 

    the selection of technology;

 

    the selection of counterparties for the marketing and sale of production; and

 

    the rate of production of the reserves.

The operators may elect not to undertake development activities, or may undertake these activities in an unanticipated fashion, which may result in significant fluctuations in our oil, natural gas and NGL revenues and cash available to make dividend payments. Additionally, if an operator were to experience financial difficulty, the operator might not be able to pay its royalty payments or continue its operations, which could have a material adverse impact on us. Sustained reductions in production by the operators of our properties may also materially adversely affect our results of operations and cash available to make dividend payments.

Project areas on our properties, which are in various stages of development, may not yield oil or natural gas in commercially viable quantities.

Project areas on our properties are in various stages of development, ranging from project areas with current drilling or production activity to project areas that have limited drilling or production history. If the

 

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wells in the process of being completed do not produce sufficient revenues or if dry holes are drilled, our financial condition, results of operations and cash available to make dividend payments may be materially adversely affected.

Our estimated reserves are based on many assumptions that may prove to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.

It is not possible to measure underground accumulations of oil or natural gas in an exact way. Oil and natural gas reserve engineering requires subjective estimates of underground accumulations of oil and natural gas and assumptions concerning future oil and natural gas prices, production levels, ultimate recoveries and operating and development costs. As a result, estimated quantities of proved reserves, probable reserves, projections of future production rates and the timing of development expenditures may prove to be incorrect.

Our historical estimates of proved reserves, probable reserves and related valuations as of December 31, 2017 were prepared by Cawley, which conducted a well-by-well review of all our properties for the period covered by its reserve report using information provided by us. Over time, we may make material changes to reserve estimates taking into account the results of actual drilling, testing and production and changes in prices. Some of our reserve estimates were made without the benefit of a lengthy production history, which are less reliable than estimates based on a lengthy production history. In estimating our reserves, we and our reserve engineers make certain assumptions that may prove to be incorrect, including assumptions regarding future oil and natural gas prices, production levels and operating and development costs. Any significant variance from these assumptions to actual figures could greatly affect our estimates of reserves, the economically recoverable quantities of oil and natural gas attributable to any particular group of properties, the classifications of reserves based on risk of recovery and estimates of future net cash flows. Numerous changes over time to the assumptions on which our reserve estimates are based, as described above, often result in the actual quantities of oil and natural gas that are ultimately recovered being different from our reserve estimates.

The present value of future net cash flows from our reserves is not necessarily the same as the current market value of our estimated reserves. In accordance with rules established by the SEC and the Financial Accounting Standards Board (the “FASB”), we base the estimated discounted future net cash flows from our proved reserves on the twelve-month average oil and natural gas index prices, calculated as the unweighted arithmetic average for the first-day-of-the-month price for each month, and costs in effect on the date of the estimate, holding the prices and costs constant throughout the life of the properties. Actual future prices and costs may differ materially from those used in the present value estimate, and future net present value estimates using then current prices and costs may be significantly less than the current estimate. In addition, the 10% discount factor we use when calculating discounted future net cash flows may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the oil and natural gas industry in general.

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 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 proved undeveloped reserves as the operators of our properties pursue their drilling programs. Moreover, we may be required to write down our proved undeveloped reserves if those wells are not drilled within the required five-year timeframe. Furthermore, we typically do not have access to the drilling schedules of our Operating Affiliate and our

 

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other operators and make our determinations about their estimated drilling schedules from any development provisions in the relevant lease agreement and the historical drilling activity, rig locations, production data and permit trends, as well as investor presentations and other public statements of our Operating Affiliate and our other operators.

Restrictions in our secured revolving credit facility and future debt agreements could limit our growth and our ability to engage in certain activities.

Prior to the completion of this offering, we will enter into a $     million secured revolving credit facility. Our secured revolving credit facility will be secured by substantially all of our assets. We expect our secured revolving credit facility will contain various covenants and restrictive provisions that will limit our ability to, among other things:

 

    incur or guarantee additional debt;

 

    pay dividends on, or redeem or repurchase, our Class A common stock;

 

    enter into hedging arrangements;

 

    make certain investments and acquisitions;

 

    incur certain liens or permit them to exist;

 

    enter into certain types of transactions with affiliates;

 

    merge or consolidate with another company; and

 

    transfer, sell or otherwise dispose of assets.

We expect our secured revolving credit facility will also contain covenants requiring us to maintain certain financial ratios or to reduce our indebtedness if we are unable to comply with such ratios. Our ability to meet those financial ratios and tests can be affected by events beyond our control. These restrictions 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 secured revolving credit facility will impose on us.

A failure to comply with the provisions of our secured revolving credit facility could result in an event of default, which could enable the lenders to declare, subject to the terms and conditions of our secured revolving credit facility, any outstanding principal of that debt, together with accrued and unpaid interest, to be immediately due and payable. If the payment of the debt is accelerated, cash flows from our operations may be insufficient to repay such debt in full, and our stockholders could experience a partial or total loss of their investment. We expect our secured revolving credit facility will contain events of default customary for transactions of this nature, including the occurrence of a change of control. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Indebtedness—New Revolving Credit Agreement.”

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

We anticipate that our secured revolving credit facility will limit the amounts we can borrow up to a borrowing base amount, which the lenders, in their sole discretion, determine on a semi-annual basis based upon projected revenues from the oil and natural gas properties securing our loan. The borrowing base will be determined based on our oil and natural gas properties and the oil and natural gas properties of our

 

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wholly owned subsidiaries. The lenders can unilaterally adjust the borrowing base and the borrowings permitted to be outstanding under our secured revolving credit facility. Any increase in the borrowing base requires the consent of the lenders holding 100% of the commitments. If the requisite number of lenders do not agree to an increase, then the borrowing base will be the lowest borrowing base acceptable to such lenders. Decreases in the available borrowing amount could result from declines in oil, natural gas and NGL prices, operating difficulties or increased costs, declines in reserves, lending requirements or regulations or certain other circumstances. Outstanding borrowings in excess of the borrowing base must be repaid, or we must pledge other oil and natural gas properties as additional collateral after applicable grace periods. We do not expect to have any substantial unpledged properties, and we may not have the financial resources in the future to make mandatory principal prepayments required under our secured revolving credit facility.

Our debt levels may limit our flexibility to obtain additional financing and pursue other business opportunities.

Our existing and future indebtedness could have important consequences to us, including:

 

    our ability to obtain additional financing, if necessary, for working capital, capital expenditures, acquisitions or other purposes may be impaired or such financing may not be available on terms acceptable to us;

 

    covenants in our existing and future credit and debt arrangements will require us to meet financial tests that may affect our flexibility in planning for and reacting to changes in our business, including possible acquisition opportunities;

 

    our access to the capital markets may be limited;

 

    our borrowing costs may increase;

 

    we may need a substantial portion of our cash flow to make principal and interest payments on our indebtedness, reducing the funds that would otherwise be available for operations, future business opportunities and cash dividends to stockholders; and

 

    our debt level may make us more vulnerable than our competitors with less debt to competitive pressures or a downturn in our business or the economy generally.

Our ability to service our indebtedness will depend upon, among other things, our future financial and operating performance, which will be affected by prevailing economic conditions and financial, business, regulatory and other factors, some of which are beyond our control. If our operating results are not sufficient to service our current or future indebtedness, we will be forced to take actions such as reducing cash dividends, reducing or delaying business activities, acquisitions, investments and/or capital expenditures, selling assets, restructuring or refinancing our indebtedness, or seeking additional equity capital or bankruptcy protection. We may not be able to effect any of these remedies on satisfactory terms or at all.

We do not intend to retain cash from our operations for replacement capital expenditures. Unless we replenish our oil, natural gas and NGL reserves, our cash generated from operations and our ability to pay cash dividends to our stockholders could be materially adversely affected.

Producing oil and natural gas wells are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Our future oil, natural gas and NGL reserves and the operators’ production thereof and our cash generated from operations and ability to pay dividends are highly dependent on the successful development and exploitation of our current reserves. Based on our reserve report as of December 31, 2017, the average estimated five-year decline rate for our existing proved

 

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developed producing reserves is approximately 9.9%. However, the production decline rates of our properties may be significantly higher than currently estimated if the wells on our properties do not produce as expected. We may also not be able to acquire additional reserves to replace the current and future production of our properties at economically acceptable terms, which could materially adversely affect our business, financial condition, results of operations and cash available to make dividend payments.

We are unlikely to be able to sustain or increase dividends over the long term without making accretive acquisitions or capital expenditures that maintain or grow our asset base. We will need to make substantial capital expenditures to maintain and grow our asset base, which will reduce our cash available to make dividend payments. We do not intend to retain cash from our operations for replacement capital expenditures primarily due to our expectation that the continued development of our properties by working interest owners will offset the natural production declines from our existing wells. Please read “Dividend Policy.”

Over a longer period of time, if we do not set aside sufficient cash reserves or make sufficient expenditures to maintain or grow our asset base, we would expect to reduce our cash dividends. With our reserves decreasing, if we do not reduce our cash dividends, then a portion of the cash dividends may be considered a return of part of your investment in us as opposed to a return on your investment.

A deterioration in general economic, business or industry conditions would materially adversely affect our results of operations, financial condition and cash available to make dividend payments.

In recent years, concerns over global economic conditions, energy costs, geopolitical issues, inflation, the availability and cost of credit and slow economic growth in the United States have contributed to economic uncertainty and diminished expectations for the global economy. Meanwhile, 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 economies of the United States and other countries. Concerns about global economic growth have had a significant adverse impact on global financial markets and commodity prices. With current global economic growth slowing, demand for oil, natural gas and NGL production has, in turn, softened. An oversupply of crude oil in 2015 led to a severe decline in worldwide oil prices. If the economic climate in the United States or abroad deteriorates further, worldwide demand for petroleum products could further diminish, which could impact the price at which oil, natural gas and NGL from our properties are sold, affect the ability of vendors, suppliers and customers associated with our properties to continue operations and ultimately materially adversely impact our results of operations, financial condition and cash available to make dividend payments.

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

Fuel conservation measures, alternative fuel requirements, increasing consumer demand for alternatives to oil and natural gas, technological advances in fuel economy and energy-generation devices could reduce demand for oil and natural gas. The impact of the changing demand for oil and natural gas services and products may materially adversely affect our business, financial condition, results of operations and cash available to make dividend payments.

Competition in the oil and natural gas industry is intense, which may adversely affect our Operating Affiliate and our other operators’ ability to succeed.

The oil and natural gas industry is intensely competitive, and the operators of our properties compete with other companies that may have greater resources. Many of these companies explore for and produce oil and natural gas, carry on midstream and refining operations and market petroleum and other products on a regional, national or worldwide basis. In addition, these companies may have a greater ability to continue

 

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exploration activities during periods of low oil and natural gas market prices. Our Operating Affiliate’s and our other operators’ larger competitors may be able to absorb the burden of present and future federal, state, local and other laws and regulations more easily than our Operating Affiliate and our other operators can, which would adversely affect our Operating Affiliate’s and our other operators’ competitive position. Our Operating Affiliate and our other operators may have fewer financial and human resources than many companies in our industry, and may be at a disadvantage in bidding for exploratory prospects and producing oil and natural gas properties.

We rely on a few key individuals whose absence or loss could materially adversely affect our business.

Many key responsibilities within our business have been assigned to a small number of individuals. We rely on our founders for their knowledge of the oil and natural gas industry, relationships within the industry and experience in identifying, evaluating and completing acquisitions. The loss of their services could adversely affect our business. Further, we do not maintain “key person” life insurance policies on any of our executive team or other key personnel. As a result, we are not insured against any losses resulting from the death of these key individuals.

Increased costs of capital could materially adversely affect our business.

Our business, ability to make acquisitions and operating results could be harmed by factors such as the availability, terms and cost of capital or increases in interest rates. Changes in any one or more of these factors could cause our cost of doing business to increase, limit our access to capital, limit our ability to pursue acquisition opportunities and place us at a competitive disadvantage. A significant reduction in the availability of credit could materially and adversely affect our ability to achieve our planned growth and operating results.

Loss of our or our operators’ information and computer systems could materially adversely affect our business.

We are dependent on our and our operators’ information systems and computer-based programs. If any of such programs or systems were to fail for any reason, including as a result of a cyber-attack, or create erroneous information in our or our operators’ hardware or software network infrastructure, possible consequences include loss of communication links and inability to automatically process commercial transactions or engage in similar automated or computerized business activities. In addition to our services agreement with our Operating Affiliate, we rely on third party service providers to perform some of our data entry, investor relations and other functions. If the programs or systems used by our third-party service providers are not adequately functioning, we could experience loss of important data. Any of the foregoing consequences could materially adversely affect our business.

A terrorist attack or armed conflict could harm our business.

Terrorist activities, anti-terrorist activities and other armed conflicts involving the United States or other countries may adversely affect the United States and global economies. If any of these events occur, the resulting political instability and societal disruption could reduce overall demand for oil and natural gas, potentially putting downward pressure on demand for our Operating Affiliate and our other operators’ services and causing a reduction in our revenues. Oil and natural gas facilities, including those of our Operating Affiliate and our other operators, could be direct targets of terrorist attacks, and if infrastructure integral to our Operating Affiliate and our other operators is destroyed or damaged, they may experience a significant disruption in their operations. Any such disruption could materially adversely affect our financial condition, results of operations and cash available to make dividend payments.

 

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Title to the properties in which we have an interest may be impaired by title defects.

We may not elect to incur the expense of retaining lawyers to examine the title to the mineral interest. Rather, we may rely upon the judgment of oil and natural gas lease brokers or landmen 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 an interest worthless and can materially adversely affect our results of operations, financial condition and cash available to make dividend payments. No assurance can be given that we will not suffer a monetary loss from title defects or title failure. Additionally, undeveloped acreage has greater risk of title defects than developed acreage. If there are any title defects or defects in assignment of leasehold rights in properties in which we hold an interest, we will suffer a financial loss.

The potential drilling locations identified by our Operating Affiliate and our other operators of our properties are susceptible to uncertainties that could materially alter the occurrence or timing of their drilling.

The ability of the operators of our properties to drill and develop identified potential drilling locations depends on a number of uncertainties, including the availability of capital, construction of infrastructure, inclement weather, regulatory changes and approvals, oil and natural gas prices, costs, drilling results and the availability of water. Further, the potential drilling locations identified by the operators of our properties are in various stages of evaluation, ranging from locations that are ready to drill to locations that will require substantial additional interpretation. The use of technologies and the study of producing fields in the same area will not enable the operators of our properties 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 sufficient quantities to be economically viable. Even if sufficient amounts of oil or natural gas exist, the operators of our properties may damage the potentially productive hydrocarbon-bearing formation or experience mechanical difficulties while drilling or completing the well, possibly resulting in a reduction in production from the well or abandonment of the well. If the operators of our properties drill additional wells that they identify as dry holes in current and future drilling locations, their drilling success rate may decline and materially harm their business as well as ours.

We cannot assure you that the analogies our Operating Affiliate and our other operators draw from available data from the wells on our acreage, more fully explored locations, or producing fields will be applicable to their drilling locations. Further, initial production rates reported by our or other operators in the areas in which our reserves are located may not be indicative of future or long-term production rates. Because of these uncertainties, we do not know if the potential drilling locations our Operating Affiliate and our other operators have identified will ever be drilled or if our Operating Affiliate and our other operators will be able to produce oil or natural gas from these or any other potential drilling locations. As such, the actual drilling activities of the operators of our properties may materially differ from those presently identified, which could materially adversely affect our business, results of operation and cash available to make dividend payments.

Acreage must be drilled before lease expiration, generally within three to five years, in order to hold the acreage by production. Our Operating Affiliate and our other operators’ failure to drill sufficient wells or sustain production to hold acreage may result in loss of the lease and prospective drilling opportunities.

Leases on oil and natural gas properties typically have a term of three to five years, after which they expire unless, prior to expiration, production is established within the spacing units covering the undeveloped acres. Any reduction in our Operating Affiliate and our other operators’ drilling programs,

 

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either through a reduction in capital expenditures or the unavailability of drilling rigs, could result in the loss of acreage through lease expirations which may terminate our overriding royalty interests derived from such leases. If our royalties are derived from mineral interests and production or drilling ceases on the leased property, the lease is typically terminated, subject to certain exceptions, and all mineral rights revert back to us and we will have to seek new lessees to explore and develop such mineral interests. Any such losses of our Operating Affiliate and our other operators or lessees could materially and adversely affect the growth of our financial condition, results of operations and cash available to make dividend payments.

The unavailability, high cost, or shortages of rigs, equipment, raw materials, supplies or personnel may restrict or result in increased costs for operators related to developing and operating our properties.

The oil and natural gas industry is cyclical, which can result in shortages of drilling rigs, equipment, raw materials (particularly sand and other proppants), supplies and personnel. When shortages occur, the costs and delivery times of rigs, equipment and supplies increase and demand for, and wage rates of, qualified drilling rig crews also rise with increases in demand. We cannot predict whether these conditions will exist in the future and, if so, what their timing and duration will be. In accordance with customary industry practice, the operators of our properties rely on independent third party service providers to provide many of the services and equipment necessary to drill new wells. If the operators of our properties are unable to secure a sufficient number of drilling rigs at reasonable costs, our financial condition and results of operations could suffer. In addition, they may not have long-term contracts securing the use of their rigs, and the operator of those rigs may choose to cease providing services to them. Shortages of drilling rigs, equipment, raw materials (particularly sand and other proppants), supplies, personnel, trucking services, tubulars, fracking and completion services and production equipment could delay or restrict our Operating Affiliate and our other operators’ exploration and development operations, which in turn could materially adversely affect our financial condition, results of operations and cash available to make dividend payments.

The results of exploratory drilling in shale plays will be subject to risks associated with drilling and completion techniques and drilling results may not meet our expectations for reserves or production.

The operators of our properties may use the latest drilling and completion techniques in their operations, and these techniques come with inherent risks. Certain of the new techniques that the operators of our properties may adopt, such as horizontal drilling, infill drilling and multi-well pad drilling, may cause irregularities or interruptions in production due to, in the case of infill drilling, offset wells being shut in and, in the case of multi-well pad drilling, the time required to drill and complete multiple wells before these wells begin producing. The results of drilling in new or emerging formations are more uncertain initially than drilling results in areas that are more developed and have a longer history of established production. Newer or emerging formations and areas often have limited or no production history and consequently the operators of our properties will be less able to predict future drilling results in these areas.

Ultimately, the success of these drilling and completion techniques can only be evaluated over time as more wells are drilled and production profiles are established over a sufficiently long time period. If our Operating Affiliate and our other operators’ drilling results are weaker than anticipated or they are unable to execute their drilling program on our properties because of capital constraints, lease expirations, access to gathering systems, or declines in oil and natural gas prices, our operating and financial results in these areas may be lower than 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, and our results of operations and cash available to make dividend payments could be materially adversely affected.

 

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The marketability of oil and natural gas production is dependent upon transportation and other facilities, certain of which neither we, our Operating Affiliate, nor the other operators of our properties control. If these facilities are unavailable, our Operating Affiliate and our other operators’ operations could be interrupted and our results of operations and cash available to make dividend payments could be materially adversely affected.

The marketability of our Operating Affiliate and our other operators’ oil and natural gas production will depend in part upon the availability, proximity and capacity of transportation facilities, including gathering systems, trucks and pipelines, owned by third parties. Neither we, our Operating Affiliate, nor the other operators of our properties control these third party transportation facilities and our Operating Affiliate and our other operators’ access to them may be limited or denied. Insufficient production from the wells on our acreage or a significant disruption in the availability of third party transportation facilities or other production facilities could adversely impact our Operating Affiliate and our other operators’ ability to deliver to market or produce oil and natural gas and thereby cause a significant interruption in our Operating Affiliate and our other operators’ operations. If they are unable, for any sustained period, to implement acceptable delivery or transportation arrangements or encounter production related difficulties, they may be required to shut in or curtail production. In addition, the amount of oil and natural gas that can be produced and sold may be subject to curtailment in certain other circumstances outside of our or our Operating Affiliate and our other operators’ control, such as pipeline interruptions due to maintenance, excessive pressure, inability of downstream processing facilities to accept unprocessed gas, physical damage to the gathering system or transportation system or lack of contracted capacity on such systems. The curtailments arising from these and similar circumstances may last from a few days to several months. In many cases, we, our Operating Affiliate and our other operators are provided with limited notice, if any, as to when these curtailments will arise and the duration of such curtailments. Any such shut in or curtailment, or an inability to obtain favorable terms for delivery of the oil and natural gas produced from our acreage, could materially adversely affect our financial condition, results of operations and cash available to make dividend payments.

Oil and natural gas operations are subject to various governmental laws and regulations. Compliance with these laws and regulations can be burdensome and expensive, and failure to comply could result in significant liabilities, which could reduce our cash available to make dividend payments.

Operations on the properties in which we hold interests are subject to various federal, state and local governmental regulations that may be changed from time to time in response to economic and political conditions. Matters subject to regulation include drilling operations, discharges or releases of pollutants or wastes and production and conservation matters (discussed in more detail below). From time to time, regulatory agencies have imposed price controls and limitations on production by restricting the rate of flow of oil and natural gas wells below actual production capacity to conserve supplies of oil and natural gas. In addition, the production, handling, storage, transportation, remediation, emission and disposal of oil and natural gas, by-products thereof and other substances and materials produced or used in connection with oil and natural gas operations are subject to regulation under federal, state and local laws and regulations primarily relating to protection of human health and safety and the environment. Failure to comply with these laws and regulations by the operators of our properties may result in the assessment of sanctions, including administrative, civil or criminal penalties, permit revocations, requirements for additional pollution controls and injunctions limiting or prohibiting some or all of their operations. Moreover, these laws and regulations have continually imposed increasingly stricter requirements for water and air pollution control and solid waste management.

 

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Laws and regulations governing exploration and production may also affect production levels. The operators of our properties must comply with federal and state laws and regulations governing conservation matters, including:

 

    provisions related to the unitization or pooling of the oil and natural gas properties;

 

    the establishment of maximum rates of production from wells;

 

    the spacing of wells;

 

    the plugging and abandonment of wells; and

 

    the removal of related production equipment.

Additionally, state and federal regulatory authorities may expand or alter applicable pipeline safety laws and regulations, compliance with which may require increased capital costs on the part of operators and third party downstream natural gas transporters.

The operators of our properties must also comply with laws and regulations prohibiting fraud and market manipulations in energy markets. To the extent the operators of our properties are shippers on interstate pipelines, they must comply with the tariffs of those pipelines and with federal policies related to the use of interstate capacity.

The operators of our properties may be required to make significant expenditures to comply with the governmental laws and regulations described above and are subject to potential fines and penalties if they are found to have violated these laws and regulations. These and other potential regulations could increase the operating costs of the operators and delay production from our properties, which could reduce the amount of cash available to make dividend payments to our stockholders.

The operators of our properties are subject to complex and evolving environmental and occupational health and safety laws and regulations. As a result, they may incur significant delays, costs and liabilities that could materially adversely affect our business and financial condition.

The operators of our properties may incur significant delays, costs and liabilities as a result of environmental and occupational health and safety laws and regulations applicable to their exploration, development and production activities on our properties. These delays, costs and liabilities could arise under a wide range of federal, regional, state and local laws and regulations relating to protection of the environment and worker health and safety. These laws, regulations and enforcement policies have become increasingly strict over time, resulting in longer waiting periods to receive permits and other regulatory approvals, and we believe this trend will continue. These laws include, but are not limited to, the federal Clean Air Act (and comparable state laws and regulations that impose obligations related to air emissions), the federal Water Pollution Control Act of 1972 (“Clean Water Act”) and the Oil Pollution Act (“OPA”) (and comparable state laws and regulations that impose requirements related to discharges of pollutants into regulated bodies of water), the federal Resource Conservation and Recovery Act, as amended (“RCRA”) (and comparable state laws that impose requirements for the handling and disposal of waste), the federal Comprehensive Environmental Response, Compensation and Liability Act, as amended (“CERCLA”), also known as the “Superfund” law, and the community right to know regulations under Title III of the act (and comparable state laws that regulate the cleanup of hazardous substances that may have been released at properties currently or previously owned or operated by our Operating Affiliate and our other operators or at locations our Operating Affiliate and our other operators sent waste for disposal and comparable state laws that require organization and/or disclosure of information about hazardous materials our Operating Affiliate and our other operators use or produce), the federal Occupational Safety and Health Act (which establishes workplace standards for the protection of health and safety of employees and requires a hazard

 

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communications program) and the Endangered Species Act and the Migratory Bird Treaty Act (and comparable state laws that seek to ensure activities do not jeopardize endangered or threatened animals, fish, or plant species by limiting or prohibiting construction activities in areas that are inhabited by such species and penalizing the taking, killing or possession of migratory birds).

Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, imposition of cleanup and site restoration costs and liens, and, in some instances, issuance of orders or injunctions limiting or requiring discontinuation of certain operations. Additionally, actions taken by federal or state agencies under these laws and regulations, such as the designation of previously unprotected species as being endangered or threatened or the designation of previously unprotected areas as a critical habitat for such species, can cause the operators of our properties to incur additional costs or become subject to operating restrictions.

Strict, joint and several liabilities may be imposed under certain environmental laws, which could cause the operators of our properties to become liable for the conduct of others or for consequences of our Operating Affiliate and our other operators’ actions that were in compliance with all applicable laws at the time those actions were taken. In addition, claims for damages to persons or property, including natural resources, may result from the environmental and worker health and safety impacts of operations by the operators of our properties. Also, new laws, regulations or enforcement policies could be more stringent and impose unforeseen liabilities, significantly increase our operating or compliance costs, reduce our liquidity, delay or halt our operations or otherwise alter the way we conduct our business. If the operators of our properties are not able to recover the resulting costs through insurance or increased revenues, our business, financial condition or results of operations could be materially and adversely affected. Please read “Business—Regulation” for a description of the laws and regulations that affect the operators of our properties and that may affect us.

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

The operators of our properties use hydraulic fracturing for the completion of their wells. Hydraulic fracturing is a process that involves pumping fluid and proppant at high pressure into a hydrocarbon bearing formation to create and hold open fractures. Those fractures enable gas or oil to move through the formation’s pores to the wellbore. Typically, the fluid used in this process is primarily water. In plays where hydraulic fracturing is necessary for successful development, the demand for water may exceed the supply. If the operators of our properties are unable to obtain water to use in their operations from local sources or are unable to effectively utilize flowback water, they may be unable to economically drill for or produce oil and natural gas, which could materially adversely affect our financial condition, results of operations and cash available to make dividend payments.

Various federal, state and local initiatives are underway to investigate or regulate hydraulic fracturing. The adoption of new laws or regulations imposing additional permitting, disclosures, restrictions or costs related to hydraulic fracturing or restricting or even banning hydraulic fracturing in certain circumstances could make drilling certain wells less economically attractive to or impossible for the operators of our properties, which could materially adversely affect our business, results of operations, financial condition and ability to pay cash dividends to our stockholders.

Certain governmental reviews have been conducted or are underway that focus on the potential environmental impacts of hydraulic fracturing. These ongoing or proposed studies could spur initiatives to further regulate hydraulic fracturing and could ultimately make it more difficult or costly for the operators of our properties to perform fracturing and increase the costs of compliance and doing business. Additional legislation or regulation could also make it easier for parties opposing the hydraulic fracturing process to

 

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initiate legal proceedings based on allegations that specific chemicals used in the fracturing process could adversely affect groundwater. There has also been increasing public controversy regarding hydraulic fracturing with regard to the use of fracturing fluids, impacts on drinking water supplies, the use of water and the potential for impacts to surface water, groundwater and the environment generally. A number of lawsuits and enforcement actions have been initiated at the state level implicating hydraulic fracturing practices. The imposition of stringent new regulatory and permitting requirements related to the practice of hydraulic fracturing could significantly increase our cost of doing business, could create adverse effects on our Operating Affiliate and our other operators, including creating delays related to the issuance of permits and, depending on the specifics of any particular proposal that is enacted, could be material.

State and federal regulatory agencies recently have focused on a possible connection between hydraulic fracturing related activities, particularly the disposal of produced water in underground injection wells, and the increased occurrence of seismic activity. When caused by human activity, such events are called induced seismicity. In some instances, operators of injection wells in the vicinity of seismic events have been ordered to reduce injection volumes or suspend operations. Some state regulatory agencies, including those in Colorado, Ohio, Oklahoma and Texas, have modified their regulations to account for induced seismicity. For example, following earthquakes in and around Cushing, Oklahoma, the Oklahoma Corporation Commission announced plans on November 7, 2016, to shut down or reduce the volume of disposal at certain injection wells that discharge into the Arbuckle formation. Regulatory agencies at all levels are continuing to study the possible linkage between oil and natural gas activity and induced seismicity. These developments could result in additional regulation and restrictions on the use of injection wells and hydraulic fracturing. Such regulations and restrictions could cause delays and impose additional costs and restrictions on the operators of our properties and on their waste disposal activities. Please read “Business—Regulation” for a description of the laws and regulations that affect the operators of our properties and that may affect us.

The adoption of climate change legislation and regulations could result in increased operating costs and reduced demand for the oil and natural gas that our Operating Affiliate and our other operators produce.

In response to findings that emissions of carbon dioxide, methane and other greenhouse gases (“GHGs”) present an endangerment to public health and the environment, the U.S. Environmental Protection Agency (“EPA”) has adopted regulations under existing provisions of 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 also will be required to meet “best available control technology” standards that will be established on a case-by-case basis. These EPA rulemakings could adversely affect operations on our properties and restrict or delay the ability of our Operating Affiliate and our other operators 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 oil and natural gas production sources in the United States on an annual basis, which include operations on certain of our properties. These requirements could increase the costs of development and production, reducing the profits available to us and potentially impairing our operators’ ability to economically develop our properties. Please read “Business—Regulation” for a description of the laws and regulations that affect the operators of our properties and that may affect us.

Efforts have been made and continue to be made in the international community toward the adoption of international treaties or protocols that would address global climate change issues. Most recently in 2015, the United States participated in the United Nations Conference on Climate Change, which led to the creation of the Paris Agreement. The Paris Agreement requires member countries to review and “represent a progression” in their intended nationally determined contributions, which set GHG emission reduction

 

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goals, every five years beginning in 2020. The Paris Agreement entered into force in November 2016. The United States announced its intention to withdraw from the Paris Agreement on June 1, 2017 and in August 2017, the U.S. Department of State provided formal notice to the United Nations that the United States intends to withdraw from the Paris Agreement as soon as it is eligible to do so under the agreement. These and other initiatives or regulatory changes could result in increased costs of development and production, reducing the profits available to us and potentially impairing our Operating Affiliate and our other operators’ ability to economically develop our properties.

While Congress has from time to time considered legislation to reduce emissions of GHGs, there has not been significant activity in the form of adopted legislation to reduce GHG emissions at the federal level in recent years. In the absence of federal climate legislation, a number of state and regional efforts have emerged that are aimed at tracking 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 future laws and regulations imposing reporting obligations on, or limiting emissions of GHGs from, our Operating Affiliate and our other operators’ equipment and operations could require them to incur costs to reduce emissions of GHGs associated with their operations. In addition, substantial limitations on GHG emissions could adversely affect demand for the oil and natural gas produced from our properties. Restrictions on emissions of methane or carbon dioxide that may be imposed in various states, as well as state and local climate change initiatives, could adversely affect the oil and natural gas industry, and, at this time, it is not possible to accurately estimate how potential future laws or regulations addressing GHG emissions would impact our business.

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 of these effects were to occur, they could materially adversely affect our properties and operations.

Drilling for and producing oil and natural gas are high-risk activities with many uncertainties that may materially adversely affect our business, financial condition, results of operations and cash available to make dividend payments.

The drilling activities of the operators of our properties will be subject to many risks. For example, we will not be able to assure you that wells drilled by the operators of our properties will be productive. Drilling for oil and natural gas often involves unprofitable efforts, not only from dry wells but also from wells that are productive but do not produce sufficient oil or natural gas to return a profit at then realized prices after deducting drilling, operating and other costs. The seismic data and other technologies used do not provide conclusive knowledge prior to drilling a well that oil or natural gas is present or that it can be produced economically. The costs of exploration, exploitation and development activities are subject to numerous uncertainties beyond our control, and increases in those costs can adversely affect the economics of a project. Further, our Operating Affiliate and our other operators’ drilling and producing operations may be curtailed, delayed, canceled or otherwise negatively impacted as a result of other factors, including:

 

    unusual or unexpected geological formations;

 

    loss of drilling fluid circulation;

 

    title problems;

 

    facility or equipment malfunctions;

 

    unexpected operational events;

 

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    shortages or delivery delays of equipment and services;

 

    compliance with environmental and other governmental requirements; and

 

    adverse weather conditions.

Any of these risks can cause substantial losses, including personal injury or loss of life, damage to or destruction of property, natural resources and equipment, pollution, environmental contamination or loss of wells and other regulatory penalties. In the event that planned operations, including the drilling of development wells, are delayed or cancelled, or existing wells or development wells have lower than anticipated production due to one or more of the factors above or for any other reason, our financial condition, results of operations and cash available to make dividend payments to our stockholders may be materially adversely affected.

Operating hazards and uninsured risks may result in substantial losses to the operators of our properties, and any losses could materially adversely affect our results of operations and cash available to make dividend payments.

The operators of our properties will be subject to all of the hazards and operating risks associated with drilling for and production of oil and natural gas, including the risk of fire, explosions, blowouts, surface cratering, uncontrollable flows of natural gas, oil and formation water, pipe or pipeline failures, abnormally pressured formations, casing collapses and environmental hazards such as oil spills, natural gas leaks and ruptures or discharges of toxic gases. In addition, their operations will be subject to risks associated with hydraulic fracturing, including any mishandling, surface spillage or potential underground migration of fracturing fluids, including chemical additives. The occurrence of any of these events could result in substantial losses to the operators of our properties due to injury or loss of life, severe damage to or destruction of property, natural resources and equipment, pollution or other environmental damage, clean-up responsibilities, regulatory investigations and penalties, suspension of operations and repairs required to resume operations.

If the operators of our properties suspend our right to receive royalty payments due to title or other issues, our business, financial condition, results of operations and cash available to make dividend payments may be adversely affected.

Prior to the closing of this offering, record title to the royalty interests that comprise our initial assets was held by various unrelated entities. Upon the closing of this offering, a significant amount of these royalty interests will be conveyed to us or our subsidiaries as asset assignments, and we or our subsidiaries will become the record owner of these interests. Upon such a change in ownership, and at regular intervals pursuant to routine audit procedures at each of our Operating Affiliate and our other operators otherwise at its discretion, the operator of the underlying property has the right to investigate and verify the title and ownership of royalty interests with respect to the properties it operates. If any title or ownership issues are not resolved to its reasonable satisfaction in accordance with customary industry standards, the operator may suspend payment of the related royalty. If an operator of our properties is not satisfied with the documentation we provide to validate our ownership, it may place our royalty payment in suspense until such issues are resolved, at which time we would receive in full payments that would have been made during the suspense period, without interest. Certain of our Operating Affiliate and our other operators impose significant documentation requirements for title transfer and may keep royalty payments in suspense for significant periods of time. During the time that an operator puts our assets in pay suspense, we would not receive the applicable mineral or royalty payment owed to us from sales of the underlying oil or natural gas related to such mineral or royalty interest. If a significant amount of our royalty interests are placed in suspense, our quarterly cash dividends may be reduced significantly. We expect the risk of payment

 

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suspense to be greatest during the quarter in which this offering occurs and the immediately succeeding fiscal quarters due to the number of title transfers that will take place upon the closing of this offering.

Further, an immaterial portion of our initial assets will be comprised of synthetic royalty interests. A synthetic royalty interest is a contractual interest in oil and gas properties rather than a real property interest and, while entitling the owner of the synthetic interest to the same rights to revenue as other royalty interests, may not have the same protections in the event of a bankruptcy of the counterparty that owns the oil and gas properties burdened by the synthetic royalty interest. Further, a synthetic royalty interest may, in certain jurisdictions, be deemed a personal obligation that would not run with the land and therefore the rights to revenue could be vulnerable to non-payment in the event of a transfer of the properties burdened by the synthetic interests absent express assumption by the transferee of the synthetic royalty interest obligation.

If an owner of working interests burdened by our overriding royalty interests declares bankruptcy and a court determines that all or a portion of such overriding royalty interests were part of the bankruptcy estate, we could be treated as an unsecured creditor with respect to such overriding royalty interests.

In determining whether overriding royalty interests may be treated as part of a bankruptcy estate, a court may take into consideration a variety of factors including, among others, whether overriding royalty interests are typically characterized as a real property interest under applicable state law, the terms conveying the overriding royalty interests and related working interests and the applicable state law procedures required to perfect the interests such parties intend to create. We believe that our overriding royalty interests would be treated as an interest in real property in the states they are located and, therefore, would not likely be considered a part of the bankruptcy estate. Nevertheless, the outcome is not certain. As such, if an owner of working interests burdened by our overriding royalty interests, including our Operating Affiliate, declares bankruptcy, a court may determine that all or a portion of such overriding royalty interests are part of the bankruptcy estate. In that event, we would be treated as a creditor in the bankruptcy case. Although holders of overriding royalty interests may be entitled to statutory liens and/or other protections under applicable state law that could be enforceable in bankruptcy, there is no guarantee that such security interests or other protections would apply. Therefore, we could be treated as an unsecured creditor of the debtor working interest owner and could lose the entire value of such overriding royalty interest.

Risks Inherent in an Investment in Us

Our board of directors may modify or revoke our dividend policy at any time at its discretion, including in such a manner that would result in an elimination of dividends regardless of the amount of our available cash. Our certificate of incorporation and bylaws do not require us to make any dividends at all.

Our board of directors will adopt a dividend policy pursuant to which we will distribute all of our available cash each quarter to Class A common stockholders of record on a pro rata basis. However, the board may change such policy at any time at its discretion and could elect not to pay dividends for one or more quarters regardless of the amount of available cash we generate. We are not required to make any cash dividends at all. Our available cash is dependent upon distributions Remora Holdings makes to its unitholders, including us. The amount of cash that Remora Holdings will be able to distribute to its unitholders, including us, principally depends upon the amount of cash that Remora Holdings generates from its business. Accordingly, investors are cautioned not to place undue reliance on the permanence of

 

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such a policy in making an investment decision. Any modification or revocation of our dividend policy could substantially reduce or eliminate the amounts of dividends to our Class A common stockholders.

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

Our governing documents will provide that our Operating Affiliate and its affiliates are not restricted from owning 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 our Operating Affiliate and its affiliates to develop acreage not burdened by our royalty interests;

 

    permit our Operating Affiliate and its affiliates and our non-employee directors 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 our Operating Affiliate or any of its affiliates who is also one of our non-employee 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.

Our Operating Affiliate or its 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. As a result, our renouncing our interest and expectancy in any business opportunity that may be from time to time presented to our Operating Affiliate and its 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.

Our Operating Affiliate and its affiliates are established participants in the oil and natural gas industry and have resources greater than ours, which may make it more difficult for us to compete with such persons with respect to commercial activities as well as for potential acquisitions. We cannot assure you that any conflicts that may arise between us and our stockholders, on the one hand, and Our Operating Affiliate, on the other hand, will be resolved in our favor. As a result, competition from our Operating Affiliate and its affiliates could adversely impact our results of operations.

Neither we nor our subsidiaries have any employees, and we rely solely on our Operating Affiliate to manage, or arrange for the management of, our business. The management team of our Operating Affiliate, which includes the individuals who will manage us, will also provide substantially similar services to other entities and thus will not be solely focused on our business.

Neither we nor our subsidiaries have any employees, and we rely solely on our Operating Affiliate to manage us and our assets. In connection with this offering, we will enter into a management services agreement with our Operating Affiliate, pursuant to which it will provide management and administrative services for us.

Additionally, our Operating Affiliate may make internal decisions on how to allocate its available resources and expertise that may not always be in our best interest compared to those of other entities. There is no requirement that our Operating Affiliate favor us over these other entities in providing its services. If

 

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the employees of our Operating Affiliate do not devote sufficient attention to the management and operation of our business, our financial results may suffer and our ability to pay dividends to our stockholders may be reduced.

Increases in interest rates may cause the market price of our Class A common stock to decline.

While interest rates have been at record low levels in recent years, this low interest rate environment likely will not continue indefinitely. An increase in interest rates may cause a corresponding decline in demand for equity investments in general, and in particular, for yield-based equity investments such as our Class A common stock. Any such increase in interest rates or reduction in demand for our Class A common stock resulting from other relatively more attractive investment opportunities may cause the trading price of our Class A common stock to decline.

Stockholders will incur immediate and substantial dilution of $         per share.

The initial public offering price of $         per share exceeds our pro forma net tangible book value of $         per share. Based on the initial public offering price of $         per share, stockholders will incur immediate and substantial dilution of $         per share. This dilution results primarily because the assets contributed to us by our predecessor are recorded at their historical cost in accordance with GAAP, and not their fair value. Please read “Dilution.”

Upon consummation of this offering, the Contributing Parties will hold      RH Units (together with a corresponding number of shares of Class B common stock), all of which may be redeemed for      shares of Class A common stock. The shares of Class A common stock we issue upon such redemptions would be “restricted securities” as defined in Rule 144 under the Securities Act. However, upon the closing of this offering, we intend to enter into a registration rights agreement with the Contributing Parties that will require us to register under the Securities Act these shares of Class A common stock.

There is no existing market for our Class A common stock, and a trading market that will provide you with adequate liquidity may not develop. The price of our Class A common stock may fluctuate significantly, and stockholders could lose all or part of their investment.

Prior to this offering, there has been no public market for our Class A common stock. After this offering, there will be only          publicly traded shares of our Class A common stock. We do not know the extent to which investor interest will lead to the development of a trading market or how liquid that market might be. Stockholders may not be able to resell their Class A common stock at or above the initial public offering price. Additionally, the lack of liquidity may result in wide bid-ask spreads, contribute to significant fluctuations in the market price of our Class A common stock and limit the number of investors who are able to buy our Class A common stock.

The initial public offering price for our Class A common stock will be determined by negotiations between us and the representative of the underwriters and may not be indicative of the market price of our Class A common stock that will prevail in the trading market. The market price of our Class A common stock may decline below the initial public offering price. The market price of our Class A common stock may also be influenced by many factors, some of which are beyond our control, including:

 

    changes in commodity prices;

 

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

 

    fluctuations in broader securities market prices and volumes, particularly among securities of oil and natural gas companies and securities of publicly traded companies;

 

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    changes in market valuations of similar companies;

 

    departures of key personnel;

 

    commencement of or involvement in litigation;

 

    variations in our quarterly results of operations or those of other oil and natural gas companies;

 

    changes in general economic conditions, financial markets or the oil and natural gas industry;

 

    announcements by us or our competitors of significant acquisitions or other transactions;

 

    variations in the amount of our quarterly cash dividends to our stockholders;

 

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

 

    the failure of securities analysts to cover our common stock after this offering or changes in their recommendations and estimates of our financial performance;

 

    future sales of our Class A common stock; and

 

    the other factors described in these “Risk Factors.”

We are a holding company. Our sole material asset after completion of this offering will be our equity interest in Remora Holdings, LLC and we are accordingly dependent upon distributions from Remora Holdings, LLC to pay taxes and cover our corporate and other overhead expenses.

We are a holding company and will have no material assets other than our equity interest in Remora Holdings, LLC. Please see “Summary—Formation Transactions.” We have no independent means of generating revenue. To the extent Remora Holdings, LLC has available cash, we intend to cause Remora Holdings, LLC to make distributions to its unitholders, including us, in an amount sufficient to cover all applicable taxes at assumed tax rates and to reimburse us for our corporate and other overhead expenses. We are limited, however, in our ability to cause Remora Holdings, LLC and its subsidiaries to make these and other distributions to us due to the restrictions under its credit facility. To the extent that we need funds and Remora Holdings, LLC or its subsidiaries are restricted from making such distributions under applicable law or regulation or under the terms of their financing arrangements, or are otherwise unable to provide such funds, it could materially adversely affect our liquidity and financial condition.

Future sales of our Class A 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.

Subject to certain limitations and exceptions, the holders of RH Units may redeem their RH Units (together with a corresponding number of shares of Class B common stock) for shares of Class A common stock (on a one-for-one basis, subject to conversion rate adjustments for stock splits, stock dividends and reclassification and other similar transactions) and then sell those shares of Class A common stock. Additionally, we may issue additional shares of Class A common stock or convertible securities in subsequent public offerings. After the completion of this offering, we will have              outstanding shares of Class A common stock and              outstanding shares of Class B common stock. This number includes             shares of Class A common stock that we are selling in this offering and the              shares of Class A common stock 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. Although they will not initially own any shares of Class A common stock following the completion of this offering, the Contributing Parties will own             shares of Class B common stock, representing approximately     % (or     % if the underwriters’

 

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option to purchase additional shares is exercised in full) of our total outstanding Class A common stock on an as-converted basis. All such shares are restricted from immediate resale under the federal securities laws and are subject to the lock-up agreements between such parties and the underwriters described in “Underwriting,” but may be sold into the market in the future. We expect that certain of the Contributing Parties will be party to a registration rights agreement with us that will require us to effect the registration of their shares in certain circumstances no earlier than the expiration of the lock-up period contained in the underwriting agreement entered into in connection with this offering. Employees will be subject to certain restrictions on the sale of their shares for 180 days after the date of this prospectus; however, after such period, and subject to compliance with the Securities Act or exemptions therefrom, these employees may sell such shares into the public market. See “Shares Eligible for Future Sale.”

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 Class A common stock issued or reserved for issuance under our equity incentive plan. Subject to the satisfaction of vesting conditions and the expiration of lock-up agreements, shares registered under the registration statement on Form S-8 will be available for resale immediately in the public market without restriction.

We cannot predict the size of future issuances of our Class A common stock or securities convertible into Class A common stock or the effect, if any, that future issuances and sales of shares of our Class A common stock will have on the market price of our Class A common stock. Sales of substantial amounts of our Class A 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 Class A common stock.

If Remora Holdings were to become a publicly traded partnership taxable as a corporation for U.S. federal income tax purposes, we and Remora Holdings might be subject to potentially significant tax inefficiencies.

We intend to operate such that Remora Holdings does not become a publicly traded partnership taxable as a corporation for U.S. federal income tax purposes. A “publicly traded partnership” is a partnership the interests of which are traded on an established securities market or are readily tradable on a secondary market or the substantial equivalent thereof. Under certain circumstances, redemptions of RH Units pursuant to the Redemption Right (or our Call Right) or other transfers of RH Units could cause Remora Holdings to be treated as a publicly traded partnership. Applicable U.S. Treasury regulations provide for certain safe harbors from treatment as a publicly traded partnership, and we intend to operate such that redemptions or other transfers of RH Units qualify for one or more such safe harbors. For example, we intend to limit the number of unitholders of Remora Holdings, and the Remora Holdings LLC Agreement, which will be entered into in connection with the closing of this offering, will provide for limitations on the ability of unitholders of Remora Holdings to redeem or transfer their RH Units and will provide us, as managing member of Remora Holdings, with the right to impose restrictions (in addition to those already in place) on the ability of unitholders of Remora Holdings to redeem or otherwise transfer their RH Units to the extent we believe it is necessary to ensure that Remora Holdings will continue to be treated as a partnership for U.S. federal income tax purposes. If Remora Holdings were to become a publicly traded partnership taxable as a corporation for U.S. federal income tax purposes, significant tax inefficiencies might result for us and for Remora Holdings, including as a result of our inability to file a consolidated U.S. federal income tax return with Remora Holdings. In addition, we would no longer have the benefit of increases in the tax bases of Remora Holdings’ assets upon a redemption of RH Units pursuant to the Redemption Right.

 

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The requirements of being a public company, including compliance with the reporting requirements of the Securities Exchange Act of 1934, as amended (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 NASDAQ, 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 NASDAQ;

 

    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 for our fiscal year ending December 31, 2017, 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 December 31, 2022. 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.

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.

 

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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 stockholders, which could limit our stockholders’ 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 of breach of a fiduciary duty owed by any of our directors, officers, employees or agents to us or our stockholders, (iii) any action asserting a claim arising pursuant to any provision of the Delaware General Corporation Law (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 stockholder’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.

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

Our certificate of incorporation will authorize us to issue, without the approval of our stockholders, one or more classes or series of preferred stock having such designations, preferences, limitations and relative rights, including preferences over our Class A common stock and Class B common stock respecting cash 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 Class A common stock and Class B 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 Class A common stock and Class B common stock.

Our certificate of incorporation and bylaws, as well as Delaware law, contain provisions that could discourage acquisition bids or merger proposals, which may adversely affect the market price of our Class A common stock.

Some provisions of our certificate of incorporation and bylaws could make it more difficult for a third party to acquire control of us, even if the change of control would be beneficial to our stockholders, including:

 

    limitations on the removal of directors;

 

    our classified board of directors, under which a director only comes up for election once every three years;

 

    limitations on the ability of our stockholders to call special meetings;

 

 

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    establishing advance notice provisions for stockholder proposals and nominations for elections to the board of directors to be acted upon at meetings of stockholders;

 

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

 

    establishing advance notice and certain information requirements for nominations for election to our board of directors or for proposing matters that can be acted upon by stockholders at stockholder meetings.

For as long as we are an emerging growth company, we will not be required to comply with certain disclosure requirements that apply to other public companies.

We are an “emerging growth company” as defined in 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 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) comply with any new audit rules adopted by the PCAOB after April 5, 2012 unless the SEC determines otherwise or (4) provide certain disclosure regarding executive compensation required of larger public companies.

In addition, Section 102 of the JOBS Act also provides that an “emerging growth company” can use the extended transition period provided in Section 7(a)(2)(B) of the Securities Act for complying with new or revised accounting standards. An “emerging growth company” can therefore delay the adoption of certain accounting standards until those standards would otherwise apply to private companies.

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. As a result, current and potential stockholders could lose confidence in our financial reporting, which would harm our business and the trading price of our shares of Class A common stock.

Prior to this offering, our predecessor has not been required to file reports with the SEC. Upon the completion of this offering, we will become subject to the public reporting requirements of the Exchange Act. We prepare our financial statements in accordance with GAAP, but our internal controls over financial reporting may not currently meet all standards applicable to companies with publicly traded securities. Effective internal controls are necessary for us to provide reliable financial reports, prevent fraud and operate successfully as a publicly traded company. If we cannot provide reliable financial reports or prevent fraud, our reputation and operating results would be harmed. We cannot be certain that our efforts to develop and maintain our internal controls will be successful, that we will be able to maintain adequate controls over our financial processes and reporting in the future or that we will be able to comply with our obligations under Section 404 of the Sarbanes-Oxley Act. For example, Section 404 will require us, among other things, to annually review and report on, and our independent registered public accounting firm to attest to, the effectiveness of our internal controls over financial reporting. However, for as long as we are an “emerging growth company” under the JOBS Act, our independent registered public accounting firm will not be required to attest to the effectiveness of our internal control over financial reporting. We must comply with Section 404 (except for the requirement for an auditor’s attestation report) beginning with our fiscal year ending December 31, 2019. Any failure to develop or maintain effective internal controls, or difficulties encountered in implementing or improving our internal controls, could harm our operating

 

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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 Class A common stock.

 

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USE OF PROCEEDS

We will receive net proceeds of approximately $         from this offering (based on an assumed initial offering price of $         per share of Class A common stock, the mid-point of the price range set forth on the cover page of this prospectus), after deducting the underwriting discounts, the structuring fee and the estimated offering expenses payable by us in connection with this offering. We intend to use the net proceeds of this offering to (1) make a contribution of $             to Remora Holdings in exchange for RH             Units representing a     % membership interest in Remora Holdings and (2) purchase RH Units representing a     % membership interest in Remora Holdings from the Contributing Parties for $        . Remora Holdings will use the proceeds of the contribution along with $         that we expect to borrow under our secured revolving credit facility upon the closing of this offering to repay in full approximately $     of our Operating Affiliate’s indebtedness that burdens the royalty interests to be contributed to Remora Holdings by our Operating Affiliate that Remora Holdings will assume in connection with the formation transactions.

Other than the $         that we expect to borrow under our secured revolving credit facility upon the closing of this offering to repay a portion of the indebtedness as described above, we have no plans to immediately draw down additional borrowings under our secured revolving credit facility.

All of our Operating Affiliate’s debt that Remora Holdings will assume and repay in full at closing was originally incurred under our Operating Affiliate’s credit agreement with BOK Financial Corporation (the “Predecessor Credit Agreement”) and a term loan with Goldman Sachs Specialty Lending Group, L.P. (the “Predecessor Term Loan”). The Predecessor Credit Agreement has a maturity date of May 27, 2020 and is secured by substantially all of our Operating Affiliate’s oil and natural gas properties. The Predecessor Term Loan has a maturity of November 27, 2020 and bears interest at the bank’s base rate plus 10% to 11% depending on the utilization levels as defined in the agreement or at the LIBOR plus 11% to 12% depending on the utilization levels as defined in the agreement with a minimum LIBOR of 1.0%.

To the extent the underwriters exercise their option to purchase additional Class A common stock, we will issue such shares to the public and use the net proceeds therefrom to purchase additional RH Units and Class B shares, on a pro forma basis, from the Contributing Parties. If the underwriters exercise their option to purchase additional Class A common stock in full, the additional net proceeds to us would be approximately $        , after deducting the underwriting discount and structuring fee.

An increase or decrease in the initial public offering price of $1.00 per share of Class A common stock would cause the net proceeds from the offering, after deducting the estimated underwriting discount and structuring fee, to increase or decrease by approximately $         million, based on an assumed initial public offering price of $         per share. Each increase of 1.0 million Class A shares offered by us, together with a concurrent $1.00 increase in the assumed public offering price of $         per share of Class A common stock, would increase net proceeds by approximately $         million. Similarly, each decrease of 1.0 million Class A shares offered by us, together with a concurrent $1.00 decrease in the assumed initial public offering price of $         per share of Class A common stock, would decrease the net proceeds to us from this offering by approximately $         million. If the proceeds increase due to a higher initial public offering price or decrease due to a lower initial public offering price, the amount used to purchase RH Units from the Contributing Parties will increase or decrease, as applicable, by a corresponding amount.

 

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CAPITALIZATION

The following table shows our cash and cash equivalents and capitalization as of March 31, 2018:

 

    on a historical basis for our predecessor; and

 

    on a pro forma basis to reflect the offering and the other formation transactions described under “Formation Transactions” and the application of the net proceeds from this offering as described under “Use of Proceeds.”

This table is derived from, and should be read together with, the historical financial statements and the accompanying notes included elsewhere in this prospectus. You should also read this table in conjunction with “Use of Proceeds” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

 

     As of March 31, 2018  
     Predecessor Historical
(in thousands)
     Remora Royalties, Inc.
Pro Forma
(in thousands)
 

Cash and cash equivalents

   $ 2,482       $               
  

 

 

    

 

 

 

Long-term debt(1)

   $ 47,950       $               
  

 

 

    

 

 

 

Stockholders’ equity/partners’ deficit:

     

Partners’ deficit

   $ (15,759)      $               

Preferred stock

     —      

Class A common stock

     —      

Class B common stock

     —      
  

 

 

    

 

 

 

Total stockholders’ equity/partners’ deficit

   $ (15,759)      $               
  

 

 

    

 

 

 

Total capitalization

   $ 32,191       $               
  

 

 

    

 

 

 

 

(1)   As of July 13, 2018, our predecessor had $31.6 million outstanding under its senior secured revolving credit facility. Prior to the completion of this offering, Remora Holdings expects to enter into a new $         million secured revolving credit facility, and expects to have $         drawn at the closing of this offering.

 

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DILUTION

Purchasers of Class A common stock offered by this prospectus will suffer immediate and substantial dilution in net tangible book value (tangible assets less total liabilities) per share of our Class A common stock for accounting purposes. Dilution in net tangible book value per share represents the difference between the amount per share paid by purchasers of our Class A common stock in this offering and the pro forma as adjusted net tangible book value per share immediately after this offering. Pro forma as adjusted net tangible book value is based on the contribution of all of our initial assets by all of the Contributing Parties, the offering of all the Class A common stock to the public in connection with this offering and the application of the net proceeds therefrom as described in “Use of Proceeds.” After giving effect to the sale of          shares of Class A common stock in this offering at the initial public offering price of $         per share (which is the mid-point of the range set forth on the cover of this prospectus), and after deduction of the underwriting discount, structuring fee and estimated offering expenses payable by us in connection with this offering, our pro forma as adjusted net tangible book value as of March 31, 2018 would have been approximately $        , or $         per share. This represents an immediate increase in net tangible book value of $         per share to our existing stockholders and an immediate pro forma dilution of $         per share to purchasers of Class A common stock in this offering. The following table illustrates this dilution on a per share basis (assuming that 100% of our Class B common stock has been redeemed for Class A common stock):

 

Assumed initial public offering price per share(1)

      $               

Pro forma as adjusted net tangible book value per share before the offering

   $                  

Decrease in net tangible book value per share attributable to purchasers in the offering

     
  

 

 

    

Less: Pro forma as adjusted net tangible book value per share after the offering(3)

     
     

 

 

 

Immediate dilution in net tangible book value per share to purchasers in the offering(4)(5)

      $               
     

 

 

 

 

(1)   The mid-point of the price range set forth on the cover of this prospectus.

 

(2)   Determined by dividing the pro forma net tangible book value of the contributed assets and liabilities by the number of shares of Class A common stock to be issued to the Contributing Parties for their redemption of Class B common stock and RH Units.

 

(3)   Determined by dividing our pro forma net tangible book value, after giving effect to the use of the net proceeds of the offering, by the total number of shares of Class A common stock outstanding after this offering.

 

(4)   If the initial public offering price were to increase or decrease by $1.00 per share, then dilution in net tangible book value per share would equal $         and $         , respectively.

 

(5)   Assumes the underwriters’ option to purchase additional shares from us is not exercised. If the underwriters’ option to purchase additional shares from us is exercised in full, the immediate dilution in net tangible book value per share to purchasers in this offering will be $        .

The following table summarizes, on an adjusted pro forma basis as of March 31, 2018, the total number of shares of Class A common stock owned by existing shareholders (assuming that 100% of our Class B common stock has been redeemed for Class A common stock) and to be owned by new investors, the total consideration paid, and the average price per share paid by our existing shareholders and to be paid

 

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by new investors in this offering at $             , the mid-point 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  

Contributing Parties(1)

                           $           

Purchasers in this offering

                 (2)          
  

 

 

    

 

 

   

 

 

   

 

 

 

Total

               $                                        
  

 

 

    

 

 

   

 

 

   

 

 

 

 

(1)   Reflects the value of the assets to be contributed to us by all of the Contributing Parties recorded at historical cost.
(2)   Reflects the net proceeds of this offering after deducting the estimated underwriting discount and structuring fee payable by us in connection with this offering, and assumes the underwriters’ option to purchase additional Class A common stock is not exercised.

 

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DIVIDEND POLICY

You should read the following discussion of our dividend policy in conjunction with the specific assumptions included in this section. Please read “—Estimated Cash Available to Make Dividend Payments for the Twelve Months Ending June 30, 2019—Assumptions and Considerations” below. In addition, you should read “Forward-Looking Statements” and “Risk Factors” for information regarding statements that do not relate strictly to historical or current facts and certain risks inherent in our business.

For additional information regarding our historical and pro forma results of operations, you should refer to our historical financial statements and the accompanying notes and our unaudited pro forma condensed combined financial statements and the accompanying notes included elsewhere in this prospectus.

General

Our Dividend Policy

Our board of directors expects to adopt a written policy whereby we intend to make a dividend of all of our cash on hand to our Class A common stockholders at the end of each quarter in an amount equal to our available cash for such quarter, beginning with the quarter ending             , 2018. Available cash for each quarter will be determined by our board of directors following the end of such quarter. We define available cash as all of our cash on hand at the end of each quarter less the amount of cash reserves established by our board of directors to provide for the proper conduct of our business. We expect that available cash for each quarter will generally equal our Adjusted EBITDA for the quarter, less cash needed for debt service, estimated taxes and other contractual obligations and fixed charges and reserves for future operating or capital needs that the board of directors may determine is appropriate. We do not currently intend to reserve cash for the purpose of maintaining stability or growth in our quarterly dividend payments or otherwise to reserve cash to make dividend payments, nor do we intend to incur debt to pay quarterly dividends.

We do not currently intend to retain cash from our operations for capital expenditures necessary to replace our existing oil and natural gas reserves or otherwise maintain our asset base (replacement capital expenditures), primarily due to our expectation that the continued development of our properties by our Contributing Parties and other working interest owners will more than offset the natural production declines from our existing wells through the year ending December 31, 2021. Our board of directors may change our dividend policy and decide to withhold replacement capital expenditures from cash available to make dividend payments, which would reduce the amount of cash available to make dividend payments in the quarter(s) in which any such amounts are withheld. Over the long term, if our reserves are depleted and our Operating Affiliate and our other operators become unable to maintain production on our existing properties and we have not been retaining cash for replacement capital expenditures, the amount of cash generated from our existing properties will decrease and we may have to reduce the amount of dividends payable to our Class A common stockholders.

It is our intent, subject to market conditions, to finance acquisitions of royalty interests that increase our asset base largely through external sources, such as borrowings under our secured revolving credit facility and the issuance of equity and debt securities, although our board of directors may choose to reserve a portion of cash generated from operations to finance such acquisitions as well. We do not currently intend to reserve cash for the purpose of maintaining stability or growth in our quarterly dividends or otherwise reserve cash for dividends, or to incur debt to pay quarterly dividends, and our board of directors may change this policy.

 

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Limitations on Cash Dividends and Our Ability to Change Our Dividend Policy

There is no guarantee that we will pay cash dividends to our Class A common stockholders each quarter. Our dividend policy is subject to certain limitations, including the following:

 

    Following the formation transactions, we expect to have $         million outstanding under our secured revolving credit facility. We anticipate that our secured revolving credit facility and any future debt agreements will contain certain financial tests and covenants that we would have to satisfy. We may also be prohibited from paying dividends if an event of default or borrowing base deficiency exists under our secured revolving credit facility. If we are unable to satisfy the restrictions under any future debt agreements, we could be prohibited from paying a dividend to you notwithstanding our stated dividend policy.

 

    Our board of directors will have discretion under our dividend policy to establish cash reserves for the prudent conduct of our business, and the establishment of, or increase in, those reserves could result in a reduction in the amount of cash dividends to our Class A common stockholders.

 

    We and Remora Holdings will enter into a management services agreement with our Operating Affiliate pursuant to which it will provide management and administrative services to Remora Holdings and us. The reimbursement of expenses and payment of fees, if any, to our Operating Affiliate will reduce the amount of available cash to pay dividends to our Class A common stockholders.

 

    We may lack sufficient cash to pay dividends to our stockholders due to cash flow shortfalls attributable to a number of commercial or other factors as well as increases in general and administrative expenses, principal and interest payments on our outstanding debt, tax expenses, working capital requirements and anticipated cash needs.

In addition, we may change our dividend policy at any time and for any reason.

We expect to generally distribute a significant percentage of our cash from operations to our stockholders on a quarterly basis, after, among other things, the establishment of cash reserves and payment of our expenses. To fund growth, we will eventually need capital in excess of the amounts we may retain in our business. As a result, our growth will depend initially on our Operating Affiliate and our other operators’ ability to fund their drilling program through cash flows from operations, and perhaps our ability in the future, to raise debt and equity capital from third parties in sufficient amounts and on favorable terms when needed. To the extent efforts to access capital externally are unsuccessful, our ability to grow will be significantly impaired.

In the sections that follow, we present the following two tables:

 

    “Unaudited Pro Forma Cash Available to Make Dividend Payments,” in which we present our unaudited estimate of the amount of pro forma cash available to make dividend payments we would have had for the year ended December 31, 2017 and the twelve months ended March 31, 2018 had this offering and the pro forma formation transactions been consummated at the beginning of such period, in each case, based on our pro forma condensed combined financial statements included elsewhere in this prospectus; and

 

    “Estimated Cash Available to Make Dividend Payments,” in which we provide our unaudited forecast of cash available to make dividend payments for the full twelve months ending June 30, 2019.

 

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Unaudited Pro Forma Cash Available to Make Dividend Payments for the Year Ended December 31, 2017 and the Twelve Months Ended March 31, 2018

We estimate that we would have generated $25.7 million and $23.2 million of pro forma cash available to make dividend payments and distributions for the year ended December 31, 2017 and the twelve months ended March 31, 2018, respectively. Assuming we do not retain cash from operations for capital expenditures, this amount would have resulted in aggregate annual dividends and distributions equal to $25.7 million for the year ended December 31, 2017 and $23.2 million for the twelve months ended March 31, 2018.

Our unaudited pro forma cash available to make dividend payments for each of the year ended December 31, 2017 and the twelve months ended March 31, 2018 includes an incremental $1.5 million of general and administrative expenses we expect to incur as a result of becoming a publicly traded company. Incremental general and administrative expenses related to being a publicly traded company include: expenses associated with SEC reporting requirements, including annual and quarterly reports to stockholders, tax return and 1099 preparation and dividend expenses, Sarbanes-Oxley Act compliance expenses, expenses associated with listing on the NASDAQ, independent auditor fees, independent reserve engineer fees, legal fees, investor relations expenses, registrar and transfer agent fees, director and officer insurance expenses and director and officer compensation expenses. These incremental general and administrative expenses are not reflected in the historical financial statements of our predecessor or our pro forma financial statements included elsewhere in this prospectus.

We based the pro forma adjustments upon currently available information and specific estimates and assumptions. The pro forma amounts below do not purport to present our results of operations had this offering and related formation transactions been completed as of the date indicated. In addition, cash available to make dividend payments is primarily a cash accounting concept, while the historical financial statements of our predecessor included elsewhere in this prospectus have been prepared on an accrual basis. As a result, you should view the amount of pro forma cash available to make dividend payments only as a general indication of the amount of cash available to make dividend payments that we might have generated had we completed this offering on the date indicated. Our unaudited pro forma cash available to make dividend payments should be read together with “Selected Historical and Unaudited Pro Forma Financial Data,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the audited historical financial statements and the accompanying notes included elsewhere in this prospectus.

The following table illustrates, on a pro forma basis, for the year ended December 31, 2017 and for the twelve months ended March 31, 2018, the amount of cash that would have been available to make dividend payments to our Class A common stockholders, assuming that this offering and the pro forma formation transactions had been consummated at the beginning of such period. All of the amounts for the year ended December 31, 2017 and the twelve months ended March 31, 2018 in the table below are estimates.

Assets from the Contributing Parties (other than our predecessor, Remora Petroleum, L.P., Vendera Resources II, LLC and its affiliates, Vendera Resources III, L.P. and its affiliates and AVAD Energy Partners, LLC) are not reflected in the pro forma financial statements. Financial statements relating to these additional assets that will be contributed to us at the consummation of this offering have not been audited and therefore are not presented in the pro forma cash available to make dividend payments for the year ended December 31, 2017 and the twelve months ended March 31, 2018.

 

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Remora Royalties, Inc.

Pro Forma Cash Available to Make Dividend Payments

 

     Year Ended
December 31, 2017
     Year Ended
March 31, 2018
 

Revenue:

     

Oil, natural gas and NGL revenues

   $ 31,321,732      $ 28,785,510  
Cost and expenses:      

Production and ad valorem taxes

   $ 2,124,507      $ 2,031,408  

Depreciation and depletion expenses(1)

   $ 14,411,188      $ 13,182,737  

Marketing and other deductions

     —          —    

General and administrative

   $ 689,219      $ 844,838  
  

 

 

    

 

 

 

Total costs and expenses

   $ 17,224,914      $ 16,058,983  
  

 

 

    

 

 

 

Operating income

   $ 14,096,819      $ 12,726,527  

Other expenses:

     

Interest expense(2)

   $ 513,750      $ 513,750  

Income tax expense(3)

   $ 2,852,444      $ 2,564,683  
  

 

 

    

 

 

 

Pro Forma Net Income(4)

   $ 10,730,624      $ 9,648,094  
  

 

 

    

 

 

 

Adjustments to reconcile to pro forma Adjusted EBITDA:

     

Depreciation and depletion expenses

   $ 14,411,188      $ 13,182,737  

Interest expense(2)

   $ 513,750      $ 513,750  

Income tax expense(3)

   $ 2,852,444      $ 2,564,683  
  

 

 

    

 

 

 

Adjusted EBITDA(5)

   $ 28,508,007      $ 25,909,264  
  

 

 

    

 

 

 

Adjustments to reconcile Adjusted EBITDA to cash available to make dividend payments:

     

Incremental general and administrative expenses(6)

   $ 1,500,000      $ 1,500,000  

Cash interest expense(2)

   $ 448,750      $ 448,750  

Cash income tax expense(3)

   $ 848,345      $ 752,652  

Capital expenditures

     —          —    
  

 

 

    

 

 

 

Cash available for dividend payments and distributions

   $ 25,710,912      $ 23,207,862  
  

 

 

    

 

 

 

Cash reserves

     —          —    

 

Aggregate dividends and distributions:            

Units in Remora Holdings held by the Contributing Parties

     Units:           

Class A common stock held by the public

     Shares:           
        

 

 

    

 

 

 

Per share dividend to Class A common stock

         $      $  
        

 

 

    

 

 

 

 

(1)   Depreciation and depletion expenses are based on our pro forma historical production volumes and an estimated depletion rate per Mcfe of approximately $1.55 which takes into account the contemplated transactions in this offering.
(2)   Interest expense is based on expected borrowings of $10.0 million at the closing of this offering to repay a portion of our Operating Affiliate’s indebtedness that Remora Holdings will assume in connection with this offering, inclusive of non-cash amortization of debt issuance costs. Cash interest expense does not include non-cash amortization of debt issuance costs.
(3)   Income tax expense is based on the statutory federal income tax rate of 21%. Cash income tax expense is based on an assumed cash income tax rate of approximately 7.0% that takes into account the effective tax rate of the Company.

 

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(4)   Pro forma net income for the years ended December 31, 2017 and March 31, 2018 gives effect to the pro forma adjustments reflected in our unaudited pro forma condensed combined financial statements included elsewhere in this prospectus.
(5)   Adjusted EBITDA is a financial measure not presented in accordance with GAAP. For a definition of Adjusted EBITDA and reconciliation to net income and net cash provided by operating activities, its most directly comparable financial measures is calculated in accordance with GAAP, please read “Summary— Summary Historical and Unaudited Pro Forma Condensed Combined Financial Data—Non-GAAP Financial Measures”.
(6)   Reflects incremental general and administrative expenses that we expect to incur as a result of operating as a publicly traded company that are not reflected in our pro forma financial statements.

Estimated Cash Available to Make Dividend Payments for the Twelve Months Ending June 30, 2019

During the twelve months ending June 30, 2019, we estimate that we will generate $23.9 million of cash available to make dividend payments and distributions. In “—Assumptions and Considerations” below, we discuss the major assumptions underlying this estimate. We can give you no assurance that our assumptions will be realized or that we will generate any cash available to make dividend payments, in which event we will not be able to pay quarterly dividends on our Class A common stock. We believe that the presentation of Estimated Cash Available to Make Dividend Payments provides investors with further information regarding the Company’s expectations of being able to pay dividends during the period ending                      and allows investors to compare such expectations with those presented by other companies holding mineral and royalty interests in oil and natural gas properties.

When considering our ability to generate cash available to make dividend payments and how we calculate forecasted cash available to make dividend payments, please keep in mind all the risk factors and other cautionary statements under the headings “Risk Factors” and “Forward-Looking Statements,” which discuss factors that could cause our results of operations and available cash to vary significantly from our estimates.

Management has prepared the prospective financial information set forth in the table below to present our expectations regarding our ability to generate $23.9 million of cash available to make dividend payments and distributions for the full twelve months ending June 30, 2019. The accompanying prospective financial information was not prepared with a view toward public disclosure or complying with the guidelines established by the American Institute of Certified Public Accountants with respect to prospective financial information, but, in the view of our management, was prepared on a reasonable basis, reflects the best currently available estimates and judgments, and presents, to the best of management’s knowledge and belief, the expected course of action and our expected future financial performance. However, this information is not fact and should not be relied upon as being necessarily indicative of future results, and readers of this prospectus are cautioned not to place undue reliance on this prospective financial information.

The assumptions and estimates underlying the prospective financial information are inherently uncertain and, though considered reasonable by our management team as of the date of its preparation, are subject to a wide variety of significant business, economic, financial, regulatory, environmental and competitive risks and uncertainties that could cause actual results to differ materially from those contained in the prospective financial information. Accordingly, there can be no assurance that the prospective results are indicative of our future performance or that actual results will not differ materially from those presented in the prospective financial information. Inclusion of the prospective financial information in this prospectus should not be regarded as a representation by any person that the results contained in the prospective financial information will be achieved.

 

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We do not undertake any obligation to release publicly the results of any future revisions we may make to the financial forecast or to update this financial forecast to reflect events or circumstances after the date of this prospectus. In light of the above, the statement that we believe that we will have sufficient cash available to make dividend payments to allow us to pay the forecasted quarterly dividends on all of our outstanding share of Class A common stock for the full twelve months ending June 30, 2019 should not be regarded as a representation by us or the underwriters or any other person that we will pay such cash dividends. Therefore, you are cautioned not to place undue reliance on this information.

The following table shows how we calculate estimated cash available to make dividend payments for the full twelve months ending June 30, 2019. The assumptions that we believe are relevant to particular line items in the table below are explained in the corresponding footnotes and in “—Assumptions and Considerations.”

Neither our independent registered public accounting firm nor any other independent registered public accounting firm has compiled, examined or performed any procedures with respect to the forecasted financial information contained herein, nor has it expressed any opinion or given any other form of assurance on such information or its achievability, and it assumes no responsibility for such forecasted financial information. Our independent registered public accounting firm’s reports included elsewhere in this prospectus relate to our audited historical financial statements. These reports do not extend to the table and the related forecasted information contained in this section and should not be read to do so.

The following table illustrates the amount of cash available to make dividend payments that we estimate that we will generate for the full twelve months ending June 30, 2019. All of the amounts for the full twelve months ending June 30, 2019 in the table below are estimates and include the assets to be contributed to us at the consummation of this offering.

 

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Remora Royalties, Inc.

Estimated Cash Available to Make Dividend Payments

(Unaudited)

 

           Twelve Months
Ending
June 30,

2019
 

Revenue:

    

Oil, natural gas and NGL revenues

     $ 30,625,547  

Cost and expenses:

    

Production and ad valorem taxes

     $ 2,383,534  

Depreciation and depletion expenses

     $ 12,608,244  

Marketing and other deductions

        

General and administrative (1)

     $ 3,000,000  
    

 

 

 

Total costs and expenses

     $ 17,991,778  
    

 

 

 

Operating income

     $ 12,633,768  

Other expenses:

    

Interest expense (2)

     $ 513,750  

Income tax expense

     $ 2,545,204  
    

 

 

 

Net Income

     $ 9,574,814  
    

 

 

 

Adjustments to reconcile to pro forma Adjusted EBITDA:

    

Depreciation and depletion expenses

     $ 12,608,244  

Interest expense (2)

     $ 513,750  

Income tax expense (3)

     $ 2,558,854  
    

 

 

 

Adjusted EBITDA (4)

     $ 25,242,013  
    

 

 

 

Adjustments to reconcile Adjusted EBITDA to cash available to make dividend payments:

    

Cash interest expense (2)

     $ 448,750  

Cash income tax expense (3)

     $ 850,925  

Capital expenditures

        
    

 

 

 

Cash available for dividend payments and distributions

     $ 23,942,337  
    

 

 

 

Cash reserves

        

Aggregate dividends and distributions:

    

Units in Remora Holdings held by the Contributing Parties

    Units:     

Class A common stock held by the public

    Shares:     
    

 

 

 

Per share dividend to Class A common stock

    
    

 

 

 

 

(1)   Reflects approximately $1.5 million of incremental general and administrative expenses that we expect to incur as a result of operating as a publicly traded company that are not reflected in our pro forma financial statements.

 

(2)   Interest expense is based on expected borrowings of $10.0 million at the closing of this offering to repay a portion of our Operating Affiliate’s indebtedness that Remora Holdings will assume in connection with this offering, inclusive of non-cash amortization of debt issuance costs. Cash interest expense does not include non-cash amortization of debt issuance costs.

 

(3)   Income tax expense is based on the statutory federal income tax rate of 21%. Cash income tax expense is based on an assumed cash income tax rate of approximately 7.0% that accounts for the effective tax rate of the Company.

 

(4)   Adjusted EBITDA is a financial measure not presented in accordance with GAAP. For a definition of Adjusted EBITDA and reconciliation to net income and net cash provided by operating activities, its most directly comparable financial measure calculated in accordance with GAAP, please read “Summary— Summary Historical and Unaudited Pro Forma Condensed Combined Financial Data—Non-GAAP Financial Measures”.

 

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Assumptions and Considerations

Based upon the specific assumptions outlined below, we expect to generate cash available to make dividend payments and distributions in an amount sufficient to allow us to pay $             per Class A common stock for the full twelve months ending June 30, 2019.

While we believe that these assumptions are reasonable in light of our management’s current expectations concerning future events, the estimates underlying these assumptions are inherently uncertain and are subject to significant business, economic, regulatory, environmental and competitive risks and uncertainties that could cause actual results to differ materially from those we anticipate. If our assumptions are not correct, the amount of actual cash available to make dividend payments could be substantially less than the amount we currently estimate and could, therefore, be insufficient to allow us to pay the forecasted cash dividends, or any amount, on our outstanding Class A common stock, in which event the market price of our Class A common stock may decline substantially. When reading this section, you should keep in mind the risk factors and other cautionary statements under the headings “Risk Factors” and “Forward-Looking Statements.” Any of the risks discussed in this prospectus could cause our actual results to vary significantly from our estimates.

General Considerations

Substantially all of the anticipated change in our estimated cash available to make dividend payments for the full twelve months ending June 30, 2019, compared to the pro forma year ended December 31, 2017 and the pro forma twelve months ended March 31, 2018, is primarily attributable to:

Assets from Contributing Parties not reflected in pro forma financial statements. Our estimate of cash available to make dividend payments for the full twelve months ending June 30, 2019 includes the additional assets that will be contributed to us at the consummation of this offering and which have not been audited and therefore are not presented in the pro forma cash available to make dividend payments for the year ended December 31, 2017 and the twelve months ended March 31, 2018. These additional assets represent approximately 12% of our future undiscounted cash flows, based on the reserve report prepared by Cawley as of December 31, 2017. During the year ended December 31, 2017 and the twelve months ended March 31, 2018, the operators on the properties reflected in our pro forma financial statements produced volumes of 9,324,481 Mcfe and 8,529,636 Mcfe, respectively, compared to our forecast of 8,157,921 Mcfe for the full twelve months ending June 30, 2019. The volume decrease reflected in the forecast compared to the year ended December 31, 2017 and the twelve months ended March 31, 2018 is 12.5% and 4.4%, respectively. The volume decrease for these periods is primarily attributable to the natural production decline of the properties as well as certain asset sales in 2017 conducted by our predecessor, partially offset by the addition of the assets discussed above.

Commodity prices. During the year ended December 31, 2017 and the twelve months ended March 31, 2018, our average realized price per Mcfe was $3.36 and $3.37, respectively, compared to the estimated weighted average NYMEX strip price of $3.75 per Mcfe for the full twelve months ending June 30, 2019 as of June 13, 2018, based on our forecasted production volumes. Our average realized price per Mcfe gives effect to the differentials between published oil and natural gas prices and the prices actually received for the oil and natural gas production. These differentials may vary significantly due to market conditions, transportation, gathering and processing costs, quality of production and other factors. The price increase reflected in the forecast compared to the year ended December 31, 2017 and the twelve months ended March 31, 2018 is 11.6% and 11.3%, respectively.

Cash available to make dividend payments. We estimate a $1.8 million decrease in cash available to make dividend payments for the full twelve months ending June 30, 2019 as compared to the year ended

 

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December 31, 2017. The decrease is primarily attributable to a 12.5% decrease in production volumes that account for $3.9 million, $0.3 million in estimated increased production and ad valorem taxes, and $0.8 million in estimated increased general and administrative expenses due to the addition of our other assets at the consummation of this offering from the Other Principal Contributing Parties, partially offset by a 11.6% increase in estimated price per Mcfe that accounts for $3.2 million.

We estimate a $0.7 million increase in cash available to make dividend payments for the full twelve months ending June 30, 2019 when compared to the twelve months ended March 31, 2018. The increase is primarily attributable to the 11.3% increase in price per Mcfe that accounts for $3.1 million, partially offset by the 4.4% decrease in production volumes that account for $1.3 million, $0.4 million in estimated increased production and ad valorem taxes, and $0.7 million in estimated increased general and administrative expenses due to the addition of our other assets at the consummation of this offering from the Other Principal Contributing Parties.

Operations and Revenue

Oil, natural gas and natural gas liquids revenues. Substantially all our revenues are a function of oil, natural gas and natural gas liquids production volumes sold and average prices received for those volumes. Based on the production and pricing information included below, we estimate that our oil, natural gas and natural gas liquids revenues for the full twelve months ending June 30, 2019 will be $30.6 million. For information on the effect of changes in prices and productions volumes, please read “—Sensitivity Analysis.”

Production. The following table sets forth information regarding production on the properties underlying our interests for the twelve months ended December 31, 2017 and March 31, 2018 and for the full twelve months ending June 30, 2019:

 

     Twelve Months Ended      Twelve
Months
Ending

June 30,
2019
 
     December
31, 2017
     March 31,
2018
    

Production:

        

Oil (Bbls)

     172,233        160,273        175,715  

Natural Gas (Mcf)

     6,934,830        6,533,022        6,352,558  

Natural gas liquids (Bbls)

     226,042        172,496        125,179  

Combined volumes (Mcfe)

     9,324,481        8,529,636        8,157,921  

Average daily production:

        

Oil (Bbls/d)

     472        439        481  

Natural gas (Mcf/d)

     19,000        17,899        17,404  

Natural gas liquids (Bbls/d)

     619        473        343  

Combined volumes (Mcfe/d)

     25,547        23,369        22,350  

We estimate that oil and natural gas production from the properties underlying our interests for the full twelve months ending June 30, 2019 will be 8,157,921 Mcfe.

We own a diversified portfolio of interests in oil and natural gas properties. Substantially all our revenues are a function of oil and natural gas production volumes sold and average prices received for those

 

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volumes. Our forecasted production is derived from existing wells on our assets and from new wells projected to begin producing during the forecast period. Approximately 97% of our forecasted production for the forecasted period is derived from existing producing wells, with the remaining production derived from the development of a portion of the PDNP reserves from our year-end reserve report prepared by Cawley.

Prices. The table below illustrates the relationship between average realized sales prices and the estimated weighted average of the monthly NYMEX strip prices as of June 13, 2018 for the full twelve months ending June 30, 2019:

 

Forecasted average oil sales prices:

  

NYMEX-WTI oil price per Bbl

   $ 65.38  

Differential to NYMEX-WTI oil per Bbl (1)

   $ (3.66

Realized oil sales price per Bbl

   $ 61.72  

Forecasted average natural gas liquids sales prices:

  

NYMEX-WTI oil price per Bbl

   $ 65.38  

Differential to NYMEX-WTI oil per Bbl (1)

   $ (41.38

Realized natural gas liquids sales price per Bbl

   $ 24.00  

Forecasted average natural gas sales prices:

  

NYMEX-Henry Hub per price MMBtu

   $ 2.93  

Differential to NYMEX-Henry Hub natural gas (1)

   $ (0.29

Realized natural gas sales price per Mcf

   $ 2.64  

Total weighted average combined realized price (per Mcfe)

   $ 3.75  

 

(1)   Differentials between published oil and natural gas prices and the prices actually received for the oil and natural gas production may vary significantly due to market conditions, transportation, gathering and processing costs, quality of production and other factors. The differentials to published oil and natural gas prices are based upon our analysis of the historic price differentials for production from the overriding royalty and mineral interests with consideration given to gravity, quality and transportation and marketing costs that may affect these differentials. There is no assurance that these assumed differentials will occur.

Costs and Expenses

Production and ad valorem taxes. The following table summarizes production and ad valorem taxes (in thousands) on a forecasted basis for the full twelve months ending June 30, 2019:

 

Production taxes

   $ 1,777  

Ad valorem taxes

   $ 606  

Total production and ad valorem taxes

   $ 2,384  
  

 

 

 

Production and ad valorem taxes as a percentage of revenue

     7.8

Our production taxes are calculated as a percentage of our oil, natural gas and NGL revenues. In general, as prices and volumes increase, our production taxes increase. As prices and volumes decrease, our production taxes decrease. Ad valorem taxes are jurisdictional taxes levied on the value of oil and natural gas royalties, minerals and reserves. Rates, methods of calculating property values, and timing of payments vary between taxing authorities. Due to the direct nature of the reserve value to the price of the commodity, as commodity prices fluctuate, the valuation of the underlying reserves generally fluctuate with the price. Therefore, the cost of ad valorem taxes generally correlate to the changes in oil, natural gas and NGL revenues.

 

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Depreciation and depletion expenses. We estimate that our depreciation and depletion expenses for the full twelve months ending June 30, 2019 will be $12.6 million. The forecasted depreciation and depletion expense is based on the production estimates in our reserve reports. The estimated depletion rate per Mcfe is approximately $1.55.

General and administrative expenses. We estimate that our general and administrative expenses for the full twelve months ending June 30, 2019 will be $3.0 million, which includes an incremental $1.5 million of general and administrative expenses we expect to incur as a result of becoming a publicly traded company.

Interest expense. We estimate that we will have $513,750 in interest expense for the full twelve months ending June 30, 2019. We intend to enter into a $             million secured revolving credit facility with an initial elected borrowing base of $65.0 million in connection with this offering, and such credit facility is forecasted to have $10.0 million of borrowings outstanding, which we expect to use to repay a portion of our Operating Affiliate’s indebtedness that Remora Holdings will assume at the closing of this offering. In addition, solely to the extent necessary as a result of any timing issues or delays in receiving mineral and royalty payments immediately upon the consummation of the assignment of our assets at the closing of this offering, we may borrow to pay a portion of our initial quarterly dividends; however, we expect such borrowings to be short-term in nature and repaid in the subsequent quarter and therefore to generate minimal incremental interest expense. At the closing of this offering, we expect to incur a commitment fee of $             and annual amortization of deferred finance costs of $             .

Financing

We intend to enter into a new $             million secured revolving credit facility with an initial elected borrowing base of $65.0 million. The unused portion of the secured revolving credit facility is subject to a commitment fee equal to                  basis points.

Capital Expenditures

We do not forecast any capital expenditures or acquisitions during the forecast period. Based on management’s analysis, we expect that, over the long term, working interest owners, including our Operating Affiliate and the other Contributing Parties, will continue to develop our acreage through recompletions, infill drilling, hydraulic fracturing, and secondary and tertiary recovery methods, and, as a result, we have estimated that we will not incur maintenance capital expenditures during the forecast period.

Regulatory, Industry and Economic Factors

Our forecast for the full twelve months ending June 30, 2019 is based on the following significant assumptions related to regulatory, industry and economic factors:

 

    there will not be any new federal, state or local regulation of portions of the energy industry in which we operate, or an interpretation of existing regulation, that will be materially adverse to our business;

 

    there will not be any major adverse change in commodity prices or the energy industry in general;

 

    our Operating Affiliate, the Other Principal Contributing Parties, and other third-party operators will continue to conduct their operations in a manner that is not substantially different than currently conducted;

 

    market, insurance and overall economic conditions will not change substantially; and

 

    we will not undertake any extraordinary transactions that would materially affect our cash flow.

 

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Forecasted Dividends

We intend to pay aggregate quarterly dividends on our Class A common stock and aggregate distributions to the Contributing Parties with respect to their ownership in Remora Holdings for the full twelve months ending June 30, 2019 of $23.9 million. While we believe that the assumptions we have used in preparing the estimates set forth above are reasonable based upon management’s current expectations concerning future events, they are inherently uncertain and are subject to significant business, economic regulatory and competitive risks and uncertainties, including those described in “Risk Factors,” that could cause actual results to differ materially from those we anticipate. If our actual results are significantly below forecasted results, or if our expenses are greater than forecasted, we may not be able to pay the forecasted annual dividends on all our outstanding Class A common stock in respect of the four calendar quarters ending June 30, 2019 or thereafter, which may cause the market price of our Class A common stock to decline materially.

Sensitivity Analysis

Our ability to generate sufficient cash from operations to make dividend payments on our Class A common stock is a function of two primary variables: (i) production volumes and (ii) commodity prices. In the paragraphs below, we demonstrate the impact that changes in either of these variables, while holding all other variables constant, would have on our ability to generate sufficient cash from our operations to pay quarterly dividends on our Class A common stock for the full twelve months ending June 30, 2019.

Production Volume Changes

The following table shows estimated cash available to make dividend payments under production levels of 90%, 100% and 110% of the production level we have forecasted for the full twelve months ending June 30, 2019.

 

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                Percentage of Forecasted Annual
Production
 
        90     100     110

Forecasted annual production:

         

Oil (bbls)

        158,144       175,715       193,287  

Natural gas (Mcf)

        5,717,302       6,352,558       6,987,814  

Natural gas liquids (Bbls)

        112,661       125,179       137,696  

Combined Volumes (Mcfe)

        7,342,129       8,157,921       8,973,713  

Forecasted average daily production:

         

Oil (bbls)

        433       481       530  

Natural gas (Mcf)

        15,664       17,404       19,145  

Natural gas liquids (Bbls)

        309       343       377  

Combined Volumes (Mcfe)

        20,115       22,350       24,586  

Forecasted average oil sales prices:

        100     100     100

NYMEX-WTI oil price per Bbl

      $ 65.38     $ 65.38     $ 65.38  

Realized oil sales price per Bbl

      $ 61.72     $ 61.72     $ 61.72  

NYMEX-WTI oil price per Bbl

      $ 65.38     $ 65.38     $ 65.38  

Realized natural gas liquids sales price per Bbl

      $ 24.00     $ 24.00     $ 24.00  

Forecasted average natural gas sales prices:

         

NYMEX-Henry Hub natural gas price per MMBtu

      $ 2.93     $ 2.93     $ 2.93  

Realized natural gas sales price per Mcf

      $ 2.64     $ 2.64     $ 2.64  

Revenue:

         

Oil, natural gas and NGL revenues

      $ 27,562,992     $ 30,625,547     $ 33,688,101  

Cost and expenses:

         

Production and ad valorem taxes

      $ 2,145,181     $ 2,383,534     $ 2,621,888  

Depreciation and depletion expenses

      $ 11,347,420     $ 12,608,244     $ 13,869,069  

Marketing and other deductions

        --       --       --  

General and administrative (1)

      $ 3,000,000     $ 3,000,000     $ 3,000,000  
     

 

 

   

 

 

   

 

 

 

Total costs and expenses

      $ 16,492,601     $ 17,991,778     $ 19,490,956  
     

 

 

   

 

 

   

 

 

 

Operating income

      $ 11,070,391     $ 12,633,768     $ 14,197,145  

Other expenses:

         

Interest expense (2)

      $ 513,750     $ 513,750     $ 513,750  

Income tax expense (3)

      $ 2,216,895     $ 2,545,204     $ 2,873,513  
     

 

 

   

 

 

   

 

 

 

Net Income

      $ 8,339,747     $ 9,574,814     $ 10,809,882  
     

 

 

   

 

 

   

 

 

 

Adjustments to reconcile to pro forma Adjusted EBITDA:

         

Depreciation and depletion expenses

      $ 11,347,420     $ 12,608,244     $ 13,869,069  

Interest expense

      $ 513,750     $ 513,750     $ 513,750  

Income tax expense

      $ 2,216,895     $ 2,545,204     $ 2,873,513  
     

 

 

   

 

 

   

 

 

 

Adjusted EBITDA (4)

      $ 22,417,811     $ 25,242,013     $ 28,066,214  
     

 

 

   

 

 

   

 

 

 

Adjustments to reconcile Adjusted EBITDA to cash available to make dividend payments:

         

Cash interest expense (2)

      $ 448,750     $ 448,750     $ 448,750  

Cash income tax expense (3)

      $ 741,749     $ 850,925     $ 960,101  

Capital expenditures

                     
     

 

 

   

 

 

   

 

 

 

Cash available for dividend payments and distributions

      $ 21,227,313     $ 23,942,337     $ 26,657,362  
     

 

 

   

 

 

   

 

 

 

Cash reserves

                     

Aggregate dividends and distributions:

         

Units in Remora Holdings held by all Contributing Parties

    Units:          

Class A common stock held by the public

    Shares:          
     

 

 

   

 

 

   

 

 

 

Per share dividend to Class A common stock

         
     

 

 

   

 

 

   

 

 

 

 

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(1)   Reflects approximately $1.5 million of incremental general and administrative expenses that we expect to incur as a result of operating as a publicly traded company that are not reflected in our pro forma financial statements.

 

(2)   Interest expense is based on expected borrowings of $10.0 million at the closing of this offering to repay a portion of our Operating Affiliate’s indebtedness that Remora Holdings will assume in connection with this offering, inclusive of non-cash amortization of debt issuance costs. Cash interest expense does not include non-cash amortization of debt issuance costs.

 

(3)   Income tax expense is based on the statutory federal income tax rate of 21%. Cash income tax expense is based on an assumed cash income tax rate of approximately 7.0% that accounts for the effective tax rate of the Company.

 

(4)   Adjusted EBITDA is a financial measure not presented in accordance with GAAP. For a definition of Adjusted EBITDA and reconciliation to net income and net cash provided by operating activities, its most directly comparable financial measure calculated in accordance with GAAP, please read “Summary— Summary Historical and Unaudited Pro Forma Condensed Combined Financial Data—Non-GAAP Financial Measures”.

Commodity Price Changes

The following table shows estimated cash available to make dividend payments under various assumed NYMEX-WTI oil and NYMEX-Henry Hub natural gas prices for the full twelve months ending June 30, 2019. The amounts shown below are based on forecasted realized commodity prices that take into account our average NYMEX commodity price differential assumptions. We have assumed no changes in our production based on changes in commodity prices. Further, we have ignored the impact of any commodity hedges that the Company may enter into in the future.

 

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Forecasted annual production:

            

Oil (Bbls)

           175,715       175,715       175,715  

Natural gas (Mcf)

           6,352,558       6,352,558       6,352,558  

Natural gas liquids (Bbls)

           125,179       125,179       125,179  

Combined Volumes (Mcfe)

           8,157,921       8,157,921       8,157,921  

Forecasted average daily production:

            

Oil (bbls)

           481       481       481  

Natural gas (Mcf)

           17,404       17,404       17,404  

Natural gas liquids (Bbls)

           343       343       343  

Combined Volumes (Mcfe)

           22,350       22,350       22,350  
                   Percentage Change in Commodity Price  

Forecasted average oil sales prices:

           90     100     110

NYMEX-WTI oil price per Bbl

         $ 58.85     $ 65.38     $ 71.92  

Realized oil sales price per Bbl

         $ 55.55     $ 61.72     $ 67.89  

NYMEX-WTI oil price per Bbl

         $ 58.85     $ 65.38     $ 71.92  

Realized natural gas liquids sales price per Bbl

         $ 21.60     $ 24.00     $ 26.40  

Forecasted average natural gas sales prices:

            

NYMEX-Henry Hub natural gas price per MMBtu

         $ 2.64     $ 2.93     $ 3.22  

Realized natural gas sales price per Mcf

         $ 2.38     $ 2.64     $ 2.90  

Revenue:

            

Oil, natural gas and NGL revenues

         $ 27,562,992     $ 30,625,547     $ 33,688,101  

Cost and expenses:

            

Production and ad valorem taxes

         $ 2,145,181     $ 2,383,534     $ 2,621,888  

Depreciation and depletion expenses

         $ 12,608,244     $ 12,608,244     $ 12,608,244  

Marketing and other deductions

                        

General and administrative (1)

         $ 3,000,000     $ 3,000,000     $ 3,000,000  
        

 

 

   

 

 

   

 

 

 

Total costs and expenses

         $ 17,753,425     $ 17,991,778     $ 18,230,132  
        

 

 

   

 

 

   

 

 

 

Operating income

         $ 9,809,567     $ 12,633,768     $ 15,457,970  

Other expenses:

            

Interest expense (2)

         $ 513,750     $ 513,750     $ 513,750  

Income tax expense (3)

         $ 1,952,122     $ 2,545,204     $ 3,138,286  
        

 

 

   

 

 

   

 

 

 

Net Income

         $ 7,343,695     $ 9,574,814     $ 11,805,933  
        

 

 

   

 

 

   

 

 

 

Adjustments to reconcile to pro forma Adjusted EBITDA:

            

Depreciation and depletion expenses

         $ 12,608,244     $ 12,608,244     $ 12,608,244  

Interest expense (2)

         $ 513,750     $ 513,750     $ 513,750  

Income tax expense (3)

         $ 1,952,122     $ 2,545,204     $ 3,138,286  
        

 

 

   

 

 

   

 

 

 

Adjusted EBITDA (4)

         $ 22,417,811     $ 25,242,013     $ 28,066,214  
        

 

 

   

 

 

   

 

 

 

 

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                   Percentage Change in Commodity Price  

Adjustments to reconcile Adjusted EBITDA to cash available to make dividend payments:

              

Cash interest expense (2)

         $ 448,750      $ 448,750      $ 448,750  

Cash income tax expense (3)

         $ 653,701      $ 850,925      $ 1,048,150  

Capital expenditures

                          
        

 

 

    

 

 

    

 

 

 

Cash available for dividend payments and distributions

         $ 21,315,361      $ 23,942,337      $ 26,569,314  
        

 

 

    

 

 

    

 

 

 

Cash reserves

                          

Aggregate dividends and distributions:

              

Units in Remora Holdings held by all Contributing Parties

     Units:              

Class A common stock held by the public

     Shares:              
        

 

 

    

 

 

    

 

 

 

Per share dividend to Class A common stock

              
        

 

 

    

 

 

    

 

 

 

 

(1)   Reflects approximately $1.5 million of incremental general and administrative expenses that we expect to incur as a result of operating as a publicly traded company that are not reflected in our pro forma financial statements.

 

(2)   Interest expense is based on expected borrowings of $10.0 million at the closing of this offering to repay a portion of our Operating Affiliate’s indebtedness that Remora Holdings will assume in connection with this offering, inclusive of non-cash amortization of debt issuance costs. Cash interest expense does not include non-cash amortization of debt issuance costs.

 

(3)   Income tax expense is based on the statutory federal income tax rate of 21%. Cash income tax expense is based on an assumed cash income tax rate of approximately 7.0% which accounts for the effective tax rate of the Company.

 

(4)   Adjusted EBITDA is a financial measure not presented in accordance with GAAP. For a definition of Adjusted EBITDA and reconciliation to net income and net cash provided by operating activities, its most directly comparable financial measure calculated in accordance with GAAP, please read “Summary— Summary Historical and Unaudited Pro Forma Condensed Combined Financial Data—Non-GAAP Financial Measures”.

 

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SELECTED HISTORICAL AND UNAUDITED PRO FORMA FINANCIAL DATA

Remora Royalties, Inc. was formed in May 2018 and does not have historical financial statements. In this prospectus we present the historical financial statements of Remora Petroleum, L.P., our predecessor for accounting purposes. We refer to this entity as “our predecessor.” The following table presents selected historical financial data of our predecessor as of the dates and for the periods indicated and selected unaudited pro forma financial data of Remora Royalties, Inc. as of the dates and for the years indicated.

The selected historical financial data of our predecessor presented as of and for the periods ended December 31, 2017 and 2016 are derived from the audited historical financial statements of our predecessor included elsewhere in this prospectus. The summary historical financial data of our predecessor presented as of March 31, 2018 and for the three months ended March 31, 2018 and 2017 are derived from the unaudited historical financial statements of our predecessor included elsewhere in this prospectus.

The selected unaudited pro forma financial data presented as of and for the three months ended March 31, 2018 and for the year ended December 31, 2017 are derived from our unaudited pro forma financial statements included elsewhere in this prospectus and give effect to the following formation transactions:

 

    Remora Holdings’ acquisition of assets to be contributed by our Operating Affiliate and the Other Principal Contributing Parties in exchange for an aggregate of          RH Units and the purchase of                  shares of Class B common stock for par value by our Operating Affiliate and the Other Principal Contributing Parties and the purchase of          RH Units from our Operating Affiliate and the Other Principal Contributing Parties in exchange for $          million in cash from the net proceeds of this offering, as further described under “Formation Transactions.” The unaudited pro forma financial statements do not reflect the issuance of          RH Units (and the purchase of an equivalent number of shares of Class B common stock) and the purchase of          RH Units for $         in cash for the assets not reflected in the unaudited pro forma financial statements;

 

    The retention by our Operating Affiliate of certain oil and natural gas properties and all other assets, liabilities and operations that will not be acquired by Remora Holdings;

 

    Remora Holdings’ assumption of approximately $         million of indebtedness of our Operating Affiliate that burdens the assets to be contributed to Remora Holdings by our Operating Affiliate;

 

    Our acquisition of the 2017 South Texas Assets;

 

    The issuance by us of         of the                 shares of Class A common stock being offered to the public in this offering at an assumed initial public offering price of $         per share, which is the mid-point of the price range set forth on the cover of this prospectus, reflecting that number of shares of common stock issued to the public the proceeds of which are deemed to (1) be contributed to Remora Holdings in exchange for                  RH Units and (2) purchase                  RH Units from our Operating Affiliate and the Other Principal Contributing Parties. The unaudited pro forma financial statements do not reflect the issuance of                 shares of Class A common stock issued to the public deemed to fund the acquisition of assets from the other Contributing Parties;

 

    The use of the net proceeds from this offering as set forth in “Use of Proceeds”;

 

    A provision for corporate income taxes at an effective rate of     %, inclusive of all U.S. federal, state and local income taxes;

 

    Remora Holdings’ entrance into a new $         million secured revolving credit facility, pursuant to which we expect to borrow approximately $         at the closing of this offering to repay the indebtedness assumed from our Operating Affiliate; and

 

    Our entrance into a management services agreement with our Operating Affiliate.

 

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The unaudited pro forma balance sheet data assumes the events described above occurred as of March 31, 2018. The unaudited pro forma statement of operations data for the three months ended March 31, 2018 and the year ended December 31, 2017 assume the events described above occurred as of January 1, 2017.

We have not given pro forma effect to our acquisition of assets to be contributed by the Contributing Parties other than our predecessor, Vendera Resources II, LLC and its affiliates, Vendera Resources, III, L.P. and its affiliates and AVAD Energy Partners, LLC, which excludes assets representing approximately 12% of our future undiscounted cash flows, based on the reserve report prepared by Cawley as of December 31, 2017.

We have not given pro forma effect to incremental general and administrative expenses of approximately $         million that we expect to incur annually as a result of operating as a publicly traded company, including: expenses associated with SEC reporting requirements, including annual and quarterly reports to stockholders, tax return and dividend expenses, Sarbanes-Oxley Act compliance expenses, expenses associated with listing on the NASDAQ, independent auditor fees, independent reserve engineer fees, legal fees, investor relations expenses, registrar and transfer agent fees, director and officer insurance expenses and director and officer compensation expenses.

For a detailed discussion of the selected historical financial data contained in the following table, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations.” The following table should also be read in conjunction with “Use of Proceeds” and the audited historical financial statements of our predecessor included elsewhere in this prospectus. Among other things, the historical financial statements include more detailed information regarding the basis of presentation for the information in the following table.

 

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The following table presents Adjusted EBITDA, a financial measure that is not presented in accordance with GAAP. We use Adjusted EBITDA in our business as we believe it is an important supplemental measure of our operating performance and liquidity. For a definition of and a reconciliation of Adjusted EBITDA to net income and net cash provided by operating activities, its most directly comparable financial measures in accordance with GAAP, please read “—Non-GAAP Financial Measures.” For a discussion of how we use Adjusted EBITDA to evaluate our operating performance and liquidity, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Adjusted EBITDA.”

 

    Remora Royalties, Inc.
Pro Forma
    Predecessor Historical  
    Three Months
Ended
March 31,
2018
    Year Ended
December 31,

2017
    Three Months
Ended March 31,
    Year Ended
December 31,
 
      2018     2017     2017     2016  

Statement of Operations Data:

           

Revenue:

           

Oil, natural gas and NGL revenue

  $                  $              $ 9,934,187     $ 11,436,818     $ 36,059,114     $ 12,438,637  

Cost and expenses:

           

Lease operating expenses

        3,367,645       2,889,744       10,608,592       5,712,571  

Workover expense

        286,250       761,359       2,588,007       870,282  

Production taxes

        604,228       488,218       1,527,684       427,193  

Marketing and other direct operating expenses

        1,493,494       1,427,614       5,426,373       1,171,845  

Depletion, depreciation and amortization

        1,779,265       1,743,568       6,703,123       3,329,649  

Accretion expense

        176,440       143,545       426,925       157,950  

Impairment of oil and natural gas properties

                          30,115,350  

General and administrative expenses

        1,497,060       718,968       3,446,096       1,662,289  
     

 

 

   

 

 

   

 

 

   

 

 

 

Total operating expenses

        9,204,382       8,173,016       30,726,800       43,447,129  

Income (loss) from operations

        729,805       3,263,802       5,332,314       (31,008,492

Net gain (loss) on derivative instruments

        (751,902     7,169,487       5,134,256       (6,280,818

Interest expense

        (1,273,697     (1,449,243     (5,348,882     (2,835,300

Other income (expense)

        17,128       1,503       1,533,756       (1,180

Income tax expense (benefit)

                           
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total other income (loss)

        (2,008,471     5,721,747       1,319,130       (9,117,298
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Net income (loss)

  $     $       $(1,278,666)     $ 8,985,549     $ 6,651,444     $ (40,125,790
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Statement of Cash Flows Data:

           

Net cash provided by (used in):

           

Operating activities

  $     $     $ 356,960     $ 1,510,260     $ 9,954,122     $ 2,102,807  

Investing activities

  $     $     $ 950,149     $ 172,291     $ 8,822,602     $ (40,583,418

Financing activities

  $     $     $ (1,359,100   $ 1,163,879     $ (17,518,999   $ 33,728,402  

Other Financial Data:

           

Adjusted EBITDA (1)

  $     $                  $ 2,249,734     $ 5,185,596     $ 16,563,317     $ 6,623,770  

Selected Balance Sheet Data:

           

Cash and cash equivalents

  $     $     $ 2,481,770     $ 4,122,466     $ 2,533,761     $ 1,276,036  

Total assets

  $     $     $ 63,072,228     $ 69,363,122     $ 66,185,399     $ 61,863,679  

Long-term debt

  $     $     $ 47,950,317     $ 67,530,376     $ 49,186,099     $ 66,254,924  

Total liabilities

  $     $     $ 78,831,327     $ 81,500,350     $ 80,656,732     $ 82,986,456  

Shareholders’ equity / Partners’ deficit

  $     $     $ (15,759,099   $ (12,137,228)     $ (14,471,333   $ (21,122,777

 

(1)   For more information, please read “—Non-GAAP Financial Measures.”

 

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Non-GAAP Financial Measures

Adjusted EBITDA

Adjusted EBITDA is used as a supplemental non-GAAP financial measure by management and external users of our financial statements, such as industry analysts, investors, lenders and rating agencies. We believe Adjusted EBITDA is useful because it allows us to more effectively evaluate our operating performance and compare the results of our operations period to period without regard to our financing methods or capital structure. In addition, management uses Adjusted EBITDA to evaluate cash flow available to pay dividends to our stockholders.

We define Adjusted EBITDA as net income (loss) plus depreciation, depletion and accretion expenses, interest expense, non-cash equity compensation, impairment of oil and natural gas properties, income tax expense and unrealized net (gain) loss on derivative instruments. Adjusted EBITDA is not a measure of net income (loss) or net cash provided by operating activities as determined by GAAP. We exclude the items listed above from net income (loss) in arriving at Adjusted EBITDA 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. Certain items excluded from Adjusted EBITDA 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 historic costs of depreciable assets, none of which are components of Adjusted EBITDA.

Adjusted EBITDA should not be considered an alternative to net income, oil, natural gas and NGL revenues, net cash provided by operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP. Our computations of Adjusted EBITDA may not be comparable to other similarly titled measures of other companies.

 

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The following tables present a reconciliation of Adjusted EBITDA to net income and net cash provided by operating activities, our most directly comparable GAAP financial measures for the periods indicated.

 

    Remora Royalties, Inc.
Pro Forma
    Predecessor Historical  
    Three Months
Ended
March 31,
2018
    Year Ended
December 31,

2017
    Three Months
Ended March 31,
    Year Ended
December 31,
 
        2018     2017     2017     2016  

Reconciliation of net income (loss) to Adjusted EBITDA:

           

Net income (loss)

  $                  $                  $ (1,278,666)     $ 8,985,549      $ 6,651,444      $ (40,125,790)  

Depreciation, depletion and accretion expenses

        1,955,705        1,887,113        7,130,048        3,487,599   

Interest expense

        1,273,697        1,449,243        5,348,882        2,835,300   

Income tax expense

        —        —        —        —   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

EBITDA

        1,950,736        12,321,905        19,130,374        (33,802,891)  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Impairment of oil and natural gas properties

        —        —        —        30,115,350   

Unrealized net (gain) loss on derivative instruments

        298,998        (7,136,309)       (2,567,057)       10,311,311   

Equity compensation

        —        —        —        —   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Adjusted EBITDA

  $                  $                  $ 2,249,734      $ 5,185,596      $ 16,563,317      $ 6,623,770   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Reconciliation of net cash provided by operating activities to Adjusted EBITDA:

           

Net cash provided by operating activities

  $                  $     $ 356,960      $ 1,510,260      $ 9,954,122      $ 2,102,807   

Interest expense

        1,273,697        1,449,243        5,348,882        2,835,300   

Income tax expense

        —        —       

Impairment of oil and natural gas properties

        —        —        —        (30,115,350)  

Unrealized net gain (loss) on derivative instruments

        (298,998)       7,136,309        2,567,057        (10,311,311)  

Equity compensation

        —        —        —        —   

Amortization of debt issuance costs

        (114,219)       (111,574)       (450,174)       (231,793)  

Settlement of asset retirement obligations

        37,305        5,847        212,313        149,658   

Changes in operating assets and liabilities:

           

Accounts receivables

        1,038,067        2,645,472        914,855        1,314,114   

Prepaid expenses and deposits

        256,105        (103,168)       (83,325)       356,381   

Accounts payable and accrued expenses

        (598,181)       (210,484)       666,644        97,303   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

EBITDA

  $     $             

$

 

 

1,950,736 

 

 

 

 

 

 

$

 

 

12,321,905 

 

 

 

 

 

  $ 19,130,374      $ (33,802,891)  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Add:

           

Impairment of oil and natural gas properties

        —        —        —        30,115,350   

Unrealized net (gain) loss on derivative instruments

        298,998        (7,136,309)       (2,567,057)       10,311,311   

Equity compensation

        —        —        —        —   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Adjusted EBITDA

  $              $     $ 2,249,734      $ 5,185,596      $ 16,563,317      $ 6,623,770   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

 

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

The following discussion should be read together with “Selected Historical and Unaudited Pro Forma Financial Data” and the historical and pro forma financial statements and related notes included elsewhere in this prospectus.

Unless otherwise indicated, the historical financial information in this “Management’s Discussion and Analysis of Financial Condition and Results of Operations” reflects only the historical financial results of our predecessor, Remora Petroleum, L.P., and does not include the results of any of the Other Principal Contributing Parties or give pro forma effect to the transactions described in “Formation Transactions.”

This discussion contains forward-looking statements that are based on the views and beliefs of our management, as well as assumptions and estimates made by our management. Such views, beliefs, assumptions and estimates may, and often do, vary from actual results and the differences can be material. Actual results could differ materially from such forward-looking statements as a result of various factors, including those that may not be in the control of our management. We do not undertake any obligation to publicly update any forward-looking statements except as otherwise required by applicable law. For further information on items that could impact our future operating performance or financial condition, please read the sections entitled “Risk Factors” and “Forward-Looking Statements” elsewhere in this prospectus.

Overview

Remora Royalties, Inc. is a growth-oriented Delaware corporation formed to own and acquire overriding royalty, mineral and royalty interests in oil and natural gas properties throughout the United States. We refer to these non-cost-bearing interests collectively as our “royalty interests.” Our royalty interests are located in 12 states and in 13 major onshore basins across the continental United States and include ownership in approximately 3,600 gross producing wells, predominantly in the Midcontinent, South Texas/Gulf Coast, East Texas/North Louisiana and Permian Basin, which are among the most historically prolific oil and natural gas regions in the United States. The geographic breadth of our assets gives us exposure to potential production and reserves from new and existing plays. As an owner of royalty interests, we benefit from the continued development of the properties in which we own an interest without the need for investment of additional capital by us. We are entitled to a portion of the revenues received from the production of oil, natural gas and associated NGLs from the acreage underlying our interests, net of post-production expenses and taxes. We are not obligated to fund drilling and completion costs, lease operating expenses or plugging and abandonment costs at the end of a well’s productive life. Our primary business objective is to provide increasing cash dividends to stockholders resulting from acquisitions of royalty interests from the Contributing Parties and third parties and from organic growth through the continued development by the Contributing Parties and other working interest owners of the properties in which we own an interest.

As of December 31, 2017, we owned royalty interests in approximately 593,000 gross acres (43,000 net acres) of which over 97% was held by production. For the year ended December 31, 2017, approximately 75% of net production underlying our royalty interests was from the Midcontinent, South Texas/Gulf Coast, East Texas/North Louisiana and Permian Basin. For this same period, the Contributing Parties operated approximately 46% of our net production, 788 of our gross wells and approximately 57% of our net acreage. The Contributing Parties were formed in part to acquire and develop mature oil and natural gas properties. We expect further development on our acreage by the Contributing Parties and other working interest owners through recompletions, infill drilling, horizontal drilling, hydraulic fracturing and secondary and tertiary recovery methods.

 

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Business Environment

Oil, natural gas and NGL prices have been historically volatile and may continue to be volatile in the future. In late 2014, prices for oil, natural gas and NGLs declined precipitously, and prices remained low throughout 2015 and for the first six months of 2016. Oil, natural gas and NGL prices have increased towards the latter part of 2017 and early 2018, but not to the price levels seen prior to the price decline in late 2014. WTI has ranged from a monthly average low of $30.32 per Bbl in February 2016 to a high of $106.29 per Bbl in September 2013. WTI monthly average price for March 2018 was $62.73 per Bbl, a 21% increase from $51.97 per Bbl for December 2016. The monthly average Henry Hub spot market price has ranged from a high of $6.00 per MMBtu in February 2014 to a low of $1.73 per MMBtu in March 2016. The monthly average Henry Hub spot market price for March 2018 was $2.69 per MMBtu, a 25% decline from $3.59 per MMBtu for December 2016. Additionally, monthly average NGL composite prices have fluctuated from approximately $11.94 per MMBtu in February 2014 to $3.69 per MMBtu in January 2016. In response to low commodity prices, operators scaled back their drilling activity significantly in late 2015 and throughout 2016.

Drilling activity has increased toward the second half of 2017 and early 2018 after experiencing a decline in 2016 and 2015 . However, drilling activity has not risen to the level seen prior to the decrease in commodity prices in late 2014. The Baker Hughes U.S. Rotary Rig count was 1,013 active rigs at April 20, 2018, a 54% increase from 658 active rigs at December 31, 2016. However, the 1,013 active rigs at April 20, 2018 represents a 45% decline from 1,840 active rigs at December 31, 2014. The following table, as reported by the EIA, sets forth the average prices for oil, natural gas and NGLs for the years ended December 31, 2017 and 2016 and the three months ended March 31, 2017 and 2018:

 

     Three Months Ended
March 31,
     Year Ended December 31,  

Average Prices:

       2018              2017              2017              2016      

Oil (Bbl)

   $ 62.89      $ 51.77      $ 50.80      $ 43.29  

Natural gas (MMBtu)

   $ 3.08      $ 3.01      $ 2.99      $ 2.52  

Natural gas liquids (Bbl)

   $ 44.98      $ 39.86      $ 41.52      $ 30.24  

 

Source: EIA.

Sources of Our Revenue

Our revenues are derived from payments we receive from our operators and purchasers based on the sale of oil and natural gas production, as well as the sale of NGLs that are extracted from natural gas during processing. For the year ended December 31, 2017, our revenues were derived 27% from oil sales, 53% from natural gas sales and 20% from NGL sales. For the three months ended March 31, 2018, our revenues were derived 32% from oil sales, 48% from natural gas sales and 20% from NGL sales. Our revenues may vary significantly from period to period as a result of changes in volumes of production sold or changes in commodity prices.

Our strategy includes entering into commodity derivative contracts covering approximately 20% to 30% of the estimated production from total PDP reserves underlying our royalty interests for at least two years, although we may increase this percentage if debt levels rise as a result of acquisitions.

Reserves and Pricing

The table below identifies our predecessor’s proved reserves at December 31, 2017 and 2016, in each case based on the estimated reserves as prepared by Cawley. The prices used to estimate proved reserves for

 

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all periods were held constant throughout the life of the properties and have been adjusted for quality, transportation fees, geographical differentials, marketing bonuses or deductions and other factors affecting the price received at the wellhead.

 

     As of December 31,  
         2017              2016      
Predecessor Estimated Net Proved Developed Reserves:      

Oil (MBbls)

     2,156        1,687  

Natural gas (MMcf)

     84,786        67,019  

Natural gas liquids (MBbls)

     3,119        3,610  
  

 

 

    

 

 

 

Total (MMcfe)(1)

     116,436        98,801  
  

 

 

    

 

 

 
Predecessor Estimated Net Proved Undeveloped Reserves:      

Oil (MBbls)

     1,071        0  

Natural gas (MMcf)

     63,338        0  

Natural gas liquids (MBbls)

     3,631        0  
  

 

 

    

 

 

 

Total (MMcfe)(1)

     91,549        0  
  

 

 

    

 

 

 
Predecessor Estimated Net Proved Reserves:      

Oil (MBbls)

     3,226        1,687  

Natural gas (MMcf)

     148,124        67,019  

Natural gas liquids (MBbls)

     6,751        3,610  
  

 

 

    

 

 

 

Total (MMcfe)(1)

     207,986        98,801  
  

 

 

    

 

 

 
Predecessor Estimated Net Probable Developed Reserves:      

Oil (MBbls)

     429     

Natural gas (MMcf)

     13,806     

Natural gas liquids (MBbls)

     0     
  

 

 

    

 

 

 

Total (MMcfe)(1)

     16,383     
  

 

 

    

 

 

 
Predecessor Estimated Net Probable Undeveloped Reserves:      

Oil (MBbls)

     2,759     

Natural gas (MMcf)

     139,587     

Natural gas liquids (MBbls)

     10,668     
  

 

 

    

 

 

 

Total (MMcfe)(1)

     220,145     
  

 

 

    

 

 

 
Predecessor Estimated Net Probable Reserves:      

Oil (MBbls)

     3,189     

Natural gas (MMcf)

     153,393     

Natural gas liquids (MBbls)

     10,668     
  

 

 

    

 

 

 

Total (MMcfe)(1)

     236,535     
  

 

 

    

 

 

 

 

    As of December 31,  

Unweighted Arithmetic Average First-Day-of-the-Month Prices

    2017         2016    

Oil (Bbls)

  $ 48.66     $ 37.78  

Natural gas (Mcf)

  $ 2.94     $ 1.57  

 

(1)   Totals may not sum or recalculate due to rounding.

 

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Adjusted EBITDA

Adjusted EBITDA is used as a supplemental non-GAAP financial measure by management and external users of our financial statements, such as industry analysts, investors, lenders and rating agencies. We believe Adjusted EBITDA is useful because it allows us to more effectively evaluate our operating performance and compare the results of our operations period to period without regard to our financing methods or capital structure. In addition, management uses Adjusted EBITDA to evaluate cash flow available to pay dividends to our stockholders.

We define Adjusted EBITDA as net income (loss) plus depreciation, depletion and accretion expenses, interest expense, non-cash equity compensation, impairment of oil and natural gas properties, income tax expense and unrealized net (gain) loss on derivative instruments. Adjusted EBITDA is not a measure of net income (loss) or net cash provided by operating activities as determined by GAAP. We exclude the items listed above from net income (loss) in arriving at Adjusted EBITDA 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. Certain items excluded from Adjusted EBITDA 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 historic costs of depreciable assets, none of which are components of Adjusted EBITDA.

Adjusted EBITDA should not be considered an alternative to net income, oil, natural gas and NGL revenues, net cash flows provided by operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP. Our computations of Adjusted EBITDA may not be comparable to other similarly titled measures of other companies.

Factors Affecting the Comparability of Our Results to the Historical Results of Our Predecessor

Our predecessor’s historical financial condition and results of operations may not be comparable, either from period to period or going forward, to the Company’s future results of operations, for the reasons described below:

Formation Transactions

The historical financial statements included in this prospectus of our predecessor, Remora Petroleum, L.P., do not reflect the formation transactions to be completed in connection with the completion of this offering. In connection with this offering, our predecessor will contribute certain royalty interests to Remora Holdings in exchange for RH Units and will purchase a corresponding number of shares of Class B common stock from us.

The historical financial data of our predecessor included in this “Management’s Discussion and Analysis of Financial Condition and Results of Operations” does not include the results of the Other Principal Contributing Parties and may not give you an accurate indication of what our actual results would have been if the transactions described in “Formation Transactions” had been completed at the beginning of the periods presented or of what our future results of operations are likely to be. Moreover, the historical financial statements of our predecessor comprise     % of our revenues on a pro forma basis after giving effect to the formation transactions. For more information, please read the historical financial statements of the entities other than our predecessor and the unaudited pro forma financial statements included elsewhere in this prospectus.

Credit Agreements

In May 2016, our predecessor entered into a credit agreement with BOK Financial Corporation and a term loan with Goldman Sachs Specialty Lending Group, L.P. For the year ended December 31, 2017 and the three months ended March 31, 2018, our predecessor’s interest expense was $5.3 million and $1.3

 

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million, respectively. Our predecessor had outstanding borrowings of $49.1 million as of March 31, 2018. We will assume $     million of our predecessor’s indebtedness in connection with the formation transactions, which will be fully repaid from the net proceeds of this offering and we expect to borrow $         under our secured revolving credit facility upon the closing of this offering. Prior to this offering, we will enter into a new $     million secured revolving credit facility. Please read “—Liquidity and Capital Resources—Indebtedness.”

Acquisition Opportunities

Acquisitions are an important part of our growth strategy, and we expect to pursue acquisitions of royalty interests from the Contributing Parties and third parties. We also may pursue acquisitions jointly with the Contributing Parties. As a consequence of any such acquisition and acquisition-related expense, the historical financial statements of our predecessor will differ from our financial statements in the future.

Management Services Agreement

In connection with this offering, we and our affiliate Remora Holdings will enter into a management services agreement with our Operating Affiliate, pursuant to which it will provide management and administrative services for our affiliate Remora Holdings and us. Amounts paid to our Operating Affiliate will reduce the amount of cash available to pay dividends to our Class A common stockholders. Please read “Certain Relationships and Related Party Transactions—Agreements and Transactions with Affiliates in Connection with this Offering—Management Services Agreement.”

Income Tax Expense

Remora Royalties, Inc. is a corporation for federal income tax purposes, and as a result, will be subject to U.S. federal, state and local income taxes. Although our predecessor was subject to franchise tax in the state of Texas (at less than 1% of modified pre-tax earnings), it generally passed through its taxable income to its owners for other income tax purposes and thus was not subject to U.S. federal income taxes or other state or local income taxes. Accordingly, the financial data attributable to our predecessor contains no provision for U.S. federal income taxes or income taxes in any state or locality other than franchise tax in the State of Texas. We estimate that we will be subject to U.S. federal, state and local taxes at a blended statutory rate of     % of pre-tax earnings.

Non-Operated Working Interest Assignment

Prior to the formation transactions, our predecessor will assign its non-operated working interests and associated asset retirement obligations to an affiliated company. At the closing of this offering, Remora Royalties, Inc. will not own any working interests and will not have any asset retirement obligations.

Reserves

The estimated reserves presented in this “Management’s Discussion and Analysis of Financial Condition and Results of Operation” and in the historical financial statements of our predecessor included elsewhere in this prospectus are based on our predecessor’s proved reserves. However, we have presented elsewhere in this prospectus estimated reserves of the Company, on a pro forma basis, which include reserves attributable to properties owned by the Contributing Parties and remove any reserves attributable to the working interests of the Predecessor.

Principal Components of Our Cost Structure

As an owner of mineral and royalty interests, we are not obligated to fund drilling and completion costs, lease operating expenses or plugging and abandonment costs at the end of a well’s productive life.

 

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Production and Ad Valorem Taxes

Production taxes are paid on produced oil, natural gas and NGLs based on a percentage of revenues from products sold at fixed rates established by federal, state or local taxing authorities. Where available, we benefit from tax credits and exemptions in our various taxing jurisdictions. We are also subject to ad valorem taxes in the counties where our production is located. Ad valorem taxes are jurisdictional taxes levied on the value of oil, natural gas and NGL minerals and reserves. Rates, methods of calculating property values and timing of payments vary between taxing authorities.

Depreciation and Depletion

We follow the full cost method of accounting for costs related to our oil, natural gas and NGL mineral and royalty properties. Under this method, all such costs are capitalized and amortized on an aggregate basis over the estimated lives of the properties using the unit-of-production method. The capitalized costs are subject to a ceiling test, which limits such pooled costs to the aggregate of the present value of future net revenues attributable to proved oil, natural gas and NGL reserves discounted at 10%, including the effect of income taxes. We do not assign any value to unproved properties in which we hold a mineral or royalty interest in calculating depletion and assessing impairment. The full cost ceiling is evaluated at the end of each quarterly period and additionally when events indicate possible impairment.

General and Administrative Expense

General and administrative expenses are costs not directly associated with the production of oil, natural gas and NGLs and include the cost of executives and employees and related benefits, office expenses and fees for professional services. In connection with this offering, we will enter into a management services agreement with our Operating Affiliate, pursuant to which it will provide management and administrative services for us.

In connection with the closing of this offering, we anticipate incurring incremental general and administrative expenses of approximately $     million that we expect to incur annually as a result of operating as a publicly traded corporation, such as expenses associated with SEC reporting requirements, including annual and quarterly reports to stockholders, tax return and dividend expenses, Sarbanes-Oxley Act compliance expenses, expenses associated with listing on the NASDAQ, independent auditor fees, independent reserve engineer fees, legal fees, investor relations expenses, registrar and transfer agent fees, director and officer insurance expenses and director and officer compensation expenses. These incremental general and administrative expenses are not reflected in the historical financial statements of our predecessor or the unaudited pro forma financial statements included elsewhere in this prospectus.

Interest Expense

For the year ended December 31, 2017 and the three months ended March 31, 2018, our predecessor’s interest expense was $5.3 million and $1.3 million, respectively. Our predecessor had outstanding borrowings of $49.2 million, net of debt discount, as of December 31, 2017. Prior to completion of this offering, Remora Holdings will enter into a new $     million secured revolving credit facility. Remora Holdings will assume $     million of our predecessor’s indebtedness in connection with the formation transactions, which will be fully repaid using the net proceeds from this offering and the $         we expect to borrow under Remora Holdings’ secured revolving credit facility upon the closing of this offering. Please read “—Liquidity and Capital Resources—Indebtedness.”

Income Tax Expense

For a discussion of income tax expense, please read “—Factors Affecting the Comparability of our Results to the Historical Results of our Predecessor—Income Tax Expense.”

 

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Predecessor Results of Operations

The following table summarizes our predecessor’s revenue and expenses and production data for the periods indicated.

 

     Three Months Ended
March 31,
    Years Ended
December 31,
 
     2018     2017     2017     2016  

Operating Results:

        

Oil, gas and NGL revenue

   $ 9,934,187     $ 11,436,818     $ 36,059,114     $ 12,438,637  

Operating expenses:

        

Lease operating expense

     3,367,645       2,889,744       10,608,592       5,712,571  

Workover expense

     286,250       761,359       2,588,007       870,282  

Production taxes

     604,228       488,218       1,527,684       427,193  

Marketing and transportation expense

     1,493,494       1,427,614       5,426,373       1,171,845  

Depletion, depreciation and amortization

     1,779,265       1,743,568       6,703,123       3,329,649  

Accretion expense

     176,440       143,545       426,925       157,950  

Impairment of oil and natural gas properties

                       30,115,350  

General and administrative expense

     1,497,060       718,968       3,446,096       1,662,289  
  

 

 

   

 

 

   

 

 

   

 

 

 

Total operating expenses

     9,204,382       8,173,016       30,726,800       43,447,129  

Income (loss) from operations

    
729,805
 
    3,263,802       5,332,314       (31,008,492

Other income (expense):

        

Net gain (loss) on derivative instruments

     (751,902     7,169,487       5,134,256       (6,280,818

Interest expense

     (1,273,697     (1,449,243     (5,348,882     (2,835,300

Other income (expense)

     17,128       1,503       1,533,756       (1,180
  

 

 

   

 

 

   

 

 

   

 

 

 

Total other income (loss)

     (2,008,471    
5,721,747
 
    1,319,130       (9,117,298
  

 

 

   

 

 

   

 

 

   

 

 

 

Net Income (loss)

   $ (1,278,666   $ 8,985,549     $ 6,651,444     $ (40,125,790

Production Data:

        

Oil (Bbls)

     49,108       59,429       200,814       146,320  

Natural gas (Mcf)

     2,080,535       1,942,289       6,747,492       2,437,883  

Natural gas liquids (Bbls)

     70,753       162,183       404,393       78,485  

Combined volumes (Mcfe) (6:1)

     2,799,702       3,271,961       10,378,734       3,786,713  

Average daily combined volumes (Mcfe/d) (6:1)

     31,108       36,355       28,435       10,346  

Comparison of the Three Months Ended March 31, 2018 to the Three Months Ended March 31, 2017

Oil, Natural Gas and Natural Gas Liquids Revenues

Our predecessor’s revenues for the three months ended March 31, 2018 was $9.9 million, a decrease of $1.5 million, from $11.4 million for the three months ended March 31, 2017. Our predecessor’s decrease in revenues was primarily due to lower realized natural gas prices for the three months ended March 31, 2018 compared to the three months ended March 31, 2017 and a 0.5 Bcfe decrease in production volumes year over year primarily due to the sale of certain oil and natural gas properties in the third quarter of 2017. The decrease in revenues was partially offset by higher realized oil and NGL prices for the three months ended March 31, 2018 compared to the three months ended March 31, 2017 and the acquisition of oil and natural gas properties in South Texas in December 2017.

Our predecessor’s revenues are a function of oil, natural gas, and NGL production volumes sold and average prices received for those volumes. Our predecessor’s sales volumes for the three months ended March 31, 2018 were 2.8 Bcfe, a decrease from 3.3 Bcfe for the three months ended March 31, 2017. Our predecessor received an average of $63.13 per Bbl of oil, $2.27 per Mcf of natural gas and $28.21 per Bbl of NGLs for the volumes sold during the three months ended March 31, 2018, as compared to an average of $48.30 per Bbl of oil, $2.84 per Mcf of natural gas and $18.32 per Bb1 of NGLs for the volumes sold during the three months ended March 31, 2017.

 

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Lease Operating Expense

Our predecessor’s lease operating expense increased by $0.5 million to $3.4 million for the three months ended March 31, 2018, from $2.9 million for the three months ended March 31, 2017. The increase in lease operating expense was primarily attributable to a one-time regulatory and environmental expense incurred for the three months ended March 31, 2018.

Workover Expense

Our predecessor’s workover expense decreased by $0.5 million to $0.3 million for the three months ended March 31, 2018, from $0.8 million for the three months ended March 31, 2017. The decrease in workover expenses were primarily attributable to the sale of certain properties in July 2017 that generated significant workover expenses.

Production Taxes

Our predecessor’s production taxes increased by $0.1 million to $0.6 million for the three months ended March 31, 2018, from $0.5 million for the three months ended March 31, 2017. The increase in production taxes was primarily attributable to higher production tax rates from oil and natural gas properties acquired in South Texas, as compared to the tax rates from oil and natural gas properties we sold in the Midcontinent in July 2017.

Marketing and Transportation Expense

Our predecessor’s marketing and transportation expense increased by $0.1 million to $1.5 million for the three months ended March 31, 2018, from $1.4 million for the three months ended March 31, 2017. The increase in marketing and transportation expense was primarily attributable to higher marketing and transportation expense from oil and natural gas properties acquired in South Texas as compared to such expenses from properties we sold in the Midcontinent in July 2017.

Depreciation, Depletion and Amortization Expense

Our predecessor’s depreciation, depletion and amortization expense increased by $0.1 million to $1.8 million for the three months ended March 31, 2018 from $1.7 million for three months ended March 31, 2017. The average depletion rate per barrel was $3.79 and $3.19 for the three months ended March 31, 2018 and 2017, respectively. The increase in the average depletion rate per barrel was primarily attributable to a higher amortization base relative to the proved reserves volumes. Depletion is the amount of cost basis of oil and natural gas properties at the beginning of a period attributable to the volume of hydrocarbons extracted during such period, calculated on a units-of-production basis. Estimates of proved developed producing reserves volumes are a major component in the calculation of depletion.

Accretion Expense

Our predecessor’s accretion expense for the three months ended March 31, 2018 was $0.2 million, an increase of $0.1 million from $0.1 million for the three months ended March 31, 2017. The increase in accretion expense was driven primarily by the increase in asset retirement obligations from the South Texas acquisition.

Impairment of Oil, Natural Gas and Natural Gas Liquids Expense

Our predecessor utilizes the full cost method of accounting for our oil and natural gas properties. Under the full cost method, capitalized costs are subject to a ceiling test, which limits such pooled costs to

 

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the aggregate of the present value of future net revenues attributable to proved oil, natural gas and NGL reserves discounted at 10%, including the effects of income taxes. Our predecessor does not assign any value to unproved properties in which it holds a royalty interest. The full cost ceiling is evaluated at the end of each quarterly period and additionally when events indicate possible impairment. Our predecessor did not incur any impairment for the three months ended March 31, 2018 and March 31, 2017 as the present value of future net revenues attributed to proved oil, natural gas and NGL reserves exceeded the net book value of our predecessor’s proved properties.

General and Administrative Expense

Our predecessor’s general and administrative expenses for the three months ended March 31, 2018 were $1.5 million, an increase of $0.8 million from $0.7 million for the three months ended March 31, 2017. Increases in general and administrative expenses were attributable to the increased costs related to this offering, particularly related to headcount increases and third-party audit and engineering services.

Net Gain (Loss) on Derivative Instruments

Our predecessor incurred a $0.8 million net loss on derivative instruments for the three months ended March 31, 2018, a decrease of $8.0 million from a $7.2 million net gain on derivative instruments for the three months ended March 31, 2017. Our predecessor had forward swap commodity contracts in 2017 and 2018, as well as collar commodity contracts on our predecessor’s oil, natural gas and natural gas liquids production. Decreases in net gain (loss) on derivative instruments were primarily due to changes in commodity prices that were less favorable toward our predecessor’s derivative position in the three months ended March 31, 2018.

Interest Expense

Our predecessor’s interest expense for the three months ended March 31, 2018 was $1.3 million, a decrease of $0.2 million from $1.5 million for the three months ended March 31, 2017. The decrease in interest expense is due to a decrease in the outstanding balance of our Predecessor Credit Facility during the three months ended March 31, 2018 compared to the three months ended March 31, 2017. Please read “—Liquidity and Capital Resources—Indebtedness.”

Comparison of the Year Ended December 31, 2017 to the Year Ended December 31, 2016

Oil, Natural Gas and Natural Gas Liquids Revenues

Our predecessor’s revenues for the year ended December 31, 2017 was $36.1 million, an increase of $23.7 million, from $12.4 million for the year ended December 31, 2016. Our predecessor’s increase in revenues was primarily due to higher commodity prices overall in 2017 compared to 2016 and 6.6 Bcfe increase in production volume year over year primarily due to our acquisition on December 9, 2016 of oil and natural gas properties in Oklahoma.

Our predecessor’s revenues are a function of oil, natural gas, and NGL production volumes sold and average prices received for those volumes. Our predecessor’s production volumes for the year ended December 31, 2017 were 10.4 Bcfe, an increase from 3.8 Bcfe for the year ended December 31, 2016. Our predecessor received an average of $47.16 per Bbl of oil, $2.81 per Mcf of natural gas and $17.64 per Bbl of NGLs for the volumes sold during the year ended December 31, 2017, as compared to an average of $39.47 per Bbl of oil, $2.26 per Mcf of natural gas and $14.28 per Bbl of NGLs for the volumes sold during the year ended December 31, 2016.

Lease Operating Expense

Our predecessor’s lease operating expense increased by $4.9 million to $10.6 million for the year ended December 31, 2017, from $5.7 million for the year ended December 31, 2016. The increase in lease

 

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operating expense was primarily attributable to the increase in production volume year over year and increase in well count year over year as a result of our predecessor’s acquisitions in late 2016 and throughout 2017.

Workover Expense

Our predecessor’s workover expense increased by $1.7 million to $2.6 million for the year ended December 31, 2017, from $0.9 million for the year ended December 31, 2016. The increase in workover expense was primarily attributable to the increase in well count year over year as a result of our predecessor’s acquisitions in late 2016 and throughout 2017.

Production Taxes

Our predecessor’s production taxes increased by $1.1 million to $1.5 million for the year ended December 31, 2017, from $0.4 million for the year ended December 31, 2016. The increase in production taxes was primarily attributable to an increase in oil, natural gas and NGL revenues.

Marketing and Transportation Expense

Our predecessor’s marketing and transportation expense increased by $4.2 million to $5.4 million for the year ended December 31, 2017, from $1.2 million for the year ended December 31, 2016. The increase in marketing and transportation expense was primarily attributable to an increase in oil, natural gas and NGL production.

Depreciation, Depletion and Amortization Expense

Our predecessor’s depreciation, depletion and accretion expense increased by $3.4 million to $6.7 million for the year ended December 31, 2017 from $3.3 million for year ended December 31, 2016. The average depletion rate per barrel was $3.86 and $5.27 for the year ended December 31, 2017 and 2016, respectively. The decrease in the average depletion rate per barrel was primarily attributable to higher proved reserves volumes relative to the amortization base. Depletion is the amount of cost basis of oil and natural gas properties at the beginning of a period attributable to the volume of hydrocarbons extracted during such period, calculated on a units-of-production basis. Estimates of proved developed producing reserves volumes are a major component in the calculation of depletion.

Accretion Expense

Our predecessor’s accretion expense for the year ended December 31, 2017 was $0.4 million, an increase of $0.2 million from $0.2 million for the year ended December 31, 2016. Increases in accretion expense were attributable to an increase in well count from acquisitions.

Impairment of Oil, Natural Gas and Natural Gas Liquids Expense

Our predecessor utilizes the full cost method of accounting for our oil and natural gas properties. Under the full cost method, capitalized costs are subject to a ceiling test, which limits such pooled costs to the aggregate of the present value of future net revenues attributable to proved oil, natural gas and NGL reserves discounted at 10%, including the effects of income taxes. Our predecessor does not assign any value to unproved properties in which it holds a royalty interest. The full cost ceiling is evaluated at the end of each quarterly period and additionally when events indicate possible impairment. Our predecessor did not incur any impairment for the year ended December 31, 2017 as the present value of future net revenues attributed to proved oil, natural gas and NGL reserves exceeded the net book value of our predecessor’s proved properties. Impairments totaled $30.1 million for the year ended December 31, 2016 primarily due to due to changes in reserve values resulting from depressed commodity prices in 2016.

 

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General and Administrative Expense

Our predecessor’s general and administrative expenses for the year ended December 31, 2017 were $3.4 million, an increase of $1.7 million from $1.7 million for the year ended December 31, 2016. Increases in general and administrative expenses were attributable to the increased costs related to this offering, particularly related to significant staffing increases and third-party audit and engineering services.

Net Gain (Loss) on Derivative Instruments

Our predecessor incurred $5.1 million net gain on derivative instruments for the year ended December 31, 2017, an increase of $11.3 million from $6.3 million net loss on derivative instruments for the year ended December 31, 2016. Our predecessor had forward swap commodity contracts in 2016 and 2017, as well as collar commodity contracts on our predecessor’s oil, natural gas and natural gas liquids production. Increases in net gain on derivative instruments were primarily due to changes in commodity prices that were more favorable toward our predecessor’s derivative position in 2017.

Interest Expense

Our predecessor’s interest expense for the year ended December 31, 2017 was $5.3 million, an increase of $2.5 million from $2.8 million for the year ended December 31, 2016. Our predecessor entered into a term loan (the “Predecessor Term Loan”) and an amended credit agreement in May 2016 (the “Predecessor Credit Agreement”). The increase in interest expense is due to a higher interest rate on the Predecessor Term Loan and the Predecessor Credit Facility, which were outstanding for the entire year of 2017 as opposed to seven months outstanding in May 2016. Please read “—Liquidity and Capital Resources—Indebtedness.”

Other income (expense)

Our predecessor’s other income for the year ended December 31, 2017 was $1.5 million, an increase of $1.5 million from $0.0 million net loss for the year ended December 31, 2016. The increase in other income (expense) is due to a sale of certain acreage surface rights to an unrelated third party for a sale price of $1.5 million in April 2017.

Liquidity and Capital Resources

Overview

Following the completion of this offering, we expect our primary sources of liquidity will be cash flows from operations as well as equity and debt financings. Our primary uses of cash will be for paying dividends to our stockholders. Prior to this offering, we will enter into a new $         million secured revolving credit facility to initially be used for general company purposes, including working capital and certain offering expenses, as well as future acquisitions.

Our board of directors expects to adopt a written policy in which we intend to make a dividend of all of our cash on hand at the end of each quarter, less reserves established by our board of directors. We refer to this cash as “available cash.” Available cash for each quarter will be determined by our board of directors following the end of such quarter. We expect that available cash for each quarter will generally equal our Adjusted EBITDA for the quarter, less cash needed for debt service and other contractual obligations and fixed charges and reserves for future operating or capital needs, that the board of directors may determine is appropriate. We are a holding company and will have no material assets other than our equity interest in Remora Holdings and no independent means of generating revenue. To the extent Remora Holdings has available cash, we intend to cause Remora Holdings to make distributions to its unitholders, including us.

 

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Our available cash for each quarter, and thus our expected dividend payments to Class A common stockholders, will in turn depend on the amount of cash available for distribution by Remora Holdings each quarter and our ownership of RH Units relative to amount of RH Units owned by the Contributing Parties.

We do not currently intend to retain cash from our operations for capital expenditures necessary to replace our existing oil and natural gas reserves or otherwise maintain our asset base (replacement capital expenditures), primarily due to our expectation that the continued development of our properties by working interest owners will offset the natural production declines from our existing wells. Our board of directors may change our dividend policy and decide to withhold replacement capital expenditures from cash available to make dividend payments, which would reduce the amount of cash available to make dividend payments in the quarter(s) in which any such amounts are withheld. Over the long term, if our reserves are depleted and our operators become unable to maintain production on our existing properties and we have not been retaining cash for replacement capital expenditures, the amount of cash generated from our existing properties will decrease and we may have to reduce the amount of dividends payable to our stockholders. To the extent that we do not withhold replacement capital expenditures, a portion of our cash available to make dividend payments will represent a return of your capital.

It is our intent, subject to market conditions, to finance acquisitions of mineral and royalty interests that increase our asset base largely through external sources, such as borrowings under our secured revolving credit facility and the issuance of equity and debt securities, although our board of directors may choose to reserve a portion of cash generated from operations to finance such acquisitions as well. We do not currently intend to reserve cash for the purpose of maintaining stability or growth in our quarterly dividend or otherwise reserve cash for dividends, or to incur debt to pay quarterly dividends, and our board of directors may change this policy.

Because our board of directors expects to adopt a written policy in which we intend to make a dividend of all available cash we generate each quarter, our stockholders will have direct exposure to fluctuations in the amount of cash generated by our business. We expect that the amount of our quarterly dividends, if any, will fluctuate based on variations in, among other factors, (i) the performance of the operators of our properties, (ii) earnings caused by, among other things, fluctuations in the price of oil, natural gas and NGLs, changes to working capital or capital expenditures and (iii) cash reserves deemed appropriate by our board of directors. Such variations in the amount of our quarterly dividends may be significant and could result in our not making any dividend for any particular quarter. Our board of directors may change our dividend policy at any time at its discretion, without unitholder approval, and could elect not to pay dividends for one or more quarters.

Predecessor Cash Flows

The following table presents our predecessor’s cash flows for the period indicated.

 

     Three Months
Ended March 31,
     Years Ended
December 31,
 
     2018     2017      2017     2016  

Cash Flow Data:

         

Cash provided by operating activities

   $ 356,960     $ 1,510,260      $ 9,954,122     $ 2,102,807  

Cash provided by (used in) investing activities

     950,149       172,291        8,822,602       (40,583,418

Cash provided by (used in) financing activities

     (1,359,100     1,163,879        (17,518,999     33,728,402  
  

 

 

   

 

 

    

 

 

   

 

 

 

Net increase (decrease) in cash and cash equivalents

   $ (51,991   $ 2,846,430      $ 1,257,725     $ (4,752,209

 

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Operating Activities (Predecessor)

Our predecessor’s operating cash flow is impacted by many variables, the most significant of which is the change in prices for oil, natural gas and NGLs. Prices for these commodities are determined primarily by prevailing market conditions. Regional and worldwide economic activity, weather and other substantially variable factors influence market conditions for these products. These factors are beyond our and our predecessor’s control and are difficult to predict. The increases in cash flows provided by operating activities for the year ended December 31, 2017 as compared to the year ended December 31, 2016 of $7.9 million were largely attributable to higher oil, natural gas and NGL sales prices and an increase in production volume of 6.6 Bcfe year over year. The decreases in cash flows provided by operating activities for the three months ended March 31, 2018 as compared to the three months ended March 31, 2017 of $1.2 million were largely attributable to lower realized natural gas prices and a 0.5 Bcfe decrease in production volumes year over year primarily due to the sale of certain oil and natural gas properties in the third quarter of 2017, partially offset by higher realized oil and NGL prices.

Investing Activities (Predecessor)

The acquisition and sale of working interests as well as capital expenditures made on oil and natural gas properties accounted for our predecessor’s cash outlays for investing activities. For the three months ended March 31, 2018, cash provided by our investing activities was $1.0 million compared to $0.2 million for the three months ended March 31, 2017.

For the three months ended March 31, 2018, our predecessor received $1.0 million from investing activities, which was primarily due to $1.4 million divestiture of oil and natural gas properties, partially offset by $0.3 million of capital expenditures spent on capital workovers and $0.1 million purchase of equipment.

For the three months ended March 31, 2017, our predecessor received $0.2 million from investing activities, which was primarily due to $2.3 million in post-close adjustments received from certain properties purchased in the Midcontinent, partially offset by a $1.2 million acquisition of certain oil and natural gas properties and $0.9 million in capital workovers.

For the year ended December 31, 2017, our predecessor received $8.8 million from investing activities compared to $40.6 million used in investing activities for the year ended December 31, 2016. The $8.8 million cash received from investing activities for the year ended December 31, 2017 was primarily due to sales of oil and natural gas producing properties of $17.7 million, offset by $7.6 million cash used to acquire oil and natural gas producing properties and $1.3 million capital expenditures spent for oil and natural gas producing properties. The $40.6 million used in investing activities for the year ended December 31, 2016 was primarily due to $39.5 million cash used to acquire oil and natural gas producing properties and $1.1 million capitalized expenditures made on our predecessor’s oil and natural gas producing properties.

Financing Activities (Predecessor)

Cash used in financing activities was $1.4 million for the three months ended March 31, 2018 as compared to cash provided by financing activities of $1.2 million for the three months ended March 31, 2017. During the three months ended March 31, 2018, our predecessor repaid $1.4 million of long-term debt. Our predecessor borrowed $1.2 million in long-term debt in the three months ended March 31, 2017.

Cash used in financing activities was $17.5 million for the year ended December 31, 2017 as compared to cash received from financing activities of $33.7 million for the year ended December 31, 2016. During the year ended December 31, 2017, our predecessor repaid $27.8 million of debt, offset by proceeds

 

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borrowed of $10.3 million. During the year ended December 31, 2016, our predecessor borrowed $64.9 million and received $1 million contributions from partners, offset by $30.5 million in repayments of borrowing and $1.7 million debt issuance costs incurred in relation to our predecessor’s borrowing.

Capital Expenditures

During the three months ended March 31, 2018, our predecessor spent $0.4 million on capital workovers and equipment. During the three months ended March 31, 2017, our predecessor spent $0.9 million on capital workovers. During the year ended December 31, 2017, our predecessor incurred $1.3 million capital expenditures for our predecessor’s oil and natural gas producing properties. In addition, our predecessor spent $7.6 million in acquiring oil and natural gas properties and received $17.7 million from sale of oil and natural gas properties for the year ended December 31, 2017.

Indebtedness

Predecessor Credit Agreement

In May 2016, our predecessor entered the Predecessor Credit Agreement with BOK Financial Corporation with an aggregate commitment of $75,000,000 and an initial borrowing base of $23,000,000. The Predecessor Credit Agreement has a maturity date of May 27, 2020 and is secured by our predecessor’s oil and natural gas properties. There is a commitment fee of up to 0.50% on the unused availability, as defined in the credit agreement. Advances on the Predecessor Credit Agreement were $25,450,000 and $42,900,000 at December 31, 2017 and 2016, respectively. Advances bear interest at the bank’s alternate base rate plus an applicable margin from 0.75% to 1.75% depending on the utilization level as defined in the agreement or at the LIBOR plus an applicable margin from 2.00% to 3.00% depending on the utilization levels as defined in the agreement.

The Predecessor Credit Agreement provides for certain affirmative covenants and restrictions, including certain required financial ratios that require maintenance of a minimum ratio of working capital, a maximum ratio of indebtedness to earnings before interest, incomes taxes, depreciation and amortization and other non-cash charges (“EBITDAX”) and a minimum total adjusted leverage to PDP-10 asset coverage calculation. In December 2016, our predecessor entered into first amendment to the Predecessor Credit Agreement (the “First Amendment”). Under the First Amendment, advances bear interest at the bank’s alternate base rate plus an applicable margin from 1.75% to 2.75% depending on the utilization level as defined in the agreement or at the LIBOR plus an applicable margin from 2.75% to 3.75% depending on the utilization levels as defined in the agreement in exchange for an increased borrowing base. At December 31, 2017, the borrowing base was $45,000,000. As of December 31, 2017, our predecessor was in compliance with all of the required financial covenants.

In May 2016, our predecessor also entered into a second lien credit agreement with Goldman Sachs Specialty Lending Group, L.P. for an aggregate commitment of $25,000,000 and a maturity of November 27, 2020. The second lien facility bears interest at the bank’s base rate plus 10% to 11% depending on the utilization levels as defined in the agreement or at the LIBOR plus 11% to 12% depending on the utilization levels as defined in the agreement with a minimum LIBOR of 1.0%. At December 31, 2017, our predecessor had $25,000,000 in outstanding borrowings under this agreement. The financial covenants under this second lien credit agreement are identical to those of the first lien credit agreement, and our predecessor was in compliance with all of its financial covenants as of December 31, 2017.

For further information on our predecessor’s indebtedness, refer to Note 7 in the audited financial statements of our predecessor included elsewhere in this prospectus. We will assume $         million of our predecessor’s indebtedness in connection with the formation transactions, which will be fully repaid using the proceeds from the offering.

 

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New Revolving Credit Agreement

We expect to enter into a new $         million revolving credit facility, which at the closing of this offering will be secured by substantially all of our assets and the assets of our wholly owned subsidiaries. Under the secured revolving credit facility, availability under the facility will equal the lesser of the aggregate maximum commitments of the lenders and the borrowing base. The borrowing base will be determined based on the value of our oil and natural gas properties and the oil and natural gas properties of our wholly owned subsidiaries. We expect that the borrowing base will be redetermined on a semi-annual basis in          and          of each year and that our initial borrowing base will be $         million. The oil and natural gas properties of our non-wholly owned subsidiaries are not subject to a lien and will not be included in borrowing base valuations. The secured revolving credit facility permits aggregate commitments under the facility to be increased to $         million, subject to the satisfaction of certain conditions and the procurement of additional commitments from new or existing lenders.

The secured revolving credit facility will contain various affirmative, negative and financial maintenance covenants. These covenants limit our ability to, among other things, incur or guarantee additional debt, make dividend payments on, or redeem or repurchase, Class A common stock, make certain investments and acquisitions, incur certain liens or permit them to exist, enter into certain types of transactions with affiliates, merge or consolidate with another company and transfer, sell or otherwise dispose of assets. The secured revolving credit facility will also contain covenants requiring us to maintain the following financial ratios or to reduce our indebtedness if we are unable to comply with such ratios: (i) a Debt to EBITDAX Ratio (as more fully defined in the secured revolving credit facility) of not more than          to 1.0; and (ii) a ratio of current assets to current liabilities of not less than          to 1.0. The secured revolving credit facility also contains customary events of default, including non-payment, breach of covenants, materially incorrect representations, cross-default, bankruptcy and change of control.

We expect to borrow approximately $         million at the closing of this offering to fund certain offering expenses.

Predecessor Contractual Obligations

The following table summarizes the contractual obligations of our predecessor as of December 31, 2017:

 

     Total      Less than 1 year      1-3 years      3-5 years  

Long-term debt

   $ 49,186,099      $      $ 49,186,099      $  

Operating leases

     1,712,662        324,243        674,831        713,588  
  

 

 

    

 

 

    

 

 

    

 

 

 

Total

   $     50,898,761      $          324,243      $     49,860,930      $          713,588  

Internal Controls and Procedures

We are not currently required to comply with the SEC’s rules implementing Section 404 of the Sarbanes-Oxley Act, and are therefore not required to make a formal assessment of the effectiveness of our internal controls 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, 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 controls over financial reporting. We will not be required to make our first assessment of our internal controls over financial reporting until the year following our first annual report required to be filed with the SEC. To comply with the requirements of being a public company, we will need to implement additional financial and management controls, reporting systems and procedures and hire additional accounting, finance and legal staff.

 

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Further, our independent registered public accounting firm is not yet required to attest to the effectiveness of our internal controls over financial reporting, and will not be required to do so for as long as we are an “emerging growth company” pursuant to the provisions of the JOBS Act or as long as we are a non-accelerated filer. Please read “Summary—Emerging Growth Company Status” and “Risk Factors—Risks Inherent in an Investment in Us—For as long as we are an emerging growth company, we will not be required to comply with certain disclosure requirements that apply to other public companies.”

New and Revised Financial Accounting Standards

We qualify as an “emerging growth company” pursuant to the provisions of the JOBS Act, enacted on April 5, 2012. 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 for complying with new or revised accounting standards. We will be classified as an emerging growth company pursuant to the provisions of the JOBS Act and have elected to take advantage of all of the applicable JOBS Act provisions.

In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2014-09, Revenue from Contracts with Customers. This standard provides a five-step approach to be applied to all contracts with customers and requires expanded disclosures about the nature, amount, timing and uncertainty of revenue (and the related cash flows) arising from customer contracts, significant judgments and changes in judgments used in applying the revenue model and the assets recognized from costs incurred to obtain or fulfill a contract. The standard permits the use of either the retrospective or cumulative effect transition method, therefore we are evaluating the effect that this new guidance will have on its consolidated financial statements and related disclosures. In 2015, the FASB voted to defer the effective date of this standard, which now will not apply to us until 2019. Nonpublic entities reporting under US GAAP are permitted to apply the standard early; however, adoption can be no earlier than annual reporting periods beginning after December 15, 2016. We have not concluded on the impact of this accounting standard to our company. However, we have evaluated our contracts from customers and related revenue recognition policies and we do not believe the adoption of this standard will have a material impact on our financial statements.

In August 2014, the FASB issued ASU 2014-15, Presentation of Financial Statements — Going Concern (Subtopic 205-40): Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern. The amendments require management to assess an entity’s ability to continue as a going concern by incorporating and expanding upon certain principles that are currently in U.S. auditing standards. Specifically, the amendments (1) provide a definition of the term substantial doubt, (2) require an evaluation every reporting period including interim periods, (3) provide principles for considering the mitigating effect of management’s plans, (4) require certain disclosures when substantial doubt is alleviated as a result of consideration of management’s plans, (5) require an express statement and other disclosures when substantial doubt is not alleviated and (6) require an assessment for a period of one year after the date that the financial statements are issued (or available to be issued). The amendments in this Update are effective for the annual period ending after December 15, 2016, and for annual periods and interim periods thereafter. We adopted this accounting standard as of December 31, 2016.

In February 2016, the FASB issued ASU No. 2016-02, Leases (“ASU 2016-02”). ASU 2016- 02 requires that a lessee should recognize the assets and liabilities that arise from leases. All leases create an asset and a liability for the lessee in accordance with FASB Concepts Statement No. 6, Elements of Financial Statements. A lessee should recognize in the statement of financial position a liability to make lease payments (the lease liability) and a right-of-use asset representing its right to use the underlying asset for the lease term. When measuring assets and liabilities arising from a lease, a lessee should include

 

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payments to be made in optional periods only if the lessee is reasonably certain to exercise an option to extend the lease or not to exercise an option to terminate the lease. Similarly, optional payments to purchase the underlying asset should be included in the measurement of lease assets and lease liabilities only if the lessee is reasonably certain to exercise that purchase option. In addition, also consistent with the previous leases guidance, a lessee should exclude most variable lease payments in measuring lease assets and lease liabilities, other than those that depend on an index or a rate or are in substance fixed payments. For leases with a term of 12 months or less, a lessee is permitted to make an accounting policy election by class of underlying asset not to recognize lease assets and lease liabilities. If a lessee makes this election, it should recognize lease expense for such leases generally on a straight- line basis over the lease term. For nonpublic entities, the new standard is effective for annual reporting periods beginning after December 15, 2019, and interim periods within fiscal years beginning after December 15, 2020. We are currently evaluating the impact of this accounting standard.

In August 2016, the FASB issued ASU 2016-15, Classification of Certain Cash Receipts and Cash Payments, which addressees eight classification issues related to the statement of cash flows: debt prepayment or debt extinguishment costs, settlement of zero-coupon bonds, contingent consideration payments made after a business combination, proceeds from the settlement of insurance claims, proceeds from the settlement of corporate-owned life insurance policies, distributions received from equity method investees, beneficial interests in securitization transactions and separately identifiable cash flows and application of the predominance principle. ASU 2016-15 is effective for us for fiscal years beginning after December 15, 2018 and interim periods beginning after December 15, 2019. Early adoption is permitted. We are currently evaluating the impact of this accounting standard.

In January 2017, the FASB issued ASU 2017-01, Business Combinations, to clarify the definition of a business by adding guidance to assist entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of a business. This standard provides a screen to determine when a set is not a business. The screen requires that when substantially all of the fair value of the gross assets acquired (or disposed of) is concentrated in a single identifiable asset or group of similar identifiable assets, the set is not a business. If the screen is not met, this standard (1) requires that to be considered a business, a set must include, at a minimum, an input and a substantive process that together significantly contribute to the ability to create output and (2) removes the evaluation of whether a market participant could replace the missing elements. ASU 2017-01 is effective for us for fiscal years beginning after December 15, 2018 and interim periods beginning after December 15, 2019. We are currently evaluating the impact of this accounting standard.

Critical Accounting Policies

The discussion and analysis of our financial condition and results of operations are based upon the historical financial statements of our predecessor, which have been prepared in accordance with GAAP. Certain of our accounting policies involve judgments and uncertainties to such an extent that there is a reasonable likelihood that materially different amounts would have been reported under different conditions, or if different assumptions had been used. The following discussions of critical accounting estimates, including any related discussion of contingencies, address all important accounting areas where the nature of accounting estimates or assumptions could be material due to the levels of subjectivity and judgment necessary to account for highly uncertain matters or the susceptibility of such matters to change. Below, we have provided a discussion of the significant accounting policies of our predecessor. In addition, we have provided a discussion of significant accounting policies of Remora Royalties, Inc. that are not applicable to our predecessor, namely “Income Taxes” and “Stock-based compensation.”

 

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See the notes to our predecessor’s historical financial statements included elsewhere in this prospectus for additional information regarding these accounting policies.

Use of Estimates

Certain amounts included in or affecting our financial statements and related disclosures must be estimated by our management, requiring certain assumptions to be made with respect to values or conditions that cannot be known with certainty at the time the financial statements are prepared. These estimates and assumptions affect the amounts we report for assets and liabilities and our disclosure of contingent assets and liabilities at the date of the financial statements. Actual results could differ from those estimates.

We evaluate these estimates on an ongoing basis, using historical experience, consultation with experts and other methods we consider reasonable in the particular circumstances. Nevertheless, actual results may differ significantly from our estimates. Any effects on our business, financial position or results of operations resulting from revisions to these estimates are recorded in the period in which the facts that give rise to the revision become known. Significant items subject to such estimates and assumptions include our asset retirement obligations, estimates of proved oil and natural gas reserves and related present value estimates of future net cash flows therefrom, and the carrying value of oil and natural gas properties.

Method of Accounting for Oil and Natural Gas Properties

We account for oil, natural gas and natural gas liquids producing activities using the full cost method of accounting. Accordingly, all costs incurred in the acquisition, exploration and development of proved oil, natural gas and natural gas liquids properties, including the costs of abandoned properties, dry holes, geophysical costs and annual lease rentals are capitalized. Sales or other dispositions of oil, natural gas and natural gas liquids properties are accounted for as adjustments to capitalized costs, with no gain or loss recorded unless the ratio of cost to proved reserves would significantly change.

Depletion of evaluated oil, natural gas and natural gas liquids properties is computed on the units of production method, whereby capitalized costs plus estimated future development costs are amortized over total proved reserves.

The net book value of all capitalized oil and natural gas properties within a cost center, less related deferred income taxes, is subject to a full cost ceiling limitation which is calculated quarterly. Under the ceiling limitation, costs may not exceed an aggregate of the present value of future net revenues attributable to proved oil and natural gas reserves discounted at 10% using the simple average of the first day-of-the-month benchmark prices for the calendar year adjusted by price differentials, plus the lower of cost or market value of unproved properties included in the amortization base, plus the cost of unevaluated properties not included in the amortization base, less any associated tax effects (the “Ceiling”). Any excess of the net book value, less related deferred tax effects, over the Ceiling is written off as impairment expense. Impairment expense recorded in one period may not be reversed in a subsequent period even though higher oil and natural gas prices may have increased the Ceiling applicable to the subsequent period.

Costs associated with unevaluated properties are excluded from the full cost pool until we have made a determination as to the existence of proved reserves. We assess all items classified as unevaluated property on an annual basis for possible impairment. We assess properties on an individual basis or as a group if properties are individually insignificant. The assessment includes consideration of the following factors, among others: intent to drill; remaining lease term; geological and geophysical evaluations; drilling results and activity; the assignment of proved reserves; and the economic viability of development if proved reserves are assigned.

 

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During any period in which these factors indicate an impairment, the cumulative drilling costs incurred to date for such property and all or a portion of the associated leasehold costs are transferred to the full cost pool and are then subject to amortization.

Oil, Natural Gas and Natural Gas Liquids Reserve Quantities and Standardized Measure of Future Net Revenue

Our independent engineers prepare our estimates of oil, natural gas and natural gas liquids reserves and associated future net revenues annually. The SEC has defined proved reserves as the estimated quantities of oil and natural gas which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. The process of estimating oil, natural gas and natural gas liquids reserves is complex, requiring significant decisions in the evaluation of available geological, geophysical, engineering and economic data. The data for a given property may also change substantially over time as a result of numerous factors, including additional development activity, evolving production history and a continual reassessment of the viability of production under changing economic conditions. As a result, material revisions to existing reserve estimates occur from time to time. Although every reasonable effort is made to ensure that reserve estimates reported represent the most accurate assessments possible, the subjective decisions and variances in available data for various properties increase the likelihood of significant changes in these estimates. If such changes are material, they could significantly affect future amortization of capitalized costs and result in impairment of assets that may be material.

There are numerous uncertainties inherent in estimating quantities of proved oil, natural gas and natural gas liquids reserves. Oil, natural gas and natural gas liquids reserve engineering is a subjective process of estimating underground accumulations of oil, natural gas and natural gas liquids that cannot be precisely measured and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of drilling, testing and production subsequent to the date of the estimate may justify revision of such estimate. Accordingly, reserve estimates are often different from the quantities of oil, natural gas and natural gas liquids that are ultimately recovered.

Asset Retirement Obligations

We have significant obligations to remove tangible equipment and facilities associated with our oil and natural gas wells and our gathering systems, and to restore land at the end of oil and natural gas production operations. Our removal and restoration obligations are associated with plugging and abandoning wells and our gathering systems. Estimating the future restoration and removal costs is difficult and requires us to make estimates and judgments because most of the removal obligations are many years in the future and contracts and regulations often have vague descriptions of what constitutes removal. Asset removal technologies and costs are constantly changing, as are regulatory, political, environmental, safety and public relations considerations. Inherent in the present value calculations are numerous assumptions and judgments including the ultimate settlement amounts, inflation factors, credit adjusted discount rates, timing of settlements and changes in the legal, regulatory, environmental and political environments.

Revenues

Our predecessor uses the sales method of accounting for oil, natural gas and natural gas liquids revenues. Under this method, revenues are recognized based on actual volumes of oil and natural gas sold to purchasers. Our predecessor accrues revenue relating to sales volumes for which our predecessor has not yet received payment.

 

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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. Though we will be required to disclose material changes made to our internal controls and procedures on a quarterly basis, we will not be required to make our first annual assessment of our internal control over financial reporting pursuant to Section 404 until the year following our first annual report required to be filed with the SEC. We will not be required to have our independent registered public accounting firm attest to the effectiveness of our internal controls over financial reporting 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.

Income taxes

The provision for income taxes is determined using the asset and liability approach of accounting for income taxes. Under this approach, deferred income taxes reflect the net tax effects of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes and net operating loss and tax credit carryforwards. The amount of deferred taxes on these temporary differences is determined using the tax rates that are expected to apply to the period when the asset is realized or the liability is settled, as applicable, based on tax rates and laws in the respective tax jurisdiction enacted as of the balance sheet date.

The Company reviews its deferred tax assets for recoverability and establishes a valuation allowance based on projected future taxable income, applicable tax strategies and the expected timing of the reversals of existing temporary differences. A valuation allowance is provided when it is more likely than not (likelihood of greater than 50%) that some portion or all of the deferred tax assets will not be realized.

The Company recognizes the tax benefit from an uncertain tax position only if it is more likely than not that the tax position will be sustained upon examination by the taxing authorities based upon the technical merits of the position. If all or a portion of the unrecognized tax benefit is sustained upon examination by the taxing authorities, the tax benefit will be recognized as a reduction to the Company’s deferred tax liability and will affect the Company’s effective tax rate in the period it is recognized.

Stock-based compensation

Stock-based compensation expense is being recognized on restricted stock, restricted stock units, performance units and stock option awards that are expected to be settled in the Company’s Class A common stock (“Equity Awards”) in the Company’s consolidated financial statements on a straight line basis over the awards’ vesting periods based on their fair values on the dates of grant or modification, as applicable. Stock-based compensation awards generally vest over a period of three years. The amount of stock-based compensation expense recognized at any date is approximately equal to the ratable portion of the grant date value of the award that is vested at that date.

The Company utilizes (i) the Black-Scholes option pricing model to measure the fair value of stock options, (ii) the prior day’s closing stock price on the date of grant to measure the fair value of Equity Awards and Liability Awards, (iii) the closing stock price on the balance sheet date to measure the fair value of the vested portions of Liability Awards and (iv) the Monte Carlo simulation method to measure the fair value of performance unit awards.

 

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Derivatives

We account for our derivative activities under the provisions of Accounting Standard Codification 815, Derivatives and Hedging (“ASC 815”). ASC 815 establishes accounting and reporting that every derivative instrument be recorded on the balance sheet as either an asset or liability measured at fair value. When derivative contracts are available at terms (or prices) acceptable to us, we may hedge a portion of our forecasted oil, natural gas, and natural gas liquids production. Derivative contracts entered into by us have consisted of transactions in which we hedge the variability of cash flow related to a forecasted transaction. We elected to not designate any of our positions for hedge accounting. Accordingly, we record the net change in the mark-to-market valuation of these positions, as well as payments and receipts on settled contracts, in “Net gain (loss) on derivative contracts” on the consolidated statements of operations.

Inflation

Inflation in the United States has been relatively low in recent years and did not have a material impact on results of operations for the period from January 1, 2016 through March 31, 2018.

Off-Balance Sheet Arrangements

As of March 31, 2018, we did not have any off-balance sheet arrangements other than operating leases.

Quantitative and Qualitative Disclosure about Market Risk

Commodity Price Risk

Our major market risk exposure is in the pricing applicable to the oil, natural gas and NGL production of our operators. Realized pricing is primarily driven by the prevailing worldwide price for crude oil and spot market prices applicable to our natural gas production. Pricing for oil, natural gas and NGL production has been volatile and unpredictable for several years, and we expect this volatility to continue in the future. The prices that our operators receive for production depend on many factors outside of our or their control.

Credit Risk

As an owner of mineral and royalty interests, we have no control over the volumes or method of sale of oil, natural gas and NGLs produced and sold from the underlying properties. During the year ended December 31, 2017, three purchasers accounted for approximately 16%, 15% and 13% of our predecessor’s oil, natural gas and NGL revenues. During the three months ended March 31, 2018, one purchaser accounted for approximately 11% of our predecessor’s oil, natural gas and NGL revenues. It is believed that the loss of any single purchaser would not have a material adverse effect on our results of operations as there are additional purchasers to whom the operators of our underlying properties could sell oil, natural gas and NGLs.

Interest Rate Risk

We will have exposure to changes in interest rates on our indebtedness. As of March 31, 2018, our predecessor had total borrowings outstanding under the Predecessor Credit Agreement and Predecessor Term Loan of $48.0 million, net of debt issuance costs. The impact of a 1% increase in the interest rate on this amount of debt would result in an increase in interest expense of approximately $0.5 million annually, assuming that our indebtedness remained constant throughout the year. We do not currently have any interest rate hedges in place.

 

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BUSINESS

Overview

We are a growth-oriented Delaware corporation formed to own and acquire overriding royalty, mineral and royalty interests in oil and natural gas properties. We refer to these non-cost-bearing interests which entitle us to a portion of the revenues received from the production of oil, natural gas and associated NGLs from the acreage underlying our interests, net of post-production expenses and taxes collectively as our “royalty interests.” Our royalty interests are located in 12 states and in 13 major onshore basins across the continental United States and include ownership in approximately 3,600 gross producing wells, predominantly in the Midcontinent, South Texas/Gulf Coast, East Texas/North Louisiana and Permian Basin, which are among the most historically prolific oil and natural gas regions in the United States. The geographic breadth of our assets gives us exposure to potential production and reserves from new and existing plays.

As an owner of royalty interests, we benefit from the continued development of the properties in which we own an interest without the need for investment of additional capital by us. We are not obligated to fund drilling and completion costs, lease operating expenses, plugging and abandonment costs at the end of a well’s productive life, or any environmental liability costs. Our primary business objective is to provide increasing dividends to stockholders resulting from acquisitions and from organic growth through the continued development of the properties in which we own an interest.

As of December 31, 2017, and on a pro forma basis, we owned royalty interests in approximately 593,000 gross acres (43,000 net acres), of which over 97% was held by production. For the year ended December 31, 2017, on a pro forma basis, approximately 75% of the net production underlying our royalty interests was from the Midcontinent, South Texas/Gulf Coast, East Texas/North Louisiana and Permian Basin. For the same period, the Contributing Parties operated approximately 46% of our net production, 788 of our gross wells and approximately 57% of our net acreage. The Contributing Parties, which includes our largest operator by proved reserves, Remora Petroleum, L.P. (our Operating Affiliate), were formed in part to acquire and develop mature oil and natural gas properties. We expect further development on our acreage by the Contributing Parties and other working interest owners through recompletions, infill drilling, horizontal drilling, hydraulic fracturing and secondary and tertiary recovery methods.

We believe our Operating Affiliate’s significant ownership interest in us will incentivize it to sell us additional royalty interests at attractive prices from its current and future inventory of properties. We also believe our Operating Affiliate, through its continued ownership in the working interests of the underlying properties and significant ownership interest in us, will be further incentivized to pursue the development of its current and future properties that would benefit us directly through increased production. Our Operating Affiliate operated 541 of our wells as of December 31, 2017 and approximately 29% of our net production during 2017. Additionally, our Operating Affiliate operates 85% of our PDNP reserves. Our Operating Affiliate was formed in 2011 by its management team and affiliates of NGP, a family of energy-focused private equity investment funds. Our Operating Affiliate is currently focused on the acquisition, development and exploitation of both conventional and unconventional oil and natural gas reserves in multiple onshore U.S. basins. Since inception, our Operating Affiliate has evaluated over 250 acquisition candidates, and has completed 43 property acquisitions and expects to continue acquiring properties for the benefit of itself and the Company. Our Operating Affiliate targets assets with a decline profile indicative of mature wells. We believe, based on publicly available data, that, as of December 31, 2017, there was production of approximately 34 Bcfe/d from wells in the lower 48 states that meet the decline profile targeted by our Operating Affiliate. We believe that operators are motivated to sell these mature and undervalued assets. As of December 31, 2017, on a pro forma basis, our Operating Affiliate owned approximately 123,000 net acres (97% held by production). For the year ended December 31, 2017, and on

 

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a pro forma basis, our Operating Affiliate had net production of 31.3 MMcfe/d and estimated proved reserves of 206 Bcfe (57.0% proved developed), according to Cawley, our independent petroleum engineering firm.

As of December 31, 2017, on a pro forma basis, the estimated proved oil, natural gas and NGL reserves attributable to our interests in our underlying acreage were 107.8 Bcfe (22.3% liquids, consisting of 12.3% oil and 10.0% NGLs) based on the reserve report prepared by Cawley. Of these reserves, 84.8% were classified as PDP reserves, 6.1% were classified as PDNP reserves and 9.1% were classified as PUD reserves. Our PDNP reserves included in this estimate are derived from 57 recompletion and workover projects, primarily located in the South Texas/Gulf Coast and East Texas/North Louisiana regions. Our PUD reserves included in this estimate are from 173 gross PUD locations, primarily located in the Arkoma STACK play. Additionally, the estimated probable oil, natural gas and NGL reserves attributable to our interests in our underlying acreage were 30.8 Bcfe (29.8% liquids), derived from 29 recompletion opportunities and 412 gross undeveloped locations. The producing properties underlying our royalty interests typically have low estimated decline rates. Our PDP reserves have an average estimated initial five-year decline rate of approximately 9.9%. For the year ended December 31, 2017, our average daily net production was 26.2 MMcfe/d.

For the year ended December 31, 2017, on a pro forma basis, our revenues were derived     % from oil sales,     % from natural gas sales and     % from NGL sales. Our revenues are derived from royalty payments we receive from the Contributing Parties and other operators of our properties based on the sale of oil and natural gas production, as well as the sale of NGLs that are extracted from natural gas during processing. As of December 31, 2017, on a pro forma basis, we had over 250 operators on our acreage, with the Contributing Parties operating approximately 46% of our net production during 2017. Our top five operators are our Operating Affiliate, AVAD Energy Partners, LP, Linn Energy LLC, SK Plymouth, LLC and Exco Operating Company, LP, and together account for approximately 66% of our net production during 2017. We have acreage in counties where there were 16 rigs operating and approximately 500 active permits as of April 2018.

We believe that one of our key strengths is our management team’s extensive experience in acquiring and managing mature oil and natural gas properties. Our management team and board of directors, which includes our founders George B. Peyton V and Grant W. Livesay, have a long history of creating value. We expect that our management team’s extensive experience in acquiring and integrating oil and natural gas properties will allow us to efficiently integrate significant acquisitions into our existing organizational structure. Furthermore, we expect the Contributing Parties to operate a significant portion of our future production and undeveloped reserves. In connection with this offering, we will enter into a management services agreement with our Operating Affiliate, pursuant to which it will identify, evaluate and recommend to us acquisition opportunities and negotiate the terms of such acquisitions. Please read “Certain Relationships and Related Party Transactions—Agreements and Transactions with Affiliates in Connection with this Offering—Management Services Agreement.”

Upon completion of this offering, the Contributing Parties will own              shares of our Class B common stock representing 100% of our outstanding Class B common stock and              RH Units representing a     % interest in Remora Holdings. Each share of Class B common stock has no economic rights but entitles its holder to one vote on all matters to be voted on by shareholders generally. The Contributing Parties expect to retain a diverse portfolio of oil and natural gas properties with production and reserve characteristics similar to the assets we will own at the closing of this offering. In connection with this offering and pursuant to the contribution agreement that we will enter into with the Contributing Parties, certain of the Contributing Parties will grant us a right of first offer for a period of three years after the closing of this offering with respect to certain oil and natural gas properties in their portfolio, including

 

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properties located in the Permian, Anadarko, Arkoma, Appalachia, Uinta and Williston Basins. These oil and natural gas interests, many of which overlap with our royalty interests include ownership in approximately 5,000 gross producing wells and approximately 600,000 gross acres across major producing basins in the United States. We believe the Contributing Parties will be incentivized through their continued ownership in the working interests in the underlying properties and ownership of our Class B common stock and RH Units to (i) offer us the opportunity to acquire additional royalty interests from them in the future and (ii) develop and grow production on the properties in which we own interests. Such Contributing Parties, however, have no obligation to sell any assets to us or to accept any offer that we may make for such assets, and we may decide not to acquire such assets even if such Contributing Parties offer them to us. Please read “Certain Relationships and Related Party Transactions—Remora Holdings LLC Agreement.”

Our Assets

We categorize our assets into two groups: overriding royalty interests and mineral interests.

Overriding Royalty Interests

We primarily own overriding royalty interests, which are royalty interests that burden the working interests of a lease and represent the right to receive a fixed, cost-free percentage of production or revenue from production from a lease for as long as the lease is effective. Overriding royalty interests typically remain in effect until the associated lease expires, and because substantially all of the underlying leases are perpetual so long as production in paying quantities perpetuates the leasehold, substantially all of our overriding royalty interests are likewise perpetual as long as production continues. Overriding royalty interests generate over 95% of our revenue and are also the assets over which our Operating Affiliate will have the most influence. The Contributing Parties operated approximately 46% of the net production associated with these interests for the year ended December 31, 2017. Approximately 97% of our overriding royalty interests are held by production.

Mineral Interests

In addition to overriding royalty interests, we also own mineral interests, which are real property interests that are typically perpetual and grant ownership to all of the oil and natural gas lying below the surface of the property, as well as the right to explore, drill and produce oil and natural gas on that property or to lease such rights to a third party. Mineral owners typically grant oil and natural gas leases to operators for an initial three-year term with an upfront cash payment to the mineral owners known as a lease bonus. Once a well is producing, the mineral owner retains a royalty interest entitling it to a cost-free percentage of production or revenue from production. When production or drilling ceases on the leased property, the lease is terminated, subject to certain exceptions, and all mineral rights revert back to the mineral owner who can then lease the exploration and development rights to another party. We also own royalty interests that have been carved out of mineral interests and are known as nonparticipating royalty interests. Nonparticipating royalty interests are typically perpetual and have rights similar to mineral interests, including the right to a cost-free percentage of production revenues for minerals extracted from the acreage, without the associated executive right to lease and the right to receive lease bonuses.

We combine our mineral and nonparticipating royalty assets into one category because they share many of the same characteristics due to the nature of the underlying interest. For example, we receive similar royalties from operators with respect to our mineral interests and nonparticipating royalty interests as long as such interests are subject to an oil and natural gas lease. As of December 31, 2017, on a pro forma basis, approximately 73% of the acreage subject to our mineral and nonparticipating royalty interests was leased. Less than 5% of our revenue for the year ended December 31, 2017, on a pro forma basis, was

 

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generated from such interests. When evaluating our business, our management team does not distinguish between mineral and nonparticipating royalty interests on leased acreage due to the similarity of the royalties received in respect to each.

Production

The following charts provide information regarding the production of oil, natural gas and NGLs for the properties underlying our royalty interests on a pro forma basis for the year ended December 31, 2017.

 

 

LOGO

   LOGO

 

(1)   “Btu-equivalent” production volumes are presented on a “natural gas-equivalent” basis using a conversion factor of six Mcf of natural gas per barrel of oil which is based on approximate energy equivalency and does not reflect the price or value relationship between oil and natural gas.

 

(2)   “Value-equivalent” production volumes are presented on a “natural gas-equivalent” basis using a conversion factor of 20 Mcf of natural gas per barrel of oil which is the conversion factor we use in our business. For a discussion of the 20-to-1 conversion factor, please read footnote three to the Royalty Interests table under “—Key Producing Regions—Royalty Interests.”

Key Producing Regions

The following tables present information about our royalty interest acreage, production and well count by basin. We may own more than one type of interest in the same tract of land. Consequently, some of the acreage shown for one type of interest below may also be included in the acreage shown for another type of interest.

 

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Royalty Interests

The following table sets forth information about the properties underlying our royalty interests on a pro forma basis as of and for the year ended December 31, 2017:

 

     As of December 31, 2017     Average Daily Production
For the Year Ended December 31,
2017 (Mcfe/d)
 

Basin or Producing Region

   Gross Acres      Net Acres      Percent HBP     6:1(2)      20:1(3)  

Midcontinent

     260,184        11,020        89     8,400        15,286  

South Texas / Gulf Coast

     72,486        19,732        100     6,443        9,889  

East Texas / North Louisiana

     63,516        2,331        100     4,366        4,759  

Permian Basin

     9,903        1,331        100     506        1,585  

Other(1)

     187,108        8,616        100     6,455        8,337  
  

 

 

    

 

 

    

 

 

   

 

 

    

 

 

 

Total

     593,197        43,030        97     26,170        39,856  
  

 

 

    

 

 

    

 

 

   

 

 

    

 

 

 

 

(1)   “Other” producing regions include multiple producing basins or plays across the United States, including the DJ Basin, San Juan Basin, Black Warrior Basin, Uinta Basin, onshore California and the western Gulf Coast (onshore) Basin.

 

(2)   “Btu-equivalent” production volumes are presented on a “natural gas-equivalent” basis using a conversion factor of six Mcf of natural gas per barrel of oil, which is based on approximate energy equivalency and does not reflect the price or value relationship between oil and natural gas.

 

(3)   “Value-equivalent” production volumes are presented on a “natural gas-equivalent” basis using a conversion factor of 20 Mcf of natural gas per barrel of oil, which is the conversion factor we use in our business. We are providing this measure supplementally because we believe this conversion factor represents an estimation of value equivalence over time and better correlates with the respective contribution of natural gas and oil to our revenues. We use the 20-to-1 conversion factor as we assess our business, including analysis of our financial and production performance, strategic decisions to purchase additional properties and budgeting. We do not adjust the 20-to-1 ratio to reflect current pricing, because the significant volatility in the conversion ratio makes it difficult for us to compare results across periods. By reviewing our aggregate production on a constant 20-to-1 basis, which removes the variability of price fluctuations but generally approximates price equivalence over recent periods, we are able to compare production data from period to period as well as the relative contribution of natural gas and oil to our revenues. The 20-to-1 conversion factor approximates the mean ratio of the average monthly price of WTI oil to the average monthly price of Henry Hub natural gas from January 1, 2008 to December 31, 2017, as reported by the EIA. During this period, the ratio of the price of oil to the price of natural gas ranged from 53.0-to-1 to 7.1-to-1. The mean ratios of the price of oil to the price of natural gas were 17.1-to-1 and 17.6-to-1 for the years ended December 31, 2017 and December 31, 2016, respectively. Due to the variability of the prices of natural gas and oil, there is no standard conversion ratio for value equivalence, and the 20-to-1 ratio presented here may not accurately reflect the ratio of oil prices to natural gas prices for a given period.

 

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Wells

The following table sets forth information about the wells in which we have a royalty interest as of December 31, 2017, on a pro forma basis:

 

Basin or Producing Region

   Well Count  

Midcontinent

     1,949  

South Texas / Gulf Coast

     222  

East Texas / North Louisiana

     592  

Permian Basin

     28  

Other(1)

     819  
  

 

 

 

Total

     3,610  
  

 

 

 

 

(1)   “Other” producing regions include multiple producing basins or plays across the United States, including the DJ Basin, San Juan Basin, Black Warrior Basin, Uinta Basin, onshore California and the western Gulf Coast (onshore) Basin.

Material Basins and Producing Regions

The following is an overview of the U.S. basins and producing regions we consider most material to our current and future business.

 

    Midcontinent. The Midcontinent is a broad area containing hundreds of fields in Arkansas, Kansas, New Mexico, Oklahoma, Nebraska and Texas, and includes the Granite Wash, Cleveland, Woodford, Meramec, Osage and Mississippi Lime formations, among many others. The Anadarko and Arkoma Basins within the Midcontinent are among the most prolific and largest onshore producing oil and natural gas basins in the United States, having multiple producing horizons and extensive well control demonstrated over seven decades of development. The Anadarko Basin is a structural basin centered in the western part of Oklahoma and the Texas Panhandle, extending into southwestern Kansas and southeastern Colorado. Our interests contain diversified exposure to the STACK, Woodford, Mississippi Lime, Granite Wash, Hunton and other liquids-rich plays across the Anadarko Basin. As of April 2018, there were 12 active rigs and approximately 370 active permits in the counties in which we own royalty interests. The Arkoma Basin is a structural basin that spans across west-central Arkansas into southeastern Oklahoma along the northern side of the Ouachita orogenic belt. A significant portion of our Midcontinent acreage lies in the Arkoma STACK play, which is primarily targeting the liquids-rich Woodford formation and secondarily targeting the Mayes shale and Caney shale formations. As of December 31, 2017, the number of active rigs increased by 100% and permitting activity increased approximately 53% compared to the prior year on and around our Arkoma Basin acreage, which is operated by multiple high-quality operators. Also, included in the Midcontinent region are our royalty interests in approximately 165 gross long-lived conventional oil wells located in the western Fort Worth Basin. These properties are operated by our Operating Affiliate and produce primarily from the Canyon, Caddo, Marble Falls, Duffer and Ellenburger formations.

 

   

South Texas/Gulf Coast. Our South Texas/Gulf Coast interests are diversified across 222 gross wells located in 22 counties and are primarily producing from prolific, long-lived natural gas-weighted reservoirs including the Wilcox, Vicksburg, Frio and Edwards Lime. Approximately 80.0% of our 18.0 Bcfe total proved reserves in South Texas/Gulf Coast are operated by our Operating Affiliate, which has identified 32 recompletion cases and more than 100 additional workover/reactivation opportunities across our acreage position. We believe the South Texas/Gulf

 

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Coast region represents an attractive opportunity for further consolidation of predictable, conventional oil and natural gas properties producing from high-quality reservoirs with substantial geologic support of in-place hydrocarbons.

 

    East Texas/North Louisiana. Our East Texas/North Louisiana interests are primarily located in Desoto, Bienville, Webster and Jackson Parishes in Louisiana and Rusk County, Texas, as well as eight additional counties and parishes. Our Operating Affiliate operates approximately 153 wells, representing 52.0% of our 15.7 Bcfe total proved reserves in East Texas/North Louisiana and primarily producing from the Hosston, Cotton Valley and Haynesville formations. Beyond our PDP reserves, we believe our interests in this area contain longer-term upside potential in a higher gas price environment, particularly in the Lower Cotton Valley, Haynesville and Bossier plays across the region.

 

    Permian Basin. The Permian Basin extends from southeastern New Mexico into west Texas and is currently one of the most active drilling regions in the United States. It includes three geologic provinces: the Midland Basin to the east, the Delaware Basin to the west and the Central Basin Platform in between. The Permian Basin consists of mature legacy onshore oil and liquids-rich natural gas reservoirs and has been actively drilled over the past 90 years. The extensive operating history, favorable operating environment, mature infrastructure, long reserve life, multiple producing horizons, horizontal development potential and liquids-rich reserves make the Permian Basin one of the most prolific oil-producing regions in the United States. Our proved reserves in the Permian Basin are primarily located in Crockett County, Texas and are operated by one of the Contributing Parties. There are a number of uphole redevelopment projects, including eight Wolfcamp recompletions, that such Contributing Party intends to pursue in the near future, which we believe will directly benefit our royalty interests.

 

    Other. Our other assets consist of interests in 819 gross wells and are located in multiple other producing basins across the United States, including the DJ Basin, San Juan Basin, Black Warrior Basin, Uinta Basin, onshore California and the western Gulf Coast (onshore) Basin.

Our Relationship with our Operating Affiliate

Our Operating Affiliate is a privately-held Texas limited partnership focused on the acquisition, development and exploitation of both conventional and unconventional oil and natural gas reserves in multiple onshore US basins. Our Operating Affiliate was formed in 2011 by its management team and affiliates of NGP.

As of December 31, 2017, on a pro forma basis, our Operating Affiliate owned approximately 123,000 net acres (97% held by production). For the year ended December 31, 2017, on a pro forma basis, our Operating Affiliate had net production of 31.3 MMcfe/d and estimated proved reserves of 206 Bcfe (57.0% proved developed), according to Cawley. Our Operating Affiliate expects to enter into hedging contracts covering approximately 75% of its estimated proved developed production for at least three years following this offering.

We believe our Operating Affiliate, through its ownership of our Class B common stock and RH Units, will be incentivized to sell us additional royalty interests from its existing inventory of properties in the future as they become mature, though it will have no obligation to do so following this offering. Furthermore, our Operating Affiliate has the ability to own operated and non-operated properties, and, although our Operating Affiliate is not limited in its ability to compete against us, we expect it to pursue acquisitions of such properties with the intention of creating additional royalty interests for us to acquire. Finally, our Operating Affiliate can pursue development of current and future properties that would benefit us directly through increased production, and would likewise benefit our Operating Affiliate through its

 

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continued ownership in the working interests of the underlying properties and ownership of our Class B common stock and RH Units.

We expect our Operating Affiliate to reinvest a substantial portion of the dividends it receives from us in the development of its properties. For example, on our royalty acreage, our Operating Affiliate has a portfolio of 57 PDNP recompletion projects (75% operated) to grow production, with the top 20 identified near term operated projects having an anticipated payback period of less than two years. Our Operating Affiliate also has an additional 29 probable recompletion projects (100% operated) in its portfolio and over 100 additional operated reactivation candidates, which could restore production in inactive wells for minimal costs. Additionally, our Operating Affiliate has advised us that it has identified a multi-year inventory of 173 gross PUD locations (99% non-operated) on acreage where we own royalty interests, primarily located in the Arkoma STACK play. Further, our Operating Affiliate has identified an additional 412 gross horizontal drilling locations (99% non-operated) included in our probable reserve estimates. We believe our Operating Affiliate’s current recompletion/workover, PUD and probable locations and reactivation projects are capable of growing the production from the acreage underlying our interests through December 2021 without acquiring incremental reserves.

Business Strategies

Our primary business objective is to provide increasing dividends to stockholders resulting from acquisitions from the Contributing Parties and third parties and from organic growth through the continued development by the Contributing Parties and other working interest owners of the properties in which we own an interest. We intend to accomplish this objective by executing the following strategies:

 

    Acquire additional royalty interests from the Contributing Parties. Following the completion of this offering, certain of the Contributing Parties will continue to own significant interests in mature producing oil and natural gas properties, as well as undeveloped acreage that we expect the Contributing Parties will drill and convert to production in the near future. We believe certain of the Contributing Parties view the Company as a key part of their growth strategy. In addition, we believe their ownership in us will incentivize them to offer us additional royalty interests from their existing asset portfolios in the future. In connection with this offering and pursuant to the contribution agreement that we will enter into with the Contributing Parties, certain of the Contributing Parties will grant us a right of first offer for a period of three years after the closing of this offering with respect to certain oil and natural gas properties in their portfolio, including properties located in the Permian, Anadarko, Arkoma, Appalachia, Uinta and Williston Basins. These oil and natural gas interests subject to such right of first offer include ownership in approximately 5,000 gross producing wells and approximately 600,000 gross acres across the major producing basins in the United States. Such Contributing Parties, however, have no obligation to sell any assets to us or to accept any offer that we may make for such assets, and we may decide not to acquire such assets even if such Contributing Parties offer them to us.

 

   

Participate with our Operating Affiliate in third-party acquisitions. Our Operating Affiliate, as well as the other Contributing Parties, were formed in part to acquire and develop mature oil and natural gas properties. Some of these properties will meet our acquisition criteria, which include (i) a sufficient, stable current production profile to create near-term accretion for our stockholders, (ii) significant amounts of recoverable oil and natural gas in place with geologic support for future production and reserve growth, (iii) a geographic footprint complementary to our diverse portfolio and (iv) targeted acreage positions in resource and conventional plays that maximize our potential for reserve and production upside. More specifically, through our relationship with our Operating Affiliate, we expect to acquire royalty interests in mature properties concurrently with our Operating

 

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Affiliate’s acquisition of such property, although our Operating Affiliate is under no obligation to include us in any acquisitions it makes. Through this participation with our Operating Affiliate in acquisitions, we expect to significantly increase the size and scope of potential acquisition targets available to us. Through our relationships with the Contributing Parties, we have access to each of their management teams and industry networks, which we believe provide us with a competitive advantage in pursuing potential third-party acquisitions. Further, we may have opportunities to work together with certain of the Contributing Parties to acquire properties that may not otherwise be attractive candidates for us or the Contributing Party individually.

Our Operating Affiliate and its affiliates have significant experience in identifying, evaluating and completing strategic acquisitions of mature producing oil and natural gas properties. In connection with the closing of this offering, we will enter into a management services agreement with our Operating Affiliate pursuant to which it will identify, evaluate and recommend to us acquisition opportunities and negotiate the terms of such acquisitions. We believe that these individuals’ knowledge of the oil and natural gas industry, relationships within the industry and experience in identifying, evaluating and completing acquisitions will provide us opportunities to grow through strategic and accretive acquisitions that complement or expand our asset portfolio.

 

    Benefit from reserve, production and cash flow growth through organic production growth and development of our royalty interests to grow dividends. Our initial assets consist of diversified royalty interests. Over the long term, we expect working interest owners will continue to develop our acreage through recompletions, infill drilling, horizontal drilling, hydraulic fracturing and secondary and tertiary recovery methods. As an owner of royalty interests, we are entitled to a portion of the revenues received from the production of oil, natural gas and associated NGLs from the acreage underlying our interests, net of post-production expenses and taxes. We are not obligated to fund drilling and completion costs, lease operating expenses or plugging and abandonment costs at the end of a well’s productive life. As such, we benefit from the continued development of the properties we own a royalty interest in without the need for investment of additional capital by us, which we expect to increase our dividends over time. For the year ended December 31, 2017, approximately 46% of our net production was operated by the Contributing Parties, who have advised us that they have identified a multi-year inventory of recompletion projects and drilling locations on our acreage. We believe the Contributing Parties will be incentivized through their ownership of Class B common stock and RH Units to develop and grow production on the properties in which we own interests.

 

    Maintain a conservative capital structure and prudently manage our business for the long term. We are committed to maintaining a conservative capital structure that will afford us the financial flexibility to execute our business strategies on an ongoing basis. Though not required pursuant to our certificate of incorporation or bylaws, our board of directors intends to adopt a written policy whereby we limit our incurrence of borrowings up to 2.5 times our debt to Adjusted EBITDA ratio for the preceding four quarters. Additionally, we expect to maintain a conservative hedging strategy. Our strategy includes entering into commodity derivative contracts covering approximately 20% to 30% of our estimated production from total PDP reserves underlying our royalty interests for at least two years, although we may increase this percentage if debt levels rise as a result of acquisitions.

 

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Competitive Strengths

We believe that the following competitive strengths will allow us to successfully execute our business strategies and achieve our primary business objective:

 

    Significant diversified portfolio of royalty interests in mature producing basins and exposure to undeveloped opportunities. We have a diversified, low decline asset base with exposure to high-quality conventional and unconventional plays. As of December 31, 2017, we owned royalty interests in approximately 593,000 gross acres and approximately 43,000 net acres, of which approximately 57% is operated by the Contributing Parties. As of December 31, 2017, over 97% of the acreage subject to our royalty interests were held by production. The geographic breadth of our assets gives us exposure to potential production and reserves from new and existing plays without further required investment on our behalf. We believe that we will continue to benefit from these cost-free additions to production and reserves for the foreseeable future as a result of technological advances and continuing interest by the Contributing Parties and third-party producers in development activities on our acreage.

 

    The Contributing Parties have significant operational control over our properties. At the completion of this offering and on a pro forma basis, the Contributing Parties will operate approximately 46% of our 2017 net production, 50% of our total proved reserves and approximately 57% of our net acreage. The Contributing Parties operate approximately 98% of our PDNP reserves and have advised us they intend to develop such reserves in the near future. Given the Contributing Parties will own 100% of our Class B common stock,              RH Units representing a     % interest in Remora Holdings, and will have continued ownership in the working interests in the underlying properties, we believe they are strongly incentivized to maximize production and development of the properties underlying our royalty interests. Further, we believe we have greater visibility into the Contributing Parties’ multi-year development programs than we would otherwise have with an unaffiliated third-party operator.

 

    Ability to acquire additional royalty interests from the Contributing Parties. We believe our relationship with the Contributing Parties will provide us with opportunities to acquire additional royalties at attractive valuations. Following the completion of this offering, the Contributing Parties will continue to own significant interests in mature producing oil and natural gas properties, as well as undeveloped acreage that we expect them to develop and convert to production in the near future. We believe the Contributing Parties view the Company as a key part of their growth strategy and that their ownership in us will incentivize them to offer us additional royalty interests from their asset portfolios over time.

 

    Exposure to leading plays in the United States, particularly in the Midcontinent region. We expect the operators of our properties to continue to drill new wells on our acreage, which we believe should more than offset the natural production declines from our existing wells through the year ending December 31, 2021. We believe that our operators have significant drilling inventory remaining on the acreage underlying our royalty interests in multiple plays. Our royalty interests are located in 12 states and in 13 major onshore basins across the continental United States and include ownership in approximately 3,600 gross producing wells, including over 1,900 wells in the Midcontinent. In the Midcontinent, and as of April 2018, there were 12 active rigs and approximately 370 active permits in the counties in which we own royalty interests. For the year ended December 31, 2017, approximately 75% of our net production was from the Midcontinent, South Texas/Gulf Coast, East Texas/North Louisiana and Permian Basin, which are among the most historically prolific oil and natural gas regions in the country.

 

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    Financial flexibility to fund expansion. We believe our conservative capital structure after this offering will permit us to maintain the financial flexibility to allow us to opportunistically purchase strategic royalty interests. We anticipate entering into a new $     million secured revolving credit facility. We expect to have a borrowing base under our secured revolving credit facility of $         million and to have $         million drawn at the closing of this offering.

 

    Experienced and proven management team with a track record of making acquisitions. The members of our management team and board of directors have a combined total of over 150 years of oil and natural gas experience. Our management team and board of directors, which includes our founders, have a long history of buying mature oil and natural gas properties in high-quality producing acreage throughout the United States. Since inception, our Operating Affiliate has evaluated over 250 acquisition candidates, and has completed 43 oil and natural gas property acquisitions and expects to continue acquiring properties for the benefit of itself and the Company.

Oil and Natural Gas Data

Proved and Probable Reserves

Evaluation and Review of Estimated Proved and Probable Reserves

Our reserve estimates as of December 31, 2017 were prepared by Cawley. Cawley is a third-party engineering firm and does not own an interest in any of our properties and is not employed by us on a contingent basis.

Within Cawley, the technical person primarily responsible for preparing the reserve estimates set forth in the reserve report incorporated herein is Mr. Todd Brooker. Mr. Brooker is the President of Cawley and has been practicing petroleum-engineering consulting at Cawley since 1992. Mr. Brooker is a registered Professional Engineer in the States of Texas. He earned a Bachelor of Science Degree in Petroleum Engineering from the University of Texas at Austin in 1989. As technical principal, Mr. Brooker 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 and is proficient in applying industry standard practices to engineering evaluations as well as in applying SEC and other industry reserves definitions and guidelines. A copy of Cawley’s estimated proved reserve report as of December 31, 2017 is attached as an exhibit to the registration statement of which this prospectus forms a part.

Our Vice President of Reservoir Engineering, Corwin Y. Ames, has agreed to provide us with reserve engineering services. Mr. Ames has managed all aspects of reservoir engineering and reserve preparation at our predecessor since 2014. Prior to joining our predecessor, he was a Petroleum Engineer with Lonquist & Co., LLC, a reservoir engineering consulting firm. Mr. Ames began his career at XTO Energy, Inc. as a Reservoir Engineer where he worked in numerous engineering capacities, including preparation of year-end SEC reserves with the company’s independent reserve engineers. Mr. Ames earned a Bachelor of Science degree in Petroleum Engineering from the University of Texas at Austin. Mr. Ames and certain engineers under his supervision worked closely with Cawley to ensure the integrity, accuracy and timeliness of the data used to calculate our proved reserves relating to our royalty interests. Mr. Ames met with Cawley periodically during the period covered by the reserve report to discuss the assumptions and methods used in the proved reserve estimation process. We provide historical information to Cawley for our properties such as ownership interest, oil and natural gas production, well test data, commodity prices and operating and development costs. Operating and development costs are not realized to our interest but are used to calculate the economic limit life of the wells. These costs are estimated and checked by Cawley.

 

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Following the completion of this offering, we anticipate that Mr. Ames will continue to be primarily responsible for the preparation of our reserves. In addition, we anticipate that the preparation of our proved reserve estimates are completed in accordance with internal control procedures, including the following:

 

    review and verification of historical production data, which data is based on actual production as reported by the operators of our properties;

 

    preparation of reserve estimates by Mr. Ames or under his direct supervision;

 

    review by Mr. Ames of all of our reported proved reserves at the close of each quarter, including the review of all significant reserve changes and all new proved undeveloped reserves additions;

 

    verification of property ownership by our land department; and

 

    no employee’s compensation is tied to the amount of reserves booked.

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 December 31, 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 three broad categories or methods: (1) performance-based methods, (2) volumetric-based methods and (3) analogy. These methods may be used singularly or in combination by the reserve evaluator in the process of estimating the quantities of reserves. The proved reserves for our properties were estimated by performance methods, analogy or a combination of both methods. All proved producing reserves attributable to producing wells were estimated by performance methods. These performance methods include, but may not be limited to, decline curve analysis, which utilized extrapolations of available historical production and pressure data. All proved developed non-producing and undeveloped reserves were estimated by the analogy method.

To estimate economically recoverable proved reserves and related future net cash flows, Cawley considered many factors and assumptions, including the use of reservoir parameters derived from geological, geophysical 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. To establish reasonable certainty with respect to our estimated proved reserves, the technologies and economic data used in the estimation of our proved reserves included production and well test data, downhole completion information, geologic data, electrical logs, radioactivity logs, core analyses, available seismic data and historical well cost and production cost data.

Estimates of probable reserves are inherently imprecise. 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 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. If deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated

 

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proved plus probable reserves. All of our probable reserves as of December 31, 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 three broad categories or methods: (1) performance-based methods, (2) volumetric-based methods and (3) analogy. These methods may be used singularly or in combination by the reserve evaluator in the process of estimating the quantities of reserves. In the case of probable reserves, the recoverable reserves cannot be said to have a “high degree of confidence that the quantities will be recovered”, but are “as likely as not to be recovered.” The lower degree of certainty can come from several factors including: (1) direct offset production that does not meet an economic threshold, despite localized averages that do meet that threshold, (2) an increased distance from offset production to the probable location of over 1 mile but under 3 miles, (3) a perceived risk of communication or depletion from nearby producers, (4) a perceived risk of attempting new drilling or completion technologies that have not been used in direct offset production or (5) an uncertainty regarding geologic positioning that could affect recoverable reserves. With respect to the probable reserves in this prospectus, 29 cases were considered Probable Developed and 412 cases were considered Probable Undeveloped. When considering the factors referenced above, the Probable Developed reserves’ lower degree of certainty came from a perceived risk of communication or depletion from nearby producing wells and an uncertainty regarding geologic positioning that could affect recoverable reserves. The Probable Undeveloped reserves’ lower degree of certainty came from an increased distance from offset production to the probable location of over one mile but under three miles, and a perceived risk of attempting new drilling or completion technologies that have not been used in direct offset production. 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.

 

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Summary of Estimated Proved and Probable Reserves

The following table presents our estimated proved and probable oil and natural gas reserves as of December 31, 2017 based on the reserve report prepared by Cawley of the assets to be contributed to us in connection with the formation transactions:

 

     As of
December 31, 2017(1)
 

Estimated proved developed reserves:

  

Oil (MBbls)

     2,100  

Natural gas (MMcf)

     76,805  

Natural gas liquids (MBbls)

     1,431  

Total (MMcfe)(6:1)(2)

     97,991  

Estimated proved undeveloped reserves:

  

Oil (MBbls)

     107  

Natural gas (MMcf)

     7,014  

Natural gas liquids (MBbls)

     362  

Total (MMcfe)(6:1)(2)

     9,828  

Estimated proved reserves:

  

Oil (MBbls)

     2,206  

Natural gas (MMcf)

     83,819  

Natural gas liquids (MBbls)

     1,793  

Total (MMcfe)(6:1)(2)

     107,813  

Percent proved developed

     91

Estimated probable developed reserves:

  

Oil (MBbls)

     192  

Natural gas (MMcf)

     6,362  

Natural gas liquids (MBbls)

     0  

Total (MMcfe)(2)

     7,514  

Estimated probable undeveloped reserves:

  

Oil (MBbls)

     274  

Natural gas (MMcf)

     15,242  

Natural gas liquids (MBbls)

     1,065  

Total (MMcfe)(2)

     23,276  

Estimated probable reserves:

  

Oil (MBbls)

     466  

Natural gas (MMcf)

     21,604  

Natural gas liquids (MBbls)

     1,065  

Total (MMcfe)(6:1)(2)

     30,790  

 

(1)   Estimates of reserves as of December 31, 2017 were prepared using an average price equal to the unweighted arithmetic average of hydrocarbon prices received on a field-by-field basis on the first day of each month within the year ended December 31, 2017, in accordance with SEC guidelines applicable to reserve estimates as of the end of such period. The unweighted arithmetic average first day of the month prices were $51.34 per Bbl for oil and $2,976 per MMBtu for natural gas at December 31, 2017. The price per Bbl for NGLs was modeled as a percentage of oil price, which was derived from historical accounting data. The reserve estimates do not include any value for possible reserves that may exist, nor do they include any value for undeveloped acreage. The reserve estimates represent our net revenue interest in our properties. Although we believe these estimates are reasonable, actual future production, cash flows, taxes, development expenditures, production costs and quantities of recoverable oil and natural gas reserves may vary substantially from these estimates.

 

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(2)   Estimated proved and probable reserves are presented on a “natural gas-equivalent” basis using a conversion of six Mcf per barrel of oil, which is the conversion factor we use in our business. This conversion is based on energy equivalence and not price or value equivalence. If a price equivalent conversion based on the twelve-month average prices for the year ended December 31, 2017 was used, the conversion factor would be approximately 17.1-to-1 Mcf per Bbl of oil. In this prospectus, we supplementally provide “value-equivalent” production information or volumes presented on a “natural gas-equivalent” basis using a conversion factor of 20 Mcf of natural gas per barrel of oil, which is the conversion factor we use in our business. For a discussion of the 20-to-1 conversion factor, please read footnote 3 to the Royalty Interests table under “Business—Key Producing Regions—Royalty Interests.”

The foregoing reserves are all located within the continental United States. 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.”

Additional information regarding our estimated proved reserves can be found in the reserve report as of December 31, 2017, which is included as an exhibit to the registration statement of which this prospectus forms a part.

Estimated Proved Undeveloped Reserves

As of December 31, 2016, we had no PUD reserves booked. As of December 31, 2017, our PUD reserves totaled 107 MBbls of oil, 7,014 MMcf of natural gas and 362 MBbls of NGLs, for a total of 9,826 MMcfe. PUD reserves will be converted from undeveloped to developed as the applicable wells begin production.

The following tables summarize our changes in PUD reserves during the year ended December 31, 2017 (in MMcfe):

 

     Proved Undeveloped Reserves(1)  

Balance, December 31, 2016

      

Acquisitions of reserves

     9,826  

Extensions and discoveries

      

Revisions and previous estimates

      

Transfers to estimated proved developed

      
  

 

 

 

Balance, December 31, 2017

     9,826  
  

 

 

 

 

(1)   “Btu-equivalent” production volumes are presented on a “natural gas-equivalent” basis using a conversion factor of six Mcf of natural gas per barrel of oil, which is based on approximate energy equivalency and does not reflect the price or value relationship between oil and natural gas. Please read “—Summary of Estimated Proved and Probable Reserves.”

Our PUD reserves as of December 31, 2017 were from 172 horizontal wells and one vertical well. As of December 31, 2017, all of our PUD drilling locations are scheduled to be drilled prior to December 31, 2022. As of December 31, 2017, approximately 6.1% of our total proved reserves were classified as PDNP.

Changes in PUDs that occurred from December 31, 2016 through December 31, 2017 were primarily due to the acquisition of an additional 9,826 MMcfe from our Operating Affiliate’s acquisitions on

 

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December 9, 2016 of oil and natural gas properties in Oklahoma (the “2016 Midcontinent Assets”) and our 2017 South Texas Assets.

In preparing our 2017 year-end reserve report, Cawley used industry standard assumptions and methodologies in assigning reserves and developing a drilling schedule for the 173 gross PUD locations in the report. Reserves and type-curves were developed using volumetrics, decline curve analysis and historical EURs to create PUD reserves that reasonably represent achievable results given the acreage location and modern drilling and completion technologies. PUD scheduling was based on operator and basin-specific rig activity as of December 31, 2017. All PUD locations are considered commercial and reasonable to develop within the five-year timeframe as set forth by the SEC.

Oil and Natural Gas Production Prices and Production Costs

Production and Price History

The following table sets forth information regarding production of oil and natural gas and certain price and cost information for each of the periods indicated:

 

    Remora Royalties, Inc.
Pro Forma(1)
    Remora Petroleum L.P.  
    Three Months
Ended March 31,
2018
    Year Ended
December 31,
2017
    Three Months
Ended March 31,
    Year Ended
December 31,
 
        2018     2017     2017     2016  

Production Data:

           

Oil and condensate (Bbls)

        49,108       59,429       200,814       146,320  

Natural gas (Mcf)

        2,080,535       1,942,289       6,747,492       2,437,883  

Natural gas liquids (Bbls)

        70,753       162,183       404,393       78,485  

Total (Mcfe)(6:1)(2)

        2,799,702       3,271,965       10,378,734       3,786,713  

Average daily production (Mcfe/d)(6:1)(2)

        31,108       36,355       28,435       10,346  

Total (Mcfe) (20:1)(2)

        4,477,755       6,374,529       18,851,632       6,933,983  

Average daily production (Mcfe/d)(20:1)(2)

        49,753       70,828       51,648       18,945  

Average Realized Prices:

           

Oil and condensate (per Bbl)

  $     $     $ 63.13     $ 48.30     $ 47.16     $ 39.47  

Natural gas (per Mcf)

  $     $     $ 2.27     $ 2.84     $ 2.81     $ 2.26  

Natural gas liquids (per Bbl)

  $     $     $ 28.21     $ 18.32     $ 17.64     $ 14.28  

Average Unit Cost per Mcfe (6:1)

           

Production and ad valorem taxes

  $     $     $ 0.22     $ 0.15     $ 0.15     $ 0.11  

Marketing and transportation expense

  $     $     $ 0.53     $ 0.44     $ 0.52     $ 0.31  

Lease operating expense

  $     $     $ 1.20     $ 0.88     $ 1.02     $ 1.51  

Workover expense

  $     $     $ 0.10     $ 0.23     $ 0.25     $ 0.23  

 

(1)   Does not include historical production from oil and natural gas properties to be contributed by the Contributing Parties other than our predecessor, Vendera Resources II, LLC and its affiliates, Vendera Resources III, L.P. and its affiliates and AVAD Energy Partners, LLC, which excludes assets representing approximately 12% of our future undiscounted cash flows, based on the reserve report prepared by Cawley as of December 31, 2017.

 

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(2)   “Btu-equivalent” production volumes are presented on a “natural gas-equivalent” basis using a conversion factor of six Mcf of natural gas per barrel of oil, which is based on approximate energy equivalency and does not reflect the price or value relationship between oil and natural gas.

 

(2)   “Value-equivalent” production volumes are presented on a “natural gas-equivalent” basis using a conversion factor of 20 Mcf of natural gas per barrel of oil, which is the conversion factor we use in our business. For a discussion of the 20-to-1 conversion factor, please read footnote 3 to the Royalty Interests table under “Business—Key Producing Regions—Royalty Interests.”

Productive Wells

Productive wells consist of producing wells, wells capable of production and exploratory, development, or extension wells that are not dry wells. As of December 31, 2017, we owned royalty interests in 3,610 gross (452 net) productive wells, which consisted of 788 gross (274 net) oil wells and 2,822 gross (178 net) natural gas wells.

Acreage

The following table sets forth information relating to the acreage underlying our royalty interests as of December 31, 2017 on a pro forma basis:

 

     Acreage by State  
     Gross
Developed
Acreage
     Gross
Undeveloped
Acreage
     Total
Gross
Acres
     Net
Developed
Acreage
     Net
Undeveloped
Acreage
     Total
Net
Acres
 

Alabama

     0        40,000        40,000        0        3,000        3,000  

Arkansas

     86,723        0        86,723        2,104        0        2,104  

California

     314        0        314        60        0        60  

Colorado

     2,560        0        2,560        407        0        407  

Kansas

     3,120        0        3,120        543        0        543  

Louisiana

     58,720        0        58,720        2,003        0        2,003  

Mississippi

     3,840        0        3,840        300        0        300  

Nebraska

     840        0        840        378        0        378  

New Mexico

     320        0        320        72        0        72  

Oklahoma

     209,363        26,781        236,144        3,387        843        4,230  

Texas

     116,551        1,081        117,632        28,155        360        28,515  

Utah

     42,964        20        42,984        1,398        20        1,418  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total

     525,315        67,882        593,197        38,807        4,223        43,030  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Drilling Results

For the year ended December 31, 2015, the operators of our properties drilled 89 gross (4 net) productive development wells on the acreage underlying our royalty interests. For the year ended December 31, 2016, the operators of our properties drilled 30 gross (1 net) productive development wells on the acreage underlying our royalty interests. For the year ended December 31, 2017, the operators of our properties drilled 21 gross (2 net) productive development wells on the acreage underlying our royalty interests. As of the same date, the operators of our properties had drilled 3,610 cumulative gross productive wells. As a holder of royalty interests, we generally are not provided information as to whether any wells drilled on the properties underlying our acreage are classified as exploratory. We are not aware of any dry holes drilled on the acreage underlying our royalty interests during the relevant periods.

 

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Competition

The oil and natural gas industry is intensely competitive; we primarily compete with companies for the acquisition of oil and natural gas properties, some of whom have greater resources than we do. 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 than our financial or human resources permit. Additionally, many of our competitors are, or are affiliated with, operators that engage in the exploration and production of their oil and natural gas properties, which allows them to acquire larger assets that include operated properties. 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. These companies may also have a greater ability to continue exploration activities during periods of low oil and natural gas market prices. Our ability to acquire additional properties 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.

Seasonal Nature of Business

Generally, demand for oil and natural gas decreases during the summer months and increases during the winter months. Seasonal weather conditions and lease stipulations can limit drilling and producing activities and other oil and natural gas operations in a portion of our operating areas. These seasonal anomalies can pose challenges for the operators of our properties in meeting well drilling objectives and can increase competition for equipment, supplies and personnel during the spring and summer months, which could lead to shortages and increase costs or delay operations.

Regulation

The following disclosure describes regulation directly associated with operators of oil and natural gas properties, including our current operators, and other owners of working interests in oil and natural gas properties.

Oil and natural gas operations are subject to various types of legislation, regulation and other legal requirements enacted by governmental authorities. This legislation and regulation affecting the oil and natural gas industry is under constant review for amendment or expansion. Some of these requirements carry substantial administrative, civil and criminal penalties for failure to comply. The regulatory burden on the oil and natural gas industry increases the cost of doing business.

Environmental Matters

Oil and natural gas exploration, development and production operations are subject to stringent laws and regulations governing the discharge of materials into the environment or otherwise relating to protection of the environment or occupational health and safety. These laws and regulations have the potential to impact production on our properties, which could materially adversely affect our business and our prospects. Numerous federal, state and local governmental agencies, such as the EPA, issue regulations that often require difficult and costly compliance measures that carry substantial administrative, civil and criminal penalties and may result in injunctive obligations for non-compliance. These laws and regulations may require the acquisition of a permit before drilling commences, restrict the types, quantities and concentrations of various substances that can be released into the environment in connection with drilling and production activities, limit or prohibit construction or drilling activities on certain lands lying within wilderness, wetlands, ecologically sensitive and other protected areas, require action to prevent or remediate

 

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pollution from current or former operations, such as plugging abandoned wells or closing earthen pits, result in the suspension or revocation of necessary permits, licenses and authorizations, require that additional pollution controls be installed and impose substantial liabilities for pollution resulting from operations. The strict, joint and several liability nature of such laws and regulations could impose liability upon the operators of our properties regardless of fault. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances, hydrocarbons or other waste products into the environment. Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent and costly pollution control or waste handling, storage, transport, disposal or cleanup requirements could materially adversely affect our business and prospects.

Non-Hazardous and Hazardous Waste

RCRA, and comparable state statutes and regulations promulgated thereunder, affect oil and natural gas exploration, development, and production activities by imposing requirements regarding the generation, transportation, treatment, storage, disposal and cleanup of hazardous and non-hazardous wastes. With federal approval, the individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. Administrative, civil and criminal penalties can be imposed for failure to comply with waste handling requirements. Although most wastes associated with the exploration, development and production of oil and natural gas are exempt from regulation as hazardous wastes under RCRA, these wastes typically constitute nonhazardous solid wastes that are subject to less stringent requirements. From time to time, the EPA and state regulatory agencies have considered the adoption of stricter disposal standards for nonhazardous wastes, including crude oil and natural gas wastes. Moreover, it is possible that some wastes generated in connection with exploration and production of oil and natural gas that are currently classified as nonhazardous may, in the future, be designated as “hazardous wastes,” resulting in the wastes being subject to more rigorous and costly management and disposal requirements. On May 4, 2016, a coalition of environmental groups filed a lawsuit against EPA in the U.S. District Court for the District of Columbia for failing to update regulations governing the disposal of certain oil and natural gas drilling wastes. On December 28, 2016, the court granted the joint motion of EPA and the plaintiff environmental groups for entry of a consent decree to settle the litigation. Pursuant to the consent decree, EPA must propose, no later than March 15, 2019, a rulemaking for revision of the Subtitle D criteria regulations pertaining to oil and natural gas wastes or sign a determination that revision of the regulations is not necessary. In the event that EPA proposes a rulemaking for revised oil and natural gas regulations, the consent decree requires that EPA take final action on such rulemaking no later than July 15, 2021. Any changes in the laws and regulations could have a material adverse effect on the operators of our properties’ capital expenditures and operating expenses, which in turn could affect production from the acreage underlying our mineral and royalty interests and adversely affect our business and prospects.

Remediation

CERCLA and analogous state laws, generally impose strict, joint and several liability, without regard to fault or legality of the original conduct, on classes of persons who are considered to be responsible for the release of a “hazardous substance” into the environment. These persons include the current owner or operator of a contaminated facility, a former owner or operator of the facility at the time of contamination, and those persons that disposed or arranged for the disposal of the hazardous substance at the facility. Under CERCLA and comparable state statutes, persons deemed “responsible parties” may be subject to strict, joint and several liability for the costs of removing or remediating previously disposed wastes (including wastes disposed of or released by prior owners or operators) or property contamination (including groundwater contamination), for damages to natural resources and for the costs of certain health studies. In addition, it is

 

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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. In addition, the risk of accidental spills or releases could expose the operators of the acreage underlying our mineral interests to significant liabilities that could have a material adverse effect on the operators’ businesses, financial condition and results of operations. Liability for any contamination under these laws could require the operators of the acreage underlying our mineral interests to make significant expenditures to investigate and remediate such contamination or attain and maintain compliance with such laws and may otherwise have a material adverse effect on their results of operations, competitive position or financial condition.

Water Discharges

The Clean Water Act, the SDWA, the OPA, and analogous state laws and regulations promulgated thereunder impose restrictions and strict controls regarding the unauthorized discharge of pollutants, including produced waters and other gas and oil wastes, into regulated 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 Clean Water Act and regulations implemented thereunder also prohibit the discharge of dredge and fill material into regulated waters, including jurisdictional wetlands, unless authorized by an appropriately issued permit. In addition, spill prevention, control and countermeasure plan requirements under federal law require appropriate containment berms and similar structures to help prevent the contamination of navigable waters in the event of a petroleum hydrocarbon tank spill, rupture or leak. The EPA has also adopted regulations requiring certain oil and natural gas exploration and production facilities to obtain individual permits or coverage under general permits for storm water discharges, and in June 2016, the EPA finalized effluent limitation guidelines for the discharge of wastewater from hydraulic fracturing.

The OPA is the primary federal law for oil spill liability. The OPA contains numerous requirements relating to the prevention of and response to petroleum releases into regulated waters, including the requirement that operators of offshore facilities and certain onshore facilities near or crossing waterways must develop and maintain facility response contingency plans and maintain certain significant levels of financial assurance to cover potential environmental cleanup and restoration costs. The OPA subjects owners of facilities to strict, joint and several liability for all containment and cleanup costs and certain other damages arising from a release, including, but not limited to, the costs of responding to a release of oil into surface waters.

Noncompliance with the Clean Water Act or the OPA may result in substantial administrative, civil and criminal penalties, as well as injunctive obligations, for the operators of the acreage underlying our mineral interests.

Air Emissions

The federal Clean Air Act, and comparable state laws and regulations, regulate emissions of various air pollutants through the issuance of permits and the imposition of other requirements. The EPA has developed, and continues to develop, stringent regulations governing emissions of air pollutants at specified sources. New facilities may be required to obtain permits before work can begin, and existing facilities may be required to obtain additional permits and incur capital costs in order to remain in compliance. For example, in May 2016, the EPA finalized additional regulations under the federal Clean Air Act that established new emission control requirements for oil and natural gas production and processing operations, which is discussed in more detail below in “— Regulation of Hydraulic Fracturing.” The EPA is currently reconsidering this rule. These laws and regulations may increase the costs of compliance for oil and natural gas producers and impact production of the acreage underlying our mineral and royalty interests, and federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance

 

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with air permits or other requirements of the federal Clean Air Act and associated state laws and regulations. Moreover, obtaining or renewing permits has the potential to delay the development of oil and natural gas projects. All of these factors could impact production on our properties and adversely affect our business and results of operations.

Climate Change

In response to findings that emissions of GHGs, including carbon dioxide and methane, present an endangerment to public health and the environment, the EPA has adopted regulations under existing provisions of the federal Clean Air Act that, among other things, require preconstruction and operating permits for certain large stationary sources. In addition, the EPA has adopted rules requiring the monitoring and reporting of GHGs from certain onshore oil and natural gas production sources on an annual basis. As a result of this continued regulatory focus, future GHG regulations applicable to the oil and natural gas industry remain a possibility.

Congress has from time to time considered adopting legislation to reduce emissions of GHGs and many states have already taken legal measures to reduce emissions of GHGs primarily through the planned development of GHG emissions inventories and/or regional GHG cap and trade programs. Although Congress has not adopted such legislation at this time, it may do so in the future and many states continue to pursue regulations to reduce GHG emissions. Additionally, efforts have been made and continue to be made in the international community toward the adoption of international treaties or protocols that would address global climate change issues. Most recently in 2015, the United States participated in the United Nations Conference on Climate Change, which led to the creation of the Paris Agreement. The Paris Agreement requires member countries to review and “represent a progression” in their intended nationally determined contributions, which set GHG emission reduction goals, every five years beginning in 2020. The Paris Agreement entered into force in November 2016. The United States announced its intention to withdraw from the Paris Agreement on June 1, 2017 and in August 2017, the U.S. Department of State provided formal notice to the United Nations that the United States intends to withdraw from the Paris Agreement as soon as it is eligible to do so under the agreement.

Restrictions on emissions of methane or carbon dioxide that may be imposed in various states, as well as state and local climate change initiatives, could adversely affect the oil and natural gas industry, and, at this time, it is not possible to accurately estimate how potential future laws or regulations addressing GHG emissions would impact our business.

In addition, one potential consequence of climate change could be increased severity of extreme weather conditions such as more intense hurricanes, thunderstorms, tornados and snow or ice storms, as well as rising sea levels. Another possible consequence of climate change is increased volatility in seasonal temperatures. Extreme weather conditions can interfere with production and increase costs and damage resulting from extreme weather may not be fully insured. However, at this time, we are unable to determine the extent to which climate change may lead to increased storm or weather hazards affecting our business.

Endangered Species Act

The Endangered Species Act (“ESA”) and analogous state laws restrict activities that may affect endangered or threatened species or their habitats. Pursuant to a settlement with environmental groups, the U.S. Fish and Wildlife Service (“USFWS”) was required to determine whether over 250 species required listing as threatened or endangered under the ESA. USFWS has not yet completed its review, but the potential remains for new species to be listed under the ESA. Some of the properties in which we own overriding royalty, mineral and royalty interests may be located in areas that are or may be designated as habitats for endangered or threatened species, and previously unprotected species may later be designated as

 

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threatened or endangered in areas where we hold overriding royalty, mineral and royalty interests. This could cause our operators to incur increased costs arising from species protection measures, delay the completion of exploration and production activities and/or result in limitations on operating activities that could have an adverse impact on our business.

Regulation of Hydraulic Fracturing

Hydraulic fracturing is an important and common practice that is used to stimulate production of hydrocarbons from tight formations. The process involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production. Hydraulic fracturing operations have historically been overseen by state regulators as part of their oil and natural gas regulatory programs, but recently the EPA and other federal agencies have asserted jurisdiction over certain aspects of hydraulic fracturing. For example, on May 9, 2014, the EPA announced an advance notice of proposed rulemaking under the Toxic Substances Control Act, relating to chemical substances and mixtures used in oil and natural gas exploration or production. However, no further action has been taken by the EPA with respect to this proposed rulemaking and additional federal regulation of hydraulic fracturing is uncertain at this time. From time to time, Congress has considered legislation that would provide for federal regulation of hydraulic fracturing and would require disclosure of the chemicals used in the fracturing process. If enacted, these or similar laws and regulations could result in additional permitting requirements for hydraulic fracturing operations as well as various restrictions on those operations. These permitting requirements and restrictions could result in delays in operations at well sites and also increased costs to make wells productive.

On August 16, 2012, the EPA approved final regulations under the federal Clean Air Act that establish new air emission controls for oil and natural gas production and natural gas processing operations. Specifically, the EPA’s rule package includes New Source Performance Standards to address emissions of sulfur dioxide and volatile organic compounds (“VOCs”) and a separate set of emission standards to address hazardous air pollutants frequently associated with oil and natural gas production and processing activities. The final rule seeks to achieve a 95% reduction in VOCs emitted by requiring the use of reduced emission completions or “green completions” on all hydraulically-fractured natural gas wells constructed or refractured after January 1, 2015. The rules also establish specific new requirements regarding emissions from compressors, controllers, dehydrators, storage tanks and other production equipment. In May 2016, the EPA finalized similar rules that impose VOC emissions limits on certain oil and natural gas operations that were previously unregulated, including hydraulically fractured oil wells, as well as methane emissions limits for certain new or modified oil and natural gas emissions sources. The EPA is currently reconsidering those rules.

In addition, a number of federal agencies have studied the environmental aspects of hydraulic fracturing practices. These studies, depending on their degree of pursuit and whether any meaningful results are obtained, could spur initiatives to further regulate hydraulic fracturing under the SDWA or other regulatory authorities. For example, in December 2016, the EPA issued its final report on a study it had conducted over several years regarding the effects of hydraulic fracturing on drinking water sources. The final report found instances in which impacts to drinking water may occur. However, the report also noted significant data gaps that prevented the EPA from determining the extent or severity of these impacts. The EPA has not proposed to take any action in response to the report’s findings.

Several states where we own interests in oil and natural gas producing properties have adopted, or are considering adopting, regulations that could restrict or prohibit hydraulic fracturing in certain circumstances and/or require the disclosure of the composition of hydraulic fracturing fluids. For example, Texas and Oklahoma have adopted rules requiring oil and natural gas operators to publicly disclose the chemicals used

 

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in the hydraulic fracturing process. 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 or prohibit the performance of well drilling in general or hydraulic fracturing in particular.

There has been increasing public controversy regarding hydraulic fracturing with regard to the use of fracturing fluids, impacts on drinking water supplies, use of water and the potential for impacts to surface water, groundwater and the environment generally. A number of lawsuits and enforcement actions have been initiated across the country implicating hydraulic fracturing practices. State and federal regulatory agencies recently have focused on a possible connection between hydraulic fracturing related activities, particularly the disposal of produced water in underground injection wells, and the increased occurrence of seismic activity. When caused by human activity, such events are called induced seismicity. In some instances, operators of injection wells in the vicinity of seismic events have been ordered to reduce injection volumes or suspend operations. Some state regulatory agencies, including those in Colorado, Ohio, Oklahoma and Texas, have modified their regulations to account for induced seismicity. Regulatory agencies at all levels are continuing to study the possible linkage between oil and natural gas activity and induced seismicity. In addition, a number of lawsuits have been filed, most recently in Oklahoma, alleging that disposal well operations have caused damage to neighboring properties or otherwise violated state and federal rules regulating waste disposal. These developments could result in additional regulation and restrictions on the use of injection wells and hydraulic fracturing. Such regulations and restrictions could cause delays and impose additional costs and restrictions on the operators of our properties and on their waste disposal activities.

If new laws or regulations that significantly restrict hydraulic fracturing and related activities are adopted, such laws could make it more difficult or costly to perform fracturing to stimulate production from tight formations as well as make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process could adversely affect groundwater. In addition, if hydraulic fracturing is further regulated at the federal or state level, fracturing activities could become subject to additional permitting and financial assurance requirements, more stringent construction specifications, increased monitoring, reporting and recordkeeping obligations, plugging and abandonment requirements and also to attendant permitting delays and potential increases in costs. Such legislative changes could cause operators to incur substantial compliance costs, and compliance or the consequences of any failure to comply by operators could have a material adverse effect on our financial condition and results of operations. At this time, it is not possible to estimate the impact on our business of newly enacted or potential federal or state legislation governing hydraulic fracturing.

Other Regulation of the Oil and Natural Gas Industry

The oil and natural gas industry is extensively regulated by numerous federal, state and local authorities. Legislation affecting the oil and natural gas industry is under constant review for amendment or expansion, frequently increasing the regulatory burden. Also, numerous departments and agencies, both federal and state, are authorized by statute to issue rules and regulations that are binding on the oil and natural gas industry and its individual members, some of which carry substantial penalties for failure to comply. Although the regulatory burden on the oil and natural gas industry increases the cost of doing business, these burdens generally do not affect us any differently or to any greater or lesser extent than they affect other companies in the industry with similar types, quantities and locations of production.

The availability, terms and cost of transportation significantly affect sales of oil and natural gas. The interstate transportation of oil and natural gas and the sale for resale of natural gas is subject to federal regulation, including regulation of the terms, conditions and rates for interstate transportation, storage and various other matters, primarily by the Federal Energy Regulatory Commission (“FERC”). Federal and state

 

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regulations govern the price and terms for access to oil and natural gas pipeline transportation. FERC’s regulations for interstate oil and natural gas transmission in some circumstances may also affect the intrastate transportation of oil and natural gas.

Although oil and natural gas prices are currently unregulated, Congress historically has been active in the area of oil and natural gas regulation. We cannot predict whether new legislation to regulate oil and natural gas might be proposed, what proposals, if any, might actually be enacted by Congress or the various state legislatures, and what effect, if any, the proposals might have on our operations. Sales of crude oil, condensate and NGLs are not currently regulated and are made at market prices.

Drilling and Production

The operations of the operators of our properties are subject to various types of regulation at the federal, state and local level. These types of regulation include requiring permits for the drilling of wells, drilling bonds and reports concerning operations. The state, and some counties and municipalities, in which we operate also regulate one or more of the following:

 

    the location of wells;

 

    the method of drilling and casing wells;

 

    the timing of construction or drilling activities, including seasonal wildlife closures;

 

    the rates of production or “allowables”;

 

    the surface use and restoration of properties upon which wells are drilled;

 

    the plugging and abandoning of wells; and

 

    notice to, and consultation with, surface owners and other third parties.

State laws regulate the size and shape of drilling and spacing units or proration units governing the pooling of oil and natural gas properties. Some states allow forced pooling or integration of tracts to facilitate exploration while other states rely on voluntary pooling of lands and leases. In some instances, forced pooling or unitization may be implemented by third parties and may reduce our interest in the unitized properties. In addition, state conservation laws establish maximum rates of production from oil and natural gas wells, generally prohibit the venting or flaring of natural gas and impose requirements regarding the ratability of production. These laws and regulations may limit the amount of oil and natural gas that the operators of our properties can produce from our wells or limit the number of wells or the locations at which operators can drill. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, natural gas and NGLs within its jurisdiction. States do not regulate wellhead prices or engage in other similar direct regulation, but we cannot assure you that they will not do so in the future. The effect of such future regulations may be to limit the amounts of oil and natural gas that may be produced from our wells, negatively affect the economics of production from these wells or to limit the number of locations operators can drill.

Federal, state and local regulations provide detailed requirements for the abandonment of wells, closure or decommissioning of production facilities and pipelines and for site restoration in areas where the operators of our properties operate. The U.S. Army Corps of Engineers and many other state and local authorities also have regulations for plugging and abandonment, decommissioning and site restoration. Although the U.S. Army Corps of Engineers does not require bonds or other financial assurances, some state agencies and municipalities do have such requirements.

 

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Natural Gas Sales and Transportation

FERC has jurisdiction over the transportation and sale for resale of natural gas in interstate commerce by natural gas companies under the Natural Gas Act of 1938 (“NGA”) and the Natural Gas Policy Act of 1978. Since 1978, various federal laws have been enacted which have resulted in the complete removal of all price and non-price controls for sales of domestic natural gas sold in “first sales.”

Under the Energy Policy Act of 2005, FERC has substantial enforcement authority to prohibit the manipulation of natural gas markets and enforce its rules and orders, including the ability to assess substantial civil penalties. FERC also regulates interstate natural gas transportation rates and service conditions and establishes the terms under which the operators of our properties may use interstate natural gas pipeline capacity, as well as the revenues the operators of our properties receive for sales of natural gas and release of natural gas pipeline capacity. Interstate pipeline companies are required to provide nondiscriminatory transportation services to producers, marketers and other shippers, regardless of whether such shippers are affiliated with an interstate pipeline company. FERC’s initiatives have led to the development of a competitive, open access market for natural gas purchases and sales that permits all purchasers of natural gas to buy gas directly from third party sellers other than pipelines.

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 under the NGA. Although its policy is still in flux, FERC has in the past reclassified certain jurisdictional transmission facilities as non-jurisdictional gathering facilities, which may increase the operators’ costs of transporting gas to point-of-sale locations. This may, in turn, affect the costs of marketing natural gas that the operators of our properties produce.

Historically, the natural gas industry has been very heavily regulated; therefore, we cannot guarantee that the less stringent regulatory approach currently pursued by FERC and Congress will continue indefinitely into the future nor can we determine what effect, if any, future regulatory changes might have on our natural gas related activities.

Oil Sales and Transportation

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

Crude oil sales are affected by the availability, terms and cost of transportation. The transportation of oil in common carrier pipelines is also subject to rate regulation. FERC regulates interstate oil pipeline transportation rates under the Interstate Commerce Act and 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 are equally applicable to all comparable shippers, we believe that the regulation of oil transportation rates will not affect our operations in any materially different way than such regulation will affect the operations of our competitors.

Further, interstate and intrastate common carrier oil pipelines must provide service on a non-discriminatory basis. Under this open access standard, common carriers must offer service to all similarly situated shippers requesting service on the same terms and under the same rates. When oil pipelines operate at full capacity, access is governed by prorating provisions set forth in the pipelines’ published tariffs. Accordingly, we believe that our access to oil pipeline transportation services will not materially differ from our competitors’ access to oil pipeline transportation services.

 

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State Regulation

Texas regulates the drilling for, and the production, gathering and sale of, oil and natural gas, including imposing severance taxes and requirements for obtaining drilling permits. Texas currently imposes a 4.6% severance tax on the market value of oil production and a 7.5% severance tax on the market value of natural gas production. States also regulate the method of developing new fields, the spacing and operation of wells and the prevention of waste of oil and natural gas resources.

States may regulate rates of production and may establish maximum daily production allowable from oil and natural gas wells based on market demand or resource conservation, or both. States do not regulate wellhead prices or engage in other similar direct economic regulation, but we cannot assure you that they will not do so in the future. Should direct economic regulation or regulation of wellhead prices by the states increase, this could limit the amount of oil and natural gas that may be produced from our wells and the number of wells or locations the operators of our properties can drill.

The petroleum industry is also subject to compliance with various other federal, state and local regulations and laws. Some of those laws relate to resource conservation and equal employment opportunity. We do not believe that compliance with these laws will have a material adverse effect on our business.

Title to Properties

We believe that the title to our assets is satisfactory in all material respects. 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.

Employees

In connection with the closing of this offering, we will enter into a management services agreement with our Operating Affiliate, pursuant to which it will provide management and administrative services for us. Please read “Management” and “Certain Relationships and Related Party Transactions.” Immediately after the closing of this offering, we expect that our Operating Affiliate will have approximately 20 employees performing services on our behalf. We believe that our Operating Affiliate has a satisfactory relationship with those employees.

Facilities

Our principal executive offices are located at 807 Las Cimas Parkway, Suite 275, Austin, Texas 78746. We believe that these facilities are adequate for our current operations.

Legal Proceedings

Although we may, from time to time, be involved in various legal claims arising out of our operations in the normal course of business, we do not believe that the resolution of these matters will have a material adverse impact on our financial condition or results of operations.

 

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MANAGEMENT

Management of Remora Royalties, Inc.

We are managed and operated by our board of directors and executive officers.

All of our executive officers are also officers of our Operating Affiliate. Our executive officers will allocate their time between managing our business and affairs and the business and affairs of certain other entities, including our Operating Affiliate. In addition, employees of our Operating Affiliate will provide management and administrative services to us pursuant to a management services agreement, but they will also provide these services to certain other entities, including our Operating Affiliate. Certain of our officers and directors, including the individuals who control our Operating Affiliate, may in the future hold similar positions with other private entities that are in the business of identifying and acquiring royalty interests. Please read “Certain Relationships and Related Party Transactions—Agreements and Transactions with Affiliates in Connection with this Offering—Management Services Agreement.” We expect our executive officers and other shared personnel to devote a sufficient amount of time to our business and affairs as is necessary for the proper management and conduct of our business. However, we anticipate that, for the foreseeable future, our executive officers and other shared personnel will also devote substantial amounts of their time to managing the businesses of other entities.

Our Executive Officers and Directors

The following table shows information for our executive officers, directors and director nominees upon the consummation of this offering:

 

Name

  

Age (as of
May 8, 2018)

  

Position

George B. Peyton V

   36    Chief Executive Officer and Chairman of the Board

Grant W. Livesay

   37    President, Chief Financial Officer, Secretary and Director

Salah I. Gamoudi

   32    Chief Accounting Officer and Controller

Corwin Y. Ames

   30    Vice President – Reservoir Engineering

Aaron T. Brack

   37    Vice President – Operations

Christopher J. Manuel

   38    Vice President – Land

Jeffrey G. Shrader

   67    Director Nominee

Frank O. Marrs

  

73

   Director Nominee

Sam C. Henry

   65    Director Nominee

Aaron R. Stanley

   44    Director Nominee

Dickie D. Hunter

   62    Director Nominee

George B. Peyton V. Mr. Peyton has served as our Chief Executive Officer and a Director since our formation and has served as the Chief Executive Officer of our predecessor since its inception in 2011. From 2009 to 2011, he served as President of Fifth Well Investment Management, LLC, a private investment firm focused on energy and other public and private investments. From 2005 to 2007, he served as Financial Analyst with XTO Energy, Inc. Mr. Peyton left XTO Energy Inc. in 2007 to attend Stanford Graduate School of Business, where he earned his Master in Business Administration in 2009. Mr. Peyton also has a Bachelor of Science in Astrophysics and a Bachelor of Business Administration in Entrepreneurial Management from Texas Christian University. We believe that Mr. Peyton’s extensive experience in the energy industry brings valuable strategic, managerial and leadership skills to the board of directors and us.

 

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Grant W. Livesay. Mr. Livesay has served as our President, Chief Financial Officer and Secretary and a Director since our formation and has served as the President and Chief Financial Officer of our predecessor since its inception in 2011. From 2009 to 2011, he served as a Research Analyst with Teton Capital Partners, an Austin-based value-oriented hedge fund with $1.6 billion in assets under management. From 2005 to 2007, he served as an Associate at NGP Energy Capital Management, a private equity firm with over $20 billion of cumulative equity commitments. Mr. Livesay left NGP Energy Capital Management in 2007 to attend Stanford Graduate School of Business, where he earned his Master in Business Administration in 2009. From 2003 to 2005, he served as an Analyst at Merrill Lynch & Co., Inc. in the Global Energy and Power Investment Banking Group. Mr. Livesay also has a Bachelor of Business Administration in Finance from The University of Texas at Austin. Mr. Livesay was selected to serve as a director because of his broad knowledge of, and extensive experience in, the oil and natural gas industry.

Salah I. Gamoudi. Mr. Gamoudi has served as our Chief Accounting Officer and Controller since our formation and has served as the Chief Accounting Officer and Controller of our predecessor since 2017. From 2015 to 2017, he served as Corporate Controller of Glacier Oil & Gas (formerly known as Miller Energy Resources, Inc.), where he restructured the accounting department and led the transition from being a publicly traded entity to a privately held company. From 2013 to 2015, he served as SOX and Internal Audit Manager of LRR Energy, L.P. and Lime Rock Resources. From 2012 to 2013, he served as an auditor for Deloitte & Touche LLP. From 2009 to 2011, he served as an auditor for Ernst & Young LLP. Mr. Gamoudi has a Bachelor of Arts in Accounting from Portland State University and is a Certified Public Accountant.

Corwin Y. Ames. Mr. Ames has served as our Vice President – Reservoir Engineering since our formation and has served as a Reservoir Engineer for our predecessor since December 2014. From August 2012 until December 2014, Mr. Ames served as a Petroleum Engineer with Lonquist & Co., a reservoir engineering firm, where he performed a wide variety of petroleum engineering analyses and consulting services for operating companies, investors, banks and other clients. From August 2010 until July 2012, Mr. Ames served as a Reservoir Engineer with XTO Energy, Inc. Mr. Ames has a Bachelor of Science in Petroleum Engineering from the University of Texas at Austin.

Aaron T. Brack. Mr. Brack has served as our Vice President – Operations since our formation and has served as the Vice President – Operations of our predecessor since August 2017. From March 2016 to August 2017, Mr. Brack served as Vice President of Engineering of Green Oak Oil & Gas LLC, where he led acquisition strategy, evaluated field operations and performed due diligence on mature, conventional properties in multiple basins. From April 2014 to February 2016, Mr. Brack served as Senior Completions / Production Engineer with Jones Energy, Inc., where he supervised production, managed daily workover operations and designed and implemented completion systems across the Anadarko and Arkoma basins. From April 2013 to March 2014, Mr. Brack managed his private oil and gas investments. From 2004 to March 2013, Mr. Brack served as a Petroleum Engineer with Comstock Resources, where he managed and developed assets in the East Texas and Permian Basins. Mr. Brack has a Bachelor of Science in Petroleum Engineering from Texas A&M University.

Christopher J. Manuel. Mr. Manuel has served as our Vice President – Land since our formation and has served as the Vice President – Land of our predecessor since September 2017. From April 2016 to September 2017, Mr. Manuel served as Land Manager of Black Falcon Energy LLC, where he built and managed a Land Department responsible for over 9,000 wells across 10 states. From February 2014 to March 2016, Mr. Manuel served as Land Manager of Tradition Resources II, LLC. From June 2012 to January 2014, Mr. Manuel served as Landman and then Land Manager of Atinum E&P, Inc. Mr. Manuel has a Bachelor of Arts in Biology from the University of Kansas.

 

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Jeffrey G. Shrader. Mr. Shrader will become a member of our board of directors in connection with our listing on the NASDAQ. Mr. Shrader is an attorney with the law firm Sprouse Shrader Smith PLLC, where he has practiced since 1992. His practice areas focus on oil and gas transactions, commercial transactions, banking and real estate law. Mr. Shrader has more than 40 years’ experience practicing oil and gas law and has represented buyers and sellers in transactions involving more than $1 billion in value. Mr. Shrader was a member of the Board of Directors of Parallel Petroleum Co. from 2001 until its sale in 2009, serving as Chairman of the Board from 2006 through its sale. Mr. Shrader also served on the Board of Directors of Hastings Entertainment, Inc., from 1992 until its sale in 2015, and was the Lead Independent Director during its sale process. Mr. Shrader received his undergraduate degree from Northwestern University and his law degree from University of Texas School of Law. We believe Mr. Shrader’s extensive experience, including his roles as an attorney in the oil and gas industry, brings important and valuable skills to our board of directors.

Frank O. Marrs. Mr. Marrs will become a member of our board of directors in connection with our listing on the NASDAQ. Mr. Marrs is the Chief Executive Officer of Gupton Marrs International, Inc. and has served as Chief Executive Officer since 2001. Prior to co-founding Gupton Marrs International, Mr. Marrs served on KPMG’s Management Committee as Vice Chairman of KPMG’s Audit Practice. He led several of KPMG’s operating committees and was responsible for the worldwide design and implementation of the firm’s risk-based assurance services and other key strategic initiatives. Mr. Marrs received a Bachelor of Business Administration in Accounting from West Texas State University, and is a Certified Public Accountant. We believe Mr. Marrs’ extensive experience, including his roles in the management and accounting industries, brings important and valuable skills to our board of directors.

Sam C. Henry. Mr. Henry will become a member of our board of directors in connection with our listing on the NASDAQ. Since January 2016, Mr. Henry has served as the Chief Executive Officer of Mira Vista Investments, LLC, a firm engaged in the private investments in energy, real estate and new ventures. Mr. Henry served as the President and Chief Executive Officer as well as a member of the board of directors of GDF Suez Energy Resources NA, Inc., the third largest non-residential electric energy provider in the U.S., from 2012 until his retirement in December 2015. As President and Chief Executive Officer, Mr. Henry was responsible for leading the development and execution of the overall strategy of the company. From 2004 to 2012 Mr. Henry was the President and CEO of IPR GDF Suez Energy Marketing NA Inc., where he was responsible for the company’s Trading & Portfolio Management activities, which covered a $10 billion portfolio of 14,000 MW of generation, LNG terminals and retail sales to C&I customers. Mr. Henry has a Bachelor of Arts in Environmental Studies from Baylor University and a Master in Business Administration from Western Governors University. We believe Mr. Henry’s extensive experience, including his roles in the energy and financial industries, brings important and valuable skills to our board of directors.

Aaron R. Stanley. Mr. Stanley will become a member of our board of directors in connection with our listing on the NASDAQ. Since June 2016, he has served as an analyst at Wallace Capital Management, Inc., a SEC registered investment advisor based in Dallas, Texas. From April 2014 to May 2016, Mr. Stanley was Managing Partner at AR Stanley & Co. In 2013, he managed his personal investments. From 2002 to 2012, he was the Co-Founder and a Partner at Treaty Oak Capital Management, an Austin-based energy-focused hedge fund. He became the Managing Partner of Treaty Oak in 2009. Mr. Stanley received a Bachelor of Arts in Managerial Studies from Rice University. We believe Mr. Stanley’s extensive experience, including his roles in the financial industry, brings important and valuable skills to our board of directors.

 

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Dickie D. Hunter. Mr. Hunter will become a member of our board of directors in connection with our listing on the NASDAQ. Mr. Hunter has served as the Chief Executive Officer and a Director of HighMark LLC and HighMark Energy, LLC since founding the companies in January 2016 and May 2013, respectively. Prior to joining HighMark Energy, Mr. Hunter served as Chief Financial Officer and Director at Rise Energy Partners, a Natural Gas Partners sponsored company. During his tenure with Rise Energy, the Company acquired and managed distressed upstream oil and gas assets and eventually sold in December 2012. From February 1995 to February 2009, Mr. Hunter served as the Chief Financial Officer of Wynn-Crosby Energy. Prior to Wynn-Crosby, Mr. Hunter was the Controller of Bridge Oil (U.S.A.) Inc. from 1988 to 1994, and served as a financial analyst with Petrus Oil Company, L.P. and Diamond Shamrock Corporation from 1981 to 1987. Mr. Hunter attended West Texas A&M University where he earned his Master in Business Administration in 1980 and a Bachelor of Science in Economics in 1978. Mr. Hunter obtained his Certified Public Accountant license in 1990. We believe Mr. Hunter’s extensive experience, including his roles in the oil and gas and financial industries, brings important and valuable skills to our board of directors.

Board 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’s ability to manage and direct our affairs and business, including, when applicable, to enhance the ability of the committees of the board to fulfill their duties.

Our directors will be divided into three classes 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.          and          will be assigned to Class I, Messrs.          and          will be assigned to Class II, and Messrs.         ,          and          will be assigned to Class III.

Independence of the Board of Directors and Board Committees

Rule 5605 of the NASDAQ Marketplace Rules requires a majority of a listed company’s board of directors to be comprised of independent directors within one year of listing. In addition, the NASDAQ Marketplace Rules require that, subject to specified exceptions, each member of a listed company’s audit, compensation and nominating and governance committees be independent and that audit committee members also satisfy independence criteria set forth in Rule 10A-3 under the Exchange Act. Under Rule 5605(a)(2), a director will only qualify as an “independent director” if, in the opinion of our board of directors, that person does not have a relationship that would interfere with the exercise of independent judgment in carrying out the responsibilities of a director. In order to be considered independent for purposes of Rule 10A-3, a member of an audit committee of a listed company may not, other than in his or her capacity as a member of the audit committee, the board of directors, or any other board committee: (1) accept, directly or indirectly, any consulting, advisory, or other compensatory fee from the listed company or any of its subsidiaries; or (2) be an affiliated person of the listed company or any of its subsidiaries.

In connection with this offering, our board of directors will undertake a review of the anticipated composition of our board of directors and its committees and the independence of each director and director nominee. Based upon information requested from and provided by each director concerning his or her

 

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background, employment and affiliations, including family and other relationships, our board of directors has determined that none of Messrs. Shrader, Marrs, Henry or Stanley, representing four of our seven directors upon consummation of this offering, has a relationship that would interfere with the exercise of independent judgment in carrying out the responsibilities of a director and that each of these directors is “independent” as that term is defined under Rule 5605(a)(2) of the NASDAQ Marketplace Rules. Our board of directors also determined that Messrs.         ,          and         , each of whom will be a member of our audit committee, Messrs.         ,          and         , who will be members of our compensation committee, and Messrs.         ,          and         , each of whom will be a member of our governance and nominating committee, satisfy the independence standards for such committees established by the SEC and the NASDAQ Marketplace Rules, as applicable. In making these determinations on the independence of our directors and director nominees, our board of directors considered the relationships that each such non-employee director has with our company and all other facts and circumstances our board of directors deemed relevant in determining independence.

Committees of our Board of Directors

Upon the conclusion of this offering, we intend to have an audit committee, a compensation committee, a nominating 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

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 applicable stock exchange or market standards.

The members of the audit committee will be Messrs.         ,         and         . Each member of the audit committee is a non-employee director within the meaning of Rule 16b-3 of the rules promulgated under the Exchange Act, each is an outside director, as defined by Section 162(m) of the United States Internal Revenue Code of 1986, as amended, or the Code, and each is an independent director, as defined by the NASDAQ Stock Market. Our board of directors has determined that          qualifies as an “audit committee financial expert” as such term is currently defined in Item 407(d)(5) of Regulation S-K. Each member of the audit committee is able to read and understand fundamental financial statements, including our balance sheet, income statement and cash flows statements. The audit committee expects to adopt a charter that will be posted on our website upon the closing of the offering.

Compensation Committee

The compensation committee approves the compensation objectives for the Company, provides a recommendation on the compensation of the Chief Executive Officer, which is subject to approval by the full board of directors, and establishes the compensation for other executives. The compensation committee reviews all compensation components including base salary, bonus, benefits and other perquisites.

The members of the compensation committee will be Messrs.         ,          and         . Each member of the compensation committee is a non-employee director within the meaning of Rule 16b-3 of the rules

 

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promulgated under the Exchange Act, each is an outside director, as defined by Section 162(m) of the United States Internal Revenue Code of 1986, as amended, or the Code, and each of Messrs.         ,          and          is an independent director, as defined by the NASDAQ Stock Market. The compensation committee expects to adopt a charter that will be posted on our website upon the closing of the offering.

Nominating and Corporate Governance Committee

The nominating and corporate governance 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. The members of the nominating and corporate governance committee will be Messrs.         ,          and         . Each of Messrs.         ,          and          is a non-employee director within the meaning of Rule 16b-3 of the rules promulgated under the Exchange Act, and each is an independent director, as defined by the NASDAQ Stock Market. The nominating and corporate governance committee expects to adopt a charter that will be posted on our website upon the closing of the offering.

Compensation Committee Interlocks and Insider Participation

None of our executive officers serve on the board of directors or compensation committee of a company that has an executive officer that serves on our board or compensation committee. 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 NASDAQ. Any waiver of this code may be made only by our board of directors and will be promptly disclosed as required by applicable U.S. federal securities laws and the corporate governance rules of the NASDAQ.

Corporate Governance Guidelines

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

 

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EXECUTIVE COMPENSATION AND OTHER INFORMATION

We were formed in May 2018. As a new company, we have not accrued or paid or will accrue or pay any obligations with respect to management compensation or retirement benefits for our directors and executive officers for any periods prior to the consummation of this offering. Accordingly, we are not presenting any compensation for historical periods.

Our executive officers will manage and operate our business as part of the services provided to us by our Operating Affiliate under a management services agreement. All of our executive officers and other employees necessary to operate our business will be employed and compensated by our Operating Affiliate or an entity with which our Operating Affiliate arranges for the provision of services. The compensation for all of our executive officers will be indirectly paid by us to the extent we reimburse our Operating Affiliate pursuant to the management services agreement that we will enter into with our Operating Affiliate in connection with this offering. Please read “Certain Relationships and Related Party Transactions—Agreements and Transactions with Affiliates in Connection with this Offering—Management Services Agreement” and “Management.”

Certain of our executive officers will have responsibilities to both us and our Operating Affiliate, and we expect that these executive officers will allocate their time between managing our business and managing the respective businesses of our Operating Affiliate. All determinations with respect to any awards that may be made to our executive officers, key employees and independent directors under any long-term incentive plan we adopt, will be made by the compensation committee of our board of directors. Please read the description of the long-term incentive plan we intend to adopt prior to the completion of this offering below under the heading “—2018 Stock and Incentive Plan.”

Our executive officers, as well as the employees of our Operating Affiliate who provide services to us, may participate in employee benefit plans and arrangements sponsored by our Operating Affiliate, including plans that may be established in the future. In the future, as we formulate and implement the compensation programs for our executive officers, our Operating Affiliate may provide different or additional compensation components, benefits or perquisites to our executive officers.

2018 Stock and Incentive Plan

In connection with this offering, our board of directors expects to adopt, and our current stockholders expect to approve, the 2018 Stock and Incentive Plan, or the 2018 Incentive Plan, prior to the effective date of this offering. The purposes of the 2018 Incentive Plan are to align the interests of our stockholders and those eligible for awards, to retain officers, directors, employees, and other service providers, and to encourage them to act in our long-term best interests. Our 2018 Incentive Plan provides for the grant of incentive stock options (within the meaning of Section 422 of the Code), nonstatutory stock options, stock appreciation rights, restricted stock, restricted stock units, other stock awards, and performance awards. Officers, directors, employees, and consultants who provide services to us or to any subsidiary of ours are eligible to receive such awards. The material terms of the 2018 Incentive Plan are as follows:

 

    Stock Subject to the Plan. The aggregate number of shares initially reserved under the 2018 Incentive Plan is              shares of our Class A common stock. To the extent an equity award granted under the 2018 Incentive Plan (other than any substitute award) expires or otherwise terminates without having been exercised or paid in full, or is settled in cash, the shares subject to such award will become available for future grant under the 2018 Incentive Plan. In addition, to the extent shares subject to an award are withheld to satisfy a participant’s tax withholding obligation upon the exercise or settlement of such award (other than any substitute award) or to pay the exercise price of a stock option, such shares will become available for future grant under the 2018 Incentive Plan.

 

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    Plan Administration. Our compensation committee will administer the 2018 Incentive Plan. Our board of directors has the authority to amend and modify the plan, subject to any stockholder approval required by law or stock exchange rules. Subject to the terms of the 2018 Incentive Plan, our compensation committee will have the authority to determine the eligibility for awards and the terms, conditions, and restrictions, including vesting terms, the number of shares subject to an award, and any performance goals applicable to grants made under the 2018 Incentive Plan. The compensation committee also will have the authority, subject to the terms of the 2018 Incentive Plan, to construe and interpret the 2018 Incentive Plan and awards, and amend outstanding awards at any time.

 

    Stock Options and Stock Appreciation Rights. Our compensation committee may grant incentive stock options, nonstatutory stock options, and stock appreciation rights under the 2018 Incentive Plan, provided that incentive stock options are granted only to employees. The exercise price of stock options and stock appreciation rights under the 2018 Incentive Plan will be fixed by the compensation committee, but must equal at least 100% of the fair market value of our Class A common stock on the date of grant. The term of an option or stock appreciation right may not exceed ten years; provided, however, that an incentive stock option held by an employee who owns more than 10% of all of our classes of stock, or of certain of our affiliates, may not have a term in excess of five years, and must have an exercise price of at least 110% of the fair market value of our Class A common stock on the grant date. Subject to the provisions of the 2018 Incentive Plan, the compensation committee will determine the remaining terms of the options and stock appreciation rights (e.g., vesting). Upon a participant’s termination of service, the participant may exercise his or her option or stock appreciation right, to the extent vested (unless the compensation committee permits otherwise), as specified in the award agreement.

 

    Stock Awards. Our compensation committee will decide at the time of grant whether an award will be in the form of restricted stock, restricted stock units, or other stock award. The compensation committee will determine the number of shares subject to the award, vesting, and the nature of any performance measures. Unless otherwise specified in the award agreement, the recipient of restricted stock will have voting rights and be entitled to receive dividends with respect to his or her shares of restricted stock. The recipient of restricted stock units will not have voting rights, but his or her award agreement may provide for the receipt of dividend equivalents. Our compensation committee may grant other stock awards that are based on or related to shares of our common stock, such as awards of shares of common stock granted as bonus and not subject to any vesting conditions, deferred stock units, stock purchase rights, and shares of our common stock issued in lieu of our obligations to pay cash under any compensatory plan or arrangement. Any dividends or dividend equivalents paid with respect to restricted stock, restricted stock units or other stock awards will be subject to the same vesting conditions as the underlying awards.

 

    Performance Awards. Our compensation committee will determine the value of any performance award, the vesting and nature of the performance measures, and whether the award is denominated or settled in cash or in shares of our common stock. The performance goals applicable to a particular award will be determined by our compensation committee at the time of grant.

 

    Transferability of Awards. The 2018 Incentive Plan does not allow awards to be transferred other than by will or the laws of inheritance following the participant’s death, and options may be exercised, during the lifetime of the participant, only by the participant. However, an award agreement may permit a participant to assign an award to a family member by gift or pursuant to a domestic relations order, or to a trust, family limited partnership or similar entity established for one of the participant’s family members. A participant may also designate a beneficiary who will receive outstanding awards upon the participant’s death.

 

   

Certain Adjustments. If any change is made in our common stock subject to the 2018 Incentive Plan, or subject to any award agreement under the 2018 Incentive Plan, without the receipt of consideration by us, such as through a stock split, stock dividend, extraordinary distribution, recapitalization,

 

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combination of shares, exchange of shares or other similar transaction, appropriate adjustments will be made in the number, class, and price of shares subject to each outstanding award and the numerical share limits contained in the plan.

 

    Change in Control. Subject to the terms of the applicable award agreement, upon a “change in control” (as defined in the 2018 Incentive Plan), our board of directors may, in its discretion, determine whether some or all outstanding options and stock appreciation rights will become exercisable in full or in part, whether the restriction period and performance period applicable to some or all outstanding restricted stock awards and restricted stock unit awards will lapse in full or in part and whether the performance measures applicable to some or all outstanding awards will be deemed to be satisfied. Our board of directors may further require that shares of stock of the corporation resulting from such a change in control, or a parent corporation thereof, be substituted for some or all of our shares of common stock subject to an outstanding award and that any outstanding awards, in whole or in part, be surrendered to us by the holder and be immediately cancelled by us in exchange for a cash payment, shares of capital stock of the corporation resulting from or succeeding us or a combination of both cash and such shares of stock.

 

    Clawback. Awards granted under the 2018 Incentive Plan and any cash payment or shares of our common stock delivered pursuant to an award are subject to forfeiture, recovery, or other action pursuant to the applicable award agreement or any clawback or recoupment policy that we may adopt.

 

    Plan Termination and Amendment. Our board of directors has the authority to amend, suspend, or terminate the 2018 Incentive Plan, subject to any requirement of stockholder approval required by law or stock exchange rules. Our 2018 Incentive Plan will terminate on the ten-year anniversary of its approval by our board of directors, unless we terminate it earlier.

 

    New Plan Benefits. The compensation committee has the discretion to grant awards under the 2018 Incentive Plan, and therefore it is not possible at the time of filing of this prospectus to determine future awards that will be received by our named executive officers or others under the 2018 Incentive Plan. All officers, directors, employees, consultants, agents and independent contractors are eligible for consideration to participate in the 2018 Incentive Plan.

 

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SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

The following table presents information regarding the beneficial ownership of our Class A common stock and Class B common stock following this offering and the other formation transactions by:

 

    each of our directors, director nominees and named executive officers;

 

    each stockholder known by us to beneficially hold 5% or more of any class of our voting securities; and

 

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

Beneficial ownership is determined under the rules of the SEC and generally includes voting or investment power with respect to securities. Unless otherwise noted, the address for each beneficial owner listed below is 807 Las Cimas Parkway, Suite 275, Austin, Texas 78746.

 

                            Combined Voting Power(2)  

Name of Beneficial Owner

  Class A
Common Stock
Beneficially
Owned(1)
    Percentage of
Class A
Common Stock
Beneficially
Owned(1)
    Class B
Common Stock
Beneficially
Owned
    Percentage of
Class B
Common Stock
Beneficially
Owned
    Common
Stock
Beneficially
Owned
    Percentage of
Common Stock
Beneficially
Owned
 

Remora Petroleum, L.P.

                                

Vendera Resources II, LLC and its affiliates(3)

                                

Vendera Resources III, L.P. and its affiliates(3)

                                

AVAD Energy Partners, LLC(4)

                                

Named Executive Officers and Directors:

           

George B. Peyton V

                                

Grant W. Livesay

                                

Jeffrey G. Shrader

                                

Sam C. Henry

                                

Aaron R. Stanley

                                

Dickie D. Hunter

                                

All directors, director nominees and executive officers as a group (         persons)

                                

 

*   Less than 1%

 

(1)   This table assumes the underwriters do not exercise their option to purchase additional shares of Class A common stock.
(2)   Represents percentage of voting power of Class A common stock and Class B common stock voting together as a single class. The holders of RH Units will hold one share of Class B common stock for each RH Unit.
(3)   The address for this beneficial owner is         .
(4)   The address for this beneficial owner is         .

 

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FORMATION TRANSACTIONS

Incorporation of Remora Royalties, Inc.

We were incorporated by our Operating Affiliate as a Delaware corporation in May 2018. Following this offering and the transactions related thereto, we will be a holding company whose sole material asset will consist of              RH Units. After the consummation of the transactions contemplated by this prospectus, we will be the managing member of Remora Holdings and will be responsible for all operational, management and administrative decisions relating to Remora Holdings’ business and will consolidate the financial results of Remora Holdings and its subsidiaries. The Limited Liability Company Agreement of Remora Holdings will be amended and restated as the Remora Holdings LLC Agreement to, among other things, admit us as the sole managing member of Remora Holdings.

In connection with this offering, (a) the Contributing Parties will contribute certain royalty interests to Remora Holdings in exchange for RH              Units and Remora Holdings’ assumption of approximately $         million of our Operating Affiliate’s indebtedness that burdens the royalty interests to be contributed by our Operating Affiliate, (b) we will contribute approximately $         of the net proceeds of this offering to Remora Holdings in exchange for              RH Units, (c) we will purchase              RH Units from the Contributing Parties in exchange for approximately $         of the net proceeds of this offering, and (d) each of the Contributing Parties will purchase from us one share of Class B common stock at par value for each RH Unit such Contributing Party holds.

After giving effect to these transactions and the offering contemplated by this prospectus, we will own an approximate     % interest in Remora Holdings (or     % if the underwriters’ option to purchase additional shares is exercised in full) and the Contributing Parties will own an approximate     % interest in Remora Holdings (or     % if the underwriters’ option to purchase additional shares is exercised in full) and all of the outstanding Class B common stock.

Each share of the Class B common stock has no economic rights but entitles its holder to one vote on all matters to be voted on by shareholders generally. Holders of Class A common stock and Class B common stock will vote together as a single class on all matters presented to our shareholders for their vote or approval, except as otherwise required by applicable law or by our certificate of incorporation. We do not intend to list Class B common stock on any stock exchange.

Following this offering, under the Remora Holdings LLC Agreement, the Contributing Parties will, subject to certain limitations, have the right to cause Remora Holdings to redeem all or a portion of their RH Units (together with a corresponding number of shares of Class B common stock) for Class A common stock (or the Cash Option) at a redemption ratio of one share of Class A common stock for each RH Unit (and corresponding share of Class B common stock) redeemed as described under “Certain Relationships and Related Party Transactions—Remora Holdings LLC Agreement.” Alternatively, upon the exercise of the Redemption Right, Remora Royalties, Inc. (instead of Remora Holdings) will have the right to, for administrative convenience, acquire each tendered RH Unit directly from the redeeming holder of RH Units for, at its election, (x) one share of Class A common stock or (y) an equivalent amount of cash. In addition, upon a change of control of Remora Royalties, Inc., Remora Royalties, Inc. has the right to require each holder of RH Units (other than Remora Royalties, Inc.) to exercise its Redemption Right with respect to some or all of such unitholder’s RH Units. In connection with any redemption of RH Units pursuant to the Redemption Right or our Call Right, the corresponding number of shares of Class B common stock will be cancelled. In addition, the Contributing Parties will have the right, under certain circumstances, to cause us to register the offer and sale of their shares of Class A common stock as described under “Certain Relationships and Related Party Transactions—Registration Rights Agreement.”

 

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The following diagram indicates our simplified ownership structure immediately prior to this offering and the transactions related thereto:

Simplified Current Ownership Structure

 

LOGO

The following diagram indicates our simplified ownership structure immediately following this offering and the transactions related thereto (assuming that the underwriters’ option to purchase additional shares is not exercised):

Simplified Ownership Structure After Giving Effect to this Offering

 

LOGO

 

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Offering

Only Class A common stock will be sold to investors pursuant to this offering. Immediately following this offering, there will be                  shares of Class A common stock issued and outstanding and                  shares of Class A common stock reserved for redemptions of RH Units and shares of Class B common stock pursuant to the Remora Holdings LLC Agreement. We estimate that our net proceeds from this offering, after deducting estimated underwriting discounts and commissions and other offering related expenses, will be approximately $         million. We intend to contribute approximately $         of the net proceeds from this offering to Remora Holdings in exchange for RH Units. We intend to use the remaining approximately $         net proceeds of this offering to purchase              RH Units from the Contributing Parties and to pay offering expenses. Remora Holdings will use approximately $         million, along with borrowings under our revolving credit facility, to repay in full approximately $         of our Operating Affiliate indebtedness that burdens the royalty interests to be contributed to Remora Holdings by our Operating Affiliate that we will assume in connection with the formation transactions. See “Use of Proceeds” for more information.

As a result of the formation transactions and the offering described above (and prior to any redemptions of RH Units):

 

    the investors in this offering will collectively own             shares of Class A common stock (or             shares of Class A common stock if the underwriters exercise in full their option to purchase additional shares of Class A common stock);

 

    we will hold              RH Units;

 

    the Contributing Parties will hold                  shares of Class B common stock and a corresponding number of RH Units;

 

    the investors in this offering will collectively hold     % of the voting power in us; and

 

    assuming no exercise of the underwriters’ option to purchase additional shares, the Contributing Parties will hold     % of the voting power in us (or     % if the underwriters exercise in full their option to purchase additional shares of Class A common stock).

Holding Company Structure

Our post-offering organizational structure will allow the holders of RH Units to have equity ownership in Remora Holdings, a partnership for U.S. federal income tax purposes. Investors in this offering will, by contrast, hold their equity ownership in the form of shares of Class A common stock in us, and we are classified as a domestic corporation for U.S. federal income tax purposes. We believe that the holders of RH Units find it advantageous to hold their equity interests in an entity that is not taxable as a corporation for U.S. federal income tax purposes. The holders of RH Units will generally incur U.S. federal, state and local income taxes on their proportionate share of any taxable income of Remora Holdings.

In addition, pursuant to our certificate of incorporation and the Remora Holdings LLC Agreement, our capital structure and the capital structure of Remora Holdings will generally replicate one another and will provide for customary antidilution mechanisms in order to maintain the one-for-one redemption ratio between the RH Units and our Class A common stock, among other things.

The holders of RH Units, including us, will generally incur U.S. federal, state and local income taxes on their proportionate share of any taxable income of Remora Holdings and will be allocated their proportionate share of any taxable loss of Remora Holdings. The Remora Holdings LLC Agreement will

 

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provide, to the extent cash is available, for distributions pro rata to the holders of RH Units if we, as the managing member of Remora Holdings, determine that the taxable income of Remora Holdings will give rise to taxable income for a unitholder. Generally, these tax distributions will be computed based on our estimate of the taxable income of Remora Holdings that is allocable to a holder of RH Units, multiplied by an assumed tax rate equal to the highest effective marginal combined U.S. federal, state and local income tax rate prescribed for an individual (or, if higher, a corporation) resident in Texas (taking into account the nondeductibility of certain expenses and the character of the allocated income).

 

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CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

The terms of the transactions and agreements disclosed in this section were determined by and among affiliated entities and, consequently, are not the result of arm’s length negotiations. These terms are not necessarily at least as favorable to the parties to these transactions and agreements as the terms that could have been obtained from unaffiliated third parties.

Dividends and Payments to the Contributing Parties and their Respective Affiliates

The following table summarizes the distributions and payments made or to be made by us to the Contributing Parties and their respective affiliates in connection with the formation, ongoing operation and any liquidation of us.

 

Formation Stage   

The consideration received by the Contributing Parties and their respective affiliates

  

 

•       shares of Class B common stock with respect to the Contributing Parties; and

 

•  We will distribute $     million of the net proceeds from this offering, after deducting the underwriting discount and structuring fee payable by us in connection with this offering, to the Contributing Parties. To the extent the underwriters exercise their option to purchase additional shares of Class A common stock, we will issue such shares to the public and use the net proceeds therefrom to purchase additional RH Units from the Contributing Parties.

  
Operational Stage   

Dividends and distributions to the Contributing Parties

   We will generally pay cash dividends to our Class A common stockholders, including any Contributing Parties, pro rata upon exercise of their Redemption Rights. After giving effect to the offering contemplated by this prospectus, the Contributing Parties will own              RH Units representing an approximate         % interest in Remora Holdings (or         % if the underwriters’ option to purchase additional shares is exercised in full), and a corresponding number of shares of Class B common stock. Under the Remora Holdings LLC Agreement, we will have the right to determine when distributions will be made to the holders of RH Units and the amount of any such distributions. Follow this offering, if we authorize a distribution, such distribution will be made to the holders of RH Units on a pro rata basis in accordance with their respective percentage ownership of RH Units.

Payments to our Operating Affiliate and its affiliates

   We and our affiliate Remora Holdings will enter into a management services agreement with our Operating Affiliate, pursuant to which our Operating Affiliate will provide management and administrative services to our affiliate Remora Holdings and us.

Agreements and Transactions with Affiliates in Connection with this Offering

In connection with this offering, we will enter into certain agreements and transactions with Remora Holdings, LLC and the Contributing Parties and their respective affiliates, as described in more detail below. These agreements and transactions are not the result of arm’s-length negotiations and they, or any of the transactions that they provide for, are not and may not be effected on terms at least as favorable to the

 

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parties to these agreements as could have been obtained from unaffiliated third parties. Because some of these agreements relate to formation transactions that, by their nature, would not occur in a third-party situation, it is not possible to determine what the differences would be in the terms of these transactions when compared to the terms of transactions with an unaffiliated third party. We believe the terms of these agreements to be comparable to the terms of agreements used in similarly structured transactions.

Remora Holdings LLC Agreement

The Remora Holdings LLC Agreement is filed as an exhibit to the registration statement of which this prospectus forms a part, and the following description of the Remora Holdings LLC Agreement is qualified in its entirety by reference thereto. In accordance with the terms of the Remora Holdings LLC Agreement, the holders of RH Units will generally have the right to redeem their RH Units (and a corresponding number of shares of our Class B common stock) for shares of our Class A common stock at a redemption ratio of one share of Class A common stock for each RH Unit (and corresponding share of Class B common stock) redeemed, subject to conversion rate adjustments for stock splits, stock dividends and reclassifications. At our or Remora Holdings’ election, Remora Holdings may give the redeeming holders of RH Units cash in an amount equal to the Cash Election Amount (as defined below) of such Class A common stock instead of shares of Class A common stock. We will be obligated to facilitate a redemption for Class A common stock through a contribution of Class A common stock to Remora Holdings or, alternatively, we will have the right to acquire the subject RH Units and corresponding Class B common stock from the holders of RH Units by paying, at our option, either (x) the number of shares of Class A common stock the holders of RH Units would have received in the proposed redemption or (y) cash in an amount equal to the Cash Election Amount of such Class A common stock. “Cash Election Amount” means, with respect to the Class A common stock to be delivered to an exchanging holder of RH Units by Remora Holdings pursuant to the Remora Holdings LLC Agreement, the amount that would be received (i) if such shares of Class A common stock were sold at a per share price equal to the trailing 30-day volume weighted average price of a share of Class A common stock or (ii) in the event shares of Class A common stock are not then publicly traded, the value that would be obtained in an arm’s length transaction for cash between an informed and willing buyer and an informed and willing seller, neither of whom is under any compulsion to purchase or sell, respectively, and without regard to the particular circumstances of the buyer and the seller, as determined by us. The holders of RH Units will be permitted to redeem their RH Units for shares of our Class A common stock on a quarterly basis, subject to certain de minimis allowances. In addition, any redemptions involving more than 2% of the outstanding RH Units (not taking into account RH Units owned by us and subject to our discretion to permit redemptions of a lower number of units) may occur at any time. In addition, upon a change of control of Remora Royalties, Remora Royalties has the right to require each holder of RH Units (other than Remora Royalties) to exercise its Redemption Right with respect to some or all of such unitholder’s RH Units. As the holders of RH Units redeem their RH Units, our membership interest in Remora Holdings will be correspondingly increased and the number of shares of Class B common stock outstanding will be reduced.

Under the Remora Holdings LLC Agreement, we will have the right to determine when distributions will be made to the holders of RH Units and the amount of any such distributions. Following this offering, if we authorize a distribution, such distribution will be made to the holders of RH Units on a pro rata basis in accordance with their respective percentage ownership of RH Units.

Remora Holdings will allocate its net income or net loss for each year to the holders of RH Units pursuant to the terms of the Remora Holdings LLC Agreement, and the holders of RH Units, including Remora Royalties, Inc., will generally incur U.S. federal, state and local income taxes on their share of any taxable income of Remora Holdings. Net income and losses of Remora Holdings generally will be allocated

 

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to the holders of RH Units on a pro rata basis in accordance with their respective percentage ownership of RH Units, subject to requirements under U.S. federal income tax law that certain items of income, gain, loss or deduction be allocated disproportionately in certain circumstances. To the extent Remora Holdings has available cash and subject to the terms of any future debt instruments, we intend to cause Remora Holdings to make (i) pro rata distributions to its unitholders, including us, in an amount sufficient to allow us to pay our taxes and (ii) tax advances, which will be repaid upon exercise of the Redemption Right or the Call Right, as applicable, in an amount sufficient to allow each of the RH Holders to pay its respective taxes on such holder’s allocable share of Remora Holdings’ taxable income after taking into account certain other distributions or payments received by the holders of RH Units from Remora Holdings.

The Remora Holdings LLC Agreement will provide that, except as otherwise determined by us, at any time we issue a share of our Class A common stock or any other equity security, the net proceeds received by us with respect to such issuance, if any, shall be concurrently invested in Remora Holdings, and Remora Holdings shall issue to us one RH Unit or other economically equivalent equity interest. Conversely, if at any time, any shares of our Class A common stock are redeemed, repurchased or otherwise acquired, Remora Holdings shall redeem, repurchase or otherwise acquire an equal number of RH Units held by us, upon the same terms and for the same price, as the shares of our Class A common stock are redeemed, repurchased or otherwise acquired.

Remora Holdings will be dissolved only upon the first to occur of (i) the sale of substantially all of its assets or (ii) an election by us to dissolve the company. Upon dissolution, Remora Holdings will be liquidated and the proceeds from any liquidation will be applied and distributed in the following manner: (a) first, to creditors (including to the extent permitted by law, creditors who are members) in satisfaction of the liabilities of Remora Holdings, (b) second, to establish cash reserves for contingent or unforeseen liabilities and (c) third, to the members in proportion to the number of RH Units owned by each of them.

Registration Rights Agreement

In connection with the closing of this offering, we will enter into a registration rights agreement with the Contributing Parties. We expect that the agreement will contain provisions by which we agree to register under the federal securities laws the sale of shares of our Class A common stock by such Contributing Parties or certain of their affiliates. These registration rights will be subject to certain conditions and limitations. We will generally be obligated to pay all registration expenses in connection with these registration obligations, regardless of whether a registration statement is filed or becomes effective.

Contribution Agreement

In connection with this offering, we will enter into a contribution agreement with the Contributing Parties that will affect the transfer of the royalty interests owned by the Contributing Parties to us and the use of the net proceeds of this offering, and also address our right of first offer to acquire royalty interests owned by certain of the Contributing Parties for a period of three years after the closing of this offering.

Management Services Agreement

In connection with the closing of this offering, we will enter into a management services agreement with our Operating Affiliate, pursuant to which our Operating Affiliate will provide management, administrative, operational and acquisition services to us.

 

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Procedures for Review, Approval and Ratification of Transactions with Related Persons

Prior to the closing of this offering, we have not maintained a policy for approval of Related Party Transactions. A “Related Party Transaction” is a transaction, arrangement or relationship in which we or any of our 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 material interest. A “Related Person” means:

 

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

 

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

 

    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 Class A 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 Class A common stock; and

 

    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.

We anticipate that 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.

 

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DESCRIPTION OF CAPITAL STOCK

Upon completion of this offering, the authorized capital stock of Remora Royalties, Inc. will consist of shares of Class A common stock, $0.01 par value per share, of which          shares will be issued and outstanding shares of Class B common stock, $0.01 par value per share, of which          shares will be issued and outstanding, and          shares of preferred stock, $0.01 par value per share, of which no shares will be issued and outstanding.

The following summary of the capital stock and certificate of incorporation and bylaws of Remora Royalties, 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.

Class A Common Stock

Voting Rights. Holders of shares of Class A common stock are entitled to one vote per share held of record on all matters to be voted upon by the shareholders. The holders of Class A common stock do not have cumulative voting rights in the election of directors.

Dividend Rights. Holders of shares of our Class A common stock are entitled to ratably receive dividends when and if declared by our board of directors out of funds legally available for that purpose, subject to any statutory or contractual restrictions on the payment of dividends and to any prior rights and preferences that may be applicable to any outstanding preferred stock.

Liquidation Rights. Upon our liquidation, dissolution, distribution of assets or other winding up, the holders of Class A common stock are entitled to receive ratably the assets available for distribution to the shareholders after payment of liabilities and the liquidation preference of any of our outstanding shares of preferred stock.

Other Matters. The shares of Class A common stock have no preemptive or conversion rights and are not subject to further calls or assessment by us. There are no redemption or sinking fund provisions applicable to the Class A common stock. All outstanding shares of our Class A common stock, including the Class A common stock offered in this offering, are fully paid and non-assessable.

Class B Common Stock

Generally. In connection with the formation transactions and this offering, the holders of RH Units will receive one share of Class B common stock for each RH Unit that they hold. Accordingly, the holders of RH Units will have a number of votes in Remora Royalties, Inc. equal to the aggregate number of RH Units that they hold.

Voting Rights. Holders of shares of our Class B common stock are entitled to one vote per share held of record on all matters to be voted upon by the shareholders. Holders of shares of our Class A common stock and Class B common stock vote together as a single class on all matters presented to our shareholders for their vote or approval, except with respect to the amendment of certain provisions of our amended and restated certificate of incorporation that would alter or change the powers, preferences or special rights of the Class B common stock so as to affect them adversely, which amendments must be by a majority of the votes entitled to be cast by the holders of the shares affected by the amendment, voting as a separate class, or as otherwise required by applicable law.

Dividend and Liquidation Rights. Holders of our Class B common stock do not have any right to receive dividends, unless the dividend consists of shares of our Class B common stock or of rights, options, warrants or other securities convertible or exercisable into or exchangeable for shares of Class B common

 

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stock paid proportionally with respect to each outstanding share of our Class B common stock and a dividend consisting of shares of Class A common stock or of rights, options, warrants or other securities convertible or exercisable into or exchangeable for shares of Class A common stock on the same terms is simultaneously paid to the holders of Class A common stock.

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, par value $0.01 per share, 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 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 described below 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, summarized below, 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 NASDAQ, 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.

 

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We intend to elect to not be subject to the provisions of Section 203 of the DGCL in our certificate of incorporation. However, our certificate of incorporation will provide that in the event our Operating Affiliate ceases to beneficially own at least 10% of the then outstanding shares of our Class A common stock, we will automatically become subject to Section 203 of the DGCL.

Under certain circumstances, Section 203 makes it more difficult for a person who would be an “interested stockholder” to effect various business combinations with a corporation for a three-year period. Accordingly, Section 203 could have an anti-takeover effect with respect to certain transactions our board of directors does not approve in advance. The provisions of Section 203 may encourage companies interested in acquiring us to negotiate in advance with our board of directors because the stockholder approval requirement would be avoided if our board of directors approves either the business combination or the transaction that results in the stockholder becoming an interested stockholder. However, Section 203 also could discourage attempts that might result in a premium over the market price for the shares of our Class A common stock held by Class A common stockholders. These provisions also may make it more difficult to accomplish transactions that Class A common stockholders may otherwise deem to be in their best interests.

Our Certificate of Incorporation and Our Bylaws

Provisions of our certificate of incorporation and 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 Class A 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. 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 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 us. These and other provisions may have the effect of deferring hostile takeovers or delaying changes in control or management of our company;

 

    provide that subject to the rights of the holders of any series of preferred stock to elect directors under specified circumstances, the authorized number of directors may be changed only by resolution of the board of directors;

 

    provide that 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 that 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

 

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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;

 

    provide our certificate of incorporation and bylaws may be amended by the affirmative vote of the holders of at least 66 23% of our then outstanding Class A common stock;

 

    provide that special meetings of our stockholders may only be called by the board of directors (pursuant to a resolution adopted by a majority of the board), the chief executive officer or the chairman of the board;

 

    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 or repealed at any regular or special meeting of stockholders or by the board of directors.

Corporate Opportunity

Our certificate of incorporation will provide that, to the extent permitted by applicable law, we, on our behalf and on behalf of our subsidiaries, renounce any interest or expectancy in, or in being offered an opportunity to participate in, corporate opportunities, that are from time to time presented to (1) the Contributing Parties or any of their respective affiliates or any of their respective agents, shareholders, members, partners, directors, officers, employees, affiliates or subsidiaries (other than us and our subsidiaries) or (2) directors of the Company who are not employees of the Company or our Operating Affiliate (each, a “Business Opportunities Exempt Party”), even if the opportunity is one that we or our subsidiaries might reasonably be deemed to have pursued or had the ability or desire to pursue if granted the opportunity to do so. No Business Opportunities Exempt Party will have any duty to communicate or offer such corporate opportunity to the Company and will generally not be liable to us or any of our subsidiaries for breach of any fiduciary or other duty, as a director or otherwise, by reason of the fact that such person pursues or acquires such corporate opportunity, directs such corporate opportunity to another person or fails to present such corporate opportunity, or information regarding such corporate opportunity, to us or our subsidiaries unless, in the case of any such person who is a director or officer of the Company, such corporate opportunity is expressly offered to such director or officer in writing solely in his or her capacity as a director or officer of the Company. Stockholders will be deemed to have notice of and consented to this provision of our certificate of incorporation.

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

 

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    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.

Limitation of Liability and Indemnification Matters

Our certificate of incorporation will limit 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 a 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 will also provide that we will indemnify our directors and officers to the fullest extent permitted by Delaware law. Our bylaws also will 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.

Registration Rights

For a description of registration rights with respect to our Class A common stock, see the information under the heading “Certain Relationships and Related Party Transactions—Registration Rights Agreement.”

 

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Transfer Agent and Registrar

The transfer agent and registrar for our Class A common stock is             .

Listing

We have applied to list our Class A common stock on the NASDAQ under the symbol “RRI.”

 

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SHARES ELIGIBLE FOR FUTURE SALE

Prior to this offering, there has been no public market for our Class A common stock. Future sales of our Class A 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 Class A common stock prevailing from time to time. As described below, only a limited number of shares 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 Class A 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 Class A 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

Upon the closing of this offering, we will have outstanding an aggregate of          shares of Class A common stock. Of these shares, all of the shares of Class A common stock to be sold in this offering 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 Class A common stock held by existing stockholders will be deemed “restricted securities” as such term is defined under Rule 144. The restricted securities were 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.

In addition, subject to certain limitations and exceptions, pursuant to the terms of the Remora Holdings LLC Agreement, holders of RH Units will each have the right to redeem all or a portion of their RH Units (together with a corresponding number of shares of Class B common stock) for Class A common stock (or the Cash Option) at a redemption ratio of one share of Class A common stock for each RH Unit (and corresponding share of Class B common stock) redeemed, subject to conversion rate adjustments for stock splits, stock dividends and reclassifications. Upon consummation of this offering, the holders of RH Units will hold          RH Units, all of which (together with a corresponding number of shares of our Class B common stock) will be redeemable for          shares of our Class A common stock. See “Certain Relationships and Related Party Transactions—Remora Holdings LLC Agreement.” The shares of Class A common stock we issue upon such redemptions would be “restricted securities” as defined in Rule 144 described below. However, upon the closing of this offering, we intend to enter into a registration rights agreement with certain Contributing Parties that will require us to register under the Securities Act these shares of Class A common stock.

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 Class A 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 (subject to extension) and when permitted under Rule 144 or Rule 701.

Lock-up Agreements

We, all of our directors, director nominees and executive officers and certain of our stockholders and employees have agreed or will agree that, subject to certain exceptions and under certain conditions, for a period of 180 days after the date of this prospectus, we and they will not, without the prior written consent

 

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of                                 , dispose of or hedge any shares or any securities convertible into or exchangeable for shares of our capital stock. Please read “Underwriting” 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 at least six 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 then outstanding shares of our Class A common stock or the average weekly trading volume of our Class A common stock reported through the NYSE 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, director nominees officers, consultants or advisors who purchase or otherwise receive shares from us in connection with a compensatory stock or option plan or other written agreement before the effective date of this offering are 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 issuable under our 2018 Stock and Incentive Plan. 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 may be made 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.

 

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MATERIAL U.S. FEDERAL INCOME TAX CONSEQUENCES

The following is a summary of the material U.S. federal income tax considerations related to the purchase, ownership and disposition of our Class A common stock by a non-U.S. holder (as defined below), that holds our Class A common stock as a “capital asset” (generally property held for investment). This summary is based on the provisions of the U.S. Internal Revenue Code of 1986 as amended (the “Code”), U.S. Treasury regulations and 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 (“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 gift or estate 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 (without limitation):

 

    banks, insurance companies or other financial institutions;

 

    tax-exempt or governmental organizations;

 

    qualified foreign pension funds (or any entities all of the interests of which are held by a qualified foreign pension fund);

 

    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 Class A 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;

 

    real estate investment trusts or regulated investment companies; and

 

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

THIS DISCUSSION IS FOR INFORMATIONAL PURPOSES ONLY AND IS NOT TAX ADVICE. PROSPECTIVE INVESTORS ARE ENCOURAGED TO CONSULT THEIR TAX ADVISORS WITH RESPECT TO THE APPLICATION OF THE U.S. FEDERAL INCOME TAX LAWS TO THEIR PARTICULAR SITUATION, AS WELL AS ANY TAX CONSEQUENCES OF THE PURCHASE, OWNERSHIP AND DISPOSITION OF OUR CLASS A COMMON STOCK ARISING UNDER THE U.S. FEDERAL GIFT OR ESTATE TAX LAWS OR UNDER THE LAWS OF ANY STATE, LOCAL, NON-U.S. OR OTHER TAXING JURISDICTION OR UNDER ANY APPLICABLE 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 Class A 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 Class A common stock, the tax treatment of a partner in the partnership generally will depend upon the status of the partner, the activities of the partnership and 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 Class A 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

Distributions of cash or property on our common stock 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 nontaxable return of capital to the extent of the non-U.S. holder’s tax basis in our Class A common stock and thereafter as capital gain from the sale or exchange of such Class A common stock. Please read “—Sales or other Taxable Dispositions.” Subject to the withholding rules under FATCA (as defined below) and with respect to effectively connected dividends, each of which is discussed below, any distribution made to a non-U.S. holder on our Class A 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.

If dividends paid to a non-U.S. holder 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), the non-U.S. holder will be exempt from U.S. withholding tax described above, provided the non-U.S. holder satisfies certain certification requirements by providing the applicable withholding agent a properly executed IRS Form W-8ECI certifying eligibility for exemption. Any such effectively connected dividends 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). 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. Non-U.S. holders should consult their tax advisors regarding any applicable tax treaties that may provide for different rules.

 

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Sales or other Taxable Disposition

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 Class A 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 Class A common stock constitutes a United States real property interest by reason of our status as a United States real property holding corporation (“USRPHC”) for U.S. federal income tax purposes and, as a result, such gain is treated as effectively connected with a trade or business conducted by the non-U.S. holder in the United States.

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, provided the non-U.S. holder has timely filed U.S. federal income tax returns with respect to such 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 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 United States 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 Class A 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 Class A common stock, more than 5% of our Class A 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 Class A common stock were not considered to be regularly traded on an established securities market, such holder (regardless of the percentage of our Class A common stock owned) would be subject to U.S. federal income tax on a taxable disposition of our Class A common stock (as described in the preceding paragraph), and a 15% withholding tax would apply to the gross proceeds from such disposition.

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 Class A 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

 

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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.

Payments of the proceeds from a sale or other disposition by a non-U.S. holder of our Class A 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 Class A 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 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 Class A 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 backup 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 (“FATCA”), impose a 30% withholding tax on any dividends paid on our common stock and on the gross proceeds from a disposition of our Class A 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 identifying the direct and indirect substantial United States owners of the entity (in either case, generally on an IRS Form W-8BEN- E); 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.

INVESTORS CONSIDERING THE PURCHASE OF OUR CLASS A 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 GIFT AND ESTATE TAX LAWS AND ANY STATE, LOCAL OR NON-U.S. TAX LAWS AND TAX TREATIES.

 

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UNDERWRITING

Underwriting

RBC Capital Markets, LLC, Wells Fargo Securities, LLC and UBS Securities LLC are acting as joint book-running managers of the offering and representatives of the underwriters named below. Subject to the terms and conditions stated in the underwriting agreement dated the date of this prospectus, each underwriter named below has severally and not jointly agreed to purchase, and we have agreed to sell to that underwriter, the number of shares of Class A common stock set forth opposite the underwriter’s name.

 

Underwriter

   Shares
of
Class A
Common
Stock
 

RBC Capital Markets, LLC

  

Wells Fargo Securities, LLC

  

UBS Securities LLC

  
  

 

 

 

Total

  
  

 

 

 

The underwriting agreement provides that the obligations of the underwriters to purchase the shares of Class A common stock included in this offering are subject to approval of legal matters by counsel and to other conditions. The underwriters are obligated to purchase all of the shares of Class A common stock (other than those covered by the over- allotment option described below) if they purchase any of the shares of Class A common stock.

Class A common stock sold by the underwriters to the public will initially be offered at the initial public offering price set forth on the cover of this prospectus. Any Class A common stock sold by the underwriters to securities dealers may be sold at a discount from the initial public offering price not to exceed $         per share. If all the shares of Class A common stock are not sold at the initial offering price, the underwriters may change the offering price and the other selling terms. The representatives have advised us that the underwriters do not intend to make sales to discretionary accounts.

Underwriting discounts and commissions

The following table shows the underwriting discounts and commissions that we are to pay to the underwriters in connection with this offering. These amounts are shown assuming both no exercise and full exercise of the underwriters’ over-allotment option.

 

     Paid by the Company  
     No Exercise      Full Exercise  

Per share

   $                   $               

Total

   $      $  

Indemnification

We have agreed to indemnify the underwriters against certain liabilities, including liabilities under the Securities Act, or to contribute to payments the underwriters may be required to make because of any of those liabilities.

 

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Overallotment Option to Purchase Additional Class A Common Stock

If the underwriters sell more shares of common stock than the total number set forth in the table above, we have granted to the underwriters an option, exercisable for 30 days from the date of this prospectus, to purchase up to                     additional shares of Class A common stock at the public offering price less the underwriting discount. The underwriters may exercise the option solely for the purpose of covering over-allotments, if any, in connection with this offering. To the extent the option is exercised, each underwriter must purchase a number of additional Class A shares approximately proportionate to that underwriter’s initial purchase commitment. Any Class A common stock issued or sold under the option will be issued and sold on the same terms and conditions as the other shares of Class A common stock that are the subject of this offering. If the underwriters exercise their option to purchase additional Class A shares, we will issue such shares to the public and use the net proceeds therefrom to purchase additional RH Units and Class B shares, on a pro rata basis, from the Contributing Parties.

Lock-Ups

We, our Operating Affiliate and our executive officers and directors have agreed that, for a period of 180 days from the date of this prospectus, we and they will not, without the prior written consent of             , dispose of or hedge any Class A common stock or any securities convertible into or exchangeable for shares of our Class A common stock. The representatives in their sole discretion may release any of the securities subject to these lock-up agreements at any time, which, in the case of officers and directors, shall be with notice.

Determination of Offering Price

Prior to this offering, there has been no public market for our Class A common stock. Consequently, the initial public offering price for the Class A common stock was determined by negotiations between us and the representatives. Among the factors considered in determining the initial public offering price were our results of operations, our current financial condition, our future prospects, our markets, the economic conditions in and future prospects for the industry in which we compete, our management, and currently prevailing general conditions in the equity securities markets, including current market valuations of publicly traded companies considered comparable to our company. We cannot assure you, however, that the price at which the Class A common stock will sell in the public market after this offering will not be lower than the initial public offering price or that an active trading market in our Class A common stock will develop and continue after this offering.

Listing

We have applied to have our Class A common stock listed on the NASDAQ under the symbol “RRI.”

Expenses and Reimbursements

We estimate that our portion of the total expenses of this offering will be $        . We have agreed to reimburse the underwriters up to $         for expenses for counsel related to any filing with, and any clearance of this offering by, the Financial Industry Regulatory Authority (“FINRA”).

Price Stabilization, Short Positions and Penalty Bids

In connection with the offering, the underwriters may purchase and sell shares of Class A common stock in the open market. Purchases and sales in the open market may include short sales, purchases to

 

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cover short positions, which may include purchases pursuant to the over-allotment option, and stabilizing purchases.

 

    Short sales involve secondary market sales by the underwriters of a greater number of shares than they are required to purchase in the offering.

 

    “Covered” short sales are sales of Class A common stock in an amount up to the number of shares of Class A common stock represented by the underwriters’ over-allotment option.

 

    “Naked” short sales are sales of Class A common stock in an amount in excess of the number of shares of Class A common stock represented by the underwriters’ over-allotment option.

 

    Covering transactions involve purchases of Class A common stock either pursuant to the underwriters’ over- allotment option or in the open market in order to cover short positions.

 

    To close a naked short position, the underwriters must purchase Class A common stock in the open market. A naked short position is more likely to be created if the underwriters are concerned that there may be downward pressure on the price of the Class A common stock in the open market after pricing that could adversely affect investors who purchase in the offering.

 

    To close a covered short position, the underwriters must purchase Class A common stock in the open market or must exercise the over-allotment option. In determining the source of Class A common stock to close the covered 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 the over-allotment option.

 

    Stabilizing transactions involve bids to purchase Class A common stock so long as the stabilizing bids do not exceed a specified maximum.

Purchases to cover short positions and stabilizing purchases, as well as other purchases by the underwriters for their own accounts, may have the effect of preventing or retarding a decline in the market price of the Class A common stock. They may also cause the price of the Class A common stock to be higher than the price that would otherwise exist in the open market in the absence of these transactions. The underwriters may conduct these transactions on the NASDAQ, in the over-the-counter market or otherwise. If the underwriters commence any of these transactions, they may discontinue them at any time.

Electronic Distribution

In connection with the offering, certain of the underwriters or securities dealers may distribute prospectuses by electronic means, such as e-mail.

Other Relationships

The underwriters are full service financial institutions engaged in various activities, which may include securities trading, commercial and investment banking, financial advisory, investment management, principal investment, hedging, financing and brokerage activities. Certain of the underwriters and their respective affiliates have in the past performed commercial banking, investment banking and advisory services for us from time to time for which they have received customary fees and reimbursement of expenses and may, from time to time, engage in transactions with and perform services for us in the ordinary course of their business for which they may receive customary fees and reimbursement of expenses. 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 (which may include bank loans and/or credit default swaps) for their own account and for the accounts of their customers and may at any time hold long and

 

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short positions in such securities and instruments. Such investments and securities activities may involve securities and/or instruments of ours or our affiliates. In addition, we anticipate affiliates of some of the

underwriters will be lenders, and in some cases agents or managers for the lenders, under our new secured revolving credit facility. Certain of the underwriters or their affiliates that may have a lending relationship with us routinely hedge their credit exposure to us consistent with their customary risk management policies. A typical such hedging strategy would include these underwriters or their affiliates hedging such exposure by entering into transactions which consist of either the purchase of credit default swaps or the creation of short positions in our securities. The underwriters and their affiliates may also make investment recommendations and/or publish or express independent research views in respect of such securities or financial instruments and may hold, or recommend to clients that they acquire, long and/or short positions in such securities and instruments.

Sales Outside the United States

No action has been taken in any jurisdiction (except in the United States) that would permit a public offering of our common stock, or the possession, circulation or distribution of this prospectus or any other material relating to us or our Class A common stock in any jurisdiction where action for that purpose is required. Accordingly, the common stock may not be offered or sold, directly or indirectly, and neither this prospectus nor any other offering material or advertisements in connection with our Class A common stock may be distributed or published, in or from any country or jurisdiction, except in compliance with any applicable rules and regulations of any such country or jurisdiction.

The underwriters may arrange to sell the shares of common stock offered hereby in certain jurisdictions outside the United States, either directly or through affiliates, where it is permitted to do so.

 

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LEGAL MATTERS

The validity of our Class A common stock and certain other legal matters will be passed upon for us by Sidley Austin LLP, Houston, Texas. Certain legal matters in connection with this offering will be passed upon for the underwriters by Latham & Watkins LLP, Houston, Texas.

EXPERTS

The audited balance sheet of Remora Royalties, Inc. included in this prospectus and elsewhere in the registration statement has been so included in reliance upon the report of Grant Thornton LLP, independent registered public accountants, upon the authority of said firm as experts in accounting and auditing.

The audited financial statements of Remora Petroleum, L.P. included in this prospectus and elsewhere in the registration statement have been so included in reliance upon the report of Grant Thornton LLP, independent registered public accountants, upon the authority of said firm as experts in accounting and auditing.

The audited statements of revenues and direct operating expenses of certain oil and gas properties owned by Vendera Resources II, LLC and its affiliates included in this prospectus and elsewhere in the registration statement have been so included in reliance upon the report of Grant Thornton LLP, independent certified public accountants, upon the authority of said firm as experts in accounting and auditing.

The audited statements of revenues and direct operating expenses of certain oil and gas properties owned by Vendera Resources III, L.P. and its affiliates included in this prospectus and elsewhere in the registration statement have been so included in reliance upon the report of Grant Thornton LLP, independent certified public accountants, upon the authority of said firm as experts in accounting and auditing.

The audited statements of revenues and direct operating expenses of certain oil and gas properties owned by AVAD Energy Partners, LLC included in this prospectus and elsewhere in the registration statement have been so included in reliance upon the report of Grant Thornton LLP, independent certified public accountants, upon the authority of said firm as experts in accounting and auditing.

The audited statements of revenues and direct operating expenses of certain oil and gas properties of the 2017 South Texas Assets included in this prospectus and elsewhere in the registration statement have been so included in reliance upon the report of Grant Thornton LLP, independent certified public accountants, upon the authority of said firm as experts in accounting and auditing.

The audited statement of revenues and direct operating expenses of certain oil and gas properties of the 2016 Midcontinent Assets included in this prospectus and elsewhere in the registration statement have been so included in reliance upon the report of Grant Thornton LLP, independent certified public accountants, upon the authority of said firm as experts in accounting and auditing.

Information included in this prospectus regarding our estimated quantities of oil and natural gas reserves as of December 31, 2017 and 2016 and the discounted present value of future net cash flows therefrom is based upon estimates of such reserves and present values prepared by Cawley, Gillespie & Associates, Inc., an independent petroleum engineering firm. This information is included herein in reliance upon the authority of said firm as experts in these matters.

 

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Change In Accountants

On July 11, 2017 the General Partner of our predecessor approved the dismissal of Hein & Associates LLP (“Hein”) as our independent public accounting firm. Hein’s audit report on our financial statements for the fiscal year ended December 31, 2016 did not contain an adverse opinion or disclaimer of opinion, nor was such report qualified or modified as to uncertainty, audit scope or accounting principles. During our two most recent fiscal years, (i) there were no disagreements with Hein on any matter of accounting principles or practices, financial statement disclosure or auditing scope or procedures, which disagreements, if not resolved to Hein’s satisfaction, would have caused Hein to make reference to the subject matter or the disagreement in connection with its report and (ii) there were no “reportable events,” as that term is described in Item 304(a)(1)(v) of Regulation S-K.

On July 11, 2017, we engaged Grant Thornton LLP (“Grant Thornton”) to serve as our independent registered public accounting firm to audit the fiscal years ended December 31, 2016 and 2015 in accordance with PCAOB Standards. The engagement of Grant Thornton was approved by our general partner of our predecessor. During the two most recent fiscal years, neither we, nor anyone acting on our behalf, consulted with Grant Thornton regarding either (i) the application of accounting principles to a specified transaction, either completed or proposed, or the type of audit opinion that might be rendered on our financial statements, and no written report nor oral advice was provided by Grant Thornton, or (ii) any matter that was either the subject of a disagreement, as that term is defined in Item 304(a)(1)(iv) of Regulation S-K, or a reportable event, as that term is defined in Item 304(a)(1)(v) of Regulation S-K.

We requested that Hein furnish us a letter addressed the SEC stating whether it agrees with the above statements. A copy of that letter is filed as Exhibit 16.1 to the Registration Statement of which this Prospectus forms a part.

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 our common stock being offered hereunder. This prospectus does not contain all of the information set forth in the registration statement and the exhibits and schedules to the registration statement. For further information with respect to us and our common stock, we refer you to the registration statement and the exhibits filed as a part of the registration statement. Statements contained in this prospectus concerning the contents of any contract or any other documents are not necessarily complete. If a contract or document has been filed as an exhibit to the registration statement, we refer you to the copy of the contract or document that has been filed as an exhibit and reference thereto is qualified in all respects by the terms of the filed exhibit. The registration statement, including any exhibits and schedules, may be inspected without charge at the Public Reference Room of the SEC at 100 F Street, N.E., Washington, D.C. 20549, and copies of these materials may be obtained from that office after payment of fees prescribed by the SEC. Information on the operation of the Public Reference Room may be obtained by calling the SEC at 1-800- SEC-0330. The SEC maintains a web site that contains reports, proxy and information statements and other information regarding registrants that file electronically with the SEC at http://www.sec.gov.

As a result of this offering, we will become subject to the full informational requirements of the Exchange Act. We will fulfill our obligations with respect to such requirements by filing period reports and other information with the SEC.

 

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FORWARD-LOOKING STATEMENTS

This prospectus contains forward-looking statements. Forward-looking statements give our current expectations, contain projections of results of operations or of financial condition, or forecasts of future events. Words such as “may,” “assume,” “forecast,” “position,” “predict,” “strategy,” “expect,” “intend,” “plan,” “estimate,” “anticipate,” “believe,” “project,” “budget,” “potential,” or “continue,” and similar expressions are used to identify forward-looking statements. They can be affected by assumptions used or by known or unknown risks or uncertainties. Consequently, no forward-looking statements can be guaranteed. When considering these forward- looking statements, you should keep in mind the risk factors and other cautionary statements in this prospectus. Actual results may vary materially. You are cautioned not to place undue reliance on any forward-looking statements. You should also understand that it is not possible to predict or identify all such factors and should not consider the following list to be a complete statement of all potential risks and uncertainties. Factors that could cause our actual results to differ materially from the results contemplated by such forward-looking statements include:

 

    our ability to execute our business strategies;

 

    the volatility of realized prices for oil, natural gas and NGLs;

 

    the level of production on our properties;

 

    the level of drilling and completion activity by the operators of our properties;

 

    regional supply and demand factors, delays or interruptions of production;

 

    our ability to replace our reserves;

 

    our ability to identify and complete acquisitions of assets or businesses;

 

    general economic, business or industry conditions;

 

    competition in the oil and natural gas industry;

 

    the ability of the operators of our properties to obtain capital or financing needed for development and exploration operations;

 

    title defects in the properties in which we invest;

 

    uncertainties with respect to identified drilling locations and estimates of reserves;

 

    the availability or cost of rigs, completion crews, equipment, raw materials, supplies, oilfield services or personnel;

 

    restrictions on or the availability of the use of water in the business of the operators of our properties;

 

    the availability of transportation facilities;

 

    the ability of the operators of our properties to comply with applicable governmental laws and regulations and to obtain permits and governmental approvals;

 

    federal and state legislative and regulatory initiatives relating to the environment, hydraulic fracturing and other matters affecting the oil and natural gas industry;

 

    future operating results;

 

    exploration and development drilling prospects, inventories, projects and programs;

 

    operating hazards faced by the operators of our properties;

 

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    the ability of the operators of our properties to keep pace with technological advancements; and

 

    certain factors discussed elsewhere in this prospectus.

All forward-looking statements are expressly qualified in their entirety by the foregoing cautionary statements.

 

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APPENDIX A — GLOSSARY OF TERMS

The following are definitions of certain terms used in this prospectus.

Basin. A large depression on the earth’s surface in which sediments accumulate.

Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume.

Bcfe. One billion cubic feet equivalent, which is a unit of measurement of volume for natural gas.

Boe. Barrels of oil equivalent, with six thousand cubic feet of natural gas being equivalent to one barrel of oil.

Boe/d. Boe per day.

British Thermal Unit (Btu). The quantity of heat required to raise the temperature of one pound of water by one degree Fahrenheit.

Condensate. A mixture of hydrocarbons that exists in the gaseous phase at original reservoir temperature and pressure, but that, when produced, is in the liquid phase at surface pressure and temperature.

Crude oil. Liquid hydrocarbons retrieved from geological structures underground to be refined into fuel sources.

Deterministic method. The method of estimating reserves or resources under which a single value for each parameter (from the geoscience, engineering, or economic data) in the reserves calculation is used in the reserves estimation procedure.

Development costs. Capital costs incurred in the acquisition, exploitation and exploration of proved oil and natural gas reserves divided by proved reserve additions and revisions to proved reserves. For a complete definition of development costs, refer to the SEC’s Regulation S-X, Rule 4-10(a)(7).

Development well. A well drilled within the proved area of an oil and natural gas reservoir to the depth of a stratigraphic horizon known to be productive.

Differential. An adjustment to the price of oil or natural gas from an established spot market price to reflect differences in the quality and/or location of oil or natural gas.

Dry hole or dry well. A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes.

Economically producible. A resource that generates revenue that exceeds, or is reasonably expected to exceed, the costs of the operation.

Electrical log. Provide information on porosity, hydraulic conductivity, and fluid content of formations drilled in fluid-filled boreholes.

Exploration. A drilling or other project which may target proven or unproven reserves (such as probable or possible reserves).

Extension well. A well drilled to extend the limits of a known reservoir.

Field. An area consisting of either a single reservoir or multiple reservoirs, all grouped on or related to the same individual geological structural feature and/or stratigraphic condition.

Formation. A layer of rock which has distinct characteristics that differs from nearby rock.

Fracturing. The process of creating and preserving a fracture or system of fractures in a reservoir rock typically by injecting a fluid under pressure through a wellbore and into the targeted formation.

 

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Gross acres or gross wells. The total acres or wells, as the case may be, in which a working interest is owned.

Horizontal drilling. A drilling technique used in certain formations where a well is drilled vertically to a certain depth and then drilled at a right angle within a specified interval.

Hydraulic fracturing. A process used to stimulate production of hydrocarbons. The process involves the injection of water, sand and chemicals under pressure into the formation to fracture the surrounding rock and stimulate production.

Lease bonus. Usually a one-time payment made to a mineral owner as consideration for the execution of an oil and natural gas lease.

Lease operating expense. 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 include labor, superintendence, supplies, repairs, maintenance, allocated overhead charges, workover, insurance and other expenses incidental to production, but exclude lease acquisition or drilling or completion expenses.

MBbls. One thousand barrels of oil or other liquid hydrocarbons.

Mcf. One thousand cubic feet of natural gas.

Mcfe. One thousand cubic feet equivalent, which is a unit of measurement of volume for natural gas.

Mineral interests. Real-property interests that grant ownership of the oil and natural gas under a tract of land and the rights to explore for, drill for and produce oil and natural gas on that land or to lease those exploration and development rights to a third party.

MMBtu. One million British Thermal Units.

MMcf. One million cubic feet of natural gas.

MMcfe. One million cubic feet equivalent, which is a unit of measurement of volume for natural gas.

MMcfe/d. MMcfe per day.

Net acres. The sum of the fractional working interest owned in gross acres.

Net revenue interest. An owner’s interest in the revenues of a well after deducting proceeds allocated to royalty, overriding royalty and other non-cost-bearing interests.

Natural gas. A combination of light hydrocarbons that, in average pressure and temperature conditions, is found in a gaseous state. In nature, it is found in underground accumulations, and may potentially be dissolved in oil or may also be found in its gaseous state.

Natural gas liquids or NGLs. Hydrocarbons found in natural gas which may be extracted as liquefied petroleum gas and natural gasoline.

Nonparticipating royalty interest. A type of non-cost-bearing royalty interest, which is carved out of the mineral interest and represents the right, which is typically perpetual, to receive a fixed cost-free percentage of production or revenue from production, without an associated right to lease.

Oil. Crude oil and condensate.

Oil and natural gas properties. Tracts of land consisting of properties to be developed for oil and natural gas resource extraction.

 

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Operator. The individual or company responsible for the exploration and/or production of an oil or natural gas well or lease. Refers to the operator of record and any lessor or working interest holder for which the operator is acting.

Overriding royalty interest or ORRI. A fractional, undivided interest or right of participation in the oil or natural gas, or in the proceeds from the sale of the oil or gas, produced from a specified tract or tracts, which are limited in duration to the terms of an existing lease and which are not subject to any portion of the expense of development, operation or maintenance.

PDP. Proved developed producing.

PDNP. Proved developed non-producing.

Play. A set of discovered or prospective oil and/or natural gas accumulations sharing similar geologic, geographic and temporal properties, such as source rock, reservoir structure, timing, trapping mechanism and hydrocarbon type.

Plugging and abandonment. Refers to the sealing off of fluids in the strata penetrated by a well so that the fluids from one stratum will not escape into another or to the surface. Regulations of all states require plugging of abandoned wells.

Pooling. The majority of our producing acreage is pooled with third-party acreage. Pooling refers to an operator’s consolidation of multiple adjacent leased tracts, which may be covered by multiple leases with multiple lessors, in order to maximize drilling efficiency or to comply with state mandated well spacing requirements. Pooling dilutes our royalty in a given well or share, but it also increases both the acreage footprint and the number of wells in which we have an economic interest. To estimate our total potential drilling locations in a given play, we include third-party acreage that is pooled with our acreage.

Production costs. The production or operational costs incurred while extracting and producing, storing, and transporting oil and/or natural gas. Typical of these costs are wages for workers, facilities lease costs, equipment maintenance, logistical support, applicable taxes and insurance. For a complete definition of production costs, refer to the SEC’s Regulation S-X, Rule 4-10(a)(20).

PUD. Proved undeveloped.

Productive well. A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of the production exceed production expenses and taxes.

Prospect. A specific geographic area which, based on supporting geological, geophysical or other data and also preliminary economic analysis using reasonably anticipated prices and costs, is deemed to have potential for the discovery of commercial hydrocarbons.

Proved developed reserves. Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.

Proved developed producing reserves. Reserves expected to be recovered from existing completion intervals in existing wells.

Proved reserves. The estimated quantities of oil, natural gas and NGLs which geological and engineering data demonstrate with reasonable certainty to be commercially recoverable in future years from known reservoirs under existing economic and operating conditions.

Proved undeveloped reserves. Proved reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion.

Recompletion. The process of re-entering an existing wellbore that is either producing or not producing and completing new reservoirs in an attempt to establish or increase existing production.

 

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Reserves. Reserves are estimated remaining quantities of oil and natural gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and natural gas or related substances to the market and all permits and financing required to implement the project. Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).

Reservoir. 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 separate from other reservoirs.

Royalty interest. An interest that gives an owner the right to receive a portion of the resources or revenues without having to carry any costs of development.

Seismic data. Seismic data is used by scientists to interpret the composition, fluid content, extent and geometry of rocks in the subsurface. Seismic data is acquired by transmitting a signal from an energy source, such as dynamite or water, into the earth. The energy so transmitted is subsequently reflected beneath the earth’s surface and a receiver is used to collect and record these reflections.

Shale. A fine grained sedimentary rock formed by consolidation of clay- and silt-sized particles into thin, relatively impermeable layers. Shale can include relatively large amounts of organic material compared with other rock types and thus has the potential to become rich hydrocarbon source rock. Its fine grain size and lack of permeability can allow shale to form a good cap rock for hydrocarbon traps.

Spacing. 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.

STACK. Sooner Trend, Anadarko Basin, Canadian and Kingfisher counties.

Tight formation. A formation with low permeability that produces natural gas with low flow rates for long periods of time.

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

Wellbore. The hole drilled by the bit that is equipped for oil or natural gas production on a completed well.

Working interest. An operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and receive a share of production and requires the owner to pay a share of the costs of drilling and production operations.

WTI. West Texas Intermediate oil, which is a light, sweet crude oil, characterized by an American Petroleum Institute gravity, of API gravity, between 39 and 41 and a sulfur content of approximately 0.4 weight percent that is used as a benchmark for the other crude oils.

 

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INDEX TO FINANCIAL STATEMENTS

 

     Page  

Remora Royalties, Inc.

  

Unaudited Pro Forma Condensed Combined Financial Statements

     F-1  

Unaudited Pro Forma Condensed Combined Balance Sheet as of March 31, 2018

     F-3  

Unaudited Pro Forma Condensed Combined Statement of Operations for the year ended December 31, 2017

     F-4  

Unaudited Pro Forma Condensed Combined Statement of Operations for the three months ended March 31, 2018

     F-5  

Notes to the Unaudited Pro Forma Condensed Combined Financial Statements

     F-6  

Audited Balance Sheet

  

Report of Independent Registered Public Accounting Firm

     F-15  

Balance Sheet as of May 8, 2018

     F-16  

Notes to Balance Sheet

     F-17  

Remora Petroleum, L.P.

  

Consolidated Financial Statements for the Three Months Ended March 31, 2018 and 2017

  

Consolidated Balance Sheets (Unaudited)

     F-18  

Consolidated Statements of Operations (Unaudited)

     F-19  

Consolidated Statements of Changes in Partners’ Capital/(Deficit) (Unaudited)

     F-20  

Consolidated Statements of Cash Flows (Unaudited)

     F-21  

Notes to Consolidated Financial Statements (Unaudited)

     F-22  

Consolidated Financial Statements for the Years Ended December 31, 2017 and 2016

  

Report of Independent Registered Public Accounting Firm

     F-36  

Consolidated Balance Sheets

     F-37  

Consolidated Statements of Operations

     F-38  

Consolidated Statements of Changes in Partners’ Capital/(Deficit)

     F-39  

Consolidated Statements of Cash Flows

     F-40  

Notes to Consolidated Financial Statements

     F-41  

Vendera Resources II, LLC and its affiliates

  

Report of Independent Certified Public Accountants

     F-56  

Statements of Revenues and Direct Operating Expenses

     F-57  

Notes to Statements of Revenues and Direct Operating Expenses

     F-58  

Vendera Resources III, L.P. and its affiliates

  

Report of Independent Certified Public Accountants

     F-62  

Statements of Revenues and Direct Operating Expenses

     F-63  

Notes to Statements of Revenues and Direct Operating Expenses

     F-64  

AVAD Energy Partners, LLC

  

Report of Independent Certified Public Accountants

     F-67  

Statements of Revenues and Direct Operating Expenses

     F-68  

Notes to Statements of Revenues and Direct Operating Expenses

     F-69  

 

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Unaudited Pro Forma Condensed Combined Financial Statements

The following unaudited pro forma condensed combined balance sheet of Remora Royalties, Inc. (“RRI” or the “Company”) as of March 31, 2018, and the unaudited pro forma condensed combined statement of operations of Remora Royalties, Inc. for the three months ended March 31, 2018 and the year ended December 31, 2017 are based on (i) the unaudited financial statements as of and for the three months ended March 31, 2018 and the audited financial statements for the year ended December 31, 2017 of Remora Petroleum, L.P. (“RPLP”), our predecessor for accounting purposes, (ii) the audited statement of revenues and direct operating expenses of oil and gas properties for the year ended December 31, 2017 and the unaudited statement of revenues and direct operating expenses of oil and gas properties for the three months ended March 31, 2018 of Vendera Resources II, LLC and its affiliates, Vendera Resources III, L.P. and its affiliates and AVAD Energy Partners, LLC, respectively (collectively the “Other Principal Contributing Parties”), (iii) the audited statement of revenues and direct operating expenses of oil and gas properties for the period from January 1, 2017 to December 9, 2017 for the 2017 South Texas Assets (as defined below) and (iv) the retention by our predecessor of certain oil and natural gas properties and all other assets, liabilities and operations that will not be acquired by RRI or its subsidiary, Remora Holdings, LLC (“Remora Holdings”).

The unaudited pro forma condensed combined statement of operations for the three months ended March 31, 2018 and the year ended December 31, 2017, and the unaudited pro forma condensed combined balance sheet as of March 31, 2018 have been prepared to reflect the pro forma formation transactions (as defined below). The pro forma financial data is presented as if the pro forma formation transactions had occurred on March 31, 2018 for the purposes of the unaudited pro forma condensed combined balance sheet and on January 1, 2017 for the purposes of the unaudited pro forma condensed combined statement of operations.

The unaudited pro forma adjustments are based on preliminary estimates, accounting judgments and currently available information and assumptions that management believes are reasonable. The notes to the unaudited pro forma condensed combined statements provide a detailed discussion of how such adjustments were derived and presented in the unaudited pro forma financial information. The unaudited pro forma condensed combined financial information should be read in conjunction with “Capitalization”, “Use of Proceeds”, “Selected Historical and Unaudited Pro Forma Financial Data”, and “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

The unaudited pro forma condensed combined financial information has been prepared to reflect adjustments to our historical financial information that are (i) directly attributable to this offering and (ii) factually supportable, and with respect to the unaudited pro forma condensed combined statement of operations, expected to have a continuing impact on our results.

These transactions include (collectively, the “pro forma formation transactions”):

 

    Remora Holdings’ acquisition of assets to be contributed by RPLP and the Other Principal Contributing Parties in exchange for an aggregate of              units representing limited liability company membership interests in Remora Holdings (“RH Units”) (and the purchase of an equivalent number of shares of RRI’s Class B common stock by RPLP and the Other Principal Contributing Parties at par value) and the purchase of              RH Units from RPLP and the Other Principal Contributing Parties in exchange for $             million in cash from the net proceeds of this offering, as further described under “Formation Transactions” elsewhere in this prospectus. The unaudited pro forma financial statements do not reflect the issuance of              RH Units and              Class B common stock issued and the purchase of              RH Units in exchange for $             million in cash paid in exchange for the acquisition of assets not reflected in the unaudited pro forma financial statements;

 

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    The retention by RPLP of certain oil and gas properties and all other assets, liabilities and operations that will not be acquired by Remora Holdings;

 

    Remora Holdings’ assumption of approximately $             million of indebtedness of RPLP that burdens the assets to be contributed to Remora Holdings by RPLP;

 

    The acquisition by RPLP of certain oil and natural gas properties in South Texas on December 19, 2017 (“2017 South Texas Assets”);

 

    The issuance by RRI of              of the              shares of Class A common stock being offered to the public in this offering at an assumed initial public offering price of $             per share, which is the mid-point of the price range set forth on the cover of the prospectus, reflecting that number of shares of Class A common stock issued to the public, the proceeds of which are deemed to (1) be contributed to Remora Holdings in exchange for              RH Units and (2) purchase              RH Units from RPLP and the Other Principal Contributing Parties. The unaudited pro forma financial statements do not reflect the issuance of              shares of Class A common stock issued to the public deemed to fund the purchase of              RH Units from the other contributing parties;

 

    The use of the net proceeds from this offering as set forth in “Use of Proceeds”;

 

    A provision for corporate income taxes at an effective rate of         %, inclusive of all U.S. federal, state and local income taxes;

 

    Remora Holdings’ entrance into a new $             million secured revolving credit facility, pursuant to which we expect Remora Holdings to borrow approximately $             at the closing of this offering to repay the indebtedness assumed from RPLP; and

 

    Our entrance into a management services agreement with RPLP.

The unaudited pro forma condensed combined statement of operations does not give pro forma effect to RRI’s acquisition of assets to be contributed by the Contributing Parties other than our predecessor and the Other Principal Contributing Parties, which excludes assets representing approximately 12% of our future undiscounted cash flows, based on a reserve report prepared by Cawley, Gillespie & Associates, Inc., as of December 31, 2017.

The unaudited pro forma condensed combined statements of operations do not include certain non-recurring items that we expect to incur in connection with the pro forma formation transactions, including costs related to legal, accounting, and consulting services.

Upon completion of this offering, we anticipate incurring incremental general and administrative expenses of approximately $         per year as a result of becoming a publicly-traded company, including expenses associated with SEC reporting requirements, including annual and quarterly reports to shareholders, tax return and 1099 preparation and distribution expenses, Sarbanes-Oxley Act compliance expenses, expenses associated with listing on the NASDAQ, independent auditor fees, independent reserve engineer fees, legal fees, investor relations expenses, registrar and transfer agent fees, director and officer insurance expenses and director and officer compensation expenses. The unaudited pro forma condensed combined financial statements do not reflect these incremental general and administrative expenses.

The unaudited pro forma condensed combined financial statements included in this registration statement do not purport to represent what our financial position and results of operations would have been had this offering and the acquisition of assets contributed by RPLP and the Other Principal Contributing Parties occurred on the dates indicated or to project our financial performance for any future period. A number of factors may affect our results. Please read “Risk Factors” and “Forward-Looking Statements” for information regarding statements that do not relate strictly to historical or current facts and certain risks inherent in our business.

 

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REMORA ROYALTIES, INC.

UNAUDITED PRO FORMA CONDENSED COMBINED BALANCE SHEET

As of March 31, 2018

 

    Predecessor
Entity
    Acquisition
Adjustments
        Equity Offering and
Other Pro Forma
Adjustments
        Pro forma  
ASSETS            

CURRENT ASSETS:

           

Cash and cash equivalents

  $ 2,481,770     $ (2,481,770   (A)   $     (F) (G)   $  

Accounts receivable

           

Trade

    5,228,813       (2,875,847   (B)             —         2,352,966  

Other

    25,222       (25,222   (A)              

Derivative asset

    2,402,607       (1,321,434   (B)             1,081,173  

Deferred tax asset

                      (H)      

Prepaid expenses and deposit

    398,801       (398,801   (A)              
 

 

 

   

 

 

     

 

 

     

 

 

 

Total current assets

    10,537,213       (7,103,074               3,434,139  
 

 

 

   

 

 

     

 

 

     

 

 

 

PROPERTY AND EQUIPMENT:

           

Evaluated oil and natural gas properties, full cost method

    157,349,507       (42,484,367   (C) (E)             114,865,140  

Unevaluated oil and natural gas properties, full cost method

    497       (134   (C) (E)             363  

Other property and equipment

    265,186       (265,186   (A)              

Less: accumulated depletion, depreciation, amortization and impairment

    (107,482,419     29,020,253     (C) (E)             (78,462,166
 

 

 

   

 

 

     

 

 

     

 

 

 

Total property and equipment, net

    50,132,771       (13,729,434               36,403,337  

Other long-term assets

    341,709       (341,709   (A)              

Long-term derivative assets

    2,060,535       (1,133,294   (B)             927,241  

Deferred tax asset

                      (H)      
 

 

 

   

 

 

     

 

 

     

 

 

 

TOTAL ASSETS

  $ 63,072,228     $ (22,307,511     $       $ 40,764,717  
 

 

 

   

 

 

     

 

 

     

 

 

 
LIABILITIES AND EQUITY            

CURRENT LIABILITIES:

           

Accounts payable and accrued expenses

  $ 3,105,989     $ (2,484,791   (D)   $       $ 621,198  

Deferred tax liability

                      (H)      

Derivative liability

    3,775,301       (2,076,416   (B)             1,698,885  

Current protion of asset retirment obligation

    820,263       (820,263   (A)              
 

 

 

   

 

 

     

 

 

     

 

 

 

TOTAL CURRENT LIABILITIES

    7,701,553       (5,381,470               2,320,083  

LONG-TERM LIABILITIES

           

Long-term debt, net

    47,950,317       (12,946,586   (C)         (D)     35,003,731  

Deferred tax liability

                      (H)      

Noncurrent derivative liability

    2,381,578       (1,309,868   (B)             1,071,710  

Asset retirement obligation

    20,797,879       (20,797,879   (A)              
 

 

 

   

 

 

     

 

 

     

 

 

 

TOTAL LIABILITIES

    78,831,327       (40,435,803               38,395,524  

Commitments and Contigencies

           

EQUITY:

           

Partners deficit

    (15,759,099                 (F)     (15,759,099

Class A Common stock

          (F) (G)      

Paid-in capital

          (F) (G)      
 

 

 

   

 

 

     

 

 

     

 

 

 

Total stockholders’ equity

    (15,759,099                     (15,759,099

Noncontrolling interest

          (F) (G)      
 

 

 

   

 

 

     

 

 

     

 

 

 

Total equity

    (15,759,099                     (15,759,099
 

 

 

   

 

 

     

 

 

     

 

 

 

TOTAL LIABILITIES AND EQUITY

  $ 63,072,228     $ (40,435,803     $       $ 22,636,425  
 

 

 

   

 

 

     

 

 

     

 

 

 

 

F-3


Table of Contents
Index to Financial Statements

REMORA ROYALTIES, INC.

UNAUDITED PRO FORMA CONDENSED COMBINED STATEMENT OF OPERATIONS

For the Year Ended December 31, 2017

 

    Predecessor
Entity
    2017
Acquisition
    Vendera
Resources II,
LLC
    Vendera
Resources III,
LP
    AVAD
Energy
Partners,
LLC
    Acquisition
Adjustments
        Equity
Offering
Adjustments
        Pro
Forma
 

Oil, Gas, and NGL Revenue

  $ 36,059,114     $ 12,935,453     $ 3,997,639     $ 989,108     $ 4,287,430       (26,947,012   (B)   $       $ 31,321,732  

OPERATING EXPENSES:

                   

Lease operating expenses

    10,608,592                               (10,608,592   (A)              

Workover expense

    2,588,007                               (2,588,007   (A)              

Production taxes

    1,527,684               (840,226   (B)             687,458  

Marketing and other direct operating expenses

    5,426,373       2,247,851       425,358       320,292       891,640       (7,874,465   (B)(1)             1,437,049  

Depletion, depreciation and amortization

    6,703,123                               (1,809,843   (C), (E)             4,893,280  

Accretion expense

    426,925                               (426,925   (A)              

Impairment of oil and gas properties

                                      (C)              

General and administrative expenses

    3,446,096                               (2,756,877   (D)             689,219  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

     

 

 

     

 

 

 

Total operating expenses

    30,726,800       2,247,851       425,358       320,292       891,640       (26,904,935               7,707,006  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

     

 

 

     

 

 

 

INCOME (LOSS) FROM OPERATIONS

    5,332,314       10,687,602       3,572,281       668,816       3,395,790       (42,076               23,614,727  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

     

 

 

     

 

 

 

OTHER INCOME (EXPENSE):

                   

Net gain (loss) on derivative instruments

    5,134,256                               (2,823,841   (B)             2,310,415  

Interest expense

    (5,348,882                             1,444,198     (C)             (3,904,684

Other income (expense)

    1,533,756                               (1,533,756   (A)              
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

     

 

 

     

 

 

 

Total Other Income
(expense)

    1,319,130                               (2,913,399               (1,594,269
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

     

 

 

     

 

 

 

NET INCOME (LOSS) BEFORE INCOME TAXES

    6,651,444       10,687,602       3,572,281       668,816       3,395,790       (2,955,475               22,020,458  

INCOME TAX (EXPENSE) BENEFIT

                      (I)      
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

     

 

 

     

 

 

 

NET INCOME (LOSS)

  $ 6,651,444     $ 10,687,602     $ 3,572,281     $ 668,816     $ 3,395,790     $ (2,955,475     $       $ 22,020,458  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

     

 

 

     

 

 

 

LESS: NET INCOME (LOSS) ATTRIBUTABLE TO NONCONTROLLING INTEREST

                      (J)      
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

     

 

 

     

 

 

 

NET INCOME (LOSS) ATTRIBUTABLE TO STOCKHOLDERS

  $ 6,651,444     $ 10,687,602     $ 3,572,281     $ 668,816     $ 3,395,790     $ (2,955,475     $     —       $ 22,020,458  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

     

 

 

     

 

 

 

NET INCOME (LOSS) PER CLASS A COMMON SHARE (e):

                   

Basic

                   
                   

 

 

 

Diluted

                   
                   

 

 

 

WEIGHTED AVERAGE COMMON SHARES OUTSTANDING (IN THOUSANDS) (e):

                   

Basic

                   
                   

 

 

 

Diluted

                   
                   

 

 

 

 

(1)   Adjustment includes removal of marketing, gathering and transportation expenses not contributed net of taxes being contributed.

 

F-4


Table of Contents
Index to Financial Statements

REMORA ROYALTIES, INC.

UNAUDITED PRO FORMA CONDENSED COMBINED STATEMENTS OF OPERATIONS

For the Three Months Ended March 31, 2018

 

    Predecessor
Entity
    Vendera
Resources II,
LLC
    Vendera
Resources III,
LP
    AVAD
Energy
Partners,
LLC
    Acquisition
Adjustments
        Equity
Offering
Adjustments
        Pro Forma  

Oil, Gas, and NGL Revenue

  $ 9,934,187     $ 994,065     $ 216,771     $ 1,097,206       (5,463,803   (B)   $       $ 6,778,426  

OPERATING EXPENSES:

                 

Lease operating expenses

    3,367,645                         (3,367,645   (A)              

Workover expense

    286,250                         (286,250   (A)              

Production taxes

    604,228             (332,325   (B)             271,903  

Marketing and other direct operating expenses

    1,493,494       98,767       127,786       332,483       (1,798,586   (B)(1)             253,944  

Depletion, depreciation and amortization

    1,779,265                         (480,402   (C), (E)             1,298,863  

Accretion expense

    176,440                         (176,440   (A)              

Impairment of oil and gas properties

                                (C)              

General and administrative expenses

    1,497,060                         (1,197,648   (D)             299,412  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

     

 

 

     

 

 

 

Total operating expenses

    9,204,382       98,767       127,786       332,483       (7,639,296               2,124,122  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

     

 

 

     

 

 

 

INCOME (LOSS) FROM OPERATIONS

    729,805       895,298       88,985       764,723       2,175,493                 4,654,304  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

     

 

 

     

 

 

 

OTHER INCOME (EXPENSE):

                 

Net gain (loss) on derivative instruments

    (751,902                       413,546     (B)             (338,356

Interest expense

    (1,273,697                       343,898     (C)             (929,799

Other income (expense)

    17,128                         (17,128   (A)              
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

     

 

 

     

 

 

 

Total Other Income (expense)

    (2,008,471                       740,316                 (1,268,155
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

     

 

 

     

 

 

 

NET INCOME (LOSS) BEFORE INCOME TAXES

    (1,278,666     895,298       88,985       764,723       2,915,809                 3,386,149  

INCOME TAX (EXPENSE) BENEFIT

                    (I)      
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

     

 

 

     

 

 

 

NET INCOME (LOSS)

  $ (1,278,666   $ 895,298     $ 88,985     $ 764,723     $ 2,915,809       $         —       $ 3,386,149  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

     

 

 

     

 

 

 

LESS: NET INCOME (LOSS) ATTRIBUTABLE TO NONCONTROLLING INTEREST

                    (J)      
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

     

 

 

     

 

 

 

NET INCOME (LOSS) ATTRIBUTABLE TO STOCKHOLDERS

  $ (1,278,666   $ 895,298     $ 88,985     $ 764,723     $ 2,915,809       $       $ 3,386,149  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

     

 

 

     

 

 

 

NET INCOME (LOSS) PER CLASS A COMMON SHARE (e):

                 

Basic

                 
                 

 

 

 

Diluted

                 
                 

 

 

 

WEIGHTED AVERAGE COMMON SHARES OUTSTANDING (IN THOUSANDS) (e):

                 

Basic

                 
                 

 

 

 

Diluted

                 
                 

 

 

 

 

(1)   Adjustment includes removal of marketing, gathering and transportation expenses not contributed net of taxes being contributed.

 

F-5


Table of Contents
Index to Financial Statements

NOTES TO UNAUDITED PRO FORMA CONDENSED COMBINED FINANCIAL STATEMENTS

For the Year Ended December 31, 2017 and the Three Months Ended March 31, 2018

 

1) Basis of Presentation

The unaudited pro forma condensed combined balance sheet as of March 31, 2018, and the unaudited pro forma condensed combined statements of operations for the year ended December 31, 2017 and the three months ended March 31, 2018, are derived from the historical financial statements of our predecessor and the historical statements of revenues and direct operating expenses of oil and gas properties of the Other Principal Contributing Parties and the 2017 South Texas Assets.

 

2) Pro Forma Adjustments and Assumptions

The adjustments are based on currently available information, certain estimates and assumptions. Therefore, the actual effects of these transactions will differ from the pro forma adjustments. A general description of these transactions and adjustments is provided as follows:

Pro Forma Adjustments A, B, C and D represent adjustments using the proportional cost and revenue allocation method to exclude (i) assets and liabilities that will not be contributed to the Company and revenues and expenses attributable to such assets and liabilities and (ii) expenses of our predecessor that will not be incurred by us relating to the working interests not contributed by our predecessor. After giving effect to the adjustments described above, the pro forma financial statements reflect the assets and liabilities to be contributed as if such contribution occurred on March 31, 2018, and the results of operations relating to such income and expenses for the year ended December 31, 2017 and the three months ended March 31, 2018 had the Company been formed and the contribution occurred on January 1, 2017. We believe the proportional cost and revenue allocation adjustments method reflects the reasonable allocation of assets and liabilities and revenues and expenses contributed by the Contributing Parties.

 

  A)   Assets and liabilities represented by the following balance sheet accounts are not contributed: cash, accounts receivable - other, prepaid expenses and deposit, other property and equipment and asset retirement obligation. Expenses in the statement of operations not expected to be incurred by us in future periods relating to the assets and liabilities contributed by our predecessor: Lease operating expense, workover expense, accretion expense and other income (expense).

 

  B)   The following balance sheet accounts are contributed at 45%, representing the assets and liabilities attributable to the ORRIs contributed by our predecessor: accounts receivable – trade, derivative assets and derivative liabilities. The following statement of operations accounts follow the same convention as the assets and liabilities listed prior: Oil, gas and NGL revenue, production taxes, ad valorem taxes, general & administrative expenses and gain (loss) on derivative instruments. Marketing, gathering and transportation expenses are not contributed.

 

  C)  

The following assets and liabilities are contributed at 73%, which represents the percentage of undiscounted cash flows to be generated from the ORRI-related reserves contributed by our predecessor in relation to the total undiscounted cash flows to be generated from our predecessor’s reserves based on the reserve reports prepared by Cawley, Gillespie & Associates, Inc., as of December 31, 2017: Oil and natural gas properties, both evaluated and unevaluated, accumulated depletion, depreciation, amortization and impairment and long-term debt. The following statement of operations accounts follow the same contribution as the corresponding above listed assets and liabilities: Depletion, depreciation and amortization, impairment, and

 

F-6


Table of Contents
Index to Financial Statements

NOTES TO UNAUDITED PRO FORMA CONDENSED COMBINED FINANCIAL STATEMENTS — (Continued)

For the Year Ended December 31, 2017 and the Three Months Ended March 31, 2018

 

  interest expense are reflected at 73%, corresponding with the contributed oil and gas property allocation.

 

  D)   Accounts payable and accrued liabilities are contributed at 20%, which reflects the estimated percentage of direct expenses and general and administrative expenses reflected in the statement of operations for the year ended December 31, 2017 and the three months ended March 31, 2018, respectively, attributable to the ORRIs contributed by our predecessor in relation to the total amount of direct and general administrative expenses incurred for that year.

 

  E)   Represents the pro forma impact of the fair value adjustments to royalty interests, and the associated change to depreciation, depletion and accretion expense, recorded as a result of the acquisition of assets contributed by the Principal Contributors. The estimated fair value assigned to oil and natural gas properties (full cost method), the estimated net proved reserves based on our management’s estimates, and the estimated depreciation, depletion and accretion expense related to oil and natural gas properties acquired are as follows:

 

     Estimated
Fair Value
     Estimated Proved
Reserves
(MBOE)
     Depreciation and Depletion
Expense for the years
ended

December 31,
 
           2017  

Oil and natural gas properties for:

        

Vendera Resources II, LLC and its affiliates

   $      $      $  

Vendera Resources III, L.P. and its affiliates

                    

AVAD Energy Partners, LLC

                    
  

 

 

    

 

 

    

 

 

 

Total pro forma adjustments

   $      $      $  

The assets to be acquired, included in these pro forma adjustments, do not constitute “an integrated set of activities and assets that are capable of being conducted and managed for the purpose of providing a return in the form of dividends, lower costs, or other economic benefits directly to investors or other owners, members, or participants.” As a result, the acquisitions are treated as an acquisition of assets under generally accepted accounting principles based on the guidance in ASC 805—Business Combinations. Because they are treated as an acquisition of assets, they will not be treated as an acquisition of a business for purposes of ASC 805.

This methodology requires the recording of net assets acquired and consideration transferred at fair value. The mineral and royalty interests acquired are based upon a valuation performed with the assistance of a third party valuation specialist as well as management estimates, utilizing a combination of the income, market and cost approaches to valuation.

We intend to acquire the royalty interests for an estimated purchase price of approximately $         million. The total estimated net consideration paid will take the form of $         million of cash and              common shares.

 

  F)   Reflects the net proceeds to us from this offering of $         million, which consists of $         million in gross proceeds from the issuance and sale of common shares at an assumed initial offering price of $         per share, which is the mid-point of the price range set forth on the cover of the prospectus, less the underwriting discount of $         million and structuring fee of $         million.

 

F-7


Table of Contents
Index to Financial Statements

NOTES TO UNAUDITED PRO FORMA CONDENSED COMBINED FINANCIAL STATEMENTS — (Continued)

For the Year Ended December 31, 2017 and the Three Months Ended March 31, 2018

 

  G)   Reflects the effect of our recapitalization as a result of the pro forma formation transactions, and a distribution of $         million to the Contributing Parties with the net proceeds of this offering.

 

  H)   Reflects adjustments to give effect to tax adjustments assuming the Company’s earnings had been subject to federal income tax as a subchapter C corporation using a statutory tax rate of approximately         %. This rate is inclusive of U.S. federal and state income taxes.

 

  I)   Reflects estimated incremental income tax provision associated with the Company’s historical results of operations assuming the Company’s earnings had been subject to federal income tax as a subchapter C corporation using a statutory tax rate of approximately         %. This rate is inclusive of U.S. federal and state income taxes.

 

  J)   Reflects the portion of equity in a subsidiary not attributable, directly or indirectly, to the parent company.

 

3) Pro Forma Net Income (Loss) per Class A Common Share

Pro forma net income per share is determined by dividing the pro forma net income available to Class A common shareholders by the number of Class A common shares issued to the public, the proceeds of which are deemed to (1) be contributed to Remora Holdings in exchange for                  RH Units and (2) purchase                  RH Units from RPLP and the Other Principal Contributing Parties. For purposes of this calculation, the number of common shares outstanding at the closing of the offering was assumed to be for the year ended December 31, 2017 and the three months ended March 31, 2018,              and             , respectively. All common shares were assumed to have been outstanding since the beginning of the periods presented.

 

4) Pro Forma Supplemental Oil and Gas Reserve Information

The following pro forma standardized measure of the discounted net future cash flows and changes are applicable to the proved reserves of our predecessor, the Other Principal Contributing Parties, and the 2017 South Texas Assets. The future cash flows are discounted at 10% per year and assume continuation of existing economic conditions. It does not include proved reserves of certain other Contributing Parties, whose financial information is not reflected in the unaudited pro forma condensed combined financial statements. The excluded assets represent approximately 12% of our future undiscounted cash flows, based on a reserve report prepared by Cawley, Gillespie & Associates, Inc., as of December 31, 2017.

The standardized measure of discounted future net cash flows, in management’s opinion, should be examined with caution. The basis for this table are the reserve studies prepared by management, 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 flows is not necessarily indicative of the fair value of the proved oil and natural gas properties of our predecessor, Vendera Resources II, LLC, Vendera Resources III, L.P., AVAD Energy Partners, LLC, and the 2017 South Texas Assets. The Acquisition Adjustments represent the retention by our predecessor of certain working interests in oil and gas properties that will not be acquired by Remora Holdings, LLC.

 

F-8


Table of Contents
Index to Financial Statements

NOTES TO UNAUDITED PRO FORMA CONDENSED COMBINED FINANCIAL STATEMENTS — (Continued)

For the Year Ended December 31, 2017 and the Three Months Ended March 31, 2018

 

The data presented should not be viewed as representing the expected cash flows 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.

The following tables provide a pro forma rollforward of the total proved reserves for the year ended December 31, 2017, as well as pro forma proved developed and proved undeveloped reserves at the beginning and end of such year as if the contribution of properties from our predecessor, Other Principal Contributing Parties and the 2017 Acquisition had occurred on January 1, 2017. The Acquisition Adjustments represent the retention by our predecessor of certain working interests in oil and gas properties that will not be acquired by Remora Holdings, LLC:

 

    Crude Oil and Condensate (MBbls)  
    Predecessor
Entity
    2017
Acquisition
    Vendera
Resources
II, LLC
    Vendera
Resources
III, LP
    AVAD Energy
Management,
LLC
    Acquisition
Adjustments(1)
    Pro Forma  

Proved developed and undeveloped reserves:

             

January 1, 2017

    1,687             243             473       (901     1,502  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Revisions of previous estimates

    170       42       15             28       (201     54  

Extensions, discoveries and other additions

    1,062                               (950     112  

Divestiture of Reserves

    (121                             121        

Purchase of reserves

    629       25                         (379     275  

Production

    (201     (67     (18           (34     147       (173
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

December 31, 2017

    3,226             240             467       (2,163     1,770  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Proved developed reserves:

             

January 1, 2017

    1,687             243             473       (901     1,502  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

December 31, 2017

    2,156             240             467       (1,200     1,663  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Proved undeveloped reserves:

             

January 1, 2017

                                         
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

December 31, 2017

    1,070                               (963     107  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

 

(1)   Represents the retention by our predecessor of certain oil and gas properties that will not be acquired by Remora Holdings, LLC.

 

F-9


Table of Contents
Index to Financial Statements

NOTES TO UNAUDITED PRO FORMA CONDENSED COMBINED FINANCIAL STATEMENTS — (Continued)

For the Year Ended December 31, 2017

 

    Natural Gas (MMcf)  
    Predecessor
Entity
    2017
Acquisition
    Vendera
Resources
II, LLC
    Vendera
Resources
III, LP
    AVAD Energy
Management,
LLC
    Acquisition
Adjustments(1)
    Pro Forma  

Proved developed and undeveloped reserves:

             

January 1, 2017

    67,019             11,076       4,870       12,258       (31,555     63,668  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Revisions of previous estimates

    4,634       1,879       1,309       1,005       2,398       (9,063     2,162  

Extensions, discoveries and other additions

    63,107                               (56,775     6,332  

Divestiture of Reserves

    (4,353                             4,353        

Purchase of reserves

    24,464       798                         (15,050     10,212  

Production

    (6,747     (2,677     (1,163     (429     (1,102     5,183       (6,935
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

December 31, 2017

    148,124             11,222       5,446       13,554       (102,907     75,439  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Proved developed reserves:

             

January 1, 2017

    67,019             11,076       4,870       12,258       (31,555     63,668  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

December 31, 2017

    84,785             11,222       5,446       13,554       (46,582     68,425  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Proved undeveloped reserves:

             

January 1, 2017

                                         
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

December 31, 2017

    63,339                               (56,325     7,014  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

 

(1)   Represents the retention by our predecessor of certain oil and gas properties that will not be acquired by Remora Holdings, LLC.

 

F-10


Table of Contents
Index to Financial Statements

NOTES TO UNAUDITED PRO FORMA CONDENSED COMBINED FINANCIAL STATEMENTS — (Continued)

For the Year Ended December 31, 2017

 

    Natural Gas Liquids (MBbls)  
    Predecessor
Entity
    2017
Acquisition
    Vendera
Resources
II, LLC
    Vendera
Resources
III, LP
    AVAD Energy
Management,
LLC
    Acquisition
Adjustments(1)
    Pro Forma  

Proved developed and undeveloped reserves:

             

January 1, 2017

    3,610             3                   (2,233     1,380  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Revisions of previous estimates

    651       155                         (828     (22

Extensions, discoveries and other additions

    3,645                               (3,276     369  

Divestiture of Reserves

    (1,429                             1,429        

Purchase of reserves

    678       (58                       (358     262  

Production

    (404     (97                       276       (225
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

December 31, 2017

    6,751             3                   (4,990     1,764  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Proved developed reserves:

             

January 1, 2017

    3,610             3                   (2,233     1,380  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

December 31, 2017

    3,120             3                   (1,719     1,404  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Proved undeveloped reserves:

             

January 1, 2017

                                         
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

December 31, 2017

    3,631                               (3,272     359  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

 

(1)   Represents the retention by our predecessor of certain oil and gas properties that will not be acquired by Remora Holdings, LLC.

 

F-11


Table of Contents
Index to Financial Statements

NOTES TO UNAUDITED PRO FORMA CONDENSED COMBINED FINANCIAL STATEMENTS — (Continued)

For the Year Ended December 31, 2017

 

    Total (MMcfe)  
    Predecessor
Entity
    2017
Acquisition
    Vendera
Resources
II, LLC
    Vendera
Resources
III, LP
    AVAD Energy
Management,
LLC
    Acquisition
Adjustments(1)
    Pro Forma  

Proved developed and undeveloped reserves:

             

January 1, 2017

    98,801             12,552       4,870       15,096       (50,359     80,960  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Revisions of previous estimates

    9,560       3,061       1,399       1,005       2,566       (15,237     2,354  

Extensions, discoveries and other additions

    91,349                               (82,131     9,218  

Divestiture of Reserves

    (13,653                             13,653        

Purchase of reserves

    32,306       600                         (19,472     13,434  

Production

    (10,377     (3,661     (1,271     (429     (1,306     7,721       (9,323
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

December 31, 2017

    207,986             12,680       5,446       16,356       (145,825     96,643  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Proved developed reserves:

             

January 1, 2017

    98,801             12,552       4,870       15,096       (50,359     80,960  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

December 31, 2017

    116,441             12,680       5,446       16,356       (64,096     86,827  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Proved undeveloped reserves:

             

January 1, 2017

                                         
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

December 31, 2017

    91,545                               (81,729     9,816  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

 

(1)   Represents the retention by our predecessor of certain oil and gas properties that will not be acquired by Remora Holdings, LLC.

 

F-12


Table of Contents
Index to Financial Statements

NOTES TO UNAUDITED PRO FORMA CONDENSED COMBINED FINANCIAL STATEMENTS — (Continued)

For the Year Ended December 31, 2017

 

    Predecessor
Entity
    Vendera
Resources
II, LLC
    Vendera
Resources
III, LP
    AVAD Energy
Management,
LLC
    Acquisition
Adjustments(1)
    Corporate
Reorganization
    Pro Forma  

Future crude oil, natural gas and NGL sales

  $ 718,009     $ 42,092     $ 12,545     $ 54,744     $ (502,343   $     $ 325,047  

Future production costs

    (357,521     (3,424     (863     (4,024     341,362         (24,470

Future development costs

    (88,978                       88,978          

Future income tax expense

    (771     (103           (134     688         (320
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Future net cash flows

    270,740       38,565       11,682       50,586       (71,315           300,258  

10% annual discount

    (154,361     (20,280     (6,293     (28,362     55,170         (154,126
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Standardized measure of discounted future net cash flows

  $ 116,378     $ 18,285     $ 5,389     $ 22,224     $ (16,145   $     $ 146,131  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

 

(1)   Represents the retention by our predecessor of certain oil and gas properties that will not be acquired by Remora Holdings, LLC.

 

F-13


Table of Contents
Index to Financial Statements

NOTES TO UNAUDITED PRO FORMA CONDENSED COMBINED FINANCIAL STATEMENTS — (Continued)

For the Year Ended December 31, 2017

 

    Predecessor
Entity
    2017
Acquisition
    Vendera
Resources
II, LLC
    Vendera
Resources
III, LP
    AVAD Energy
Management,
LLC
    Acquisition
Adjustments(1)
    Corporate
Reorganization
    Pro Forma  

Balance at January 1, 2017

  $ 54,601     $     $ 15,232     $ 4,126     $ 17,953     $ 8,181       $ 100,093  

Sales of crude oil, natural gas and NGL, net

    (15,908     (10,688     (3,572     (669     (3,396     472         (33,761

Net change in prices and production costs

    29,741       9,463       3,512       851       3,143       (21,061       25,649  

Net change in future development costs

    (4,325                             4,325          

Extensions and discoveries

    28,600                               (16,363       12,237  

Acquisitions of reserves

    27,761       (7,912                       2,916         22,765  

Sales of reserves

    (7,970                             7,970          

Revisions of previous quantity estimates

    4,156       5,921       2,030       994       3,492       (8,984       7,609  

Previously estimated development costs incurred

                                           

Net change in income taxes

    (355     (46     (3           (8     359         (53

Accretion of discount

    5,472       4,885       1,527       413       1,800       1,272         15,369  

Other

    (5,395     (1,623     (441     (326     (760     4,768         (3,777
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Balance at December 31, 2017

  $ 116,378     $     $ 18,285     $ 5,389     $ 22,224     $ (16,145   $     $ 146,131  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

 

(1)   Represents the retention by our predecessor of certain oil and gas properties that will not be acquired by Remora Holdings, LLC.

 

F-14


Table of Contents
Index to Financial Statements
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Board of Directors

Remora Royalties, Inc.

Opinion on the financial statements

We have audited the accompanying balance sheet of Remora Royalties, Inc. (a Delaware corporation) (the “Company”) and the related notes (collectively referred to as the “financial statements”) as of May 8, 2018. In our opinion, the financial statement presents fairly, in all material respects, the financial position of the Company as of May 8, 2018, in conformity with accounting principles generally accepted in the United States of America.

Basis for opinion

This financial statement is the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statement based on our audit. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (“PCAOB”) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statement is free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audit we are required to obtain an understanding of internal control over financial reporting 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.

Our audit included performing procedures to assess the risks of material misstatement of the financial statement, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statement. Our audit also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statement. We believe that our audit provides a reasonable basis for our opinion.

We have served as the Company’s auditor since 2017.

/s/ Grant Thornton LLP

Dallas, Texas

May 14, 2018

 

F-15


Table of Contents
Index to Financial Statements

REMORA ROYALTIES, INC.

BALANCE SHEET

 

     May 8, 2018  
ASSETS   

CURRENT ASSETS

  

Cash and cash equivalents

   $  
  

 

 

 

TOTAL ASSETS

   $  
  

 

 

 
LIABILITIES AND SHAREHOLDER’S EQUITY   

TOTAL LIABILITIES

  

Total liabilities

   $  

SHAREHOLDER’S EQUITY

  

Common stock, $0.01 par value, 1,000 shares authorized, 100 shares issued and outstanding

     1  

Less receivable from Remora Petroleum, L.P.

     (1
  

 

 

 

Total shareholder’s equity

      
  

 

 

 

TOTAL LIABILITIES AND SHAREHOLDER’S EQUITY

   $  
  

 

 

 

 

F-16


Table of Contents
Index to Financial Statements

REMORA ROYALTIES, INC.

NOTES TO BALANCE SHEET

Note 1—Nature of Operations

Remora Royalties Inc. (the “Company”) is a Delaware corporation formed as a wholly owned subsidiary of Remora Petroleum, L.P. (“RPLP”) on May 8, 2018. The Company has no prior operating activities.

Note 2—Basis of Presentation and Summary of Significant Accounting Policies

This balance sheet has been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”). Separate Statements of Operations, Changes in Stockholder’s Equity and of Cash Flows have not been presented because the Company has had no business transactions or activities to date, except for the initial capitalization of the Company which was funded by a receivable from RPLP. In this regard, general and administrative costs associated with the formation and daily management of the Company have been determined by the Company to be insignificant.

In preparing the accompanying balance sheet, the Company considered disclosures of events occurring after May 8, 2018, up until the issuance of the balance sheet.

Estimates

The preparation of the balance sheet, in accordance with generally accepted accounting principles in the United States of America, requires management to make estimates and assumptions that affect the amounts reported in the balance sheet and accompanying notes. Actual results could differ from those estimates.

Receivable from Remora Petroleum, L.P.

Receivable from RPLP represents an amount of $1.00 due for the issuance of 100 shares of $.01 par value common stock to the Parent. Prior to payment by RPLP, this receivable will be recorded as a reduction of shareholder’s equity.

Note 3—Shareholder’s Equity

The Company has authorized share capital of 1,000 common shares with $0.01 par value. On May 8, 2018, 100 shares were issued and acquired by RPLP for consideration of an amount of a $1.00 receivable from RPLP. Each share has one voting right.

 

F-17


Table of Contents
Index to Financial Statements

REMORA PETROLEUM, L.P.

CONSOLIDATED BALANCE SHEETS

(unaudited)

 

     As of March 31,     As of December 31,  
     2018     2017  
ASSETS     

CURRENT ASSETS

    

Cash and cash equivalents

   $ 2,481,770     $ 2,533,761  

Accounts receivable

    

Trade

     5,228,813       4,150,194  

Other

     25,222       65,774  

Derivative asset

     2,402,607       3,100,944  

Prepaid expenses and deposits

     398,801       484,405  
  

 

 

   

 

 

 

Total current assets

     10,537,213       10,335,078  

PROPERTY AND EQUIPMENT:

    

Evaluated oil and natural gas properties, full cost method

     157,349,507       158,335,732  

Unevaluated oil and natural gas properties, full cost method

     497       263,767  

Other property and equipment

     265,186       177,747  

Less: accumulated depletion, depreciation, amortization and impairment

     (107,482,419     (105,703,154
  

 

 

   

 

 

 

Total property and equipment, net

     50,132,771       53,074,092  
  

 

 

   

 

 

 

Other long-term assets

     341,709        

Long-term derivative assets

     2,060,535       2,776,229  
  

 

 

   

 

 

 

TOTAL ASSETS

   $ 63,072,228     $ 66,185,399  
  

 

 

   

 

 

 
LIABILITIES AND PARTNERS’ CAPITAL / (DEFICIT)     

CURRENT LIABILITIES

    

Accounts payable and accrued expenses

   $ 3,105,989     $ 2,500,701  

Derivative liability

     3,775,301       3,714,682  

Current portion of asset retirement obligation

     820,263       860,342  
  

 

 

   

 

 

 

Total current liabilities

     7,701,553       7,075,725  

LONG-TERM LIABILITIES

    

Long-term debt, net

     47,950,317       49,186,099  

Noncurrent derivative liability

     2,381,578       3,564,335  

Asset retirement obligation

     20,797,879       20,830,573  
  

 

 

   

 

 

 

Total liabilities

     78,831,327       80,656,732  

COMMITMENTS AND CONTINGENCIES (Note 10)

    

PARTNERS’ DEFICIT

     (15,759,099     (14,471,333
  

 

 

   

 

 

 

TOTAL LIABILITIES AND PARTNERS’ DEFICIT

   $ 63,072,228     $ 66,185,399  
  

 

 

   

 

 

 

 

F-18


Table of Contents
Index to Financial Statements

REMORA PETROLEUM, L.P.

CONSOLIDATED STATEMENTS OF OPERATIONS

(unaudited)

 

     Three Months Period Ended March 31,  
             2018                     2017          

OIL, GAS, AND NGL REVENUE

   $ 9,934,187     $ 11,436,818  
  

 

 

   

 

 

 

OPERATING EXPENSES:

    

Lease operating expense

     3,367,645       2,889,744  

Workover expense

     286,250       761,359  

Production taxes

     604,228       488,218  

Marketing and transportation expense

     1,493,494       1,427,614  

Depletion, depreciation and amortization

     1,779,265       1,743,568  

Accretion expense

     176,440       143,545  

General and administrative expense

     1,497,060       718,968  
  

 

 

   

 

 

 

Total operating expenses

     9,204,382       8,173,016  

INCOME FROM OPERATIONS

     729,805       3,263,802  

OTHER INCOME (EXPENSE):

    

Net gain (loss) on derivative instruments

     (751,902     7,169,487  

Interest expense

     (1,273,697     (1,449,243

Other income (expense)

     17,128       1,503  
  

 

 

   

 

 

 

Total other income (expense)

     (2,008,471     5,721,747  
  

 

 

   

 

 

 

NET INCOME (LOSS)

   $ (1,278,666   $ 8,985,549  

 

F-19


Table of Contents
Index to Financial Statements

REMORA PETROLEUM, L.P.

CONSOLIDATED STATEMENTS OF CHANGES

IN PARTNERS’ CAPITAL / (DEFICIT)

FOR THE THREE MONTHS ENDED MARCH 31, 2018

(unaudited)

 

     General Partner’s      Limited Partner’s     Total Partners’  
     Capital      (Deficit)     (Deficit)  

Balance at January 1, 2017

     4,703        (21,127,480     (21,122,777

Net Income

            6,651,444       6,651,444  
  

 

 

    

 

 

   

 

 

 

Balance at December 31, 2017

   $ 4,703      $ (14,476,036   $ (14,471,333

Partners’ Tax Distribution

            (9,100     (9,100

Net loss

            (1,278,666     (1,278,666
  

 

 

    

 

 

   

 

 

 

Balance at March 31, 2018

   $ 4,703      $ (15,763,802   $ (15,759,099

 

F-20


Table of Contents
Index to Financial Statements

REMORA PETROLEUM, L.P.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(unaudited)

 

     Three Months Period Ended March 31,  
             2018                     2017          

CASH FLOWS FROM OPERATING ACTIVITIES:

    

Net income (loss)

   $ (1,278,666   $ 8,985,549  

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

    

Depletion, depreciation and amortization

     1,779,265       1,743,568  

Accretion expense

     176,440       143,545  

Unrealized net (gain) loss on derivative instruments

     298,998       (7,136,309

Amortization of debt issuance costs

     114,219       111,574  

Settlements on asset retirement obligations

     (37,305     (5,847

Changes in working capital

    

Accounts receivable

     (1,038,067     (2,645,472

Prepaid expenses and deposits

     (256,105     103,168  

Accounts payable and accrued expenses

     598,181       210,484  
  

 

 

   

 

 

 

Net cash provided by operating activities

     356,960       1,510,260  

CASH FLOWS FROM INVESTING ACTIVITIES

    

Additions to oil and gas properties

     (309,885     1,345,212  

Acquisition of oil and gas properties

           (1,172,921

Proceeds from sales of oil and gas properties

     1,347,473        

Purchase of other property and equipment

     (87,439      
  

 

 

   

 

 

 

Net cash provided by investing activities

     950,149       172,291  

CASH FLOWS FROM FINANCING ACTIVITIES

    

Proceeds from line of credit

           1,200,000  

Payments on line of credit

     (1,350,000      

Tax distribution to partners

     (9,100      

Debt issuance costs

           (36,121
  

 

 

   

 

 

 

Net cash provided by (used in) financing activities

     (1,359,100     1,163,879  

NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS

     (51,991     2,846,430  

CASH AND CASH EQUIVALENTS, beginning of period

     2,533,761       1,276,036  
  

 

 

   

 

 

 

CASH AND CASH EQUIVALENTS, end of period

   $ 2,481,770     $ 4,122,466  
  

 

 

   

 

 

 

SUPPLEMENTAL CASH FLOW DISCLOSURES

    

Cash paid for interest

   $ 1,105,521     $ 1,231,488  
  

 

 

   

 

 

 

NON-CASH INVESTING AND FINANCING ACTIVITIES

    

Change in accrued capital expenditures

   $ 23,870     $  
  

 

 

   

 

 

 

 

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Index to Financial Statements

REMORA PETROLEUM, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

 

1.   ORGANIZATION

Remora Petroleum, L.P., a Texas limited partnership (“RPLP”), was formed on October 19, 2011 and is engaged in acquiring and developing leases of oil and natural gas properties primarily located in Oklahoma, Texas and Louisiana. RPLP’s headquarters are located in Austin, Texas. During 2014, RPLP formed two wholly-owned subsidiaries, Remora Operating, LLC and Remora Operating CA, LLC.

 

2.   SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation — The accompanying unaudited interim consolidated financial statements of the Partnership have been prepared in accordance with generally accepted accounting principles in the United States (“U.S. GAAP”) and pursuant to the rules and regulations of the U.S. Securities and Exchange Commission (“SEC”). These unaudited interim consolidated financial statements have been prepared in accordance with the instructions to Form 10-Q and, therefore, do not include all disclosures required for financial statements prepared in conformity with U.S. GAAP. Accordingly, the accompanying unaudited interim consolidated financial statements and related notes should be read in conjunction with the Partnership’s financial statements for the years ended December 31, 2017 and 2016, which are included in the Partnership’s annual report within the S-1 report. In the opinion of the Partnership’s management, the unaudited interim consolidated financial statements contain all adjustments of a normal recurring nature necessary to fairly present the financial position and results of operations for the interim periods in accordance with U.S. GAAP. The results of operations for the three months ended March 31, 2018 are not necessarily indicative of the results to be expected for the full year.

Principles of Consolidation — The consolidated financial statements include the accounts of RPLP and its wholly owned subsidiaries, Remora Operating, LLC and Remora Operating CA, LLC (collectively, the “Partnership”). All significant intercompany balances and transactions have been eliminated.

Cash and Cash Equivalents — The Partnership considers cash equivalents to include all cash items, such as time deposits and short-term investments, which mature in three months or less from time of purchase. Accounts at each institution are insured by the Federal Deposit Insurance Corporation (“FDIC”) up to $250,000. At March 31, 2018 and December 31, 2017, the Company had $2,231,770 and $2,283,761 in excess of the FDIC insured limit, respectively. As of March 31, 2018 and December 31, 2017, the Partnership had no short-term investments classified as cash equivalents.

Accounts Receivable — Accounts receivable-trade are uncollateralized and consist of oil, natural gas and natural gas liquid revenues due under normal trade terms, generally requiring payment within 60 days of production. Accounts receivable-other consists of uncollateralized joint interest owner obligations due within 15 days of delivery of the invoice and amounts due to the Partnership related to other miscellaneous receivables. Management reviews receivables periodically and reduces the carrying amount by an allowance for doubtful accounts that reflects management’s best estimate of the amount that may not be collectible. There was no allowance for doubtful accounts as of March 31, 2018 and December 31, 2017.

Oil and Gas Producing Activities — The Partnership follows the full cost method of accounting for oil and gas properties. Under the full cost method, all costs associated with property acquisition, exploration, and development activities are capitalized and depleted over the estimated lives of the properties using the units of production method. Capitalized costs include lease acquisitions, geological and geophysical work, delay rentals, costs of drilling, completing and equipping successful and unsuccessful oil and gas wells and

 

F-22


Table of Contents
Index to Financial Statements

REMORA PETROLEUM, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(unaudited)

 

directly related costs. Costs of production and general and administrative corporate costs unrelated to acquisition, exploration, and development activities are expensed as incurred.

Gains or losses are normally not recognized on the sale or other disposition of oil and gas properties unless the ratio of cost to proved reserves would significantly change. Gains or losses are normally reflected as an adjustment to the full cost pool.

Depletion is calculated using the capitalized costs included in the amortization base, including estimated asset retirement costs, plus the estimated future expenditures to be incurred in developing proved reserves, net of estimated salvage values.

The net book value of all capitalized oil and natural gas properties within a cost center, less related deferred income taxes, is subject to a full cost ceiling limitation which is calculated quarterly. Under the ceiling limitation, costs may not exceed an aggregate of the present value of future net revenues attributable to proved oil and natural gas reserves discounted at 10% using the simple average of the first day-of-the-month benchmark prices for the calendar year adjusted by price differentials, plus the lower of cost or market value of unproved properties included in the amortization base, plus the cost of unevaluated properties not included in the amortization base, less any associated tax effects (the “Ceiling”). Any excess of the net book value, less related deferred tax effects, over the Ceiling is written off as impairment expense. Impairment expense recorded in one period may not be reversed in a subsequent period even though higher oil and gas prices may have increased the Ceiling applicable to the subsequent period. The Partnership did not incur any impairment expense as a result of reductions in estimated proved reserves and lower commodity prices for the three months ended March 31, 2018 and 2017.

The costs of certain unevaluated leasehold acreage and certain wells being drilled are not amortized. The Partnership excludes all costs until proved reserves are found or until it is determined that the costs are impaired. Costs not amortized are periodically assessed for possible impairments or reductions in value. If a reduction in value has occurred, costs being amortized are increased by such amount. No impairment expense was recognized for the three months ended March 31, 2018 and 2017 related to unproved property.

Asset Retirement Obligations — An asset retirement obligation (“ARO”) associated with the retirement of a tangible long-lived asset is to be recognized as a liability in the period in which a legal obligation is incurred and becomes determinable, with an offsetting increase in the carrying amount of the associated asset. The cost of the tangible asset, including the initially recognized ARO, is depleted such that the cost of the ARO is recognized over the useful life of the asset. The ARO is recorded initially at fair value. Accretion expense is recognized over time as the discounted liability is accreted to its expected settlement value. The fair value of the ARO is measured using expected future cash outflows discounted at the Partnership’s credit-adjusted risk-free interest rate. Fair value, to the extent possible, includes a market risk premium for unforeseeable circumstances. No market risk premium was included in the Partnership’s ARO fair value estimate since a reasonable estimate could not be made. Given the unobservable nature of inputs, the initial measurement of the obligation is considered to be a Level 3 fair value estimate.

Inherent in the fair value calculation of ARO are numerous assumptions and judgments including the ultimate settlement amounts, inflation factors, credit-adjusted risk-free rates, timing of settlement, and changes in the legal, regulatory, environmental, and political environments. To the extent future revisions to these assumptions impact the value of the existing ARO liability, a corresponding adjustment is made to the

 

F-23


Table of Contents
Index to Financial Statements

REMORA PETROLEUM, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(unaudited)

 

oil and gas property balance. If the liability is settled for an amount other than the recorded amount, the difference is recorded to accumulated amortization.

Revenues — The Partnership uses the sales method of accounting for oil, natural gas and natural gas liquids revenues. Under this method, revenues are recognized based on actual volumes of oil and gas sold to purchasers. The Partnership accrues revenue relating to sales volumes for which the Partnership has not yet received payment.

Other Property and Equipment — Other property and equipment consists of office furniture and fixtures and vehicles, which are recorded at cost. Depreciation on office furniture and fixtures and vehicles is provided using the straight-line method over the estimated useful lives ranging from three to seven years. Depreciation expense on other property and equipment was $10,146 and $5,237 for the three months ended March 31, 2018 and 2017, respectively. Gain or loss on retirement, sale, or other disposition of these assets is included in the statements of operations in the period of disposition. Costs of major repairs that extend the useful life are capitalized. Costs for maintenance and repairs are expensed as incurred.

The Partnership reviews its other property and equipment for impairment whenever events or changes in circumstances indicate that the carrying value of such assets may not be recoverable. When it is determined that an asset’s estimated future net cash flows will not be sufficient to recover its carrying amount, an impairment charge is recorded to reduce its carrying value to its estimated fair value. No impairment expense was recognized for the three months ended March 31, 2018 and 2017.

Derivatives — The Partnership enters into derivative contracts on its oil and natural gas products primarily to stabilize cash flows and reduce the risk and financial impact of downward commodity price movements on commodity sales. These derivatives are reflected as current assets and liabilities and non-current assets and liabilities on the balance sheet. All derivatives are marked-to-market each period with the unrealized gain or loss reflected in the statement of operations.

Debt Issuance Costs — Debt issuance costs are being amortized to interest expense over the term of the credit agreement using the straight line method. The amount of amortization under the straight-line method does not materially differ from the effective interest method. The amortization expense of these costs is included in interest expense on the statement of operations. Debt issuance costs are recorded as a direct deduction from the carrying amount of long-term debt.

Use of Estimates — The preparation of the consolidated financial statements in conformity with accounting principles generally accepted in the United States of America (“U.S. GAAP”) requires management to make estimates and assumptions that affect the reported amounts in the consolidated financial statements as well as certain financial statement disclosures. The Partnership evaluates estimates and assumptions on an ongoing basis using historical experience and other factors, including the current economic and commodity price environment. While management believes that the estimates and assumptions used in the preparation of the financial statements are appropriate, actual results could differ from those estimates.

The Partnership’s consolidated financial statements are based on a number of significant estimates, including oil and gas reserve quantities which are the basis for the calculation of depreciation, depletion, and amortization and impairment of oil and gas properties. The discounted present value of the proved oil and natural gas reserves is a major component of the ceiling test calculation and requires subjective

 

F-24


Table of Contents
Index to Financial Statements

REMORA PETROLEUM, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(unaudited)

 

judgments. Estimates of reserves are forecasts based on engineering and geological analyses. Different reserve engineers could reach different conclusions as to estimated quantities of oil and natural gas reserves based on the same information. Reserve estimates are inherently imprecise and estimates of non-producing properties and more recent discoveries are more imprecise than those for properties with long production histories and revisions are made to prior estimates based on updated information.

In addition to the uncertainties inherent in the reserve estimation process, these amounts are affected by historical and projected prices for oil and natural gas which have typically been volatile. There can be no assurance that significant revisions to the Partnership’s oil and natural gas reserves will not be necessary in the future.

Other significant estimates include the valuation of derivative instruments and asset retirement obligations.

Income Taxes — Federal income taxes have not been provided in the accompanying consolidated financial statements, as the Partnership does not incur federal income taxes. The partners are liable for the federal income taxes attributable to the Partnership’s taxable income.

For state taxes, all of the revenues and properties of the Partnership are attributable to Arkansas, California, Colorado, Kansas, Louisiana, Mississippi, Nebraska, New Mexico, Oklahoma and Texas.

Arkansas, California, Colorado, Kansas, Louisiana, Mississippi, Nebraska, New Mexico, and Oklahoma all tax the income of its resident and nonresident partners, but not the partnership doing business in the state. The state of Texas does tax the Partnership at a rate of 0.75% on the Partnership’s taxable margin, which is calculated as gross receipts less attributable costs of goods sold. For the three months ended March 31, 2018 and 2017, the Partnership did not incur any Texas tax expense.

As of March 31, 2018 and December 31, 2017, the Partnership had no uncertain tax positions or accrued interest or penalties associated with uncertain tax positions. The Partnership does not expect that such amounts will change significantly within the next 12 months. The Partnership’s policy is to recognize interest related to any unrecognized tax positions as interest expense and penalties as operating expenses. The Partnership believes that it has appropriate support for the income tax positions taken on its tax returns and that its accruals for state tax liabilities are adequate for all open years based on an assessment of many factors including past experience and interpretations of tax law applied to the facts of each matter. The Partnership’s state income tax returns are open to audit under the statute of limitations for the periods ended December 31, 2013 through 2016. The Partnership’s federal income tax returns are open to audit under the statute of limitations for the periods ended December 31, 2014 through 2016.

Concentration of Credit Risk — Financial instruments that potentially expose the Partnership to concentrations of credit risk consist primarily of accounts receivable, derivative instruments and cash and cash equivalents. Substantially all accounts receivable result from revenues from oil, natural gas and natural gas liquids sales; therefore, the Partnership’s customers may be similarly affected by changes in economic and other conditions within the industry. Although the Partnership is directly affected by the economic conditions of the oil and gas production industry, management does not believe significant credit risk existed at March 31, 2018 and December 31, 2017.

The Partnership experienced no credit losses on its accounts receivable for the three months ended March 31, 2018 and 2017.

 

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Table of Contents
Index to Financial Statements

REMORA PETROLEUM, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(unaudited)

 

The Partnership’s derivative assets from price risk management activities represent estimated unrealized receivables from an investment grade commercial bank, which is also the Partnership’s lender under its credit facility and term loan. The Partnership does not believe significant credit risk existed at March 31, 2018 and December 31, 2017. The Partnership experienced no credit losses on its derivative assets from price risk management activities for the three months ended March 31, 2018 and 2017.

The Partnership maintains its cash and cash equivalents on deposit with a commercial bank. At times, deposits exceed federally insured limits. The Partnership experienced no losses on its deposits for the three months ended March 31, 2018 and 2017.

New Accounting Pronouncements — In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2014-09, Revenue from Contracts with Customers. This standard provides a five-step approach to be applied to all contracts with customers and requires expanded disclosures about the nature, amount, timing and uncertainty of revenue (and the related cash flows) arising from customer contracts, significant judgments and changes in judgments used in applying the revenue model and the assets recognized from costs incurred to obtain or fulfill a contract. The standard permits the use of either the retrospective or cumulative effect transition method, therefore the Partnership is evaluating the effect that this new guidance will have on its consolidated financial statements and related disclosures. In 2015, the FASB voted to defer the effective date of this standard, which now will not apply to the Partnership until 2019. Nonpublic entities reporting under US GAAP are permitted to apply the standard early; however, adoption can be no earlier than annual reporting periods beginning after December 15, 2016. We have not concluded on the impact of this accounting standard to our company. However, we have evaluated our contracts from customers and related revenue recognition policies and we do not believe the adoption of this standard will have a material impact on our financial statements.

In August 2014, the FASB issued ASU 2014-15, Presentation of Financial Statements—Going Concern (Subtopic 205-40): Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern. The amendments require management to assess an entity’s ability to continue as a going concern by incorporating and expanding upon certain principles that are currently in U.S. auditing standards. Specifically, the amendments (1) provide a definition of the term substantial doubt, (2) require an evaluation every reporting period including interim periods, (3) provide principles for considering the mitigating effect of management’s plans, (4) require certain disclosures when substantial doubt is alleviated as a result of consideration of management’s plans, (5) require an express statement and other disclosures when substantial doubt is not alleviated and (6) require an assessment for a period of one year after the date that the financial statements are issued (or available to be issued). The amendments in this Update are effective for the annual period ending after December 15, 2016, and for annual periods and interim periods thereafter. The Partnership adopted this accounting standard as of December 31, 2016.

In February 2016, the FASB issued ASU No. 2016-02, Leases (“ASU 2016-02”). ASU 2016- 02 requires that a lessee should recognize the assets and liabilities that arise from leases. All leases create an asset and a liability for the lessee in accordance with FASB Concepts Statement No. 6, Elements of Financial Statements. A lessee should recognize in the statement of financial position a liability to make lease payments (the lease liability) and a right-of-use asset representing its right to use the underlying asset for the lease term. When measuring assets and liabilities arising from a lease, a lessee should include payments to be made in optional periods only if the lessee is reasonably certain to exercise an option to extend the lease or not to exercise an option to terminate the lease. Similarly, optional payments to purchase

 

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Table of Contents
Index to Financial Statements

REMORA PETROLEUM, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(unaudited)

 

the underlying asset should be included in the measurement of lease assets and lease liabilities only if the lessee is reasonably certain to exercise that purchase option. In addition, also consistent with the previous leases guidance, a lessee should exclude most variable lease payments in measuring lease assets and lease liabilities, other than those that depend on an index or a rate or are in substance fixed payments. For leases with a term of 12 months or less, a lessee is permitted to make an accounting policy election by class of underlying asset not to recognize lease assets and lease liabilities. If a lessee makes this election, it should recognize lease expense for such leases generally on a straight-line basis over the lease term. For nonpublic entities, the new standard is effective for annual reporting periods beginning after December 15, 2019, and interim periods within fiscal years beginning after December 15, 2020. The Partnership is currently evaluating the impact of this accounting standard.

In August 2016, the FASB issued ASU 2016-15, Classification of Certain Cash Receipts and Cash Payments, which addressees eight classification issues related to the statement of cash flows: debt prepayment or debt extinguishment costs, settlement of zero-coupon bonds, contingent consideration payments made after a business combination, proceeds from the settlement of insurance claims, proceeds from the settlement of corporate-owned life insurance policies, distributions received from equity method investees, beneficial interests in securitization transactions, and separately identifiable cash flows and application of the predominance principle. ASU 2016-15 is effective for the Partnership for fiscal years beginning after December 15, 2018 and interim periods beginning after December 15, 2019. Early adoption is permitted. The Partnership is currently evaluating the impact of this accounting standard.

In January 2017, the FASB issued ASU 2017-01, Business Combinations, to clarify the definition of a business by adding guidance to assist entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of a business. This standard provides a screen to determine when a set is not a business. The screen requires that when substantially all of the fair value of the gross assets acquired (or disposed of) is concentrated in a single identifiable asset or group of similar identifiable assets, the set is not a business. If the screen is not met, this standard (1) requires that to be considered a business, a set must include, at a minimum, an input and a substantive process that together significantly contribute to the ability to create output and (2) removes the evaluation of whether a market participant could replace the missing elements. ASU 2017-01 is effective for the Partnership for fiscal years beginning after December 15, 2018 and interim periods beginning after December 15, 2019. The Partnership is currently evaluating the impact of this accounting standard.

 

3.   ACQUISITIONS & DIVESTITURES

On March 20, 2018, the Partnership sold various land and surface rights in addition to the working interests and net revenue interests in certain proved properties for a sale price of approximately $1.35 million. The effective date of this sale was January 22, 2018. The Partnership accounted for this sale pursuant to the acquisition method of accounting whereby all the sold assets and liabilities are recorded at their estimated fair values. Allocation of the adjusted sale price is as follows:

 

Oil and gas properties

   $ 1,347,473  

Asset retirement costs

   $ 109,467  

Asset retirement obligations

   $ (109,467

 

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Index to Financial Statements

REMORA PETROLEUM, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(unaudited)

 

On December 19, 2017, the Partnership entered into an agreement with an unrelated third party to acquire various working interests and net revenue interests in certain proved properties for a purchase price of approximately $14.2 million. The adjusted purchase price was paid to seller at closing. The Partnership accounted for this acquisition pursuant to the acquisition method of accounting whereby all the acquired assets and assumed liabilities are recorded at their estimated fair values. Allocation of the adjusted purchase price is as follows:

 

Oil and gas properties

   $ 10,549,245  

Asset retirement costs

   $ 15,805,542  

Asset retirement obligations

   $ (15,805,542

On November 30, 2017, the Partnership sold various land and surface rights in addition to the working interests and net revenue interests in certain proved properties for a sale price of approximately $1.25 million. The effective date of this sale was September 7, 2017. The Partnership accounted for this sale pursuant to the acquisition method of accounting whereby all the sold assets and liabilities are recorded at their estimated fair values. Allocation of the adjusted sale price is as follows:

 

Oil and gas properties

   $ 1,246,182  

Asset retirement costs

   $ 39,998  

Asset retirement obligations

   $ (39,998

On July 19, 2017, the Partnership sold various working interests and net revenue interests in certain proved properties for a sale price of approximately $16.5 million. The effective date of this sale was June 1, 2017. The Partnership accounted for this sale pursuant to the acquisition method of accounting whereby all the sold assets and liabilities are recorded at their estimated fair values. Allocation of the adjusted sale price is as follows:

 

Oil and gas properties

   $ 16,500,000  

Asset retirement costs

   $ 3,803,813  

Asset retirement obligations

   $ (3,930,756

On April 28, 2017, the Partnership sold certain leasehold acreage to an unrelated third party for a sale price of $1,460,458, recorded as a gain in other income (expense) in the consolidated statement of operations. The effective date of the sale was on April 1, 2017.

On January 19, 2017, the Partnership acquired various working interests and net revenue interests in certain proved properties for a purchase price of approximately $1.2 million. The effective date of this sale was September 1, 2016. The Partnership accounted for this acquisition pursuant to the acquisition method of accounting whereby all the acquired assets and assumed liabilities are recorded at their estimated fair values. Allocation of the adjusted purchase price is as follows:

 

Oil and gas properties

   $ 995,039  

Asset retirement costs

   $ 226,735  

Asset retirement obligations

   $ (226,735

On December 22, 2016, the Partnership acquired various working interests and net revenue interests in certain proved properties from an unrelated third party for a purchase price of approximately $10.5 million. The effective date of this acquisition was September 1, 2016. The Partnership accounted for this acquisition

 

F-28


Table of Contents
Index to Financial Statements

REMORA PETROLEUM, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(unaudited)

 

pursuant to the acquisition method of accounting whereby all the acquired assets and assumed liabilities are recorded at their estimated fair values. Allocation of the adjusted purchase price is as follows:

 

Oil and gas properties

   $ 8,766,269  

Asset retirement costs

   $ 3,545,658  

Asset retirement obligations

   $ (3,545,658

On December 16, 2016, the Partnership acquired various working interests and net revenue interests in certain proved properties from an unrelated third party for a purchase price of approximately $1.45 million. The effective date of this acquisition was November 1, 2016. The Partnership accounted for this acquisition pursuant to the acquisition method of accounting whereby all the acquired assets and assumed liabilities are recorded at their estimated fair values. Allocation of the adjusted purchase price is as follows:

 

Oil and gas properties

   $ 1,416,011  

Asset retirement costs

   $ 1,678  

Asset retirement obligations

   $ (1,678

On December 9, 2016, the Partnership acquired various working interests and net revenue interests in certain proved properties from an unrelated third party for a purchase price of approximately $27.5 million. The effective date of this acquisition was September 1, 2016. The Partnership accounted for this acquisition pursuant to the acquisition method of accounting whereby all the acquired assets and assumed liabilities are recorded at their estimated fair values. Allocation of the adjusted purchase price is as follows:

 

Oil and gas properties

   $ 25,264,277  

Asset retirement costs

   $ 1,605,273  

Asset retirement obligations

   $ (1,605,273

In all acquisitions, the Partnership incurred immaterial amount of transaction costs, which are reflected in general and administrative expenses in the accompanying consolidated statements of operations for the three months ended March 31, 2018 and 2017. For certain acquired oil and gas properties, we recorded post close adjustments as a result of the change in estimates of certain revenues and expenses incurred between the effective and closing date of the acquisitions.

In all sales of our assets, the sales did not significantly impact the ratio of cost to proved reserves, and as such, no gains / losses were recognized. Any gains / losses were reflected as an adjustment to the full cost pool.

 

4.   DERIVATIVE INSTRUMENTS

The Partnership enters into various derivatives for the purpose of hedging the impact of market fluctuations of crude oil and natural gas prices. These derivatives include crude oil and natural gas costless collars and swaps. The Partnership’s commodity derivative instruments generally serve as effective economic hedges of commodity risk exposure, however, the Partnership has elected not to account for the derivatives as cash flow hedges. As such, the Partnership recognizes all changes in fair value of its derivatives in earnings.

 

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Table of Contents
Index to Financial Statements

REMORA PETROLEUM, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(unaudited)

 

As of March 31, 2018, the Partnership had crude oil commodity contracts in place based on NYMEX prices as follows:

 

     FIXED-PRICE SWAPS  

PRODUCTION PERIOD

   BARRELS      WEIGHTED
AVERAGE
FIXED PRICE
 

2018

     189,500      $ 52.07  

2019

     187,000      $ 51.49  

2020

     126,000      $ 53.04  

2021

     96,000      $ 52.07  

As of March 31, 2018, the Partnership had natural gas commodity contracts in place based on NYMEX prices as follows:

 

     FIXED-PRICE SWAPS      PUT OPTIONS      CALL OPTIONS  

PRODUCTION

PERIOD

   MMBTU      WEIGHTED
AVERAGE
FIXED PRICE
     MMBTU      WEIGHTED
AVERAGE
FIXED PRICE
     MMBTU      WEIGHTED
AVERAGE
FIXED PRICE
 

2018

     4,695,000      $ 2.99        420,000      $ 2.50        420,000      $ 3.10  

2019

     5,585,000      $ 2.69        60,000      $ 2.50        60,000      $ 3.13  

2020

     3,920,000      $ 2.83        540,000      $ 2.50        540,000      $ 3.17  

2021

     880,000      $ 2.79        1,200,000      $ 2.50        1,200,000      $ 3.23  

As of March 31, 2018, the Partnership had natural gas liquids commodity contracts in place based on NYMEX prices as follows:

 

     FIXED-PRICE SWAPS  

PRODUCTION PERIOD

   BARRELS      WEIGHTED
AVERAGE
FIXED PRICE
 

2018

     437,786      $ 25.73  

2019

     445,714      $ 25.05  

2020

     214,857      $ 24.82  

 

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Table of Contents
Index to Financial Statements

REMORA PETROLEUM, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(unaudited)

 

The Partnership’s commodity derivative financial instruments are recorded at their fair values on the consolidated balance sheets, with the change in fair value recognized in the consolidated statements of operations in other income (expense) as follows:

 

   

ASSET DERIVATIVES

   

LIABILITY DERIVATIVES

 
        March 31,
2018
    December 31,
2017
        March 31,
2018
    December 31,
2017
 

AS OF DECEMBER 31,

 

BALANCE
SHEET
LOCATION

  FAIR
VALUE
    FAIR
VALUE
   

BALANCE SHEET
LOCATION

  FAIR
VALUE
    FAIR
VALUE
 

Commodity contracts (current)

  Current assets   $ 2,402,607     $ 3,100,944     Current liabilities   $ (3,775,301   $ (3,714,682

Commondity contracts (long-term)

  Long-term assets     2,060,535       2,776,229     Long-term liabilities     (2,381,578     (3,564,335
   

 

 

   

 

 

     

 

 

   

 

 

 

Total derivatives

    $ 4,463,142     $ 5,877,173       $ (6,156,879   $ (7,279,017
   

 

 

   

 

 

     

 

 

   

 

 

 

 

    

LOCATION OF GAIN
(LOSS) RECOGNIZED
ON STATEMENT OF
OPERATIONS

   AMOUNT OF GAIN (LOSS)
RECOGNIZED AS INCOME
(EXPENSE) ON
DERIVATIVES
 
          March 31,  
                  2018                     2017          

Realized commodity contract

   Other income (expense)    $ (452,904   $ 33,178  

Unrealized commodity contract

   Other income (expense)      (298,998     7,136,309  
     

 

 

   

 

 

 
      $ (751,902   $ 7,169,487  
     

 

 

   

 

 

 

 

5.   FAIR VALUE MEASUREMENTS

Accounting Standards Codification (“ASC”) 820, Fair Value Measurements and Disclosures defines fair value, establishes a framework for measuring fair value and explains the related disclosure requirements. ASC 820 indicates, among other things, that a fair value measurement assumes that the transaction to sell an asset or transfer a liability occurs in the principal market for the asset or liability or, in the absence of a principal market, the most advantageous market for the asset or liability and defines fair value based upon an exit price model.

ASC 820 establishes a valuation hierarchy for disclosure of the inputs to valuation used to measure fair value. This hierarchy prioritizes the inputs into three broad levels as follows. Level 1 inputs are quoted prices (unadjusted) in active markets for identical assets or liabilities. Level 2 inputs are quoted prices for similar assets and liabilities in active markets or inputs that are observable for the asset or liability, either directly or indirectly through market corroboration, for substantially the full term of the financial instrument. Level 3 inputs are unobservable inputs based on the Partnership’s assumptions used to measure assets and liabilities at fair value. A financial asset or liability’s classification within the hierarchy is determined based on the lowest level input that is significant to the fair value measurement.

The Partnership carries cash, accounts receivable and payables at historical value which approximate fair value due to the short-term nature of these instruments. Based on market rates for similar loans, the fair value of long-term debt approximates its carrying value. Nonfinancial assets and liabilities initially

 

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Index to Financial Statements

REMORA PETROLEUM, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(unaudited)

 

measured at fair value include certain assets and liabilities acquired in a business combination, impaired other property and equipment, and asset retirement obligations. Financial assets and liabilities are reported in the accompanying consolidated financial statements at fair value.

The following table sets forth, by level within the fair value hierarchy, the Partnership’s financial assets, net of liabilities that were accounted for at fair value as of March 31, 2018 and December 31, 2017. Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The Partnership’s assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.

 

     MARCH 31, 2018  
     LEVEL 1      LEVEL 2     LEVEL 3      TOTAL  

LIABILITIES

          

Commodity collars

   $      $ (45,856   $      $ (45,856

Commodity fixed price swaps

   $      $ (1,644,881   $      $ (1,644,881
     DECEMBER 31, 2017  
     LEVEL 1      LEVEL 2     LEVEL 3      TOTAL  

ASSETS

  

Commodity collars

   $      $ 34,800     $      $ 34,800  

LIABILITIES

          

Commodity fixed price swaps

   $      $ (1,436,644   $      $ (1,436,644

In general, the determination of the fair values incorporates various factors. These factors include the credit standing of the counterparties for the Partnership’s assets and the impact of the Partnership’s own nonperformance risk on any liabilities. As of March 31, 2018 and December 31, 2017, the Partnership’s derivative contracts were placed at major corporations with investment grade credit ratings which have a low credit risk. The Partnership is exposed to credit risk to the extent of nonperformance by the counterparties in the derivative contracts discussed; however, the Partnership does not anticipate such nonperformance.

 

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Index to Financial Statements

REMORA PETROLEUM, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(unaudited)

 

6.   ASSET RETIREMENT OBLIGATION

The Partnership has an ARO associated with the future abandonments of its oil and gas properties. The following table presents the activity of the Partnership’s ARO:

 

     March 31, 2018      December 31, 2017  

Asset retirement obligation, beginning of year

   $ 21,690,915      $ 8,326,214  

Liabilities incurred

            16,032,377  

Accretion expense

     176,440        426,925  

Liabilities sold

     (116,543      (3,992,921

Liabilities settled

     (28,320      (212,213

Revisions of estimates

     (104,350      1,110,533  
  

 

 

    

 

 

 
     21,618,142        21,690,915  

Less: current portion

     820,263        860,342  
  

 

 

    

 

 

 

Asset retirement obligation, long-term

   $ 20,797,879      $ 20,830,573  
  

 

 

    

 

 

 

 

7.   DEBT

Long-term debt consisted of the following:

 

     March 31, 2018      December 31, 2017  

Line of credit

   $ 24,100,000      $ 25,450,000  

Term loan

     25,000,000        25,000,000  
  

 

 

    

 

 

 

Total long-term debt

     49,100,000        50,450,000  

Less: debt issuance costs

     (1,149,683      (1,263,901
  

 

 

    

 

 

 

Long-term debt, net

   $ 47,950,317      $ 49,186,099  
  

 

 

    

 

 

 

In May 2016, the Partnership entered into an amended and restated credit agreement with BOKF, NA dba Bank of Texas (“Bank of Texas”) an aggregate commitment of $75,000,000 and an initial borrowing base of $23,000,000. The credit agreement has a maturity date of May 27, 2020 and is secured by the oil and gas properties. There is a commitment fee of up to 0.50% on the unused availability, as defined in the credit agreement. Advances on the credit agreement were $24,100,000 and $25,450,000 at March 31, 2018 and December 31, 2017, respectively. Advances bear interest at the bank’s alternate base rate plus an applicable margin from 0.75% to 1.75% depending on the utilization level as defined in the agreement or at the LIBOR plus an applicable margin from 2.00% to 3.00% depending on the utilization levels as defined in the agreement.

The credit agreement provides for certain affirmative covenants and restrictions, including certain required financial ratios that require maintenance of a minimum ratio of working capital, a maximum ratio of indebtedness to earnings before interest, incomes taxes, depreciation and amortization and other non-cash charges (“EBITDAX”), and a minimum total adjusted leverage to PDP-10 asset coverage calculation. In December 2016, the Partnership entered into first amendment to the amended and restated credit agreement (“First Amendment”). Under the First Amendment, advances bear interest at the bank’s alternate base rate plus an applicable margin from 1.75% to 2.75% depending on the utilization level as defined in the agreement or at the LIBOR plus an applicable margin from 2.75% to 3.75% depending on the utilization

 

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Index to Financial Statements

REMORA PETROLEUM, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(unaudited)

 

levels as defined in the agreement in exchange for an increased borrowing base. At March 31, 2018, the borrowing base was $45,000,000. As of March 31, 2018, the Partnership was in compliance with all of the required financial covenants.

In May 2016, the Partnership also entered into a second lien credit agreement with Goldman Sachs Specialty Lending Group, L.P. (“Goldman Sachs”) for an aggregate commitment of $25,000,000 and a maturity of November 27, 2020. The second lien facility bears interest at the bank’s base rate plus 10% to 11% depending on the utilization levels as defined in the agreement or at the LIBOR plus 11% to 12% depending on the utilization levels as defined in the agreement with a minimum LIBOR of 1.0%. At March 31, 2018, the Partnership had $25,000,000 in outstanding borrowings under this agreement. The financial covenants under this second lien credit agreement are identical to those of the first lien credit agreement, and the Partnership was in compliance with all of its financial covenants as of March 31, 2018.

 

8.   PARTNERS’ CAPITAL / (DEFICIT)

In connection with the formation of the Partnership, Remora Petroleum GP, LLC (the “General Partner”) and certain other qualified investors (the “Class A Limited Partners”) entered into a limited partnership agreement dated October 19, 2011. The total capital commitment was $0 as of March 31, 2018 and December 31, 2017.

Upon request, Class A Limited Partners and the General Partner are required to make capital contributions to the Partnership based on amounts as determined by the limited partnership agreement. For the three months ended March 31, 2018 and the year ended December 31, 2017, there were no contribution from the General Partner and the Class A Limited Partners. During the investment period, as defined in the limited partnership agreement, the General Partner has sole discretion as to the timing, amount and form of distributions. No distributions were made for the three months ended March 31, 2018 and year ended December 31, 2017.

On May 27, 2016, the Partnership amended the limited partnership agreement to issue a new class of partnership interest designated as Class A-3 Partnership Interest. The Class A-3 partners have no capital commitment and no voting rights.

 

9.   RELATED PARTY TRANSACTIONS

During the three months ended March 31, 2018 and 2017, the Partnership paid two of its partners approximately $100,000 each quarter, respectively, for management services performed as employees of the Partnership.

 

10.   COMMITMENTS AND CONTINGENCIES

Commitments — In August 2014, the Partnership entered into a lease agreement for new office space with a third party. In April 2015, the lease was amended to include additional office space. In November 2017, the Company entered into a lease agreement with another third party for a new office space. Rent expense for the three months ended March 31, 2018 and 2017 was approximately $40,000 and $70,000, respectively.

 

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Index to Financial Statements

REMORA PETROLEUM, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(unaudited)

 

Future approximate minimum payments related to this lease are as follows:

 

YEARS ENDING DECEMBER 31,

      

2018 (remainder of)

   $ 268,417  

2019

     362,458  

2020

     312,373  

2021

     225,318  

2022

     222,312  

Thereafter

     265,958  
  

 

 

 
   $ 1,656,836  
  

 

 

 

Contingencies — In the ordinary course of business, the Partnership is subject to possible loss contingencies arising from federal, state, and local environmental, health, and safety laws and regulations and third-party litigation. There are no matters which, in the opinion of management, will have a material adverse effect on the financial position, results of operations, or cash flows of the Partnership.

 

11.   SUBSEQUENT EVENTS

On June 5, 2018, the Partnership acquired various working interests and net revenue interests in certain proved properties for a purchase price of approximately $3.7 million. The effective date of this sale was April 9, 2018. The Partnership accounted for this acquisition pursuant to the acquisition method of accounting whereby all the acquired assets and assumed liabilities are recorded at their estimated fair values.

On June 19, 2018, the Partnership entered into an agreement with an unrelated third party to acquire oil and natural gas properties for a purchase price of approximately $12.5 million. The adjusted purchase price shall be paid to the seller at closing.

The Partnership has evaluated subsequent events through June 22, 2018, the date on which these consolidated financial statements were available to be issued.

 

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Index to Financial Statements
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Partners of

Remora Petroleum, L.P.

Opinion on the financial statements

We have audited the accompanying consolidated balance sheets of Remora Petroleum, L.P. and subsidiaries (the “Company”) as of December 31, 2017 and 2016, and the related consolidated statements of operations, changes in partners’ capital (deficit), and cash flows for the years then ended, and the related notes (collectively referred to as the “financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2017 and 2016, and the results of its operations and its cash flows for the years then ended, in conformity with accounting principles generally accepted in the United States of America.

Basis for opinion

These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (“PCAOB”) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB 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, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits we are required to obtain an understanding of internal control over financial reporting 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.

Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

We have served as the Company’s auditor since 2017.

/s/ Grant Thornton LLP

Dallas, Texas

May 14, 2018

 

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Index to Financial Statements

REMORA PETROLEUM, L.P.

CONSOLIDATED BALANCE SHEETS

 

     AS OF DECEMBER 31,  
     2017     2016  
ASSETS     

CURRENT ASSETS

    

Cash and cash equivalents

   $ 2,533,761     $ 1,276,036  

Accounts receivable

    

Trade

     4,150,194       3,208,791  

Other

     65,774       92,322  

Derivative asset

     3,100,944       591,536  

Prepaid expenses and deposits

     484,405       586,727  
  

 

 

   

 

 

 

Total current assets

     10,335,078       5,755,412  

PROPERTY AND EQUIPMENT:

    

Evaluated oil and natural gas properties, full cost method

     158,335,732       153,812,460  

Unevaluated oil and natural gas properties, full cost method

     263,767       444,728  

Other property and equipment

     177,747       114,310  

Less: accumulated depletion, depreciation, amortization and impairment

     (105,703,154     (99,000,031
  

 

 

   

 

 

 

Total property and equipment, net

     53,074,092       55,371,467  

Long-term derivative assets

     2,776,229       736,800  
  

 

 

   

 

 

 

TOTAL ASSETS

   $ 66,185,399     $ 61,863,679  
  

 

 

   

 

 

 
LIABILITIES AND PARTNERS’ CAPITAL / (DEFICIT)     

CURRENT LIABILITIES

    

Accounts payable and accrued expenses

   $ 2,500,701     $ 3,113,791  

Derivative liability

     3,714,682       2,444,183  

Current portion of asset retirement obligation

     860,342       1,041,734  
  

 

 

   

 

 

 

Total current liabilities

     7,075,725       6,599,708  

LONG-TERM LIABILITIES

    

Long-term debt, net

     49,186,099       66,254,924  

Noncurrent derivative liability

     3,564,335       2,847,344  

Asset retirement obligation

     20,830,573       7,284,480  
  

 

 

   

 

 

 

Total liabilities

     80,656,732       82,986,456  

COMMITMENTS AND CONTINGENCIES (Note 10)

    

PARTNERS’ DEFICIT

     (14,471,333     (21,122,777
  

 

 

   

 

 

 

TOTAL LIABILITIES AND PARTNERS’ DEFICIT

   $ 66,185,399     $ 61,863,679  
  

 

 

   

 

 

 

See accompanying notes to these consolidated financial statements.

 

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Index to Financial Statements

REMORA PETROLEUM, L.P.

CONSOLIDATED STATEMENTS OF OPERATIONS

 

     YEARS ENDED DECEMBER 31,  
             2017                     2016          

OIL, GAS, AND NGL REVENUE

   $ 36,059,114     $ 12,438,637  
  

 

 

   

 

 

 

OPERATING EXPENSES:

    

Lease operating expense

     10,608,592       5,712,571  

Workover expense

     2,588,007       870,282  

Production taxes

     1,527,684       427,193  

Marketing and transportation expense

     5,426,373       1,171,845  

Depletion, depreciation and amortization

     6,703,123       3,329,649  

Accretion expense

     426,925       157,950  

Impairment of oil and gas properties

           30,115,350  

General and administrative expense

     3,446,096       1,662,289  
  

 

 

   

 

 

 

Total operating expenses

     30,726,800       43,447,129  

INCOME (LOSS) FROM OPERATIONS

     5,332,314       (31,008,492

OTHER INCOME (EXPENSE):

    

Net gain (loss) on derivative instruments

     5,134,256       (6,280,818

Interest expense

     (5,348,882     (2,835,300

Other income (expense)

     1,533,756       (1,180
  

 

 

   

 

 

 

Total other income (expense)

     1,319,130       (9,117,298
  

 

 

   

 

 

 

NET INCOME (LOSS)

   $ 6,651,444     $ (40,125,790

See accompanying notes to these consolidated financial statements.

 

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Index to Financial Statements

REMORA PETROLEUM, L.P.

CONSOLIDATED STATEMENTS OF CHANGES

IN PARTNERS’ CAPITAL / (DEFICIT)

FOR THE YEARS ENDED DECEMBER 31, 2016 AND 2017

 

     General Partner’s
Capital / (Deficit)
     Limited Partners’
Capital / (Deficit)
    Total Partners’ Capital
/ (Deficit)
 

Balance at January 1, 2016

     4,703        17,998,310       18,003,013  

Contributions from Partners

            1,000,000       1,000,000  

Net loss

            (40,125,790     (40,125,790
  

 

 

    

 

 

   

 

 

 

Balance at December 31, 2016

   $ 4,703      $ (21,127,480   $ (21,122,777

Net income

            6,651,444       6,651,444  
  

 

 

    

 

 

   

 

 

 

Balance at December 31, 2017

   $ 4,703      $ (14,476,036   $ (14,471,333

See accompanying notes to these consolidated financial statements.

 

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Index to Financial Statements

REMORA PETROLEUM, L.P.

CONSOLIDATED STATEMENTS OF CASH FLOWS

 

     YEARS ENDED DECEMBER 31,  
              2017                       2016           

CASH FLOWS FROM OPERATING ACTIVITIES:

    

Net income (loss)

   $ 6,651,444     $ (40,125,790

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

    

Depletion, depreciation and amortization

     6,703,123       3,329,649  

Impairment of oil and gas properties

           30,115,350  

Accretion expense

     426,925       157,950  

Unrealized net (gain) loss on derivative instruments

     (2,567,057     10,311,311  

Amortization of debt issuance costs

     450,174       231,793  

Settlements on asset retirement obligations

     (212,313     (149,658

Changes in working capital

    

Accounts receivable

     (914,855     (1,314,114

Prepaid expenses and deposits

     83,325       (356,381

Accounts payable and accrued expenses

     (666,644     (97,303
  

 

 

   

 

 

 

Net cash provided by operating activities

     9,954,122       2,102,807  

CASH FLOWS FROM INVESTING ACTIVITIES

    

Capitalized expenses of oil and gas properties

     (1,261,413     (1,121,416

Acquisition of oil and gas properties

     (7,617,767     (39,490,002

Proceeds from sales of oil and gas properties

     17,746,182       28,000  

Purchase of other property and equipment

     (44,400      
  

 

 

   

 

 

 

Net cash provided by (used in) investing activities

     8,822,602       (40,583,418

CASH FLOWS FROM FINANCING ACTIVITIES

    

Proceeds from line of credit

     10,300,000       64,900,000  

Payments on line of credit

     (27,750,000     (30,477,437

Contributions from partners

           1,000,000  

Debt issuance costs

     (68,999     (1,694,161
  

 

 

   

 

 

 

Net cash provided by (used in) financing activities

     (17,518,999     33,728,402  

NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS

     1,257,725       (4,752,209

CASH AND CASH EQUIVALENTS, beginning of year

     1,276,036       6,028,245  
  

 

 

   

 

 

 

CASH AND CASH EQUIVALENTS, end of year

   $ 2,533,761     $ 1,276,036  
  

 

 

   

 

 

 

SUPPLEMENTAL CASH FLOW DISCLOSURES

    

Cash paid for interest

   $ 4,757,105     $ 2,540,452  
  

 

 

   

 

 

 

NON-CASH INVESTING AND FINANCING ACTIVITIES

    

Asset retirement obligations incurred and assumed

   $ 17,142,910     $ 5,288,860  
  

 

 

   

 

 

 

Change in accrued capital expenditures

   $ 59,225     $ 262,199  
  

 

 

   

 

 

 

See accompanying notes to these consolidated financial statements.

 

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Index to Financial Statements

REMORA PETROLEUM, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2017 AND 2016

 

1.   ORGANIZATION

Remora Petroleum, L.P., a Texas limited partnership (“RPLP”), was formed on October 19, 2011 and is engaged in acquiring and developing leases of oil and natural gas properties primarily located in Oklahoma, Texas and Louisiana. RPLP’s headquarters are located in Austin, Texas. During 2014, RPLP formed two wholly-owned subsidiaries, Remora Operating, LLC and Remora Operating CA, LLC.

 

2.   SIGNIFICANT ACCOUNTING POLICIES

Principles of Consolidation — The consolidated financial statements include the accounts of RPLP and its wholly owned subsidiaries, Remora Operating, LLC and Remora Operating CA, LLC (collectively, the “Partnership”). All significant intercompany balances and transactions have been eliminated.

Cash and Cash Equivalents — The Partnership considers cash equivalents to include all cash items, such as time deposits and short-term investments, that mature in three months or less from time of purchase. Accounts at each institution are insured by the Federal Deposit Insurance Corporation (“FDIC”) up to $250,000. At December 31, 2017 and December 31, 2016, the Partnership had $2,283,761 and $1,026,036 in excess of the FDIC insured limit, respectively. As of December 31, 2017 and 2016, the Partnership had no short -term investments classified as cash equivalents.

Accounts Receivable — Accounts receivable-trade are uncollateralized and consist of oil, natural gas and natural gas liquid revenues due under normal trade terms, generally requiring payment within 60 days of production. Accounts receivable-other consists of uncollateralized joint interest owner obligations due within 15 days of delivery of the invoice and amounts due to the Partnership related to other miscellaneous receivables. Management reviews receivables periodically and reduces the carrying amount by an allowance for doubtful accounts that reflects management’s best estimate of the amount that may not be collectible. There was no allowance for doubtful accounts as of December 31, 2017 and 2016.

Oil and Natural Gas Producing Activities — The Partnership follows the full cost method of accounting for oil and natural gas properties. Under the full cost method, all costs associated with property acquisition, exploration, and development activities are capitalized and depleted over the estimated lives of the properties using the units of production method. Capitalized costs include lease acquisitions, geological and geophysical work, delay rentals, costs of drilling, completing and equipping successful and unsuccessful oil and natural gas wells and directly related costs. Costs of production and general and administrative corporate costs unrelated to acquisition, exploration, and development activities are expensed as incurred.

Gains or losses are normally not recognized on the sale or other disposition of oil and natural gas properties unless the ratio of cost to proved reserves would significantly change. Gains or losses are normally reflected as an adjustment to the full cost pool.

Depletion is calculated using the capitalized costs included in the amortization base, including estimated asset retirement costs, plus the estimated future expenditures to be incurred in developing proved reserves, net of estimated salvage values.

The net book value of all capitalized oil and natural gas properties within a cost center, less related deferred income taxes, is subject to a full cost ceiling limitation which is calculated quarterly. Under the

 

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Index to Financial Statements

REMORA PETROLEUM, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

DECEMBER 31, 2017 AND 2016

 

ceiling limitation, costs may not exceed an aggregate of the present value of future net revenues attributable to proved oil and natural gas reserves discounted at 10% using the simple average of the first day-of-the-month benchmark prices for the calendar year adjusted by price differentials, plus the lower of cost or market value of unproved properties included in the amortization base, plus the cost of unevaluated properties not included in the amortization base, less any associated tax effects (the “Ceiling”). Any excess of the net book value, less related deferred tax effects, over the Ceiling is written off as impairment expense. Impairment expense recorded in one period may not be reversed in a subsequent period even though higher oil and natural gas prices may have increased the Ceiling applicable to the subsequent period. The Partnership recorded an impairment expense as a result of reductions in estimated proved reserves and lower commodity prices of $0 and $30,115,350 in 2017 and 2016, respectively.

The costs of certain unevaluated leasehold acreage and certain wells being drilled are not amortized. The Partnership excludes all costs until proved reserves are found or until it is determined that the costs are impaired. Costs not amortized are periodically assessed for possible impairments or reductions in value. If a reduction in value has occurred, costs being amortized are increased by such amount. No impairment expense was recognized during 2017 and 2016 related to unproved property.

Asset Retirement Obligations — An asset retirement obligation (“ARO”) associated with the retirement of a tangible long-lived asset is to be recognized as a liability in the period in which a legal obligation is incurred and becomes determinable, with an offsetting increase in the carrying amount of the associated asset. The cost of the tangible asset, including the initially recognized ARO, is depleted such that the cost of the ARO is recognized over the useful life of the asset. The ARO is recorded initially at fair value. Accretion expense is recognized over time as the discounted liability is accreted to its expected settlement value. The fair value of the ARO is measured using expected future cash outflows discounted at the Partnership’s credit-adjusted risk-free interest rate. Fair value, to the extent possible, includes a market risk premium for unforeseeable circumstances. No market risk premium was included in the Partnership’s ARO fair value estimate since a reasonable estimate could not be made. Given the unobservable nature of inputs, the initial measurement of the obligation is considered to be a Level 3 fair value estimate.

Inherent in the fair value calculation of ARO are numerous assumptions and judgments including the ultimate settlement amounts, inflation factors, credit-adjusted risk-free rates, timing of settlement, and changes in the legal, regulatory, environmental, and political environments. To the extent future revisions to these assumptions impact the value of the existing ARO liability, a corresponding adjustment is made to the oil and natural gas property balance. If the liability is settled for an amount other than the recorded amount, the difference is recorded to accumulated amortization.

Revenues — The Partnership uses the sales method of accounting for oil, natural gas and natural gas liquids revenues. Under this method, revenues are recognized based on actual volumes of oil and natural gas sold to purchasers. The Partnership accrues revenue relating to sales volumes for which the Partnership has not yet received payment.

Other Property and Equipment — Other property and equipment consists of office furniture and fixtures and vehicles, which are recorded at cost. Depreciation on office furniture and fixtures and vehicles is provided using the straight-line method over the estimated useful lives ranging from three to seven years. Depreciation expense on other property and equipment was $21,234 and $22,776 for the years ended December 31, 2017 and 2016, respectively. Gain or loss on retirement, sale, or other disposition of these

 

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Index to Financial Statements

REMORA PETROLEUM, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

DECEMBER 31, 2017 AND 2016

 

assets is included in the statements of operations in the period of disposition. Costs of major repairs that extend the useful life are capitalized. Costs for maintenance and repairs are expensed as incurred.

The Partnership reviews its other property and equipment for impairment whenever events or changes in circumstances indicate that the carrying value of such assets may not be recoverable. When it is determined that an asset’s estimated future net cash flows will not be sufficient to recover its carrying amount, an impairment charge is recorded to reduce its carrying value to its estimated fair value. No impairment expense was recognized during 2017 and 2016.

Derivatives — The Partnership enters into derivative contracts on its oil and natural gas products primarily to stabilize cash flows and reduce the risk and financial impact of downward commodity price movements on commodity sales. These derivatives are reflected as current assets and liabilities and non-current assets and liabilities on the balance sheet. All derivatives are marked-to-market each period with the unrealized gain or loss reflected in the statement of operations.

Debt Issuance Costs — Debt issuance costs are being amortized to interest expense over the term of the credit agreement using the straight line method. The amount of amortization under the straight-line method does not materially differ from the effective interest method. The amortization expense of these costs is included in interest expense on the statement of operations. Debt issuance costs are recorded as a direct deduction from the carrying amount of long-term debt.

Use of Estimates — The preparation of the consolidated financial statements in conformity with accounting principles generally accepted in the United States of America (“U.S. GAAP”) requires management to make estimates and assumptions that affect the reported amounts in the consolidated financial statements as well as certain financial statement disclosures. The Partnership evaluates estimates and assumptions on an ongoing basis using historical experience and other factors, including the current economic and commodity price environment. While management believes that the estimates and assumptions used in the preparation of the financial statements are appropriate, actual results could differ from those estimates.

The Partnership’s consolidated financial statements are based on a number of significant estimates, including oil and natural gas reserve quantities which are the basis for the calculation of depreciation, depletion, and amortization and impairment of oil and natural gas properties. The discounted present value of the proved oil and natural gas reserves is a major component of the ceiling test calculation and requires subjective judgments. Estimates of reserves are forecasts based on engineering and geological analyses. Different reserve engineers could reach different conclusions as to estimated quantities of oil and natural gas reserves based on the same information. Reserve estimates are inherently imprecise and estimates of non-producing properties and more recent discoveries are more imprecise than those for properties with long production histories and revisions are made to prior estimates based on updated information.

In addition to the uncertainties inherent in the reserve estimation process, these amounts are affected by historical and projected prices for oil and natural gas which have typically been volatile. There can be no assurance that significant revisions to the Partnership’s oil and natural gas reserves will not be necessary in the future.

Other significant estimates include the valuation of derivative instruments and asset retirement obligations.

 

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Index to Financial Statements

REMORA PETROLEUM, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

DECEMBER 31, 2017 AND 2016

 

Income Taxes — Federal income taxes have not been provided in the accompanying consolidated financial statements, as the Partnership does not incur federal income taxes. The partners are liable for the federal income taxes attributable to the Partnership’s taxable income.

For state taxes, all of the revenues and properties of the Partnership are attributable to Arkansas, California, Colorado, Kansas, Louisiana, Mississippi, Nebraska, New Mexico, Oklahoma and Texas.

Arkansas, California, Colorado, Kansas, Louisiana, Mississippi, Nebraska, New Mexico, and Oklahoma all tax the income of its resident and nonresident partners, but not the partnership doing business in the state. The state of Texas does tax the Partnership at a rate of 0.75% on the Partnership’s taxable margin, which is calculated as gross receipts less attributable costs of goods sold. For the years ended December 31, 2017 and 2016, the Partnership did not incur any Texas tax expense.

As of December 31, 2017 and 2016, the Partnership had no uncertain tax positions or accrued interest or penalties associated with uncertain tax positions. The Partnership does not expect that such amounts will change significantly within the next 12 months. The Partnership’s policy is to recognize interest related to any unrecognized tax positions as interest expense and penalties as operating expenses. The Partnership believes that it has appropriate support for the income tax positions taken on its tax returns and that its accruals for state tax liabilities are adequate for all open years based on an assessment of many factors including past experience and interpretations of tax law applied to the facts of each matter. The Partnership’s state income tax returns are open to audit under the statute of limitations for the periods ended December 31, 2013 through 2016. The Partnership’s federal income tax returns are open to audit under the statute of limitations for the periods ended December 31, 2014 through 2016.

Concentration of Credit RiskFinancial instruments that potentially expose the Partnership to concentrations of credit risk consist primarily of accounts receivable, derivative instruments and cash and cash equivalents. Substantially all accounts receivable result from revenues from oil, natural gas and natural gas liquids sales; therefore, the Partnership’s customers may be similarly affected by changes in economic and other conditions within the industry. Although the Partnership is directly affected by the economic conditions of the oil and natural gas production industry, management does not believe significant credit risk existed at December 31, 2017 and 2016.

The Partnership experienced no credit losses on its accounts receivable during 2017 and 2016.

The Partnership’s derivative assets from price risk management activities represent estimated unrealized receivables from an investment grade commercial bank, which is also the Partnership’s lender under its credit facility and term loan. The Partnership does not believe significant credit risk existed at December 31, 2017 and 2016. The Partnership experienced no credit losses on its derivative assets from price risk management activities during 2017 and 2016.

The Partnership maintains its cash and cash equivalents on deposit with a commercial bank. At times, deposits exceed federally insured limits. The Partnership experienced no losses on its deposits during 2017 and 2016.

New Accounting Pronouncements — In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2014-09, Revenue from Contracts with Customers. This standard provides a five-step approach to be applied to all contracts with customers and requires expanded disclosures about the nature, amount, timing and uncertainty of revenue (and the related

 

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Index to Financial Statements

REMORA PETROLEUM, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

DECEMBER 31, 2017 AND 2016

 

cash flows) arising from customer contracts, significant judgments and changes in judgments used in applying the revenue model and the assets recognized from costs incurred to obtain or fulfill a contract. The standard permits the use of either the retrospective or cumulative effect transition method, therefore the Partnership is evaluating the effect that this new guidance will have on its consolidated financial statements and related disclosures. In 2015, the FASB voted to defer the effective date of this standard, which now will not apply to the Partnership until 2019. Nonpublic entities reporting under US GAAP are permitted to apply the standard early; however, adoption can be no earlier than annual reporting periods beginning after December 15, 2016. We have not concluded on the impact of this accounting standard to our company. However, we have evaluated our contracts from customers and related revenue recognition policies and we do not believe the adoption of this standard will have a material impact on our financial statements.

In August 2014, the FASB issued ASU 2014-15, Presentation of Financial Statements—Going Concern (Subtopic 205-40): Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern. The amendments require management to assess an entity’s ability to continue as a going concern by incorporating and expanding upon certain principles that are currently in U.S. auditing standards. Specifically, the amendments (1) provide a definition of the term substantial doubt, (2) require an evaluation every reporting period including interim periods, (3) provide principles for considering the mitigating effect of management’s plans, (4) require certain disclosures when substantial doubt is alleviated as a result of consideration of management’s plans, (5) require an express statement and other disclosures when substantial doubt is not alleviated and (6) require an assessment for a period of one year after the date that the financial statements are issued (or available to be issued). The amendments in this Update are effective for the annual period ending after December 15, 2016, and for annual periods and interim periods thereafter. The Partnership adopted this accounting standard as of December 31, 2016.

In February 2016, the FASB issued ASU No. 2016-02, Leases (“ASU 2016-02”). ASU 2016- 02 requires that a lessee should recognize the assets and liabilities that arise from leases. All leases create an asset and a liability for the lessee in accordance with FASB Concepts Statement No. 6, Elements of Financial Statements. A lessee should recognize in the statement of financial position a liability to make lease payments (the lease liability) and a right-of-use asset representing its right to use the underlying asset for the lease term. When measuring assets and liabilities arising from a lease, a lessee should include payments to be made in optional periods only if the lessee is reasonably certain to exercise an option to extend the lease or not to exercise an option to terminate the lease. Similarly, optional payments to purchase the underlying asset should be included in the measurement of lease assets and lease liabilities only if the lessee is reasonably certain to exercise that purchase option. In addition, also consistent with the previous leases guidance, a lessee should exclude most variable lease payments in measuring lease assets and lease liabilities, other than those that depend on an index or a rate or are in substance fixed payments. For leases with a term of 12 months or less, a lessee is permitted to make an accounting policy election by class of underlying asset not to recognize lease assets and lease liabilities. If a lessee makes this election, it should recognize lease expense for such leases generally on a straight -line basis over the lease term. For nonpublic entities, the new standard is effective for annual reporting periods beginning after December 15, 2019, and interim periods within fiscal years beginning after December 15, 2020. The Partnership is currently evaluating the impact of this accounting standard.

In August 2016, the FASB issued ASU 2016-15, Classification of Certain Cash Receipts and Cash Payments, which addressees eight classification issues related to the statement of cash flows: debt

 

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Index to Financial Statements

REMORA PETROLEUM, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

DECEMBER 31, 2017 AND 2016

 

prepayment or debt extinguishment costs, settlement of zero-coupon bonds, contingent consideration payments made after a business combination, proceeds from the settlement of insurance claims, proceeds from the settlement of corporate-owned life insurance policies, distributions received from equity method investees, beneficial interests in securitization transactions, and separately identifiable cash flows and application of the predominance principle. ASU 2016-15 is effective for the Partnership for fiscal years beginning after December 15, 2018 and interim periods beginning after December 15, 2019. Early adoption is permitted. The Partnership is currently evaluating the impact of this accounting standard.

In January 2017, the FASB issued ASU 2017-01, Business Combinations, to clarify the definition of a business by adding guidance to assist entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of a business. This standard provides a screen to determine when a set is not a business. The screen requires that when substantially all of the fair value of the gross assets acquired (or disposed of) is concentrated in a single identifiable asset or group of similar identifiable assets, the set is not a business. If the screen is not met, this standard (1) requires that to be considered a business, a set must include, at a minimum, an input and a substantive process that together significantly contribute to the ability to create output and (2) removes the evaluation of whether a market participant could replace the missing elements. ASU 2017-01 is effective for the Partnership for fiscal years beginning after December 15, 2018 and interim periods beginning after December 15, 2019. The Partnership is currently evaluating the impact of this accounting standard.

Reclassifications — Certain amounts in prior year’s consolidated financial statements have been reclassified to conform to current year presentation. None of these reclassifications impacted previously reported equity, cash flows or net income (loss).

 

3.   ACQUISITIONS & DIVESTITURES

On December 19, 2017, the Partnership entered into an agreement with an unrelated third party to acquire various working interests and net revenue interests in certain proved properties for a purchase price of approximately $14.2 million. The adjusted purchase price was paid to seller at closing. The Partnership accounted for this acquisition pursuant to the acquisition method of accounting whereby all the acquired assets and assumed liabilities are recorded at their estimated fair values. Allocation of the adjusted purchase price is as follows:

 

Oil and gas properties

   $ 10,549,245  

Asset retirement costs

   $ 15,805,542  

Asset retirement obligations

   $ (15,805,542

On November 30, 2017, the Partnership sold various land and surface rights in addition to the working interests and net revenue interests in certain proved properties for a sale price of approximately $1.25 million. The effective date of this sale was September 7, 2017. The Partnership accounted for this sale pursuant to the acquisition method of accounting whereby all the sold assets and liabilities are recorded at their estimated fair values. Allocation of the adjusted sale price is as follows:

 

Oil and gas properties

   $ 1,246,182  

Asset retirement costs

   $ 39,998  

Asset retirement obligations

   $ (39,998

On July 19, 2017, the Partnership sold various working interests and net revenue interests in certain proved properties for a sale price of approximately $16.5 million. The effective date of this sale was June 1,

 

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Index to Financial Statements

REMORA PETROLEUM, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

DECEMBER 31, 2017 AND 2016

 

2017. The Partnership accounted for this sale pursuant to the acquisition method of accounting whereby all the sold assets and liabilities are recorded at their estimated fair values. Allocation of the adjusted sale price is as follows:

 

Oil and gas properties

   $ 16,500,000  

Asset retirement costs

   $ 3,803,813  

Asset retirement obligations

   $ (3,930,756

On April 28, 2017, the Partnership sold certain leasehold acreage to an unrelated third party for a sale price of $1,460,458, recorded as a gain in other income (expense) in the consolidated statement of operations. The effective date of the sale was on April 1, 2017.

On January 19, 2017, the Partnership acquired various working interests and net revenue interests in certain proved properties for a purchase price of approximately $1.2 million. The effective date of this sale was September 1, 2016. The Partnership accounted for this acquisition pursuant to the acquisition method of accounting whereby all the acquired assets and assumed liabilities are recorded at their estimated fair values. Allocation of the adjusted purchase price is as follows:

 

Oil and gas properties

   $ 995,039  

Asset retirement costs

   $ 226,735  

Asset retirement obligations

   $ (226,735

On December 22, 2016, the Partnership acquired various working interests and net revenue interests in certain proved properties from an unrelated third party for a purchase price of approximately $10.5 million. The effective date of this acquisition was September 1, 2016. The Partnership accounted for this acquisition pursuant to the acquisition method of accounting whereby all the acquired assets and assumed liabilities are recorded at their estimated fair values. Allocation of the adjusted purchase price is as follows:

 

Oil and gas properties

   $ 8,766,269  

Asset retirement costs

   $ 3,545,658  

Asset retirement obligations

   $ (3,545,658

On December 16, 2016, the Partnership acquired various working interests and net revenue interests in certain proved properties from an unrelated third party for a purchase price of approximately $1.45 million. The effective date of this acquisition was November 1, 2016. The Partnership accounted for this acquisition pursuant to the acquisition method of accounting whereby all the acquired assets and assumed liabilities are recorded at their estimated fair values. Allocation of the adjusted purchase price is as follows:

 

Oil and gas properties

   $ 1,416,011  

Asset retirement costs

   $ 1,678  

Asset retirement obligations

   $ (1,678

On December 9, 2016, the Partnership acquired various working interests and net revenue interests in certain proved properties from an unrelated third party for a purchase price of approximately $27.5 million. The effective date of this acquisition was September 1, 2016. The Partnership accounted for this acquisition

 

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Index to Financial Statements

REMORA PETROLEUM, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

DECEMBER 31, 2017 AND 2016

 

pursuant to the acquisition method of accounting whereby all the acquired assets and assumed liabilities are recorded at their estimated fair values. Allocation of the adjusted purchase price is as follows:

 

Oil and gas properties

   $ 25,264,277  

Asset retirement costs

   $ 1,605,273  

Asset retirement obligations

   $ (1,605,273

In all acquisitions, the Partnership incurred immaterial amount of transaction costs, which are reflected in general and administrative expenses in the accompanying consolidated statements of operations for the years ended December 31, 2017 and 2016. For certain acquired oil and gas properties, we recorded post close adjustments as a result of the change in estimates of certain revenues and expenses incurred between the effective and closing date of the acquisitions.

In all sales of our assets, the sales did not significantly impact the ratio of cost to proved reserves, and as such, no gains / losses were recognized. Any gains / losses were reflected as an adjustment to the full cost pool.

 

4.   DERIVATIVE INSTRUMENTS

The Partnership enters into various derivatives for the purpose of hedging the impact of market fluctuations of crude oil and natural gas prices. These derivatives include crude oil and natural gas costless collars and swaps. The Partnership’s commodity derivative instruments generally serve as effective economic hedges of commodity risk exposure, however, the Partnership has elected not to account for the derivatives as cash flow hedges. As such, the Partnership recognizes all changes in fair value of its derivatives in earnings.

As of December 31, 2017, the Partnership had crude oil commodity contracts in place based on NYMEX prices as follows:

 

     FIXED-PRICE SWAPS  

PRODUCTION PERIOD

   BARRELS      WEIGHTED
AVERAGE
FIXED PRICE
 

2018

     246,000      $ 51.97  

2019

     187,000      $ 51.49  

2020

     126,000      $ 53.04  

2021

     72,000      $ 51.63  

As of December 31, 2017, the Partnership had natural gas commodity contracts in place based on NYMEX prices as follows:

 

     FIXED-PRICE SWAPS      PUT OPTIONS      CALL OPTIONS  

PRODUCTION
PERIOD

   MMBTU      WEIGHTED
AVERAGE
FIXED PRICE
     MMBTU      WEIGHTED
AVERAGE
FIXED PRICE
     MMBTU      WEIGHTED
AVERAGE
FIXED PRICE
 

2018

     6,330,000      $ 2.81        600,000      $ 2.50        600,000      $ 3.10  

2019

     5,585,000      $ 2.69        60,000      $ 2.50        60,000      $ 3.13  

2020

     3,920,000      $ 2.83        540,000      $ 2.50        540,000      $ 3.17  

2021

     880,000      $ 2.79        1,200,000      $ 2.50        1,200,000      $ 3.23  

 

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Index to Financial Statements

REMORA PETROLEUM, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

DECEMBER 31, 2017 AND 2016

 

As of December 31, 2017, the Partnership had natural gas liquids commodity contracts in place based on NYMEX prices as follows:

 

     FIXED-PRICE SWAPS  

PRODUCTION PERIOD

   BARRELS      WEIGHTED
AVERAGE
FIXED PRICE
 

2018

     558,429      $ 25.50  

2019

     445,714      $ 25.05  

2020

     214,857      $ 24.82  

The Partnership’s commodity derivative financial instruments are recorded at their fair values on the consolidated balance sheets, with the change in fair value recognized in the consolidated statements of operations in other income (expense) as follows:

 

   

ASSET DERIVATIVES

   

LIABILITY DERIVATIVES

 
        2017     2016         2017     2016  

AS OF DECEMBER 31,

 

BALANCE
SHEET
LOCATION

  FAIR
VALUE
    FAIR
VALUE
   

BALANCE

SHEET

LOCATION

  FAIR
VALUE
    FAIR
VALUE
 

Commodity contracts (current)

  Current assets   $ 3,100,944     $ 591,536     Current liabilities   $ (3,714,682   $ (2,444,183

Commondity contracts (long-term)

  Long-term assets     2,776,229       736,800     Long-term liabilities     (3,564,335     (2,847,344
   

 

 

   

 

 

     

 

 

   

 

 

 

Total derivatives

    $ 5,877,173     $ 1,328,336       $ (7,279,017   $ (5,291,527
   

 

 

   

 

 

     

 

 

   

 

 

 

 

    

LOCATION OF GAIN
(LOSS) RECOGNIZED
ON STATEMENT OF
OPERATIONS

   AMOUNT OF GAIN (LOSS)
RECOGNIZED AS INCOME
(EXPENSE) ON DERIVATIVES
 
                  2017                      2016          

Realized commodity contract

   Other income    $ 2,567,199      $ 4,030,493  

Unrealized commodity contract

   Other income (expense)         2,567,057        (10,311,311
     

 

 

    

 

 

 
      $ 5,134,256      $ (6,280,818
     

 

 

    

 

 

 

 

5.   FAIR VALUE MEASUREMENTS

Accounting Standards Codification (“ASC”) 820, Fair Value Measurements and Disclosures defines fair value, establishes a framework for measuring fair value and explains the related disclosure requirements. ASC 820 indicates, among other things, that a fair value measurement assumes that the transaction to sell an asset or transfer a liability occurs in the principal market for the asset or liability or, in the absence of a principal market, the most advantageous market for the asset or liability and defines fair value based upon an exit price model.

ASC 820 establishes a valuation hierarchy for disclosure of the inputs to valuation used to measure fair value. This hierarchy prioritizes the inputs into three broad levels as follows. Level 1 inputs are quoted prices (unadjusted) in active markets for identical assets or liabilities. Level 2 inputs are quoted prices for similar assets and liabilities in active markets or inputs that are observable for the asset or liability, either

 

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Index to Financial Statements

REMORA PETROLEUM, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

DECEMBER 31, 2017 AND 2016

 

directly or indirectly through market corroboration, for substantially the full term of the financial instrument. Level 3 inputs are unobservable inputs based on the Partnership’s assumptions used to measure assets and liabilities at fair value. A financial asset or liability’s classification within the hierarchy is determined based on the lowest level input that is significant to the fair value measurement.

The Partnership carries cash, accounts receivable and payables at historical value which approximate fair value due to the short-term nature of these instruments. Based on market rates for similar loans, the fair value of long-term debt approximates its carrying value. Nonfinancial assets and liabilities initially measured at fair value include certain assets and liabilities acquired in a business combination, impaired other property and equipment and asset retirement obligations. Financial assets and liabilities are reported in the accompanying consolidated financial statements at fair value.

The following table sets forth, by level within the fair value hierarchy, the Partnership’s financial assets, net of liabilities that were accounted for at fair value as of December 31, 2017 and 2016. Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The Partnership’s assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.

 

     DECEMBER 31, 2017  
     LEVEL 1      LEVEL 2     LEVEL 3      TOTAL  

ASSETS

          

Commodity collars

   $      $ 34,800     $      $ 34,800  

LIABILITIES

          

Commodity fixed price swaps

   $      $ (1,436,644   $      $ (1,436,644
     DECEMBER 31, 2016  
     LEVEL 1      LEVEL 2     LEVEL 3      TOTAL  

LIABILITIES

          

Commodity fixed price swaps

   $      $ (3,963,191   $      $ (3,963,191

In general, the determination of the fair values incorporates various factors. These factors include the credit standing of the counterparties for the Partnership’s assets and the impact of the Partnership’s own nonperformance risk on any liabilities. As of December 31, 2017 and 2016, the Partnership’s derivative contracts were placed at major corporations with investment grade credit ratings which have a low credit risk. The Partnership is exposed to credit risk to the extent of nonperformance by the counterparties in the derivative contracts discussed; however, the Partnership does not anticipate such nonperformance.

 

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Index to Financial Statements

REMORA PETROLEUM, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

DECEMBER 31, 2017 AND 2016

 

6.   ASSET RETIREMENT OBLIGATION

The Partnership has an ARO associated with the future abandonments of its oil and natural gas properties. The following table presents the activity of the Partnership’s ARO for the years ended December 31:

 

     2017      2016  

Asset retirement obligation, beginning of year

   $ 8,326,214      $ 2,885,038  

Liabilities incurred

     16,032,377        5,288,860  

Accretion expense

     426,925        157,950  

Liabilities sold

     (3,992,921       

Liabilities settled

     (212,213      (5,634

Revisions of estimates

     1,110,533         
  

 

 

    

 

 

 
     21,690,915        8,326,214  

Less: current portion

     860,342        1,041,734  
  

 

 

    

 

 

 

Asset retirement obligation, long-term

   $ 20,830,573      $ 7,284,480  
  

 

 

    

 

 

 

 

7.   DEBT

Long-term debt consisted of the following at December 31:

 

     2017      2016  

Line of credit

   $ 25,450,000      $ 42,900,000  

Term loan

     25,000,000        25,000,000  
  

 

 

    

 

 

 

Total long-term debt

     50,450,000        67,900,000  

Less: debt issuance costs

     (1,263,901      (1,645,076
  

 

 

    

 

 

 

Long-term debt, net

   $ 49,186,099      $ 66,254,924  
  

 

 

    

 

 

 

In May 2016, the Partnership entered into an amended and restated credit agreement with BOKF, NA dba Bank of Texas (“Bank of Texas”) an aggregate commitment of $75,000,000 and an initial borrowing base of $23,000,000. The credit agreement has a maturity date of May 27, 2020 and is secured by the oil and natural gas properties. There is a commitment fee of up to 0.50% on the unused availability, as defined in the credit agreement. Advances on the credit agreement were $25,450,000 and $42,900,000 at December 31, 2017 and 2016, respectively. Advances bear interest at the bank’s alternate base rate plus an applicable margin from 0.75% to 1.75% depending on the utilization level as defined in the agreement or at the LIBOR plus an applicable margin from 2.00% to 3.00% depending on the utilization levels as defined in the agreement.

The credit agreement provides for certain affirmative covenants and restrictions, including certain required financial ratios that require maintenance of a minimum ratio of working capital, a maximum ratio of indebtedness to earnings before interest, incomes taxes, depreciation and amortization and other non-cash charges (“EBITDAX”), and a minimum total adjusted leverage to PDP-10 asset coverage calculation. In December 2016, the Partnership entered into first amendment to the amended and restated credit agreement (“First Amendment”). Under the First Amendment, advances bear interest at the bank’s alternate base rate plus an applicable margin from 1.75% to 2.75% depending on the utilization level as defined in the

 

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Index to Financial Statements

REMORA PETROLEUM, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

DECEMBER 31, 2017 AND 2016

 

agreement or at the LIBOR plus an applicable margin from 2.75% to 3.75% depending on the utilization levels as defined in the agreement in exchange for an increased borrowing base. At December 31, 2017, the borrowing base was $45,000,000. As of December 31, 2017, the Partnership was in compliance with all of its financial covenants as of December 31, 2017 but did not meet an affirmative covenant to provide Bank of Texas with the consolidated financial statements within 120 days after December 31, 2017. We have obtained a waiver from Bank of Texas for the non-compliance with the affirmative covenant.

In May 2016, the Partnership also entered into a second lien credit agreement with Goldman Sachs Specialty Lending Group, L.P. (“Goldman Sachs”) for an aggregate commitment of $25,000,000 and a maturity of November 27, 2020. The second lien facility bears interest at the bank’s base rate plus 10% to 11% depending on the utilization levels as defined in the agreement or at the LIBOR plus 11% to 12% depending on the utilization levels as defined in the agreement with a minimum LIBOR of 1.0%. At December 31, 2017, the Partnership had $25,000,000 in outstanding borrowings under this agreement. The financial covenants under this second lien credit agreement are identical to those of the first lien credit agreement, and the Partnership was in compliance with all of its financial covenants as of December 31, 2017 but did not meet an affirmative covenant to provide Goldman Sachs with the consolidated financial statements within 120 days after December 31, 2017. We have obtained a waiver from Goldman Sachs for the non-compliance with the affirmative covenant.

 

8.   PARTNERS’ CAPITAL / (DEFICIT)

In connection with the formation of the Partnership, Remora Petroleum GP, LLC (the “General Partner”) and certain other qualified investors (the “Class A Limited Partners”) entered into a limited partnership agreement dated October 19, 2011. The total remaining capital commitment was $0 as of December 31, 2017 and 2016.

Upon request, Class A Limited Partners and the General Partner were required to make capital contributions to the Partnership based on amounts as determined by the limited partnership agreement. During 2017 and 2016, contributions from both the General Partner and the Class A Limited Partners totaled $0 and $1,000,000, respectively. The General Partner has sole discretion as to the timing, amount and form of distributions. No distributions were made in 2017 or 2016.

On May 27, 2016, the Partnership amended the limited partnership agreement to issue a new class of partnership interest designated as Class A-3 Partnership Interest. The Class A-3 partners have no capital commitment and no voting rights.

 

9.   RELATED PARTY TRANSACTIONS

During 2017 and 2016, the Partnership paid two of its partners approximately $400,000 each year for management services performed as employees of the Partnership.

 

10.   COMMITMENTS AND CONTINGENCIES

Commitments — In August 2014, the Partnership entered into a lease agreement for new office space with a third party. In April 2015, the lease was amended to include additional office space. In November 2017, the Company entered into a lease agreement with another third party for a new office space. Rent expense for 2017 and 2016 was approximately $192,000 and $163,000, respectively.

 

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Index to Financial Statements

REMORA PETROLEUM, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

DECEMBER 31, 2017 AND 2016

 

Future approximate minimum payments related to this lease are as follows:

 

YEARS ENDING DECEMBER 31,

      

2018

   $ 324,243  

2019

     362,458  

2020

     312,373  

2021

     225,318  

2022

     222,312  

Thereafter

     265,958  
  

 

 

 
   $ 1,712,662  
  

 

 

 

Contingencies — In the ordinary course of business, the Partnership is subject to possible loss contingencies arising from federal, state, and local environmental, health, and safety laws and regulations and third-party litigation. There are no matters which, in the opinion of management, will have a material adverse effect on the financial position, results of operations, or cash flows of the Partnership.

 

11.   SUBSEQUENT EVENTS

On April 9, 2018, the Partnership entered into an agreement with an unrelated third party to acquire oil and natural gas properties for a purchase price of approximately $4.1 million. The adjusted purchase price shall be paid to the seller at closing.

The Partnership has evaluated subsequent events through May 14, 2018, the date on which these consolidated financial statements were available to be issued.

 

12.   SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED)

The reserves at December 31, 2017 and 2016 presented below were prepared Cawley, Gillespie & Associates, Inc. Estimates of proved reserves are inherently imprecise and are continually subject to revision based on production history, results of additional exploration and development, price changes and other factors. The reserves are located in various states (AR, CA, CO, KS, LA, MS, NE, NM, OK & TX).

Guidelines prescribed in FASB ASC Topic 932, Extractive Industries — Oil and Gas (“ASC Topic 932”), have been followed for computing a standardized measure of future net cash flows and changes therein related to estimated proved reserves. Future cash inflows and future production and development and abandonment costs are determined by applying prices and costs, including transportation, quality, and basis differentials, to the period-end estimated quantities of oil, natural gas and NGLs to be produced in the future. The resulting future net cash flows are reduced to present value amounts by applying a ten percent annual discount factor. Future operating costs are determined based on estimates of expenditures to be incurred in producing the proved oil and natural gas reserves in place at the end of the period using period-end costs and assuming continuation of existing economic conditions, plus overhead incurred. Future development and abandonment costs are determined based on estimates of capital expenditures to be incurred in developing proved oil and natural gas reserves.

The assumptions used to compute the standardized measure are those prescribed by the FASB and the SEC. These assumptions do not necessarily reflect management’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

 

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Index to Financial Statements

REMORA PETROLEUM, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

DECEMBER 31, 2017 AND 2016

 

computations since these reserve quantity estimates are the basis for the valuation process. Reserve estimates are inherently imprecise, and estimates of new discoveries and undeveloped locations are more imprecise than estimates of established proved producing oil and natural gas properties. Accordingly, these estimates are expected to change as future information becomes available.

The following table sets forth information for the years ended December 31, 2017 and 2016, with respect to changes in the proved reserves:

 

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

January 1, 2016

     1,552       25,506       603  
  

 

 

   

 

 

   

 

 

 

Revisions

     (346     (2,728     (96

Extensions, discoveries, and other additions

     55       161       12  

Divestiture of Reserves

                  

Purchase of reserves

     572       46,518       3,169  

Production

     (146     (2,438     (78
  

 

 

   

 

 

   

 

 

 

December 31, 2016

     1,687       67,019       3,610  

Revisions

     170       4,634       651  

Extensions, discoveries, and other additions

     1,062       63,107       3,645  

Divestiture of Reserves

     (121     (4,353     (1,429

Purchase of reserves

     629       24,464       678  

Production

     (201     (6,747     (404
  

 

 

   

 

 

   

 

 

 

December 31, 2017

     3,226       148,124       6,751  

Proved developed reserves, included above:

      

January 1, 2016

     1,552       25,506       603  

December 31, 2016

     1,687       67,019       3,610  

December 31, 2017

     2,156       84,785       3,119  

Proved undeveloped reserves, included above(1):

      

January 1, 2016

                  

December 31, 2016

                  

December 31, 2017

     1,070       63,338       3,631  

As of December 31, 2016, the reserves were comprised of 10.2% crude oil, 67.8% natural gas, and 21.9% NGL on an energy equivalent basis. As of December 31, 2017, the reserves were comprised of 9.3% crude oil, 71.2% natural gas, and 19.5% NGL on an energy equivalent basis.

The following values for the 2017 proved reserves were derived based on prices of $48.656 per Bbl of crude oil, and $2.941 per Mcf of natural gas, and $18.569 per Bbl of NGL. The following values for the 2016 proved reserves were derived based on prices of $37.78 per Bbl of crude oil, and $1.574 per Mcf of natural gas, and $11.747 per Bbl of NGL. These prices were based on the 12-month arithmetic average first-of-month price for January 2017 through December 2017, and January 2016 through December 2016, respectively. The crude oil pricing was based on the West Texas Intermediate (“WTI”) price; the natural gas pricing was based on the Henry Hub price; the NGL pricing was 38% and 32% of WTI in 2017 and 2016, respectively. All prices have been adjusted for transportation, quality and basis differentials.

For the year ended December 31, 2017, the Company had upward revisions of previous estimates of 1,593.4 MBOE. These revisions are primarily due to an increase in the SEC prices causing the wells to be

 

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Index to Financial Statements

REMORA PETROLEUM, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

DECEMBER 31, 2017 AND 2016

 

more economic. As a result of ongoing drilling and completion activities during the fiscal year in 2017, the Company reported extensions, discoveries, and other additions of 15,224.4 MBOE. Additionally, during the fiscal year in 2017 the Company purchased reserves of 5,384.6 MBOE and had divestitures of 2,276.0 MBOE.

For the year ended December 31, 2016, the Company had downward revisions of previous estimates of 892.2 MBOE. These revisions are primarily due to the result of decreased decline curve related to well performance on existing wells as well as a decrease in the SEC prices causing the wells to be less economic. As a result of ongoing drilling and completion activities during the fiscal year in 2016, the Company reported extensions, discoveries and other additions of 94.1 MBOE. Additionally, during the fiscal year in 2016, the Company purchased reserves of 11,494.1 MBOE.

The following summary sets forth the future net cash flows related to proved oil and natural gas reserves based on the standardized measure prescribed in ASC Topic 932 (in thousands):

 

     As of December 31,  
     2017      2016  

Future crude oil, natural gas and NGLs sales

   $ 718,009      $ 206,487  

Future production costs

     (357,520      (115,345

Future development costs

     (88,978      (1,447

Future income tax expense

     (771      (199
  

 

 

    

 

 

 

Future net cash flows

     270,740        89,496  
  

 

 

    

 

 

 

10% annual discount

     (154,360      (34,894
  

 

 

    

 

 

 

Standardized measure of discounted future net cash flows

   $ 116,380      $ 54,601  
  

 

 

    

 

 

 

The principal sources of change in the standardized measure of discounted future net cash flows are (in thousands):

 

     For the Years Ended December 31,  
             2017                      2016          

Balance at beginning of period

   $ 54,601      $ 40,114  

Sales of crude oil, natural gas and NGLs

     (15,908      (4,257

Net change in prices and production costs

     29,742        (11,572

Net changes in future development costs

     (4,325      1,827  

Extensions, discoveries, and other additions

     28,600        1,268  

Sales of reserves

     (7,970       

Purchase of reserves

     27,762        30,256  

Revisions of previous quantity estimates

     4,156        (5,700

Previously estimated development costs incurred

             

Net change in income taxes

     (355      19  

Accretion of discount

     5,472        4,025  

Other

     (5,395      (1,379
  

 

 

    

 

 

 

Balance at end of period

   $ 116,380      $ 54,601  
  

 

 

    

 

 

 

 

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Index to Financial Statements
REPORT OF INDEPENDENT CERTIFIED PUBLIC ACCOUNTANTS

To the Partners of

Remora Petroleum, L.P.

We have audited the accompanying Statements of Revenues and Direct Operating Expenses of certain oil and gas properties (“the Statements”) owned by Vendera Resources II, LLC and its affiliates for the years ended December 31, 2017 and 2016 and the related notes to the Statements.

Management’s responsibility for the financial statements

Management is responsible for the preparation and fair presentation of these Statements 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 financial statements that are free from material misstatement, whether due to fraud or error.

Auditor’s responsibility

Our responsibility is to express an opinion on these Statements 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 Statements are free from material misstatement.

An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the Statements. The procedures selected depend on the auditor’s judgment, including the assessment of the risks of material misstatement of the financial statements, 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 Statements 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 Statements.

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 Statements referred to above present fairly, in all material respects, the revenues and direct operating expenses of certain oil and gas properties owned by Vendera Resources II, LLC and its affiliates as of December 31, 2017 and 2016, in accordance with accounting principles generally accepted in the United States of America.

Emphasis of matter

As described in Note 1 to the Statements, the accompanying statements of revenue and direct operating expenses were prepared for the purpose of complying with the rules and regulations of the U.S. Securities and Exchange Commission (for inclusion in the registration statement on Form S-1 of Remora Royalties, Inc.) and are not intended to be a complete presentation of the results of operations of the oil and gas properties owned by Vendera Resources II, LLC and its affiliates. Our opinion is not modified with respect to this matter.

/s/ Grant Thornton LLP

Dallas, Texas

May 14, 2018

 

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Index to Financial Statements

STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES OF CERTAIN OIL AND GAS PROPERTIES OWNED BY VENDERA RESOURCES II, LLC AND ITS AFFILIATES

 

     For the Three Months Ended
March 31,
    For the Years Ended
December 31,
 
             2018                     2017             2017     2016  
     (unaudited)              

Oil, natural gas and NGL revenues

   $ 994,065     $ 1,036,013     $ 3,997,639     $ 3,311,353  

Direct operating expenses

     (98,767     (113,985     (425,358     (470,336
  

 

 

   

 

 

   

 

 

   

 

 

 

Revenues in excess of direct operating expenses

     895,298       922,028     $ 3,572,281     $ 2,841,017  
  

 

 

   

 

 

   

 

 

   

 

 

 

 

 

 

The accompanying notes are an integral part of these statements.

 

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Index to Financial Statements

NOTES TO STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES OF CERTAIN OIL AND GAS PROPERTIES OWNED BY VENDERA

RESOURCES II, LLC AND ITS AFFILIATES

 

1.   BASIS OF PRESENTATION

The accompanying statements include revenues from the sale of crude oil, natural gas and natural gas liquids (“NGLs”) production and direct operating expenses associated with certain proved reserves and properties in the United States of America (collectively, the “Properties”) owned by Vendera Resources II, LLC and its affiliates (“Vendera Resources II”) for the periods presented. Revenues and direct operating expenses are presented on the accrual basis of accounting and were derived from Vendera Resources II’s historical accounting records. During the periods presented, the Properties were not accounted for or operated as a separate division or entity of Vendera Resources II; therefore, certain expenses such as depreciation, depletion and amortization expense, general and administrative expense, interest expense and income taxes were not allocated to the Properties. Accordingly, complete separate financial statements reflecting the financial position, results of operations and cash flows of the Properties prepared in accordance with accounting principles generally accepted in the United States of America (“U.S. GAAP”) are not presented because the information necessary to prepare such statements is neither readily available on a combined or individual property basis, nor practicable to obtain in these circumstances. As such, the accompanying statements are not intended to be a complete presentation of the revenues and expenses of the Properties and are not indicative of the results of the operation of the Properties going forward due to the omission of various expenses including those described above.

 

2.   SIGNIFICANT ACCOUNTING POLICIES

Revenue Recognition

Vendera Resources II recognizes revenue 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.

Direct Operating Expenses

Direct operating expenses are recognized when incurred and include: (i) gathering, transportation, and other direct operating expenses, (ii) production taxes and (iii) ad valorem taxes.

Management Estimates

The preparation of financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of revenues and direct operating expenses during the reporting period. These estimates and assumptions are based on management’s best estimates and judgment. Actual results may differ from the estimates and assumptions used in the preparation of the statements of revenues and direct operating expenses. Management evaluates its estimates and assumptions on an ongoing basis using historical experience and other factors, including the current economic environment, which management believes to be reasonable under the circumstances. Management evaluates subsequent events through the date the financial statements are issued.

 

3.   COMMITMENTS AND CONTINGENCIES

Management is not aware of any legal, environmental or other commitments or contingencies that would have a material effect on Vendera Resources II’s financial condition, results of operations or liquidity.

 

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Index to Financial Statements

NOTES TO STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES OF CERTAIN OIL AND GAS PROPERTIES OWNED BY VENDERA

RESOURCES II, LLC AND ITS AFFILIATES — (Continued)

 

4.   SUBSEQUENT EVENTS

Management has evaluated subsequent events through May 14, 2018, the date the financial statements were issued.

 

5.   SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION (UNAUDITED)

The reserves at December 31, 2017 presented below were prepared Cawley, Gillespie & Associates, Inc. Estimates of proved reserves are inherently imprecise and are continually subject to revision based on production history, results of additional exploration and development, price changes and other factors. The reserves are located in Louisiana and Texas.

Guidelines prescribed in FASB ASC Topic 932 Extractive Industries – Oil and Gas (“ASC Topic 932”) have been followed for computing a standardized measure of future net cash flows and changes therein related to estimated proved reserves. Future cash inflows and future production costs are determined by applying prices and costs, including transportation, quality, and basis differentials, to the period-end estimated quantities of oil, natural gas and NGLs to be produced in the future. The resulting future net cash flows are reduced to present value amounts by applying a ten percent annual discount factor. Future operating costs are determined based on estimates of expenditures to be incurred in producing the proved oil and natural gas reserves in place at the end of the period using period-end costs and assuming continuation of existing economic conditions, plus overhead to be incurred.

The assumptions used to compute the standardized measure are those prescribed by the FASB and the SEC. These assumptions do not necessarily reflect management’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. Reserve estimates are inherently imprecise, and estimates of new discoveries and undeveloped locations are more imprecise than estimates of established proved producing oil and natural gas properties. Accordingly, these estimates are expected to change as future information becomes available.

The following table sets forth information for the years ended December 31, 2017 and 2016, with respect to changes in the proved reserves:

 

 

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

January 1, 2016

     272        12,402        3  

Revisions

     (10      (98       

Production

     (19      (1,228       
  

 

 

    

 

 

    

 

 

 

December 31, 2016

     243        11,076        3  

Revisions

     15        1,309         

Production

     (18      (1,163       
  

 

 

    

 

 

    

 

 

 

December 31, 2017

     240        11,222        3  
  

 

 

    

 

 

    

 

 

 

As of December 31, 2017 and 2016, all of the reserves for Vendera Resources II are proved developed.

 

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Index to Financial Statements

NOTES TO STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES OF CERTAIN OIL AND GAS PROPERTIES OWNED BY VENDERA

RESOURCES II, LLC AND ITS AFFILIATES — (Continued)

 

As of December 31, 2017, the reserves were comprised of 11.4% crude oil, 88.5% natural gas, and 0.1% NGLs on an energy equivalent basis. As of December 31, 2016, the reserves were comprised of 11.6% crude oil, 88.3% natural gas, and 0.1% NGLs on an energy equivalent basis. The following values for the 2017 proved reserves were derived based on prices of $48.591 per Bbl of crude oil, and $2.704 per Mcf of natural gas, and $23.719 per Bbl of NGL. The following values for the 2016 proved reserves were derived based on prices of $40.005 per Bbl of crude oil, and $2.201 per Mcf of natural gas, and $19.750 per Bbl of NGL. These prices were based on the 12-month arithmetic average first-of-month price for January 2017 through December 2017, and January 2016 through December 2016, respectively. The crude oil pricing was based on the West Texas Intermediate (“WTI”) price; the natural gas pricing was based on the Henry Hub price; the NGL pricing was 49% of WTI in 2017 and 2016, respectively. All prices have been adjusted for transportation, quality and basis differentials.

For the year ended December 31, 2017, the Company had upward revisions of previous estimates of 234.1 MBOE. These revisions are primarily due to higher trailing first of the month of twelve month average price resulting in longer economic lives of wells resulting in additional reserves.

For the year ended December 31, 2016, the Company had downward revisions of previous estimates of 27.6 MBOE. These revisions are due to lower trailing first of the month of twelve month average price resulting in shorter economic lives of wells resulting in less reserves.

The following summary sets forth the future net cash flows related to proved oil and natural gas reserves based on the standardized measure prescribed in ASC Topic 932 (in thousands):

 

     As of December 31,  
     2017      2016  

Future crude oil, natural gas and NGLs sales

   $ 42,092      $ 34,157  

Future production costs

     (3,424      (2,950

Future income tax expense

     (103      (91
  

 

 

    

 

 

 

Future net cash flows

     38,565        31,116  

10% annual discount

     (20,280      (15,884
  

 

 

    

 

 

 

Standardized measure of discounted future net cash flows

   $ 18,285      $ 15,232  
  

 

 

    

 

 

 

 

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Index to Financial Statements

NOTES TO STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES OF CERTAIN OIL AND GAS PROPERTIES OWNED BY VENDERA

RESOURCES II, LLC AND ITS AFFILIATES — (Continued)

 

The principal sources of change in the standardized measure of discounted future net cash flows are (in thousands):

 

     For the Years Ended
December 31,
 
     2017      2016  

Balance at beginning of period

   $ 15,232      $ 18,138  

Sales of crude oil, natural gas and NGLs

     (3,572      (2,841

Net change in prices and production costs

     3,512        (2,147

Revisions of previous quantity estimates

     2,030        (204

Net change in income taxes

     (3      9  

Accretion of discount

     1,527        1,819  

Other

     (441      458  
  

 

 

    

 

 

 

Balance at end of period

   $ 18,285      $ 15,232  
  

 

 

    

 

 

 

 

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Index to Financial Statements
REPORT OF INDEPENDENT CERTIFIED PUBLIC ACCOUNTANTS

To the Partners of

Remora Petroleum, L.P.

We have audited the accompanying Statements of Revenues and Direct Operating Expenses of certain oil and gas properties (“the Statements”) owned by Vendera Resources III, L.P. and its affiliates for the years ended December 31, 2017 and 2016 and the related notes to the Statements.

Management’s responsibility for the financial statements

Management is responsible for the preparation and fair presentation of these Statements 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 financial statements that are free from material misstatement, whether due to fraud or error.

Auditor’s responsibility

Our responsibility is to express an opinion on these Statements 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 Statements are free from material misstatement.

An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the Statements. The procedures selected depend on the auditor’s judgment, including the assessment of the risks of material misstatement of the financial statements, 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 Statements 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 Statements.

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 Statements referred to above present fairly, in all material respects, the revenues and direct operating expenses of certain oil and gas properties owned by Vendera Resources III, L.P. and its affiliates as of December 31, 2017 and 2016, in accordance with accounting principles generally accepted in the United States of America.

Emphasis of matter

As described in Note 1 to the Statements, the accompanying statements of revenue and direct operating expenses were prepared for the purpose of complying with the rules and regulations of the U.S. Securities and Exchange Commission (for inclusion in the registration statement on Form S-1 of Remora Royalties, Inc.) and are not intended to be a complete presentation of the results of operations of the oil and gas properties owned by Vendera Resources III, L.P. and its affiliates. Our opinion is not modified with respect to this matter.

/s/ Grant Thornton LLP

Dallas, Texas

May 14, 2018

 

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Index to Financial Statements

STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES

OF CERTAIN OIL AND GAS PROPERTIES OWNED BY VENDERA

RESOURCES III, L.P. AND ITS AFFILIATES

 

     For the Three Months Ended
March 31,
    For the Years Ended
December 31,
 
             2018                     2017             2017     2016  
     (unaudited)              

Oil, natural gas and NGL revenues

   $ 216,771     $ 274,133     $ 989,108     $ 839,381  

Direct operating expenses

     (127,786     (78,481     (320,292     (302,484
  

 

 

   

 

 

   

 

 

   

 

 

 

Revenues in excess of direct operating expenses

     88,985       195,652     $ 668,816     $ 536,897  
  

 

 

   

 

 

   

 

 

   

 

 

 

 

 

 

The accompanying notes are an integral part of these statements.

 

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Index to Financial Statements

NOTES TO STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES OF CERTAIN OIL AND GAS PROPERTIES OWNED BY VENDERA

RESOURCES III, L.P. AND ITS AFFILIATES

 

1.   BASIS OF PRESENTATION

The accompanying statements include revenues from the sale of crude oil, natural gas and natural gas liquids (“NGLs”) production and direct operating expenses associated with certain proved reserves and properties in the United States of America (collectively, the “Properties”) owned by Vendera Resources III, L.P. and its affiliates (“Vendera Resources III”) for the periods presented. Revenues and direct operating expenses are presented on the accrual basis of accounting and were derived from Vendera Resources III’s historical accounting records. During the periods presented, the Properties were not accounted for or operated as a separate division or entity of Vendera Resources III; therefore, certain expenses such as depreciation, depletion and amortization expense, general and administrative expense, interest expense and income taxes were not allocated to the Properties. Accordingly, complete separate financial statements reflecting the financial position, results of operations and cash flows of the Properties prepared in accordance with accounting principles generally accepted in the United States of America (“U.S. GAAP”) are not presented because the information necessary to prepare such statements is neither readily available on a combined or individual property basis, nor practicable to obtain in these circumstances. As such, the accompanying statements are not intended to be a complete presentation of the revenues and expenses of the Properties and are not indicative of the results of the operation of the Properties going forward due to the omission of various expenses including those described above.

 

2.   SIGNIFICANT ACCOUNTING POLICIES

Revenue Recognition

Vendera Resources III recognizes revenue 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.

Direct Operating Expenses

Direct operating expenses are recognized when incurred and include: (i) gathering, transportation, and other direct operating expenses, (ii) production taxes and (iii) ad valorem taxes.

Management Estimates

The preparation of financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of revenues and direct operating expenses during the reporting period. These estimates and assumptions are based on management’s best estimates and judgment. Actual results may differ from the estimates and assumptions used in the preparation of the statements of revenues and direct operating expenses. Management evaluates its estimates and assumptions on an ongoing basis using historical experience and other factors, including the current economic environment, which management believes to be reasonable under the circumstances. Management evaluates subsequent events through the date the financial statements are issued.

 

3.   COMMITMENTS AND CONTINGENCIES

Management is not aware of any legal, environmental or other commitments or contingencies that would have a material effect on Vendera Resources III’s financial condition, results of operations or liquidity.

 

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Table of Contents
Index to Financial Statements

NOTES TO STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES OF CERTAIN OIL AND GAS PROPERTIES OWNED BY VENDERA

RESOURCES III, L.P. AND ITS AFFILIATES — (Continued)

 

4.   SUBSEQUENT EVENTS

Management has evaluated subsequent events through May 14, 2018, the date the financial statements were issued.

 

5.   SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION (UNAUDITED)

The reserves at December 31, 2017 presented below were prepared Cawley, Gillespie & Associates, Inc. Estimates of proved reserves are inherently imprecise and are continually subject to revision based on production history, results of additional exploration and development, price changes and other factors. The reserves are located in Utah.

Guidelines prescribed in FASB ASC Topic 932 Extractive Industries – Oil and Gas (“ASC Topic 932”) have been followed for computing a standardized measure of future net cash flows and changes therein related to estimated proved reserves. Future cash inflows and future production costs are determined by applying prices and costs, including transportation, quality, and basis differentials, to the period-end estimated quantities of oil, natural gas and NGLs to be produced in the future. The resulting future net cash flows are reduced to present value amounts by applying a ten percent annual discount factor. Future operating costs are determined based on estimates of expenditures to be incurred in producing the proved oil and natural gas reserves in place at the end of the period using period-end costs and assuming continuation of existing economic conditions, plus overhead to be incurred.

The assumptions used to compute the standardized measure are those prescribed by the FASB and the SEC. These assumptions do not necessarily reflect management’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. Reserve estimates are inherently imprecise, and estimates of new discoveries and undeveloped locations are more imprecise than estimates of established proved producing oil and natural gas properties. Accordingly, these estimates are expected to change as future information becomes available.

The following table sets forth information for the years ended December 31, 2017 and 2016, with respect to changes in the proved reserves:

 

     (MMcf)
Natural Gas
 

January 1, 2016

     5,656  

Revisions

     (291

Production

     (495
  

 

 

 

December 31, 2016

     4,870  

Revisions

     1,005  

Production

     (429
  

 

 

 

December 31, 2017

     5,446  
  

 

 

 

 

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Index to Financial Statements

NOTES TO STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES OF CERTAIN OIL AND GAS PROPERTIES OWNED BY VENDERA

RESOURCES III, L.P. AND ITS AFFILIATES — (Continued)

 

As of December 31, 2017 and 2016, all of the reserves for Vendera Resources III were proved developed.

As of December 31, 2017 and 2016, the reserves were comprised of 100% natural gas on an energy equivalent basis. The following values for the 2017 and 2016 proved reserves were derived based on $2.304 and $1.850 per Mcf of natural gas, respectively. These prices were based on the 12-month arithmetic average first-of-month price for January 2017 through December 2017, and January 2016 through December 2016, respectively. Natural gas pricing was based on the Henry Hub price. Prices have been adjusted for transportation, quality and basis differentials.

For the year ended December 31, 2017, the Company had upward revisions of previous estimates of 167.4 MBOE. These revisions are primarily due to higher trailing first of the month of twelve month average price resulting in longer economic lives of wells resulting in additional reserves.

For the year ended December 31, 2016, the Company had downward revisions of previous estimates of 48.5 MBOE. These revisions are due to lower trailing first of the month of twelve month average price resulting in shorter economic lives of wells resulting in less reserves.

The following summary sets forth the future net cash flows related to proved oil and natural gas reserves based on the standardized measure prescribed in ASC Topic 932 (in thousands):

 

     As of December 31,  
     2017      2016  

Future crude oil, natural gas and NGLs sales

   $ 12,545      $ 9,011  

Future production costs

     (863      (620

Future income tax expense

             
  

 

 

    

 

 

 

Future net cash flows

     11,682        8,391  

10% annual discount

     (6,293      (4,265
  

 

 

    

 

 

 

Standardized measure of discounted future net cash flows

   $ 5,389      $ 4,126  
  

 

 

    

 

 

 

The principal sources of change in the standardized measure of discounted future net cash flows are (in thousands):

 

     For the Years Ended
December 31,
 
         2017              2016      

Balance at beginning of period

   $ 4,126      $ 4,915  

Sales of crude oil, natural gas and NGLs

     (669      (537

Net change in prices and production costs

     851        (556

Revisions of previous quantity estimates

     994        (253

Accretion of discount

     413        492  

Other

     (326      65  
  

 

 

    

 

 

 

Balance at end of period

   $ 5,389      $ 4,126  
  

 

 

    

 

 

 

 

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Index to Financial Statements
REPORT OF INDEPENDENT CERTIFIED PUBLIC ACCOUNTANTS

To the Partners of

Remora Petroleum, L.P.

We have audited the accompanying Statements of Revenues and Direct Operating Expenses of certain oil and gas properties (“the Statements”) owned by Avad Energy Partners, LLC for the years ended December 31, 2017 and 2016 and the related notes to the Statements.

Management’s responsibility for the financial statements

Management is responsible for the preparation and fair presentation of these Statements 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 financial statements that are free from material misstatement, whether due to fraud or error.

Auditor’s responsibility

Our responsibility is to express an opinion on these Statements 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 Statements are free from material misstatement.

An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the Statements. The procedures selected depend on the auditor’s judgment, including the assessment of the risks of material misstatement of the financial statements, 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 Statements 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 Statements.

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 Statements referred to above present fairly, in all material respects, the revenues and direct operating expenses of certain oil and gas properties owned by Avad Energy Partners, LLC as of December 31, 2017 and 2016, in accordance with accounting principles generally accepted in the United States of America.

Emphasis of matter

As described in Note 1 to the Statements, the accompanying statements of revenue and direct operating expenses were prepared for the purpose of complying with the rules and regulations of the U.S. Securities and Exchange Commission (for inclusion in the registration statement on Form S-1 of Remora Royalties, Inc.) and are not intended to be a complete presentation of the results of operations of the oil and gas properties owned by Avad Energy Partners, LLC. Our opinion is not modified with respect to this matter.

/s/ Grant Thornton LLP

Dallas, Texas

May 14, 2018

 

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Index to Financial Statements

STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES

OF CERTAIN OIL AND GAS PROPERTIES OWNED BY AVAD ENERGY PARTNERS, LLC

 

     For the Three Months Ended
March 31,
    For the Years Ended
December 31,
 
             2018                     2017             2017     2016  
     (unaudited)              

Oil, natural gas and NGL revenues

   $ 1,097,206     $ 1,105,087     $ 4,287,430     $ 3,543,048  

Direct operating expenses

     (332,483     (232,751     (891,640     (849,484
  

 

 

   

 

 

   

 

 

   

 

 

 

Revenues in excess of direct operating expenses

     764,723       872,336     $ 3,395,790     $ 2,693,564  
  

 

 

   

 

 

   

 

 

   

 

 

 

 

 

 

The accompanying notes are an integral part of these statements.

 

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Table of Contents
Index to Financial Statements

NOTES TO STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES OF CERTAIN OIL AND GAS PROPERTIES OWNED BY AVAD ENERGY PARTNERS, LLC

 

1.   BASIS OF PRESENTATION

The accompanying statements include revenues from the sale of crude oil, natural gas and natural gas liquids (“NGLs”) production and direct operating expenses associated with certain proved reserves and properties in the United States of America (collectively, the “Properties”) owned by AVAD Energy Partners, LLC (“AVAD”) for the periods presented. Revenues and direct operating expenses are presented on the accrual basis of accounting and were derived from AVAD’s historical accounting records. During the periods presented, the Properties were not accounted for or operated as a separate division or entity of AVAD; therefore, certain expenses such as depreciation, depletion and amortization expense, general and administrative expense, interest expense and income taxes were not allocated to the Properties. Accordingly, complete separate financial statements reflecting the financial position, results of operations and cash flows of the Properties prepared in accordance with accounting principles generally accepted in the United States of America (“U.S. GAAP”) are not presented because the information necessary to prepare such statements is neither readily available on a combined or individual property basis, nor practicable to obtain in these circumstances. As such, the accompanying statements are not intended to be a complete presentation of the revenues and expenses of the Properties and are not indicative of the results of the operation of the Properties going forward due to the omission of various expenses including those described above.

 

2.   SIGNIFICANT ACCOUNTING POLICIES

Revenue Recognition

AVAD recognizes revenue 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.

Direct Operating Expenses

Direct operating expenses are recognized when incurred and include: (i) gathering, transportation, and other direct operating expenses, (ii) production taxes and (iii) ad valorem taxes.

Management Estimates

The preparation of financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of revenues and direct operating expenses during the reporting period. These estimates and assumptions are based on management’s best estimates and judgment. Actual results may differ from the estimates and assumptions used in the preparation of the statements of revenues and direct operating expenses. Management evaluates its estimates and assumptions on an ongoing basis using historical experience and other factors, including the current economic environment, which management believes to be reasonable under the circumstances. Management evaluates subsequent events through the date the financial statements are issued.

 

3.   COMMITMENTS AND CONTINGENCIES

Management is not aware of any legal, environmental or other commitments or contingencies that would have a material effect on AVAD’s financial condition, results of operations or liquidity.

 

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Index to Financial Statements

NOTES TO STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES OF CERTAIN OIL AND GAS PROPERTIES OWNED BY AVAD ENERGY PARTNERS, LLC — (Continued)

 

4.   SUBSEQUENT EVENTS

Management has evaluated subsequent events through May 14, 2018, the date the financial statements were issued.

 

5.   SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION (UNAUDITED)

The reserves at December 31, 2017 presented below were prepared Cawley, Gillespie & Associates, Inc. Estimates of proved reserves are inherently imprecise and are continually subject to revision based on production history, results of additional exploration and development, price changes and other factors. The reserves are located in Utah and Texas.

Guidelines prescribed in FASB ASC Topic 932 Extractive Industries – Oil and Gas (“ASC Topic 932”) have been followed for computing a standardized measure of future net cash flows and changes therein related to estimated proved reserves. Future cash inflows and future production costs are determined by applying prices and costs, including transportation, quality, and basis differentials, to the period-end estimated quantities of oil, natural gas and NGLs to be produced in the future. The resulting future net cash flows are reduced to present value amounts by applying a ten percent annual discount factor. Future operating costs are determined based on estimates of expenditures to be incurred in producing the proved oil and natural gas reserves in place at the end of the period using period-end costs and assuming continuation of existing economic conditions, plus overhead to be incurred.

The assumptions used to compute the standardized measure are those prescribed by the FASB and the SEC. These assumptions do not necessarily reflect management’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. Reserve estimates are inherently imprecise, and estimates of new discoveries and undeveloped locations are more imprecise than estimates of established proved producing oil and natural gas properties. Accordingly, these estimates are expected to change as future information becomes available.

The following table sets forth information for the years ended December 31, 2017 and 2016, with respect to changes in the proved reserves:

 

     (Mbbl)
Crude Oil
     (MMcf)
Natural Gas
 

January 1, 2016

     528        14,241  

Revisions

     (23      (710

Production

     (32      (1,273
  

 

 

    

 

 

 

December 31, 2016

     473        12,258  

Revisions

     28        2,398  

Production

     (34      (1,102
  

 

 

    

 

 

 

December 31, 2017

     467        13,554  
  

 

 

    

 

 

 

As of December 31, 2017 and 2016, all of the reserves for AVAD were proved developed. As of December 31, 2017, the reserves were comprised of 17.1% crude oil and 82.9% natural gas on an energy

 

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Index to Financial Statements

NOTES TO STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES OF CERTAIN OIL AND GAS PROPERTIES OWNED BY AVAD ENERGY PARTNERS, LLC — (Continued)

 

equivalent basis. As of December 31, 2016, the reserves were comprised of 18.8% crude oil and 81.2% natural gas on an energy equivalent basis. The following values for the 2017 proved reserves were derived based on prices of $48.693 per Bbl of crude oil and $2.361 per Mcf of natural gas. The following values for the 2016 proved reserves were derived based on prices of $40.106 per Bbl of crude oil and $1.914 per Mcf of natural gas. These prices were based on the 12-month arithmetic average first-of-month price for January 2017 through December 2017, and January 2016 through December 2016, respectively. The crude oil pricing was based on the West Texas Intermediate (“WTI”) price and the natural gas pricing was based on the Henry Hub price. All prices have been adjusted for transportation, quality and basis differentials.

For the year ended December 31, 2017, the Company had upward revisions of previous estimates of 427.3 MBOE. These revisions are due to higher trailing first of the month of twelve month average price resulting in longer economic lives of wells resulting in additional reserves.

For the year ended December 31, 2016, the Company had downward revisions of previous estimates of 143.9 MBOE. These revisions are due to lower trailing first of the month of twelve month average price resulting in shorter economic lives of wells resulting in less reserves.

The following summary sets forth the future net cash flows related to proved oil and natural gas reserves based on the standardized measure prescribed in ASC Topic 932 (in thousands):

 

     As of
December 31,
 
     2017      2016  

Future crude oil, natural gas and NGLs sales

   $ 54,744      $ 42,446  

Future production costs

     (4,024      (3,141

Future income tax expense

     (134      (112
  

 

 

    

 

 

 

Future net cash flows

     50,586        39,193  

10% annual discount

     (28,362      (21,240
  

 

 

    

 

 

 

Standardized measure of discounted future net cash flows

   $ 22,224      $ 17,953  
  

 

 

    

 

 

 

The principal sources of change in the standardized measure of discounted future net cash flows are (in thousands):

 

     For the Years Ended
December 31,
 
     2017      2016  

Balance at beginning of period

   $ 17,953      $ 22,309  

Sales of crude oil, natural gas and NGLs

     (3,396      (2,694

Net change in prices and production costs

     3,143        (3,214

Revisions of previous quantity estimates

     3,492        (1,087

Net change in income taxes

     (8      14  

Accretion of discount

     1,800        2,237  

Other

     (760      388  
  

 

 

    

 

 

 

Balance at end of period

   $ 22,224      $ 17,953  
  

 

 

    

 

 

 

 

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Index to Financial Statements
REPORT OF INDEPENDENT CERTIFIED PUBLIC ACCOUNTANTS

To the Partners of

Remora Petroleum, L.P.

We have audited the accompanying Statements of Revenues and Direct Operating Expenses of certain oil and gas properties (“the Statements”) located in South Texas (“the 2017 South Texas Assets”) acquired by Remora Petroleum, L.P. for the period from January 1, 2017 through December 19, 2017 and the year ended December 31, 2016 and the related notes to the Statements.

Management’s responsibility for the financial statements

Management is responsible for the preparation and fair presentation of these Statements 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 financial statements that are free from material misstatement, whether due to fraud or error.

Auditor’s responsibility

Our responsibility is to express an opinion on these Statements 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 Statements are free from material misstatement.

An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the Statements. The procedures selected depend on the auditor’s judgment, including the assessment of the risks of material misstatement of the Statements, 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 Statements 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 Statements.

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 Statements referred to above present fairly, in all material respects, the revenues and direct operating expenses of certain oil and gas properties of the 2017 South Texas Assets described in Note 1 for the period from January 1, 2017 through December 19, 2017 and the year ended December 31, 2016 in accordance with accounting principles generally accepted in the United States of America.

Emphasis of matter

As described in Note 1 to the Statements, the accompanying statements of revenue and direct operating expenses were prepared for the purpose of complying with the rules and regulations of the U.S. Securities and Exchange Commission and are not intended to be a complete presentation of the results of operations of the 2017 South Texas Assets. Our opinion is not modified with respect to this matter.

/s/ Grant Thornton LLP

Dallas, Texas

May 14, 2018

 

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Index to Financial Statements

2017 SOUTH TEXAS ASSETS

STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES OF CERTAIN OIL AND GAS PROPERTIES

 

     January 1, 2017 to
December 19,
    For the Year Ended
December 31,
 
     2017     2016  

Oil, natural gas and NGL revenues

   $ 12,935,453     $ 12,062,562  

Direct operating expenses

     (2,247,851     (2,203,262
  

 

 

   

 

 

 

Revenues in excess of direct operating expenses

   $ 10,687,602     $ 9,859,300  
  

 

 

   

 

 

 

 

 

 

 

The accompanying notes are an integral part of these statements.

 

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Index to Financial Statements

2017 SOUTH TEXAS ASSETS

NOTES TO STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES OF CERTAIN OIL AND GAS PROPERTIES

 

1.   BASIS OF PRESENTATION

The accompanying statements of revenues and direct expenses are presented on an accrual basis of accounting. Such amounts may not be representative of future operations. The statements do not include depreciation, depletion and amortization, general and administrative expenses, income taxes or interest expense. Historical financial statements reflecting financial position, results of operations and cash flows required by accounting principles generally accepted in the United States (“US GAAP”) are not presented as such information is not readily available on an individual property basis nor is it practicable to obtain in these circumstances. Accordingly the historical statements of revenues and direct operating expenses of the 2017 south Texas asset acquisition are presented in lieu of the financial statements required under rule 3-05 of the securities and exchange commission regulation S-X.

 

2.   SIGNIFICANT ACCOUNTING POLICIES

Revenue Recognition

The Company recognizes revenue 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.

Direct Operating Expenses

Direct operating expenses are recognized when incurred and include: (i) gathering, transportation, and other direct operating expenses, (ii) production taxes and (iii) ad valorem taxes.

Management Estimates

The preparation of financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of revenues and direct operating expenses during the reporting period. These estimates and assumptions are based on management’s best estimates and judgment. Actual results may differ from the estimates and assumptions used in the preparation of the statements of revenues and direct operating expenses. Management evaluates its estimates and assumptions on an ongoing basis using historical experience and other factors, including the current economic environment, which management believes to be reasonable under the circumstances. Management evaluates subsequent events through the date the financial statements are issued.

 

3.   COMMITMENTS AND CONTINGENCIES

Management is not aware of any legal, environmental or other commitments or contingencies that would have a material effect on the Company’s financial condition, results of operations or liquidity.

 

4.   SUBSEQUENT EVENTS

Management has evaluated subsequent events through May 14, 2018, the date the financial statements were issued.

 

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Index to Financial Statements

2017 SOUTH TEXAS ASSETS

NOTES TO STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES OF CERTAIN OIL AND GAS PROPERTIES — (Continued)

 

5.   SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION (UNAUDITED)

The reserves at December 19, 2017 below were prepared based on estimates of proved reserves prepared by Cawley, Gillespie & Associates, Inc. Estimates of proved reserves are inherently imprecise and are continually subject to revision based on production history, results of additional exploration and development, price changes and other factors. The reserves are located in Texas.

Guidelines prescribed in FASB ASC Topic 932 Extractive Industries – Oil and Gas (“ASC Topic 932”) have been followed for computing a standardized measure of future net cash flows and changes therein related to estimated proved reserves. Future cash inflows and future production costs are determined by applying prices and costs, including transportation, quality, and basis differentials, to the period-end estimated quantities of oil, natural gas and NGLs to be produced in the future. The resulting future net cash flows are reduced to present value amounts by applying a ten percent annual discount factor. Future operating costs are determined based on estimates of expenditures to be incurred in producing the proved oil and natural gas reserves in place at the end of the period using period-end costs and assuming continuation of existing economic conditions, plus overhead to be incurred.

The assumptions used to compute the standardized measure are those prescribed by the FASB and the SEC. These assumptions do not necessarily reflect management’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. Reserve estimates are inherently imprecise, and estimates of new discoveries and undeveloped locations are more imprecise than estimates of established proved producing oil and natural gas properties. Accordingly, these estimates are expected to change as future information becomes available.

 

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Index to Financial Statements

2017 SOUTH TEXAS ASSETS

NOTES TO STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES OF CERTAIN OIL AND GAS PROPERTIES — (Continued)

 

The following table sets forth information for the period from January 1, 2017 to December 19, 2017 and for the year ended December 31, 2016, with respect to changes in the proved reserves:

 

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

January 1, 2016

     729        26,849        641  

Revisions

     (25      (1,192      89  

Production

     (91      (2,964      (126
  

 

 

    

 

 

    

 

 

 

December 31, 2016

     613        22,693        604  

Revisions

     42        1,879        155  

Production

     (67      (2,677      (97
  

 

 

    

 

 

    

 

 

 

December 19, 2017

     588        21,895        662  
  

 

 

    

 

 

    

 

 

 

Proved developed reserves, included above:

        

January 1, 2016

     723        26,779        641  

December 31, 2016

     607        26,623      604  

December 19, 2017

     582        21,820      662  

Proved undeveloped reserves, included above :

        

January 1, 2016

     6        70         

December 31, 2016

     6        70       

December 19, 2017

     6        75       

As of December 19, 2017, the reserves comprised 12.0% crude oil, 74.5% natural gas, and 13.5% NGLs on an energy equivalent basis. As of December 31, 2016, the reserves comprised 12.3% crude oil, 75.7% natural gas, and 12.0% NGLs on an energy equivalent basis. The following values for the 2017 proved reserves were derived based on prices of $47.915 per Bbl of crude oil, and $2.884 per Mcf of natural gas, and $19.741 per Bbl of NGLs. The following values for the 2016 proved reserves were derived based on prices of $39.327 per Bbl of crude oil, and $2.412 per Mcf of natural gas, and $16.456 per Bbl of NGLs. These prices were based on the 12-month arithmetic average first-of-month price for January 2017 through December 2017, and January 2016 through December 2016, respectively. The crude oil pricing was based on the West Texas Intermediate (“WTI”) price; the natural gas pricing was based on the Henry Hub price; the NGL pricing was 41% of WTI in 2017 and 42% of WTI in 2016. All prices have been adjusted for transportation, quality and basis differentials.

For the year ended December 31, 2017, the Company had upward revisions of previous estimates of 510.2 MBOE. These revisions are primarily due to higher trailing first of the month of twelve month average price resulting in longer economic lives of wells resulting in additional reserves.

For the year ended December 31, 2016, the Company had downward revisions of previous estimates of 134.7 MBOE. These revisions are due to lower trailing first of the month of twelve month average price resulting in shorter economic lives of wells resulting in less reserves.

 

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2017 SOUTH TEXAS ASSETS

NOTES TO STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES OF CERTAIN OIL AND GAS PROPERTIES — (Continued)

 

The following summary sets forth the future net cash flows related to proved oil and natural gas reserves based on the standardized measure prescribed in ASC Topic 932 (in thousands):

 

     As of
December 19, 2017
     As of
December 31, 2016
 

Future crude oil, natural gas and NGLs sales

   $ 104,397      $ 88,777

Future production costs

     (10,065      (8,555

Future income tax expense

     (548      (466
  

 

 

    

 

 

 

Future net cash flows

     93,784        79,756  

10% annual discount

     (37,306      (31,190
  

 

 

    

 

 

 

Standardized measure of discounted future net cash flows

   $ 56,478      $ 48,566  
  

 

 

    

 

 

 

The principal sources of change in the standardized measure of discounted future net cash flows are (in thousands):

 

     For the period from
January 1, 2017 to
December 19, 2017
     For the year ended
December 31, 2016
 

Balance at beginning of period

   $ 48,566      $ 60,238

Sales of crude oil, natural gas and NGLs

     (10,688      (9,859

Net change in prices and production costs

     9,463        (7,341

Revisions of previous quantity estimates

     5,921        (1,448

Net change in income taxes

     (46      119  

Accretion of discount

     4,885        6,064

Other

     (1,623      794  
  

 

 

    

 

 

 

Balance at end of period

   $ 56,478      $ 48,566
  

 

 

    

 

 

 

 

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REPORT OF INDEPENDENT CERTIFIED PUBLIC ACCOUNTANTS

To the Partners of

Remora Petroleum, L.P.

We have audited the accompanying Statement of Revenues and Direct Operating Expenses of certain oil and gas properties (“the Statement”) located in the Midcontinent (the “2016 Midcontinent Assets”), acquired by Remora Petroleum, L.P. for the period from January 1, 2016 through December 9, 2016 and the related notes to the Statement.

Management’s responsibility for the financial statements

Management is responsible for the preparation and fair presentation of this Statement 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 financial statements that are free from material misstatement, whether due to fraud or error.

Auditor’s responsibility

Our responsibility is to express an opinion on this Statement 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 Statement is free from material misstatement.

An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the Statement. The procedures selected depend on the auditor’s judgment, including the assessment of the risks of material misstatement of the financial statement, 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 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.

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 Statement referred to above presents fairly, in all material respects, the revenues and direct operating expenses of certain oil and gas properties of the 2016 Midcontinent Assets as described in Note 1 for the period from January 1, 2016 through December 9, 2016 in accordance with accounting principles generally accepted in the United States of America.

Emphasis of matter

As described in Note 1 to the Statement, the accompanying statement of revenue and direct operating expenses was prepared for the purpose of complying with the rules and regulations of the U.S. Securities and Exchange Commission and are not intended to be a complete presentation of the results of operations of the 2016 Midcontinent Assets. Our opinion is not modified with respect to this matter.

/s/ Grant Thornton LLP

Dallas, Texas

May 14, 2018

 

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2016 MIDCONTINENT ASSETS

STATEMENT OF REVENUES AND DIRECT OPERATING EXPENSES OF CERTAIN OIL AND GAS PROPERTIES

 

     January 1, 2016 to
December 9, 2016
 

Oil, natural gas and NGL revenues

   $ 14,403,122  

Direct operating expenses

     (4,155,578
  

 

 

 

Revenues in excess of direct operating expenses

   $ 10,247,544  
  

 

 

 

 

 

 

The accompanying notes are an integral part of this statement.

 

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2016 MIDCONTINENT ASSETS

NOTES TO STATEMENT OF REVENUES AND DIRECT OPERATING EXPENSES OF CERTAIN OIL AND GAS PROPERTIES

 

1.   BASIS OF PRESENTATION

The accompanying statement of revenues and direct expenses is presented on an accrual basis of accounting. Such amounts may not be representative of future operations. The statement does not include depreciation, depletion and amortization, general and administrative expenses, income taxes or interest expense. Historical financial statements reflecting financial position, results of operations and cash flows required by accounting principles generally accepted in the United States (“US GAAP”) are not presented as such information is not readily available on an individual property basis nor is it practicable to obtain in these circumstances. Accordingly the historical statement of revenues and direct operating expenses of the 2016 midcontinent asset acquisition is presented in lieu of the financial statements required under rule 3-05 of the securities and exchange commission regulation S-X.

 

2.   SIGNIFICANT ACCOUNTING POLICIES

Revenue Recognition

The Company recognizes revenue 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.

Direct Operating Expenses

Direct operating expenses are recognized when incurred and include: (i) gathering, transportation, and other direct operating expenses, (ii) production taxes and (iii) ad valorem taxes.

Management Estimates

The preparation of financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of revenues and direct operating expenses during the reporting period. These estimates and assumptions are based on management’s best estimates and judgment. Actual results may differ from the estimates and assumptions used in the preparation of the statements of revenues and direct operating expenses. Management evaluates its estimates and assumptions on an ongoing basis using historical experience and other factors, including the current economic environment, which management believes to be reasonable under the circumstances. Management evaluates subsequent events through the date the financial statements are issued.

 

3.   COMMITMENTS AND CONTINGENCIES

Management is not aware of any legal, environmental or other commitments or contingencies that would have a material effect on the Company’s financial condition, results of operations or liquidity.

 

4.   SUBSEQUENT EVENTS

Management has evaluated subsequent events through May 14, 2018, the date the financial statements were issued.

 

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2016 MIDCONTINENT ASSETS

NOTES TO STATEMENT OF REVENUES AND DIRECT OPERATING EXPENSES OF CERTAIN OIL AND GAS PROPERTIES — (Continued)

 

5.   SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION (UNAUDITED)

The reserves at December 9, 2016 presented below are inherently imprecise and are continually subject to revision based on production history, results of additional exploration and development, price changes and other factors. The reserves are located in Colorado, Oklahoma, Louisiana and Texas.

Guidelines prescribed in FASB ASC Topic 932 Extractive Industries — Oil and Gas (“ASC Topic 932”) have been followed for computing a standardized measure of future net cash flows and changes therein related to estimated proved reserves. Future cash inflows and future production costs are determined by applying prices and costs, including transportation, quality, and basis differentials, to the period-end estimated quantities of oil, natural gas and NGLs to be produced in the future. The resulting future net cash flows are reduced to present value amounts by applying a ten percent annual discount factor. Future operating costs are determined based on estimates of expenditures to be incurred in producing the proved oil and natural gas reserves in place at the end of the period using period-end costs and assuming continuation of existing economic conditions, plus overhead to be incurred.

The assumptions used to compute the standardized measure are those prescribed by the FASB and the SEC. These assumptions do not necessarily reflect management’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. Reserve estimates are inherently imprecise, and estimates of new discoveries and undeveloped locations are more imprecise than estimates of established proved producing oil and natural gas properties. Accordingly, these estimates are expected to change as future information becomes available.

The following table sets forth information for period from January 1, 2016 to December 9, 2016, with respect to changes in the proved reserves:

 

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

January 1, 2016

     885        66,088        2,774  

Revisions

     (52      (1,403      3  

Production

     (124      (5,076      (103
  

 

 

    

 

 

    

 

 

 

December 9, 2016

     709        59,609        2,674  
  

 

 

    

 

 

    

 

 

 

Proved developed reserves, included above:

        

January 1, 2016

     656        50,739        1,976  

December 9, 2016

     484        44,302        1,881  

 

Proved undeveloped reserves, included above:

        

January 1, 2016

     229        15,349        798  

December 9, 2016

     225        15,307        793  

As of December 9, 2016, the reserves were comprised of 5.3% crude oil, 74.6% natural gas, and 20.1% NGLs on an energy equivalent basis. The following values for the proved reserves were derived based on prices of $40.462 per Bbl of crude oil, $2.474 per Mcf of natural gas, and $15.262 per Bbl of NGL. These prices were based on the 12-month arithmetic average first-of-month price for December 2015 through November 2016. The crude oil pricing was based on the West Texas Intermediate (“WTI”) price; the natural

 

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2016 MIDCONTINENT ASSETS

NOTES TO STATEMENT OF REVENUES AND DIRECT OPERATING EXPENSES OF CERTAIN OIL AND GAS PROPERTIES — (Continued)

 

gas pricing was based on the Henry Hub price; the NGL pricing was 38% of WTI. All prices have been adjusted for transportation, quality and basis differentials.

For the period from January 1, 2016 to December 9, 2016, the Company had downward revisions of previous estimates of 282.8 MBOE. These revisions are due to lower trailing first of the month of 12 month average price resulting in longer economic lives of wells resulting in additional reserves.

The following summary sets forth the future net cash flows related to proved oil and natural gas reserves based on the standardized measure prescribed in ASC Topic 932 (in thousands):

 

     As of
December 9, 2016
 

Future crude oil, natural gas and NGLs sales

   $ 216,936  

Future production costs

     (14,112

Future income tax expense

     (3
  

 

 

 

Future net cash flows

     202,821  

10% annual discount

     (107,705
  

 

 

 

Standardized measure of discounted future net cash flows

   $ 95,116  
  

 

 

 

The principal sources of change in the standardized measure of discounted future net cash flows are (in thousands):

 

     For the period from
January 1, 2016 to
December 9, 2016
 

Balance at beginning of period

   $ 113,345  

Sales of crude oil, natural gas and NGLs

     (10,248

Net change in prices and production costs

     (16,984

Revisions of previous quantity estimates

     (2,185

Net change in income taxes

     5

Accretion of discount

     11,335  

Other

     (152
  

 

 

 

Balance at end of period

   $ 95,116  
  

 

 

 

 

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            Shares

 

 

LOGO

Remora Royalties, Inc.

Class A Common Stock

 

 

PROSPECTUS

                    , 2018

 

Joint Book-Running Managers

 

RBC Capital Markets  

Wells Fargo Securities

  UBS Investment Bank

Co-Managers

 

Through and including                     , 2018 (25 days after the date of this prospectus), all dealers that buy, sell or trade our Class A common stock, whether or not participating in this offering, may be required to deliver a prospectus. This is in addition to the dealers’ obligation to deliver a prospectus when acting as underwriters and with respect to their unsold allotments or subscriptions.

 

 

 


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PART II

INFORMATION NOT REQUIRED IN PROSPECTUS

ITEM 13. OTHER EXPENSES OF ISSUANCE AND DISTRIBUTION.

Set forth below are the expenses (other than the underwriting discount and structuring fee) expected to be incurred by the Contributing Parties and us in connection with the issuance and distribution of the securities registered hereby. With the exception of the SEC registration fee, the FINRA filing fee and the NASDAQ listing fee, the amounts set forth below are estimates.

 

SEC registration fee

   $               

FINRA filing fee

  

Printing and engraving expenses

  

Fees and expenses of legal counsel

  

Accounting fees and expenses

  

Transfer agent and registrar fees

  

NASDAQ listing fee

  

Miscellaneous

  
  

 

 

 

Total

   $  

ITEM 14. INDEMNIFICATION OF OFFICERS AND MEMBERS OF OUR BOARD OF DIRECTORS.

Our bylaws will provide that a director will not be liable to the corporation or its stockholders for monetary damages to the fullest extent permitted by the DGCL. 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, stockholder 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 may 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.

We have obtained directors’ and officers’ insurance to cover our directors, officers and some of our employees for certain liabilities.

 

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We will enter into written indemnification agreements with our directors and executive officers. Under these proposed agreements, if an officer or director makes a claim of indemnification to us, either a majority of the independent directors or independent legal counsel selected by the independent 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.

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.

On May 8, 2018, Remora Royalties, Inc. issued 100 shares of common stock, par value $0.01 per share, to Remora Petroleum, L.P. for $1.00. The issuance of such shares of common stock was not registered under the Securities Act, because the shares were offered and sold in a transaction exempt from registration under Section 4(2) of the Securities Act.

ITEM 16. EXHIBITS.

See the Exhibit Index on the page immediately preceding the exhibits for a list of exhibits filed as part of this Registration Statement on Form S-1, which Exhibit Index is incorporated herein by reference.

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 Securities and Exchange Commission 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 (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 430A 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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EXHIBIT INDEX

 

Exhibit

Number

        

Description

  1.1 **       Form of Underwriting Agreement
  3.1      Certificate of Incorporation of Remora Royalties, Inc.
  3.2      Bylaws of Remora Royalties, Inc.
  3.3 **       Form of Amended and Restated Certificate of Incorporation of Remora Royalties, Inc.
  3.4 **       Form of Amended and Restated Bylaws of Remora Royalties, Inc.
  4.1 **       Form of Registration Rights Agreement
  5.1      Form of Opinion of Sidley Austin LLP as to the legality of the securities being registered
  10.1 **       Form of Amended and Restated Limited Liability Company Agreement of Remora Holdings, LLC
  10.2 **       Form of Contribution Agreement
  10.3 **       Form of Credit Agreement
  10.4 **       Form of Remora Royalties, Inc. Stock and Incentive Plan
  10.5 **       Form of Management Services Agreement
  10.6 **       Form of Indemnification Agreement
  16.1  

   Letter of Hein & Associates LLP
  21.1      List of subsidiaries of Remora Royalties, Inc.
  23.1      Consent of Grant Thornton LLP with respect to audited financial information of Remora Petroleum, L.P.
  23.2      Consent of Grant Thornton LLP with respect to audited financial information of Vendera Resources II, LLC and its affiliates
  23.3      Consent of Grant Thornton LLP with respect to audited financial information of Vendera Resources III, L.P. and its affiliates
  23.4      Consent of Grant Thornton LLP with respect to audited financial information of AVAD Energy Partners, LLC
  23.5      Consent of Grant Thornton LLP with respect to audited financial information for the 2016 Midcontinent Acquisition
  23.6      Consent of Grant Thornton LLP with respect to audited financial information for the 2017 South Texas Acquisition
  23.7      Consent of Cawley, Gillespie & Associates, Inc.
  23.8      Consent of Sidley Austin LLP (included in Exhibit 5.1)
  23.9      Consent of Director Nominee
  23.10      Consent of Director Nominee
  23.11      Consent of Director Nominee
  23.12      Consent of Director Nominee
  23.13      Consent of Director Nominee
  23.14      Consent of Grant Thornton LLP with respect to audited financial information of Remora Royalties, Inc.

 

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Exhibit

Number

         

Description

  24.1       Powers of Attorney (included on signature page)
  99.1       Report of Cawley, Gillespie & Associates, Inc. as of April 20, 2018
  99.2       Report of Cawley, Gillepsie & Associates, Inc. as of February 16, 2018
  99.3       Report of Cawley, Gillepsie & Associates, Inc. as of March 31, 2017

 

*   Filed herewith.

 

**   To be provided by amendment.

 

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SIGNATURES

Pursuant to the requirements of the Securities Act of 1933, as amended, the registrant has duly caused this Registration Statement to be signed on its behalf by the undersigned, hereunto duly authorized, in the City of Austin, State of Texas, on July 13, 2018.

 

Remora Royalties, Inc.
By:  

/s/ George B. Peyton V

  Name: George B. Peyton V
  Title:   Chief Executive Officer and Chairman             of the Board

Each person whose signature appears below appoints George B. Peyton V and Grant W. Livesay, 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 re-substitution, for him or her and in his or her 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 of 1933, as amended, and to file the same, with all exhibits thereto, and all other documents in connection therewith, with the Securities and Exchange Commission, 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 might or would do in person, hereby ratifying and confirming all that said attorneys-in-fact and agents, or any of them of their, or his or her substitute and substitutes, may lawfully do or cause to be done by virtue hereof.

Pursuant to the requirements of the Securities Act of 1933, as amended, this Registration Statement has been signed below by the following persons in the capacities on July 13, 2018.

 

Signature

  

Title

/s/ George B. Peyton V

George B. Peyton V

   Chief Executive Officer and Chairman of the Board (Principal Executive Officer)

/s/ Grant W. Livesay

Grant W. Livesay

   President, Chief Financial Officer, Secretary and Director (Principal Financial Officer)

/s/ Salah Gamoudi

Salah Gamoudi

  

Chief Accounting Officer

(Principal Accounting Officer)

 

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