Index to Financial Statements


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. ☐

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:

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. ☐

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.

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 AUGUST 29, 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 30.

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)(2)	$	$
Proceeds to Remora Royalties, Inc. (before expenses)(1)	$	$

(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.”

(2)

We refer you to “Underwriting” on page 168 of this prospectus for additional information regarding underwriting compensation.

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		Stifel

Co-Managers


Stephens Inc.		Seaport Global Securities

Prospectus dated , 2018

DIVERSIFIED ROYALTY INTERESTS IN 3,600+ GROSS WELLS ACROSS 12 STATES

50% OF TOTAL PROVED RESERVES OPERATED BY OUR CONTRIBUTING PARTIES

LOGO

(1)

Numbers may not sum due to rounding.

(2)

Reserves based on 3rd party reserve report prepared by Cawley, Gillespie & Associates, Inc. in accordance with SEC guidelines as of December 31, 2017. Please see “Business – Oil and Natural Gas Data” for more information.

(3)

Pro forma for the offering transactions, as described herein.

TABLE OF CONTENTS


Summary			1
Risk Factors			30
Use of Proceeds			60
Capitalization			61
Dilution			62
Dividend Policy			64
Selected Historical and Unaudited Pro Forma Financial Data			81
Management’s Discussion and Analysis of Financial Condition and Results of Operations			86
Business			108
Management			134
Executive Compensation and Other Information			140


Security Ownership of Certain Beneficial Owners and Management			143
Formation Transactions			145
Certain Relationships and Related Party Transactions			150
Description of Capital Stock			156
Shares Eligible for Future Sale			162
Material U.S. Federal Income Tax Consequences			164
Underwriting			168
Legal Matters			172
Experts			172
Where You Can Find More Information			173
Forward-Looking Statements			174
Appendix A – Glossary of Terms			A-1
Index to Financial Statements			F-i

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.

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.

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

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 giving effect to the contribution of working interests from the Contributing Parties to our Operating Affiliate, 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.

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 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

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.

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.

(1)

Numbers may not sum due to rounding.

(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. 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.

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)

(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.

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)

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.

•

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.

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 (100% 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.

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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.

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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.

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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.

Competitive Strengths

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

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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.

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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.

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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.

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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 $175.0 million secured revolving credit facility in connection with the closing of this offering. We expect to have an initial borrowing base under our secured revolving credit facility of $95.0 million and an initial aggregate elected commitment amount of $65.0 million, with approximately $10.0 million of borrowings outstanding at the closing of this offering.

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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

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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.

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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 September 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.

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

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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.

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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

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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.

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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.

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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.

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

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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 proceeds of this offering, net of underwriting discounts and the structuring fee, to Remora Holdings in exchange for RH Units, (c) we will purchase RH Units from the Contributing Parties in exchange for approximately $ of the proceeds of this offering, net of underwriting discounts and the structuring fee, 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.

Additionally, the Contributing Parties will contribute certain working interests to our Operating Affiliate.

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 (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 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.

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:

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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”);

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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;

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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

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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

“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, Building II 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.

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 underwriting discounts and the structuring fee. 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 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.

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 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.

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 September 30, 2019, we expect to generate approximately $23.8 million in cash available to make dividend payments and distributions for the twelve months ending September 30, 2019, resulting in $ million of cash available for dividend payments to Class A common stock for the same period, after distributions to holders of RH Units, or $ per share of Class A common stock. Please read “Dividend Policy—Estimated Cash Available to Make Dividend Payments for the Twelve Months Ending September 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.”

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 June 30, 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 June 30, 2018.” Our pro forma cash available for dividend payments and distributions generated during the year ended December 31, 2017 and the twelve months ended June 30, 2018 would have been $25.4 million and $17.1 million, respectively, resulting in $ million and $ million of pro forma cash available for dividend payments to Class A common stock for the same periods, respectively, after distributions to holders of RH Units. However, the pro forma cash available for dividend payments information for the year ended December 31, 2017 and the twelve months ended June 30, 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 Remora Holdings’ 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.

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 June 30, 2018 and for the six months ended June 30, 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 June 30, 2018 and for the six months ended June 30, 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 June 30, 2018 and for the six months ended June 30, 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:

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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 proceeds of this offering, net of underwriting discounts and the structuring fee, 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;

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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;

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Remora Holdings’ assumption of approximately $50.0 million of indebtedness of our Operating Affiliate that burdens the assets to be contributed to Remora Holdings by our Operating Affiliate;

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Our acquisition of the 2017 South Texas Assets;

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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;

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

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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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Remora Holdings’ entrance into a new $175.0 million secured revolving credit facility, with an initial borrowing base of $95.0 million and an initial aggregate elected commitment amount of $65.0 million, pursuant to which we expect to borrow approximately $10.0 million at the closing of this offering to repay the indebtedness assumed from our Operating Affiliate; and

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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 June 30, 2018. The unaudited pro forma statement of operations data for the six months ended June 30, 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 $1.5 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.”


	Remora Royalties, Inc. Pro Forma						Predecessor Historical
	Six Months Ended June 30, 2018			Year Ended December 31, 2017			Six Months Ended June 30,						Year Ended December 31,
	Six Months Ended June 30, 2018			Year Ended December 31, 2017			2018			2017			2017			2016
Oil, Gas and NGL Revenue	$	13,527,829		$	31,321,732		$	20,153,723		$	20,924,227		$	36,059,114		$	12,438,637

OPERATING EXPENSES:
Lease operating expenses		—			—			6,144,734			5,795,897			10,608,592			5,712,571
Workover expense		—			—			794,336			2,074,592			2,588,007			870,282
Production taxes		—						1,178,821			872,459			1,527,684			427,193
Marketing and other direct operating expenses		940,764			2,124,507			2,756,707			2,831,023			5,426,373			1,171,845
Depletion, depreciation and amortization		2,538,822			4,893,280			3,477,839			3,067,491			6,703,123			3,329,649
Accretion expense		—			—			365,564			264,824			426,925			157,950
Impairment of oil and gas properties		—			—			—			—			—			30,115,350
General and administrative expenses		800,611			689,219			4,003,055			1,344,504			3,446,096			1,662,289

Total operating expenses		4,280,197			7,707,006			18,721,056			16,250,790			30,726,800			43,447,129

INCOME (LOSS) FROM OPERATIONS		9,247,632			23,614,726			1,432,667			4,673,437			5,332,314			(31,008,492	)
OTHER INCOME (EXPENSE):
Net gain (loss) on derivative instruments		(2,465,453	)		2,310,415			(5,478,784	)		10,413,070			5,134,256			(6,280,818	)
Interest expense		(1,893,995	)		(3,904,684	)		(2,594,514	)		(2,879,601	)		(5,348,882	)		(2,835,300	)
Other income (expense)		—			—			17,980			1,530,150			1,533,756			(1,180	)

Total other income (expense)		(4,359,448	)		(1,594,269	)		(8,055,318	)		9,063,619			1,319,130			(9,117,298	)


NET INCOME (LOSS) BEFORE INCOME TAXES								(6,622,651	)		13,737,056			6,651,444			(40,125,790	)
INCOME TAX (EXPENSE) BENEFIT								—			—			—			—
NET INCOME (LOSS)	$			$			$	(6,622,651	)	$	13,737,056		$	6,651,444		$	(40,125,790	)

Statement of Cash Flows Data:
Net cash provided by (used in):
Operating activities							$	785,414		$	5,233,967		$	9,954,122		$	2,102,807
Investing activities							$	(5,992,140	)	$	1,191,170		$	8,822,602		$	(40,583,418	)
Financing activities							$	5,487,169		$	(5,847,221	)	$	(17,518,999	)	$	33,728,402
Other Financial Data:
Adjusted EBITDA(1)	$			$			$	4,463,711		$	10,449,441		$	16,563,317		$	6,623,770
Selected Balance Sheet Data:
Cash and cash equivalents	$						$	2,814,204		$	1,853,952		$	2,533,761		$	1,276,036
Total assets	$						$	76,173,762		$	64,686,528		$	66,185,399		$	61,863,679
Long-term debt	$			$			$	55,514,536		$	60,631,159		$	49,186,099		$	66,254,924
Total liabilities	$						$	97,880,577		$	72,072,249		$	80,656,732		$	82,986,456
Shareholders’ equity / Partners’ deficit	$						$	(21,706,815	)	$	(7,385,722	)	$	(14,471,333	)	$	(21,122,777	)

(1)

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

Non-GAAP Financial Measures

Adjusted EBITDA

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, amortization and accretion expenses, interest expense, 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.

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
	Six Months Ended June 30, 2018	Year Ended December 31, 2017	Six Months Ended June 30,						Year Ended December 31,
	Six Months Ended June 30, 2018	Year Ended December 31, 2017	2018			2017			2017			2016

Reconciliation of net income (loss) to Adjusted EBITDA:
Net income (loss)			$	(6,622,651	)	$	13,737,056		$	6,651,444		$	(40,125,790	)
Depreciation, depletion, amortization and accretion expenses				3,843,403			3,332,315			6,703,123			3,329,649
Interest expense				2,594,514			2,879,601			5,348,882			2,835,300
Income tax expense				—			—			—			—

EBITDA				(184,734	)		19,948,972			19,130,374			(33,802,891	)
Impairment of oil and natural gas properties				—			—			—			30,115,350
Unrealized net (gain) loss on derivative instruments				4,648,445			(9,499,531	)		(2,567,057	)		10,311,311

Adjusted EBITDA			$	4,463,711		$	10,449,441		$	16,563,317		$	6,623,770


Reconciliation of net cash provided by operating activities to Adjusted EBITDA:
Net cash provided by operating activities			$	785,414		$	5,233,967		$	9,954,122		$	2,102,807
Interest expense				2,594,514			2,879,601			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				(4,648,445	)		9,499,531			2,567,057			(10,311,311	)
Amortization of debt issuance costs				(228,438	)		(223,457	)		(450,174	)		(231,793	)
Settlements on asset retirement obligations				164,978			60,938			212,313			149,658
Changes in operating assets and liabilities:
Accounts receivable				2,330,394			1,396,890			914,855			1,314,114
Prepaid expenses and deposits				2,032,520			(296,519	)		(83,325	)		356,381
Accounts payable and accrued expenses				(3,215,671	)		1,398,021			666,644			97,303

EBITDA			$	(184,734	)	$	19,948,972		$	19,130,374		$	(33,802,891	)
Add:
Impairment of oil and natural gas properties				—			—			—			30,115,350
Unrealized net (gain) loss on derivative instruments				4,648,445			(9,499,531	)		(2,567,057	)		10,311,311

Adjusted EBITDA			$	4,463,711		$	10,449,441		$	16,563,317		$	6,623,770

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)		97,988

Estimated proved undeveloped reserves:
Oil (MBbls)		107
Natural gas (MMcf)		7,014
Natural gas liquids (MBbls)		362

Total (MMcfe)(2)		9,826

Estimated proved reserves:
Oil (MBbls)		2,206
Natural gas (MMcf)		83,819
Natural gas liquids (MBbls)		1,793

Total (MMcfe)(2)		107,815

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)		23,274

Estimated probable reserves:
Oil (MBbls)		466
Natural gas (MMcf)		21,604
Natural gas liquids (MBbls)		1,065

Total (MMcfe)(2)		30,788

(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.”

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
	Six Months Ended June 30, 2018		Year Ended December 31, 2017		Six Months Ended June 30,				Year Ended December 31,
	Six Months Ended June 30, 2018		Year Ended December 31, 2017		2018		2017		2017		2016
Production Data:
Oil and condensate (Bbls)		72,580		172,233		102,299		110,904		200,814		146,320
Natural gas (Mcf)		3,063,683		6,934,830		4,112,951		3,714,214		6,747,492		2,437,883
Natural gas liquids (Bbls)		62,102		226,043		137,885		289,621		404,393		78,485
Total (Mcfe)(6:1)(2)		3,871,772		9,324,483		5,554,055		6,117,364		10,378,734		3,786,713
Average daily production (Mcfe/d)(6:1)(2)		21,391		25,547		30,685		33,798		28,435		10,346
Total (Mcfe)(20:1)(2)		5,757,313		14,900,342		8,916,631		11,724,714		18,851,632		6,933,983
Average daily production (Mcfe/d)(20:1)(2)		31,808		40,823		49,263		64,777		51,648		18,945
Average Realized Prices:
Oil and condensate (per Bbl)	$	63.37	$	47.74	$	63.49	$	47.16	$	47.16	$	39.47
Natural gas (per Mcf)	$	2.40	$	2.71	$	2.47	$	2.80	$	2.81	$	2.26
Natural gas liquids (per Bbl)	$	24.38	$	18.23	$	24.38	$	17.47	$	17.64	$	14.17

(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.”

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 September 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 September 30, 2019—Assumptions and Considerations.” If our price or production assumptions prove to be inaccurate, our actual dividend payments for the twelve months ending September 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.”

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 September 30, 2019” includes our forecast of results of operations, Adjusted EBITDA and cash available to make dividend payments for the full twelve months ending September 30, 2019. We estimate that our total cash available to make dividend payments and distributions for the full twelve months ending September 30, 2019 will be approximately $23.8 million, resulting in $ million of cash available for dividend payments to Class A common stock for the same period, after distributions to holders of RH Units, as compared to approximately $25.4 million and $ million, respectively, for the year ended December 31, 2017 and approximately $17.1 million and $ million, respectively, for the twelve months ended June 30, 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 September 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 June 30, 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.

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.”

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;

•

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 six months ended June 30, 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.

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.

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:

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recoverable reserves;

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

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development plans;

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operating costs; and

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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

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:

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

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

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

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

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mistaken assumptions about the overall cost of equity or debt;

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

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

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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.

Our Operating Affiliate is not obligated to develop acreage burdened by our royalty interests and its development decisions are subject to its discretion, absent contractual obligations otherwise. Such decisions may be influenced by the existence of our royalty interests. In addition, our Operating Affiliate may be less incentivized to develop acreage underlying our royalty interests if and when it sells its equity interests in us.

We depend on our Operating Affiliate for a significant portion of the exploration, development and production on the properties underlying our royalty interests. However, our Operating Affiliate is not obligated to develop acreage burdened by our royalty interests and may choose to develop other acreage opportunities. In the absence of a specific contractual obligation, any development and production activities will be subject to its sole discretion (subject, in certain cases, to obligations to develop imposed by state law). In addition, our Operating Affiliate may be less incentivized to develop acreage underlying our royalty interests if and when it sells its equity interests in us. Similarly, in instances where our Operating Affiliate is not the operator, our Operating Affiliate may choose not to consent to or provide funding to develop acreage burdened by our royalty interests.

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 six months ended June 30, 2018, we received revenue from over 250 unaffiliated operators. On a pro forma basis for the year ended December 31, 2017 and the six months ended June 30, 2018, we received 63% and 56% 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:

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

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

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prevailing commodity prices;

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

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the operators’ expertise, operating efficiency and financial resources;

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approval of other participants in drilling wells;

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

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the selection of technology;

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

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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 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 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 Remora Holdings’ secured revolving credit facility and future debt agreements could limit Remora Holdings’ growth and its ability to engage in certain activities.

In connection with the closing of this offering, Remora Holdings will enter into a $175.0 million secured revolving credit facility, with an initial borrowing base of $95.0 million and an initial aggregate elected commitment amount of $65.0 million. Remora Holdings’ secured revolving credit facility will be secured by substantially all of Remora Holdings’ assets and all of the assets of its subsidiaries. Remora Holdings’ secured revolving credit facility will contain various covenants and restrictive provisions that will limit Remora Holdings’ ability (and the ability of its subsidiaries) to, among other things:

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incur or guarantee additional debt;

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declare or make distributions;

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enter into hedging arrangements;

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make certain investments and acquisitions;

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incur certain liens or permit them to exist;

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enter into certain types of transactions with affiliates;

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merge or consolidate with another company; and

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transfer, sell or otherwise dispose of assets.

Remora Holdings’ secured revolving credit facility will contain covenants requiring Remora Holdings and its subsidiaries to maintain certain financial ratios or to reduce indebtedness if Remora Holdings and its subsidiaries are unable to comply with such ratios. Remora Holdings’ ability to meet those financial ratios and tests can be affected by events beyond its control. These restrictions may also limit Remora Holdings’ ability to obtain future financings to withstand a future downturn in its business or the economy in general, or to otherwise conduct necessary corporate activities. Remora Holdings and its subsidiaries may also be

prevented from taking advantage of business opportunities that arise because of the limitations that the restrictive covenants under Remora Holdings’ secured revolving credit facility will impose on Remora Holdings and its subsidiaries.

A failure to comply with the provisions of Remora Holdings’ 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 Remora Holdings’ 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 Remora Holdings’ operations may be insufficient to repay such debt in full, and Remora Holdings’ unitholders, including the Company, could experience a partial or total loss of their investment. Remora Holdings’ 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 Remora Holdings’ borrowing base under its secured revolving credit facility as a result of the periodic borrowing base redeterminations or otherwise may negatively impact Remora Holdings’ ability to fund its operations.

Remora Holdings’ secured revolving credit facility will limit the amounts Remora Holdings can borrow up to a borrowing base amount, which the lenders, in their sole discretion, determine on a semi-annual basis based upon (among other things) projected revenues from the oil and natural gas properties securing Remora Holdings’ loan. The borrowing base will be determined based on (among other things) Remora Holdings’ oil and natural gas properties and the oil and natural gas properties of Remora Holdings’ wholly owned subsidiaries. The lenders can unilaterally adjust the borrowing base and the borrowings permitted to be outstanding under Remora Holdings’ 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 highest borrowing base acceptable to such lenders. Decreases in the available borrowing amount could result from (among other factors) 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 Remora Holdings must pledge other oil and natural gas properties as additional collateral after applicable grace periods. Remora Holdings and its subsidiaries do not expect to have any substantial unpledged properties, and Remora Holdings may not have the financial resources in the future to make mandatory principal prepayments required under its secured revolving credit facility.

Remora Holdings’ debt levels may limit our, Remora Holdings’ and its subsidiaries’ flexibility to obtain additional financing and pursue other business opportunities.

Remora Holdings’ existing and future indebtedness could have important consequences to us, Remora Holdings and its subsidiaries, including:

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our, Remora Holdings’ and its subsidiaries’ 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, or Remora Holdings;

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

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our, Remora Holdings’ and its subsidiaries’ access to the capital markets may be limited;

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our, Remora Holdings’ and its subsidiaries’ borrowing costs may increase;

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Remora Holdings may need a substantial portion of its cash flow to make principal and interest payments on its indebtedness, reducing the funds that would otherwise be available for operations, future business opportunities and cash distributions to unitholders, including us; and

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Remora Holdings’ debt level may make us, Remora Holdings and its subsidiaries more vulnerable than our competitors with less debt to competitive pressures or a downturn in our business or the economy generally.

Remora Holdings’ and its subsidiaries’ ability to service its indebtedness will depend upon, among other things, its 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 its control. If Remora Holdings’ and its subsidiaries’ operating results are not sufficient to service its current or future indebtedness, it will be forced to take actions such as reducing cash distributions, reducing or delaying business activities, acquisitions, investments and/or capital expenditures, selling assets, restructuring or refinancing its indebtedness, or seeking additional equity capital or bankruptcy protection. Remora Holdings and its subsidiaries 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 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 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.

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, 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.

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.

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:

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

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the establishment of maximum rates of production from wells;

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the spacing of wells;

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the plugging and abandonment of wells; and

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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 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 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 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:

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unusual or unexpected geological formations;

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loss of drilling fluid circulation;

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title problems;

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facility or equipment malfunctions;

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unexpected operational events;

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shortages or delivery delays of equipment and services;

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compliance with environmental and other governmental requirements; and

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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 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 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 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:

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permit our Operating Affiliate and its affiliates to develop acreage not burdened by our royalty interests;

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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

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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 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:

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changes in commodity prices;

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

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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;

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departures of key personnel;

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commencement of or involvement in litigation;

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

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

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

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

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

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

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future sales of our Class A common stock; and

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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’ 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.

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.

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 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. 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;

•

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 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.

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 and the structuring fee. 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 approximately $10.0 million that we will borrow under our secured revolving credit facility upon the closing of this offering to repay in full approximately $50.0 million 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 and the estimated offering expenses payable in connection with this offering.

Other than approximately $10.0 million that we will borrow under our secured revolving credit facility upon the closing of this offering to pay the estimated offering expenses and 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.

CAPITALIZATION

The following table shows our cash and cash equivalents and capitalization as of June 30, 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 June 30, 2018
	Predecessor Historical (in thousands)			Remora Royalties, Inc. Pro Forma (in thousands)
Cash and cash equivalents		2,814		$

Long-term debt(1)	$	55,515		$

Stockholders’ equity/partners’ deficit:
Partners’ deficit		(21,707	)	$
Preferred stock		—
Class A common stock		—
Class B common stock		—

Total stockholders’ equity/partners’ deficit	$	(21,707	)	$

Total capitalization	$	33,808		$

(1)

As of August 9, 2018, our predecessor had $38.6 million outstanding under its senior secured revolving credit facility. In connection with the closing of this offering, we expect Remora Holdings to enter into a new $175.0 million secured revolving credit facility, with an initial borrowing base of $95.0 million and an aggregate elected commitment amount of $65.0 million, and to have approximately $10.0 million of borrowings outstanding at the closing of this offering.

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 June 30, 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 proceeds of the offering, net of underwriting discounts and the structuring fee, 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 June 30, 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 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.

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 September 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 December 31, 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.

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 approximately $10.0 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 June 30, 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 September 30, 2019.

Unaudited Pro Forma Cash Available to Make Dividend Payments for the Year Ended December 31, 2017 and the Twelve Months Ended June 30, 2018

We estimate that we would have generated $25.4 million and $17.1 million of pro forma cash available to make dividend payments and distributions for the year ended December 31, 2017 and the twelve months ended June 30, 2018, respectively, resulting in $ million and $ million of pro forma cash available for dividend payments to Class A common stock for the same periods, respectively, after distributions to holders of RH Units. Assuming we do not retain cash from operations for capital expenditures, this amount would have resulted in aggregate annual dividends and distributions equal to $25.4 million for the year ended December 31, 2017 and $17.1 million for the twelve months ended June 30, 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 June 30, 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 June 30, 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 June 30, 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 June 30, 2018.

Remora Royalties, Inc.

Pro Forma Cash Available to Make Dividend Payments


	Year Ended Dec 31, 2017			Year Ended Jun 30, 2018
Revenue:
Oil, natural gas and NGL revenues	$	31,321,732		$	30,696,146
Cost and expenses:
Marketing and other direct operating expenses (1)	$	2,124,507		$	2,343,466
Depreciation, depletion, amortization and accretion expenses	$	4,893,280		$	4,985,462
General and administrative	$	689,219		$	1,220,929

Total costs and expenses	$	7,707,006		$	8,549,857


Operating income	$	23,614,726		$	22,146,289
Other expenses:
Interest expense	$	3,904,684		$	3,696,570
Net loss/(gain) on derivative instruments	$	(2,310,415	)	$	4,840,919
Impairment of oil and natural gas properties		—			—
Income tax expense		—			—

Pro Forma Net Income (2)	$	22,020,457		$	13,608,800


Adjustments to reconcile to pro forma Adjusted EBITDA:
Depreciation, depletion, amortization and accretion expenses	$	4,893,280		$	4,985,462
Interest expense	$	3,904,684		$	3,696,570
Impairment of oil and natural gas properties		—			—
Unrealized net loss/(gain) on derivative instruments		—			—
Income tax expense		—			—

Adjusted EBITDA (3)	$	30,818,421		$	22,290,832

Adjustments to reconcile Adjusted EBITDA to cash available to make dividend payments:
Incremental general and administrative expenses (4)	$	1,500,000		$	1,500,000
Cash interest expense	$	3,904,684		$	3,696,570
Cash income tax expense		—			—
Capital expenditures		—			—

Cash available for dividend payments and distributions	$	25,413,737		$	17,094,262

Cash reserves		—			—
Distributions with respect to RH Units held by Contributing Parties ( Units)

Cash available for dividend payments to Class A common stock ( shares)

Per share dividend to Class A common stock	$			$

(1)

Production and ad valorem taxes are included in Marketing and other direct operating expenses.

(2)

Pro forma net income for the years ended December 31, 2017 and June 30, 2018 gives effect to the pro forma adjustments reflected in our unaudited pro forma condensed combined financial statements included elsewhere in this prospectus.

(3)

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”.

(4)

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 September 30, 2019

During the twelve months ending September 30, 2019, we estimate that we will generate $23.8 million of cash available to make dividend payments and distributions, resulting in $ million of cash available for dividend payments to Class A common stock for the same period, after distributions to holders of RH Units. 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 September 30, 2019 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 $23.8 million of cash available to make dividend payments and distributions for the full twelve months ending September 30, 2019 and $ million of cash available for dividend payments to Class A common stock for the same period, after distributions to holders of RH Units. 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.

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 shares of Class A common stock for the full twelve months ending September 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 September 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 September 30, 2019 and for each quarter during that twelve-month period. All of the amounts for the full twelve months ending September 30, 2019 in the table below are estimates and include the assets to be contributed to us at the consummation of this offering.

Remora Royalties, Inc.

Estimated Cash Available to Make Dividend Payments

(Unaudited)


	Three Months Ending Dec 31, 2018		Three Months Ending Mar 31, 2019		Three Months Ending Jun 30, 2019		Three Months Ending Sept 30, 2019		Twelve Months Ending Sept 30, 2019
Revenue:
Oil, natural gas and NGL revenues	$	7,711,551	$	7,829,768	$	7,343,338	$	7,598,106	$	30,482,763
Cost and expenses:
Production and ad valorem taxes	$	592,188	$	605,565	$	571,600	$	585,094	$	2,354,447
Depreciation, depletion and accretion expenses	$	3,100,435	$	3,057,780	$	3,069,953	$	3,197,314	$	12,425,482
Marketing and other deductions		—		—		—		—		—
General and administrative (1)	$	750,000	$	750,000	$	750,000	$	750,000	$	3,000,000

Total costs and expenses	$	4,442,623	$	4,413,345	$	4,391,553	$	4,532,408	$	17,779,929

Operating income	$	3,268,928	$	3,416,423	$	2,951,785	$	3,065,698	$	12,702,834
Other expenses:
Interest expense (2)	$	205,970	$	203,682	$	205,970	$	205,970	$	821,592
Net loss/(gain) on derivatives		—		—		—		—		—
Impairment of oil and natural gas properties		—		—		—		—		—
Income tax expense	$	643,221	$	674,676	$	576,621	$	600,543	$	2,495,061

Net Income	$	2,419,737	$	2,538,065	$	2,169,194	$	2,259,185	$	9,386,181

Adjustments to reconcile to pro forma Adjusted EBITDA:
Depreciation, depletion, amortization and accretion expenses	$	3,100,435	$	3,057,780	$	3,069,953	$	3,197,314	$	12,425,482
Interest expense (2)	$	205,970	$	203,682	$	205,970	$	205,970	$	821,592
Impairment of oil and natural gas properties		—		—		—		—		—
Unrealized net loss/(gain) on derivative instruments		—		—		—		—		—
Income tax expense (3)	$	643,221	$	674,676	$	576,621	$	600,543	$	2,495,061

Adjusted EBITDA (4)	$	6,369,363	$	6,474,203	$	6,021,738	$	6,263,012	$	25,128,316

Adjustments to reconcile Adjusted EBITDA to cash available to make dividend payments:
Cash interest expense (2)	$	164,063	$	162,240	$	164,063	$	164,063	$	654,429
Cash income tax expense (3)	$	284,525	$	132,071	$	122,565	$	127,614	$	666,775
Capital expenditures		—		—		—		—		—

Cash available for dividend payments and distributions	$	5,920,775	$	6,179,892	$	5,735,110	$	5,971,335	$	23,807,112

Cash reserves		—		—		—		—		—
Distributions with respect to RH Units held by Contributing Parties ( units)

Cash available for dividend payments to Class A common stock ( 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 approximately $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 effective tax rate of approximately 5.5%.

(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”.

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 September 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 September 30, 2019, compared to the pro forma year ended December 31, 2017 and the pro forma twelve months ended June 30, 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 September 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 June 30, 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 June 30, 2018, the operators on the properties reflected in our pro forma financial statements produced volumes of 9,324,483 Mcfe and 8,888,556 Mcfe, respectively, compared to our forecast of 8,039,669 Mcfe for the full twelve months ending September 30, 2019. The volume decrease reflected in the forecast compared to the year ended December 31, 2017 and the twelve months ended June 30, 2018 is 13.8% and 9.6%, 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 June 30, 2018, our average realized price per Mcfe was $3.36 and $3.45, respectively, compared to the estimated weighted average projected realized price, based on NYMEX WTI and Henry Hub pricing, of $3.79 per Mcfe for the full twelve months ending September 30, 2019 as of August 7, 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 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. The price increase reflected in the forecast compared to the year ended December 31, 2017 and the twelve months ended June 30, 2018 is 12.8% and 9.9%, respectively. While the pro forma cash available for dividends for the year ended December 31, 2017 and the twelve months ended June 30, 2018 includes the impact of derivative instruments, we do not estimate any impact from such realized or unrealized gains and losses on derivative instruments for the twelve months ended September 30, 2019.

Cash available to make dividend payments. We estimate a $1.6 million decrease in cash available to make dividend payments and distributions for the full twelve months ending September 30, 2019 as compared to the year ended December 31, 2017. The decrease is primarily attributable to a 13.8% decrease in production volumes that account for $4.3 million, a $2.3 million decrease in net derivative gains, $0.2 million in estimated increased production and ad valorem taxes, $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, and $0.7 million in estimated increased income tax expense, partially offset by a 12.8% increase in estimated price per Mcfe that accounts for $3.5 million, and $3.2 million in estimated decreased interest expense.

We estimate a $6.7 million increase in cash available to make dividend payments and distributions for the twelve months ending September 30, 2019 as compared to the year ended June 30, 2018. The increase is primarily attributable to a 9.9% increase in price per Mcfe that accounts for $2.7 million, a $4.8 million decrease in net derivative losses, and $3.1 million in estimated decreased interest expense, partially offset by the 9.6% decrease in production volumes that account for $2.9 million, $0.3 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, and $0.7 million in estimated increased income tax expense.

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 September 30, 2019 will be $30.5 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 June 30, 2018 and for the full twelve months ending September 30, 2019:


	Twelve Months Ended				Twelve Months Ending September 30, 2019
	December 31, 2017		June 30, 2018		Twelve Months Ending September 30, 2019
Production:
Oil (Bbls)		172,233		169,533		184,269
Natural Gas (Mcf)		6,934,830		6,925,215		6,189,895
Natural gas liquids (Bbls)		226,043		157,691		124,027
Combined volumes (Mcfe)		9,324,483		8,888,556		8,039,669

Average daily production:
Oil (Bbls/d)		472		464		505
Natural gas (Mcf/d)		19,000		18,973		16,959
Natural gas liquids (Bbls/d)		619		432		340
Combined volumes (Mcfe/d)		25,547		24,352		22,026

We estimate that oil and natural gas production from the properties underlying our interests for the full twelve months ending September 30, 2019 will be 8,039,669 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 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 94% 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 and PUD 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 August 7, 2018 for the full twelve months ending September 30, 2019:


Forecasted average oil sales prices:
NYMEX-WTI oil price per Bbl	$	66.06
Differential to NYMEX-WTI oil per Bbl (1)	$	(3.34	)
Realized oil sales price per Bbl	$	62.72

Forecasted average natural gas liquids sales prices:
NYMEX-WTI oil price per Bbl	$	66.06
Differential to NYMEX-WTI oil per Bbl (1)	$	(41.65	)
Realized natural gas liquids sales price per Bbl	$	24.41

Forecasted average natural gas sales prices:
NYMEX-Henry Hub per price MMBtu	$	2.83
Differential to NYMEX-Henry Hub natural gas (1)	$	(0.27	)
Realized natural gas sales price per Mcf	$	2.57
Total weighted average combined realized price (per Mcfe)	$	3.79

(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 September 30, 2019:


Production taxes	$	1,764
Ad valorem taxes	$	591

Total production and ad valorem taxes	$	2,355
Production and ad valorem taxes as a percentage of revenue		7.7	%

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.

Depreciation and depletion expenses. We estimate that our depreciation and depletion expenses for the full twelve months ending September 30, 2019 will be $12.4 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 September 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 $0.8 million in interest expense for the full twelve months ending September 30, 2019. We intend to enter into a $175.0 million secured revolving credit facility with an initial borrowing base of $95.0 million and an initial aggregate elected commitment amount of $65.0 million in connection with this offering, and such credit facility is expected to have approximately $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 approximately $0.2 million and annual amortization of deferred finance costs of approximately $0.2 million.

Financing

We intend to enter into a new $175.0 million secured revolving credit facility with an initial borrowing base of $95.0 million and an initial aggregate elected commitment amount of $65.0 million. The unused portion of the secured revolving credit facility is subject to a commitment fee up to 50 basis points on the unused portion of the aggregate elected commitment amount.

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 September 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.

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 September 30, 2019 of $23.8 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 September 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 September 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 September 30, 2019.


	Percentage of Forecasted Annual Production
	90%			100%			110%
Forecasted annual production:
Oil (bbls)		165,842			184,269			202,696
Natural gas (Mcf)		5,570,905			6,189,895			6,808,884
Natural gas liquids (Bbls)		111,624			124,027			136,429
Combined Volumes (Mcfe)		7,235,702			8,039,669			8,843,636

Forecasted average daily production:
Oil (bbls)		454			505			555
Natural gas (Mcf)		15,263			16,959			18,654
Natural gas liquids (Bbls)		306			340			374
Combined Volumes (Mcfe)		19,824			22,026			24,229

Forecasted average oil sales prices:		100	%		100	%		100	%
NYMEX-WTI oil price per Bbl	$	66.06		$	66.06		$	66.06
Realized oil sales price per Bbl	$	62.72		$	62.72		$	62.72

NYMEX-WTI oil price per Bbl	$	66.06		$	66.06		$	66.06
Realized natural gas liquids sales price per Bbl	$	24.41		$	24.41		$	24.41

Forecasted average natural gas sales prices:
NYMEX-Henry Hub natural gas price per MMBtu	$	2.83		$	2.83		$	2.83
Realized natural gas sales price per Mcf	$	2.57		$	2.57		$	2.57

Revenue:
Oil, natural gas and NGL revenues	$	27,434,486		$	30,482,763		$	33,531,039
Cost and expenses:
Production and ad valorem taxes	$	2,119,002		$	2,354,447		$	2,589,892
Depreciation, depletion, amortization and accretion expenses	$	11,182,934		$	12,425,482		$	13,668,031
Marketing and other deductions		—			—			—
General and administrative (1)	$	3,000,000		$	3,000,000		$	3,000,000

Total costs and expenses	$	16,301,936		$	17,779,929		$	19,257,923

Operating income	$	11,132,550		$	12,702,834		$	14,273,116
Other expenses:
Interest expense (2)	$	821,593		$	821,592		$	821,593
Net loss/(gain) on derivatives		—			—			—
Impairment of oil and natural gas properties		—			—			—
Income tax expense (3)	$	2,165,301		$	2,495,061		$	2,824,820

Net Income	$	8,145,656		$	9,386,181		$	10,626,703

Adjustments to reconcile to pro forma Adjusted EBITDA:
Depreciation, depletion, amortization and accretion expenses	$	11,182,934		$	12,425,482		$	13,668,031
Interest expense	$	821,593		$	821,592		$	821,593
Impairment of oil and natural gas properties		—			—			—
Unrealized net loss/(gain) on derivative instruments		—			—			—
Income tax expense	$	2,165,301		$	2,495,061		$	2,824,820

Adjusted EBITDA (4)	$	22,315,484		$	25,128,316		$	27,941,147


Adjustments to reconcile Adjusted EBITDA to cash available to make dividend payments:
Cash interest expense (2)	$	654,427		$	654,429		$	654,427
Cash income tax expense (3)	$	579,873		$	666,775		$	753,676
Capital expenditures		—			—			—

Cash available for dividend payments and distributions	$	21,081,184		$	23,807,112		$	26,533,044

Cash reserves		—			—			—
Distributions with respect to RH Units held by Contributing Parties ( Units)

Cash available for dividend payments to Class A common stock ( Shares)

Per share dividend to Class A common stock

(1)

(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 effective tax rate of approximately 5.5%.

(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 September 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.


Forecasted annual production:
Oil (bbls)		184,269			184,269			184,269
Natural gas (Mcf)		6,189,895			6,189,895			6,189,895
Natural gas liquids (Bbls)		124,027			124,027			124,027
Combined Volumes (Mcfe)		8,039,669			8,039,669			8,039,669

Forecasted average daily production:
Oil (bbls)		505			505			505
Natural gas (Mcf)		16,959			16,959			16,959
Natural gas liquids (Bbls)		340			340			340
Combined Volumes (Mcfe)		22,026			22,026			22,026

	Percentage Change in Commodity Price
Forecasted average oil sales prices:		90	%		100	%		110	%
NYMEX-WTI oil price per Bbl	$	59.45		$	66.06		$	72.67
Realized oil sales price per Bbl	$	56.45		$	62.72		$	68.99

NYMEX-WTI oil price per Bbl	$	59.45		$	66.06		$	72.67
Realized natural gas liquids sales price per Bbl	$	21.97		$	24.41		$	26.85

Forecasted average natural gas sales prices:
NYMEX-Henry Hub natural gas price per MMBtu	$	2.55		$	2.83		$	3.12



	Percentage Change in Commodity Price
Realized natural gas sales price per Mcf	$	2.31	$	2.57	$	2.83

Revenue:
Oil, natural gas and NGL revenues	$	27,434,486	$	30,482,763	$	33,531,039
Cost and expenses:
Production and ad valorem taxes	$	2,119,002	$	2,354,447	$	2,589,892
Depreciation, depletion, amortization and accretion expenses	$	12,425,482	$	12,425,482	$	12,425,482
Marketing and other deductions		—		—		—
General and administrative (1)	$	3,000,000	$	3,000,000	$	3,000,000

Total costs and expenses	$	17,544,485	$	17,779,929	$	18,015,374

Operating income	$	9,890,002	$	12,702,834	$	15,515,665
Other expenses:
Interest expense (2)	$	821,593	$	821,592	$	821,593
Net loss/(gain) on derivatives		—		—		—
Impairment of oil and natural gas properties		—		—		—
Income tax expense (3)	$	1,904,366	$	2,495,061	$	3,085,755

Net Income	$	7,164,043	$	9,386,181	$	11,608,317


Adjustments to reconcile to pro forma Adjusted EBITDA:
Depreciation, depletion, amortization and accretion expenses	$	12,425,482	$	12,425,482	$	12,425,482
Interest expense (2)	$	821,593	$	821,592	$	821,593
Impairment of oil and natural gas properties		—		—		—
Unrealized net loss/(gain) on derivative instruments		—		—		—
Income tax expense (3)	$	1,904,366	$	2,495,061	$	3,085,755

Adjusted EBITDA (4)	$	22,315,484	$	25,128,316	$	27,941,147

Adjustments to reconcile Adjusted EBITDA to cash available to make dividend payments:
Cash interest expense (2)	$	654,427	$	654,429	$	654,427
Cash income tax expense (3)	$	511,109	$	666,775	$	822,441
Capital expenditures		—		—		—

Cash available for dividend payments and distributions	$	21,149,948	$	23,807,112	$	26,464,279

Cash reserves		—		—		—
Distributions with respect to RH Units held by Contributing Parties ( Units)

Cash available for dividend payments to Class A common stock ( Shares)

Per share dividend to Class A common stock

(1)

(2)

(3)

Income tax expense is based on the statutory federal income tax rate of 21%. Cash income tax expense is based on an assumed effective tax rate of approximately 5.5%.

(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”.

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 June 30, 2018 and for the six months ended June 30, 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 six months ended June 30, 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 $50.0 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 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 $175.0 million secured revolving credit facility, pursuant to which we expect to borrow approximately $10.0 million 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.

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 $1.5 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.

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
	Six Months Ended June 30, 2018			Year Ended December 31, 2017			Six Months Ended June 30,						Year Ended December 31,
	Six Months Ended June 30, 2018			Year Ended December 31, 2017			2018			2017			2017			2016
Oil, gas and NGL revenue	$	13,527,829		$	31,321,732		$	20,153,723		$	20,924,227		$	36,059,114		$	12,438,637

OPERATING EXPENSES:
Lease operating expenses		—			—			6,144,734			5,795,897			10,608,592			5,712,571
Workover expense		—			—			794,336			2,074,592			2,588,007			870,282
Production taxes		—						1,178,821			872,459			1,527,684			427,193
Marketing and other direct operating expenses		940,764			2,124,507			2,756,707			2,831,023			5,426,373			1,171,845
Depletion, depreciation and amortization		2,538,822			4,893,280			3,477,839			3,067,491			6,703,123			3,329,649
Accretion expense		—			—			365,564			264,824			426,925			157,950
Impairment of oil and gas properties		—			—			—			—			—			30,115,350
General and administrative expenses		800,611			689,219			4,003,055			1,344,504			3,446,096			1,662,289

Total operating expenses		4,280,197			7,707,006			18,721,056			16,250,790			30,726,800			43,447,129

INCOME (LOSS) FROM OPERATIONS		9,247,632			23,614,726			1,432,667			4,673,437			5,332,314			(31,008,492	)
OTHER INCOME (EXPENSE):
Net gain (loss) on derivative instruments		(2,465,453	)		2,310,415			(5,478,784	)		10,413,070			5,134,256			(6,280,818	)
Interest expense		(1,893,995	)		(3,904,684	)		(2,594,514	)		(2,879,601	)		(5,348,882	)		(2,835,300	)
Other income (expense)		—			—			17,980			1,530,150			1,533,756			(1,180	)

Total other income (expense)		(4,359,448	)		(1,594,269	)		(8,055,318	)		9,063,619			1,319,130			(9,117,298	)


NET INCOME (LOSS) BEFORE INCOME TAXES								(6,622,651	)		13,737,056			6,651,444			(40,125,790	)
INCOME TAX (EXPENSE) BENEFIT								—			—			—			—
NET INCOME (LOSS)	$			$			$	(6,622,651	)	$	13,737,056		$	6,651,444		$	(40,125,790	)

Statement of Cash Flows Data:
Net cash provided by (used in):
Operating activities	$			$			$	785,414		$	5,233,967		$	9,954,122		$	2,102,807
Investing activities	$			$			$	(5,992,140	)	$	1,191,170		$	8,822,602		$	(40,583,418	)
Financing activities	$			$			$	5,487,169		$	(5,847,221	)	$	(17,518,999	)	$	33,728,402
Other Financial Data:
Adjusted EBITDA (1)	$			$			$	4,463,711		$	10,449,441		$	16,563,317		$	6,623,770
Selected Balance Sheet Data:
Cash and cash equivalents	$			$			$	2,814,204		$	1,853,952		$	2,533,761		$	1,276,036
Total assets	$			$			$	76,173,762		$	64,686,528		$	66,185,399		$	61,863,679
Long-term debt	$			$			$	55,514,536		$	60,631,159		$	49,186,099		$	66,254,924
Total liabilities	$			$			$	97,880,577		$	72,072,249		$	80,656,732		$	82,986,456
Shareholders’ equity / Partners’ deficit	$			$			$	(21,706,815	)	$	(7,385,722	)	$	(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. 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.


	Remora Royalties, Inc. Pro Forma				Predecessor Historical
	Six Months Ended June 30, 2018		Year Ended December 31, 2017		Six Months Ended June 30,						Year Ended December 31,
	Six Months Ended June 30, 2018		Year Ended December 31, 2017		2018			2017			2017			2016
Reconciliation of net income (loss) to Adjusted EBITDA:
Net income (loss)	$		$		$	(6,622,651	)	$	13,737,056		$	6,651,444		$	(40,125,790	)
Depreciation, depletion, amortization and accretion expenses		—		—		3,843,403			3,332,315			7,130,048			3,487,599
Interest expense						2,594,514			2,879,601			5,348,882			2,835,300
Income tax expense		—		—		—			—			—			—

EBITDA						(184,734	)		19,948,972			19,130,374			(33,802,891	)

Impairment of oil and natural gas properties		—		—		—			—			—			30,115,350
Unrealized net (gain) loss on derivative instruments						4,648,445			(9,499,531	)		(2,567,057	)		10,311,311

Adjusted EBITDA	$		$		$	4,463,711		$	10,449,441		$	16,563,317		$	6,623,770

Reconciliation of net cash provided by operating activities to Adjusted EBITDA:
Net cash provided by operating activities	$		$		$	785,414		$	5,233,967		$	9,954,122		$	2,102,807
Interest expense						2,594,514			2,879,601			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						(4,648,445	)		9,499,531			2,567,057			(10,311,311	)
Amortization of debt issuance costs						(228,438	)		(223,457	)		(450,174	)		(231,793	)
Settlement of asset retirement obligations						164,978			60,938			212,313			149,658
Changes in operating assets and liabilities:
Accounts receivables						2,330,394			1,396,890			914,855			1,314,114
Prepaid expenses and deposits						2,032,520			(296,519	)		(83,325	)		356,381
Accounts payable and accrued expenses						(3,215,671	)		1,398,021			666,644			97,303

EBITDA	$		$		$	(184,734	)	$	19,948,972		$	19,130,374		$	(33,802,891	)

Add:
Impairment of oil and natural gas properties		—		—		—			—			—			30,115,350
Unrealized net (gain) loss on derivative instruments						4,648,445			(9,499,531	)		(2,567,057	)		10,311,311

Adjusted EBITDA	$		$		$	4,463,711		$	10,449,441		$	16,563,317		$	6,623,770

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.

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 June 2018 was $67.87 per Bbl, a 31% 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 June 2018 was $2.97 per MMBtu, a 17% 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 the first half of 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 1,044 active rigs at August 3, 2018, a 59% increase from 658 active rigs at December 31, 2016. However, the 1,044 active rigs at August 3, 2018 represents a 43% 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 six months ended June 30, 2017 and 2018:


	Six Months Ended June 30,				Year Ended December 31,
Average Prices:	2018		2017		2017		2016
Oil (Bbl)	$	65.46	$	50.00	$	50.80	$	43.29
Natural gas (MMBtu)	$	2.97	$	3.04	$	2.99	$	2.52
Natural gas liquids (Bbl)	$	46.06	$	38.05	$	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 six months ended June 30, 2018, our revenues were derived 32% from oil sales, 51% from natural gas sales and 17% 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

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)		116,433		98,801

Predecessor Estimated Net Proved Undeveloped Reserves:
Oil (MBbls)		1,071		—
Natural gas (MMcf)		63,338		—
Natural gas liquids (MBbls)		3,631		—

Total (MMcfe)(1)		91,549		—

Predecessor Estimated Net Proved Reserves:
Oil (MBbls)		3,227		1,687
Natural gas (MMcf)		148,124		67,019
Natural gas liquids (MBbls)		6,750		3,610

Total (MMcfe)(1)		207,982		98,801

Predecessor Estimated Net Probable Developed Reserves:
Oil (MBbls)		430		—
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)		3,188		—
Natural gas (MMcf)		153,393		—
Natural gas liquids (MBbls)		10,668		—

Total (MMcfe)(1)		236,528		—


	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.

Adjusted EBITDA

We define Adjusted EBITDA as net income (loss) plus depreciation, depletion and accretion expenses, interest expense, 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 for the six months ended June 30, 2018, the revenues reflected in the historical financial statements of our predecessor comprise 67% 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 six months ended June 30, 2018, our predecessor’s interest expense was $5.3 million and $2.6 million,

respectively. Our predecessor had outstanding borrowings of $56.6 million as of June 30, 2018. We will assume approximately $50.0 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 approximately $10.0 million under our secured revolving credit facility upon the closing of this offering. In connection with the closing of this offering, we will enter into a new $175.0 million secured revolving credit facility, with an initial borrowing base of $95.0 million and an aggregate elected commitment amount of $65.0 million. 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.

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 $1.5 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 six months ended June 30, 2018, our predecessor’s interest expense was $5.3 million and $2.6 million, respectively. Our predecessor had outstanding borrowings of $49.2 million, net of debt discount, as of December 31, 2017. In connection with the closing of this offering, Remora Holdings will enter into a new $175.0 million secured revolving credit facility, with an initial borrowing base of $95.0 million and an aggregate elected commitment amount of $65.0 million. Remora Holdings will assume approximately $50.0 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 $10.0 million 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.”

Predecessor Results of Operations

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


	Six Months Ended June 30,						Years Ended December 31,
	2018			2017			2017			2016
Operating Results:
Oil, gas and NGL revenue	$	20,153,723		$	20,924,227		$	36,059,114		$	12,438,637
Operating expenses:
Lease operating expense		6,144,734			5,795,897			10,608,592			5,712,571
Workover expense		794,336			2,074,592			2,588,007			870,282
Production taxes		1,178,821			872,459			1,527,684			427,193
Marketing and transportation expense		2,756,707			2,831,023			5,426,373			1,171,845
Depletion, depreciation and amortization		3,477,839			3,067,491			6,703,123			3,329,649
Accretion expense		365,564			264,824			426,925			157,950
Impairment of oil and natural gas properties		—			—			—			30,115,350
General and administrative expense		4,003,055			1,344,504			3,446,096			1,662,289

Total operating expenses		18,721,056			16,250,790			30,726,800			43,447,129
Income (loss) from operations		1,432,667			4,673,437			5,332,314			(31,008,492	)
Other income (expense):
Net gain (loss) on derivative instruments		(5,478,784	)		10,413,070			5,134,256			(6,280,818	)
Interest expense		(2,594,514	)		(2,879,601	)		(5,348,882	)		(2,835,300	)
Other income (expense)		17,980			1,530,150			1,533,756			(1,180	)

Total other income (expense)		(8,055,318	)		9,063,619			1,319,130			(9,117,298	)

Net Income (loss)	$	(6,622,651	)	$	13,737,056		$	6,651,444		$	(40,125,790	)
Production Data:
Oil (Bbls)		102,299			110,904			200,814			146,320
Natural gas (Mcf)		4,112,951			3,714,214			6,747,492			2,437,883
Natural gas liquids (Bbls)		137,885			289,621			404,393			78,485
Combined volumes (Mcfe) (6:1)		5,554,055			6,117,364			10,378,734			3,786,713
Average daily combined volumes (Mcfe/d) (6:1)		30,685			33,798			28,435			10,346

Comparison of the Six Months Ended June 30, 2018 to the Six Months Ended June 30, 2017

Oil, Natural Gas and Natural Gas Liquids Revenues

Our predecessor’s revenues for the six months ended June 30, 2018 was $20.2 million, a decrease of $0.7 million, from $20.9 million for the six months ended June 30, 2017. Our predecessor’s decrease in revenues was primarily due to lower realized natural gas prices for the six months ended June 30, 2018 compared to the six months ended June 30, 2017 and a 0.6 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 six months ended June 30, 2018 compared to the six months ended June 30, 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 six months ended

June 30, 2018 were 5.6 Bcfe, a decrease from 6.1 Bcfe for the six months ended June 30, 2017. Our predecessor received an average of $63.49 per Bbl of oil, $2.47 per Mcf of natural gas and $24.38 per Bbl of NGLs for the volumes sold during the six months ended June 30, 2018, as compared to an average of $47.16 per Bbl of oil, $2.80 per Mcf of natural gas and $17.47 per Bb1 of NGLs for the volumes sold during the six months ended June 30, 2017.

Lease Operating Expense

Our predecessor’s lease operating expense increased by $0.3 million to $6.1 million for the six months ended June 30, 2018, from $5.8 million for the six months ended June 30, 2017. The increase in lease operating expense was primarily attributable to a one-time regulatory and environmental expense incurred for the six months ended June 30, 2018.

Workover Expense

Our predecessor’s workover expense decreased by $1.3 million to $0.8 million for the six months ended June 30, 2018, from $2.1 million for the six months ended June 30, 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 $0.3 million to $1.2 million for the six months ended June 30, 2018, from $0.9 million for the six months ended June 30, 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 remained unchanged for the six months ended June 30, 2018, at $2.8 million, the same as for the six months ended June 30, 2017.

Depreciation, Depletion and Amortization Expense

Our predecessor’s depreciation, depletion and amortization expense increased by $0.4 million to $3.5 million for the six months ended June 30, 2018 from $3.1 million for six months ended June 30, 2017. The average depletion rate per barrel was $3.74 and $3.00 for the six months ended June 30, 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 six months ended June 30, 2018 was $0.4 million, an increase of $0.1 million from $0.3 million for the six months ended June 30, 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 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 six months ended June 30, 2018 and June 30, 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 six months ended June 30, 2018 were $4.0 million, an increase of $2.7 million from $1.3 million for the six months ended June 30, 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 $5.5 million net loss on derivative instruments for the six months ended June 30, 2018, a decrease of $15.9 million from a $10.4 million net gain on derivative instruments for the six months ended June 30, 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 six months ended June 30, 2018.

Interest Expense

Our predecessor’s interest expense for the six months ended June 30, 2018 was $2.6 million, a decrease of $0.3 million from $2.9 million for the six months ended June 30, 2017. The decrease in interest expense is due to a decrease in the outstanding balance of our Predecessor Credit Facility during the six months ended June 30, 2018 compared to the six months ended June 30, 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 $14.17 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 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

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.

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 $11.4 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. In connection with the closing of this offering, we will enter into a new $175.0 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. 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.


	Six Months Ended June 30,						Years Ended December 31,
	2018			2017			2017			2016
Cash Flow Data:
Cash provided by operating activities	$	785,414		$	5,233,967		$	9,954,122		$	2,102,807
Cash provided by (used in) investing activities		(5,992,140	)		1,191,170			8,822,602			(40,583,418	)
Cash provided by (used in) financing activities		5,487,169			(5,847,221	)		(17,518,999	)		33,728,402

Net increase (decrease) in cash and cash equivalents	$	280,443		$	577,916		$	1,257,725		$	(4,752,209	)

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 six months ended June 30, 2018 as compared to the six months ended June 30, 2017 of $4.4 million were largely attributable to lower realized natural gas prices and a 0.6 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 six months ended June 30, 2018, cash used in our investing activities was $6.0 million compared to cash provided by our investing activities of $1.2 million for the six months ended June 30, 2017.

For the six months ended June 30, 2018, our predecessor paid $6.0 million for investing activities, which was primarily due to a $5.6 million acquisition of oil and natural gas properties, $1.5 million in capital workovers and a $0.2 million purchase of equipment, partially offset by $1.4 million in divestitures of oil and natural gas properties.

For the six months ended June 30, 2017, our predecessor received $1.2 million from investing activities, which was primarily due to $3.8 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 $1.4 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 provided by financing activities was $5.5 million for the six months ended June 30, 2018 as compared to cash used in financing activities of $5.8 million for the six months ended June 30, 2017. During the six months ended June 30, 2018, our predecessor borrowed $7.5 million of long-term debt, repaid $1.4 million of long-term debt and paid $0.6 million of tax distributions to partners. Our predecessor borrowed $7.0 million of long-term debt and repaid $1.2 million of long-term debt during the six months ended June 30, 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 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 six months ended June 30, 2018, our predecessor spent $1.5 million on capital workovers and equipment. During the six months ended June 30, 2017, our predecessor spent $1.4 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 the 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 approximately $50.0 million of our predecessor’s indebtedness in connection with the formation transactions, which will be fully repaid using the proceeds from the offering.

New Revolving Credit Agreement

Remora Holdings will enter into a new $175.0 million revolving credit facility, which at the closing of this offering will be secured by substantially all of Remora Holdings’ assets and the assets of Remora Holdings’ subsidiaries. Under the secured revolving credit facility, availability under the facility will equal the least of the aggregate maximum commitments of the lenders, the aggregate elected commitments of the lenders, and the borrowing base. The borrowing base will be determined by the administrative agent and the lenders based on (among other things) the value of Remora Holdings’ oil and natural gas properties and the oil and natural gas properties of Remora Holdings’ wholly owned subsidiaries. The borrowing base will be redetermined on a semi-annual basis in each year and be subject to interim adjustments at Remora Holdings’ election or at the election of the administrative agent or the lenders. The borrowing base will be subject to provisions requiring borrowing base decreases upon certain dispositions of Remora Holdings’ and its subsidiaries’ oil and natural gas properties and upon certain incurrences of permitted unsecured indebtedness. Remora Holdings’ initial borrowing base will be $95.0 million. The aggregate elected commitment amount is chosen by Remora Holdings from time to time, but such amount will be subject to provisions requiring lockstep decreases of the aggregate elected commitment amount should the borrowing base fall below the aggregate elected commitment amount. The initial aggregate elected commitment amount will be $65.0 million. The secured revolving credit facility permits aggregate elected commitment amounts under the facility to be increased up to the borrowing base then in effect, 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 Remora Holdings’ ability to, among other things, incur or guarantee additional debt, declare or make distributions, 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 Remora Holdings and its subsidiaries to maintain the following financial ratios or to reduce indebtedness if Remora Holdings and its subsidiaries are unable to comply with such ratios: (i) a consolidated Funded Debt to adjusted consolidated EBITDAX Ratio (as more fully defined in the secured revolving credit facility) of not more than 3.50 to 1.00; and (ii) a ratio of consolidated current assets to consolidated current liabilities of not less than 1.00 to 1.00. 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.

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Remora Holdings expects to borrow approximately $10.0 million at the closing of this offering to fund certain offering expenses and repay a portion of our Operating Affiliate’s indebtedness that we will assume in connection with the formation transactions. See “Use of Proceeds” for more information.

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.

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

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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 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

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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.”

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.

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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.

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

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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.

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

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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.

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 June 30, 2018.

Off-Balance Sheet Arrangements

As of June 30, 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

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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 six months ended June 30, 2018, one purchaser accounted for approximately 12% 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 June 30, 2018, our predecessor had total borrowings outstanding under the Predecessor Credit Agreement and Predecessor Term Loan of $55.5 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 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

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approximately 123,000 net acres (97% held by production). For the year ended December 31, 2017, and on a pro forma basis giving effect to the contribution of working interests from the Contributing Parties to our Operating Affiliate, 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 27% from oil sales, 60% from natural gas sales and 13% 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.

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

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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 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

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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.

Production

(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

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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)

(2)

(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)

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.

•

South Texas/Gulf Coast. Our South Texas/Gulf Coast interests are diversified across 222 gross wells located in 19 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.

•

Our Relationship with our Operating Affiliate

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

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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.

Business Strategies

•

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

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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.

•

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:

•

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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 $175.0 million secured revolving credit facility in connection with the closing of this offering. We expect to have a borrowing base under our secured revolving credit facility of $95.0 million and an initial aggregate elected commitment amount of $65.0 million, with approximately $10.0 million of borrowings outstanding at the closing of this offering.

•

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)		97,988
Estimated proved undeveloped reserves:
Oil (MBbls)		107
Natural gas (MMcf)		7,014
Natural gas liquids (MBbls)		362
Total (MMcfe)(6:1)(2)		9,826
Estimated proved reserves:
Oil (MBbls)		2,206
Natural gas (MMcf)		83,819
Natural gas liquids (MBbls)		1,793
Total (MMcfe)(6:1)(2)		107,815
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)		23,274
Estimated probable reserves:
Oil (MBbls)		466
Natural gas (MMcf)		21,604
Natural gas liquids (MBbls)		1,065
Total (MMcfe)(6:1)(2)		30,788

(1)

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(2)

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)

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.
	Six Months Ended June 30, 2018		Year Ended December 31, 2017		Six Months Ended June 30,				Year Ended December 31,
	Six Months Ended June 30, 2018		Year Ended December 31, 2017		2018		2017		2017		2016
Production Data:
Oil and condensate (Bbls)		72,580		172,233		102,299		110,904		200,814		146,320
Natural gas (Mcf)		3,063,683		6,934,830		4,112,951		3,714,214		6,747,492		2,437,883
Natural gas liquids (Bbls)		62,102		226,043		137,885		289,621		404,393		78,485
Total (Mcfe)(6:1)(2)		3,871,772		9,324,483		5,554,055		6,117,364		10,378,734		3,786,713
Average daily production (Mcfe/d)(6:1)(2)		21,391		25,547		30,685		33,798		28,435		10,346
Total (Mcfe) (20:1)(2)		5,757,313		14,900,342		8,916,631		11,724,714		18,851,632		6,933,983
Average daily production (Mcfe/d)(20:1)(2)		31,808		40,823		49,263		64,777		51,648		18,945
Average Realized Prices:
Oil and condensate (per Bbl)	$	63.37	$	47.74	$	63.49	$	47.16	$	47.16	$	39.47
Natural gas (per Mcf)	$	2.40	$	2.71	$	2.47	$	2.80	$	2.81	$	2.26
Natural gas liquids (per Bbl)	$	24.38	$	18.23	$	24.38	$	17.47	$	17.64	$	14.17
Average Unit Cost per Mcfe (6:1)
Production and ad valorem taxes	$	0.24	$	0.23	$	0.21	$	0.14	$	0.15	$	0.11
Marketing and transportation expense	$	0.00	$	0.00	$	0.50	$	0.46	$	0.52	$	0.31
Lease operating expense	$	0.00	$	0.00	$	1.11	$	0.95	$	1.02	$	1.51
Workover expense	$	0.00	$	0.00	$	0.14	$	0.34	$	0.25	$	0.23

(1)

(2)

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(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 (274 net) productive wells, which consisted of 788 gross (97 net) oil wells and 3,610 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.

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

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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 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

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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 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

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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 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.

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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 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.

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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 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.

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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 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.

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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:

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the location of wells;

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the method of drilling and casing wells;

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the timing of construction or drilling activities, including seasonal wildlife closures;

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the rates of production or “allowables”;

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the surface use and restoration of properties upon which wells are drilled;

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the plugging and abandoning of wells; and

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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.

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.”

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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.

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.

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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 22 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, Building II 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

Remora Royalties, Inc. S-1/A