Index to Financial Statements


Matthew R. Pacey, P.C. Eric M. Willis Kirkland & Ellis LLP 600 Travis Street, Suite 3300 Houston, Texas 77002 Tel: (713) 835-3600 Fax: (713) 835-3601		Joshua Davidson Hillary H. Holmes Baker Botts L.L.P. One Shell Plaza 910 Louisiana Street Houston, Texas 77002 Tel: (713) 229-1234 Fax: (713) 229-1522

Approximate date of commencement of proposed sale to the public:

As soon as practicable after this registration statement becomes effective.

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

If this Form is a post-effective amendment filed pursuant to Rule 462(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” and “smaller reporting company” in Rule 12b-2 of the Exchange 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 which specifically states that this registration statement shall thereafter become effective in accordance with Section 8(a) of the Securities Act of 1933 or until the 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. We may not sell these securities until the registration statement filed with the Securities and Exchange Commission is effective. The prospectus is not an offer to sell these securities nor a solicitation of an offer to buy these securities in any jurisdiction where the offer and sale is not permitted.

Subject to Completion, dated July 14, 2015

PROSPECTUS

LOGO

Common Units

Representing Limited Partner Interests

This is the initial public offering of our common units representing limited partner interests. We are offering common units. Prior to this offering, there has been no public market for our common units. We currently expect the initial public offering price to be between $ and $ per common unit. We intend to apply to list our common units on the New York Stock Exchange under the symbol “ORRI.”

Investing in our common units involves risks. Please read “Risk Factors” beginning on page 21.

These risks include the following:

•

We may not have sufficient available cash to pay any quarterly distribution on our common units.

•

All of our revenues are derived from royalty payments that are based on the price at which oil, natural gas and natural gas liquids produced from the underlying acreage is sold, and we do not currently hedge these commodity prices. The volatility of these prices due to factors beyond our control greatly affects our financial condition, results of operations and cash available for distribution.

•

We depend on two third party operators for substantially all of the exploration and production on the properties underlying our ORRIs. Substantially all of our revenue is derived from royalty payments made by these operators. Therefore, any reduction in production from the wells drilled on our acreage by these operators or the failure of our operators to adequately and efficiently develop and operate our acreage could have a material adverse effect on our revenues and cash available for distribution. None of the operators of the properties underlying our ORRIs are contractually obligated to undertake any development activities, so any development and production activities will be subject to their discretion.

•

Our Sponsor owns and controls our general partner, which has sole responsibility for conducting our business and managing our operations. Our general partner and its affiliates, including our Sponsor, have conflicts of interest with us and limited duties, and they may favor their own interests to the detriment of us and our unitholders.

•

We will not have any employees, and we will rely solely on the employees of our general partner to manage our business. The management team of Riverbend, which includes the individuals who will manage us, will also perform similar services for our Sponsor and other industry partners, and thus will not be solely focused on our business.

•

Holders of our common units have limited voting rights and are not entitled to elect our general partner or its directors.

•

Unitholders will incur immediate and substantial dilution in net tangible book value per common unit.

•

Our tax treatment depends on our status as a partnership for federal income tax purposes, as well as our not being subject to a material amount of entity-level taxation by individual states. If the Internal Revenue Service were to treat us as a corporation for federal income tax purposes or we were to become subject to entity-level taxation for state tax purposes, then our cash available for distribution to you could be substantially reduced.

•

Even if you do not receive any cash distributions from us, you will be required to pay taxes on your share of our taxable income.

In addition, we qualify as an “emerging growth company” as defined in Section 2(a)(19) of the Securities Act of 1933 and, as such, are allowed to provide in this prospectus more limited disclosures than an issuer that would not so qualify. Furthermore, for so long as we remain an emerging growth company, we will qualify for certain limited exceptions from investor protection laws such as the Sarbanes-Oxley Act of 2002 and the Investor Protection and Securities Reform Act of 2010. Please read “Summary—Emerging Growth Company Status.”


	Per Common Unit	Total
Public Offering Price	$	$
Underwriting Discount(1)	$	$
Proceeds to Royal Resources Partners LP (before expenses)	$	$

(1)	See “Underwriting.”

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

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

The underwriters expect to deliver the common units to purchasers on or about , 2015 through the book-entry facilities of The Depository Trust Company.


Credit Suisse	Citigroup	Morgan Stanley

Wells Fargo Securities	Barclays	BofA Merrill Lynch

Prospectus dated , 2015

LOGO

TABLE OF CONTENTS


SUMMARY			1
RISK FACTORS			21
USE OF PROCEEDS			54
CAPITALIZATION			55
DILUTION			56
CASH DISTRIBUTION POLICY AND RESTRICTIONS ON DISTRIBUTIONS			57
HOW WE MAKE DISTRIBUTIONS			70
SELECTED HISTORICAL FINANCIAL DATA			83
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS			85
BUSINESS			96
MANAGEMENT			115
EXECUTIVE COMPENSATION AND OTHER INFORMATION			118
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT			123
CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS			124
CONFLICTS OF INTEREST AND FIDUCIARY DUTIES			127
DESCRIPTION OF OUR COMMON UNITS			135
THE PARTNERSHIP AGREEMENT			137
UNITS ELIGIBLE FOR FUTURE SALE			151
MATERIAL U.S. FEDERAL INCOME TAX CONSEQUENCES			153
INVESTMENT IN ROYAL RESOURCES PARTNERS LP BY EMPLOYEE BENEFIT PLANS			168
UNDERWRITING			169
LEGAL MATTERS			173
EXPERTS			173
WHERE YOU CAN FIND MORE INFORMATION			173
FORWARD-LOOKING STATEMENTS			174
INDEX TO FINANCIAL STATEMENTS			F-1
FORM OF FIRST AMENDED AND RESTATED AGREEMENT OF LIMITED PARTNERSHIP OF ROYAL RESOURCES PARTNERS LP			A-1
GLOSSARY OF TERMS			B-1

You should rely only on the information contained in this prospectus, any free writing prospectus prepared by or on behalf of us or any other information to which we have referred you in connection with this offering. We have not, and the underwriters have not, authorized any other person to provide you with information different from that contained in this prospectus. Neither the delivery of this prospectus nor sale of our common units means that information contained in this prospectus is correct after the date of this prospectus. This prospectus is not an offer to sell or solicitation of an offer to buy our common units in any circumstances under which the offer or solicitation is unlawful.

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 our operators, 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.

(i)

CERTAIN TERMS USED IN THIS PROSPECTUS

All references in this prospectus to:

•

“DGK,” “our predecessor,” “we,” “our,” “us” or like terms when used in a historical context refer to DGK ORRI Company, L.P., which Royal Resources L.P. is contributing to Royal Resources Partners LP in connection with this offering and which has historically owned all of our assets;

•

“we,” “our,” “us,” “our partnership” or like terms used in the present tense or prospectively refer to Royal Resources Partners LP and its subsidiaries;

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“Holdings” refer to DGK ORRI Holdings, LP, the historical parent of DGK;

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“Royal” or “our Sponsor” refer to Royal Resources L.P. and its subsidiaries other than Royal Resources Partners LP and its subsidiaries, except where expressly noted otherwise;

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“our general partner” refer to Royal Resources Partners GP, LLC, a wholly owned subsidiary of Royal Resources L.P.;

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“Riverbend” refer to Riverbend Oil & Gas, L.L.C., which owns a portion of Royal through an affiliate and whose employees have historically managed DGK’s and our business;

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“Blackstone” refer to The Blackstone Group, L.P., Blackstone Energy Partners L.P. and Blackstone Capital Partners VI L.P., and their respective affiliates, which own a portion of and control Royal; and

•

“our executive officers” and “our directors” refer to the executive officers and directors of our general partner, respectively.

(ii)

SUMMARY

This summary highlights information contained elsewhere in this prospectus. This summary does not contain all of the information that you should consider before investing in our common units. You should read the entire prospectus carefully, including the historical financial statements and the notes to those financial statements, before investing in our common units. The information presented in this prospectus assumes an initial public offering price of $ per common unit (the mid-point of the price range set forth on the cover page of this prospectus), and unless otherwise indicated, that the underwriters’ option to purchase additional common units is not exercised. You should read “Risk Factors” for information about important risks that you should consider before buying our common units.

We include a glossary of some of the industry terms used in this prospectus as Appendix B.

Royal Resources Partners LP

Overview

We are a Delaware limited partnership formed by our Sponsor to own and acquire overriding royalty interests, or ORRIs, and mineral and royalty interests in oil and natural gas properties in North America. These types of interests entitle the holder to a portion of the production of oil and natural gas from the underlying acreage at the sales price received by the operator, net of post-production expenses and taxes. The holder of these interests has no obligation to fund finding and development costs, lease operating expenses or plugging and abandonment costs at the end of a well’s productive life. All of our initial assets consist of ORRIs in properties in the Eagle Ford Shale region in South Texas. Our primary business objective is to provide increasing cash distributions to unitholders resulting from organic growth through the development of the properties underlying our ORRIs by third party operators and from accretive growth opportunities through acquisitions from our Sponsor and from third parties.

As of December 31, 2014, the estimated proved oil, natural gas liquids, and natural gas reserves of our underlying acreage were 19,141 MBOE (75% liquids, consisting of 57% oil and 18% natural gas liquids (“NGLs”)) based on a reserve report prepared by Ryder Scott Company, L.P. (“Ryder Scott”). Of these reserves, 23% were classified as proved developed producing (“PDP”) reserves and 68% were classified as proved undeveloped (“PUD”) reserves. PUD reserves included in this estimate are from 1,347 gross proved undeveloped well locations.

12% from natural gas 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. Oil, natural gas liquids and natural gas prices have historically been volatile, and we do not currently hedge our exposure to changes in commodity prices.

The Eagle Ford Shale is one of the fastest growing and most active unconventional shale trends in North America. According to monthly rig count metrics published by Baker Hughes, the Eagle Ford Shale has consistently been one of the most active US basins since 2012 and has also proven to be the most robust of the liquids-focused basins, experiencing the lowest percentage decline in rig counts in the current low commodity price environment when compared to the Permian and Williston basins. Over 98% of our acreage is located in DeWitt County, one of the most active counties in terms of new wells drilled in the Eagle Ford Shale over the last five years. Our acreage is characterized by high liquids content and low finding and development costs leading to attractive operator economics compared to other unconventional basins. We believe these factors make development of the Eagle Ford Shale commercially viable in lower commodity price environments. Over 99% of our acreage is operated by BHP Billiton Petroleum (“BHP”) and Devon Energy Corporation (“Devon”) through a joint venture, ConocoPhillips Company (“ConocoPhillips”), EOG Resources, Inc. (“EOG”), and Pioneer Natural Resources Company (“Pioneer”). These operators have publicly announced aggregate capital expenditure programs in the Eagle Ford Shale of over $5.0 billion in 2015. As of June 1, 2015, BHP, Devon and ConocoPhillips operate 7 of the 8 rigs on our acreage, comprising 54% of their total rigs in the Eagle Ford Shale.

Upon the completion of this offering, our Sponsor will own and control our general partner, and will own approximately % of our outstanding common units and all of our outstanding subordinated units and incentive distribution rights. Our Sponsor is an independent oil and natural gas company currently focused on the acquisition and ownership of non-operating, non-cost bearing oil and natural gas properties in North America, such as mineral and royalty interests and ORRIs. We believe that the properties held by our Sponsor include acreage that will continue to support future reserve and production growth as operators explore other target zones, and have production and reserves characteristics, as well as significant acreage overlap, that could make them attractive for inclusion in our partnership. In addition, we believe our Sponsor’s significant ownership interest in us will motivate it to offer additional mineral and royalty interests in oil and natural gas properties to us in the future, although our Sponsor has no obligation to do so and may elect to dispose of interests without offering us the opportunity to acquire such interests. Please read “—Our Relationship with Royal and Others.”

Our Properties

Our initial assets consist of ORRIs related to 69,974 net leasehold acres, associated with 245 drilling units, in what we believe is the “core of the core” of the Eagle Ford Shale. As of March 31, 2015, these interests entitle us to receive an average royalty of 1.20% from the producing wells on the acreage underlying our ORRIs, with no additional future capital or operating expenses required. As of March 31, 2015, there were 770 horizontal wells producing on this acreage, and net production was approximately 4,381 BOE/d during the month of February 2015. In addition, there were 188 horizontal wells in various stages of completion. As of June 1, 2015, there were 114 permits outstanding for undrilled wells or wells currently being drilled on the acreage underlying our ORRIs. For the three months ended March 31, 2015, revenue generated from these ORRIs was $13.5 million.

The following table includes our operating metrics as of December 31, 2014, unless otherwise indicated.


	Net Leasehold Acres to Which Royalty Applies		Average Royalty Interest per PDP Well(1)			Average Daily Production(2)								Total Proved Reserves (MBOE)		%Reserves			Proved Undeveloped Locations		Rigs Operating On Our Acreage(1)
Operator/Developer	Net Leasehold Acres to Which Royalty Applies		Average Royalty Interest per PDP Well(1)			Oil (Bbls/d)		Natural Gas (Mcf/d)		Natural Gas Liquids (Bbls/d)		Combined Volumes (BOE/d)		Total Proved Reserves (MBOE)		%Reserves			Proved Undeveloped Locations		Rigs Operating On Our Acreage(1)
Devon/BHP		60,970		1.40	%		2,329		4,584		768		3,862		15,798		83	%		822		5
ConocoPhillips		7,500		0.59	%		201		436		72		346		2,933		15	%		475		2
EOG, Pioneer & Other		1,504		0.56	%		79		319		41		173		410		2	%		50		1

Total		69,974		1.20	%		2,609		5,339		881		4,381		19,141		100	%		1,347		8

(1)	As of June 1, 2015.

(2)	Average daily production for the month of February 2015.

The leases underlying our ORRIs are delineated by 770 producing horizontal wells as of March 31, 2015, all of which have been drilled over the past five years. The leases on these properties are 100% held by production and will generally only expire upon termination of production.

The gross estimated ultimate recoveries (“EURs”) from the future PUD horizontal wells included in our reserve report on 40-acre spacing, as estimated by Ryder Scott as of December 31, 2014, range from 316 MBOE per well (consisting of 155 MBbls of oil, 658 MMcf of natural gas and 50 MBbls of natural gas liquids) to 1,829 MBOE per well (consisting of 868 MBbls of oil, 3,774 MMcf of natural gas and 331 MBbls of natural gas liquids) with an average EUR per well of 952 MBOE (consisting of 476 MBbls of oil, 1,889 MMcf of natural gas and 162 MBbls of natural gas liquids).

The following chart shows the number of producing wells on the acreage underlying our ORRIs for each quarter since the acquisition of the ORRIs by our Sponsor in March 2012.

Producing Wells By Quarter

LOGO

Our Relationship with Royal and Others

Royal. Upon the completion of this offering, our Sponsor will own and control our general partner and will own approximately % of our outstanding common units and all of our outstanding subordinated units and incentive distribution rights. We believe our Sponsor’s significant ownership interest in us will motivate it to offer additional ORRIs and other mineral and royalty interests to us in the future, although our Sponsor has no obligation to do so and may elect to dispose of interests without offering us the opportunity to acquire such interests.

Following the completion of this offering, our Sponsor will continue to own oil and gas interests in the Eagle Ford Shale region consisting solely of ORRIs and mineral and royalty interests (the “Retained Assets”). As of March 31, 2015, the Retained Assets relate to 77,403 net leasehold acres (many of which overlap with acreage underlying our ORRIs), with an average royalty of 1.11% from the producing wells on this acreage. As of December 31, 2014, our Sponsor had estimated proved oil, natural gas liquids and natural gas reserves of 23,727 MBOE attributable to the Retained Assets. Of these reserves, 20% were classified as PDP reserves and 52% were oil, 19% were natural gas liquids and 29% were natural gas. PUD reserves included in this estimate are from 1,623 gross horizontal well locations.

The following table shows a comparison of the assets that we will hold at the completion of this offering to the assets that will be retained by our Sponsor, as of December 31, 2014 unless otherwise indicated.


	Our initial assets		Sponsor retained assets
Average daily production (BOE/d)(1)		4,381		5,505
Total proved reserves (MBOE)		19,141		29,810
PDP reserves (MBOE)		4,440		5,862
PUD reserves (MBOE)		12,957		22,681

(1)	Average daily production for the month of February 2015.

The following map shows the location of 323 drilling units in the Eagle Ford Shale in which we and our Sponsor own interests. We own interests in 245 drilling units in the Eagle Ford Shale. Our Sponsor’s Retained Assets include interests in 317 drilling units in the Eagle Ford Shale, of which 239 overlap with drilling units in which we own interests.

LOGO

We believe that the Retained Assets held by our Sponsor include acreage that will continue to support future reserve and production growth as operators explore other target zones, and have, or with additional development by third party operators will have, production and reserves characteristics that are similar to our properties, which could make them attractive for inclusion in our partnership. Furthermore, we believe our Sponsor will provide us with opportunities to pursue acquisitions that will be accretive to our unitholders. However, our Sponsor may elect to acquire properties without offering us the opportunity to participate in such transactions and our Sponsor’s pursuit of such acquisitions may be in competition with us. Moreover, our Sponsor may not be successful in identifying potential acquisitions. After this offering, our Sponsor will continue to be free to act in a manner that is beneficial to its interests without regard to ours, which may include electing not to present us with acquisition or disposition opportunities. Please read “Conflicts of Interest and Fiduciary Duties.”

Riverbend. Riverbend is an owner-managed firm formed in 2003 focused on the acquisition of minerals and royalty interests, ORRIs and non-operated working interests. Riverbend’s historic co-investment equity partners have included Blackstone and other industry partners. Riverbend has completed numerous acquisitions and divestments, drilling arrangements and equity investments. Riverbend’s team, currently comprised of 21 employees, has extensive energy experience in the exploration and production sector and encompasses all disciplines (finance, engineering, accounting and land), which are all housed and managed internally.

Since December 2013, an affiliate of Riverbend has owned an equity interest in our Sponsor, and Riverbend provides management and advisory services to our Sponsor pursuant to a management services agreement. Following the closing of this offering, neither we nor our subsidiaries will have any employees, and we will be managed by employees of our general partner, some of which are also employees of Riverbend. Please read “Management” and “Certain Relationships and Related Party Transactions.”

Blackstone. Royal and our general partner are controlled by affiliates of Blackstone, one of the world’s leading investment and advisory firms. Blackstone’s alternative asset management businesses include the management of corporate private equity funds, real estate funds, hedge fund solutions, credit-oriented funds and closed-end mutual funds. Blackstone also provides various financial advisory services, including financial and strategic advisory, restructuring and reorganization advisory and fund placement services. Through its different investment businesses, as of March 31, 2015, Blackstone had assets under management over $310 billion. Blackstone has committed and invested over $8.7 billion in more than 21 energy transactions throughout the energy value chain on a global basis, primarily through Blackstone Energy Partners L.P., a $2.5 billion fund that invests globally in energy opportunities, and Blackstone Capital Partners VI L.P., a $16.2 billion fund that invests alongside Blackstone Energy Partners L.P. in energy and natural resource transactions. Investments in oil and natural gas assets represent a substantial portion of this activity and include leading independent onshore and offshore exploration and production companies in North America and globally.

Business Strategies

Our primary business objective is to provide an attractive return to unitholders by focusing on business results and total distributions and pursuing accretive growth opportunities through acquisitions from our Sponsor and from third parties. We intend to accomplish this objective by executing the following strategies:

•

Benefit from reserve, production and cash flow growth from organic development of our acreage. We are a beneficiary of the continued organic development by our operators of the acreage underlying our ORRIs. As of December 31, 2014, 68% of the proved reserves attributable to our ORRIs were characterized as PUD reserves, which provides for significant development opportunities for our operators. We believe that our operators will continue to rapidly develop this acreage due to its strategic location in what we believe is the “core of the core” of the Eagle Ford Shale, the relatively low-risk, delineated nature of its reserves, and attractive operator economics. As a holder of ORRIs, we have no responsibility for finding and development costs, lease operating expenses or plugging and abandonment at the end of a well’s productive life. As such, we benefit from this continued development cost-free to us, which we believe will enable us to grow our distributions over time.

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Seek to acquire additional interests in oil and gas properties from our Sponsor. Following the completion of this offering, our Sponsor will continue to own significant mineral and royalty interests and ORRIs in the Eagle Ford Shale and may acquire additional assets in the future. As of March 31, 2015 and after giving effect to this offering, our Sponsor retained additional ORRIs covering 77,403 net leasehold acres in the Eagle Ford Shale. Many of our Sponsor’s retained interests are in acreage in which we currently own an interest. We believe our Sponsor may be incentivized to sell additional interests in oil and gas properties to us, as doing so may enhance our Sponsor’s economic returns by monetizing properties while potentially retaining a portion of the resulting cash flow through its ownership of the incentive distribution rights, all of the subordinated units and common units, representing a % limited partner interest in us. However, neither our Sponsor nor any of its affiliates are contractually obligated to offer or sell any properties to us.

•

Pursue accretive third party acquisitions and leverage our relationships with our Sponsor, Riverbend and Blackstone. We intend to expand our portfolio of interests in oil and gas properties by pursuing acquisitions that are accretive to distributable cash flow. We intend to actively pursue strategic acquisitions of mineral and royalty interests and ORRIs in basins that have substantial organic growth potential. Our criteria for acquisitions will include similar characteristics to our existing assets, such as high rates of return, well-capitalized operators, existing production and the potential for organic production growth. In addition, through our relationships with our Sponsor, Riverbend and Blackstone, we have access to their significant pool of management talent and industry relationships, which we believe provide us with a competitive advantage in pursuing potential third party acquisition opportunities. We may have additional opportunities to work jointly with our Sponsor to pursue certain acquisitions of oil and natural gas properties that may not otherwise be attractive acquisition candidates for either of us individually. We believe this arrangement may give us access to third party acquisition opportunities that we would not otherwise be in a position to pursue.

•

Maintain a conservative capital structure and prudently manage the business for the long term. We intend to maintain a conservative capital structure to allow us the financial flexibility to execute our business strategies over the long term, including the ability to pursue strategic acquisitions. Following the completion of this offering, we will have $ million of available liquidity under our undrawn revolving credit facility and no outstanding indebtedness. We believe that this liquidity, together with cash flow from operations and access to the public debt and equity markets, will provide us with financial flexibility to execute on strategic acquisitions and to contribute to production and cash flow growth over time.

Competitive Strengths

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

•

specifically identified locations, which have been reviewed and confirmed by Ryder Scott in connection with the preparation of the reserve report as of December 31, 2014. For additional information regarding our drilling locations, please read “Business – Oil and Natural Gas Data – Identification of Drilling Locations.” As of June 1, 2015, our operators had obtained 106 permits for undeveloped locations on our acreage and were running an aggregate of 8 rigs on our acreage. We believe this extensive inventory of undeveloped acreage will contribute to strong organic growth.

•

High-quality operators with active development programs. Over 99% of our acreage is operated by BHP and Devon through a joint venture, ConocoPhillips, EOG and Pioneer. These operators have publicly announced aggregate capital expenditure programs in the Eagle Ford Shale of over $5.0 billion in 2015. As of June 1, 2015, BHP, Devon and ConocoPhillips operate 7 of the 8 rigs on our acreage, comprising 54% of their aggregate rigs in the Eagle Ford Shale. These operators are characterized by investment grade credit profiles as of March 31, 2015. We believe our operators will continue to develop our acreage in lower commodity price environments because of its high margin economics and public statements from our operators that the Eagle Ford Shale continues to be a top priority.

•

Significant opportunity for our operators to increase production through down spacing and development of other zones. All of our current proved reserves are attributable to the lower Eagle Ford Shale and assume 40-acre spacing. Several of our operators are currently down spacing their development programs, using staggered development that could yield additional down spacing to 20-acre spacing. Based on our analysis, we believe that there is little degradation of well performance caused by this spacing. In addition, several of our operators are testing our acreage for other target zones, such as the Upper Eagle Ford and Austin Chalk. We believe this down spacing and drilling in additional zones could increase reserves, well locations and production beyond our reserve report.

•

Experienced and proven management team. Our management team has an average of over years of industry experience, most of which were focused on managing and acquiring non-operated oil and gas interests. This team has a proven track record of executing and integrating on property acquisitions. We believe this experience is essential for us to grow from our initial property base.

Management

We are managed and operated by the board of directors and executive officers of our general partner, Royal Resources Partners GP, LLC, a wholly owned subsidiary of our Sponsor. As a result of owning our general partner, our Sponsor will have the right to appoint all members of the board of directors of our general partner, including at least three directors meeting the independence standards established by the New York Stock Exchange (the “NYSE”). At least one of our independent directors will be appointed by the time our common units are first listed for trading on the NYSE. Our unitholders will not be entitled to elect our general partner or its directors or otherwise directly participate in our management or operations. In addition, neither we nor our subsidiaries will have any employees. The executive officers and some of the directors of our general partner currently serve as executive officers and directors of our Sponsor. Please read “Management” and “Certain Relationships and Related Party Transactions.”

Conflicts of Interest and Fiduciary Duties

Although our relationship with our Sponsor may provide significant benefits to us, it may also become a source of potential conflicts. For example, our Sponsor and its affiliates, including Riverbend and Blackstone, are not restricted from competing with us. In addition, the executive officers and certain of the directors of our general partner also serve as officers or directors of our Sponsor, and these officers and directors face conflicts of interest, including conflicts of interest regarding the allocation of their time between us and our Sponsor.

Our general partner has a contractual duty to manage us in a manner that it believes is not adverse to our interest. However, the executive officers and directors of our general partner have fiduciary duties to manage our general partner in a manner beneficial to our Sponsor, the owner of our general partner. Our Sponsor and its affiliates are not prohibited from engaging in other business activities, including those that might be in direct competition with us. In addition, our Sponsor may compete with us for investment opportunities and may own an interest in entities that compete with us. As a result, conflicts of interest may arise in the future between us or our unitholders, on the one hand, and our Sponsor and our general partner, on the other hand.

Our partnership agreement limits the liability of and replaces the fiduciary duties owed by our general partner to our unitholders. Our partnership agreement also restricts the remedies available to our unitholders for actions that might otherwise constitute a breach of duties by our general partner or its directors or executive officers. Our partnership agreement also provides that affiliates of our general partner, including our Sponsor, are not restricted in competing with us and have no obligation to present business opportunities to us. By purchasing a common unit, the purchaser agrees to be bound by the terms of our partnership agreement, and each unitholder is treated as having consented to various actions and potential conflicts of interest contemplated in the partnership agreement that might otherwise be considered a breach of fiduciary or other duties under Delaware law.

For a more detailed description of the conflicts of interest and duties of our general partner and its directors and executive officers, please read “Conflicts of Interest and Fiduciary Duties.” For a description of other relationships with our affiliates, please read “Certain Relationships and Related Party Transactions.”

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 applicable generally to other public companies. These exemptions include:

•

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

•

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

•

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

•

reduced disclosure of executive compensation.

In addition, Section 107 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 (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.

However, we are choosing to “opt out” of such extended transition period and, as a result, we will comply with new or revised accounting standards on the relevant dates on which adoption of such standards is required for non-emerging growth companies. Our decision to opt out of the extended transition period for complying with new or revised accounting standards is irrevocable.

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 $1.0 billion or more in annual revenues, (ii) the first day of the first fiscal year after we have more than $700 million in outstanding common equity held by non-affiliates and have been public for at least 12 months (the value of our outstanding common equity will be measured each year on the last day of our second fiscal quarter), (iii) the date on which we have issued more than $1.0 billion of non-convertible debt over a three-year period or (iv) the last day of the first fiscal year following the fifth anniversary of our initial public offering.

Formation Transactions and Structure

At or prior to the closing of this offering, the following transactions will occur:

•

Holdings will contribute its 100% ownership interest in DGK to us;

•

we will issue common units and subordinated units, representing an aggregate % limited partner interest in us, to Holdings, and incentive distribution rights (“IDRs”) directly to our Sponsor;

•

our general partner will maintain its non-economic general partner interest;

•

we will issue and sell common units to the public in this offering, representing a % limited partner interest in us;

•

we will pay the related underwriting discounts and offering expenses and use the net proceeds from this offering in the manner described under “Use of Proceeds”; and

•

we will enter into a new $ million revolving credit facility, as described in “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Revolving Credit Facility,” which will be undrawn at the closing of this offering.

We refer to these transactions collectively as the “formation transactions.”

The number of common units to be issued to our Sponsor includes common units that will be issued at the expiration of the underwriters’ option to purchase additional common units, assuming that the underwriters do not exercise the option. Any exercise of the underwriters’ option to purchase additional common units would reduce the common units shown as issued to our Sponsor by the number to be purchased by the underwriters in connection with such exercise. If and to the extent the underwriters exercise their option to purchase additional common units, the number of common units purchased by the underwriters pursuant to any exercise will be sold to the public, and any remaining common units not purchased by the underwriters pursuant to any exercise of the option will be issued to our Sponsor at the expiration of the option period for no additional consideration. We will use any net proceeds from the exercise of the underwriters’ option to purchase additional common units from us to make an additional cash distribution to our Sponsor.

The following chart illustrates our organizational structure after giving effect to this offering and the other formation transactions described above:

LOGO


Public Common Units		%
Interests of Royal:
Common Units		%(1)
Subordinated Units	100	%
Non-Economic General Partner Interest	0.0	%(2)
Incentive Distribution Rights	—	(3)

	100.0	%

(1)	Assumes the underwriters do not exercise their option to purchase additional common units and such additional common units are issued to Royal.

(2)	Our general partner owns a non-economic general partner interest in us. Please read “How We Make Distributions—General Partner Interest.”

(3)

Incentive distribution rights represent a variable interest in distributions and thus are not expressed as a fixed percentage. Please read “How We Make Distributions—Incentive Distribution Rights.” Distributions with respect to the incentive distribution rights will be classified as distributions with respect to equity interests. Incentive distribution rights will be issued to Royal.

Principal Executive Offices

Our principal executive offices are located at One Allen Center, 500 Dallas Street, Suite 1250, Houston, Texas 77002, and our telephone number is (713) 874-9000. Our website address will be www. .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 or any other website is not incorporated by reference into this prospectus and does not constitute a part of this prospectus.

Risk Factors

An investment in our common units involves risks. You should carefully consider the risks described in “Risk Factors” and the other information in this prospectus, before deciding whether to invest in our common units. If any of these risks were to occur, our financial condition, results of operations, cash flows, and ability to make distributions to our unitholders would be adversely affected, and you could lose all or part of your investment.

The Offering

Common units offered to the public

common units ( common units if the underwriters exercise in full their option to purchase additional common units from us).

Options to purchase additional units

We have granted the underwriters a 30-day option to purchase up to an additional common units.

Units outstanding after this offering

common units and subordinated units. If and to the extent the underwriters do not exercise their option to purchase additional common units, in whole or in part, we will issue up to an additional common units to our Sponsor at the expiration of the option for no additional consideration. If and to the extent the underwriters exercise their option to purchase additional common units, the number of common units purchased by the underwriters pursuant to any exercise will be sold to the public, and any remaining common units not purchased by the underwriters pursuant to any exercise of the option will be issued to our Sponsor at the expiration of the option period for no additional consideration. Accordingly, the exercise of the underwriters’ option will not affect the total number of common units outstanding or the amount of cash needed to pay the minimum quarterly distribution on all units.

Use of proceeds

We intend to use the estimated net proceeds of approximately $ million from this offering (based on an assumed initial offering price of $ per common unit), after deducting the estimated underwriting discounts and offering expenses payable by us, to repay our existing indebtedness and make a distribution to our Sponsor.

The net proceeds from any exercise of the underwriters’ option to purchase up to an additional common units (approximately $ million based on an assumed initial offering price of $ per common unit, if exercised in full) will be used to make a distribution to our Sponsor. Please read “Use of Proceeds.”

Cash distributions

Within 60 days after the end of each quarter, we expect to make a cash distribution to holders of our common units and subordinated units. We expect to make a minimum quarterly distribution of $ per common unit and subordinated unit ($ per common unit and subordinated unit on an annualized basis) to the extent we have sufficient cash after the establishment of cash reserves and the payment of fees and expenses, including payments to our general partner and its affiliates. For the first quarter that we are publicly traded, we will pay a prorated distribution covering the period after the consummation of this offering through , 2015, based on the actual length of that period.

The board of directors of our general partner will adopt a policy pursuant to which distributions for each quarter will be paid to the extent we have

sufficient cash after establishment of cash reserves and payment of fees and expenses, including payments to our general partner and its affiliates. However, the board of directors of our general partner may change such policy at any time at its discretion, without unitholder approval, and could elect not to pay distributions for one or more quarters. Our ability to pay the minimum quarterly distribution is subject to various restrictions and other factors described in more detail in “Cash Distribution Policy and Restrictions on Distributions.”

Our partnership agreement generally provides that we will distribute cash each quarter during the subordination period in the following manner:

•

first, to the holders of common units, until each common unit has received the minimum quarterly distribution of $ plus any arrearages from prior quarters;

•

second, to the holders of subordinated units, until each subordinated unit has received the minimum quarterly distribution of $ ; and

•

third, to the holders of common units and subordinated units, pro rata, until each has received a distribution of $ .

If cash distributions to our unitholders exceed $ per unit on all common and subordinated units in any quarter, our unitholders and our Sponsor, as the holder of our IDRs, will receive distributions according to the following percentage allocations:


Total Quarterly Distribution Target Amount	Marginal Percentage Interest in Distributions
Total Quarterly Distribution Target Amount	Unitholders			Our Sponsor (as holder of IDRs)
above $ up to $		100	%		0	%
above $ up to $		85	%		15	%
above $		75	%		25	%

We refer to the additional increasing distributions to our general partner as “incentive distributions.” Please read “How We Make Distributions—Incentive Distribution Rights.”

On a pro forma basis, assuming we had completed this offering and the related formation transactions on January 1, 2014, our unaudited pro forma cash available for distribution for the year ended December 31, 2014 and the twelve months ended March 31, 2015 would have been approximately $50.2 million and $48.6 million, respectively. The amount of cash available for distribution we must generate to support the payment of the minimum quarterly distribution for four quarters on our common units and subordinated units to be outstanding immediately after this offering is approximately $ million (or an average of approximately

$ million per quarter). As a result, for the year ended December 31, 2014 and the twelve months ended March 31, 2015, we would have had sufficient cash available for distribution to pay only approximately % and % of the full minimum quarterly distributions on our common units, respectively, and we would not have had sufficient cash available for distribution to pay any of the minimum quarterly distributions on our subordinated units for either period. Please read “Cash Distribution Policy and Restrictions on Distributions—Unaudited Pro Forma Cash Available for Distribution for the Year Ended December 31, 2014 and the Twelve Months Ended March 31, 2015.”

We believe, based on our financial forecast and related assumptions included in “Cash Distribution Policy and Restrictions on Distributions,” that we will have sufficient cash available for distribution to pay the minimum quarterly distribution of $ on all of our common units and subordinated units for the twelve months ending June 30, 2016. However, we do not have a legal or contractual obligation to pay distributions quarterly or on any other basis or at the minimum quarterly distribution rate or at any other rate, and there is no guarantee that we will pay distributions to our unitholders in any quarter. Please read “Cash Distribution Policy and Restrictions on Distributions.”

Subordinated units

Our Sponsor will initially own all of our subordinated units. The principal difference between our common units and subordinated units is that for any quarter during the subordination period, holders of the subordinated units will not be entitled to receive any distribution from operating surplus until the common units have received the minimum quarterly distribution from operating surplus for such quarter plus any arrearages in the payment of the minimum quarterly distribution from prior quarters. Subordinated units will not accrue arrearages.

Conversion of subordinated units

The subordination period will end on the first business day after we have earned and paid an aggregate amount of at least $ (the minimum quarterly distribution on an annualized basis) multiplied by the total number of outstanding common and subordinated units for each of three consecutive, non-overlapping four-quarter periods ending on or after and there are no outstanding arrearages on our common units.

Notwithstanding the foregoing, the subordination period will end on the first business day after we have paid an aggregate amount of at least $ (150% of the minimum quarterly distribution on an annualized basis) multiplied by the total number of outstanding common and subordinated units and we have earned that amount plus the related distribution on the incentive distribution rights, for any four-quarter period ending on or after and there are no outstanding arrearages on our common units.

When the subordination period ends, all subordinated units will convert into common units on a one-for-one basis, and all common units will thereafter no longer be entitled to arrearages.

Royal’s right to reset the target distribution levels

Our Sponsor, as the initial holder of our incentive distribution rights, will have the right, at any time when there are no subordinated units outstanding and we have made distributions at or above 150% of the minimum quarterly distribution for the prior four consecutive whole fiscal quarters and the aggregate amount of the distributions over such four-quarter period does not exceed the amount of adjusted operating surplus generated during such period, to reset the initial target distribution levels at higher levels based on our cash distributions at the time of the exercise of the reset election. If our Sponsor transfers all or a portion of our incentive distribution rights in the future, then the holder or holders of a majority of our incentive distribution rights will be entitled to exercise this right. Following a reset election, the minimum quarterly distribution will be adjusted to equal the distribution for the quarter immediately preceding the reset, and the target distribution levels will be reset to correspondingly higher levels based on the same percentage increases above the reset minimum quarterly distribution as the initial target distribution levels were above the minimum quarterly distribution.

If the target distribution levels are reset, the holders of our incentive distribution rights will be entitled to receive common units. The number of common units to be issued will equal the number of common units that would have entitled the holders of our incentive distribution rights to an aggregate quarterly cash distribution for the quarter prior to the reset election equal to the distribution on the incentive distribution rights for the quarter prior to the reset election. Please read “How We Make Distributions—Incentive Distribution Rights Holder’s Right to Reset Incentive Distribution Levels.”

Issuance of additional units

Our partnership agreement authorizes us to issue an unlimited number of additional units without the approval of our unitholders. Please read “Units Eligible for Future Sale” and “The Partnership Agreement—Issuance of Additional Interests.”

Limited voting rights

Our general partner will manage and operate us. Unlike the holders of common stock in a corporation, our unitholders will have only limited voting rights on matters affecting our business. Our unitholders will have no right to elect our general partner or its directors on an annual or other continuing basis. Our general partner may not be removed except by a vote of the unitholders holding at least 66²⁄₃% of the outstanding units, including any units owned by our general partner and its affiliates, voting together as a single class. Upon the consummation of this offering, our Sponsor will own an aggregate of % of our common units (or % of our common units, if the underwriters exercise their option to purchase additional common units in full). This

will effectively give our Sponsor the ability to prevent the removal of our general partner. In addition, any vote to remove our general partner during the subordination period must provide for the election of a successor general partner by the holders of a majority of the common units and a majority of the subordinated units, voting as separate classes. This will provide our Sponsor the ability to prevent the removal of our general partner. Please read “The Partnership Agreement—Voting Rights.”

Limited call right

If at any time our general partner and its affiliates own more than 80% of the outstanding common units, our general partner will have the right, but not the obligation, to purchase all of the remaining common units at a price equal to the greater of (1) the average of the daily closing price of the common units over the 20 trading days preceding the date three days before notice of exercise of the call right is first mailed and (2) the highest per-unit price paid by our general partner or any of its affiliates for common units during the 90-day period preceding the date such notice is first mailed. Please read “The Partnership Agreement—Limited Call Right.”

Estimated ratio of taxable income to distributions

We estimate that if you own the common units you purchase in this offering through the record date for distributions for the period ending December 31, 2018, you will be allocated, on a cumulative basis, an amount of federal taxable income for that period that will be less than % of the cash expected to be distributed to you with respect to that period. For example, if you receive an annual distribution of $ per unit, we estimate that your average allocable federal taxable income per year will be no more than approximately $ per unit. Thereafter, the ratio of allocable taxable income to cash distributions to you could substantially increase. Please read “Material U.S. Federal Income Tax Consequences—Tax Consequences of Unit Ownership” for the basis of this estimate.

Material federal income tax consequences

For a discussion of the material federal income tax consequences that may be relevant to certain unitholders who are individual citizens or residents of the United States, please read “Material U.S. Federal Income Tax Consequences.”

Exchange listing

We intend to apply to list our common units on the NYSE under the symbol “ORRI.”

Summary Historical Financial Data

Royal Resources Partners LP was formed in November 2014 and does not have historical financial statements. Therefore, in this prospectus we present the consolidated historical financial statements of Holdings, our accounting predecessor. Holdings is the parent of DGK, which is the entity that will be contributed to Royal Resources Partners LP upon the closing of this offering. The following table presents summary consolidated historical financial data of Holdings as of the dates and for the periods indicated. DGK and Holdings were each formed on March 1, 2012 in connection with Holdings’ acquisition of our ORRIs from a third party.

The summary historical financial data of Holdings presented as of and for the years ended December 31, 2014 and 2013 are derived from the audited historical financial statements of Holdings that are included elsewhere in this prospectus. The summary historical financial data presented as of and for the three months ended March 31, 2015 and for the three months ended March 31, 2014 is derived from the unaudited historical financial statements of Holdings included elsewhere in this prospectus.

For a detailed discussion of the summary consolidated 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 and unaudited consolidated historical financial statements of Holdings included elsewhere in this prospectus. Among other things, the consolidated historical financial statements include more detailed information regarding the basis of presentation for the information in the following table.


	Holdings Historical
	Year Ended December 31,						Three Months Ended March 31,
	2013			2014			2014			2015
	(in thousands)
Statement of Operations Data:
Oil and Gas Revenues	$	42,489		$	67,878		$	13,642		$	13,508

Costs and Expenses:
Production and ad valorem taxes		2,515			4,431			1,074			665
Marketing and transportation		1,075			2,170			186			1,317
Amortization of royalty mineral interests in oil and natural gas properties		12,003			13,426			3,477			5,182
General and administrative expenses		2,083			4,425			491			901

Total costs and expenses		17,676			24,452			5,228			8,065

Other Expenses
Interest expense		4,072			4,860			1,226			1,302

Net income	$	20,741		$	38,566		$	7,188		$	4,141

Statement of Cash Flow Data:
Net cash provided by (used in):
Operating activities	$	30,123		$	53,526		$	10,421		$	10,772
Investing activities		(35	)		—			—			—
Financing activities		(33,083	)		(46,937	)		(8,775	)		(5,000	)
Other Financial Data:
Adjusted EBITDA(1)	$	36,816		$	56,852		$	11,891		$	10,625


	Holdings Historical
	As of December 31,				As of March 31, 2015
	2013		2014		As of March 31, 2015
	(in thousands)
Balance Sheet Data:
Cash and cash equivalents	$	1,959	$	8,548	$	14,320
Total assets		262,456		254,872		254,792
Total liabilities		91,640		110,427		111,206
Partner’s capital		170,816		144,445		143,586

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

Non-GAAP Financial Measure

Adjusted EBITDA

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

We define Adjusted EBITDA as net income (loss) before income taxes, gain/loss on derivative instruments, interest expense, depreciation, depletion and amortization, impairment of oil and gas properties and non-cash equity based compensation. Adjusted EBITDA is not a measure of net income (loss) as determined by United States’ generally accepted accounting principles (“GAAP”). We believe Adjusted EBITDA is useful because it allows us to more effectively evaluate our operating performance and compare the results of our operations from period to period without regard to our financing methods or capital structure. We exclude the items listed above from net income (loss) in arriving at Adjusted 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. Adjusted EBITDA should not be considered as an alternative to, or more meaningful than, net income (loss) as determined in accordance with GAAP or as an indicator of our operating performance or liquidity. 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, as well as the historic costs of depreciable assets, none of which are components of Adjusted EBITDA. Our computation of Adjusted EBITDA may not be comparable to other similarly titled measures of other companies.

The following table presents a reconciliation of Adjusted EBITDA to the most directly comparable GAAP financial measure for the period indicated.


	Holdings Historical
	Year Ended December 31,				Three Months Ended March 31,
	2013		2014		2014		2015
	(in thousands)
Reconciliation of Adjusted EBITDA to Net Income
Net income	$	20,741	$	38,566	$	7,188	$	4,141
Interest expense		4,072		4,860		1,226		1,302
Amortization of mineral interests		12,003		13,426		3,477		5,182

Adjusted EBITDA	$	36,816	$	56,852	$	11,891	$	10,625

Summary Reserve Data

The following table sets forth estimates of our net proved oil, natural gas liquids, and natural gas reserves as of December 31, 2013, based on a reserve report prepared by W.D. Von Gonten & Co. (“Von Gonten”), and as of December 31, 2014, based on a reserve report prepared by Ryder Scott. The reserve reports were prepared in accordance with the rules and regulations of the SEC. You should refer to “Risk Factors,” “Business—Oil and Natural Gas Data—Proved Reserves,” “Business—Oil and Natural Gas Production Prices and Production Costs—Production and Price History,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our audited and unaudited financial statements and notes thereto included herein in evaluating the material presented below.


	As of December 31,
	2013			2014
Estimated proved developed reserves:
Oil (MBbls)		1,739.2			3,640.4
Natural gas (MMcf)		4,342.8			8,798.5
Natural gas liquids (MBbls)		577.6			1,077.5
Total (MBOE)		3,040.6			6,184.3
Estimated proved undeveloped reserves:
Oil (MBbls)		4,736.4			7,193.5
Natural gas (MMcf)		15,126.7			20,399.0
Natural gas liquids (MBbls)		1,997.5			2,363.2
Total (MBOE)		9,255.1			12,956.5
Estimated Net Proved Reserves:
Oil (MBbls)		6,475.6			10,833.8
Natural gas (MMcf)		19,469.5			29,197.5
Natural gas liquids (MBbls)		2,575.1			3,440.7
Total (MBOE)(1)		12,295.7			19,140.8
Percent proved developed		25	%		32	%
PV-10 of proved reserves (in millions)(2)	$	431.7		$	617.5

(1)

Estimates of reserves as of December 31, 2013 and 2014 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 years ended December 31, 2013 and 2014, in accordance with SEC guidelines applicable to reserve estimates as of the end of such periods. The unweighted arithmetic average first day of the month prices were $96.78 per Bbl for oil and $3.67 per MMBtu for natural gas as of December 31, 2013 and $94.99 per Bbl for oil and $4.35 per MMBtu for natural gas as of December 31, 2014. The price per Bbl for natural gas liquids was modeled as a percentage of oil price, which was derived from historical accounting data. Reserve estimates do not include any value for probable or possible reserves that may exist, nor do they include any value for undeveloped acreage. The reserve estimates represent our ORRI share in our properties. Although we believe these estimates are reasonable, actual future production, cash flows, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves may vary substantially from these estimates.

(2)

In this prospectus, we have disclosed our PV-10 based on our reserve report. PV-10 represents the period-end present value of estimated future cash inflows from our natural gas and crude oil reserves, less future development and production costs, discounted at 10% per annum to reflect timing of future cash flows and using SEC pricing assumptions in effect at the end of the period. Because of this, PV-10 can be used within the industry and by creditors and securities analysts to evaluate estimated net cash flows from proved reserves on a more comparable basis. PV-10 differs from standardized measure because it does not include

the effects of income taxes. However, because we are a limited partnership, we are generally not subject to federal income taxes and thus our PV-10 for proved reserves and standardized measure are equivalent. Neither PV-10 nor standardized measure represents an estimate of fair market value of our natural gas and oil properties. We and others in the industry use PV-10 as a measure to compare the relative size and value of estimated reserves held by companies without regard to the specific tax characteristics of such entities.

Summary Production Data


	Year Ended December 31,				Three Months Ended March 31,
	2013		2014		2015
Production Data:
Oil (Bbls)		373,084		639,325		240,636
Natural gas (Mcf)		876,105		1,452,080		534,437
Natural gas liquids (Bbls)		68,407		202,365		88,572
Combined volumes (BOE)		587,508		1,083,704		418,281
Average daily combined volumes (BOE/d)		1,610		2,969		4,648
Average Realized Prices:
Oil (per Bbl)	$	96.28	$	87.19	$	43.51
Natural gas (per Mcf)	$	3.58	$	4.29	$	3.07
Natural gas liquids (per Bbl)	$	50.14	$	29.19	$	15.77
Weighted average combined (per BOE)	$	72.32	$	62.63	$	32.29

RISK FACTORS

Limited partner interests are inherently different from the capital stock of a corporation, although many of the business risks to which we are subject are similar to those that would be faced by a corporation engaged in a similar business. You should carefully consider the following risk factors together with all of the other information included in this prospectus in evaluating an investment in our common units.

If any of the following risks were to occur, our business, financial condition, results of operations and cash available for distribution could be materially adversely affected. In that case, we might not be able to make distributions on our common units, the trading price of our common units could decline, and you could lose all or part of your investment.

Risks Related to Our Business

We may not have sufficient available cash to pay any quarterly distribution on our common units.

We may not have sufficient available cash each quarter to enable us to pay any distributions to our common unitholders. Our expected aggregate annual distribution amount for the twelve months ending June 30, 2016 is based on the price and production assumptions set forth in “Cash Distribution Policy and Restrictions on Distributions—Estimated Cash Available for Distribution for the Twelve Months Ending June 30, 2016.” Furthermore, our partnership agreement does not require us to pay distributions on a quarterly basis or otherwise. If our price or production assumptions prove to be inaccurate, our actual distributions for the twelve months ending June 30, 2016 may be significantly lower than our forecasted distributions, or we may not be able to pay a distribution at all. The amount of cash we have to distribute each quarter principally depends upon the amount of revenue we generate, which are dependent upon the prices that our operators realize from the sale of oil and natural gas production. In addition, the actual amount of cash we will have to distribute each quarter under the cash distribution policy that the board of directors of our general partner will adopt will be reduced by payments in respect of debt service and other contractual obligations and fixed charges and increases in reserves for future operating or capital needs that the board of directors may determine is appropriate.

For a description of additional restrictions and factors that may affect our ability to make cash distributions, please read “Cash Distribution Policy and Restrictions on Distributions.”

On a pro forma basis, we would not have generated sufficient cash available for distribution to support the payment of the minimum quarterly distribution on all of our units for the year ended December 31, 2014 and the twelve months ended March 31, 2015.

We must generate approximately $ million of cash available for distribution to support the payment of the minimum quarterly distribution for four quarters on all of our common units and subordinated units that will be outstanding immediately following this offering. The amount of pro forma cash available for distribution generated during the year ended December 31, 2014 and the twelve months ended March 31, 2015 would not have been sufficient to support the payment of the full minimum quarterly distribution on our common units and subordinated units during each such period. Specifically, the amount of pro forma cash available for distribution generated during the year ended December 31, 2014 would have been sufficient to support a distribution of $ per common unit per quarter ($ per common unit on an annualized basis), or % of the minimum quarterly distribution on our common units, and would not have supported any distributions on our subordinated units. Similarly, the amount of pro forma cash available for distribution generated during the twelve months ended March 31, 2015 would have been sufficient to support a distribution of $ per common unit per quarter ($ per common unit on an annualized basis), or % of the minimum quarterly distribution on our common units, and would not have supported any distributions on our subordinated units. For a calculation of our ability to make cash distributions to our unitholders based on our pro forma results for the year ended December 31, 2014 and the twelve months ended March 31, 2015, please read “Cash Distribution Policy and Restrictions on Distributions.” If we are unable to generate sufficient cash available for distribution in future periods, we may

not be able to support the payment of the full minimum quarterly distribution or any amount on our common units or subordinated units, in which event the market price of our common units may decline materially.

The assumptions underlying the forecast of cash available for distribution that we include in “Cash Distribution Policy and Restrictions on Distributions” are inherently uncertain and are subject to significant business, economic, financial, regulatory and competitive risks and uncertainties that could cause actual results to differ materially from those forecasted.

The forecast of cash available for distribution set forth in “Cash Distribution Policy and Restrictions on Distributions” includes our forecasted results of operations, Adjusted EBITDA and cash available for distribution for the twelve-month period ending June 30, 2016. We estimate that our total cash available for distribution for the twelve-month period ending June 30, 2016 will be approximately $ million, as compared to approximately $ million for the year ended December 31, 2014 on a pro forma basis. The financial forecast has been prepared by management, and we have not received an opinion or report on it from our or any other independent auditor. The assumptions underlying the forecast are inherently uncertain and are subject to significant business, economic, financial, regulatory and competitive risks and uncertainties that could cause actual results to differ materially from those forecasted. If we do not achieve the forecasted results, we may not be able to pay the full minimum quarterly distribution or any amount on our common units or subordinated units, in which event the market price of our common units may decline materially.

The amount of cash we have available for distribution to holders of our units depends primarily on our cash flow and not solely on profitability, which may prevent us from making cash distributions during periods when we record net income.

The amount of cash we have available for distribution depends primarily upon our cash flow and not solely on profitability, which will be affected by non-cash items. As a result, we may make cash distributions during periods in which we record net losses for financial accounting purposes and may be unable to make cash distributions during periods in which we record net income.

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

Royal Resources Partners LP was formed in November 2014. Our predecessor, Holdings, acquired the mineral interests to be contributed to us upon the consummation of this initial public offering in March 2012. Moreover, we do not have historical financial statements with respect to the mineral interests for periods prior to their acquisition by Holdings in March 2012. As a result, there is only limited historical financial and operating information available upon which to base your evaluation of our performance.

We do not have a legal or contractual obligation to pay distributions quarterly or on any other basis or at the minimum quarterly distribution rate or at any other rate, and there is no guarantee that we will pay distributions to our unitholders in any quarter. The amount of our quarterly cash distributions, 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 distributions should not invest in our common units. Our future business performance may be volatile, and our cash flows may be unstable, as a result of fluctuations in the prices of oil and natural gas due to factors beyond our control. Please read “—All of our revenues are derived from royalty payments that are based on the price at which oil, natural gas and natural gas liquids produced from the underlying acreage is sold, and we do not currently hedge these commodity prices or plan to do so in the future. The volatility of these prices due to factors beyond our control greatly affects our financial condition, results of operations and cash available for distribution.” Although we expect to make a minimum quarterly distribution to holders of our common units, there is no guarantee that we will pay distributions to our unitholders in any quarter. Because our quarterly distributions will significantly correlate to the cash we generate each quarter after payment of our fixed and variable expenses, future quarterly distributions paid to our unitholders may vary significantly from quarter to quarter and may be zero.

The board of directors of our general partner may modify or revoke our cash distribution policy at any time at its discretion. Our partnership agreement does not require us to pay any distributions at all.

The board of directors of our general partner will adopt a cash distribution policy pursuant to which we intend to distribute quarterly at least $ per unit on all of our units to the extent we have sufficient cash after the establishment of cash reserves and the payment of our expenses, including payments to our general partner and its affiliates. However, the board of directors of our general partner may change such policy at any time at its discretion, without unitholder approval, and could elect not to pay distributions for one or more quarters. Please read “Cash Distribution Policy and Restrictions on Distributions.”

In addition, our partnership agreement does not require us to pay any distributions at all. 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 cash distribution policy could substantially reduce or eliminate the amounts of distributions to our unitholders. The amount of distributions we make, if any, and the decision to make any distribution at all will be determined by the board of directors of our general partner, whose interests may differ from those of our common unitholders. Our general partner has limited duties to our unitholders, which may permit it to favor its own interests or the interests of Royal to the detriment of our common unitholders.

All of our revenues are derived from royalty payments that are based on the price at which oil, natural gas and natural gas liquids produced from the underlying acreage is sold, and we do not currently hedge these commodity prices or plan to do so in the future. The volatility of these prices due to factors beyond our control greatly affects our business, financial condition, results of operations and cash available for distribution.

Our revenues, operating results, cash available for distribution and the carrying value of our oil and natural gas properties depend significantly upon the prevailing prices for oil and natural gas. Oil and natural gas are commodities and, therefore, their prices are subject to wide fluctuations in response to relatively minor changes in supply and demand. Historically, oil and natural gas prices have been volatile and they are likely to remain volatile due to a variety of additional factors that are beyond our control, including:

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worldwide and regional economic conditions affecting the global supply of and demand for oil and natural gas;

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

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

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

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

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the price and quantity of foreign imports;

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increases in U.S. domestic production;

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

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speculative trading in crude oil and natural gas derivative contracts;

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the level of consumer product demand;

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weather conditions and other natural disasters;

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risks associated with operating drilling rigs;

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technological advances affecting energy consumption;

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domestic and foreign governmental regulations and taxes;

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the continued threat of terrorism and the impact of military and other action, including U.S. military operations in the Middle East;

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

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the price and availability of competitors’ supplies of oil and natural gas and alternative fuels.

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 West Texas intermediate light sweet crude oil, which we refer to as West Texas Intermediate or WTI, has ranged from a low of $43.39 per Bbl in March 2015 to a high of $113.39 per Bbl in April 2011. The Henry Hub spot market price of natural gas has ranged from a low of $1.82 per MMBtu in April 2012 to a high of $8.15 per MMBtu in February 2014. During 2014, West Texas Intermediate posted prices ranged from $53.45 to $107.95 per Bbl and the Henry Hub spot market price of natural gas ranged from $2.74 to $8.15 per MMBtu. On March 31, 2015, the West Texas Intermediate posted price for crude oil was $47.72 per Bbl and the Henry Hub spot market price of natural gas was $2.65 per MMBtu. In recent weeks, there has been a continued decline in the price of light sweet crude oil. Any substantial decline in the price of oil and natural gas will likely have a material adverse effect on our financial condition, results of operations and cash available for distribution.

In addition, lower oil and natural gas prices may also reduce the amount of oil and natural gas that can be produced economically by our operators. This may result in having to make substantial downward adjustments to our estimated proved reserves. Our operators could also determine during periods of low commodity prices to shut in or curtail production from wells on the properties underlying our ORRIs. In addition, they could determine during periods of low commodity prices to plug and abandon marginal wells that otherwise may have been allowed to continue to produce for a longer period under conditions of higher prices. Specifically, they may abandon any well if they reasonably believe that the well can no longer produce oil or natural gas in commercially paying quantities thereby potentially causing some or all of the underlying oil and gas lease to expire along with our ORRI therein.

We do not currently enter into hedging arrangements with respect to the oil and natural gas production from our properties, and we will be exposed to the impact of decreases in the prices of oil and natural gas.

We have not entered into hedging arrangements to establish, in advance, a price for the sale of the oil and natural gas produced from our properties, and we do not intend to enter into such arrangements in the future. As a result, we may realize the benefit of any short-term increase in the price of oil and natural gas, but we will not be protected against decreases in price, and if the price of oil and natural gas decreases significantly, our business, results of operation and cash available for distribution may be materially adversely affected.

In the future, we may enter into hedging transactions, which could expose us to counterparty credit risk.

In the future, we may enter into hedging transactions, which could expose us to risk of financial loss if a counterparty were to fail to perform under a derivative contract. Disruptions in the financial markets or other unforeseen events could lead to sudden changes in a counterparty’s liquidity, which could impair its ability to perform under the terms of a derivative contract and, accordingly, prevent us from realizing the benefit of such a derivative contract.

Because we depend on our third party operators for all 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, 2014, we received approximately 53%, 24% and 10% of our revenue from Devon, Petrohawk Energy Corporation, a subsidiary of BHP (“Petrohawk”), and ConocoPhillips, respectively. For the three months ended March 31, 2015, we received approximately 52%, 27% and 11% of our revenue from Devon, BHP/Petrohawk and Pioneer, respectively. The failure of the aforementioned operators to adequately or efficiently perform operations or an operator’s failure to act in ways that are in our best interests could reduce production and revenues. Further, none of the operators of the properties underlying our ORRIs are contractually obligated to undertake any development activities, so any development and production activities will be subject to their reasonable discretion. The success and timing of drilling and development activities on the properties underlying our ORRIs, therefore, depends on a number of factors that will be largely outside of our control, including:

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the ability of our operators to access capital;

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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 selection of technology;

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the selection of counterparties for the sale of production; and

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the rate of production of the reserves.

The third party operators may elect not to undertake development activities, or may undertake such activities in an unanticipated fashion, which may result in significant fluctuations in our revenues and cash available for distribution to our unitholders. If reductions in production by the operators are implemented on the properties underlying our ORRIs and sustained, our revenues may also be substantially affected. 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.

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

As of December 31, 2014, 68% of our total estimated proved reserves were proved undeveloped reserves and may not be ultimately developed or produced by our operators. Recovery of proved undeveloped reserves requires significant capital expenditures and successful drilling operations by our operators. The reserve data included in the reserve report of our independent petroleum engineer assume that substantial capital expenditures by our operators are required to develop such reserves. We cannot be certain that the estimated costs of the development of these reserves are accurate, that our operators will develop the properties underlying our ORRIs as scheduled or that the results of such development will be as estimated. Delays in the development of our reserves, increases in costs to drill and develop such reserves or decreases in commodity prices will reduce the future net revenues of our estimated proved undeveloped reserves and may result in some projects becoming uneconomical for our operators. In addition, delays in the development of reserves could force us to reclassify certain of our proved reserves as unproved reserves.

Our producing properties and substantially all of the Retained Assets are located in the Eagle Ford Shale region of South Texas, making us vulnerable to risks associated with operating in a single geographic area. In addition, we have a large amount of proved reserves attributable to a single producing horizon within this area.

All of our properties and substantially all of the Retained Assets are geographically concentrated in DeWitt County in the Eagle Ford Shale region of South Texas. As a result of this concentration, we may be disproportionately exposed to the impact of regional supply and demand factors, delays or interruptions of

production from wells in this area caused by governmental regulation, processing or transportation capacity constraints, availability of equipment, facilities, personnel or services market limitations or interruption of the processing or transportation of crude oil, natural gas or natural gas liquids. In addition, the effect of fluctuations on supply and demand may become more pronounced within specific geographic oil and natural gas producing areas such as the Eagle Ford Shale region, which may cause these conditions to occur with greater frequency or magnify the effects of these conditions. Due to the concentrated nature of our properties, they could experience any of the same conditions at the same time, resulting in a relatively greater impact on our results of operations than they might have on other companies that have a more diversified portfolio of properties. Such delays or interruptions could have a material adverse effect on our financial condition, results of operations and cash available for distribution. Because substantially all of the Retained Assets have significant overlap with our properties, acquisitions from our Sponsor will not significantly increase our geographic diversity.

Our success depends on finding or acquiring additional reserves, and our operators developing those additional reserves.

Our future success depends upon our ability to acquire additional oil and natural gas 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 the properties underlying our ORRIs by our operators or we acquire properties containing proved reserves, or both. Aside from acquisitions, we have no control over the exploration and development of our properties. To increase reserves and production, we would need our operators to undertake replacement activities or use third parties to accomplish these activities. Substantial capital expenditures will be necessary for the acquisition of oil and natural gas reserves. Neither we nor our third party operators may have sufficient resources to acquire additional reserves or to undertake exploration, development, production or other replacement activities, such activities may not result in significant additional reserves and efforts to drill productive wells at low finding and development costs may be unsuccessful. Furthermore, although our revenues and cash available for distribution may increase if prevailing oil and natural gas prices increase significantly, finding costs for additional reserves could also increase.

Our failure to successfully identify, complete and integrate acquisitions of properties or businesses could slow our growth and adversely affect our results of operations and cash available for distribution.

There is intense competition for acquisition opportunities in our industry. The successful acquisition of producing properties requires an assessment of several factors, including:

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recoverable reserves;

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future oil and natural gas prices and their applicable differentials;

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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. 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 may not always be 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 operators further develop our existing properties, we will depend on acquisitions to grow our reserves, production and cash flow.

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 properties, which could result in unforeseen operating difficulties. In addition, if we enter into new geographic markets, 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 operations. The process of integrating acquired businesses may involve unforeseen difficulties and may require a disproportionate amount of our managerial and financial resources. In addition, possible future acquisitions may be larger and for purchase prices significantly higher than those paid for earlier acquisitions.

No assurance can be given that we will be able to identify suitable acquisition opportunities, negotiate acceptable terms, obtain financing for acquisitions on acceptable terms or successfully acquire identified targets. Our failure to achieve consolidation savings, to integrate the acquired businesses and assets into our existing operations successfully or to minimize any unforeseen operational difficulties could have a material adverse effect on our financial condition, results of operations and cash available for distribution. The inability to effectively manage the integration of acquisitions could reduce our focus on subsequent acquisitions and current operations, which, in turn, could negatively impact our growth, results of operations and cash available for distribution.

If we are unable to make acquisitions on economically acceptable terms from our Sponsor or third parties, our future growth will be limited, and the acquisitions we do make may reduce, rather than increase, our cash generated from royalties.

Our ability to grow depends, in part, on our ability to make acquisitions that increase our cash generated from royalties. The acquisition component of our strategy is based, in large part, on our expectation of ongoing acquisitions from industry participants, including our Sponsor. While we note elsewhere in this prospectus that we believe our Sponsor will be incentivized pursuant to its economic relationship with us to offer us opportunities to purchase oil and gas properties, 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 our Sponsor. Furthermore, many factors could impair our access to future acquisitons, including a change in control of our Sponsor or a transfer of the incentive distribution rights by our Sponsor to a third party. A material decrease in divestitures of oil and gas properties by our Sponsor or otherwise would limit our opportunities for future acquisitions and could have a material adverse effect on our business, results of operations, financial condition and ability to make quarterly cash distributions to our unitholders.

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

Acquiring oil and natural gas properties requires us to assess reservoir and infrastructure characteristics, including recoverable reserves, development and operating costs and potential environmental and other liabilities. Such assessments are inexact and inherently uncertain. In connection with the assessments, we perform a review of the subject properties, but such a review will not necessarily reveal all existing or potential problems. In the course of our due diligence, we may not inspect every well or pipeline. We cannot necessarily observe structural and environmental problems, such as pipe corrosion, when an inspection is made. We may not be able to obtain contractual indemnities from the seller for liabilities created prior to our purchase of the property. We may be required to assume the risk of the physical condition of the properties in addition to the risk that the properties may not perform in accordance with our expectations.

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

Project areas on the properties underlying our ORRIs 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. For the year ended December 31, 2014, BHP and Devon, through a joint venture, ConocoPhillips, EOG, and Pioneer, which are the operators for 99% of the acreage associated with our properties, drilled a total of 144 gross wells, of which 88 wells were completed as producing wells and 56 wells were in various stages of completion. 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 for distribution may be materially affected.

Identified drilling locations, which are scheduled out over many years, are susceptible to uncertainties that could materially alter the occurrence or timing of their drilling.

As of December 31, 2014, we had identified 1,347 gross proved undeveloped drilling locations across our acreage. These drilling locations represent a significant part of our growth strategy, however, we do not control the development of these locations. Our operators’ ability to drill and develop identified potential drilling locations will depend on a number of factors, including the availability of capital, seasonal conditions, regulatory changes and approvals, negotiation of agreements with third parties, commodity prices, costs, the generation of additional seismic or geological information, the availability of drilling rigs, drilling results, construction of infrastructure, inclement weather, and lease expirations.

Further, identified potential drilling locations are in various stages of evaluation, ranging from locations that are ready to drill to locations that will require substantial additional analysis of data. We will not be able to predict in advance of drilling and testing whether any particular drilling location will yield production in sufficient quantities for operators to recover drilling or completion costs or to be economically viable. Even if sufficient amounts of oil or natural gas reserves exist, the potentially productive hydrocarbon bearing formation may be damaged or mechanical difficulties may develop while drilling or completing the well, possibly resulting in a reduction in production from the well or abandonment of the well. If our operators drill dry holes in our current and future drilling locations, our business may be materially harmed. We will not be able to assure you that the analogies drawn from available data from other wells, more fully explored locations or producing fields will be applicable to our drilling locations. Further, initial production rates reported by us or our operators in our areas of operations may not be indicative of future or long-term production rates.

Because of these uncertainties, we do not know if the potential drilling locations identified on our acreage will ever be drilled or if oil or natural gas reserves will be able to be produced from these or any other potential drilling locations. As such, actual drilling activities with respect to our acreage may materially differ from those presently identified, which could adversely affect our business, financial condition, results of operations and cash available for distribution.

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

Oil and natural gas reserve engineering is not an exact science and 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, projections of future production rates and the timing of development expenditures may be incorrect.

Our historical estimates of proved reserves and related valuations as of December 31, 2014, were prepared by Ryder Scott, an independent petroleum engineering firm, 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.

Also, certain assumptions regarding future oil and natural gas prices, production levels and operating and development costs may prove incorrect. 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. In addition, none of the operators of the properties underlying our ORRIs are contractually obligated to provide us with information regarding drilling activities or historical production data with respect to the properties underlying our interests, which may affect our estimates of reserves. A substantial portion of our reserve estimates are made without the benefit of a lengthy production history, which are less reliable than estimates based on a lengthy production history. 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.

You should not assume that the present value of future net revenues from our reserves is the current market value of our estimated reserves. We generally base the estimated discounted future net cash flows from reserves on prices and costs on the date of the estimate. Actual future prices and costs may differ materially from those used in the present value estimate.

The estimates of reserves as of December 31, 2014 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, 2014, in accordance with the revised SEC guidelines applicable to reserve estimates for such period.

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 our operators 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.

The PV-10 of our estimated proved reserves is not necessarily the same as the current market value of our estimated proved oil and natural gas reserves.

The present value of future net cash flows from our proved reserves shown in this report, or PV-10, may not be the current market value of our estimated natural gas and oil reserves. In accordance with rules established by the SEC and the Financial Accounting Standards Board (“FASB”), we base the estimated discounted future net cash flows from our proved reserves on the 12-month average oil and 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 net 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 natural gas and oil industry in general.

Restrictions in our existing and future debt agreements could limit our growth and our ability to engage in certain activities.

We anticipate our credit facility will contain number of restrictive covenants that may limit our ability to, among other things, incur additional indebtedness, make loans and advances, make capital expenditures, incur liens and sell assets.

In addition, we anticipate that our credit facility will require us to maintain certain financial ratios or to reduce our indebtedness if we are unable to comply with such ratios. These restrictions may also limit our ability

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

Unless we replace our reserves with new reserves that our operators develop, our reserves royalty payments will decline, which would adversely affect our future cash flows, results of operations and cash available for distribution.

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

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

Concerns over global economic conditions, energy costs, geopolitical issues, inflation, the availability and cost of credit, the European debt crisis, the Chinese economy, the United States mortgage market and a weak real estate market in the United States have contributed to increased economic uncertainty and diminished expectations for the global economy. These factors, combined with volatile prices of oil, natural gas and natural gas liquids, declining business and consumer confidence and increased unemployment, have precipitated an economic slowdown and a recession. In addition, continued hostilities in the Middle East and the occurrence or threat of terrorist attacks in the United States or other countries could adversely affect the 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. If the economic climate in the United States or abroad deteriorates further, worldwide demand for petroleum products could diminish, which could impact the price at which oil, natural gas and natural gas liquids from the properties underlying our ORRIs are sold, affect the ability of vendors, suppliers and customers associated with the properties underlying our ORRIs to continue operations and ultimately adversely impact our results of operations, financial condition and cash available for distribution.

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 have a material adverse effect on our business, financial condition, results of operations and cash available for distribution.

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

The oil and natural gas industry is intensely competitive, and our third party operators 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 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 operators can, which would adversely affect our operators’ competitive position. Our operators may have fewer financial and human resources than many companies in our operators’ industry, and may be at a disadvantage in bidding for exploratory prospects and producing oil and natural gas properties.

The generation of revenues depends in part on access to and gathering, transportation and processing facilities. Any limitation in the availability of those facilities could interfere with sales of oil and natural gas production from our properties.

The amount of oil and natural gas that may be produced and sold from a well is subject to curtailment in certain circumstances, such as by reason of weather conditions, pipeline interruptions due to scheduled and unscheduled maintenance, failure of tendered oil and natural gas to meet quality specifications of gathering lines or downstream transporters, excessive line pressure which prevents delivery, physical damage to the gathering system or transportation system or lack of contracted capacity on such systems. The curtailments may vary from a few days to several months. In many cases, the operators of our properties are provided limited notice, if any, as to when production will be curtailed and the duration of such curtailments. If the operators are forced to reduce production due to such a curtailment, our revenues and the amount of our cash distributions to our unitholders would similarly be reduced due to the reduction of revenues from the sale of production.

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

Many key responsibilities within our business have been assigned to a small number of individuals. The loss of their services could adversely affect our business. In particular, the loss of the services of one or more members of our executive team, including Randolph Newcomer, Jr., could disrupt our business. Further, we do not maintain “key person” life insurance policies on any of our executive officers. As a result, we are not insured against any losses resulting from the death of these key individuals.

Increased costs of capital could adversely affect our business.

Our business and ability to make acquisitions could be harmed by factors such as the availability, terms and cost of capital, increases in interest rates or a reduction in our credit rating. 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 information and computer systems could adversely affect our business.

We are dependent on our information systems and computer based programs. If any of such programs or systems were to fail or create erroneous information in our hardware or software network infrastructure, possible consequences include our loss of communication links and inability to automatically process commercial transactions or engage in similar automated or computerized business activities. Any such consequence could have a material adverse effect on our business.

The oil and gas operations on the acreage underlying our ORRIs are subject to environmental, health and safety laws and regulations that could adversely affect the cost, manner or feasibility of conducting operations on them or result in significant costs and liabilities, which could reduce the amount of cash available for distribution to unitholders.

The oil and natural gas exploration and production operations on the acreage underlying our ORRIs are subject to stringent and comprehensive federal, state and local laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection or the health and safety of workers and other affected individuals. These laws and regulations may impose numerous obligations that apply to the operations on the acreage underlying our ORRIs, including the requirement to obtain a permit before

conducting drilling, waste disposal or other regulated activities; the restriction of types, quantities and concentrations of materials that can be released into the environment; restrictions on water withdrawal and use; the incurrence of significant development expenses to install pollution or safety-related controls at the operated facilities; the limitation or prohibition of drilling activities on certain lands lying within wilderness, wetlands and other protected areas; the protection of threatened or endangered species; and the imposition of substantial liabilities for pollution resulting from operations. For example, in April 2012, the United States Environmental Protection Agency (“EPA”) published final rules that subject all oil and natural gas operations (production, processing, transmission, storage and distribution) to regulation under the New Source Performance Standards (“NSPS”) and the National Emission Standards for Hazardous Air Pollutants (“NESHAPS”) programs. These rules became effective in October 2012 and include NSPS standards for completions of hydraulically-fractured gas wells. The standards include the reduced emission completion techniques developed in the EPA’s Natural Gas STAR program along with pit flaring of gas not sent to the gathering line. The standards are applicable to newly drilled and fractured wells and wells that are refractured on or after January 1, 2015. Further, the rules under NESHAPS include Maximum Achievable Control Technology (“MACT”) for glycol dehydrators and storage vessels at major source of hazardous air pollutants not currently subject to MACT standards. The EPA received numerous requests for reconsideration of these rules and court challenges were also filed. At this point, we cannot predict the final regulatory requirements or the cost to the operators on the acreage underlying our ORRIs to comply with such requirements with any certainty.

Further, the EPA plans to issue a proposed rule in the summer of 2015 and a final rule in 2016 that would impose more stringent methane emissions control requirements for oil and gas development and production operations, which may require operators on the acreage underlying our ORRIs to incur additional expenses to control air emissions by installing emissions control technologies and adhering to a variety of work practice and other requirements. These requirements could increase the costs of development and production, reducing the profits available to us and potentially impairing our operator’s ability to economically develop acreage underlying our ORRIs.

There is inherent risk of incurring significant environmental costs and liabilities in the operations on the acreage underlying our ORRIs as a result of the handling of petroleum hydrocarbons and wastes, air emissions and wastewater discharges related to operations, and historical industry operations and waste disposal practices. Under certain environmental laws and regulations, the operators could be subject to joint and several strict liability for the removal or remediation of previously released materials or property contamination regardless of whether such operators were responsible for the release or contamination or whether the operations were in compliance with all applicable laws at the time those actions were taken. Private parties, including the owners of properties on or adjacent to which wells are drilled and facilities where petroleum hydrocarbons or wastes are taken for reclamation or disposal, may also have the right to pursue legal actions to enforce compliance as well as to seek damages for non-compliance with environmental laws and regulations or for personal injury or property damage. In addition, the risk of accidental spills or releases could expose the operators of the acreage underlying our ORRIs to significant liabilities that could have a material adverse effect on the operators’ businesses, financial condition and results of operations.

Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent or costly operational control requirements or waste handling, storage, transport, disposal or cleanup requirements could require the operators of the acreage underlying our ORRIs to make significant expenditures to attain and maintain compliance and may otherwise have a material adverse effect on their results of operations, competitive position or financial condition.

Climate change laws and regulations restricting emissions of GHGs could result in increased operating costs and reduced demand for the oil and natural gas produced from the acreage underlying our ORRIs, while potential physical effects of climate change could disrupt production and cause operators to incur significant costs in preparing for or responding to those effects.

In response to EPA findings that emissions of carbon dioxide, methane and other GHGs 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 the monitoring and reporting of GHG emissions from specified onshore and offshore oil and natural gas production sources in the United States on an annual basis, which include certain of the operations conducted on the acreage underlying our ORRIs. Additional EPA rules could affect the ability of operators on the acreage underlying our ORRIs to obtain air permits for new or modified facilities. The acreage underlying our ORRIs may be subject to these requirements or become subject to them in the future.

While Congress has from time to time considered legislation to reduce emissions of GHGs, there has not been significant activity in the form of adopted legislation to reduce GHG emissions at the federal level in recent years. In the absence of such federal climate legislation, a number of state and regional efforts have emerged that are aimed at tracking and/or reducing GHG emissions by means of cap and trade programs. These programs typically require major sources of GHG emissions to acquire and surrender emission allowances in return for emitting those GHGs. Any such future laws and regulations imposing reporting obligations on, or limiting emissions of, GHGs could require operators of the acreage underlying our ORRIs to incur costs to reduce emissions of GHGs. Substantial limitations on GHG emissions could adversely affect demand for oil and natural gas.

Finally, it should be noted that some scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods and other climatic events; if any such effects were to occur, they could have a material adverse effect on the operations conducted on the acreage underlying our ORRIs.

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

Hydraulic fracturing is an important and common practice that is used to stimulate production of oil and/or natural gas from dense subsurface rock formations. The hydraulic fracturing process involves the injection of water, sand and chemicals under pressure into targeted subsurface formations to fracture the surrounding rock and stimulate production. Hydraulic fracturing is typically regulated by state oil and natural gas commissions, but the EPA has asserted federal regulatory authority pursuant to the federal Safe Drinking Water Act (“SDWA”) over certain hydraulic fracturing activities involving the use of diesel fuels and published permitting guidance in February 2014 addressing the performance of such activities using diesel fuels. In May 2014, the EPA issued an Advanced Notice of Proposed Rulemaking, seeking comment on the development of regulations under the Toxic Substances Control Act to require companies to disclose information regarding the chemicals used in hydraulic fracturing. Also, in March 2015, the Bureau of Land Management of the U.S. Department of the Interior published a final rule that imposes requirements for hydraulic fracturing activities on federal lands, including new requirements relating to public disclosure, as well as wellbore integrity and handling of flowback water. In addition, Congress has from time to time considered legislation to provide for federal regulation of hydraulic fracturing under the SDWA and to require disclosure of the chemicals used in the hydraulic fracturing process. It is unclear how any future federal disclosure requirements that add to any applicable state disclosure requirements already in effect may affect operations on the acreage underlying our ORRIs.

Certain governmental reviews have been conducted or are underway that focus on the potential environmental impacts of hydraulic fracturing. The EPA commenced a study of the potential impact of hydraulic

fracturing on drinking water resources in 2011 and released the draft report for public comment in June 2015. The draft report concluded that hydraulic fracturing has not led to widespread, systemic impacts on drinking water resources, but it does have the potential to impact drinking water resources. The White House Council on Environmental Quality is coordinating an administration-wide review of hydraulic fracturing practices. Other governmental agencies, including the U.S. Department of Energy, have evaluated or are evaluating various other aspects 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 on the acreage underlying our ORRIs to perform fracturing and increase the costs of compliance and doing business.

At the state level, several states have adopted or are considering legal requirements that could impose more stringent permitting, disclosure and well construction requirements on hydraulic fracturing activities. 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. If new or more stringent federal, state or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where we hold ORRIs, the operators of the acreage underlying our ORRIs could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of development activities, and perhaps even be precluded from drilling wells.

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 and could prevent us from meeting our financial and other obligations. 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 operators’ services and causing a reduction in our revenues. Oil and natural gas facilities, including those of our operators, could be direct targets of terrorist attacks, and, to the extent we acquire working interests in the future, our operations could be adversely impacted if infrastructure integral to our customers’ operations is destroyed or damaged.

Risks Related to Our Operators

Operators of our properties, including our current third party operators, are subject to the risks and uncertainties described below.

The unavailability, high cost or shortages of rigs, equipment, raw materials, supplies, oilfield services or personnel may restrict our our operators’ operations.

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, our operators will rely on independent third party service providers to provide most of the services necessary to drill new wells. If they 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, frac crews, tubulars, fracking and completion services and production equipment could delay or restrict our operators’ exploration and development operations, which in turn could adversely affect our financial condition, results of operations and cash available for distribution.

Restrictions on our operators’ ability to obtain water may have an adverse effect on our financial condition, results of operations and cash available for distribution.

Water is an essential component of deep shale oil and natural gas production during both the drilling and hydraulic fracturing processes. During the last several years, Texas has experienced extreme drought conditions. As a result of this severe drought, some local water districts have begun restricting the use of water subject to their jurisdiction for hydraulic fracturing to protect local water supply. If our operators we are unable to obtain water to use in their operations from local sources, or our operators are unable to effectively utilize flowback water, they may be unable to economically drill for or produce oil and natural gas, which could have an adverse effect on our financial condition, results of operations and cash available for distribution.

The results of our operators’ 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.

Our operators’ operations will involve utilizing the latest drilling and completion techniques. Risks that they will face while drilling include, but are not limited to, landing their well bore in the desired drilling zone, staying in the desired drilling zone while drilling horizontally through the formation, running their casing the entire length of the well bore and being able to run tools and other equipment consistently through the horizontal well bore. Risks that they will face while completing wells include, but are not limited to, being able to fracture stimulate the planned number of stages, being able to run tools the entire length of the well bore during completion operations and successfully cleaning out the well bore after completion of the final fracture stimulation stage. Furthermore, certain of the new techniques our operators may adopt, such as 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 any such 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 we 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 operators’ drilling results are less than anticipated or they are unable to execute their drilling program because of capital constraints, lease expirations, access to gathering systems, and/or declines in natural gas and oil prices, the return on our investment in these areas may not be as attractive as we anticipate.

The marketability of oil and natural gas production is dependent upon transportation and other facilities, certain of which neither we nor our operators control. If these facilities are unavailable, our operators’ operations could be interrupted and our results of operations and cash available for distribution could be adversely affected.

The marketability of our 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 nor our operators control these third party transportation facilities and our operators’ access to them may be limited or denied. Insufficient production from the wells on the acreage underlying our ORRIs to support the construction of pipeline facilities by our purchasers or a significant disruption in the availability of third party transportation facilities or other production facilities could adversely impact our operators’ ability to deliver to market or produce oil and natural gas and thereby cause a significant interruption in our 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 control, such as pipeline interruptions due to maintenance, excessive pressure, ability of downstream processing facilities to accept unprocessed gas, physical

damage to the gathering 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, and in many cases, we and our operators are provided with limited, if any, notice as to when these circumstances will arise and their duration. Any such shut in or curtailment, or an inability to obtain favorable terms for delivery of the oil and natural gas produced from the acreage underlying our ORRIs fields, could adversely affect our financial condition, results of operations and cash available for distribution.

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

Our operators’ drilling activities will be subject to many risks. For example, we will not be able to assure you that wells drilled by our operators 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 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 for distribution to our unitholders may be adversely affected.

Risks Inherent in an Investment in Us

Royal owns and controls our general partner, which has sole responsibility for conducting our business and managing our operations. Our general partner and its affiliates, including Royal, have conflicts of interest with us and limited duties, and they may favor their own interests to the detriment of us and our unitholders.

Following the offering, Royal will own and control our general partner and will appoint all of the directors of our general partner. All of the executive officers and certain of the directors of our general partner are also officers and/or directors of Royal. Although our general partner has a duty to manage us in a manner that it believes is not adverse to our interest, the executive officers and directors of our general partner have a fiduciary duty to manage our general partner in a manner beneficial to Royal. Therefore, conflicts of interest may arise between Royal or any of its affiliates, including our general partner, on the one hand, and us or any of our

unitholders, on the other hand. In resolving these conflicts of interest, our general partner may favor its own interests and the interests of its affiliates over the interests of our common unitholders. These conflicts include the following situations, among others:

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Our general partner is allowed to take into account the interests of parties other than us, such as Royal, in exercising certain rights under our partnership agreement.

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Neither our partnership agreement nor any other agreement requires Royal to pursue a business strategy that favors us.

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Our partnership agreement replaces the fiduciary duties that would otherwise be owed by our general partner with contractual standards governing its duties, limits our general partner’s liabilities and restricts the remedies available to our unitholders for actions that, without such limitations, might constitute breaches of fiduciary duty.

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Except in limited circumstances, our general partner has the power and authority to conduct our business without unitholder approval.

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Our general partner determines the amount and timing of asset purchases and sales, borrowings, issuances of additional partnership securities and the level of cash reserves, each of which can affect the amount of cash that is distributed to our unitholders.

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Our general partner determines the amount and timing of any cash expenditure and whether an expenditure is classified as a maintenance capital expenditure, which reduces operating surplus, or an expansion capital expenditure, which does not reduce operating surplus. Our partnership agreement requires our general partner to deduct estimated, rather than actual, maintenance capital expenditures from operating surplus in determining cash available for distribution from operating surplus. Please read “How We Make Distributions—Capital Expenditures” for a discussion on when a capital expenditure constitutes a maintenance capital expenditure or an expansion capital expenditure, as well as their effect on operating surplus. Our general partner’s classification of capital expenditures can affect the amount of cash from operating surplus that is distributed to our unitholders which, in turn, may affect the ability of the subordinated units to convert into common units and our ability to make incentive distributions. Please read “How We Make Distributions—Subordination Period.”

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Our general partner may cause us to borrow funds in order to permit the payment of cash distributions, even if the purpose or effect of the borrowing is to make a distribution on the subordinated units, to make incentive distributions or to accelerate the expiration of the subordination period.

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Our partnership agreement permits us to distribute up to $ million as operating surplus, even if it is generated from asset sales, non-working capital borrowings or other sources that would otherwise constitute capital surplus. This cash may be used to fund distributions on our subordinated units or the incentive distribution rights.

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Our general partner determines which costs incurred by it and its affiliates are reimbursable by us.

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Our partnership agreement does not restrict our general partner from causing us to pay it or its affiliates for any services rendered to us or entering into additional contractual arrangements with its affiliates on our behalf.

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Our general partner intends to limit its liability regarding our contractual and other obligations.

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Our general partner may exercise its right to call and purchase common units if it and its affiliates own more than 80% of the common units.

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Our general partner controls the enforcement of obligations that it and its affiliates owe to us.

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Our general partner decides whether to retain separate counsel, accountants or others to perform services for us.

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Royal may elect to cause us to issue common units to it in connection with a resetting of the target distribution levels related to Royal’s incentive distribution rights without the approval of the conflicts committee of the board of directors of our general partner or the unitholders. This election may result in lower distributions to the common unitholders in certain situations.

In addition, Royal or its affiliates, including Riverbend, may compete with us. Please read “—Royal and other affiliates of our general partner, including Riverbend and Blackstone, may compete with us.” and “Conflicts of Interest and Fiduciary Duties.”

Royal and other affiliates of our general partner, including Riverbend and Blackstone, may compete with us.

Our partnership agreement provides that our general partner will be restricted from engaging in any business activities other than acting as our general partner, engaging in activities incidental to its ownership interest in us and providing management, advisory and administrative services to its affiliates or to other persons. However, affiliates of our general partner, including Royal and Riverbend, are not prohibited from engaging in other businesses or activities, including those that might be in direct competition with us. In addition, Royal or Riverbend may compete with us for investment opportunities and may own an interest in entities that compete with us. Further, Royal and its affiliates, including Riverbend, may acquire, develop or dispose of additional oil and natural gas properties or other assets in the future, without any obligation to offer us the opportunity to purchase or develop any of those assets.

Royal, Riverbend and Blackstone are each an established participant in the oil and natural gas industry and have resources greater than ours, which factors may make it more difficult for us to compete with Royal with respect to commercial activities as well as for potential acquisitions. As a result, competition from Royal and its affiliates could adversely impact our results of operations and cash available for distribution to our unitholders.

Pursuant to the terms of our partnership agreement, the doctrine of corporate opportunity, or any analogous doctrine, does not apply to our general partner or any of its affiliates, including its executive officers and directors, Royal and Riverbend. Any such person or entity that becomes aware of a potential transaction, agreement, arrangement or other matter that may be an opportunity for us will not have any duty to communicate or offer such opportunity to us. Any such person or entity will not be liable to us or to any limited partner for breach of any fiduciary duty or other duty by reason of the fact that such person or entity pursues or acquires such opportunity for itself, directs such opportunity to another person or entity or does not communicate such opportunity or information to us. This may create actual and potential conflicts of interest between us and affiliates of our general partner and result in less than favorable treatment of us and our unitholders. Please read “Conflicts of Interest and Fiduciary Duties.”

from those of our common unitholders. Our general partner has limited duties to our unitholders, which may permit it to favor its own interests or the interests of Royal to the detriment of our common unitholders.

We expect to distribute a significant portion of our cash available for distribution to our partners, which could limit our ability to grow and make acquisitions.

We plan to distribute most of our cash available for distribution, which may cause our growth to proceed at a slower pace than that of businesses that reinvest their cash to expand ongoing operations. To the extent we issue additional units in connection with any acquisitions or expansion capital expenditures, the payment of distributions on those additional units may increase the risk that we will be unable to maintain or increase our per unit distribution level. There are no limitations in our partnership agreement on our ability to issue additional units, including units ranking senior to the common units. The incurrence of additional commercial borrowings or other debt to finance our growth strategy would result in increased interest expense, which, in turn, may impact the cash that we have available to distribute to our unitholders.

Our Sponsor, Royal, may receive incentive distributions solely because of increases in commodity prices or the actions of our third party operators.

Royal will own all of our incentive distributions rights, which will entitle it to an increasing portion of the total cash available for distributions to unitholders as our cash distributions increase over time. Our cash distributions may increase over time solely as a result of increases in the commodity prices of oil, natural gas and natural gas liquids, which are set by the market, or actions by our third party operators, such as the drilling of new wells, the workover of existing wells, and the institution of new techniques or exploration of new formations to improve the production of oil, gas and natural gas liquids. As a result, we may be required to pay incentive distributions to Royal even though neither Royal nor our general partner has taken any action to cause such increase in cash available for distribution. Payment of these incentive distributions will reduce the portion of total cash available for distribution to our common unitholders. This could result in a decline in the price of our common units.

Our general partner intends to limit its liability regarding our obligations.

Our general partner intends to limit its liability under contractual arrangements between us and third parties so that the counterparties to such arrangements have recourse only against our assets, and not against our general partner or its assets. Our general partner may therefore cause us to incur indebtedness or other obligations that are nonrecourse to our general partner. Our partnership agreement provides that any action taken by our general partner to limit its liability is not a breach of our general partner’s duties, even if we could have obtained more favorable terms without the limitation on liability. In addition, we are obligated to reimburse or indemnify our general partner to the extent that it incurs obligations on our behalf. Any such reimbursement or indemnification payments would reduce the amount of cash otherwise available for distribution to our unitholders.

We will not have any employees, and we will rely solely on the employees of our general partner to manage our business, some of which will also be employees of Riverbend. The management team of Riverbend, which includes the individuals who will manage us, will also perform similar services for Royal and other industry partners, and thus will not be solely focused on our business.

We will not have any employees and we will rely solely on the employees of our general partner, some of which will be employees of Riverbend, to operate our assets and perform other management, administrative and operating services for us. The management team of Riverbend will provide similar activities for Royal and other industry partners. Because employees of Riverbend will be providing services to us that are similar to those performed for Royal and its other industry partners, those individuals may not have sufficient human, technical and other resources to provide those services to us at a level that they would be able to provide to us if they were solely focused on our business and operations. The management team of Riverbend may make internal decisions on how to allocate its available resources and expertise that may not always be in our best interest. There is no

requirement that the employees of our general partner, who are also employees of Riverbend, will favor us over Royal or its other industry partners in providing their services. If those individuals do not devote sufficient attention to the management and operation of our business, our financial results may suffer and our ability to make distributions to our unitholders may be reduced.

Our partnership agreement replaces our general partner’s fiduciary duties to our unitholders.

Our partnership agreement contains provisions that eliminate and replace the fiduciary standards to which our general partner would otherwise be held by state fiduciary duty law. For example, our partnership agreement permits our general partner to make a number of decisions in its individual capacity, as opposed to in its capacity as our general partner, or otherwise free of fiduciary duties to us and our unitholders. This entitles our general partner to consider only the interests and factors that it desires and relieves it of any duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or our limited partners. Examples of decisions that our general partner may make in its individual capacity include:

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how to allocate business opportunities among us and its affiliates;

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whether to exercise its call right;

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how to exercise its voting rights with respect to the units it owns;

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whether to elect to reset target distribution levels;

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whether to exercise its registration rights; and

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whether or not to consent to any merger or consolidation of the partnership or any amendment to the partnership agreement.

By purchasing a common unit, a unitholder is treated as having consented to the provisions in the partnership agreement, including the provisions discussed above. Please read “Conflicts of Interest and Fiduciary Duties—Fiduciary Duties.”

Our partnership agreement restricts the remedies available to holders of our units for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty.

Our partnership agreement contains provisions that restrict the remedies available to unitholders for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty under state fiduciary duty law. For example, our partnership agreement provides that:

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whenever our general partner makes a determination or takes, or declines to take, any other action in its capacity as our general partner, our general partner is generally required to make such determination, or take or decline to take such other action, in good faith, and will not be subject to any higher standard imposed by our partnership agreement, Delaware law, or any other law, rule or regulation, or at equity;

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our general partner and its executive officers and directors will not be liable for monetary damages or otherwise to us or our limited partners resulting from any act or omission unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that such losses or liabilities were the result of conduct of our general partner or such officer or director engaged by it in bad faith or, with respect to any criminal conduct, with the knowledge that its conduct was unlawful; and

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our general partner will not be in breach of its obligations under the partnership agreement or its duties to us or our limited partners if a transaction with an affiliate or the resolution of a conflict of interest is:

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approved by the conflicts committee of the board of directors of our general partner, although our general partner is not obligated to seek such approval; or

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approved by the vote of a majority of the outstanding common units, excluding any common units owned by our general partner and its affiliates.

In connection with a situation involving a transaction with an affiliate or a conflict of interest, other than one where our general partner is permitted to act in its sole discretion, any determination by our general partner must be made in good faith. If an affiliate transaction or the resolution of a conflict of interest is not approved by our common unitholders or the conflicts committee then it will be presumed that, in making its decision, taking any action or failing to act, the board of directors acted in good faith, and in any proceeding brought by or on behalf of any limited partner or the partnership, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption. Please read “Conflicts of Interest and Fiduciary Duties.”

Our partnership agreement provides that the conflicts committee of the board of directors of our general partner may be comprised of one or more independent directors. If our general partner establishes a conflicts committee with only one independent director, your interests may not be as well served as if the conflicts committee were comprised of at least two independent directors. A single-member conflicts committee would not have the benefit of discussion with, and input from, other independent directors.

The holder or holders of our incentive distribution rights may elect to cause us to issue common units to it in connection with a resetting of the target distribution levels related to the incentive distribution rights, without the approval of the conflicts committee of our general partner’s board of directors or the holders of our common units. This could result in lower distributions to holders of our common units.

The holder or holders of a majority of our incentive distribution rights (initially Royal) have the right, at any time when there are no subordinated units outstanding and we have made cash distributions in excess of the highest then-applicable target distribution for each of the prior four consecutive fiscal quarters and the aggregate distribution for such four-quarter period did not exceed adjusted operating surplus generated during such period, to reset the initial target distribution levels at higher levels based on our cash distribution levels at the time of the exercise of the reset election. Following a reset election by Royal, the minimum quarterly distribution will be calculated equal to an amount equal to the prior cash distribution per common unit for the fiscal quarter immediately preceding the reset election (which amount we refer to as the “reset minimum quarterly distribution”) and the target distribution levels will be reset to correspondingly higher levels based on percentage increases above the reset minimum quarterly distribution. If Royal elects to reset the target distribution levels, it will be entitled to receive a number of common units equal to the number of common units that would have entitled the holder to an aggregate quarterly cash distribution for the quarter prior to the reset election equal to the distribution on the incentive distribution rights for the quarter prior to the reset election.

We anticipate that Royal would exercise this reset right in order to facilitate acquisitions or internal growth projects that would not be sufficiently accretive to cash distributions per unit without such conversion. However, Royal may transfer the incentive distribution rights at any time. It is possible that Royal or a transferee could exercise this reset election at a time when we are experiencing declines in our aggregate cash distributions or at a time when the holders of the incentive distribution rights expect that we will experience declines in our aggregate cash distributions in the foreseeable future. In such situations, the holders of the incentive distribution rights may be experiencing, or may expect to experience, declines in the cash distributions it receives related to the incentive distribution rights and may therefore desire to be issued our common units rather than retain the right to receive incentive distributions based on the initial target distribution levels. As a result, a reset election may cause our common unitholders to experience reduction in the amount of cash distributions that they would have otherwise received had we not issued new common units to the holders of the incentive distribution rights in connection with resetting the target distribution levels. Please read “How We Make Distributions—Incentive Distribution Right Holders’ Right to Reset Incentive Distribution Levels.”

Holders of our common units have limited voting rights and are not entitled to elect our general partner or its directors, which could reduce the price at which our common units will trade.

Unlike the holders of common stock in a corporation, unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management’s decisions regarding our business. Unitholders will have no right on an annual or ongoing basis to elect our general partner or its board of directors.

The board of directors of our general partner, including the independent directors, is chosen entirely by Royal, as a result of it owning our general partner, and not by our unitholders. Please read “Management—Management of Royal Resources Partners LP” and “Certain Relationships and Related Party Transactions.” Unlike publicly traded corporations, we will not conduct annual meetings of our unitholders to elect directors or conduct other matters routinely conducted at annual meetings of stockholders of corporations. As a result of these limitations, the price at which the common units will trade could be diminished because of the absence or reduction of a takeover premium in the trading price.

Even if holders of our common units are dissatisfied, they cannot initially remove our general partner without its consent.

If our unitholders are dissatisfied with the performance of our general partner, they will have limited ability to remove our general partner. Unitholders initially will be unable to remove our general partner without its consent because affiliates of our general partner will own sufficient units upon the completion of this offering to be able to prevent its removal. The vote of the holders of at least 66 2/3% of all outstanding common and subordinated units voting together as a singled class is required to remove our general partner. Following the closing of this offering, Royal will own % of our common and subordinated units (or % of our common units, if the underwriters exercise their option to purchase additional common units in full).

In addition, any vote to remove our general partner during the subordination period must provide for the election of a successor general partner by the holders of a majority of the common units and a majority of the subordinated units, voting as separate classes. This will provide Royal the ability to prevent the removal of our general partner.

Our partnership agreement restricts the voting rights of unitholders owning 20% or more of our common units (other than our general partner and its affiliates and permitted transferees).

Our partnership agreement restricts unitholders’ voting rights by providing that any units held by a person that owns 20% or more of any class of units then outstanding, other than our general partner, its affiliates, their transferees and persons who acquired such units with the prior approval of the board of directors of our general partner, may not vote on any matter.

Cost reimbursements due to our general partner and its affiliates for services provided to us or on our behalf will reduce cash available for distribution to our unitholders. Our partnership agreement does not set a limit on the amount of expenses for which our general partner and its affiliates, including Riverbend and Blackstone, may be reimbursed. The amount and timing of such reimbursements will be determined by our general partner.

Prior to making any distribution on the common units, we will reimburse our general partner and its affiliates for all expenses they incur and payments they make on our behalf. Our partnership agreement does not set a limit on the amount of expenses for which our general partner and its affiliates may be reimbursed. These expenses include salary, bonus, incentive compensation and other amounts paid to persons who perform services for us or on our behalf and expenses allocated to our general partner by its affiliates. Our partnership agreement provides that our general partner will determine the expenses that are allocable to us. The reimbursement of expenses and payment of fees, if any, to our general partner and its affiliates will reduce the amount of cash available for distribution to our unitholders. Please read “Cash Distribution Policy and Restrictions on Distributions.”

Our general partner interest or the control of our general partner may be transferred to a third party without unitholder consent.

Our general partner may transfer its general partner interest to a third party without the consent of our unitholders. Furthermore, our partnership agreement does not restrict the ability of the owner of our general

partner to transfer its membership interests in our general partner to a third party. After any such transfer, the new member or members of our general partner would then be in a position to replace the board of directors and executive officers of our general partner with its own designees and thereby exert significant control over the decisions taken by the board of directors and executive officers of our general partner. This effectively permits a “change of control” without the vote or consent of the unitholders.

The incentive distribution rights may be transferred to a third party without unitholder consent.

Our Sponsor may transfer the incentive distribution rights to a third party at any time without the consent of our unitholders. If our Sponsor transfers the incentive distribution rights to a third party, our Sponsor would not have the same incentive to grow our partnership and increase quarterly distributions to unitholders over time. For example, a transfer of incentive distribution rights by our Sponsor could reduce the likelihood of our Sponsor accepting offers made by us relating to assets owned by our Sponsor, as it would have less of an economic incentive to grow our business, which in turn would impact our ability to grow our asset base.

If we distribute cash from capital surplus, which is analogous to a return of capital, our minimum quarterly distribution will be reduced proportionately, and the distribution thresholds after which the incentive distribution rights entitle our Sponsor to an increased percentage of distributions will be proportionately decreased.

Our cash distributions will be characterized as coming from either operating surplus or capital surplus. Operating surplus is defined in our partnership agreement, and generally means amounts we receive from operating sources, such as sale of our oil and natural gas production, less operating expenditures, such as production costs and taxes, and less estimated average maintenance capital expenditures, which are generally amounts we estimate we will need to spend in the future to maintain our production levels over the long term. Capital surplus is defined in our partnership agreement, and generally would result from cash received from non-operating sources such as sales of properties and issuances of debt and equity interests. Cash representing capital surplus, therefore, is analogous to a return of capital. Distributions of capital surplus are made to our unitholders and will result in a decrease in our minimum quarterly distribution. For a more detailed description of operating surplus, capital surplus and the effect of distributions from capital surplus, please read “The Partnership Agreement—Cash Distributions.”

Our partnership agreement allows us to add to operating surplus $ million. As a result, a portion of this amount, which is analogous to a return of capital, may be distributed to the general partner and its affiliates, as holders of incentive distribution rights, rather than to holders of common units as a return of capital.

Our general partner will be required to deduct estimated maintenance capital expenditures from our operating surplus, which may result in less cash available for distribution to unitholders from operating surplus than if actual maintenance capital expenditures were deducted.

Maintenance capital expenditures are those capital expenditures required to maintain our long-term production or asset base, including expenditures to replace our oil and natural gas reserves, through the acquisition of a new oil or natural gas property. Our partnership agreement requires our general partner to deduct estimated, rather than actual, maintenance capital expenditures from operating surplus in determining cash available for distribution from operating surplus. The amount of estimated maintenance capital expenditures deducted from operating surplus will be subject to review and change by our conflicts committee at least once a year. Our partnership agreement does not cap the amount of maintenance capital expenditures that our general partner may estimate. In years when our estimated maintenance capital expenditures are higher than actual maintenance capital expenditures, the amount of cash available for distribution to unitholders from operating surplus will be lower than if actual maintenance capital expenditures had been deducted from operating surplus. On the other hand, if our general partner underestimates the appropriate level of estimated maintenance capital expenditures, we will have more cash available for distribution from operating surplus in the short term but will

have less cash available for distribution from operating surplus in future periods when we have to increase our estimated maintenance capital expenditures to account for the previous underestimation.

Due to our expectation that existing and planned development of our initial assets by our operators will lead to inclining production and revenues for at least the next several years, we have estimated that the amount of maintenance capital expenditures currently necessary to maintain our production over the next several years is negligible. Therefore, we will not initially reduce our operating surplus by any estimated maintenance capital expenditures. However, the board of directors of our general partner may in the future determine that capital expenditures are required to be made to maintain our production or asset base over the long term, in which case, we will be required to deduct an estimated amount of such capital expenditures from our operating surplus in each quarter. This would reduce the amount of cash available for distribution to our unitholders. As a result of our decision not to initially deduct any estimated maintenance capital expenditures in anticipation of future reserve replacement, the amount of estimated maintenance capital expenditures that we will have to deduct from operating surplus in the future to maintain our asset base will be more than it otherwise would have been (and our distributable cash flow at such time will be less than it otherwise would have been) had we started deducting estimated maintenance capital expenditures immediately following the closing of this offering.

Unitholders may have liability to repay distributions and in certain circumstances may be personally liable for the obligations of the partnership.

Under certain circumstances, unitholders may have to repay amounts wrongfully returned or distributed to them. Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act (the “Delaware Act”), we may not make a distribution to our unitholders if the distribution would cause our liabilities to exceed the fair value of our assets. Delaware law provides that for a period of three years from the date of the impermissible distribution, limited partners who received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable to the limited partnership for the distribution amount. Liabilities to partners on account of their partnership interests and liabilities that are non-recourse to the partnership are not counted for purposes of determining whether a distribution is permitted.

A limited partner that participates in the control of our business within the meaning of the Delaware Act may be held personally liable for our obligations under the laws of Delaware, to the same extent as our general partner. This liability would extend to persons who transact business with us under the reasonable belief that the limited partner is a general partner. Neither our partnership agreement nor the Delaware Act specifically provides for legal recourse against our general partner if a limited partner were to lose limited liability through any fault of our general partner. Please read “The Partnership Agreement—Limited Liability.”

Unitholders will incur immediate and substantial dilution in net tangible book value per common unit.

The assumed initial public offering price of $ per common unit (the mid-point of the price range set forth on the cover page of this prospectus) exceeds our pro forma net tangible book value of $ per common unit. Based on the assumed initial public offering price of $ per common unit, unitholders will incur immediate and substantial dilution of $ per common unit. This dilution results primarily because the assets contributed to us by affiliates of our general partner are recorded at their historical cost in accordance with GAAP, and not their fair value. Please read “Dilution.”

Our general partner has a call right that may require unitholders to sell their common units at an undesirable time or price.

If at any time our general partner and its affiliates own more than 80% of the common units, our general partner will have the right, which it may assign to any of its affiliates or to us, but not the obligation, to acquire all, but not less than all, of the common units held by unaffiliated persons at a price equal to the greater of (1) the average of the daily closing price of the common units over the 20 trading days preceding the date three days before notice of exercise of the call right is first mailed and (2) the highest per-unit price paid by our general

partner or any of its affiliates for common units during the 90-day period preceding the date such notice is first mailed. As a result, unitholders may be required to sell their common units at an undesirable time or price and may not receive any return or a negative return on their investment. Unitholders may also incur a tax liability upon a sale of their units. Our general partner is not obligated to obtain a fairness opinion regarding the value of the common units to be repurchased by it upon exercise of the limited call right. There is no restriction in our partnership agreement that prevents our general partner from causing us to issue additional common units and then exercising its call right. If our general partner exercised its limited call right, the effect would be to take us private and, if the units were subsequently deregistered, we would no longer be subject to the reporting requirements of the Securities Exchange Act of 1934 (the “Exchange Act”). Upon consummation of this offering, and assuming no exercise of the underwriters’ option to purchase additional common units, Royal will own % of our common units. For additional information about the limited call right, please read “The Partnership Agreement—Limited Call Right.”

We may issue additional common units and other equity interests without unitholder approval, which would dilute existing unitholder ownership interests.

Under our partnership agreement, we are authorized to issue an unlimited number of additional interests, including common units, without a vote of the unitholders. The issuance by us of additional common units or other equity interests of equal or senior rank will have the following effects:

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the proportionate ownership interest of unitholders in us immediately prior to the issuance will decrease;

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the amount of cash distributions on each common unit may decrease;

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because a lower percentage of total outstanding units will be subordinated units, the risk that a shortfall in the payment of the minimum quarterly distribution will be borne by our common unitholders will increase;

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the ratio of our taxable income to distributions may increase;

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the relative voting strength of each previously outstanding common unit may be diminished; and

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the market price of the common units may decline.

Please read “The Partnership Agreement—Issuance of Additional Interests.”

There are no limitations in our partnership agreement on our ability to issue units ranking senior to the common units.

In accordance with Delaware law and the provisions of our partnership agreement, we may issue additional partnership interests that are senior to the common units in right of distribution, liquidation and voting. The issuance by us of units of senior rank may (i) reduce or eliminate the amount of cash available for distribution to our common unitholders; (ii) diminish the relative voting strength of the total common units outstanding as a class; or (iii) subordinate the claims of the common unitholders to our assets in the event of our liquidation.

The market price of our common units could be adversely affected by sales of substantial amounts of our common units in the public or private markets, including sales by Royal or other large holders.

After this offering, we will have common units and subordinated units outstanding, including the common units that we are selling in this offering that may be resold in the public market immediately. All of the subordinated units will convert into common units on a one-for-one basis at the end of the subordination period. All of the common units that are issued to Royal will be subject to resale restrictions under a 180-day lock-up agreement with the underwriters. Each of the lock-up agreements with the underwriters may be waived in the discretion of certain of the underwriters. Sales by Royal or other large holders of a substantial number of our common units in the public markets following this offering, or the perception that such sales might occur, could have a material adverse effect on the price of our common units or could impair our ability to obtain capital

through an offering of equity securities. In addition, we have agreed to provide registration rights to Royal. Under our partnership agreement, our general partner and its affiliates have registration rights relating to the offer and sale of any units that they hold. Alternatively, we may be required to undertake a future public or private offering of common units and use the net proceeds from such offering to redeem an equal number of common units held by Royal. Please read “Units Eligible for Future Sale.”

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

Prior to this offering, there has been no public market for the common units. After this offering, there will be only publicly traded common units. 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. Unitholders may not be able to resell their common units 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 the common units and limit the number of investors who are able to buy the common units.

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

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our quarterly distributions;

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our quarterly or annual earnings or those of other companies in our industry;

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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 limited partnerships and limited liability 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 distributions to our unitholders;

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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 units after this offering or changes in their recommendations and estimates of our financial performance;

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future sales of our common units; and

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the other factors described in these “Risk Factors.”

We will incur increased costs as a result of being a publicly traded partnership.

We have no history operating as a publicly traded partnership. As a publicly traded partnership, we will incur significant legal, accounting and other expenses that we did not incur prior to this offering. In addition, the

Sarbanes-Oxley Act and the Dodd-Frank Act of 2010, as well as rules implemented by the SEC and the NYSE, require, or will require, publicly traded entities to adopt various corporate governance practices that will further increase our costs. Before we are able to make distributions to our unitholders, we must first pay our expenses, including the costs of being a publicly traded partnership and other operating expenses. As a result, the amount of cash we have available for distribution to our unitholders will be affected by our expenses, including the costs associated with being a publicly traded partnership.

Following this offering, we will become subject to the public reporting requirements of the Exchange Act. We expect these requirements will increase certain of our legal and financial compliance costs and make compliance activities more time-consuming and costly. For example, as a result of becoming a publicly traded partnership, we are required to have at least three independent directors and adopt policies regarding internal controls and disclosure controls and procedures, including the preparation of reports on internal control over financial reporting.

We estimate that we will incur approximately $2.0 million of incremental costs per year associated with being a publicly traded partnership; however, it is possible that our actual incremental costs of being a publicly traded partnership will be higher than we currently estimate.

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

We are classified as an “emerging growth company” under Section 2(a)(19) of the Securities Act. For as long as we are an emerging growth company, which may be up to five full fiscal years, unlike other public companies, we will not be required to, among other things, (1) provide an auditor’s attestation report on management’s assessment of the effectiveness of our system of internal control over financial reporting pursuant to Section 404(b) of the Sarbanes-Oxley Act or (2) provide certain disclosure regarding executive compensation required of larger public 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 unitholders could lose confidence in our financial reporting, which would harm our business and the trading price of our units.

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 consolidated 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 partnership. 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. We must comply with Section 404 (except for the requirement for an auditor’s attestation report) beginning with our fiscal year ending December 31, 2016. Any failure to develop or maintain effective internal controls, or difficulties encountered in implementing or improving our internal controls, could harm our operating results or cause us to fail to meet our reporting obligations. Ineffective internal controls could also cause investors to lose confidence in our reported financial information, which would likely have a negative effect on the trading price of our common units.

Our independent registered public accounting firm has identified a material weakness in our internal control over financial reporting that, if not properly remediated, could result in material misstatements in our financial statements in future periods.

Although we did not engage our independent registered public accounting firm to conduct an audit of our internal control over financial reporting, in connection with the audits of our historical financial statements as of and for the years ended December 31, 2014 and 2013, our independent registered public accounting firm informed us that it identified a material weakness relating to our internal control over financial reporting under standards established by the PCAOB. The PCAOB defines a material weakness as a deficiency, or a combination of deficiencies, in internal control over financial reporting such that there is a reasonable possibility that a material misstatement of the company’s annual or interim financial statements will not be prevented or detected on a timely basis. A deficiency in internal control exists when the design or operation of a control does not allow management or employees, in the normal course of performing their assigned functions, to prevent or detect misstatements on a timely basis.

We restated our audited consolidated financial statements for the year ended December 31, 2014. The restatement was due to omitted disclosure regarding the two classes of ownership and the misclassification of proved developed non-producing reserves as proved undeveloped reserves rather than proved developed reserves in the unaudited supplemental oil and gas information in the footnotes to our financial statements. Accordingly, our independent registered public accounting firm identified a material weakness related to adjustments made in connection with their audits of our financial statements in the area of disclosure controls for an omitted disclosure related to ownership interests and supplemental information on oil and gas operations. The material weakness resulted in adjustments to our footnotes for the periods that were the subject of these audits.

We have taken and will take a number of actions to remediate this material weakness including, but not limited to, dedicating existing personnel and hiring new personnel who are charged with the responsibility of developing and maintaining an appropriate accounting process and system of internal controls over financial reporting, including an augmented review process. We cannot assure you when we will remediate such weakness, nor can we be certain of whether additional actions will be required or the costs of any such actions.

We may need to take additional measures to fully mitigate these issues, and the measures we have taken, and expect to take, to improve our internal controls may not be sufficient to address the issues identified, to ensure that our internal controls are effective or to ensure that the identified material weakness or significant deficiencies or other material weaknesses or deficiencies will not result in a material misstatement of our annual or interim financial statements. In addition, other material weaknesses or deficiencies may be identified in the future. If we are unable to correct material weaknesses or deficiencies in internal controls in a timely manner, our ability to record, process, summarize and report financial information accurately and within the time periods specified in the rules and forms of the SEC will be adversely affected. This failure could negatively affect the market price and trading liquidity of our common units, cause investors to lose confidence in our reported financial information, subject us to civil and criminal investigations and penalties, and generally materially and adversely impact our business and financial condition.

The NYSE does not require a publicly traded partnership like us to comply with certain of its corporate governance requirements.

We intend to apply to list our common units on the NYSE. Because we will be a publicly traded partnership, the NYSE does not require us to have a majority of independent directors on our general partner’s board of directors or to establish a compensation committee or a nominating and corporate governance committee. Accordingly, unitholders will not have the same protections afforded to stockholders of certain corporations that are subject to all of the NYSE’s corporate governance requirements. Please read “Management.”

Our partnership agreement includes exclusive forum, venue and jurisdiction provisions. By purchasing a common unit, a limited partner is irrevocably consenting to these provisions regarding claims, suits, actions or proceedings and submitting to the exclusive jurisdiction of Delaware courts.

Our partnership agreement is governed by Delaware law. Our partnership agreement includes exclusive forum, venue and jurisdiction provisions designating Delaware courts as the exclusive venue for most claims, suits, actions and proceedings involving us or our officers, directors and employees. Please read “The Partnership Agreement—Applicable Law; Forum, Venue and Jurisdiction.” By purchasing a common unit, a limited partner is irrevocably consenting to these provisions regarding claims, suits, actions or proceedings and submitting to the exclusive jurisdiction of Delaware courts. If a dispute were to arise between a limited partner and us or our officers, directors or employees, the limited partner may be required to pursue its legal remedies in Delaware which may be an inconvenient or distant location and which is considered to be a more corporate-friendly environment.

Our general partner may amend our partnership agreement, as it determines necessary or advisable, to permit the general partner to redeem the units of certain unitholders.

Our general partner may amend our partnership agreement, as it determines necessary or advisable, to obtain proof of the U.S. federal income tax status and/or the nationality, citizenship or other related status of our limited partners (and their owners, to the extent relevant) and to permit our general partner to redeem the units held by any person (i) whose tax status has or is reasonably likely to have a material adverse effect on the maximum applicable rates chargeable to our customers, (ii) whose nationality, citizenship or related status creates substantial risk of cancellation or forfeiture of any of our property and/or (iii) who fails to comply with the procedures established to obtain such proof. The redemption price in the case of such a redemption will be the average of the daily closing prices per unit for the 20 consecutive trading days immediately prior to the date set for redemption. Please read “The Partnership Agreement—Non-Taxpaying Holders; Redemption” and “The Partnership Agreement—Non-Citizen Assignees; Redemption.”

Tax Risks to Common Unitholders

In addition to reading the following risk factors, you should read “Material U.S. Federal Income Tax Consequences” for a more complete discussion of the expected material federal income tax consequences of owning and disposing of common units.

Our tax treatment depends on our status as a partnership for federal income tax purposes, as well as our not being subject to a material amount of entity-level taxation by individual states. If the IRS were to treat us as a corporation for federal income tax purposes or we were to become subject to entity-level taxation for state tax purposes, then our cash available for distribution to you could be substantially reduced.

The anticipated after-tax economic benefit of an investment in our common units depends largely on our being treated as a partnership for federal income tax purposes.

Despite the fact that we are organized as a limited partnership under Delaware law, we would be treated as a corporation for U.S. federal income tax purposes unless we satisfy a “qualifying income” requirement. Based upon our current operations, we believe we satisfy the qualifying income requirement. However, we have not requested, and do not plan to request, a ruling from the IRS on this or any other matter affecting us. Failing to meet the qualifying income requirement or a change in current law could cause us to be treated as a corporation for U.S. federal income tax purposes or otherwise subject us to taxation as an entity.

If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our taxable income at the corporate tax rate, which is currently a maximum of 35%. Distributions to you would generally be taxed again as corporate distributions, and no income, gains, losses or deductions would flow through to you. Because a tax would be imposed upon us as a corporation, our cash available for distribution to

you would be substantially reduced. In addition, changes in current state law may subject us to additional entity-level taxation by individual states. Because of widespread state budget deficits and other reasons, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise and other forms of taxation. Imposition of any such taxes may substantially reduce the cash available for distribution to you. Therefore, treatment of us as a corporation or the assessment of a material amount of entity-level taxation would result in a material reduction in the anticipated cash flow and after-tax return to the unitholders, likely causing a substantial reduction in the value of our common units.

The tax treatment of publicly traded partnerships or an investment in our common units could be subject to potential legislative, judicial or administrative changes or differing interpretations, possibly applied on a retroactive basis.

The present U.S. federal income tax treatment of publicly traded partnerships, including us, or an investment in our common units may be modified by administrative, legislative or judicial changes or differing interpretations at any time. For example, the Obama administration’s budget proposal for fiscal year 2016 recommends that certain publicly traded partnerships earning income from activities related to fossil fuels be taxed as corporations beginning in 2021. From time to time, members of Congress propose and consider substantive changes to the existing U.S. federal income tax laws that affect publicly traded partnerships. One such legislative proposal would have eliminated the qualifying income exception to the treatment of all publicly traded partnerships as corporations upon which we rely for our treatment as a partnership for U.S. federal income tax purposes. In addition, on May 5, 2015, the Department of the Treasury issued proposed Treasury Regulations addressing the application of the “qualifying income” requirement in certain specified circumstances. We do not expect that such proposed Treasury Regulations, if finalized in their current form, would negatively impact our ability to satisfy the “qualifying income” requirement, however, there can be no assurance that future regulations would not impact our ability to satisfy such requirement. We are unable to predict whether any of these changes, or other proposals, will be reintroduced or will ultimately be enacted. Any such changes could negatively impact the value of an investment in our common units. Any modification to U.S. federal income tax laws may be applied retroactively and could make it more difficult or impossible for us to meet the qualifying income requirement to be treated as a partnership for U.S. federal income tax purposes. For further discussion of the importance of our treatment as a partnership for federal income purposes, please read “Material U.S. Federal Income Tax Consequences—Taxation of the Partnership—Partnership Status.”

If the IRS were to contest the federal income tax positions we take, it may adversely impact the market for our common units, and the costs of any such contest would reduce cash available for distribution to our unitholders.

We have not requested a ruling from the IRS with respect to our treatment as a partnership for federal income tax purposes or any other matter affecting us or our unitholders. The IRS may adopt positions that differ from the conclusions of our counsel expressed in this prospectus or from the positions we take. It may be necessary to resort to administrative or court proceedings to sustain some or all of our counsel’s conclusions or the positions we take. A court may not agree with some or all of our counsel’s conclusions or positions we take. Any contest with the IRS may materially and adversely impact the market for our common units and the price at which they trade. Moreover, the costs of any contest between us and the IRS will result in a reduction in cash available for distribution to our unitholders and thus will be borne indirectly by our unitholders.

Even if you do not receive any cash distributions from us, you will be required to pay taxes on your share of our taxable income.

You will be required to pay federal income taxes and, in most cases, state and local income taxes on your share of our taxable income, whether or not you receive cash distributions from us. You may not receive cash distributions from us equal to your share of our taxable income or even equal to the actual tax due from you with respect to that income.

Tax gain or loss on disposition of our common units could be more or less than expected.

If you sell your common units, you will recognize a gain or loss equal to the difference between the amount realized and your tax basis in those common units. Because distributions in excess of your allocable share of our net taxable income decrease your tax basis in your common units, the amount, if any, of such prior excess distributions with respect to the units you sell will, in effect, become taxable income to you if you sell such units at a price greater than your tax basis in those units, even if the price you receive is less than your original cost. Furthermore, a substantial portion of the amount realized, whether or not representing gain, may be taxed as ordinary income due to potential recapture items, including depreciation and depletion recapture. In addition, because the amount realized includes a unitholder’s share of our nonrecourse liabilities, if you sell your common units, you may incur a tax liability in excess of the amount of cash you receive from the sale. Please read “Material U.S. Federal Income Tax Consequences—Disposition of Units—Recognition of Gain or Loss” for a further discussion of the foregoing.

Tax-exempt entities and non-U.S. persons face unique tax issues from owning our common units that may result in adverse tax consequences to them.

Investment in common units by tax-exempt entities, such as employee benefit plans and individual retirement accounts (known as IRAs), and non-U.S. persons raises issues unique to them. For example, a portion of our income allocated to organizations that are exempt from federal income tax, including IRAs and other retirement plans, may be unrelated business taxable income and may be taxable to them. Distributions to non-U.S. persons will be subject to withholding taxes imposed at the highest effective tax rate applicable to such non-U.S. persons, and each non-U.S. person may be required to file United States federal tax returns and pay tax on their share of our taxable income if it is treated as effectively connected income. If you are a tax-exempt entity or a non-U.S. person, you should consult your tax advisor before investing in our common units. Please read “Material U.S. Federal Income Tax Consequences—Tax Exempt Organizations and Other Investors.”

We will treat each purchaser of common units as having the same tax benefits without regard to the common units actually purchased. The IRS may challenge this treatment, which could adversely affect the value of the common units.

Because, among other reasons, we cannot match transferors and transferees of our common units, we will adopt depreciation and amortization positions that may not conform to all aspects of existing Treasury Regulations. Our counsel is unable to opine as to the validity of this approach. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to you. It also could affect the timing of these tax benefits or the amount of gain from your sale of common units and could have a negative impact on the value of our common units or result in audit adjustments to your tax returns. Please read “Material U.S. Federal Income Tax Consequences—Tax Consequences of Unit Ownership—Section 754 Election” for a further discussion of the effect of the depreciation and amortization positions we adopted.

We will prorate our items of income, gain, loss and deduction between transferors and transferees of our common units each month based upon the ownership of our common units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The IRS may challenge this treatment, which could change the allocation of items of income, gain, loss and deduction among our unitholders.

We will prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The use of this proration method may not be permitted under existing Treasury regulations, and, accordingly, our counsel is unable to opine as to the validity of this method. The U.S. Treasury Department has issued proposed Treasury Regulations that provide a safe harbor pursuant to which a publicly traded partnership may use a similar monthly simplifying convention to allocate tax items among transferor and transferee unitholders. Nonetheless, the proposed regulations do not specifically authorize the use of the proration method we have adopted. If the IRS were to challenge our proration method or new Treasury

Regulations were issued, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders. Please read “Material U.S. Federal Income Tax Consequences—Disposition of Units—Allocations Between Transferors and Transferees.”

A unitholder whose units are the subject of a securities loan (e.g., a loan to a “short seller” to cover a short sale of units) may be considered to have disposed of those units. If so, the unitholder would no longer be treated for tax purposes as a partner with respect to those units during the period of the loan and could recognize gain or loss from the disposition.

Because there are no specific rules governing the U.S. federal income tax consequence of loaning a partnership interest, a unitholder whose units are the subject of a securities loan may be considered to have disposed of the loaned units. In that case, the unitholder may no longer be treated for tax purposes as a partner with respect to those units during the period of the loan to the short seller and the unitholder may recognize gain or loss from such disposition. Moreover, during the period of the loan, any of our income, gain, loss or deduction with respect to those units may not be reportable by the unitholder and any cash distributions received by the unitholder as to those units could be fully taxable as ordinary income. Our counsel has not rendered an opinion regarding the treatment of a unitholder where common units are loaned to a short seller to effect a short sale of common units. Unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a securities loan are urged to modify any applicable brokerage account agreements to prohibit their brokers from borrowing their units.

We may adopt certain valuation methodologies that could result in a shift of income, gain, loss and deduction between the general partner and the unitholders. The IRS may challenge this treatment, which could adversely affect the value of the common units.

When we issue additional units or engage in certain other transactions, we will determine the fair market value of our assets and allocate any unrealized gain or loss attributable to our assets to the capital accounts of our unitholders and our general partner. Our methodology may be viewed as understating the value of our assets. In that case, there may be a shift of income, gain, loss and deduction between certain unitholders and the general partner, which may be unfavorable to such unitholders. The IRS may challenge our valuation methods, or our allocation of the Section 743(b) adjustment attributable to our tangible and intangible assets, and allocations of income, gain, loss and deduction between the general partner and certain of our unitholders.

A successful IRS challenge to these methods or allocations could adversely affect the amount of taxable income or loss being allocated to our unitholders. It also could affect the amount of gain from our unitholders’ sale of common units and could have a negative impact on the value of the common units or result in audit adjustments to our unitholders’ tax returns without the benefit of additional deductions.

The sale or exchange of 50% or more of our capital and profits interests during any twelve-month period will result in the termination of our partnership for federal income tax purposes.

We will be considered to have terminated for federal income tax purposes if there is a sale or exchange of 50% or more of the total interests in our capital and profits within a twelve-month period. Immediately following this offering, affiliates of Royal will directly and indirectly own more than % of the total interests in our capital and profits. Therefore, a transfer by affiliates of Royal of all or a portion of their interests in us could result in a termination of our partnership for federal income tax purposes. Our termination would, among other things, result in the closing of our taxable year for all unitholders, and in the event we acquire depreciable property in the future, could result in deferral of depreciation deductions allowable in computing our taxable income. In the case of a unitholder reporting on a taxable year other than the calendar year, the closing of our taxable year may also result in more than twelve months of our taxable income or loss being includable in his taxable income for the year of termination. Our termination currently would not affect our classification as a partnership for federal income tax purposes, but instead, after our termination we would be treated as a new

partnership for federal income tax purposes. If treated as a new partnership, we must make new tax elections and could be subject to penalties if we are unable to determine that a termination occurred. Please read “Material U.S. Federal Income Tax Consequences—Disposition of Units—Constructive Termination” for a discussion of the consequences of our termination for federal income tax purposes.

Changes to current federal tax laws may affect unitholders’ ability to take certain tax deductions.

Substantive changes to the existing federal income tax laws have been proposed that, if adopted, would affect, among other things, the ability to take certain operations-related deductions, including deductions for intangible drilling and deductions for U.S. production activities. We are unable to predict whether any changes, or other proposals to such laws, ultimately will be enacted. In the event we acquire property subject to such deductions in the future, any such changes could negatively impact the value of an investment in our units.

You may be subject to state and local taxes and return filing requirements in states where you do not live as a result of investing in our common units.

In addition to federal income taxes, you may be subject to other taxes, including state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we conduct business or own property now or in the future, even if you do not live in any of those jurisdictions. We will initially own assets and conduct business in Texas, which currently imposes income taxes on corporations and other entities but does not impose a personal income tax. As we make acquisitions or expand our business, we may own assets or conduct business in additional states or foreign jurisdictions that impose a personal income tax. You may be required to file state and local income tax returns and pay state and local income taxes in these jurisdictions. Further, you may be subject to penalties for failure to comply with those requirements. It is your responsibility to file all U.S. federal, foreign, state and local tax returns. Our counsel has rendered an opinion solely with respect to certain federal income tax consequences of an investment in our common units. Our counsel’s opinion does not address any other tax consequences with respect to an investment in our common units except those specified herein. Please read “Material U.S. Federal Income Tax Consequences” for further discussion of the scope of our counsel’s opinion.

USE OF PROCEEDS

We intend to use the estimated net proceeds of approximately $ million from this offering (based on an assumed initial offering price of $ per common unit, the mid-point of the price range set forth on the cover page of this prospectus), after deducting the estimated underwriting discount and offering expenses payable by us, to repay all $ million in existing indebtedness and make a $ million distribution to our Sponsor.

Our existing indebtedness consists of $78 million outstanding under our credit facility, and $30 million outstanding under our second lien facility. Borrowings under our credit facilities are at a blended, average interest rate of 4.7% per annum. The outstanding principal on our credit facility is due October 2017 and the outstanding principal on our second lien facility is due April 2018.

If and to the extent the underwriters exercise their option to purchase additional common units, the number of common units purchased by the underwriters pursuant to any exercise will be sold to the public, and any remaining common units not purchased by the underwriters pursuant to any exercise of the option will be issued to our Sponsor at the expiration of the option period for no additional consideration. If the underwriters exercise their option to purchase additional common units in full, the additional net proceeds to us would be approximately $ million, after deducting underwriting discounts. We will use any net proceeds from the exercise of the underwriters’ option to purchase additional common units from us to make an additional cash distribution to our Sponsor.

CAPITALIZATION

The following table shows our cash and cash equivalents and capitalization as of March 31, 2015:

•

on an actual basis for our predecessor; and

•

on an as adjusted basis to reflect the offering and the other formation transactions described under “Summary—Formation Transactions and Structure,” the application of the net proceeds from this offering as described under “Use of Proceeds” and our entry into a new revolving credit facility.

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


	As of March 31, 2015
	Actual		As Adjusted
	(in thousands)
Cash and cash equivalents(1)	$	14,320	$

Long-term debt:
Credit facility(1)(2)	$	78,000		—
Second lien facility(2)	$	30,000		—

Total long-term debt	$	108,000		—
Members’ equity/Partners’ capital:
Members’ equity	$	143,586	$	—
Common unitholders—public		—
Common unitholders—Royal		—
Subordinated unitholders—Royal		—

Total members’ equity/partners’ capital	$	143,586	$

Total capitalization	$	251,586	$

(1)	As of June 1, 2015, our cash and cash equivalents were $7.1 million and our outstanding borrowings under our credit facility and second lien facility were $78.0 million and $30 million, respectively.

(2)	In connection with the repayment of our credit facility and second lien facility with the proceeds of this offering, we will recognize a one time non-cash charge of $0.5 million related to unamortized debt issuance costs.

DILUTION

Purchasers of common units offered by this prospectus will suffer immediate and substantial dilution in net tangible book value per unit. Dilution in net tangible book value per unit represents the difference between the amount per unit paid by purchasers of our common units in this offering and the pro forma net tangible book value per unit immediately after this offering. After giving effect to the sale of common units in this offering at an initial public offering price of $ per common unit, and after deduction of the estimated underwriting discount and estimated offering expenses payable by us, our pro forma net tangible book value as of March 31, 2015 would have been approximately $ million, or $ per unit. This represents an immediate increase in net tangible book value of $ per unit to our existing unitholders and an immediate pro forma dilution of $ per unit to purchasers of common units in this offering. The following table illustrates this dilution on a per unit basis:


Assumed initial public offering price per common unit		$
Pro forma net tangible book value per common unit before the offering(1)	$
Increase in net tangible book value per common unit attributable to purchasers in the offering

Less: Pro forma net tangible book value per common unit after the offering(2)

Immediate dilution in net tangible book value per common unit to purchasers in the offering		$

(1)	Determined by dividing the pro forma net tangible book value of the contributed assets and liabilities by the number of common units to be issued to Holdings for its contribution of assets and liabilities to us.

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

The following table sets forth the number of units that we will issue and the total consideration contributed to us by Holdings and by the purchasers of our common units in this offering upon consummation of the transactions contemplated by this prospectus ($ in millions).


	Units				Total Consideration
	Number	Percent			Amount		Percent
Holdings(1)(3)				%	$				%
New investors				%	$	(2)			%

Total			100	%	$			100	%

(1)	Reflects the value of the assets to be contributed to us by Holdings recorded at historical cost.

(2)	Reflects the net proceeds of this offering after deducting the underwriting discounts and estimated offering expenses payable by us, and assumes the underwriter’s option to purchase additional common units is not exercised.

(3)	The assets contributed by our general partner and its affiliates were recorded at historical cost in accordance with GAAP. Book value of the consideration provided by the general partner and its affiliates, as of March 31, 2015, after giving effect to the formation transactions, is as follows:


		(in thousands)
Book value of net assets contributed		$
Less: Distribution to Holdings from net proceeds of this offering

Total consideration		$

CASH DISTRIBUTION POLICY AND RESTRICTIONS ON DISTRIBUTIONS

You should read the following discussion of our cash distribution policy in conjunction with the specific assumptions included in this section. 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 results of operations, you should refer to Holdings’ audited consolidated historical financial statements as of December 31, 2013 and 2014, and for the years ended December 31, 2013 and 2014 and to Holdings’ unaudited consolidated historical financial statements as of March 31, 2015 and for the three months ended March 31, 2014 and 2015 included elsewhere in this prospectus.

General

Our Cash Distribution Policy

The board of directors of our general partner will adopt a cash distribution policy pursuant to which we intend to distribute at least the minimum quarterly distribution of $ per unit ($ per unit on an annualized basis) on all of our units to the extent we have sufficient cash after the establishment of cash reserves and the payment of our expenses, including payments to our general partner and its affiliates. We expect that if we are successful in executing our business strategy, we will grow our business in a steady and sustainable manner and distribute to our unitholders a portion of any increase in our cash available for distribution resulting from such growth. Our general partner has not caused us to establish any cash reserves, and does not have any specific types of expenses for which it intends to establish reserves. We expect our general partner may cause us to establish reserves for specific purposes, such as major capital expenditures or debt service payments, or may choose to generally reserve cash in the form of excess distribution coverage from time to time for the purpose of maintaining stability or growth in our quarterly distributions. In addition, our general partner may cause us to borrow amounts to fund distributions in quarters when we generate less cash than is necessary to sustain or grow our cash distributions per unit. Our cash distribution policy reflects a judgment that our unitholders will be better served by our distributing rather than retaining our cash available for distribution.

The board of directors of our general partner may change our distribution policy at any time and from time to time. Our partnership agreement does not require us to pay cash distributions on a quarterly or other basis.

Limitations on Cash Distributions and Our Ability to Change Our Cash Distribution Policy

There is no guarantee that we will make cash distributions to our unitholders. We do not have a legal or contractual obligation to pay distributions quarterly or on any other basis or at our minimum quarterly distribution rate or at any other rate. Our cash distribution policy is subject to certain restrictions and may be changed at any time. The reasons for such uncertainties in our stated cash distribution policy include the following factors:

•

Our cash distribution policy will be subject to restrictions on distributions under our new senior secured revolving credit facility or other debt agreements that we may enter into in the future. Specifically, we anticipate that our new senior secured revolving credit agreement will contain financial tests and covenants that we must satisfy. These financial tests and covenants are described in “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Indebtedness.” Should we be unable to satisfy these restrictions or if we are otherwise in default under our credit facility, we will be prohibited from making cash distributions to you notwithstanding our stated cash distribution policy.

•

Our general partner will have the authority to cause us to establish cash reserves for the prudent conduct of our business, including for future cash distributions to our unitholders, and the establishment of or

increase in those cash reserves could result in a reduction in cash distributions from levels we currently anticipate pursuant to our stated cash distribution policy. Our partnership agreement and our cash distribution policy do not set a limit on the amount of cash reserves that our general partner may cause us to establish.

•

We are obligated under our partnership agreement to reimburse our general partner for all expenses it incurs and payments it makes on our behalf. Our partnership agreement does not set a limit on the amount of expenses for which our general partner may be reimbursed. These expenses include salary, bonus, incentive compensation and other amounts paid to persons who perform services for us or on our behalf and expenses allocated to our general partner by its affiliates. Our partnership agreement provides that our general partner will determine the expenses that are allocable to us. The reimbursement of expenses and payment of fees, if any, to our general partner will reduce the amount of cash available to pay distributions to our unitholders.

•

Even if our cash distribution policy is not modified or revoked, the amount of distributions we pay under our cash distribution policy and the decision to make any distribution is determined by our general partner.

•

Under Section 17-607 of the Delaware Act, we may not make a distribution if the distribution would cause our liabilities to exceed the fair value of our assets.

•

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

•

If and to the extent our cash available for distribution materially declines, we may reduce our quarterly distribution in order to service or repay our debt or fund capital expenditures.

•

If we make distributions out of capital surplus, as opposed to operating surplus, any such distributions would constitute a return of capital and would result in a reduction in the minimum quarterly distribution and the target distribution levels. Please read “How We Make Distributions—Adjustment to the Minimum Quarterly Distribution and Target Distribution Levels.” We do not anticipate that we will make any distributions from capital surplus.

•

Our ability to make distributions to our unitholders depends on the performance of our subsidiaries and their ability to distribute cash to us. The ability of our subsidiaries to make distributions to us may be restricted by, among other things, the provisions of future indebtedness, applicable state limited liability company laws and other laws and regulations.

Our Ability to Grow may be Dependent on Our Ability to Access External Expansion Capital

We expect to generally distribute a significant percentage of our cash from operations to our unitholders on a quarterly basis, after the establishment of cash reserves and payment of our expenses. Therefore, our growth may not be as fast as businesses that reinvest most or all of their cash to expand ongoing operations. We expect that we will rely primarily upon external financing sources, including bank borrowings and issuances of debt and equity interests, to fund our expansion capital expenditures. To the extent we are unable to finance growth externally, our cash distribution policy will significantly impair our ability to grow.

Our Minimum Quarterly Distribution

Upon completion of this offering, our partnership agreement will provide for a minimum quarterly distribution of $ per unit for each whole quarter, or $ per unit on an annualized basis. The payment of the full minimum quarterly distribution on all of the common units and subordinated units to be outstanding after completion of this offering would require us to have cash available for distribution of approximately $

million per quarter, or $ million per year. Our ability to make cash distributions at the minimum quarterly distribution rate will be subject to the factors described above under “—General—Limitations on Cash Distributions and Our Ability to Change Our Cash Distribution Policy.” The table below sets forth the amount of common units and subordinated units that will be outstanding immediately after this offering, assuming the underwriters do not exercise their option to purchase additional common units, and the cash available for distribution needed to pay the aggregate minimum quarterly distribution on all of such units for a single fiscal quarter and a four quarter period:


		Distributions
	Number of Units	One Quarter	Annualized
Publicly held common units		$	$
Common units held by Royal
Subordinated units held by Royal

Total		$	$

If and to the extent the underwriters do not exercise their option to purchase additional common units, in whole or in part, we will issue up to an additional common units to Royal at the expiration of the option for no additional consideration. If and to the extent the underwriters exercise their option to purchase additional common units, the number of common units purchased by the underwriters pursuant to any exercise will be sold to the public, and any remaining common units not purchased by the underwriters pursuant to any exercise of the option will be issued to Royal at the expiration of the option period for no additional consideration. Accordingly, the exercise of the underwriters’ option will not affect the total number of common units outstanding or the amount of cash needed to pay the minimum quarterly distribution on all units.

Royal, our Sponsor, will initially hold the incentive distribution rights, which entitle the holder to increasing percentages, up to a maximum of 25%, of the cash we distribute in excess of $ per unit per quarter.

We expect to pay our distributions on or about the last day of each of February, May, August and November to holders of record on or about the 15th day of each such month. We will adjust the quarterly distribution for the period after the closing of this offering through , 2015, based on the actual length of the period.

Subordinated Units

Royal will initially own all of our subordinated units. The principal difference between our common units and subordinated units is that for any quarter during the subordination period, holders of the subordinated units are not entitled to receive any distribution from operating surplus until the common units have received the minimum quarterly distribution from operating surplus for such quarter plus any arrearages in the payment of the minimum quarterly distribution from prior quarters. Subordinated units will not accrue arrearages. When the subordination period ends, all of the subordinated units will convert into an equal number of common units.

To the extent we do not pay the minimum quarterly distribution from operating surplus on our common units, our common unitholders will not be entitled to receive such payments in the future except during the subordination period. To the extent we have cash available for distribution from operating surplus in any future quarter during the subordination period in excess of the amount necessary to pay the minimum quarterly distribution to holders of our common units, we will use this excess cash to pay any distribution arrearages on common units related to prior quarters before any cash distribution is made to holders of subordinated units. Please read “How We Make Distributions—Subordination Period.”

Unaudited Pro Forma Cash Available for Distribution for the Year Ended December 31, 2014 and the Twelve Months Ended March 31, 2015

If we had completed this offering and the related transactions on January 1, 2014, we estimate that we would have generated $50.2 million and $48.6 million of cash available for distribution for the year ended December 31, 2014 and the twelve months ended March 31, 2015, respectively.

Our unaudited pro forma cash available for distribution for each of the year ended December 31, 2014 and the twelve months ended March 31, 2015 includes $4.4 million and $4.8 million, respectively, of general and administrative expenses as well as an incremental $2.0 million of general and administrative expenses we expect to incur as a result of becoming a publicly traded partnership. Incremental general and administrative expenses related to being a publicly traded partnership include: SEC reporting requirements, including annual and quarterly reports to unitholders, tax return and Schedule K-1 preparation and distribution, Sarbanes-Oxley Act compliance, listing fees, independent auditor fees, legal fees, investor relations activities, registrar and transfer agent fees, director and officer insurance and director compensation. These incremental general and administrative expenses are not reflected in the historical financial statements of our predecessor 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 for distribution 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 for distribution only as a general indication of the amount of cash available for distributions that we might have generated had we completed this offering on the date indicated. Our unaudited pro forma cash available for distribution should be read together with “Selected Historical Financial Data,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the audited historical financial statements and the notes to those statements included elsewhere in this prospectus.

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 for distribution that we estimate that we would have generated for the year ended December 31, 2014 and the twelve months ended March 31, 2015. All of the amounts for the year ended December 31, 2014 and the twelve months ended March 31, 2015 in the table below are estimates.


	Year Ended December 31, 2014			Twelve Months Ended March 31, 2015
	(in thousands, except per unit data) (unaudited)
Average sales prices:
Oil (per Bbl)	$	87.19		$	75.82
Natural gas liquids (per Bbl)		29.19			24.26
Natural gas (per Mcf)		4.29			4.04

Oil and Gas Revenues		67,878			67,743
Costs and Expenses:
Production and ad valorem taxes		4,431			4,022
Marketing and transportation		2,170			3,301
Amortization of royalty mineral interests in oil and natural gas properties		13,426			15,131
General and administrative expenses		4,425			4,835

Total costs and expenses		24,452			27,289

Other Expenses:
Interest expense		4,860			4,935

Net income	$	38,566		$	35,519
Adjustments to reconcile net income to Adjusted EBITDA:
Add:
Interest expense	$	4,860		$	4,935
Amortization of mineral interests		13,426			15,131

Adjusted EBITDA(1)		56,852			55,585
Adjustments to reconcile estimated Adjusted EBITDA to estimated cash available for distribution:
Less:
Cash interest expense		(4,671	)		(4,999	)
Incremental public partnership general and administrative expenses		(2,000	)		(2,000	)
Maintenance capital expenditures(2)		—			—
Expansion capital expenditures(2)		—			—

Minimum estimated cash available for distribution	$	50,181		$	48,586

Implied cash distribution based on available cash:
Distributions per unit	$			$
Distributions to(3):
Public common unitholders
Royal:
Common units
Subordinated units
Total Distributions to Royal
Total distributions to our unitholders and Royal at the minimum distribution rate	$			$

Excess cash available for distribution over minimum quarterly cash distributions	$			$

Percent of minimum quarterly distributions payable to common unitholders

Percent of minimum quarterly distributions payable to subordinated unitholders

(1)	For more information, please read “Summary—Summary Historical Financial Data—Non-GAAP Financial Measure.”

(2)

that the amount of maintenance capital expenditures currently necessary to maintain our production over the near term is negligible. However, the board of directors of our general partner may in the future determine that capital expenditures incurred in connection with acquisitions are required to be made to maintain our production over the long term, in which case, we will be required to deduct an estimated amount of such capital expenditures from our operating surplus in each quarter. This would reduce the amount of cash available for distribution.

(3)

The table reflects the number of common and subordinated units that we anticipate will be outstanding immediately following the closing of this offering, and the aggregate distribution amounts payable on those units during the forecast period at our minimum quarterly distribution rate of $ per unit assuming that the underwriters’ option to purchase additional common units has not been exercised and the additional common units subject to the underwriters’ option are issued to our Sponsor.

Estimated Cash Available for Distribution for the Twelve Months Ending June 30, 2016

During the twelve months ending June 30, 2016, we estimate that we will generate $50.8 million of cash available for distribution. In “—Assumptions and Considerations” below, we discuss the major assumptions underlying this estimate. The available cash discussed in the forecast should not be viewed as management’s projection of the actual available cash that we will generate during the twelve months ending June 30, 2016. We can give you no assurance that our assumptions will be realized or that we will generate any cash available for distribution, in which event we will not be able to pay quarterly cash distributions on our common units.

When considering our ability to generate cash available for distribution and how we calculate forecasted available cash, 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 $50.8 million of cash available for distribution for the twelve months ending June 30, 2016. 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 the management team of our general partner as of the date of its preparation, are subject to a wide variety of significant business, economic, 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 for distribution to allow us to pay the forecasted quarterly distributions on all of our outstanding common units for the twelve months ending June 30, 2016 should not be regarded as a representation by us or the underwriters or any other person that we will make such distributions. Therefore, you are cautioned not to place undue reliance on this information.

The following table shows how we calculate estimated cash available for distribution for the twelve months ending June 30, 2016. 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.”

We do not as a matter of course make public projections as to future sales, earnings, or other results. However, we prepared the prospective financial information set forth below to present the expectations regarding the ability to generate future cash flows. The accompanying prospective financial information was not prepared with a view toward public disclosure or with a view toward 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, our 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 supplement are cautioned not to place undue reliance on the prospective financial information.


	Three Months Ending September 30, 2015		Three Months Ending December 31, 2015		Three Months Ending March 31, 2016		Three Months Ending June 30, 2016		Twelve Months Ending June 30, 2016
	(in thousands, except per unit data) (unaudited)
Oil and Gas Revenues	$	14,484	$	15,239	$	16,283	$	18,256	$	64,262

Costs and Expenses:
Production and ad valorem taxes		1,115		1,172		1,252		1,404		4,943
Marketing and transportation		527		540		539		595		2,201
Amortization of royalty mineral interests in oil and natural gas properties		4,775		4,972		5,031		5,596		20,374
General and administrative expenses(1)		1,575		1,575		1,575		1,575		6,300

Total costs and expenses		7,992		8,259		8,397		9,170		33,818

Other Expenses:
Interest expense		—		—		—		—		—

Net income	$	6,493	$	6,980	$	7,886	$	9,085	$	30,444
Adjustments to reconcile net income to Adjusted EBITDA:
Add:
Interest expense	$	—	$	—	$	—	$	—	$	—
Amortization of mineral interests		4,775		4,972		5,031		5,596		20,374

Adjusted EBITDA(2)		11,267		11,952		12,917		14,682		50,818
Adjustments to reconcile estimated Adjusted EBITDA to estimated cash available for distribution:
Less:
Interest expense	$	—	$	—	$	—	$	—	$	—
Maintenance capital expenditures(3)		—		—		—		—		—
Expansion capital expenditures(3)		—		—		—		—		—

Minimum estimated cash available for distribution	$	11,267	$	11,952	$	12,917	$	14,682	$	50,818

Implied cash distribution based on available cash:
Distributions per unit	$		$		$		$		$
Distributions to(4):
Public common unitholders
Royal:
Common units
Subordinated units
Total Distributions to Royal
Total distributions to our unitholders and Royal at the minimum distribution rate	$		$		$		$		$

Excess cash available for distribution over minimum quarterly cash distributions	$		$		$		$		$
Percent of minimum quarterly distributions payable to common unitholders
Percent of minimum quarterly distributions payable to subordinated unitholders

(1)	Includes $ million of annual general and administrative expenses that we expect to incur as a result of operating as a publicly traded partnership.

(2)	For more information, please read “Summary—Summary Historical Financial Data—Non-GAAP Financial Measure.”

(3)

Maintenance capital expenditures are those capital expenditures required to maintain our long-term production or asset base, including expenditures to replace our oil and natural gas reserves, through the acquisition of new oil or natural gas properties. The allocation of capital expenditures as maintenance capital expenditures (as opposed to expansion capital expenditures) is determined by our general partner and is supported by management’s analysis of the historical and projected decline profiles of wells on the acreage underlying our assets, the current and projected production rates of such wells and wells expected to be drilled, completed and brought online, and the existing and expected development of the acreage underlying our interests by our operators. Based on this analysis, we expect that existing and expected development of our initial assets by our operators will lead to consistent or increasing production and revenues for at least the next several years, and, as a result, we have estimated that the amount of maintenance capital expenditures currently necessary to maintain our production over the near term is negligible. However, the board of directors of our general partner may in the future determine that capital expenditures incurred in connection with acquisitions are required to be made to maintain our production over the long term, in which case, we will be required to deduct an estimated amount of such capital expenditures from our operating surplus in each quarter thereafter. This would reduce the amount of cash available for distribution.

(4)

Assumptions and Considerations

Based upon the specific assumptions outlined below, we expect to generate available cash in an amount sufficient to allow us to pay $ per common unit on all of our outstanding units for the twelve months ending June 30, 2016.

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 pay distributions could be substantially less than the amount we currently estimate and could, therefore, be insufficient to allow us to pay the forecasted cash distribution, or any amount, on our outstanding common units, in which event the market price of our common units 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.

Operations and Revenue

Oil and Gas Revenues. Our revenues are a function of oil, natural gas and natural gas liquids production volumes sold and average prices received for those volumes. The mineral interests to be contributed to us upon the closing of this offering entitle us to receive an average of 1.20% from producing wells on the underlying acreage with no additional future capital or operating expenses required. Based on the production and pricing information included below, we estimate that our oil and gas revenues for the twelve months ending June 30, 2016 will be $64.3 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 ORRIs for the twelve months ending June 30, 2016:


Forecasted annual production:
Oil (Bbls)			910,997
Natural Gas (Mcf)			2,115,227
Natural gas liquids (Bbls)			257,404
Combined volumes (BOE)			1,520,939

Forecasted average daily production:
Oil (Bbl/d)			2,496
Natural gas (Mcf/d)			5,795
Natural gas liquids (Bbl/d)			705
Combined volumes (BOE/d)			4,167

We estimate that oil and natural gas production from the properties underlying our ORRIs for the twelve months ending June 30, 2016 will be 1,521 MBOE. We estimate the average daily production for the three months ended September 30, 2015, December 31, 2015, March 31, 2016 and June 30, 2016 will be 3,874 BOE/d, 4,034 BOE/d, 4,127 BOE/d and 4,591 BOE/d, respectively.

Our production forecast is based on the assumption that between March 31, 2015 and June 30, 2016, 188 wells waiting to be brought online and 213 PUD locations on our acreage will be converted to producing wells. As of March 31, 2015, we had 188 wells waiting to be brought online on our acreage. We assume these wells waiting to be brought online will be converted to producing wells upon receipt of completion crews or wellhead connections. We expect 139 of the wells to be drilled on PUD locations for which permits have been issued as of March 31, 2015 will be converted to producing wells in this period. We assume 74 of the wells to be drilled on PUD locations will be converted to producing wells at unidentified locations on our acreage based on an analysis of the concentration of assets by the operators on the acreage underlying our interests, historic permit and production trends, the average period of time from permit to first production for wells on the acreage underlying our interests, the percentage probability that permitted wells will be converted to producing wells, and forecasts, based on public statements and guidance by the operators on our acreage regarding future production, of the number of wells necessary to be drilled to achieve specified production levels.

Prices. The table below illustrates the relationship between average realized sales prices and the average of the monthly NYMEX prices as of May 1, 2015 for the twelve months ending June 30, 2016 (held constant throughout the period):


Forecasted average oil sales prices:
NYMEX-WTI oil price per Bbl	$	62.83
Differential to NYMEX-WTI oil per Bbl(1)	$	(6.49	)
Realized oil sales price per Bbl	$	56.34

Forecasted average natural gas liquids sales prices:
NYMEX-WTI oil price per Bbl	$	62.83
Differential to NYMEX-WTI oil per Bbl(1)	$	(38.96	)
Realized natural gas liquids sales price per Bbl	$	23.87

Forecasted average natural gas sales prices:
NYMEX-Henry Hub per price MMBtu	$	3.04
Differential to NYMEX-Henry Hub natural gas(1)	$	0.17
Realized natural gas sales price per Mcf	$	3.21

Total weighted average combined realized price (per BOE)	$	42.25

(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 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 forecast basis for the twelve months ending June 30, 2016:


Production taxes	$	3,108
Ad valorem taxes	$	1,835
Total production and ad valorem taxes	$	4,943
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 natural gas liquids 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 generally tied to the valuation of the oil and natural gas properties; such valuation is reasonably correlated to revenues.

Marketing and transportation expenses. We estimate that our marketing and transportation expenses for the twelve months ending June 30, 2016 will be $2.20 million. The forecasted marketing and transportation expense is based on our historical marketing and transportation expense applied to our forecasted production, which is based on our reserve reports.

Amortization of royalty mineral interests in oil and natural gas properties. We estimate that our amortization of royalty mineral interests in oil and natural gas properties for the twelve months ending June 30, 2016 will be $20.4 million. The forecasted amortization of royalty mineral interests in oil and natural gas properties is based on the production estimates in our reserve reports. The per BOE depletion rate is $13.40.

General and administrative expenses. We estimate that our general and administrative expenses for the twelve months ending June 30, 2016 will be $6.3 million. We expect that the $6.3 million will consist of $2.0 million of general and administrative expenses associated with being a publicly traded partnership and $4.3 million of general and administrative expenses incurred by our general partner and its affiliates, including Royal, that will be allocated to us for services performed on our behalf.

Interest expense. We estimate that we will have no interest expense for the twelve months ending June 30, 2016 because the new credit facility we intend to enter into in connection with the closing of this offering will have no borrowings outstanding.

Capital Expenditures

We do not anticipate incurring capital expenditures or making any acquisitions during the forecast period. Based on management’s analysis, we expect that existing and expected development of our initial assets by our operators will lead to consistent or increasing production and revenues for at least the next several years, 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 twelve months ending June 30, 2016 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;

•

the Texas Railroad Commission will continue to issue drilling permits at rates consistent with past practice;

•

our 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 Distributions

We intend to distribute aggregate quarterly distributions on our common units for the twelve months ending June 30, 2016 of $50.8 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 distribution on all our outstanding common units in respect of the four calendar quarters ending June 30, 2016 or thereafter, which may cause the market price of our common units to decline materially.

Sensitivity Analysis

Our ability to generate sufficient cash from operations to pay distributions to our unitholders 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 distributions on our common units for the twelve months ending June 30, 2016.

Production Volume Changes

The following table shows estimated cash available for distribution under production levels of 90%, 100% and 110% of the production level we have forecasted for the twelve months ending June 30, 2016.


	Percentage of Forecasted Annual Production
	90%		100%		110%
Forecasted annual production:
Oil (Bbls)		819,898		910,997		1,002,097
Natural gas (Mcf)		1,903,704		2,115,227		2,326,750
Natural gas liquids (Bbls)		231,664		257,404		283,144
Combined volumes (BOE)		1,368,845		1,520,939		1,673,033

Forecasted average daily production:
Oil (Bbl/d)		2,246		2,496		2,745
Natural gas (Mcf/d)		5,216		5,795		6,375
Natural gas liquids (Bbl/d)		635		705		776
Combined volumes (BOE/d)		3,750		4,167		4,584

Forecasted average sales prices:
NYMEX-WTI oil price per Bbl	$	62.83	$	62.83	$	62.83
Realized oil sales price per Bbl	$	56.34	$	56.34	$	56.34

NYMEX-WTI oil price per Bbl	$	62.83	$	62.83	$	62.83
Realized natural gas liquids sales price per Bbl	$	23.87	$	23.87	$	23.87

NYMEX-Henry Hub price per MMBtu	$	3.04	$	3.04	$	3.04
Realized natural gas sales price per Mcf	$	3.21	$	3.21	$	3.21

Minimum estimated cash available for distribution (in thousands):
Oil and gas revenues	$	57,835	$	64,262	$	70,688

Production and ad valorem taxes	$	4,449	$	4,943	$	5,437
Marketing and transportation expense	$	1,981	$	2,201	$	2,421

Minimum estimated cash available for distribution	$	51,406	$	57,118	$	62,830

Aggregate minimum quarterly distribution	$		$		$
Excess cash available for distribution over aggregate minimum quarterly distribution	$		$		$

Commodity Price Changes

The following table shows estimated cash available for distribution under various assumed NYMEX-WTI oil and natural gas prices for the twelve months ending June 30, 2016. 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 prices.


Forecasted annual production:
Oil (Bbls)	910,997	910,997	910,997
Natural gas (Mcf)	2,115,227	2,115,227	2,115,227
Natural gas liquids (Bbls)	257,404	257,404	257,404
Combined volumes (BOE)	1,520,939	1,520,939	1,520,939

Forecasted average daily production:
Oil (Bbl/d)	2,496	2,496	2,496
Natural gas (Mcf/d)	5,795	5,795	5,795
Natural gas liquids (Bbl/d)	705	705	705
Combined volumes (BOE/d)	4,167	4,167	4,167


	Percentage Change in Commodity Price
	90%		100%		110%
Forecasted average sales prices:
NYMEX-WTI oil price per Bbl	$	56.55	$	62.83	$	69.11
Realized oil sales price per Bbl	$	50.06	$	56.34	$	62.63

NYMEX-WTI oil price per Bbl	$	56.55	$	62.83	$	69.11
Realized natural gas liquids sales price per Bbl	$	17.59	$	23.87	$	30.15

NYMEX-Henry Hub price per MMBtu	$	2.73	$	3.04	$	3.34
Realized natural gas sales price per Mcf	$	2.91	$	3.21	$	3.51

Minimum estimated cash available for distribution:
Oil and gas revenues	$	56,278	$	64,262	$	72,246

Production and ad valorem taxes	$	4,329	$	4,943	$	5,557
Marketing and transportation expense	$	2,201	$	2,201	$	2,201

Minimum estimated cash available for distribution	$	49,748	$	57,118	$	64,488

Aggregate minimum quarterly distribution	$		$		$
Excess cash available for distribution over aggregate minimum quarterly distribution	$		$		$

HOW WE MAKE DISTRIBUTIONS

General

Cash Distribution Policy

Our partnership agreement provides that our general partner will make a determination as to whether to make a distribution, but our partnership agreement does not require us to pay distributions at any time or in any amount. Instead, the board of directors of our general partner will adopt a cash distribution policy to be effective as of the closing of this offering that will set forth our general partner’s intention with respect to the distributions to be made to unitholders. Pursuant to our cash distribution policy, within 60 days after the end of each quarter, beginning with the quarter ending , 2015, we intend to distribute to the holders of common and subordinated units on a quarterly basis at least the minimum quarterly distribution of $ per unit, or $ on an annualized basis, to the extent we have sufficient cash after establishment of cash reserves and payment of fees and expenses, including payments to our general partner and its affiliates. We will prorate the quarterly distribution for the period after the closing of this offering through , 2015.

The board of directors of our general partner may change the foregoing distribution policy at any time and from time to time, and even if our cash distribution policy is not modified or revoked, the amount of distributions paid under our policy and the decision to make any distribution is determined by our general partner. Our partnership agreement does not contain a requirement for us to pay distributions to our unitholders, and there is no guarantee that we will pay the minimum quarterly distribution, or any distribution, on the units in any quarter. However, our partnership agreement does contain provisions intended to motivate our general partner to make steady, increasing and sustainable distributions over time.

Set forth below is a summary of the significant provisions of our partnership agreement that relate to cash distributions.

Operating Surplus and Capital Surplus

General

Any distributions we make will be characterized as made from “operating surplus” or “capital surplus.” Distributions from operating surplus are made differently than cash distributions that we would make from capital surplus. Operating surplus distributions will be made to our unitholders and, if we make quarterly distributions above the first target distribution level described below, to the holder of our incentive distribution rights. We do not anticipate that we will make any distributions from capital surplus. In such an event, however, any capital surplus distribution would be made pro rata to all unitholders, but the incentive distribution rights would generally not participate in any capital surplus distributions. Any distribution from capital surplus would result in a reduction of the minimum quarterly distribution and target distribution levels and, if we reduce the minimum quarterly distribution to zero and eliminate any unpaid arrearages, thereafter capital surplus would be distributed as if it were operating surplus and the incentive distribution rights would thereafter be entitled to participate in such distributions. Please see “—Distributions From Capital Surplus.”

Operating Surplus

We define operating surplus as:

•

$ million (as described below); plus

•

all of our cash receipts after the closing of this offering, excluding cash from interim capital transactions (as defined below) and provided that cash receipts from the termination of any hedge contract prior to its stipulated settlement or termination date will be included in equal quarterly installments over the remaining scheduled life of such hedge contract had it not been terminated; plus

•

cash distributions paid in respect of equity issued (including incremental distributions on incentive distribution rights), other than equity issued in this offering, to finance all or a portion of expansion capital expenditures in

respect of the period that commences when we enter into a binding obligation for the acquisition, construction, development or expansion and ending on the earlier to occur of the date any acquisition, construction, development or expansion commences commercial service and the date that it is disposed of or abandoned; plus cash distributions paid in respect of equity issued (including incremental distributions on incentive distribution rights) to pay the construction period interest on debt incurred, or to pay construction period distributions on equity issued, to finance the expansion capital expenditures referred to above, in each case, in respect of the period that commences when we enter into a binding obligation for the acquisition, construction, development or expansion and ending on the earlier to occur of the date any acquisition, construction, development or expansion commences commercial service and the date that it is disposed of or abandoned; less

•

all of our operating expenditures (as defined below) after the closing of this offering; less

•

the amount of cash reserves established by our general partner to provide funds for future operating expenditures; less

•

all working capital borrowings not repaid within twelve months after having been incurred or repaid within such twelve month period with the proceeds of additional working capital borrowings; less

•

any cash loss realized on disposition of an investment capital expenditure.

Disbursements made, cash received (including working capital borrowings) or cash reserves established, increased or reduced after the end of a period but on or before the date on which cash or cash equivalents will be distributed with respect to such period shall be deemed to have been made, received, established, increased or reduced, for purposes of determining operating surplus, within such period if our general partner so determines. Furthermore, cash received from an interest in an entity for which we account using the equity method will not be included to the extent it exceeds our proportionate share of that entity’s operating surplus (calculated as if the definition of operating surplus applied to such entity from the date of our acquisition of such an interest without any basket similar to that described in the first bullet above). Operating surplus does not only reflect cash generated by our operations. For example, it includes a basket of $ million that will enable us, if we choose, to distribute as operating surplus cash we receive in the future from non-operating sources such as asset sales, issuances of securities and long-term borrowings that would otherwise be distributed as capital surplus. In addition, the effect of including, as described above, certain cash distributions on equity interests in operating surplus will be to increase operating surplus by the amount of any such cash distributions. As a result, we may also distribute as operating surplus up to the amount of any such cash that we receive from non-operating sources.

The proceeds of working capital borrowings increase operating surplus and repayments of working capital borrowings are generally operating expenditures, as described below, and thus reduce operating surplus when made. However, if a working capital borrowing is not repaid during the twelve-month period following the borrowing, it will be deducted from operating surplus at the end of such period, thus decreasing operating surplus at such time. When such working capital borrowing is in fact repaid, it will be excluded from operating expenditures because operating surplus will have been previously reduced by the deduction.

We define operating expenditures in our partnership agreement, and it generally means all of our cash expenditures, including, but not limited to, taxes, reimbursement of expenses to our general partner or its affiliates, payments made under hedge contracts (provided that (1) with respect to amounts paid in connection with the initial purchase of a hedge contract such amounts will be amortized over the life of the applicable hedge contract and (2) payments made in connection with the termination of any hedge contract prior to the expiration of its stipulated settlement or termination date will be included in operating expenditures in equal quarterly installments over the remaining scheduled life of such hedge contract), officer compensation, repayment of working capital borrowings, interest on indebtedness and estimated maintenance capital expenditures (as discussed in further detail below), provided that operating expenditures will not include:

•

repayment of working capital borrowings deducted from operating surplus pursuant to the penultimate bullet point of the definition of operating surplus above when such repayment actually occurs;

•

payments (including prepayments and prepayment penalties and the purchase price of indebtedness that is repurchased and cancelled) of principal of and premium on indebtedness, other than working capital borrowings;

•

expansion capital expenditures;

•

investment capital expenditures;

•

payment of transaction expenses relating to interim capital transactions;

•

distributions to our partners (including distributions in respect of our incentive distribution rights);

•

repurchases of equity interests except to fund obligations under employee benefit plans; or

•

any other expenditures or payments using the proceeds of this offering that are described in “Use of Proceeds.”

Capital Surplus

Capital surplus is defined in our partnership agreement as any cash distributed in excess of our operating surplus. Accordingly, capital surplus would generally be generated only by the following (which we refer to as “interim capital transactions”):

•

borrowings other than working capital borrowings;

•

sales of our equity interests; and

•

sales or other dispositions of assets for cash, other than inventory, accounts receivable and other assets sold in the ordinary course of business or as part of normal retirement or replacement of assets.

Characterization of Cash Distributions

Our partnership agreement provides that we treat all cash distributed as coming from operating surplus until the sum of all cash distributed since the closing of this offering (other than any distributions of proceeds of this offering) equals the operating surplus from the closing of this offering. Our partnership agreement provides that we treat any amount distributed in excess of operating surplus, regardless of its source, as distributions of capital surplus. We do not anticipate that we will make any distributions from capital surplus.

Capital Expenditures

Estimated maintenance capital expenditures reduce operating surplus, but expansion capital expenditures, actual maintenance capital expenditures and investment capital expenditures do not. Maintenance capital expenditures are those cash expenditures made to maintain our production over the long term. We expect that maintenance capital expenditures will be capital expenditures required to replace declines in annual production through the acquisition of a new royalty or mineral interest in an oil and natural gas property. Capital expenditures in connection with such acquisitions will be allocated as maintenance capital expenditures with respect to that portion of such interests acquired to replace declines in annual production as a result of natural production decline. Specifically, the allocation of capital expenditures as maintenance capital expenditures (as opposed to expansion capital expenditures) is determined by our general partner and is supported by management’s analysis of the historical and projected decline profiles of wells on the acreage underlying our assets, the current and projected production rates of such wells and wells expected to be drilled, completed and brought online, and the existing and expected development of the acreage underlying our interests by our operators. Maintenance capital expenditures will also include interest (and related fees) on debt incurred and distributions on equity issued (including incremental distributions on incentive distribution rights) to finance all or any portion of the construction, replacement, acquisition or improvement of a capital asset that is paid in respect of the period from such financing until the earlier to occur of the date that any such construction

replacement, acquisition or improvement of a capital asset begins producing in paying quantities or is placed into service, as applicable, and the date that it is abandoned or disposed of. Capital expenditures made solely for investment purposes will not be considered maintenance capital expenditures.

Because our maintenance capital expenditures can be irregular, the amount of our actual maintenance capital expenditures may differ substantially from period to period, which could cause similar fluctuations in the amounts of operating surplus and adjusted operating surplus if we subtracted actual maintenance capital expenditures from operating surplus. To address this issue, our partnership agreement will require that an estimate of the average quarterly maintenance capital expenditures necessary to maintain our production or asset base over the long term be subtracted from operating surplus each quarter as opposed to the actual amounts spent. The amount of estimated maintenance capital expenditures deducted from operating surplus is subject to review and change by our general partner’s board of directors at least once a year, provided that any change is approved by the conflicts committee of our general partner’s board of directors. The estimate will be made at least annually and whenever an event occurs that is likely to result in a material adjustment to the amount of our maintenance capital expenditures, such as a major acquisition. For purposes of calculating operating surplus, any adjustment to this estimate will be prospective only. As a result of our decision not to initially deduct any estimated maintenance capital expenditures in anticipation of future reserve replacement, the amount of estimated maintenance capital expenditures that we will have to deduct from operating surplus in the future to maintain our asset base will be more than it otherwise would have been (and our distributable cash flow at such time will be less than it otherwise would have been) had we started deducting estimated maintenance capital expenditures immediately following the closing of this offering. For a discussion of the amounts we have allocated toward estimated maintenance capital expenditures, please read “Cash Distribution Policy and Restrictions on Distributions.”

The use of estimated maintenance capital expenditures in calculating operating surplus will have the following effects:

•

it will reduce the risk that maintenance capital expenditures in any one quarter will be large enough to render operating surplus less than the minimum quarterly distribution to be paid on all the units for the quarter;

•

it will increase our ability to distribute as operating surplus cash we receive from non-operating sources;

•

in quarters where estimated maintenance capital expenditures exceed actual maintenance capital expenditures, it will be more difficult for us to raise our distribution above the minimum quarterly distribution, because the amount of estimated maintenance capital expenditures will reduce the amount of cash available for distribution from operating surplus to our unitholders, even in quarters where there are no corresponding actual capital expenditures; conversely, the use of estimated maintenance capital expenditures in calculating operating surplus will have the opposite effect for quarters in which actual maintenance capital expenditures exceed our estimated maintenance capital expenditures; and

•

it will reduce the likelihood that a large maintenance capital expenditure during a particular quarter will prevent our general partner’s affiliates from being able to convert some or all of their subordinated units to common units since the effect of an estimate is to spread the expected expense over several periods, thereby mitigating the effect of the actual payment of the expenditure on any single period.

Expansion capital expenditures are those cash expenditures made to increase our production over the long term. We expect that expansion capital expenditures will be comprised of acquisitions of new royalty or mineral interests with attributable reserves or production, to the extent such expenditures are incurred to increase our production over the long term. Capital expenditures in connection with such acquisitions will be allocated as expansion capital expenditures with respect to that portion of such interest acquired to increase our production over the long term. As noted above, the allocation of capital expenditures as expansion capital expenditures (as opposed to maintenance capital expenditures) is determined by our general partner and is supported by management’s analysis. Expansion capital expenditures will also include interest (and related fees) on debt incurred and distributions on equity issued (including incremental distributions on incentive distribution rights)

to finance all or any portion of such capital improvement during the period from such financing until the earlier to occur of the date any such capital improvement begins producing in paying quantities or is placed into service, as applicable, and the date that it is abandoned or disposed of.

Investment capital expenditures are those capital expenditures, including transaction expenses, that are neither maintenance capital expenditures nor expansion capital expenditures. Investment capital expenditures largely will consist of capital expenditures made for investment purposes. Examples of investment capital expenditures include traditional capital expenditures for investment purposes, such as purchases of securities, as well as other capital expenditures that might be made in lieu of such traditional investment capital expenditures, such as the acquisition of an asset for investment purposes or development of assets that are in excess of the maintenance of our existing operating capacity or net income, but which are not expected to expand, for more than the short term, our operating capacity or net income.

As described above, neither investment capital expenditures nor expansion capital expenditures are operating expenditures, and thus will not reduce operating surplus. Because expansion capital expenditures include interest payments (and related fees) on debt incurred to finance all or a portion of an acquisition, development or expansion in respect of a period that begins when we enter into a binding obligation for an acquisition, construction, development or expansion and ending on the earlier to occur of the date on which such acquisition, construction, development or expansion commences commercial service and the date that it is abandoned or disposed of, such interest payments also do not reduce operating surplus. Losses on disposition of an investment capital expenditure will reduce operating surplus when realized and cash receipts from an investment capital expenditure will be treated as a cash receipt for purposes of calculating operating surplus only to the extent the cash receipt is a return on principal.

Cash expenditures that are made in part for maintenance capital purposes, investment capital purposes or expansion capital purposes will be allocated as maintenance capital expenditures, investment capital expenditures or expansion capital expenditures by our general partner.

Subordination Period

General

Our partnership agreement provides that, during the subordination period (which we describe below), the common units will have the right to receive distributions from operating surplus each quarter in an amount equal to $ per common unit, which amount is defined in our partnership agreement as the minimum quarterly distribution, plus any arrearages in the payment of the minimum quarterly distribution on the common units from prior quarters, before any distributions from operating surplus may be made on the subordinated units. These units are deemed “subordinated” because for a period of time, referred to as the subordination period, the subordinated units will not be entitled to receive any distribution from operating surplus for any quarter until the common units have received the minimum quarterly distribution from operating surplus for such quarter plus any arrearages in the payment of the minimum quarterly distribution from prior quarters. Furthermore, no arrearages will be paid on the subordinated units. The practical effect of the subordinated units is to increase the likelihood that during the subordination period there will be sufficient cash from operating surplus to pay the minimum quarterly distribution on the common units.

Determination of Subordination Period

Except as described below, the subordination period will begin on the closing date of this offering and expire on the first business day after the distribution to unitholders in respect of any quarter, beginning with the quarter ending , if each of the following has occurred:

•

for each of the three consecutive, non-overlapping four-quarter periods immediately preceding that date, aggregate distributions from operating surplus equaled or exceeded the sum of the minimum quarterly distribution multiplied by the total number of common and subordinated units and other units ranking senior to or equal in right of distribution to the subordinated units outstanding in each quarter in each period;

•

for the same three consecutive, non-overlapping four-quarter periods, the “adjusted operating surplus” (as described below) equaled or exceeded the sum of the minimum quarterly distribution multiplied by the total number of common and subordinated units outstanding and other units ranking senior to or equal in right of distribution to the subordinated units during each quarter on a fully diluted weighted average basis; and

•

there are no arrearages in payment of the minimum quarterly distribution on the common units.

For the period after the closing of this offering through , 2015, our partnership agreement will prorate the minimum quarterly distribution based on the actual length of the period, and use such prorated distribution for all purposes, including in determining whether the test described above has been satisfied.

Early Termination of Subordination Period

Notwithstanding the foregoing, the subordination period will automatically terminate, and all of the subordinated units will convert into common units on a one-for-one basis, on the first business day after the distribution to unitholders in respect of any quarter, beginning with the quarter ending , if each of the following has occurred:

•

for one four-quarter period immediately preceding that date, aggregate distributions from operating surplus exceeded the sum of 150% of the minimum quarterly distribution multiplied by the total number of common units and subordinated units and other units ranking senior to or equal in right of distribution to the subordinated units outstanding in each quarter in the period;

•

for the same four-quarter period, the “adjusted operating surplus” (as described below) equaled or exceeded the sum of 150% of the minimum quarterly distribution multiplied by the total number of common and subordinated units and other units ranking senior to or equal in right of distribution to the subordinated units outstanding during each quarter on a fully diluted weighted average basis, plus the related distribution on the incentive distribution rights; and

•

there are no arrearages in payment of the minimum quarterly distributions on the common units.

Conversion Upon Removal of the General Partner

In addition, if the unitholders remove our general partner other than for cause, the subordinated units held by any person will immediately and automatically convert into common units on a one-for-one basis, provided (1) neither such person nor any of its affiliates voted any of its units in favor of the removal and (2) such person is not an affiliate of the successor general partner.

Expiration of the Subordination Period

When the subordination period ends, each outstanding subordinated unit will convert into one common unit and will then participate pro-rata with the other common units in distributions.

Adjusted Operating Surplus

Adjusted operating surplus is intended to generally reflect the cash generated from operations during a particular period and therefore excludes net increases in working capital borrowings and net drawdowns of reserves of cash generated in prior periods if not utilized to pay expenses during that period. Adjusted operating surplus for any period consists of:

•

operating surplus generated with respect to that period (excluding any amounts attributable to the items described in the first bullet point under “—Operating Surplus and Capital Surplus—Operating Surplus” above); less

•

any net increase during that period in working capital borrowings; less

•

any net decrease during that period in cash reserves for operating expenditures not relating to an operating expenditure made during that period; less

•

any expenditures that are not operating expenditures solely because of the provision described in the last bullet point describing operating expenditures above; plus

•

any net decrease during that period in working capital borrowings; plus

•

any net increase during that period in cash reserves for operating expenditures required by any debt instrument for the repayment of principal, interest or premium; plus

•

any net decrease made in subsequent periods in cash reserves for operating expenditures initially established during such period to the extent such decrease results in a reduction of adjusted operating surplus in subsequent periods pursuant to the third bullet point above.

Any disbursements received, cash received (including working capital borrowings) or cash reserves established, increased or reduced after the end of a period that the general partner determines to include in operating surplus for such period shall also be deemed to have been made, received or established, increased or reduced in such period for purposes of determining adjusted operating surplus for such period.

Distributions From Operating Surplus During the Subordination Period

If we make a distribution from operating surplus for any quarter ending before the end of the subordination period, our partnership agreement requires that we make the distribution in the following manner:

•

first, to the common unitholders, pro rata, until we distribute for each common unit an amount equal to the minimum quarterly distribution for that quarter and any arrearages in payment of the minimum quarterly distribution on the common units for any prior quarters;

•

second, to the subordinated unitholders, pro rata, until we distribute for each subordinated unit an amount equal to the minimum quarterly distribution for that quarter; and

•

thereafter, in the manner described in “—Incentive Distribution Rights” below.

Distributions From Operating Surplus After the Subordination Period

If we make distributions of cash from operating surplus for any quarter ending after the subordination period, our partnership agreement requires that we make the distribution in the following manner:

•

first, to all common unitholders, pro rata, until we distribute for each common unit an amount equal to the minimum quarterly distribution for that quarter; and

•

thereafter, in the manner described in “—Incentive Distribution Rights” below.

General Partner Interest

Our general partner owns a non-economic general partner interest in us, which does not entitle it to receive cash distributions. However, our general partner may in the future own common units or other equity interests in us and will be entitled to receive distributions on any such interests.

Incentive Distribution Rights

Incentive distribution rights represent the right to receive increasing percentages (15% and 25%) of quarterly distributions from operating surplus after the minimum quarterly distribution and the target distribution levels have been achieved. Royal currently holds the incentive distribution rights, but may transfer these rights.

If for any quarter:

•

we have distributed cash from operating surplus to the common and subordinated unitholders in an amount equal to the minimum quarterly distribution; and

•

we have distributed cash from operating surplus to the common unitholders in an amount necessary to eliminate any cumulative arrearages in payment of the minimum quarterly distribution;

then we will make additional distributions from operating surplus for that quarter among the unitholders and the holders of the incentive distribution rights in the following manner:

•

first, to all unitholders, pro rata, until each unitholder receives a total of $ per unit for that quarter (the “first target distribution”);

•

second, 85% to all common unitholders and subordinated unitholders, pro rata, and 15% to the holders of our incentive distribution rights, until each unitholder receives a total of $ per unit for that quarter (the “second target distribution”); and

•

thereafter, 75% to all common unitholders and subordinated unitholders, pro rata, and 25% to the holders of our incentive distribution rights.

Percentage Allocations of Distributions From Operating Surplus

The following table illustrates the percentage allocations of distributions from operating surplus between the unitholders and the holders of our incentive distribution rights based on the specified target distribution levels. The amounts set forth under the column heading “Marginal Percentage Interest in Distributions” are the percentage interests of the holders of our incentive distribution rights and the unitholders in any distributions from operating surplus we distribute up to and including the corresponding amount in the column “Total Quarterly Distribution Per Unit.” The percentage interests shown for our unitholders and the holders of our incentive distribution rights for the minimum quarterly distribution are also applicable to quarterly distribution amounts that are less than the minimum quarterly distribution. The percentage interests set forth below assume there are no arrearages on common units.


	Total Quarterly Distribution Per Unit	Marginal Percentage Interest in Distributions
	Total Quarterly Distribution Per Unit	Unitholders			IDR Holders
Minimum Quarterly Distribution	up to $		100	%		0	%
First Target Distribution	above $ up to $		100	%		0	%
Second Target Distribution	above $ up to $		85	%		15	%
Thereafter	above $		75	%		25	%

Incentive Distribution Rights Holder’s Right to Reset Incentive Distribution Levels

Royal, as the initial holder of our incentive distribution rights, has the right under our partnership agreement to elect to relinquish the right to receive incentive distribution payments based on the initial target distribution levels and to reset, at higher levels, the target distribution levels upon which the incentive distribution payments would be set. If Royal transfers all or a portion of the incentive distribution rights in the future, then the holder or holders of a majority of our incentive distribution rights will be entitled to exercise this right. The following discussion assumes that Royal holds all of the incentive distribution rights at the time that a reset election is made.

The right to reset the target distribution levels upon which the incentive distributions are based may be exercised, without approval of our unitholders or the conflicts committee of our general partner, at any time when there are no subordinated units outstanding and we have made cash distributions in excess of the highest then-applicable target distribution for the prior four consecutive fiscal quarters and the aggregate amount of the cash distributions made in such four-quarter period does not exceed the amount of adjusted operating surplus for such period. The reset target distribution levels will be higher than the most recent per unit distribution level prior to the reset election and higher than the target distribution levels prior to the reset such that there will be no incentive distributions paid under the reset target distribution levels until cash distributions per unit following the reset event increase as described below. Because the reset target distribution levels will be higher than the most

recent per unit distribution level prior to the reset, if we were to issue additional common units after the reset and maintain the per unit distribution level, no additional incentive distributions would be payable. By contrast, if there were no such reset and we were to issue additional common units and maintain the per unit distribution level, additional incentive distributions would have to be paid based on the additional number of outstanding common units and the percentage interest of the incentive distribution rights above the target distribution levels. Thus, the exercise of the reset right would lower our cost of equity capital. We anticipate that Royal would exercise this reset right in order to facilitate acquisitions or internal growth projects that would otherwise not be sufficiently accretive to cash distributions per common unit, taking into account the existing levels of incentive distribution payments being made.

In connection with the resetting of the target distribution levels and the corresponding relinquishment by Royal of incentive distribution payments based on the target cash distributions prior to the reset, Royal will be entitled to receive a number of newly issued common units based on the formula described below that takes into account the “cash parity” value of the cash distributions related to the incentive distribution rights for the quarter prior to the reset event as compared to the cash distribution per common unit in such quarter.

The number of common units to be issued in connection with a resetting of the minimum quarterly distribution amount and the target distribution levels would equal the quotient determined by dividing (x) the amount of cash distributions received in respect of the incentive distribution rights for the fiscal quarter ended immediately prior to the date of such reset election by (y) the amount of cash distributed per common unit with respect to such quarter.

Following a reset election, the reset minimum quarterly distribution will be calculated and the target distribution levels will be reset to be correspondingly higher such that we would make distributions from operating surplus for each quarter thereafter as follows:

•

first, to all common unitholders, pro rata, until each unitholder receives an amount per unit for that quarter equal to 115% of the reset minimum quarterly distribution;

•

second, 85% to all common unitholders, pro rata, and 15% to the holders of our incentive distribution rights, until each unitholder receives an amount per unit for that quarter equal to 125% of the reset minimum quarterly distribution;

•

thereafter, 75% to all common unitholders, pro rata, and 25% to the holders of our incentive distribution rights.

Because a reset election can only occur after the subordination period expires, the reset minimum quarterly distribution will have no significance except as a baseline for the target distribution levels.

The following table illustrates the percentage allocation of distributions from operating surplus between the unitholders and the holders of our incentive distribution rights at various distribution levels (1) pursuant to the distribution provisions of our partnership agreement in effect at the closing of this offering, as well as (2) following a hypothetical reset of the target distribution levels based on the assumption that the quarterly distribution amount per common unit during the fiscal quarter immediately preceding the reset election was $ .


	Quarterly Distribution Per Unit Prior to Reset		Unitholders			Incentive Distribution Rights Holders			Quarterly Distribution Per Unit Following Hypothetical Reset
Minimum Quarterly Distribution	up to $			100	%		0	%		up to $ (1)
First Target Distribution	above $	up to $		100	%		0	%		above $ up to $ (2)
Second Target Distribution	above $	up to $		85	%		15	%		above $ up to $ (3)
Thereafter	above $			75	%		25	%		above $

(1)	This amount is equal to the hypothetical reset minimum quarterly distribution.

(2)	This amount is 115% of the hypothetical reset minimum quarterly distribution.

(3)	This amount is 125% of the hypothetical reset minimum quarterly distribution.

The following table illustrates the total amount of distributions from operating surplus that would be distributed to the unitholders and the holders of incentive distribution rights, based on the amount distributed for the quarter immediately prior to the reset. The table assumes that immediately prior to the reset there would be common units outstanding and the distribution to each common unit would be $ for the quarter prior to the reset.

Quarterly Distribution per Unit
Prior to Reset

Cash
Distributions
to Common
Unitholders
Prior to
Reset

Cash Distributions
to Holders of
Incentive
Distribution
Rights Prior to
Reset

Total
Distributions

Minimum Quarterly Distribution

up to $

—

First Target Distribution

above $

up to $

—

Second Target Distribution

above $

up to $

Thereafter

above $

The following table illustrates the total amount of distributions from operating surplus that would be distributed to the unitholders and the holders of our incentive distribution rights, with respect to the quarter in which the reset occurs. The table reflects that as a result of the reset there would be common units outstanding and the distribution to each common unit would be $ . The number of common units to be issued upon the reset was calculated by dividing (1) the amount received in respect of the incentive distribution rights for the quarter prior to the reset as shown in the table above, or $ , by (2) the amount of cash distributed on each common unit for the quarter prior to the reset as shown in the table above, or $ .

Quarterly Distribution per Unit
Prior to Reset

Cash
Distributions
to Common
Unitholders
Prior to
Reset

Cash Distributions to Holders of
Incentive Distribution Rights
After Reset

Total
Distributions

Common
Units(1)

Incentive
Distribution
Rights

Total

Minimum Quarterly Distribution

up to $

—

First Target Distribution

above $

up to $

—

Second Target Distribution

above $

up to $

—

Thereafter

above $

—

(1)	Represents distributions in respect of the common units issued upon the reset.

The holders of incentive distribution rights will be entitled to cause the target distribution levels to be reset on more than one occasion.

Distributions From Capital Surplus

How Distributions From Capital Surplus Will Be Made

Our partnership agreement requires that we make distributions from capital surplus, if any, in the following manner:

•

first, to all common unitholders and subordinated unitholders, pro rata, until the minimum quarterly distribution is reduced to zero, as described below;

•

second, to the common unitholders, pro rata, until we distribute for each common unit an amount from capital surplus equal to any unpaid arrearages in payment of the minimum quarterly distribution on the common units; and

•

thereafter, we will make all distributions from capital surplus as if they were from operating surplus.

Effect of a Distribution from Capital Surplus

Our partnership agreement treats a distribution from capital surplus as the repayment of the initial unit price from this initial public offering, which is a return of capital. Each time a distribution from capital surplus is made, the minimum quarterly distribution and the target distribution levels will be reduced in the same proportion as the distribution from capital surplus to the fair market value of the common units prior to the announcement of the distribution. Because distributions of capital surplus will reduce the minimum quarterly distribution and target distribution levels after any of these distributions are made, it may be easier for Royal to receive incentive distributions and for the subordinated units to convert into common units. However, any distribution from capital surplus before the minimum quarterly distribution is reduced to zero cannot be applied to the payment of the minimum quarterly distribution or any arrearages.

Once we reduce the minimum quarterly distribution and target distribution levels to zero, all future distributions will be made such that 75% is paid to all unitholders, pro rata, and 25% is paid to the holder or holders of incentive distribution rights.

Adjustment to the Minimum Quarterly Distribution and Target Distribution Levels

In addition to adjusting the minimum quarterly distribution and target distribution levels to reflect a distribution from capital surplus, if we combine our common units into fewer common units or subdivide our common units into a greater number of common units, our partnership agreement specifies that the following items will be proportionately adjusted:

•

the minimum quarterly distribution;

•

the target distribution levels;

•

the initial unit price, as described below under “—Distributions of Cash Upon Liquidation”;

•

the per unit amount of any outstanding arrearages in payment of the minimum quarterly distribution on the common units; and

•

the number of subordinated units.

For example, if a two-for-one split of the common units should occur, the minimum quarterly distribution, the target distribution levels and the initial unit price would each be reduced to 50.0% of its initial level. If we combine our common units into a lesser number of units or subdivide our common units into a greater number of units, we will combine or subdivide our subordinated units using the same ratio applied to the common units. We will not make any adjustment by reason of the issuance of additional units for cash or property.

In addition, if as a result of a change in law or interpretation thereof, we or any of our subsidiaries is treated as an association taxable as a corporation or is otherwise subject to additional taxation as an entity for U.S. federal, state, local or non-U.S. income or withholding tax purposes, our general partner may, in its sole discretion, reduce the minimum quarterly distribution and the target distribution levels for each quarter by multiplying each distribution level by a fraction, the numerator of which is cash for that quarter (after deducting our general partner’s estimate of our additional aggregate liability for the quarter for such income and withholding taxes payable by reason of such change in law or interpretation) and the denominator of which is the sum of (1) cash for that quarter, plus (2) our general partner’s estimate of our additional aggregate liability for the quarter for such income and withholding taxes payable by reason of such change in law or interpretation thereof. To the extent that the actual tax liability differs from the estimated tax liability for any quarter, the difference will be accounted for in distributions with respect to subsequent quarters.

Distributions of Cash Upon Liquidation

General

If we dissolve in accordance with the partnership agreement, we will sell or otherwise dispose of our assets in a process called liquidation. We will first apply the proceeds of liquidation to the payment of our creditors. We will distribute any remaining proceeds to the unitholders and the holders of the incentive distribution rights, in accordance with their capital account balances, as adjusted to reflect any gain or loss upon the sale or other disposition of our assets in liquidation.

The allocations of gain and loss upon liquidation are intended, to the extent possible, to entitle the holders of units to a repayment of the initial value contributed by unitholders for their units in this offering, which we refer to as the “initial unit price” for each unit. The allocations of gain and loss upon liquidation are also intended, to the extent possible, to entitle the holders of common units to a preference over the holders of subordinated units upon our liquidation, to the extent required to permit common unitholders to receive their initial unit price plus the minimum quarterly distribution for the quarter during which liquidation occurs plus any unpaid arrearages in payment of the minimum quarterly distribution on the common units. However, there may not be sufficient gain upon our liquidation to enable the common unitholders to fully recover all of these amounts, even though there may be cash available for distribution to the holders of subordinated units. Any further net gain recognized upon liquidation will be allocated in a manner that takes into account the incentive distribution rights.

Manner of Adjustments for Gain

The manner of the adjustment for gain is set forth in the partnership agreement. If our liquidation occurs before the end of the subordination period, we will generally allocate any gain to the partners in the following manner:

•

first, to our general partner to the extent of certain prior losses specially allocated to our general partner;

•

second, to the common unitholders, pro rata, until the capital account for each common unit is equal to the sum of: (1) the initial unit price; (2) the amount of the minimum quarterly distribution for the quarter during which our liquidation occurs; and (3) any unpaid arrearages in payment of the minimum quarterly distribution;

•

third, to the subordinated unitholders, pro rata, until the capital account for each subordinated unit is equal to the sum of: (1) the initial unit price; and (2) the amount of the minimum quarterly distribution for the quarter during which our liquidation occurs;

•

fourth, to all unitholders, pro rata, until we allocate under this bullet an amount per unit equal to: (1) the sum of the excess of the first target distribution per unit over the minimum quarterly distribution per unit for each quarter of our existence; less (2) the cumulative amount per unit of any distributions from operating surplus in excess of the minimum quarterly distribution per unit that we distributed to the unitholders, pro rata, for each quarter of our existence;

•

fifth, 85% to all unitholders, pro rata, and 15% to the holders of our incentive distribution rights, until we allocate under this bullet an amount per unit equal to: (1) the sum of the excess of the second target distribution per unit over the first target distribution per unit for each quarter of our existence; less (2) the cumulative amount per unit of any distributions from operating surplus in excess of the first target distribution per unit that we distributed 85% to the unitholders, pro rata, and 15% to the holders of our incentive distribution rights for each quarter of our existence; and

•

thereafter, 75% to all unitholders, pro rata, and 25% to holders of our incentive distribution rights.

If the liquidation occurs after the end of the subordination period, the distinction between common units and subordinated units will disappear, so that clause (3) of the second bullet point above and all of the third bullet point above will no longer be applicable.

We may make special allocations of gain among the partners in a manner to create economic uniformity among the common units into which the subordinated units convert and the common units held by public unitholders.

Manner of Adjustments for Losses

If our liquidation occurs before the end of the subordination period, we will generally allocate any loss to our general partner and the unitholders in the following manner:

•

first, to holders of subordinated units in proportion to the positive balances in their capital accounts until the capital accounts of the subordinated unitholders have been reduced to zero;

•

second, to the holders of common units in proportion to the positive balances in their capital accounts, until the capital accounts of the common unitholders have been reduced to zero; and

•

thereafter, 100.0% to our general partner.

If the liquidation occurs after the end of the subordination period, the distinction between common units and subordinated units will disappear, so that all of the first bullet point above will no longer be applicable.

We may make special allocations of loss among the partners in a manner to create economic uniformity among the common units into which the subordinated units convert and the common units held by public unitholders.

Adjustments to Capital Accounts

Our partnership agreement requires that we make adjustments to capital accounts upon the issuance of additional units. In this regard, our partnership agreement specifies that we allocate any unrealized and, for federal income tax purposes, unrecognized gain resulting from the adjustments to the unitholders and the holders of our incentive distribution rights in the same manner as we allocate gain upon liquidation. In the event that we make positive adjustments to the capital accounts upon the issuance of additional units, our partnership agreement requires that we generally allocate any later negative adjustments to the capital accounts resulting from the issuance of additional units or upon our liquidation in a manner that results, to the extent possible, in the partners’ capital account balances equaling the amount that they would have been if no earlier positive adjustments to the capital accounts had been made. In contrast to the allocations of gain, and except as provided above, we generally will allocate any unrealized and unrecognized loss resulting from the adjustments to capital accounts upon the issuance of additional units to the unitholders and the holders of our incentive distribution rights based on their respective percentage ownership of us. In this manner, prior to the end of the subordination period, we generally will allocate any such loss equally with respect to our common and subordinated units. If we make negative adjustments to the capital accounts as a result of such loss, future positive adjustments resulting from the issuance of additional units will be allocated in a manner designed to reverse the prior negative adjustments, and special allocations will be made upon liquidation in a manner that results, to the extent possible, in our unitholders’ capital account balances equaling the amounts they would have been if no earlier adjustments for loss had been made.

SELECTED HISTORICAL FINANCIAL DATA

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 and unaudited consolidated historical financial statements of Holdings 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.


	Holdings Historical
	Year Ended December 31,						Three Months Ended March 31,
	2013			2014			2014			2015
	(in thousands)
Statement of Operations Data:
Oil and Gas Revenues	$	42,489		$	67,878		$	13,642		$	13,508

Costs and Expenses:
Production and ad valorem taxes		2,515			4,431			1,074			665
Marketing and transportation		1,075			2,170			186			1,317
Amortization of royalty mineral interests in oil and natural gas properties		12,003			13,426			3,477			5,182
General and administrative expenses		2,083			4,425			491			901

Total costs and expenses		17,676			24,452			5,228			8,065

Other Expenses:
Interest expense		4,072			4,860			1,226			1,302

Net income	$	20,741		$	38,566		$	7,188		$	4,141

Statement of Cash Flow Data:
Net cash provided by (used in):
Operating activities	$	30,123		$	53,526		$	10,421		$	10,772
Investing activities		(35	)		—			—			—
Financing activities		(33,083	)		(46,937	)		(8,775	)		(5,000	)
Other Financial Data:
Adjusted EBITDA(1)	$	36,816		$	56,852		$	11,891		$	10,625


	Holdings Historical
	As of December 31,				As of March 31, 2015
	2013		2014		As of March 31, 2015
	(in thousands)
Balance Sheet Data:
Cash and cash equivalents	$	1,959	$	8,548	$	14,320
Total assets		262,456		254,872		254,792
Total liabilities		91,640		110,427		111,206
Partner’s capital		170,816		144,445		143,586

(1)	For more information, please read “Summary—Summary Historical Financial Data—Non-GAAP Financial Measure.”

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION

AND RESULTS OF OPERATIONS

You should read the following discussion of our historical performance, financial condition and future prospects in conjunction with Holdings’ audited consolidated financial statements as of December 31, 2013 and 2014, and for the years ended December 31, 2013 and 2014 and the unaudited financial statements as of March 31, 2015 and for the three months ended March 31, 2014 and 2015 included elsewhere in this prospectus. The information provided below supplements, but does not form part of, Holdings’ financial statements. 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. Actual results could differ materially from such forward-looking statements as a result of various risk factors, including those that may not be in the control of management. For further information on items that could impact our future operating performance or financial condition, see the section entitled “Risk Factors” elsewhere in this prospectus.

Overview

We are a Delaware limited partnership formed by our Sponsor to own and acquire overriding royalty interests or ORRIs, and mineral and royalty interests in oil and natural gas properties in North America. These types of interests entitle the holder to a portion of the production of oil and natural gas from the underlying acreage at the sales price received by the operator, net of post-production expenses and taxes. The holder of these interests has no obligation to fund finding and development costs, lease operating expenses or plugging and abandonment costs at the end of a well’s productive life. 100% of our initial interests consist of ORRIs in properties in the Eagle Ford Shale region in South Texas. Our primary business objective is to provide increasing cash distributions to unitholders resulting from organic growth through the development of the properties underlying our ORRIs by third party operators and from accretive growth opportunities through acquisitions from our Sponsor and from third parties.

As of March 31, 2015, our assets consisted of ORRIs related to 69,974 net leasehold acres concentrated in what we believe is the “core of the core” of the liquids-rich condensate region of the Eagle Ford Shale. We believe that the wells and locations on the properties underlying our ORRIs are among the most productive in North America, and that such properties are experiencing some of the highest levels of development activity in North America. Our acreage is 100% held by production and is delineated by 770 producing horizontal wells as of March 31, 2015, all of which have been drilled over the past five years. The average net daily production attributable to the acreage underlying our ORRIs has increased 191% since the initial acquisition of the ORRIs by our predecessor in March 2012 to 4,381 BOE/d for the month of February 2015, primarily due to rapid development of these properties by third party operators. The increased rate of development on the acreage underlying our interests is attributable to greater efficiencies in drilling and completion operations by our operators. For example, pad drilling has led to a reduction in the amount of time necessary to drill wells, a reduction in time required to relocate rigs on our acreage and an increase in our average daily production rate. Our operators are increasingly capable of drilling more wells, in less time, with greater recoveries as compared to historical operations.

As of December 31, 2014, the estimated proved oil, natural gas liquids, and natural gas reserves of our underlying acreage were 19,141 MBOE (75% liquids, consisting of 57% oil and 18% natural gas liquids) based on a reserve report prepared by Ryder Scott. Of these reserves, 23% were classified as PDP reserves and 68% were classified as PUD reserves. PUD reserves included in this estimate are from 1,347 gross proved undeveloped drilling locations.

Reserves and Pricing

Von Gonten prepared estimates of our proved reserves at December 31, 2013 and Ryder Scott prepared estimates of our proved reserves at December 31, 2014 consistent with SEC guidelines. 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,
	2013		2014
Estimated Net Proved Reserves:
Oil (Bbls)		6,475,600		10,833,831
Natural gas (Mcf)		19,469,500		29,197,484
Natural gas liquids (Bbls)		2,575,100		3,440,718
Total (BOE)		12,295,617		19,140,797


	Unweighted Arithmetic Average First-Day-of-the-Month Prices
	As of December 31,
	2013		2014
Oil (Bbls)	$	96.78	$	94.99
Natural gas (MMBtu)	$	3.67	$	4.35

Sources of Our Revenue

Our revenues are derived from royalty payments we receive from our operators based on the sale of oil and natural gas production, as well as the sale of natural gas liquids that are extracted from natural gas during processing. As of March 31, 2015, our ORRIs represent the right to receive an average of 1.20% from the producing wells on the underlying acreage at the sales price received by our operators net of post-production expenses and taxes. For the year ended December 31, 2014, our revenues were derived 82% from oil sales, 9% from natural gas liquid sales and 9% from natural gas sales. For the three months ended March 31, 2015, our revenues were derived 78% from oil sales, 10% from natural gas liquid sales and 12% from natural gas 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. Oil, natural gas liquids and natural gas prices have historically been volatile, and we do not currently hedge our exposure to changes in commodity prices. During the twelve months ended December 31, 2014, West Texas Intermediate posted prices ranged from $53.45 to $107.95 per Bbl and the Henry Hub spot market price of natural gas ranged from $2.74 to $8.15 per MMBtu. On June 1, 2015, the West Texas Intermediate posted price for crude oil was $60.24 WTI per Bbl and the Henry Hub spot market price of natural gas was $2.78 per MMBtu.

Commodity prices are inherently volatile and have experienced significant declines recently. Changes in such prices may impact our revenue. The following table sets forth the average market prices for oil, natural gas and natural gas liquids for the years ended December 31, 2014 and 2013 and for the three months ended March 31, 2015:


	Year Ended December 31,				Three Months Ended March 31, 2015
	2013		2014		Three Months Ended March 31, 2015
Average prices:
Oil (Bbl)	$	96.28	$	87.19	$	43.51
Natural gas (MMBtu)	$	3.58	$	4.29	$	3.07
Natural gas liquids (Bbl)	$	50.14	$	29.19	$	15.77

Average market prices for oil, natural gas and natural gas liquids decreased significantly in the last part of 2014 with continued weakness throughout the first half of 2015. If product prices remain at these levels experienced during the fourth quarter of 2014 and the first half of 2015 throughout 2015, we may experience lower revenue compared to historical results.

Principal Components of Our Cost Structure

Production and Ad Valorem Taxes

The operators of the properties underlying our ORRIs allocate a portion of their production taxes to us based on the volumes of production attributable to our ORRIs. Production taxes are paid at fixed rates on produced oil and natural gas based on a percentage of revenues from products sold, established by federal, state or local taxing authorities. Where available, we benefit from tax credits and exemptions in our various taxing jurisdictions. We also directly pay ad valorem taxes in the counties where our production is located. Ad valorem taxes are generally based on the state government’s appraisal of our oil and gas properties.

Marketing and Transportation

The operators of the properties underlying our ORRIs allocate a portion of their post production costs to us based on the volumes of production attributable to our ORRIs. These are costs incurred to bring natural gas, natural gas liquids, and oil to the market. Such costs include our operators’ costs to operate and maintain low- and high-pressure gathering and compression systems as well as fees paid to third parties who operate low- and high-pressure gathering systems that transport our gas. They also include costs to process and extract natural gas liquids from our produced gas and to transport our natural gas liquids and oil to market.

Amortization

Our overriding royalty interests are recorded at cost and capitalized as tangible assets. Acquisition costs are amortized on a units of production basis over the life of the proved reserves.

General and Administrative

These are costs incurred for overhead, including the allocation of a portion of the cost of management, operating and administrative services provided under a master services agreement between Riverbend and Royal, audit and other fees for professional services and legal compliance. Please read “Certain Relationships and Related Party Transactions—Agreements and Transactions with Affiliates in Connection with this Offering.”

We anticipate incurring incremental general and administrative expenses of approximately $2.0 million annually as a result of being a publicly traded partnership, consisting of expenses associated with SEC reporting requirements, including annual and quarterly reports to unitholders, tax return and Schedule K-1 preparation and distribution, Sarbanes-Oxley Act compliance, listing fees, independent auditor fees, legal fees, investor relations activities, registrar and transfer agent fees, director and officer insurance and director compensation.

Interest Expense

Borrowings under our credit facility and second lien facility fund distributions to our equity owners. As a result, we incur substantial interest expense that is affected by both fluctuations in interest rates and our financing decisions. In connection with the closing of this offering, we intend to repay our existing revolving credit facility and second lien facility and enter into a new revolving credit facility, which we expect will be undrawn at the closing of this offering. Please read “—Liquidity and Capital Resources—Indebtedness.”

Income Tax Expense

We are treated as a partnership for federal income tax purposes, with each partner being separately taxed on its share of taxable income; therefore, there will be no federal income tax expense reflected in our financial statements.

Results of Operations

The following table summarizes our revenue and expenses and production data for the period indicated.


	Year Ended December 31,				Three Months Ended March 31,
	2013		2014		2014		2015
	(in thousands)
Operating Results:
Oil and Gas Revenues	$	42,489	$	67,878	$	13,642	$	13,508

Costs and Expenses:
Production and ad valorem taxes		2,515		4,431		1,074		665
Marketing and transportation		1,075		2,170		186		1,317
Amortization of royalty mineral interests in oil and natural gas properties		12,003		13,426		3,477		5,182
General and administrative expenses		2,083		4,425		491		901

Total costs and expenses		17,676		24,452		5,228		8,065

Other Expenses:
Interest expense		4,072		4,860		1,226		1,302

Net income	$	20,741	$	38,566	$	7,188	$	4,141

Production Data:
Oil (Bbls)		373		639		119		241
Natural gas (Mcf)		876		1,452		262		534
Natural gas liquids (Bbls)		68		202		29		89
Combined volumes (BOE)		588		1,083		192		418
Average daily combined volumes (BOE/d)		1.6		3.0		2.1		4.6

Comparison of the year ended December 31, 2014 to the year ended December 31, 2013

Oil and Gas Revenues

Oil and gas revenues increased $25.4 million, or 60%, to $67.9 million for the year ended December 31, 2014, from $42.5 million for the year ended December 31, 2013. The increase in oil and gas revenues is attributable to a $34.4 million increase resulting from increased drilling activity, partially offset by a $9.0 million decrease from decreased average realized commodity prices. Our revenues are a function of oil, natural gas liquids and natural gas production volumes sold and average prices received for those volumes. We received an average of $87.19 per Bbl of oil, $29.19 per Bbl of natural gas liquids and $4.28 per Mcf of natural gas for the volumes sold during the year ended December 31, 2014 compared to an average of $96.28 per Bbl of oil, $50.14 per Bbl of natural gas liquids and $3.58 per Mcf of natural gas for the volumes sold during the year ended December 31, 2013.

Production and Ad Valorem Taxes

Production and ad valorem taxes increased $1.9 million, or 76%, to $4.4 million for the year ended December 31, 2014, from $2.5 million for the year ended December 31, 2013. The increase in production and ad valorem taxes is attributable to increased production and increased valuations for ad valorem tax.

Marketing and Transportation Expense

Marketing and transportation expense increased $1.1 million, or 100%, to $2.2 million for the year ended December 31, 2014, from $1.1 million for the year ended December 31, 2013. The increase in marketing and transportation expense is attributable to increased production.

Amortization of Royalty Mineral Interests in Oil and Natural Gas Properties Expense

Amortization of royalty mineral interests in oil and natural gas properties expense increased $1.4 million, or 12%, to $13.4 million for the year ended December 31, 2014, from $12.0 million for year ended December 31, 2013. The increase in amortization of royalty mineral interests in oil and natural gas properties expense is attributable to increased production volumes attributable to new wells.

General and Administrative Expense

General and administrative expense increased $2.3 million, or 110%, to $4.4 million for the year ended December 31, 2014, from $2.1 million for the year ended December 31, 2013. The increase in general and administrative expense is attributable to a fee of $1.3 million paid to Riverbend in 2014 in connection with the management of our royalty mineral interests and $1.3 million related to expenses in connection with our initial public offering.

Interest Expense

Interest expense increased $0.8 million, or 20%, to $4.9 million for the year ended December 31, 2014, from $4.1 million for the year ended December 31, 2013. In May 2013 borrowings were increased $11 million and in December 2013 borrowings were increased $15 million. In October of 2014 borrowings were increased $18 million. The increase in interest expense is attributable to a full year of interest on the 2013 borrowings for the year ended December 31, 2014 and the two months of interest on the 2014 borrowings.

Comparison of the three months ended March 31, 2015 to the three months ended March 31, 2014

Oil and Gas Revenues

Oil and gas revenues decreased $.1 million, or 1%, to $13.5 million for the three months ended March 31, 2015, from $13.6 million for the three months ended March 31, 2014. The decrease in oil and gas revenues is attributable to a $16.2 million increase resulting from increased drilling activity offset by a $16.3 million decrease from decreased average realized prices. We received an average price of $43.51 per Bbl of oil, $3.07 per Mcf of gas and $15.77 per Bbl of natural gas liquids sold in the three months ended March 31, 2015 compared to $95.26 per Bbl of oil, $4.82 per Mcf of gas and $49.45 per Bbl of natural gas liquids sold during the three months ended March 31, 2014.

Production and Ad Valorem Taxes

Production and ad valorem taxes decreased $0.4 million, or 36%, to $0.7 million for the three months ended March 31, 2015, from $1.1 million for the three months ended March 31, 2014. The decrease in production and ad valorem taxes is attributable to the decrease in oil and gas revenues.

Marketing and Transportation Expense

Marketing and transportation expense increased $1.1 million, or 550%, to $1.3 million for the three months ended March 31, 2015, from $0.2 million for the three months ended March 31, 2014. The increase in marketing and transportation expense is attributable to increased production.

Amortization of Royalty Mineral Interests in Oil and Natural Gas Properties Expense

Amortization of royalty mineral interests in oil and natural gas properties expense increased $1.7 million, or 49%, to $5.2 million for the three months ended March 31, 2015, from $3.5 million for the three months ended March 31, 2014. The increase in amortization of royalty mineral interests in oil and natural gas properties expense is attributable to increased production.

General and Administrative Expense

General and administrative expense increased $0.4 million, or 80%, to $0.9 million for the three months ended March 31, 2015, from $0.5 million for the three months ended March 31, 2014. The increase in general and administrative expense is attributable to the commencement of the management fee arrangement with Riverbend.

Liquidity and Capital Resources

Overview

Following the completion of this offering, we expect our primary sources of liquidity will be cash flows from operations and equity and debt financings and our primary uses of cash will be for paying distributions to our unitholders and for replacement and growth capital expenditures, including the acquisition of oil and natural gas properties. In connection with the closing of this offering, we intend to repay our existing revolving credit facility and second lien facility and enter into a new revolving credit facility.

Our partnership agreement does not require us to distribute any of the cash we generate from operations. We believe, however, that it will be in the best interests of our unitholders if we distribute a substantial portion of the cash we generate from our operations. The board of directors of our general partner will adopt a policy to distribute an a substantial amount of the available cash we generate each quarter to our unitholders, beginning with the quarter ending September 30, 2015. However, the board of directors of our general partner may change such policy at any time at its discretion, without unitholder approval, and could elect not to pay distributions for one or more quarters. Our initial dividend policy will be to distribute approximately $ per quarter (or $ on an annualized basis). We currently expect that the initial distribution will equal approximately % of the cash generated from operations for the twelve months ending June 30, 2016. We expect to retain the remainder of funds generated from operations during that period to fund replacement and growth capital.

Cash Flows

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


	Year Ended December 31,						Three Months Ended March 31,
	2013			2014			2014			2015
	(in thousands)
Cash Flow Data:
Cash flows provided by operating activities	$	30,123		$	53,526		$	10,421		$	10,772
Cash flows used in investing activities		(35	)		—			—			—
Cash flows provided by (used in) financing activities		(33,083	)		(46,937	)		(8,775	)		(5,000	)

Net increase (decrease) in cash		(2,995	)		6,589			1,646			5,772

Operating Activities

Our operating cash flow is sensitive to many variables, the most significant of which is the volatility of prices for the oil and natural gas we produce. 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 control and are difficult to predict.

The increase in cash flow provided from operating activities in the year ended December 31, 2014 as compared to the year ended December 31, 2013 is attributable to higher production from our oil and gas properties related to new wells.

Financing Activities

Cash used in financing activities for the year ended December 31, 2014 was $46.9 million, a result of $18.0 million from debt proceeds, and $64.9 million used in partner distributions.

Cash used in financing activities for the year ended December 31, 2013 was $33.1 million, a result of partner distributions of $58.9 million and debt issuance costs of $0.2 million, and $26 million from proceeds from long term debt.

Cash used in financing activities for the three month ended March 31, 2015 and 2014 was $5.0 and $8.8 million, respectively, and was entirely related to partner distributions.

Indebtedness

Our primary sources of indebtedness are our credit facility and second lien facility, which we entered into in October 2012 and which will be paid off in connection with the closing of this offering:

•

Credit facility: As of March 31, 2015, the borrowing base on the credit facility is $78 million with a $150 million maximum base. The borrowing base is re-determined semi-annually. Borrowings are either at LIBOR or at the Base Rate, at our option, plus a variable credit spread. The variable credit spread is based on the percentage of the borrowing base utilized. The outstanding principal is due October 15, 2017.

•

Second lien facility: As of March 31, 2015, the principal outstanding on the second lien facility is $30 million with a $150 million maximum. Borrowings are between 7% and 9% for LIBOR-based loans, and between 6% and 8% for Base Rate loans. The interest rate is based on the percentage of the borrowing base utilized. The outstanding principal is due April 19, 2018.

The availability under each facility is subject to our compliance with certain customary contractual financial and non-financial covenants and each facility is secured by our assets.

Revolving Credit Facility. In connection with the closing of this offering, we expect to enter into a credit agreement providing for a revolving credit facility. The facility would be secured by substantially all of our assets. We expect that the credit agreement will contain various affirmative, negative and financial maintenance covenants. These covenants would, among other things, limit additional indebtedness, additional liens, sales of assets, mergers and consolidations, transactions with affiliates and entering into certain swap agreements and require the maintenance of certain financial ratios. We also expect that the credit agreement will contain customary events of default, including non-payment, breach of covenants, materially incorrect representations, cross-default, bankruptcy and change of control.

Contractual Obligations

The following table presents our contractual obligations and other commitments as of December 31, 2014 and March 31, 2015:


	Payments Due by Period
	Total		2014		2015		2016		2017		2018		Thereafter
	(in thousands)
Long-term debt(1)	$	108,000		—		—		—	$	78,000	$	30,000		—
Total	$	108,000		—		—		—	$	78,000	$	30,000		—

(1)	See Note 5 to the Audited Consolidated Historical Financial Statements for DGK ORRI Holdings, L.P.

We intend to repay our existing indebtedness using a portion of the proceeds of this offering. In connection with the completion of this offering, we also intend to enter into a new revolving credit facility, but do not expect to draw down any amount form the facility at closing.

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 formally 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. See “Summary—Emerging Growth Company Status.” Please also see “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, including those relating to accounting standards and disclosure about our executive compensation and internal control auditing requirements that apply to other public companies.”

Although we did not engage our independent registered public accounting firm to conduct an audit of our internal control over financial reporting, in connection with the audits of our historical predecessor financial statements as of and for the years ended December 31, 2014 and 2013, our independent registered public accounting firm informed us that it identified a material weakness relating to our internal control over financial reporting under standards established by the PCAOB. The PCAOB defines a material weakness as a deficiency, or a combination of deficiencies, in internal control over financial reporting such that there is a reasonable possibility that a material misstatement of the company’s annual or interim financial statements will not be prevented or detected on a timely basis. A deficiency in internal control exists when the design or operation of a control does not allow management or employees, in the normal course of performing their assigned functions, to prevent or detect misstatements on a timely basis.

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 102 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. However, we are choosing to “opt out” of such extended transition period, and as a result, we will comply with new or revised accounting standards on the relevant dates on which adoption of such standards is required for non-emerging growth companies. Our election to “opt-out” of the extended transition period is irrevocable.

In May 2014, the FASB issued Accounting Standards Update No. 2014-09, Revenue from Contracts with Customers (“ASU 2014-09”). The objective of ASU 2014-09 is to clarify the principles for recognizing revenue and to develop a common revenue standard for U.S. GAAP and International Financial Reporting Standards. ASU 2014 09 is effective for fiscal years, and interim periods within those years, beginning after December 15, 2017. We are currently evaluating the impact of adopting ASU 2014 09, but the Standard is not expected to have a significant effect on our consolidated financial statements.

In August 2014, the FASB issued Accounting Standards Update No. 2014-15, Presentation of Financial Statements – Going Concern (“ASU 2014-15”). The objective of ASU 2014-15 is to provide guidance on management’s responsibility to evaluate whether there is substantial doubt about a company’s ability to continue as a going concern and to provide related footnote disclosures. ASU 2014-15 is effective for fiscal years ending after December 15, 2016, and annual and interim periods thereafter. This standard will not have an impact on the Partnership’s consolidated financial statements.

Critical Accounting Policies

The discussion and analysis of our financial condition and results of operations are based upon our consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States. Below, we have provided expanded discussion of our more significant accounting policies, estimates and judgments. We believe these accounting policies reflect our more significant estimates and assumptions used in preparation of our financial statements. See the notes to our consolidated financial statements included elsewhere in this prospectus for additional information regarding these accounting policies.

Management Estimates

The preparation of the consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. The more significant areas requiring the use of management estimates and

assumptions relate to amortization calculations, and estimates of fair value for asset impairments. Our management bases its estimates on historical experience and on various other assumptions that are believed to be reasonable under the circumstances. Actual results could differ from these estimates.

Royalty Mineral Interests in Oil and Natural Gas Properties

Our royalty interests include acquired mineral, oil and natural gas, and other royalty interests in production, development and exploration stage properties. We follow the successful efforts method of accounting for oil and natural gas operations. Under this method, acquired royalty interests are recorded at cost and capitalized as tangible assets. Our royalty interests have no rights or obligations to explore, develop or operate the properties in which we maintain such interest, and we do not incur any of the costs of exploration, development and operation of the properties.

The adjusted purchase price of royalty interests are amortized using the units of production method over the life of the proven reserves, which were estimated by management in connection with the acquisition. In the 2012 period, management calculated amortization using reserves based on its acquisition forecast because better information was not available. However, in 2013 management obtained the necessary information to develop a Securities and Exchange Commission case reserve forecast, which was used by management on a prospective basis to calculate amortization of their oil and gas properties.

Acquisition costs of royalty interests are amortized using the units of production method over the life of the proven reserves.

We review and evaluate our royalty interests for impairment when events or changes in circumstances indicate that the related carrying amounts may not be recoverable. Our estimates of recoverability and fair value are based on numerous assumptions and it is possible that actual results will be significantly different than the estimates, as actual future quantities of recoverable oil and natural gas, commodity prices, production levels and taxes associated with production and oil and gas reserves are each subject to significant risks and uncertainties. When required, impairment losses are recognized based on the fair value of the assets.

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

Our independent engineers and technical staff prepare our estimates of oil and natural gas reserves and associated future net revenues. The SEC has defined proved reserves as the estimated quantities of oil and 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 and gas 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 and natural gas reserves. Oil and natural gas reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be precisely measured and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of drilling, testing and production subsequent to the date of the estimate may justify revision of such estimate. Accordingly, reserve estimates are often different from the quantities of oil and natural gas that are ultimately recovered.

Revenue Recognition

Revenue from our royalty interests from oil and gas sales is recognized when management can reliably estimate the royalty receivable, pursuant to the terms of the royalty agreements, and collection is reasonably assured. Differences between estimates of revenue and the actual amounts are adjusted and recorded in the period that the actual amounts are known.

Inflation

Inflation did not have a material impact on results of operations for the period from inception (March 1, 2012) through March 31, 2015.

Off-Balance Sheet Arrangements

We currently have no off-balance sheet arrangements.

Quantitative and Qualitative Disclosure about Market Risk

Commodity Price Risk

Our major market risk exposure is in the pricing applicable to the oil and natural gas 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 and natural gas production has been volatile and unpredictable for several years, we expect this volatility to continue in the future and we do not hedge our exposure to changes in commodity prices. The prices that our operators receive for production depend on many factors outside of our or their control. Historically, we have not entered into hedging arrangements to manage commodity price risks.

Credit Risk

We are subject to risk resulting from the concentration of oil and gas revenues in producing oil and natural gas properties and receivables with several significant purchasers. For the year ended December 31, 2014, we received approximately 53%, 24% and 10% of our revenue from Devon, BHP/Petrohawk, and ConocoPhillips, respectively. For the three months ended March 31, 2015, we received approximately 52%, 27% and 11% of our revenue from Devon, BHP/Petrohawk and Pioneer, respectively. We do not require collateral and do not believe the loss of any single purchaser would materially impact our operating results, as crude oil and natural gas are fungible products with well-established markets and numerous purchasers.

BUSINESS

Overview

We are a Delaware limited partnership formed by our Sponsor to own and acquire overriding royalty interests, or ORRIs, and mineral and royalty interests in oil and natural gas properties in North America. These types of interests entitle the holder to a portion of the production of oil and natural gas from the underlying acreage at the sales price received by the operator, net of post-production expenses and taxes. The holder of these interests has no obligation to fund finding and development costs, lease operating expenses or plugging and abandonment costs at the end of a well’s productive life. 100% of our initial interests consist of ORRIs in properties in the Eagle Ford Shale region in South Texas. Our primary business objective is to provide increasing cash distributions to unitholders resulting from organic growth, through the development of the properties underlying our ORRIs by third party operators and from accretive growth opportunities through acquisitions from our Sponsor and from third parties.

As of December 31, 2014, the estimated proved oil, natural gas liquids, and natural gas reserves of our underlying acreage were 19,141 MBOE (75% liquids, consisting of 57% oil and 18% NGLs) based on a reserve report prepared by Ryder Scott. Of these reserves, 23% were classified as PDP reserves and 68% were classified as PUD reserves. PUD reserves included in this estimate are from 1,347 gross proved undeveloped drilling locations.

The Eagle Ford Shale is one of the fastest growing and most active unconventional shale trends in North America. According to monthly rig count metrics published by Baker Hughes, the Eagle Ford Shale has consistently been one of the most active US basins since 2012 and has also proven to be the most robust of the liquids-focused basins, experiencing the lowest percentage decline in rig counts in the current low commodity price environment when compared to the Permian and Williston basins. Over 98% of our acreage is located in DeWitt County, one of the most active counties in terms of new wells drilled in the Eagle Ford Shale over the last five years. Our acreage is characterized by high liquids content and low finding and development costs leading to attractive operator economics compared to other unconventional basins. We believe these factors make development of the Eagle Ford Shale commercially viable in lower commodity price environments. Over 99% of our acreage is operated by BHP and Devon through a joint venture, ConocoPhillips, EOG, and Pioneer. These operators have publicly announced aggregate capital expenditure programs in the Eagle Ford Shale of over $5.0

billion in 2015. As of June 1, 2015, BHP, Devon and ConocoPhillips operate 7 of the 8 rigs on our acreage, comprising 54% of their aggregate rigs in the Eagle Ford Shale.

Upon the completion of this offering, our Sponsor will own and control our general partner, and will own approximately % of our outstanding common units and all of our outstanding subordinated units and incentive distribution rights. Our Sponsor is an independent oil and natural gas company currently focused on the acquisition and ownership of non-operating, non-cost bearing oil and natural gas properties in North America, such as mineral and royalty interests and ORRIs. We believe that the properties held by our Sponsor include acreage that will continue to support future reserve and production growth as operators explore other target zones, and have production and reserves characteristics, as well as significant acreage overlap, that could make them attractive for inclusion in our partnership. We believe our Sponsor’s significant ownership interest in us will motivate it to offer additional oil and natural gas properties to us in the future, although our Sponsor has no obligation to do so and may elect to dispose of properties without offering us the opportunity to acquire such properties.

Our Properties

Our initial assets consist of ORRIs related to 69,974 net leasehold acres, associated with 245 drilling units, in what we believe is the “core of the core” of the Eagle Ford Shale. As of March 31, 2015, these interests entitle us to receive an average royalty of 1.20% from the producing wells on the acreage underlying our ORRIs, with no additional future capital or operating expenses required. As of March 31, 2015, there were 770 horizontal wells producing on this acreage, and net production was approximately 4,381 BOE/d for the month of February 2015. In addition, there were 188 horizontal wells in various stages of completion. As of June 1, 2015, there were 114 permits outstanding for undrilled wells or wells currently being drilled on the acreage underlying our ORRIs. For the three months ended March 31, 2015, revenue generated from these ORRIs was $13.5 million.

The following table includes operating metrics as of December 31, 2014, unless otherwise indicated.


	Net Leasehold Acres toWhich Royalty Applies		Average Royalty Interest per PDP Well(1)			Average Daily Production(2)								Total Proved Reserves (MBOE)		% Reserves			Proved Undeveloped Locations		Rigs Operating On Our Acreage(1)
Operator/Developer	Net Leasehold Acres toWhich Royalty Applies		Average Royalty Interest per PDP Well(1)			Oil (Bbls/d)		Natural Gas (Mcf/d)		Natural Gas Liquids (Bbls/d)		Combined Volumes (BOE/d)		Total Proved Reserves (MBOE)		% Reserves			Proved Undeveloped Locations		Rigs Operating On Our Acreage(1)
Devon/BHP		60,970		1.40	%		2,329		4,584		768		3,862		15,798		83	%		822		5
ConocoPhillips		7,500		0.59	%		201		436		72		346		2,933		15	%		475		2
EOG, Pioneer & Other		1,504		0.56	%		79		319		41		173		410		2	%		50		1

Total		69,974		1.20	%		2,609		5,339		881		4,381		19,141		100	%		1,347		8

(1)	As of June 1, 2015.

(2)	Average daily production for the month of February 2015.

The gross EURs from the future PUD horizontal wells included in our reserve report on 40-acre spacing, as estimated by Ryder Scott as of December 31, 2014, range from 316 MBOE per well (consisting of 155 MBbls of oil, 658 MMcf of natural gas and 50 MBbls of natural gas liquids) to 1,829 MBOE per well (consisting of 868 MBbls of oil, 3,774 MMcf of natural gas and 331 MBbls of natural gas liquids) with an average EUR per well of 952 MBOE (consisting of 476 MBbls of oil, 1,889 MMcf of natural gas and 162 MBbls of natural gas liquids).

The following chart shows the number of producing wells on the acreage underlying our ORRIs for each quarter since the acquisition of the ORRIs by our Sponsor in March 2012.

Producing Wells By Quarter

LOGO

The following map shows the location of 323 drilling units in the Eagle Ford Shale in which our Sponsor and we own interests. We own interests in 245 drilling units in the Eagle Ford Shale. Our Sponsor owns interests in 317 drilling units in the Eagle Ford Shale, of which 239 overlap with drilling units that we own.

LOGO

Business Strategies

•

Maintain a conservative capital structure and prudently manage the business for the long term. We intend to maintain a conservative capital structure to allow us the financial flexibility to execute our business strategies over the long term, including the ability to pursue strategic acquisitions. Following the completion of this offering, we will have $ million of available liquidity under our undrawn revolving credit facility and no outstanding indebtedness. We believe that this liquidity, together with cash flow from operations and access to the public debt and equity markets, will provide us with financial flexibility to execute on strategic acquisitions to contribute and to production and cash flow growth over time.

Competitive Strengths

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

•

Low-risk, multi-year inventory in one of North America’s leading liquids plays. Our concentrated acreage position is located in what we believe is the “core of the core” of one of the most prolific plays in North America, the Eagle Ford Shale in South Texas. Over 98% of our properties are located in DeWitt County, the most productive section of the play, which is characterized by high liquids content and low finding and development costs, which lead to attractive operator economics compared to other unconventional basins. We believe these characteristics make the acreage underlying our ORRIs commercially viable to our operators in a variety of commodity price environments. As of March 31, 2015, our acreage is 100% held by production and is delineated by 770 producing horizontal wells that have been drilled over the past five years. As of December 31, 2014, our estimated proved oil and natural gas reserves were 19,141 MBOE (75% liquids, consisting of 57% oil and 18% natural gas liquids), of which 23% were classified as PDP reserves. As of December 31, 2014, we identified 1,347 gross proved undeveloped drilling locations on our acreage. Our identification of drilling locations is based on specifically identified locations, which have been reviewed and confirmed by Ryder Scott in connection with the preparation of the reserve report as of December 31, 2014. For additional information regarding our drilling locations, please read “– Oil and Natural Gas Data – Identification of Drilling Locations.” As of June 1, 2015, our operators had obtained 106 permits for undeveloped locations on our acreage and were running an aggregate of 8 rigs on our acreage. We believe this extensive inventory of undeveloped acreage will contribute to strong organic growth.

•

High-quality operators with active development programs. Over 99% of our acreage is operated by BHP and Devon, through a joint venture, ConocoPhillips, EOG and Pioneer. These operators have publicly announced aggregate capital expenditure programs in the Eagle Ford Shale of over $5.0 billion in 2015. As of June 1, 2015 BHP, Devon and ConocoPhillips operate 7 of the 8 rigs on our acreage, comprising 54% of their aggregate rigs in the Eagle Ford Shale. These operators are characterized by investment grade credit profiles as of March 31, 2015. We believe our operators will continue to develop our acreage in lower commodity price environments because of its high margin economics and public statements from our operators that the Eagle Ford Shale continues to be a top priority.

•

Significant opportunity for our operators to increase production through down spacing and development of other zones. All of our current proved reserves are attributable to the lower Eagle Ford Shale and assumes 40-acre spacing. Several of our operators are currently down spacing their development programs, using staggered development that could yield additional down spacing to 20-acre spacing. Based on our analysis, we believe that there is little degradation of well performance caused by this spacing. In addition, several of our operators are testing our acreage for other target zones, such as the Upper Eagle Ford and Austin Chalk. We believe this down spacing and drilling in additional zones could increase reserves, well locations and production beyond our reserve report.

•

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Comparison of Types of Interests

Mineral Interest. Mineral interests are perpetual rights of the owner to exploit, mine, and/or produce any or all of the minerals lying below the surface of the property. The holder of a mineral interest has the right to lease the minerals to a working interest holder pursuant to an oil and gas lease.

Working Interest. Working interest holders have the rights to extract minerals from acreage leased pursuant to an oil and gas lease from a mineral interest holder. Holders of working interests are responsible for their pro rata share of capital expenditures and lease operating expenses, but holders of working interests only receive revenues after distributions have first been made to holders of royalty interests and ORRIs. Working interests expire upon the termination or expiration of the underlying oil and gas lease.

Royalty Interest. Royalty interests generally result when the owner of a mineral interest leases the underlying minerals to a working interest holder pursuant to an oil and gas lease. Typically, the resulting royalty interest is a cost-free percentage of production revenues for minerals extracted from the acreage. Holders of royalty interests are generally not responsible for capital expenditures or lease operating expenses, but may be responsible for certain post-production expenses, and typically have limited environmental liability. Royalty interests expire upon the expiration of the oil and gas lease.

Overriding Royalty Interest. ORRIs are created by carving out the right to receive royalties from a working interest. Like royalty interests, ORRIs do not confer an obligation to make capital expenditures or pay for lease operating expenses and have limited environmental liability, however ORRIs may be calculated net of post-production expenses, depending on how the ORRI is structured. ORRIs that are carved out of working interests are linked to the same underlying oil and gas lease that created the working interest, and therefore, such ORRIs are typically subject to expiration upon the expiration or termination of the oil and gas lease.

Oil and Natural Gas Data

Proved Reserves

Evaluation and Review of Reserves

Our historical reserve estimates as of December 31, 2013 and 2014 were prepared by Von Gonten and Ryder Scott, respectively. Von Gonten and Ryder Scott are each an independent petroleum engineering firm. The technical persons responsible for preparing our proved reserve estimates meet the requirements with regards to qualifications, independence, objectivity and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. Von Gonten and Ryder Scott are each a third party engineering firm and do not own an interest in any of our properties and are not employed by us on a contingent basis.

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, 2014 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 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 gas reserves relies on the use of certain generally accepted analytical procedures. These analytical procedures fall into three broad categories or methods: (1) performance-

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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 the properties underlying our ORRIs were estimated by performance methods, analogy or a combination of both methods. Approximately 75% of the 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. The remaining 25% of the proved producing reserves were estimated by analogy, or a combination of performance and analogy methods. The analogy method was used where there were inadequate historical performance data to establish a definitive trend and where the use of production performance data as a basis for the reserve estimates was considered to be inappropriate. 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, Von Gonten and Ryder Scott 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 operating expense data.

Historically, employees of Riverbend have worked closely with our independent reserve engineers to ensure the integrity, accuracy and timeliness of the data used to calculate our proved reserves relating to our assets in the Eagle Ford Shale region. Riverbend’s technical team met with our independent reserve engineers 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 the independent reserve engineers for our properties such as ownership interest, oil and gas production, commodity prices and transportation and marketing expenses. 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 our independent reserve engineer. Scott Rice, Vice President—Engineering and Business Development at Riverbend has historically been primarily responsible for overseeing the preparation of all of our reserve estimates. Mr. Rice is a petroleum engineer with over 10 years of reservoir experience. Riverbend’s technical staff uses historical information for the properties underlying our ORRIs such as ownership interest, oil and gas production, well test data, commodity prices and operating and development costs.

Following the completion of this offering, we anticipate that an employee of our general partner will 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 our operators;

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preparation of reserve estimates by our Vice President—Engineering and Business Development or under his direct supervision;

•

review by our Vice President—Engineering and Business Development 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;

•

direct reporting responsibilities by our Vice President—Engineering and Business Development to our Chief Executive Officer;

•

verification of property ownership by our land department; and

•

no employee’s compensation is tied to the amount of reserves booked.

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The following table presents our estimated net proved oil and natural gas reserves as of December 31, 2013, based on the reserve report prepared by Von Gonten, and as of December 31, 2014, based on the reserve report prepared by Ryder Scott. The reserve report has been prepared in accordance with the rules and regulations of the SEC. All of our proved reserves included in the reserve report are located in the continental United States.


	As of December 31,
	2013			2014
Estimated proved developed reserves:
Oil (MBbls)		1,739.2			3,640.4
Natural gas (MMcf)		4,342.8			8,798.5
Natural gas liquids (MBbls)		577.6			1,077.5
Total (MBOE)		3,040.6			6,184.3
Estimated proved undeveloped reserves:
Oil (MBbls)		4,736.4			7,193.5
Natural gas (MMcf)		15,126.7			20,399.0
Natural gas liquids (MBbls)		1,997.5			2,363.2
Total (MBOE)		9,255.1			12,956.5
Estimated Net Proved Reserves:
Oil (MBbls)		6,475.6			10,833.8
Natural gas (MMcf)		19,469.5			29,197.5
Natural gas liquids (MBbls)		2,575.1			3,440.7
Total (MBOE)(1)		12,295.7			19,140.8
Percent proved developed		25	%		32	%
PV-10 of proved reserves (in millions)(2)	$	431.7		$	617.5

(1)

Estimates of reserves as of December 31, 2013 and December 31, 2014 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 years ended December 31, 2013 and 2014, respectively, in accordance with revised SEC guidelines applicable to reserve estimates as of the end of such periods. The unweighted arithmetic average first day of the month prices were $96.78 per Bbl for oil and $3.67 per MMBtu for natural gas and $94.99 per Bbl for oil and $4.35 per MMBtu for natural gas at December 31, 2013 and December 31, 2014, respectively. The price per Bbl for natural gas liquids was modeled as a percentage of oil price, which was derived from historical accounting data. Reserve estimates do not include any value for probable or possible reserves that may exist, nor do they include any value for undeveloped acreage. The reserve estimates represent our ORRI share in our properties. Although we believe these estimates are reasonable, actual future production, cash flows, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves may vary substantially from these estimates.

(2)

In this prospectus, we have disclosed our PV-10 based on our reserve report. PV-10 represents the period end present value of estimated future cash inflows from our natural gas and crude oil reserves, less future development and production costs, discounted at 10% per annum to reflect timing of future cash flows and using SEC pricing assumptions in effect at the end of the period. Because of this, PV-10 can be used within the industry and by creditors and securities analysts to evaluate estimated net cash flows from proved reserves on a more comparable basis. PV-10 differs from standardized measure because it does not include the effects of income taxes. However, because we are a limited partnership, we are generally not subject to federal income taxes and thus our PV-10 for proved reserves and standardized measure are equivalent. Neither PV-10 nor standardized measure represents an estimate of fair market value of our natural gas and oil properties. We and others in the industry use PV-10 as a measure to compare the relative size and value of estimated reserves held by companies without regard to the specific tax characteristics of such entities.

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As of December 31, 2014, our proved developed reserves totaled 3,640 MBbls of oil, 8,798 MMcf of natural gas and 1,077 MBbls of natural gas liquids, for a total of 6,184 MBOE. Of the total proved developed reserves, 72 percent are producing and the remaining 28 percent are from wells that have been stimulated but are not yet producing hydrocarbons.

The foregoing reserves are all located within the continental United States. Reserve engineering is 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. See “Risk Factors.” We have not filed any estimates of total, proved net oil or natural gas reserves with any federal authority or agency other than the SEC.

Additional information regarding our proved reserves can be found in the reserve report as of December 31, 2013 prepared by Von Gonten and as of December 31, 2014 prepared by Ryder Scott, which are filed as Exhibits 99.1 and 99.2, respectively, to the registration statement of which this prospectus is a part.

Proved Undeveloped Reserves

As of December 31, 2014, our proved undeveloped reserves totaled 7,194 MBbls of oil, 20,399 MMcf of natural gas and 2,363 MBbls of natural gas liquids, for a total of 12,957 MBOE. PUD reserves will be converted from undeveloped to developed as the applicable wells begin production.

During the year ended December 31, 2014, our operators converted 1,800 MBOE of PUD reserves, which represented approximately 19.5% of our estimated PUD reserves as of December 31, 2013. Due to the non-cost bearing nature of our ORRIs, we did not make any capital expenditures in connection with the conversion of these PUD reserves. Our PUD reserves increased from 9,225 MBOE to 12,957 MBOE due to:

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an increase of 6,638 MBOE attributable to increasing well density, resulting from the decrease from 80-acre spacing to 40-acre spacing;

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the conversion of 1,800 MBOE of PUD reserves into PDP and PNP reserves; and

•

a decrease of 1,106 MBOE attributable to decreased reserves on a per well basis, resulting from the decrease from 80-acre spacing to 40-acre spacing.

All of our PUD drilling locations are scheduled to be drilled prior to the end of December 2019. This development schedule is based on a 169 well inventory waiting to be brought online, 167 permits that identify activity and continued PUD conversion based on historical drilling activity and the publicly announced capital expenditure plans of our operators.

Identification of Drilling Locations

Our identification of drilling locations is based on specifically identified locations on our leasehold acreage based on our assessment of current geoscientific, engineering, land, well-spacing and historic production profile information derived from state agencies and public statements by our the operators on the acreage underlying our interests. These drilling locations are identified on a detailed map and allocated a reserve profile and identifier. Further, Ryder Scott reviewed and confirmed our drilling locations in estimating our PUD reserves in connection with the preparation of its reserve report as of December 31, 2014. We update and revise our drilling locations on a periodic basis as our assessment of the information described above changes.

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Oil and Natural Gas Production Prices and Production Costs

Production and Price History

The following table sets forth information regarding our net production of oil, natural gas and natural gas liquids, all of which is from the Eagle Ford Shale region in South Texas, and certain price and cost information for each of the periods indicated:


	Year Ended December 31,				Three Months Ended March 31,
	2013		2014		2015
Production Data:
Oil (Bbls)		373,084		639,325		240,636
Natural gas (Mcf)		876,105		1,452,080		534,437
Natural gas liquids (Bbls)		68,407		202,365		88,572
Combined volumes (BOE)		587,508		1,083,704		418,281
Daily combined volumes (BOE/d)		1,610		2,969		4,648
Average Realized Prices:
Oil (per Bbl)	$	96.28	$	87.19	$	43.51
Natural gas (per Mcf)	$	3.58	$	4.29	$	3.07
Natural gas liquids (per Bbl)	$	50.14	$	29.19	$	15.77
Weighted average combined (per BOE)	$	72.32	$	62.63	$	32.29

Productive Wells

As of March 31, 2015, we owned an overriding royalty interest in 770 productive wells located on the acreage in which we have a mineral interest. Productive wells consist of producing wells and wells capable of production, including natural gas wells awaiting pipeline connections to commence deliveries and oil wells awaiting connection to production facilities.

Acreage

The following table sets forth information as of March 31, 2015 relating to our gross acreage:

Basin

Developed
Acreage(1)

Undeveloped
Acreage(2)

Total
Acreage

Eagle Ford

38,320

84,882

123,202

(1)	Developed acres are acres spaced or assigned to productive wells and do not include undrilled acreage held by production under the terms of the lease. The value provided is for horizontal wells only and are based on 40 acres per well for wells drilled as of March 31, 2015.

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

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Drilling Results

As of March 31, 2015, our operators had 188 wells in the process of drilling, completing or dewatering or shut in awaiting infrastructure that are not reflected in the below table.


	Year Ended December 31, 2013		Year Ended December 31, 2014		Three Months Ended March 31, 2015
Development:
Productive		184		235		73
Dry		—		—		—
Exploratory:
Productive		—		—		—
Dry		—		—		—
Total:
Productive		184		235		73
Dry		—		—		—

Competition

The oil and natural gas industry is intensely competitive; we primarily compete with companies for the acquisition of oil and natural gas properties some of whom have greater resources than we do. These companies may be able to pay more for productive oil and natural gas properties and exploratory prospects or to define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. Additionally, many of our competitors are, or are affiliated with, operators that engage in the exploration and production of their oil and 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.

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 our operators 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 penalties for failure to comply. The regulatory burden on the oil and natural gas industry increases the cost of doing business.

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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. 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 strict and joint and several liability nature of such laws and regulations could impose liability upon responsible parties (including the operators of the acreage underlying our ORRIs) 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.

Waste Handling

The Resource Conservation and Recovery Act, as amended (“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. Although most wastes associated with the exploration, development and production of crude oil and natural gas are exempt from regulation as hazardous wastes under RCRA, such wastes may constitute “solid wastes” that are subject to the less stringent requirements of non-hazardous waste provisions. However, we cannot assure you that the EPA or state or local governments will not adopt more stringent requirements for the handling of non-hazardous wastes or categorize some non-hazardous wastes as hazardous for future regulation. Indeed, legislation has been proposed from time to time in Congress to re-categorize certain oil and natural gas exploration, development and production wastes as “hazardous wastes.” Any such changes in the laws and regulations could have a material adverse effect on the capital expenditures and operating expenses of the operators of the acreage underlying our ORRIs.

Administrative, civil and criminal penalties can be imposed on the operators of the acreage underlying our ORRIs for failure to comply with waste handling requirements. Any legislative or regulatory reclassification of oil and natural gas exploration and production wastes could increase the costs to manage and dispose of wastes for such operators.

Remediation of Hazardous Substances

The Comprehensive Environmental Response, Compensation and Liability Act, as amended (“CERCLA”), also known as the “Superfund” law, and analogous state laws, generally impose strict and 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

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strict and 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 ORRIs 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 ORRIs 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 Federal Water Pollution Control Act of 1972, as amended, also known as the “Clean Water Act,” the Safe Drinking Water Act (“SDWA”), the Oil Pollution Act (“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 navigable waters of the United States, as well as state 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. 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. These laws and regulations also prohibit certain activity in wetlands unless authorized by a permit issued by the U.S. Army Corps of Engineers. 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. In addition, in April 2015, the EPA issued proposed effluent limitation guidelines for the discharge of wastewater from hydraulic fracturing. Costs may be associated with the treatment of wastewater or developing and implementing storm water pollution prevention plans, as well as for monitoring and sampling the storm water runoff from certain of our facilities. Some states also maintain groundwater protection programs that require permits for discharges or operations that may impact groundwater conditions.

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 waters of the United States, 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 to surface waters.

Noncompliance with the Clean Water Act or OPA may result in substantial administrative, civil and criminal penalties, as well as injunctive obligations, for the operators of the acreage underlying our ORRIs.

Air Emissions

The federal Clean Air Act, as amended, 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, on August 16, 2012, the EPA published final regulations under the federal Clean Air Act that establish new emission

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controls for oil and natural gas production and processing operations, which regulations are discussed in more detail below in “—Regulation of Hydraulic Fracturing.” These laws and regulations may increase the costs of compliance for some facilities we own or operate, 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. Obtaining or renewing permits has the potential to delay the development of oil and natural gas projects.

Climate Change

In response to findings that emissions of greenhouse gases (“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. Pursuant to the Obama Administration’s Climate Action Plan, first announced in 2013, the EPA also proposed new restrictions on coal-fired power plants in June 2014, which could have an adverse effect on our financial condition and results of operations. In addition, the EPA has adopted rules requiring the monitoring and reporting of GHGs from specified onshore and offshore oil and natural gas production sources in the United States on an annual basis. We believe that we are in substantial compliance with applicable obligations under these rules. As a result of this continued regulatory focus, future GHG regulations of the oil and gas industry remain a possibility. In addition, Congress has from time to time considered adopting legislation to reduce emissions of greenhouse gases and many states have already taken legal measures to reduce emissions of greenhouse gases primarily through the planned development of greenhouse gas emission inventories and/or regional greenhouse gas 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 greenhouse gas emissions.

Restrictions on emissions of methane or carbon dioxide that may be imposed in various states could adversely affect the oil and natural gas industry, and state and local climate change initiatives and, at this time, it is not possible to accurately estimate how potential future laws or regulations addressing greenhouse gas emissions would impact our business.

In addition, there has been public discussion that climate change may be associated with 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. Some studies indicate that climate change could cause some areas to experience temperatures substantially colder than their historical averages. 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.

Regulation of Hydraulic Fracturing

Hydraulic fracturing is an important common practice that is used to stimulate production of hydrocarbons, particularly natural gas, from tight formations, including shales. The process involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production. The federal SDWA regulates the underground injection of substances through the UIC program. Hydraulic fracturing generally is exempt from regulation under the UIC program, and the hydraulic fracturing process is typically regulated by state oil and gas commissions. The EPA, however, has recently taken the position that hydraulic fracturing with fluids containing diesel fuel is subject to regulation under the UIC program, specifically as “Class II” UIC wells. At the same time, the White House Council on Environmental Quality is coordinating an administration-wide review of hydraulic fracturing practices and the EPA has been conducting a study of the potential impacts of hydraulic fracturing on drinking water resources (the EPA released a draft report for public comment in June 2015 which concluded that, while hydraulic fracturing has the potential to impact drinking water resources, the EPA did not find evidence that it has led to widespread, systemic impacts on drinking

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water resources). As part of these studies, the EPA has requested that certain companies provide them with information concerning the chemicals used in the hydraulic fracturing process. These studies, depending on their results, could spur initiatives to regulate hydraulic fracturing under the SDWA or otherwise.

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, or 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 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. The EPA received numerous requests for reconsideration of these rules from both industry and the environmental community, and court challenges to the rules were also filed. The EPA has been issuing revised rules to address some of these requests. For example, on September 23, 2013, the EPA published an amendment extending compliance dates for certain storage vessels. At this point, we cannot predict the final regulatory requirements or the cost to comply with such requirements with any certainty. In addition, the U.S. Department of the Interior published a final rule in March 2015 that updates existing regulation for hydraulic fracturing activities on federal lands, including requirements for disclosure, well bore integrity and handling of flowback water.

In addition, there are certain governmental reviews either underway or being proposed that focus on environmental aspects of hydraulic fracturing practices. These ongoing or proposed 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. The EPA is currently evaluating the potential impacts of hydraulic fracturing on drinking water. The U.S. Department of Energy has conducted an investigation into practices the agency could recommend to better protect the environment from drilling using hydraulic-fracturing completion methods. Additionally, certain members of Congress have called upon the U.S. Government Accountability Office to investigate how hydraulic fracturing might adversely affect water resources, the SEC to investigate the natural-gas industry and any possible misleading of investors or the public regarding the economic feasibility of pursuing natural gas deposits in shale formations by means of hydraulic fracturing, and the U.S. Energy Information Administration to provide a better understanding of that agency’s estimates regarding natural gas reserves, including reserves from shale formations, as well as uncertainties associated with those estimates.

Several states, including Texas, 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. The Texas Legislature previously adopted legislation requiring oil and gas operators to publicly disclose the chemicals used in the hydraulic fracturing process, effective as of September 1, 2011. The Texas Railroad Commission subsequently adopted rules and regulations implementing this legislation that apply to all wells for which the Railroad Commission issues an initial drilling permit. This law requires that the well operator disclose the list of chemical ingredients subject to the requirements of the Occupational Safety and Health Act (“OSHA”) for disclosure on an internet website and also file the list of chemicals with the Texas Railroad Commission with the well completion report. The total volume of water used to hydraulically fracture a well must also be disclosed to the public and filed with the Texas Railroad Commission. Further, in May 2013, the Texas Railroad Commission issued a “well integrity rule,” which updates the requirements for drilling, putting pipe down, and cementing wells. The rule also includes new testing and reporting requirements, such as: (i) the requirement to submit cementing reports after well completion or after cessation of drilling, whichever is later; and (ii) the imposition of additional testing on wells less than 1,000 feet below usable groundwater. The well integrity rule took effect in January 2014. Local governments also may seek to adopt ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular 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. If new laws or regulations that significantly restrict hydraulic fracturing 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 and sale for resale of oil and 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.

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 condensate and oil and natural gas liquids are not currently regulated and are made at market prices.

Drilling and Production

The operations of our operators 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 our operators 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 natural gas liquids 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 the acreage underlying our ORRIs 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

Historically, federal legislation and regulatory controls have affected the price and marketing of natural gas. FERC has jurisdiction over the transportation and sale for resale of natural gas in interstate commerce by natural gas companies under the Natural Gas Act of 1938 (“NGA”) and the Natural Gas Policy Act of 1978. Since 1978, various federal laws have been enacted which have resulted in the complete removal of all price and non-price controls for sales of domestic natural gas sold in “first sales.” Under the Energy Policy Act of 2005, FERC has substantial enforcement authority to prohibit the manipulation of natural gas markets and enforce its rules and orders, including the ability to assess substantial civil penalties.

FERC also regulates interstate natural gas transportation rates and service conditions and establishes the terms under which our operators may use interstate natural gas pipeline capacity, which affects the marketing of natural gas that our operators produce, as well as the revenues our operators receive for sales of natural gas and release of natural gas pipeline capacity. Commencing in 1985, FERC promulgated a series of orders, regulations and rule makings that significantly fostered competition in the business of transporting and marketing gas. Today, 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. However, the natural gas industry historically 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.

Under FERC’s current regulatory regime, transmission services must be provided on an open-access, nondiscriminatory basis at cost-based rates or at market-based rates if the transportation market at issue is sufficiently competitive. 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

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facilities from regulation by FERC as a natural gas company 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 has the tendency to increase our operators’ costs of transporting gas to point-of-sale locations.

Oil Sales and Transportation

Sales of crude oil, condensate and natural gas liquids 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 shippers requesting service on the same terms and under the same rates. When oil pipelines operate at full capacity, access is governed by prorationing provisions set forth in the pipelines’ published tariffs. Accordingly, we believe that access to oil pipeline transportation services generally will be available to our operators to the same extent as to our or their competitors.

State Regulation

Texas regulates the drilling for, and the production, gathering and sale of, oil and natural gas, including imposing severance taxes and requirements for obtaining drilling permits. Texas currently imposes a 4.6% severance tax on the market value of oil production and a 7.5% severance tax on the market value of natural gas production. States also regulate the method of developing new fields, the spacing and operation of wells and the prevention of waste of oil and natural gas resources. States may regulate rates of production and may establish maximum daily production allowables 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. The effect of these regulations may be to limit the amount of oil and natural gas that may be produced from our wells and to limit the number of wells or locations our operators 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 us.

Employees

We are managed and operated by the board of directors and executive officers of our general partner, who are also employees of Riverbend. However, neither we nor our subsidiary will have any employees. All of the employees that will conduct our business, including our executive officers, will be employed by our general partner.

As of March 31, 2015, Riverbend had 21 full time employees. Following the completion of this offering, our general partner will have full-time employees. None of Riverbend’s or our general partner’s employees are represented by labor unions or covered by any collective bargaining agreements. Riverbend and our general partner also hire independent contractors and consultants involved in land, technical, regulatory and other disciplines to assist their full time employees. Please read “Management” and “Certain Relationships and Related Party Transactions.”

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Facilities

Riverbend leases office space for our principal executive offices in Houston, Texas. We believe that these facilities are adequate for our current operations.

Legal Proceedings

Due to the nature of our business, we are, from time to time, involved in routine litigation or subject to disputes or claims related to our business activities. In the opinion of our management, there are no pending litigation, disputes or claims against us, if decided adversely, will have a material adverse effect on our financial condition, cash flows or results of operations.

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MANAGEMENT

Management of Royal Resources Partners LP

We are managed and operated by the board of directors and executive officers of our general partner.

Royal owns all the membership interests in our general partner. As a result of owning our general partner, Royal will have the right to appoint all members of the board of directors of our general partner, including the independent directors. Our unitholders will not be entitled to elect our general partner or its directors or otherwise directly participate in our management or operation. Our general partner owes certain duties to our unitholders as well as a fiduciary duty to its owner.

Upon the closing of this offering, we expect that our general partner will have six directors, of whom will be independent as defined under the independence standards established by the NYSE and the Exchange Act. In accordance with the rules of the NYSE, Royal will appoint one additional independent member within 90 days of the effective date of the registration statement of which this prospectus forms a part and one additional independent member within one year of such effective date, bringing the total number of directors on the board of directors of our general partner to eight. The NYSE does not require a listed publicly traded partnership, such as ours, to have a majority of independent directors on the board of directors of our general partner or to establish a compensation committee or a nominating and corporate governance committee. However, our general partner is required to have an audit committee of at least three members, and all its members are required to meet the independence and experience standards established by the NYSE and the Exchange Act, subject to the transitional relief during the one-year period following completion of this offering.

The executive officers of our general partner will manage the day-to-day affairs of our business. All of the executive officers of our general partner also serve as executive officers of Royal. Our executive officers listed below will allocate their time between managing our business and the business of Royal. Our executive officers intend, however, to devote as much time as is necessary for the proper conduct of our business.

Our partnership agreement requires us to reimburse our general partner and its affiliates, including Royal, for all expenses they incur and payments they make on our behalf in connection with operating our business. Our partnership agreement does not set a limit on the amount of expenses for which our general partner and its affiliates may be reimbursed. These expenses include salary, bonus, incentive compensation and other amounts paid to persons who perform services for us or on our behalf and expenses allocated to our general partner by its affiliates. Our partnership agreement provides that our general partner will determine the expenses that are allocable to us.

Executive Officers and Directors of Our General Partner

The following table shows information for the executive officers and directors of our general partner upon the consummation of this offering. Directors hold office until their successors have been elected or qualified or until the earlier of their death, resignation, removal or disqualification. Executive officers serve at the discretion of the board. There are no family relationships among any of our directors or executive officers.

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Randolph Newcomer, Jr.— Chief Executive Officer and Director. Mr. Newcomer serves as the Chief Executive Officer and President of Riverbend Oil & Gas, L.L.C. (and affiliates), a position he has held since forming Riverbend in 2003. Mr. Newcomer served as a Vice President of EnCap Investments L.P. (from 1997 to 2003, Houston) where he evaluated and co-managed a multitude of exploration and production financings involving mezzanine debt and equity investments. Mr. Newcomer began his career in 1989 at Amoco Production Company (Houston) serving in diverse production and reservoir engineering, business development, and acquisition and divestment roles (notably on the transaction support team associated with the formation of Altura Energy), with all Amoco service time associated with assets in the Permian Basin. He holds a B.S. in Petroleum Engineering from Texas A&M University and an Executive M.B.A. from the University of Houston. E&P companies that Mr. Newcomer has served and/or serves on the Board of Directors of Riverbend, Ovation Energy, Chalker Energy II & III, Navidad Resources and Parsley Energy, Inc. Furthermore, he has served or serves on the Board of Directors of Houston Producer’s Forum and the Advisory Boards of Yellowstone Academy and Stoney Creek Ranch. We believe that Mr. Newcomer’s experience as a chief executive officer of an oil and gas company, his broad knowledge of the industry and oil and gas investments, and his position as our Chief Executive Officer qualify him for service on our board of directors.

David Foley—Director. Mr. Foley is a Senior Managing Director in the Private Equity Group at The Blackstone Group, L.P. and is the Chief Executive Officer of Blackstone Energy Partners L.P. Mr. Foley currently leads Blackstone’s investment activities in the energy and natural resources sector. Since joining Blackstone in 1995, Mr. Foley has been responsible for building the Blackstone energy and natural resources practice and has been involved in every private equity energy deal that the firm has invested in. Before joining Blackstone, Mr. Foley worked with AEA Investors in that firm’s private equity business, and prior to that served as a consultant for the Monitor Company. Mr. Foley currently serves as a director of Kosmos Energy, PBF Energy Inc., Cheniere Energy Inc. and Cheniere Energy Partners, LP and several privately-held energy companies in which Blackstone is an equity investor. Mr. Foley received a Bachelor of Arts and a Master of Arts in Economics from Northwestern University and received a Master of Business Administration degree with distinction from Harvard Business School. Because of his broad knowledge of the industry and oil and gas investments, we believe Mr. Foley is well qualified to serve on our board of directors.

Angelo Acconcia—Director. Mr. Acconcia is a Senior Managing Director in the Private Equity Group at The Blackstone Group, L.P. Mr. Acconcia currently leads Blackstone’s private equity investment activities in the oil & gas sector on a global basis. Since joining Blackstone in 2004, Mr. Acconcia was involved in the execution of several Blackstone investments, including Graham Packaging, Ondeo Nalco, TRW Automotive and Texas Genco. Mr. Acconcia has been involved in every one of Blackstone’s oil and gas investments, including Alta Energy, GeoSouthern Energy, Kosmos Energy, LLOG Exploration, OSUM Oil Sands and Royal Resources L.P. Before joining Blackstone, Mr. Acconcia worked at Morgan Stanley & Company’s Investment Banking Division in their Global Energy and Mergers and Acquisitions departments in both the U.S. and Canada. Mr. Acconcia received an Honors degree in Business from Queen’s University in Canada, where he graduated with First Class Honors. Because of his broad knowledge of the industry and oil and gas investments, we believe Mr. Acconcia is well qualified to serve on our board of directors.

Director Independence

In accordance with the rules of the NYSE, Royal must appoint at least one independent director by the time our common units are first listed on the NYSE, one additional independent member within 90 days of the effective date of the registration statement of which this prospectus forms a part, and one additional independent member within one year of the effective date of the registration statement.

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Committees of the Board of Directors

The board of directors of our general partner will have an audit committee and a conflicts committee. We do not expect that we will have a compensation committee, but rather that the board of directors of our general partner will have authority over compensation matters.

Audit Committee

We are required to have an audit committee of at least three members, and all its members are required to meet the independence and experience standards established by the NYSE and Rule 10A-3 promulgated under the Exchange Act, subject to certain transitional relief during the one-year period following consummation of this offering as described above. The audit committee will assist the board of directors in its oversight of the integrity of our financial statements and our compliance with legal and regulatory requirements and partnership policies and controls. The audit committee will have the sole authority to retain and terminate our independent registered public accounting firm, approve all auditing services and related fees and the terms thereof performed by our independent registered public accounting firm, and pre-approve any non-audit services and tax services to be rendered by our independent registered public accounting firm. The audit committee will also be responsible for confirming the independence and objectivity of our independent registered public accounting firm. Our independent registered public accounting firm will be given unrestricted access to the audit committee and our management, as necessary.

Conflicts Committee

We expect that at least one independent member of the board of directors of our general partner will serve on a conflicts committee to review specific matters that the board believes may involve conflicts of interest and determines to submit to the conflicts committee for review. The conflicts committee will determine if the resolution of the conflict of interest is in our best interest. The members of the conflicts committee may not be officers or employees of our general partner or directors, officers or employees of its affiliates, including Royal, and must meet the independence standards established by the NYSE and the Exchange Act to serve on an audit committee of a board of directors, along with other requirements in our partnership agreement. Any matters approved by the conflicts committee will be conclusively deemed to be approved by us and all of our partners and not a breach by our general partner of any duties it may owe us or our unitholders.

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EXECUTIVE COMPENSATION AND OTHER INFORMATION

Compensation Discussion and Analysis

We are a new subsidiary of Royal, formed in November 2014, consisting of certain assets that Holdings is contributing to us in connection with this offering. Accordingly, neither we nor our general partner incurred any cost or liability with respect to management compensation or retirement benefits for directors or executive officers for any periods prior to our formation date. As a result, we have no historical compensation information to present. We currently do not have a compensation committee.

Our general partner has the sole responsibility for conducting our business and for managing our operations, and its board of directors and executive officers make decisions on our behalf. We do not and will not directly employ any of the persons responsible for managing our business. Our executive officers will be employed and compensated by our general partner. All of the initial executive officers that will be responsible for managing our day-to-day affairs are also current employees of Riverbend.

All of the executive officers of our general partner will have responsibilities to both us and Royal, and we expect that our executive officers will allocate their time between managing our business and managing the business of Royal. Since all of our executive officers will be employed by Royal or one of its subsidiaries, the responsibility and authority for compensation-related decisions for our executive officers will reside with the Royal compensation committee. Royal has the ultimate decision-making authority with respect to the total compensation of the executive officers that are employed by Royal including, subject to the terms of the partnership agreement, the portion of that compensation that is allocated to us pursuant to Royal’s allocation methodology. Any such compensation decisions will not be subject to any approvals by the board of directors of our general partner or any committees thereof. However, all determinations with respect to any awards that may be made to our executive officers, key employees, and independent directors under any long-term incentive plan we adopt will be made by the board of directors of our general partner or a committee thereof that may be established for such purpose. Please see the description of the long-term incentive plan we intend to adopt prior to the completion of this offering below under the heading “—Long-Term Incentive Plan.”

The executive officers of our general partner, as well as the employees of Royal who provide services to us, may participate in employee benefit plans and arrangements sponsored by Royal, including plans that may be established in the future. Except with respect to any awards that may be granted under the long-term incentive plan we intend to adopt prior to the completion of this offering, our executive officers will not receive separate amounts of compensation in relation to the services they provide to us. In accordance with the terms of our partnership agreement, we will reimburse Royal for compensation related expenses attributable to the portion of the executive’s time dedicated to providing services to us. Please read “The Partnership Agreement—Reimbursement of Expenses.” Although we will bear an allocated portion of Royal’s costs of providing compensation and benefits to employees who serve as executive officers of our general partner, we will have no control over such costs and will not establish or direct the compensation policies or practices of Royal. Except with respect to any awards granted under the long-term incentive plan we intend to adopt prior to the completion of this offering, we expect that compensation paid or awarded by us in 2015 will consist only of the portion of compensation paid by Royal that is allocated to us and our general partner pursuant to Royal’s allocation methodology and subject to the terms of the partnership agreement.

We expect that future compensation for our executive officers will be structured in a manner similar to that currently used by Royal to compensate its named executive officers. If additional details regarding the terms of future compensatory arrangements for our executive officers are known prior to the effective date of this offering, such details will be outlined in further detail herein. In the future, as Royal and our general partner formulate and implement the compensation programs for our executive officers, Royal, our general partner or both may provide different or additional compensation components, benefits or perquisites to our executive officers, to ensure they are provided with a balanced, comprehensive and competitive compensation structure.

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Long-Term Incentive Plan

In order to incentivize our management and directors following the completion of this offering to continue to grow our business, the board of directors of our general partner intends to adopt a long-term incentive plan, or the “LTIP,” for employees, officers, consultants and directors of our general partner and any of its affiliates, including Royal, who perform services for us. Our general partner intends to implement the LTIP prior to the completion of this offering to provide maximum flexibility with respect to the design of compensatory arrangements for individuals providing services to us; however, at this time, neither we nor our general partner has made any decisions regarding any specific grants under the LTIP in conjunction with this offering or in the near term, other than grants in connection with the appointment of non-employee directors

The description of the LTIP set forth below is a summary of the material features of the LTIP that our general partner intends to adopt. This summary, however, does not purport to be a complete description of all the provisions of the LTIP that will be adopted and represents only the general partner’s current expectations regarding the LTIP. This summary is qualified in its entirety by reference to the LTIP, the form of which will be filed as an exhibit to this registration statement. The purpose of the LTIP is to provide a means to attract and retain individuals who are essential to our growth and profitability and to encourage them to devote their best efforts to advancing our business by affording such individuals a means to acquire and maintain ownership of awards, the value of which is tied to the performance of our common units. We expect that the LTIP will provide for the grant of unit options, unit appreciation rights, restricted units, unit awards, phantom units, distribution equivalent rights, cash awards, performance awards, other unit-based awards and substitute awards (collectively, “awards”). These awards are intended to align the interests of employees, officers, consultants and directors with those of our unitholders and to give such individuals the opportunity to share in our long-term performance. Any awards that are made under the LTIP will be approved by the board of directors of our general partner or a committee thereof that may be established for such purpose. We will be responsible for the cost of awards granted under the LTIP.

Administration

The LTIP will be administered by the board of directors of our general partner or an alternative committee appointed by the board of directors of our general partner, which we refer to together as the “committee” for purposes of this summary. The committee will administer the LTIP pursuant to its terms and all applicable state, federal, or other rules or laws. The committee will have the power to determine to whom and when awards will be granted, determine the amount of awards (measured in cash or in shares of our common units), proscribe and interpret the terms and provisions of each award agreement (the terms of which may vary), accelerate the vesting provisions associated with an award, delegate duties under the LTIP and execute all other responsibilities permitted or required under the LTIP. In the event that the committee is not comprised of “nonemployee directors” within the meaning of Rule 16b-3 under the Exchange Act, the full board of directors or a subcommittee of two or more nonemployee directors will administer all awards granted to individuals that are subject to Section 16 of the Exchange Act.

Securities to be Offered

The maximum aggregate number of common units that may be issued pursuant to any and all awards under the LTIP shall not exceed common units, subject to adjustment due to recapitalization or reorganization, or related to forfeitures or expiration of awards, as provided under the LTIP.

If any common units subject to any award are not issued or transferred, or cease to be issuable or transferable for any reason, including (but not exclusively) because units are withheld or surrendered in payment of taxes or any exercise or purchase price relating to an award or because an award is forfeited, terminated, expires unexercised, is settled in cash in lieu of common units, or is otherwise terminated without a delivery of units, those common units will again be available for issue, transfer, or exercise pursuant to awards under the

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LTIP, to the extent allowable by law. Common units to be delivered pursuant to awards under our LTIP may be common units acquired by our general partner in the open market, from any other person, directly from us, or any combination of the foregoing.

Awards

Unit Options

We may grant unit options to eligible persons. Unit options are rights to acquire common units at a specified price. The exercise price of each unit option granted under the LTIP will be stated in the unit option agreement and may vary; provided, however, that, the exercise price for an unit option must not be less than 100% of the fair market value per common unit as of the date of grant of the unit option unless that unit option is intended to otherwise comply with the requirements of Section 409A of the Internal Revenue Code of 1986, as amended (the “Code”). Unit options may be exercised in the manner and at such times as the committee determines for each unit option, unless that unit option is determined to be subject to Section 409A of the Code, in which case the unit option will be subject to any necessary timing restrictions imposed by the Code or federal regulations. The committee will determine the methods and form of payment for the exercise price of a unit option and the methods and forms in which common units will be delivered to a participant.

Unit Appreciation Rights

A unit appreciation right is the right to receive, in cash or in common units, as determined by the committee, an amount equal to the excess of the fair market value of one common unit on the date of exercise over the grant price of the unit appreciation right. The committee will be able to make grants of unit appreciation rights and will determine the time or times at which a unit appreciation right may be exercised in whole or in part. The exercise price of each unit appreciation right granted under the LTIP will be stated in the unit appreciation right agreement and may vary; provided, however, that, the exercise price must not be less than 100% of the fair market value per common unit as of the date of grant of the unit appreciation right, unless that unit appreciation right is intended to otherwise comply with the requirements of Section 409A of the Code.

Restricted Units

A restricted unit is a grant of a common unit subject to a risk of forfeiture, performance conditions, restrictions on transferability and any other restrictions imposed by the committee in its discretion. Restrictions may lapse at such times and under such circumstances as determined by the committee. The committee shall provide, in the restricted unit agreement, whether the restricted unit will be forfeited upon certain terminations of employment. Unless otherwise determined by the committee, a common unit distributed in connection with a unit split or unit dividend, and other property distributed as a dividend, will generally be subject to restrictions and a risk of forfeiture to the same extent as the restricted unit with respect to which such common unit or other property has been distributed.

Unit Awards

The committee will be authorized to grant common units that are not subject to restrictions. The committee may grant unit awards to any eligible person in such amounts as the committee, in its sole discretion, may select.

Phantom Units

Phantom units are rights to receive common units, cash or a combination of both at the end of a specified period. The committee may subject phantom units to restrictions (which may include a risk of forfeiture) to be specified in the phantom unit agreement that may lapse at such times determined by the committee. Phantom units may be satisfied by delivery of common units, cash equal to the fair market value of the specified number of common units covered by the phantom unit or any combination thereof determined by the committee. Except

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as otherwise provided by the committee in the phantom unit agreement or otherwise, phantom units subject to forfeiture restrictions may be forfeited upon termination of a participant’s employment prior to the end of the specified period. Cash distribution equivalents may be paid during or after the vesting period with respect to a phantom unit, as determined by the committee.

Distribution Equivalent Rights

The committee will be able to grant distribution equivalent rights in tandem with awards under the LTIP (other than unit awards or an award of restricted units), or distribution equivalent rights may be granted alone. Distribution equivalent rights entitle the participant to receive cash equal to the amount of any cash distributions made by us during the period the distribution equivalent right is outstanding. Payment of cash distributions pursuant to a distribution equivalent right issued in connection with another award may be subject to the same vesting terms as the award to which it relates or different vesting terms, in the discretion of the committee.

Cash Awards

The LTIP will permit the grant of awards denominated and settled in cash. Cash awards may be based, in whole or in part, on the value or performance of a common unit.

Performance Awards

The committee may condition the right to exercise or receive an award under the LTIP, or may increase or decrease the amount payable with respect to an award, based on the attainment of one or more performance conditions deemed appropriate by the committee.

Other Unit-Based Awards

The LTIP will permit the grant of other unit-based awards, which are awards that may be based, in whole or in part, on the value or performance of a common unit or are denominated or payable in common units. Upon settlement, these other unit-based awards may be paid in common units, cash or a combination thereof, as provided in the award agreement.

Substitute Awards

The LTIP will permit the grant of awards in substitution for similar awards held by individuals who become employees, consultants or directors as a result of a merger, consolidation, or acquisition by or involving us, an affiliate of another entity, or the assets of another entity. Such substitute awards that are unit options or unit appreciation rights may have exercise prices less than 100% of the fair market value per common unit on the date of the substitution if such substitution complies with Section 409A of the Code and its regulations and other applicable laws and exchange rules.

Miscellaneous

Tax Withholding

At our discretion, and subject to conditions that the committee may impose, a participant’s minimum statutory tax withholding with respect to an award may be satisfied by withholding from any payment related to an award or by the withholding of common units issuable pursuant to the award based on the fair market value of the common units.

Anti-Dilution Adjustments

If any “equity restructuring” event occurs that could result in an additional compensation expense under Financial Accounting Standards Board Accounting Standards Codification Topic 718 (“FASB ASC Topic 718”)

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if adjustments to awards with respect to such event were discretionary, the committee will equitably adjust the number and type of units covered by each outstanding award and the terms and conditions of each such award to equitably reflect the restructuring event. With respect to a similar event that would not result in a FASB ASC Topic 718 accounting charge if adjustment to awards were discretionary, the committee shall have complete discretion to adjust awards in the manner it deems appropriate. In the event the committee makes any adjustment in accordance with the foregoing provisions, a corresponding and proportionate adjustment shall be made with respect to the maximum number of units available under the LTIP and the kind of units or other securities available for grant under the LTIP. Furthermore, in the case of (i) a subdivision or consolidation of the common units (by reclassification, split or reverse split or otherwise), (ii) a recapitalization, reclassification, or other change in our capital structure or (iii) any other reorganization, merger, combination, exchange, or other relevant change in capitalization of our equity, then a corresponding and proportionate adjustment shall be made in accordance with the terms of the LTIP, as appropriate, with respect to the maximum number of units available under the LTIP, the number of units that may be acquired with respect to an award, and, if applicable, the exercise price of an award, in order to prevent dilution or enlargement of awards as a result of such events.

Change in Control

Upon a “change in control” (as defined in the LTIP), the committee may, in its discretion, (i) remove any forfeiture restrictions applicable to an award, (ii) accelerate the time of exercisability or vesting of an award, (iii) require awards to be surrendered in exchange for a cash payment, (iv) cancel unvested awards without payment or (v) make adjustments to awards as the committee deems appropriate to reflect the change in control.

Termination of Employment or Service

The consequences of the termination of a participant’s employment, consulting arrangement or membership on the board of directors will be determined by the committee in the terms of the relevant award agreement.

Director Compensation

We and our general partner were formed in November 2014 and, as such, have not accrued or paid any obligations with respect to compensation for directors for any periods prior to our formation date.

The executive officers or employees of our general partner or of Royal who also serve as directors of our general partner will not receive additional compensation for their service as a director of our general partner. Directors of our general partner who are not executive officers or employees of our general partner or of Royal will receive compensation as “non-employee directors” as set by our general partner’s board of directors.

Effective as of the closing of this offering, each non-employee director will receive a compensation package that will consist of an annual cash retainer of $ plus an additional annual payment of $ for the chairperson and $ for each other member of the audit committee and $ for the chairperson and $ for each other member of each other committee. In addition, our directors will be reimbursed for out-of-pocket expenses in connection with attending meetings of the board of directors or its committees. Each non-employee director may receive grants of equity-based awards under the long-term incentive plan we intend to adopt prior to the completion of this offering from time to time for so long as he or she serves as a director.

Each member of the board of directors of our general partner will be indemnified for his actions associated with being a director to the fullest extent permitted under Delaware law.

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SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

The following table presents information regarding the beneficial ownership of our common units following this offering and the other formation transactions by:

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our general partner;

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each of our general partner’s directors and executive officers;

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each unitholder known by us to beneficially hold 5% or more of our common units; and

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all of our general partner’s directors and executive officers as a group.

Beneficial ownership is determined under the rules of the SEC and generally includes voting or investment power with respect to securities. Unless otherwise noted, the address for each beneficial owner listed below is One Allen Center, 500 Dallas Street, Suite 1200, Houston, Texas 77002.


Name of Beneficial Owner	Common Units Beneficially Owned		Percentage of Common Units Beneficially Owned			Subordinated Units Beneficially Owned		Percentage of Subordinated Units Beneficially Owned			Percentage of Common and Subordinated Units Beneficially Owned
Royal Resources L.P.(1)(2)					%				100	%			%
Royal Resources Partners GP, LLC		—		—			—		—			—
Randolph Newcomer, Jr.					%								%
David Foley(3)					%								%
Angelo Acconcia(3)					%								%
													%
All directors and executive officers as a group ( persons)					%								%

*	Less than 1%

(1)	The table assumes the underwriters do not exercise their option to purchase additional common units and such units are therefore issued to Royal upon the option’s expiration. If such option is exercised in full, Royal will beneficially own common units, or % of total common units outstanding.

(2)

The sole general partner of Royal Resources L.P. is Royal Resources GP L.L.C., a Delaware limited liability company (“Royal GP”). The Series A Members of Royal GP have the right to appoint 100% of the members of the board of Royal GP. The Series A Members of Royal GP consist of Blackstone Management Associates VI L.L.C. and Blackstone Energy Management Associates L.L.C. BMA VI L.L.C., a Delaware limited liability company, is the sole member of Blackstone Management Associates VI L.L.C. Blackstone EMA VI L.L.C., a Delaware limited liability company, is the sole member of Blackstone Energy Management Associates L.L.C. Blackstone Holdings III L.P., a Québec limited partnership, is the managing member of both BMA VI L.L.C. and Blackstone EMA L.L.C. Blackstone Holdings III GP L.P., a Delaware limited partnership, is the general partner of Blackstone Holdings III L.P. Blackstone Holdings III GP Management L.L.C., a Delaware limited liability company, is the general partner of Blackstone Holdings III GP L.P. The Blackstone Group L.P., a Delaware limited partnership, is the sole member of Blackstone Holdings III GP Management L.L.C. The general partner of The Blackstone Group L.P. is Blackstone Group Management L.L.C., a Delaware limited liability company. Blackstone Group Management L.L.C. is wholly owned by Blackstone’s senior managing directors and controlled by its founder, Stephen A. Schwarzman.

(3)	The address for this beneficial owner is 345 Park Avenue, New York, New York 10154.

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CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

After this offering, assuming that the underwriters do not exercise their option to purchase additional common units, Royal will own common units and subordinated units representing an aggregate approximately % limited partner interest in us (excluding the incentive distribution rights, which cannot be expressed as a fixed percentage), and will own and control our general partner. Royal will also appoint all of the directors of our general partner, which will own a non-economic general partner interest in us and will own the incentive distribution rights.

The terms of the transactions and agreements disclosed in this section were determined by and among affiliated entities and, consequently, are not the result of arm’s length negotiations. These terms are not necessarily at least as favorable to the parties to these transactions and agreements as the terms that could have been obtained from unaffiliated third parties.

Distributions and Payments to Royal and Its Affiliates

The following table summarizes the distributions and payments made or to be made by us to Royal and its affiliates (including our general partner) in connection with the formation, ongoing operation and any liquidation of Royal.

Formation Stage


The consideration received by Royal and its affiliates for the contribution of their interests in DGK		common units subordinated units our incentive distribution rights; and We will distribute the $ million of net proceeds from this offering (after deducting the underwriting discounts and the expenses of this offering) to Royal. To the extent the underwriters exercise their option to purchase additional common units, we will issue such units to the public and distribute the net proceeds to Royal. Any common units not purchased by the underwriters pursuant to their option will be issued to Royal.

Operational Stage

Distributions of cash available for distribution to our general partner and its affiliates		We will generally make cash distributions 100% to our unitholders, including affiliates of our general partner. In addition, if distributions exceed the minimum quarterly distribution and other higher target distribution levels, our general partner will be entitled to increasing percentages of the distributions, up to 25% of the distributions above the highest target distribution level. Assuming we have sufficient cash available for distribution to pay the full minimum quarterly distribution on all of our outstanding common units and subordinated units for four quarters, our general partner and its affiliates would receive an annual distribution of approximately $ million on their units.

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Payments to our general partner and its affiliates		Our general partner will not receive a management fee or other compensation for its management of our partnership, but we will reimburse our general partner and its affiliates for all direct and indirect expenses they incur and payments they make on our behalf. Our partnership agreement does not set a limit on the amount of expenses for which our general partner and its affiliates may be reimbursed. These expenses include salary, bonus, incentive compensation and other amounts paid to persons who perform services for us or on our behalf and expenses allocated to our general partner by its affiliates. Our partnership agreement provides that our general partner will determine the expenses that are allocable to us.

Withdrawal or removal of our general partner		If our general partner withdraws or is removed, its non-economic general partner interest will either be sold to the new general partner for cash or converted into common units, in each case for an amount equal to the fair market value of those interests. Please read “The Partnership Agreement—Withdrawal or Removal of Our General Partner.”

Liquidation Stage

Liquidation		Upon our liquidation, the partners, including our general partner, will be entitled to receive liquidating distributions according to their respective capital account balances.

Agreements and Transactions with Affiliates in Connection with this Offering

In connection with this offering, we will enter into certain agreements and transactions with Royal and its affiliates, as described in more detail below.

Contribution Agreement

In connection with the closing of this offering, we will enter into a contribution agreement that will effect the transactions, including the transfer of the ownership interests in DGK to us, and the use of the net proceeds of this offering. While we believe this agreement is on terms no less favorable to any party than those that could have been negotiated with an unaffiliated third party, it will not be the result of arm’s-length negotiations. All of the transaction expenses incurred in connection with these transactions will be paid from the proceeds of this offering.

Registration Rights Agreement

In connection with this offering, we will enter into a registration rights agreement with Royal and Holdings pursuant to which we may be required to register the sale of the (i) common units issued (or issuable) to Royal pursuant to the contribution agreement, (ii) subordinated units and (iii) common units issuable upon conversion of the subordinated units pursuant to the terms of the partnership agreement (together, the “Registrable Securities”) it holds. Under the registration rights agreement, Royal and Holdings will have the right to request that we register the sale of Registrable Securities held by them, and Royal and Holdings will have the right to require us to make available shelf registration statements permitting sales of Registrable Securities into the market from time to time over an extended period, subject to certain limitations. In addition, the registration rights agreement gives Royal and Holdings piggyback registration rights under certain circumstances. The

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registration rights agreement also includes provisions dealing with indemnification and contribution and allocation of expenses. All of the Registrable Securities held by Royal and Holdings and their permitted transferees will be entitled to these registration rights.

Management Fees

We paid monitoring fees (referred to as “management fees” in the accompanying financial statements) approximately $1.2 million and $2.4 million to Blackstone Management Partners L.L.C. during the years ended December 31, 2013 and 2014, respectively. Blackstone Management Partners L.L.C. is the registered investment adviser that advises the Blackstone funds that indirectly hold interests in us.

Procedures for Review, Approval and Ratification of Transactions with Related Persons

We expect that the board of directors of our general partner will adopt policies for the review, approval and ratification of transactions with related persons. We anticipate the board will adopt a written code of business conduct and ethics, under which a director would be expected to bring to the attention of the chief executive officer or the board any conflict or potential conflict of interest that may arise between the director or any affiliate of the director, on the one hand, and us or our general partner on the other. The resolution of any such conflict or potential conflict should, at the discretion of the board in light of the circumstances, be determined by a majority of the disinterested directors.

If a conflict or potential conflict of interest arises between our general partner or its affiliates, on the one hand, and us or our unitholders, on the other hand, the resolution of any such conflict or potential conflict should be addressed by the board of directors of our general partner in accordance with the provisions of our partnership agreement. At the discretion of the board in light of the circumstances, the resolution may be determined by the board in its entirety or by a conflicts committee meeting the definitional requirements for such a committee under our partnership agreement.

Upon our adoption of our code of business conduct and ethics, we would expect that any executive officer will be required to avoid conflicts of interest unless approved by the board of directors of our general partner.

Please read “Conflicts of Interest and Fiduciary Duties—Conflicts of Interest” for additional information regarding the relevant provisions of our partnership agreement.

The code of business conduct and ethics described above will be adopted in connection with the closing of this offering, and as a result, the transactions described above were not reviewed according to such procedures.

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CONFLICTS OF INTEREST AND FIDUCIARY DUTIES

The Delaware Act, provides that Delaware limited partnerships may, in their partnership agreements, expand, restrict or eliminate the fiduciary duties otherwise owed by the general partner to the limited partners and the partnership. Our partnership agreement contains provisions that eliminate and replace the fiduciary standards to which our general partner would otherwise be held by state fiduciary duty law. Our partnership agreement also specifically defines the remedies available to unitholders for actions taken that, without these defined liability standards, might constitute breaches of fiduciary duty under applicable Delaware law.

When our general partner is acting in its capacity as our general partner, as opposed to in its individual capacity, it must act in “good faith,” meaning it must not act in a manner that it believes is adverse to our interest. This duty to act in good faith is the default standard set forth under our partnership agreement and our general partner will not be subject to any higher standard.

Our partnership agreement specifies decisions that our general partner may make in its individual capacity, and permits our general partner to make these decisions free of any contractual or other duty to us or our unitholders. This entitles our general partner to consider only the interests and factors that it desires, and it has no duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or any limited partner. Examples include the exercise of its call right, its voting rights with respect to any units it owns, its registration rights and its determination whether or not to consent to any merger or consolidation or amendment of the partnership agreement.

When the directors and officers of our general partner cause our general partner to manage and operate our business, the directors and officers must cause our general partner to act in a manner consistent with our general partner’s applicable duties. However, the directors and officers of our general partner have fiduciary duties to manage our general partner, including when it is acting in its capacity as our general partner, in a manner beneficial to Royal.

Conflicts may arise as a result of the duties of our general partner and its directors and officers to act for the benefit of its owners, which may conflict with our interests and the interests of our public unitholders. Where the directors and officers of our general partner are causing our general partner to act in its capacity as our general partner, the directors and officers must cause the general partner to act in good faith, meaning they cannot cause the general partner to take an action that they believe is adverse to our interest. However, where a decision by our general partner in its capacity as our general partner is not clearly not adverse to our interest, the directors of our general partner may determine to submit the determination to the conflicts committee for review or to seek approval by the unitholders, as described below.

Conflicts of Interest

Conflicts of interest exist and may arise in the future as a result of the relationships between our general partner and its directors, executive officers and owners (including Royal), on the one hand, and us and our limited partners, on the other hand.

Whenever a conflict arises between our general partner or its owners, on the one hand, and us or our limited partners, on the other hand, the resolution, course of action or transaction in respect of such conflict of interest shall be conclusively deemed approved by us and all our limited partners and shall not constitute a breach of our partnership agreement, of any agreement contemplated thereby or of any duty, if the resolution or course of action or transaction in respect of such conflict of interest is:

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approved by the conflicts committee of our general partner; or

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approved by the holders of a majority of the outstanding common units, excluding any such units owned by our general partner or any of its affiliates.

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Our general partner may, but is not required to, seek the approval of such resolutions or courses of action from the conflicts committee of its board of directors or from the holders of a majority of the outstanding common units as described above. If our general partner does not seek approval from the conflicts committee or from holders of common units as described above and the board of directors of our general partner approves the resolution or course of action taken with respect to the conflict of interest, then it will be presumed that, in making its decision, the board of directors of our general partner acted in good faith, and in any proceeding brought by or on behalf of us or any of our unitholders, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption and proving that such decision was not in good faith. Unless the resolution of a conflict is specifically provided for in our partnership agreement, the board of directors of our general partner or the conflicts committee of the board of directors of our general partner may consider any factors they determine in good faith to consider when resolving a conflict. An independent third party is not required to evaluate the resolution. Under our partnership agreement, all determinations, other actions or failures to act by our general partner, the board of directors of our general partner or any committee thereof (including the conflicts committee) will be presumed to be “in good faith,” and in any proceeding brought by or on behalf of us or any of our unitholders, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption and proving that such decision was not in good faith. Please read “Management—Committees of the Board of Directors—Conflicts Committee” for information about the conflicts committee of our general partner’s board of directors.

Conflicts of interest could arise in the situations described below, among others:

Actions taken by our general partner may affect the amount of cash available to pay distributions to unitholders or accelerate the right to convert subordinated units.

The amount of cash that is available for distribution to unitholders is affected by decisions of our general partner regarding such matters as:

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amount and timing of asset purchases and sales;

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cash expenditures;

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borrowings;

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entry into and repayment of current and future indebtedness;

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issuance of additional units; and

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the creation, reduction or increase of reserves in any quarter.

In addition, borrowings by us and our affiliates do not constitute a breach of any duty owed by our general partner to our unitholders, including borrowings that have the purpose or effect of:

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enabling our general partner or its affiliates to receive distributions on any subordinated units held by them or the incentive distribution rights; or

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hastening the expiration of the subordination period.

In addition, our general partner may use an amount, initially equal to $ million, which would not otherwise constitute operating surplus, in order to permit the payment of distributions on subordinated units and the incentive distribution rights. All of these actions may affect the amount of cash distributed to our unitholders and our general partner and may facilitate the conversion of subordinated units into common units. Please read “How We Make Distributions.”

For example, in the event we have not generated sufficient cash from our operations to pay the minimum quarterly distribution on our common units and our subordinated units, our partnership agreement permits us to

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borrow funds, which would enable us to make such distribution on all outstanding units. Please read “How We Make Distributions—Operating Surplus and Capital Surplus—Operating Surplus.”

The directors and executive officers of our general partner who are also officers and directors of Royal have a fiduciary duty to make decisions in the best interests of the owners of Royal, which may be contrary to our interests.

The executive officers and certain directors of our general partner are also officers and directors of Royal. These officers and directors have fiduciary duties to Royal that may cause them to pursue business strategies that disproportionately benefit Royal or which otherwise are not in our best interests.

Our general partner is allowed to take into account the interests of parties other than us, such as Royal, in exercising certain rights under our partnership agreement.

Our partnership agreement contains provisions that replace the standards to which our general partner would otherwise be held by state fiduciary duty law. For example, our partnership agreement permits our general partner to make a number of decisions in its individual capacity, as opposed to in its capacity as our general partner. This entitles our general partner to consider only the interests and factors that it desires, and it has no duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or any limited partner. Examples include the exercise of its call right, its voting rights with respect to any units it owns, its registration rights and its determination whether or not to consent to any merger or consolidation of the partnership or amendment of the partnership agreement.

Our partnership agreement restricts the remedies available to our unitholders for actions that, without the limitations, might constitute breaches of fiduciary duty.

In addition to the provisions described above, our partnership agreement contains provisions that have the effect of restricting the remedies available to our unitholders for actions that might otherwise constitute breaches of fiduciary duty. For example, our partnership agreement provides that:

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our general partner will not have any liability to us or our unitholders for decisions made in its capacity as general partner so long as it acted in good faith, meaning it believed that the decision was not adverse to the interest of the partnership, and, with respect to criminal conduct, did not act with the knowledge that its conduct was unlawful;

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our general partner and its officers and directors will not be liable for monetary damages or otherwise to us or our limited partners for any losses sustained or liabilities incurred as a result of the general partner’s, officer’s or director’s determinations, acts or omissions in their capacities as general partner, officers or directors, unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that such losses or liabilities were the result of the conduct of our general partner or such officer or director engaged by it in bad faith or, with respect to any criminal conduct, with the knowledge that its conduct was unlawful; and

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in resolving conflicts of interest, it will be presumed that in making its decision our general partner, the board of directors of our general partner or the conflicts committee of the board of directors of our general partner acted in good faith, and in any proceeding brought by or on behalf of any limited partner or us, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption and proving that such decision was not in good faith.

By purchasing a common unit, a common unitholder will agree to become bound by the provisions in our partnership agreement, including the provisions discussed above. Please read “—Fiduciary Duties.”

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Common unitholders have no right to enforce obligations of our general partner and its affiliates under agreements with us.

Any agreements between us, on the one hand, and our general partner and its affiliates, on the other, will not grant to the unitholders, separate and apart from us, the right to enforce the obligations of our general partner and its affiliates in our favor.

Contracts between us, on the one hand, and our general partner and its affiliates, on the other, are not and will not be the result of arm’s-length negotiations.

Neither our partnership agreement nor any of the other agreements, contracts and arrangements between us and our general partner and its affiliates are or will be the result of arm’s-length negotiations. Our general partner will determine, in good faith, the terms of any of such future transactions.

Except in limited circumstances, our general partner has the power and authority to conduct our business without unitholder approval.

Under our partnership agreement, our general partner has full power and authority to do all things, other than those items that require unitholder approval, necessary or appropriate to conduct our business including, but not limited to, the following actions:

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expending, lending, or borrowing money, assuming, guaranteeing, or otherwise contracting for, indebtedness and other liabilities, issuing evidences of indebtedness, including indebtedness that is convertible into our securities, and incurring any other obligations;

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preparing and transmitting tax, regulatory and other filings, periodic or other reports to governmental or other agencies having jurisdiction over our business or assets;

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acquiring, disposing, mortgaging, pledging, encumbering, hypothecating, or exchanging our assets or merging or otherwise combining us with or into another person;

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negotiating, executing and performing contracts, conveyance or other instruments;

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distributing cash or cash equivalents;

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selecting or dismissing employees and agents, outside attorneys, accountants, consultants and contractors and determining their compensation and other terms of employment or hiring;

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maintaining insurance for our benefit;

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forming, acquiring an interest in, and contributing property and loaning money to, any further limited partnerships, joint ventures, corporations, limited liability companies or other entities;

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controlling all matters affecting our rights and obligations, including bringing and defending actions at law or in equity or otherwise litigating, arbitrating or mediating, and incurring legal expense and settling claims and litigation;

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indemnifying any person against liabilities and contingencies to the extent permitted by law;

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purchasing, selling or otherwise acquiring or disposing of our partnership interests, or issuing additional options, rights, warrants, appreciation rights, phantom or tracking interests relating to our partnership interests; and

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entering into agreements with any of its affiliates to render services to us or to itself in the discharge of its duties as our general partner.

Please read “The Partnership Agreement” for information regarding the voting rights of unitholders.

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Our general partner determines which of the costs it incurs on our behalf are reimbursable by us.

We will reimburse our general partner and its affiliates for the costs incurred in managing and operating us, including costs incurred in rendering corporate staff and support services to us. Our partnership agreement provides that our general partner will determine such other expenses that are allocable to us, and neither the partnership agreement nor the advisory services agreement limits the amount of expenses for which our general partner and its affiliates may be reimbursed. Please read “Certain Relationships and Related Party Transactions—Agreements and Transactions with Affiliates in Connection with this Offering.”

Common units are subject to our general partner’s call right.

If at any time our general partner and its affiliates own more than 80% of the common units, our general partner will have the right, which it may assign to any of its affiliates or to us, but not the obligation, to acquire all, but not less than all, of the common units held by unaffiliated persons at the price calculated in accordance with our partnership agreement. Please read “Risk Factors—Risks Inherent in an Investment in Us—Our general partner has a call right that may require unitholders to sell their common units at an undesirable time or price.” and “The Partnership Agreement—Limited Call Right.”

We may choose to not retain separate counsel for ourselves or for the holders of common units.

The attorneys, independent accountants and others who perform services for us have been retained by our general partner. Attorneys, independent accountants and others who perform services for us are selected by our general partner or the conflicts committee of the board of directors of our general partner and may perform services for our general partner and its affiliates. We may retain separate counsel for ourselves or the conflict committee in the event of a conflict of interest between our general partner and its affiliates, on the one hand, and us or the holders of common units, on the other, depending on the nature of the conflict, although we may choose not to do so.

Our general partner’s affiliates may compete with us, and neither our general partner nor its affiliates have any obligation to present business opportunities to us.

Our partnership agreement provides that our general partner is restricted from engaging in any business activities other than acting as our general partner, engaging in activities incidental to its ownership interest in us and providing management, advisory, and administrative services to its affiliates or to other persons. However, affiliates of our general partner, including Royal and Riverbend, are not prohibited from engaging in other businesses or activities, including those that might be in direct competition with us. In addition, Royal and Riverbend may compete with us for investment opportunities and may own an interest in entities that compete with us. Pursuant to the terms of our partnership agreement, the doctrine of corporate opportunity, or any analogous doctrine, does not apply to our general partner or any of its affiliates, including its executive officers and directors and Royal and Riverbend. Any such person or entity that becomes aware of a potential transaction, agreement, arrangement or other matter that may be an opportunity for us will not have any duty to communicate or offer such opportunity to us. Any such person or entity will not be liable to us or to any limited partner for breach of any fiduciary duty or other duty by reason of the fact that such person or entity pursues or acquires such opportunity for itself, directs such opportunity to another person or entity or does not communicate such opportunity or information to us.

The holder or holders of our IDRs may elect to cause us to issue common units to it in connection with a resetting of target distribution levels related to the IDRs, without the approval of the conflicts committee of our general partner’s board of directors or the holders of our common units. This could result in lower distributions to holders of our common units.

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target distribution levels at higher levels based on our cash distribution levels at the time of the exercise of the reset election. Following a reset election, the reset minimum quarterly distribution will be calculated and the target distribution levels will be reset to correspondingly higher levels based on percentage increases above the reset minimum quarterly distribution.

Fiduciary Duties

Duties owed to unitholders by our general partner are prescribed by law and in our partnership agreement. The Delaware Act provides that Delaware limited partnerships may, in their partnership agreements, expand, restrict or eliminate the fiduciary duties otherwise owed by the general partner to limited partners and the partnership.

Our partnership agreement contains various provisions modifying and restricting the fiduciary duties that might otherwise be owed by our general partner. We have adopted these provisions to allow our general partner or its affiliates to engage in transactions with us that otherwise might be prohibited by state law fiduciary standards and to take into account the interests of other parties in addition to our interests when resolving conflicts of interest. We believe this is appropriate and necessary because the board of directors of our general partner has a duty to manage our partnership in good faith and a duty to manage our general partner in a manner beneficial to its owner. Without these modifications, our general partner’s ability to make decisions involving conflicts of interest would be restricted. The modifications to the fiduciary standards benefit our general partner by enabling it to take into consideration all parties involved in the proposed action. These modifications also strengthen the ability of our general partner to attract and retain experienced and capable directors. These modifications represent a detriment to our public unitholders because they restrict the remedies available to our public unitholders for actions that, without those limitations, might constitute breaches of fiduciary duty, as described below, and permit our general partner to take into account the interests of third parties in addition to our interests when resolving conflicts of interests.

The following is a summary of:

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the default fiduciary duties under by the Delaware Act;

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the standards contained in our partnership agreement that replace the default fiduciary duties; and

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certain rights and remedies of limited partners contained in the Delaware Act.

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State law fiduciary duty standards

Fiduciary duties are generally considered to include an obligation to act in good faith and with due care and loyalty. The duty of care, in the absence of a provision in a partnership agreement providing otherwise, would generally require a general partner to act for the partnership in the same manner as a prudent person would act on his own behalf. The duty of loyalty, in the absence of a provision in a partnership agreement providing otherwise, would generally require that any action taken or transaction engaged in be entirely fair to the partnership.

Partnership agreement modified standards

Our partnership agreement contains provisions that waive or consent to conduct by our general partner and its affiliates that might otherwise raise issues as to compliance with fiduciary duties or applicable law. For example, our partnership agreement provides that when our general partner is acting in its capacity as our general partner, as opposed to in its individual capacity, it must act in “good faith,” meaning that it believed its actions or omissions were not adverse to the interests of the partnership, and will not be subject to any other standard under applicable law. In addition, when our general partner is acting in its individual capacity, as opposed to in its capacity as our general partner, it may act without any fiduciary obligation to us or the unitholders whatsoever. These contractual standards replace the obligations to which our general partner would otherwise be held.

If our general partner does not obtain approval from the conflicts committee of the board of directors of our general partner or our common unitholders, excluding any such units owned by our general partner or its affiliates, and the board of directors of our general partner approves the resolution or course of action taken with respect to the conflict of interest, then it will be presumed that, in making its decision, its board, which may include board members affected by the conflict of interest, acted in good faith, and in any proceeding brought by or on behalf of any limited partner or the partnership, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption and proving that such decision was not in good faith. These standards replace the obligations to which our general partner would otherwise be held.

Rights and remedies of limited partners

The Delaware Act generally provides that a limited partner may institute legal action on behalf of the partnership to recover damages from a third party where a general partner has refused to institute the action or where an effort to cause a general partner to do so is not likely to succeed. These actions include actions against a general partner for breach of its duties or of our partnership agreement. In addition, the statutory or case law of some jurisdictions may permit a limited partner to institute legal action on behalf of himself and all other similarly situated limited partners to recover damages from a general partner for violations of its fiduciary duties to the limited partners.

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Partnership agreement modified standards

The Delaware Act provides that, unless otherwise provided in a partnership agreement, a partner or other person shall not be liable to a limited partnership or to another partner or to another person that is a party to or is otherwise bound by a partnership agreement for breach of fiduciary duty for the partner’s or other person’s good faith reliance on the provisions of the partnership agreement. Under our partnership agreement, to the extent that, at law or in equity an indemnitee has duties (including fiduciary duties) and liabilities relating thereto to us or to our partners, our general partner and any other indemnitee acting in connection with our business or affairs shall not be liable to us or to any partner for its reliance on the provisions of our partnership agreement.

By purchasing our common units, each common unitholder automatically agrees to be bound by the provisions in our partnership agreement, including the provisions discussed above. This is in accordance with the policy of the Delaware Act favoring the principle of freedom of contract and the enforceability of partnership agreements. The failure of a limited partner to sign a partnership agreement does not render the partnership agreement unenforceable against that person.

Under our partnership agreement, we must indemnify our general partner and its officers, directors, managers and certain other specified persons, to the fullest extent permitted by law, against liabilities, costs and expenses incurred by our general partner or these other persons. We must provide this indemnification unless there has been a final and non-appealable judgment by a court of competent jurisdiction determining that such losses or liabilities were the result of conduct of our general partner or such officer or director engaged by it in bad faith or, with respect to any criminal conduct, with the knowledge that its conduct was unlawful. Thus, our general partner could be indemnified for its negligent acts if it meets the requirements set forth above. To the extent these provisions purport to include indemnification for liabilities arising under the Securities Act, in the opinion of the SEC, such indemnification is contrary to public policy and, therefore, unenforceable. Please read “The Partnership Agreement—Indemnification.”

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DESCRIPTION OF OUR COMMON UNITS

Our Common Units

The common units offered hereby represent limited partner interests in us. The holders of common units are entitled to participate in partnership distributions and exercise the rights and privileges provided to limited partners under our partnership agreement. For a description of the relative rights and privileges of holders of our common units to partnership distributions, please read “How We Make Distributions.” For a description of the rights and privileges of limited partners under our partnership agreement, including voting rights, please read “The Partnership Agreement.”

Transfer Agent and Registrar

will serve as registrar and transfer agent for the common units. We pay all fees charged by the transfer agent for transfers of common units, except the following, which must be paid by unitholders:

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surety bond premiums to replace lost or stolen certificates, taxes and other governmental charges;

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special charges for services requested by a holder of a common unit; and

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other similar fees or charges.

There is no charge to our unitholders for disbursements of our quarterly cash distributions. We will indemnify the transfer agent, its agents and each of their stockholders, directors, officers and employees against all claims and losses that may arise out of acts performed or omitted for its activities in that capacity, except for any liability due to any gross negligence or intentional misconduct of the indemnified person or entity.

The transfer agent may resign, by notice to us, or be removed by us. The resignation or removal of the transfer agent will become effective upon our appointment of a successor transfer agent and registrar and its acceptance of the appointment. If a successor has not been appointed or has not accepted its appointment within 30 days after notice of the resignation or removal, our general partner may act as the transfer agent and registrar until a successor is appointed.

Transfer of Common Units

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represents that the transferee has the capacity, power and authority to become bound by our partnership agreement;

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automatically agrees to be bound by the terms and conditions of, and is deemed to have executed, our partnership agreement; and

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gives the consents and approvals contained in our partnership agreement, such as the approval of all transactions and agreements entered into in connection with our formation and this offering.

A transferee will become a substituted limited partner of our partnership for the transferred common units automatically upon the recording of the transfer on our books and records. Our general partner will cause any transfers to be recorded on our books and records from time to time as necessary to accurately reflect the transfers.

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We may, at our discretion, treat the nominee holder of a common unit as the absolute owner. In that case, the beneficial holder’s rights are limited solely to those that it has against the nominee holder as a result of any agreement between the beneficial owner and the nominee holder.

Common units are securities and are transferable according to the laws governing transfer of securities. In addition to other rights acquired upon transfer, the transferor gives the transferee the right to become a limited partner in our partnership for the transferred common units.

Until a common unit has been transferred on our books, we and the transfer agent may treat the record holder of the common unit as the absolute owner for all purposes, except as otherwise required by law or stock exchange regulations.

Listing

We intend to apply to list our common units on the NYSE under the symbol “ORRI.”

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THE PARTNERSHIP AGREEMENT

The following is a summary of the material provisions of our partnership agreement, which we will adopt in connection with the closing of this offering. The form of our partnership agreement is included in this prospectus as Appendix A. We will provide investors and prospective investors with a copy of our partnership agreement, when available, upon request at no charge.

We summarize the following provisions of our partnership agreement elsewhere in this prospectus:

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with regard to distributions of cash available for distribution, please read “How We Make Distributions”;

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with regard to the duties of, and standard of care applicable to, our general partner, please read “Conflicts of Interest and Fiduciary Duties”;

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with regard to the transfer of common units, please read “Description of Our Common Units—Transfer of Common Units”; and

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with regard to allocations of taxable income and taxable loss, please read “Material U.S. Federal Income Tax Consequences.”

Organization and Duration

We were organized in November 2014 and will have a perpetual existence unless terminated pursuant to the terms of our partnership agreement.

Purpose

Our purpose, as set forth in our partnership agreement, is limited to any business activity that is approved by our general partner and that lawfully may be conducted by a limited partnership organized under Delaware law; provided that our general partner shall not cause us to take any action that the general partner determines would be reasonably likely to cause us to be treated as an association taxable as a corporation or otherwise taxable as an entity for federal income tax purposes.

Although our general partner has the ability to cause us and our subsidiaries to engage in activities other than our current activities, our general partner may decline to do so in its sole discretion. Our general partner is generally authorized to perform all acts it determines to be necessary or appropriate to carry out our purposes and to conduct our business.

Cash Distributions

Our partnership agreement does not require us to pay distributions at any time or in any amount. Instead, the board of directors of our general partner will adopt a cash distribution policy to be effective as of the closing of this offering that will set forth our general partner’s intention with respect to the distributions to be made to unitholders.

Our partnership agreement specifies the manner in which we will make cash distributions to holders of our common units and other partnership securities as well as to Royal in respect of its incentive distribution rights. For a description of these cash distribution provisions, please read “How We Make Distributions.”

Capital Contributions

Unitholders are not obligated to make additional capital contributions, except as described below under “—Limited Liability.”

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Voting Rights

The following is a summary of the unitholder vote required for approval of the matters specified below. Matters that call for the approval of a “unit majority” require:

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during the subordination period, the approval of a majority of the common units, excluding those common units whose vote is controlled by our general partner or its affiliates, and a majority of the subordinated units, voting as separate classes; and

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after the subordination period, the approval of a majority of the common units.

In voting their common and subordinated units, our general partner and its affiliates will have no duty or obligation whatsoever to us or the limited partners, including any duty to act in the best interests of us or the limited partners.

The incentive distribution rights may be entitled to vote in certain circumstances.

Issuance of additional units

No approval right.

Amendment of the partnership agreement

Certain amendments may be made by our general partner without the approval of the unitholders. Other amendments generally require the approval of a unit majority. Please read “—Amendment of the Partnership Agreement.”

Merger of our partnership or the sale of all or substantially all of our assets

Unit majority in certain circumstances. Please read “—Merger, Consolidation, Conversion, Sale or Other Disposition of Assets.”

Dissolution of our partnership

Unit majority. Please read “—Dissolution.”

Continuation of our business upon dissolution

Unit majority. Please read “—Dissolution.”

Withdrawal of our general partner

Under most circumstances, the approval of a majority of the common units, excluding common units held by our general partner and its affiliates, is required for the withdrawal of our general partner prior to , 2025 in a manner that would cause a dissolution of our partnership. Please read “—Withdrawal or Removal of Our General Partner.”

Removal of our general partner

Not less than 66²⁄₃% of the outstanding units, voting as a single class, including units held by our general partner and its affiliates. In addition, any vote to remove our general partner during the subordination period must provide for the election of a successor general partner by the holders of a majority of the common units and a majority of the subordinated units, voting as separate classes. Please read “—Withdrawal or Removal of Our General Partner.”

Transfer of our general partner interest

No approval right. Please read “—Transfer of General Partner Interest.”

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Transfer of incentive distribution rights

No approval right. Please read “—Transfer of Subordinated Units and Incentive Distribution Rights.”

Transfer of ownership interests in our general partner

No approval right. Please read “—Transfer of Ownership Interests in the General Partner.”

If any person or group other than our general partner and its affiliates acquires beneficial ownership of 20% or more of any class of units, that person or group loses voting rights on all of its units. This loss of voting rights does not apply to any person or group that acquires the units from our general partner or its affiliates and any transferees of that person or group approved by our general partner or to any person or group who acquires the units with the specific prior approval of our general partner.

Applicable Law; Forum, Venue and Jurisdiction

Our partnership agreement is governed by Delaware law. Our partnership agreement requires that any claims, suits, actions or proceedings:

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arising out of or relating in any way to the partnership agreement (including any claims, suits or actions to interpret, apply or enforce the provisions of the partnership agreement or the duties, obligations or liabilities among limited partners or of limited partners to us, or the rights or powers of, or restrictions on, the limited partners or us);

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brought in a derivative manner on our behalf;

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asserting a claim of breach of a duty owed by any director, officer or other employee of us or our general partner, or owed by our general partner, to us or the limited partners;

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asserting a claim arising pursuant to any provision of the Delaware Act; or

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asserting a claim governed by the internal affairs doctrine,

shall be exclusively brought in the Court of Chancery of the State of Delaware (or, if such court does not have subject matter jurisdiction thereof, any other court located in the State of Delaware with subject matter jurisdiction), regardless of whether such claims, suits, actions or proceedings sound in contract, tort, fraud or otherwise, are based on common law, statutory, equitable, legal or other grounds, or are derivative or direct claims. By purchasing a common unit, a limited partner is irrevocably consenting to these limitations and provisions regarding claims, suits, actions or proceedings and submitting to the exclusive jurisdiction of the Court of Chancery of the State of Delaware (or such other court) in connection with any such claims, suits, actions or proceedings.

Limited Liability

Assuming that a limited partner does not participate in the control of our business within the meaning of the Delaware Act and that he otherwise acts in conformity with the provisions of the partnership agreement, his liability under the Delaware Act will be limited, subject to possible exceptions, to the amount of capital he is obligated to contribute to us for his common units plus his share of any undistributed profits and assets. However, if it were determined that the right, or exercise of the right, by the limited partners as a group:

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to remove or replace our general partner;

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to approve some amendments to our partnership agreement; or

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to take other action under our partnership agreement,

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constituted “participation in the control” of our business for the purposes of the Delaware Act, then the limited partners could be held personally liable for our obligations under the laws of Delaware, to the same extent as our general partner. This liability would extend to persons who transact business with us under the reasonable belief that the limited partner is a general partner. Neither our partnership agreement nor the Delaware Act specifically provides for legal recourse against our general partner if a limited partner were to lose limited liability through any fault of our general partner. While this does not mean that a limited partner could not seek legal recourse, we know of no precedent for this type of a claim in Delaware case law.

Under the Delaware Act, a limited partnership may not make a distribution to a partner if, after the distribution, all liabilities of the limited partnership, other than liabilities to partners on account of their partnership interests and liabilities for which the recourse of creditors is limited to specific property of the partnership, would exceed the fair value of the assets of the limited partnership. For the purpose of determining the fair value of the assets of a limited partnership, the Delaware Act provides that the fair value of property subject to liability for which recourse of creditors is limited shall be included in the assets of the limited partnership only to the extent that the fair value of that property exceeds the nonrecourse liability. The Delaware Act provides that a limited partner who receives a distribution and knew at the time of the distribution that the distribution was in violation of the Delaware Act shall be liable to the limited partnership for the amount of the distribution for three years.

Following the completion of this offering, we expect that our subsidiaries will conduct business in several states and we may have subsidiaries that conduct business in other states or countries in the future. Maintenance of our limited liability as owner of our operating subsidiaries may require compliance with legal requirements in the jurisdictions in which the operating subsidiaries conduct business, including qualifying our subsidiaries to do business there.

Limitations on the liability of members or limited partners for the obligations of a limited liability company or limited partnership have not been clearly established in many jurisdictions. If, by virtue of our ownership interest in our subsidiaries or otherwise, it were determined that we were conducting business in any jurisdiction without compliance with the applicable limited partnership or limited liability company statute, or that the right or exercise of the right by the limited partners as a group to remove or replace our general partner, to approve some amendments to our partnership agreement, or to take other action under our partnership agreement constituted “participation in the control” of our business for purposes of the statutes of any relevant jurisdiction, then the limited partners could be held personally liable for our obligations under the law of that jurisdiction to the same extent as our general partner under the circumstances. We will operate in a manner that our general partner considers reasonable and necessary or appropriate to preserve the limited liability of the limited partners.

Issuance of Additional Interests

Our partnership agreement authorizes us to issue an unlimited number of additional partnership interests for the consideration and on the terms and conditions determined by our general partner without the approval of the unitholders.

It is possible that we will fund acquisitions through the issuance of additional common units, subordinated units or other partnership interests. Holders of any additional common units we issue will be entitled to share equally with the then-existing common unitholders in our distributions. In addition, the issuance of additional common units or other partnership interests may dilute the value of the interests of the then-existing common unitholders in our net assets.

In accordance with Delaware law and the provisions of our partnership agreement, we may also issue additional partnership interests that, as determined by our general partner, may have rights to distributions or special voting rights to which the common units are not entitled. In addition, our partnership agreement does not prohibit our subsidiaries from issuing equity interests, which may effectively rank senior to the common units.

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Our general partner will have the right, which it may from time to time assign in whole or in part to any of its affiliates, to purchase common units, subordinated units or other partnership interests whenever, and on the same terms that, we issue partnership interests to persons other than our general partner and its affiliates, to the extent necessary to maintain the percentage interest of our general partner and its affiliates, including such interest represented by common and subordinated units, that existed immediately prior to each issuance. The common unitholders will not have preemptive rights under our partnership agreement to acquire additional common units or other partnership interests.

Amendment of the Partnership Agreement

General

Amendments to our partnership agreement may be proposed only by our general partner. However, our general partner will have no duty or obligation to propose any amendment and may decline to do so free of any duty or obligation whatsoever to us or the limited partners, including any duty to act in the best interests of us or the limited partners. In order to adopt a proposed amendment, other than the amendments discussed below, our general partner is required to seek written approval of the holders of the number of units required to approve the amendment or to call a meeting of the limited partners to consider and vote upon the proposed amendment. Except as described below, an amendment must be approved by a unit majority.

Prohibited Amendments

No amendment may be made that would:

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enlarge the obligations of any limited partner without his consent, unless approved by at least a majority of the type or class of limited partner interests so affected; or

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enlarge the obligations of, restrict in any way any action by or rights of, or reduce in any way the amounts distributable, reimbursable or otherwise payable by us to our general partner or any of its affiliates without the consent of our general partner, which consent may be given or withheld in its sole discretion.

The provision of our partnership agreement preventing the amendments having the effects described in the clauses above can be amended upon the approval of the holders of at least 90.0% of the outstanding units, voting as a single class (including units owned by our general partner and its affiliates). Upon completion of the offering, an affiliate of our general partner will own approximately % of our outstanding common and subordinated units.

No Unitholder Approval

Our general partner may generally make amendments to our partnership agreement without the approval of any limited partner to reflect:

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a change in our name, the location of our principal place of business, our registered agent or our registered office;

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the admission, substitution, withdrawal or removal of partners in accordance with our partnership agreement;

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a change that our general partner determines to be necessary or appropriate to qualify or continue our qualification as a limited partnership or other entity in which the limited partners have limited liability under the laws of any state or to ensure that neither we nor any of our subsidiaries will be treated as an association taxable as a corporation or otherwise taxed as an entity for federal income tax purposes (to the extent not already so treated or taxed);

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an amendment that is necessary, in the opinion of our counsel, to prevent us or our general partner or its directors, officers, agents or trustees from in any manner being subjected to the provisions of the

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Investment Company Act of 1940, the Investment Advisers Act of 1940 or “plan asset” regulations adopted under the Employee Retirement Income Security Act of 1974, or “ERISA,” whether or not substantially similar to plan asset regulations currently applied or proposed;

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an amendment that our general partner determines to be necessary or appropriate in connection with the creation, authorization or issuance of additional partnership interests or the right to acquire partnership interests;

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any amendment expressly permitted in our partnership agreement to be made by our general partner acting alone;

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an amendment effected, necessitated or contemplated by a merger agreement that has been approved under the terms of our partnership agreement;

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any amendment that our general partner determines to be necessary or appropriate for the formation by us of, or our investment in, any corporation, partnership or other entity, as otherwise permitted by our partnership agreement;

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a change in our fiscal year or taxable year and related changes;

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conversions into, mergers with or conveyances to another limited liability entity that is newly formed and has no assets, liabilities or operations at the time of the conversion, merger or conveyance other than those it receives by way of the conversion, merger or conveyance; or

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any other amendments substantially similar to any of the matters described in the clauses above.

In addition, our general partner may make amendments to our partnership agreement, without the approval of any limited partner, if our general partner determines that those amendments:

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do not adversely affect the limited partners, considered as a whole, or any particular class of limited partners, in any material respect;

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are necessary or appropriate to satisfy any requirements, conditions or guidelines contained in any opinion, directive, order, ruling or regulation of any federal or state agency or judicial authority or contained in any federal or state statute;

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are necessary or appropriate to facilitate the trading of limited partner interests or to comply with any rule, regulation, guideline or requirement of any securities exchange on which the limited partner interests are or will be listed for trading;

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are necessary or appropriate for any action taken by our general partner relating to splits or combinations of units under the provisions of our partnership agreement; or

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are required to effect the intent expressed in this prospectus or the intent of the provisions of our partnership agreement or are otherwise contemplated by our partnership agreement.

Opinion of Counsel and Unitholder Approval

Any amendment that our general partner determines adversely affects in any material respect one or more particular classes of limited partners, and is not permitted to be adopted by our general partner without limited partner approval, will require the approval of at least a majority of the class or classes so affected, but no vote will be required by any class or classes of limited partners that our general partner determines are not adversely affected in any material respect. Any such amendment that would have a material adverse effect on the rights or preferences of any type or class of outstanding units in relation to other classes of units will require the approval of at least a majority of the type or class of units so affected. Any such amendment that would reduce the voting percentage required to take any action other than to remove the general partner or call a meeting of unitholders is required to be approved by the affirmative vote of limited partners whose aggregate outstanding units constitute not less than the voting requirement sought to be reduced. Any such amendment that would increase the

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percentage of units required to remove the general partner or call a meeting of unitholders must be approved by the affirmative vote of limited partners whose aggregate outstanding units constitute not less than the percentage sought to be increased. For amendments of the type not requiring unitholder approval, our general partner will not be required to obtain an opinion of counsel that an amendment will neither result in a loss of limited liability to the limited partners nor result in our being treated as a taxable entity for federal income tax purposes in connection with any of the amendments. No other amendments to our partnership agreement will become effective without the approval of holders of at least 90% of the outstanding units, voting as a single class, unless we first obtain an opinion of counsel to the effect that the amendment will not affect the limited liability under applicable law of any of our limited partners.

Merger, Consolidation, Conversion, Sale or Other Disposition of Assets

A merger, consolidation or conversion of us requires the prior consent of our general partner. However, our general partner will have no duty or obligation to consent to any merger, consolidation or conversion and may decline to do so free of any duty or obligation whatsoever to us or the limited partners, including any duty to act in the best interest of us or the limited partners.

In addition, our partnership agreement generally prohibits our general partner, without the prior approval of the holders of a unit majority, from causing us to sell, exchange or otherwise dispose of all or substantially all of our assets in a single transaction or a series of related transactions, including by way of merger, consolidation or other combination. Our general partner may, however, mortgage, pledge, hypothecate or grant a security interest in all or substantially all of our assets without such approval. Our general partner may also sell all or substantially all of our assets under a foreclosure or other realization upon those encumbrances without such approval. Finally, our general partner may consummate any merger without the prior approval of our unitholders if we are the surviving entity in the transaction, our general partner has received an opinion of counsel regarding limited liability and tax matters, the transaction would not result in a material amendment to the partnership agreement (other than an amendment that the general partner could adopt without the consent of other partners), each of our units will be an identical unit of our partnership following the transaction and the partnership interests to be issued do not exceed 20% of our outstanding partnership interests (other than incentive distribution rights) immediately prior to the transaction.

If the conditions specified in our partnership agreement are satisfied, our general partner may convert us or any of our subsidiaries into a new limited liability entity or merge us or any of our subsidiaries into, or convey all of our assets to, a newly formed entity, if the sole purpose of that conversion, merger or conveyance is to effect a mere change in our legal form into another limited liability entity, we have received an opinion of counsel regarding limited liability and tax matters and the governing instruments of the new entity provide the limited partners and our general partner with the same rights and obligations as contained in our partnership agreement. Our unitholders are not entitled to dissenters’ rights of appraisal under our partnership agreement or applicable Delaware law in the event of a conversion, merger or consolidation, a sale of substantially all of our assets or any other similar transaction or event.

Dissolution

We will continue as a limited partnership until dissolved under our partnership agreement. We will dissolve upon:

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he election of our general partner to dissolve us, if approved by the holders of units representing a unit majority;

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there being no limited partners, unless we are continued without dissolution in accordance with applicable Delaware law;

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the entry of a decree of judicial dissolution of our partnership; or

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the withdrawal or removal of our general partner or any other event that results in its ceasing to be our general partner other than by reason of a transfer of its general partner interest in accordance with our partnership agreement or its withdrawal or removal following the approval and admission of a successor.

Upon a dissolution under the last clause above, the holders of a unit majority may also elect, within specific time limitations, to continue our business on the same terms and conditions described in our partnership agreement by appointing as a successor general partner an entity approved by the holders of units representing a unit majority, subject to our receipt of an opinion of counsel to the effect that:

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the action would not result in the loss of limited liability under Delaware law of any limited partner; and

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neither our partnership nor any of our subsidiaries would be treated as an association taxable as a corporation or otherwise be taxable as an entity for federal income tax purposes upon the exercise of that right to continue (to the extent not already so treated or taxed).

Liquidation and Distribution of Proceeds

Upon our dissolution, unless our business is continued, the liquidator authorized to wind up our affairs will, acting with all of the powers of our general partner that are necessary or appropriate, liquidate our assets and apply the proceeds of the liquidation as described in “How We Make Distributions—Distributions of Cash Upon Liquidation.” The liquidator may defer liquidation or distribution of our assets for a reasonable period of time or distribute assets to partners in kind if it determines that a sale would be impractical or would cause undue loss to our partners.

Withdrawal or Removal of Our General Partner

Except as described below, our general partner has agreed not to withdraw voluntarily as our general partner prior to , 2025 without obtaining the approval of the holders of at least a majority of the outstanding common units, excluding common units held by our general partner and its affiliates, and furnishing an opinion of counsel regarding limited liability and tax matters. On or after , 2025, our general partner may withdraw as general partner without first obtaining approval of any unitholder by giving 90 days’ written notice, and that withdrawal will not constitute a violation of our partnership agreement. Notwithstanding the information above, our general partner may withdraw without unitholder approval upon 90 days’ notice to the limited partners if at least 50% of the outstanding common units are held or controlled by one person and its affiliates, other than our general partner and its affiliates. In addition, our partnership agreement permits our general partner, in some instances, to sell or otherwise transfer all of its general partner interest in us without the approval of the unitholders. Please read “—Transfer of General Partner Interest.”

Upon withdrawal of our general partner under any circumstances, other than as a result of a transfer by our general partner of all or a part of its general partner interest in us, the holders of a unit majority may select a successor to that withdrawing general partner. If a successor is not elected, or is elected but an opinion of counsel regarding limited liability and tax matters cannot be obtained, we will be dissolved, wound up and liquidated, unless within a specified period after that withdrawal, the holders of a unit majority agree in writing to continue our business and to appoint a successor general partner. Please read “—Dissolution.”

Our general partner may not be removed unless that removal is approved by the vote of the holders of not less than 66²⁄₃% of the outstanding units, voting together as a single class, including units held by our general partner and its affiliates, and we receive an opinion of counsel regarding limited liability and tax matters. Any removal of our general partner is also subject to the approval of a successor general partner by the vote of the holders of a majority of the outstanding common units, voting as a class, and the outstanding subordinated units, voting as a class. The ownership of more than 33¹⁄₃% of the outstanding units by our general partner and its affiliates gives them the ability to prevent our general partner’s removal. At the closing of this offering, an affiliate of our general partner will own % of our outstanding limited partner units, including all of our subordinated units.

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Our partnership agreement also provides that if our general partner is removed as our general partner under circumstances where cause does not exist:

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all subordinated units held by any person who did not, and whose affiliates did not, vote any units in favor of the removal of the general partner, will immediately and automatically convert into common units on a one-for-one basis; and

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if all of the subordinated units convert pursuant to the foregoing, all cumulative common unit arrearages on the common units will be extinguished and the subordination period will end.

In the event of the removal of our general partner under circumstances where cause exists or withdrawal of our general partner where that withdrawal violates our partnership agreement, a successor general partner will have the option to purchase the general partner interest of the departing general partner and its affiliates for a cash payment equal to the fair market value of those interests. Under all other circumstances where our general partner withdraws or is removed by the limited partners, the departing general partner will have the option to require the successor general partner to purchase the general partner interest of the departing general partner and its affiliates for fair market value. This fair market value will be determined by agreement between the departing general partner and the successor general partner. If no agreement is reached, an independent investment banking firm or other independent expert selected by the departing general partner and the successor general partner will determine the fair market value. Or, if the departing general partner and the successor general partner cannot agree upon an expert, then an expert chosen by agreement of the experts selected by each of them will determine the fair market value.

If the option described above is not exercised by either the departing general partner or the successor general partner, the departing general partner’s general partner interest will automatically convert into common units equal to the fair market value of those interests as determined by an investment banking firm or other independent expert selected in the manner described in the preceding paragraph.

In addition, we will be required to reimburse the departing general partner for all amounts due the departing general partner, including, without limitation, all employee-related liabilities, including severance liabilities, incurred as a result of the termination of any employees employed for our benefit by the departing general partner or its affiliates.

Transfer of General Partner Interest

At any time, our general partner may transfer all or any of its general partner interest to another person without the approval of our common unitholders. As a condition of this transfer, the transferee must, among other things, assume the rights and duties of our general partner, agree to be bound by the provisions of our partnership agreement and furnish an opinion of counsel regarding limited liability and tax matters.

Transfer of Ownership Interests in the General Partner

At any time, the owner of our general partner may sell or transfer all or part of its ownership interests in our general partner to an affiliate or third party without the approval of our unitholders.

Transfer of Subordinated Units and Incentive Distribution Rights

By transfer of subordinated units or incentive distribution rights in accordance with our partnership agreement, each transferee of subordinated units or incentive distribution rights will be admitted as a limited partner with respect to the subordinated units or incentive distribution rights transferred when such transfer and admission is reflected in our books and records. Each transferee:

•

represents that the transferee has the capacity, power and authority to become bound by our partnership agreement;

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•

automatically becomes bound by the terms and conditions of our partnership agreement; and

•

gives the consents, waivers and approvals contained in our partnership agreement, such as the approval of all transactions and agreements we are entering into in connection with our formation and this offering.

Our general partner will cause any transfers to be recorded on our books and records no less frequently than quarterly.

We may, at our discretion, treat the nominee holder of subordinated units or incentive distribution rights as the absolute owner. In that case, the beneficial holder’s rights are limited solely to those that it has against the nominee holder as a result of any agreement between the beneficial owner and the nominee holder.

Subordinated units and incentive distribution rights are securities and any transfers are subject to the laws governing transfer of securities. In addition to other rights acquired upon transfer, the transferor gives the transferee the right to become a limited partner for the transferred subordinated units or incentive distribution rights.

Until a subordinated unit or incentive distribution right has been transferred on our books, we and the transfer agent may treat the record holder of the unit or right as the absolute owner for all purposes, except as otherwise required by law or stock exchange regulations.

Change of Management Provisions

Our partnership agreement contains specific provisions that are intended to discourage a person or group from attempting to remove Royal Resources Partners GP, LLC as our general partner or from otherwise changing our management. Please read “—Withdrawal or Removal of Our General Partner” for a discussion of certain consequences of the removal of our general partner. If any person or group, other than our general partner and its affiliates, acquires beneficial ownership of 20% or more of any class of units, that person or group loses voting rights on all of its units. This loss of voting rights does not apply in certain circumstances. Please read “—Meetings; Voting.”

Limited Call Right

If at any time our general partner and its affiliates own more than 80% of the then-issued and outstanding limited partner interests of any class, our general partner will have the right, which it may assign in whole or in part to any of its affiliates or to us, to acquire all, but not less than all, of the limited partner interests of the class held by unaffiliated persons, as of a record date to be selected by our general partner, on at least 10, but not more than 60, days’ notice. The purchase price in the event of this purchase is the greater of:

•

the highest price paid by our general partner or any of its affiliates for any limited partner interests of the class purchased within the 90 days preceding the date on which our general partner first mails notice of its election to purchase those limited partner interests; and

•

the average of the daily closing prices of the partnership securities of such class over the 20 trading days preceding the date that is three days before the date the notice is mailed.

As a result of our general partner’s right to purchase outstanding limited partner interests, a holder of limited partner interests may have his limited partner interests purchased at an undesirable time or at a price that may be lower than market prices at various times prior to such purchase or lower than a unitholder may anticipate the market price to be in the future. The tax consequences to a unitholder of the exercise of this call right are the same as a sale by that unitholder of his common units in the market. Please read “Material U.S. Federal Income Tax Consequences—Disposition of Units.”

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Non-Taxpaying Holders; Redemption

To avoid any adverse effect on our ability to operate our assets or generate revenues from our assets, our partnership agreement provides our general partner the power to amend our partnership agreement. If our general partner, with the advice of counsel, determines that our not being treated as an association taxable as a corporation or otherwise taxable as an entity for federal income tax purposes, coupled with the tax status (or lack of proof thereof) of one or more of our limited partners (or their owners, to the extent relevant), has, or is reasonably likely to have, a material adverse effect on our ability to operate our assets or generate revenues from our assets, then our general partner may adopt such amendments to our partnership agreement as it determines necessary or advisable to:

•

obtain proof of the federal income tax status of our limited partners (and their owners, to the extent relevant); and

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permit us to redeem the units held by any person whose tax status has or is reasonably likely to have a material adverse effect on our ability to operate our assets or generate revenues from our assets or who fails to comply with the procedures instituted by our general partner to obtain proof of such person’s federal income tax status. The redemption price in the case of such a redemption will be the average of the daily closing prices per unit for the 20 consecutive trading days immediately prior to the date set for redemption.

Non-Citizen Assignees; Redemption

If our general partner, with the advice of counsel, determines we are subject to federal, state or local laws or regulations that, in the reasonable determination of our general partner, create a substantial risk of cancellation or forfeiture of any property that we have an interest in because of the nationality, citizenship or other related status of any limited partner (or its owners, to the extent relevant), then our general partner may adopt such amendments to our partnership agreement as it determines necessary or advisable to:

•

obtain proof of the nationality, citizenship or other related status of our limited partners (or their owners, to the extent relevant); and

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permit us to redeem the units held by any person whose nationality, citizenship or other related status creates substantial risk of cancellation or forfeiture of any property or who fails to comply with the procedures instituted by the general partner to obtain proof of the nationality, citizenship or other related status. The redemption price in the case of such a redemption will be the average of the daily closing prices per unit for the 20 consecutive trading days immediately prior to the date set for redemption.

Meetings; Voting

Except as described below regarding a person or group owning 20% or more of any class of units then outstanding, record holders of units on the record date will be entitled to notice of, and to vote at, meetings of our limited partners and to act upon matters for which approvals may be solicited.

Our general partner does not anticipate that any meeting of our unitholders will be called in the foreseeable future. Any action that is required or permitted to be taken by the unitholders may be taken either at a meeting of the unitholders or without a meeting if consents in writing describing the action so taken are signed by holders of the number of units necessary to authorize or take that action at a meeting. Meetings of the unitholders may be called by our general partner or by unitholders owning at least 20% of the outstanding units of the class for which a meeting is proposed. Unitholders may vote either in person or by proxy at meetings. The holders of a majority of the outstanding units of the class or classes for which a meeting has been called, represented in person or by proxy, will constitute a quorum, unless any action by the unitholders requires approval by holders of a greater percentage of the units, in which case the quorum will be the greater percentage. Our general partner may

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postpone any meeting of unitholders one or more times for any reason by giving notice to the unitholders entitled to vote at such meeting. Our general partner may also adjourn any meeting of unitholders one or more times for any reason, including the absence of a quorum, without a vote of the unitholders.

Each record holder of a unit has a vote according to his percentage interest in us, although additional limited partner interests having special voting rights could be issued. Please read “—Issuance of Additional Interests.” However, if at any time any person or group, other than our general partner and its affiliates, or a direct or subsequently approved transferee of our general partner or its affiliates and purchasers specifically approved by our general partner, acquires, in the aggregate, beneficial ownership of 20% or more of any class of units then outstanding, that person or group will lose voting rights on all of its units and the units may not be voted on any matter and will not be considered to be outstanding when sending notices of a meeting of unitholders, calculating required votes, determining the presence of a quorum or for other similar purposes. Common units held in nominee or street name account will be voted by the broker or other nominee in accordance with the instruction of the beneficial owner unless the arrangement between the beneficial owner and his nominee provides otherwise. Except as our partnership agreement otherwise provides, subordinated units will vote together with common units, as a single class.

Any notice, demand, request, report or proxy material required or permitted to be given or made to record common unitholders under our partnership agreement will be delivered to the record holder by us or by the transfer agent.

Voting Rights of Incentive Distribution Rights

If a majority of the incentive distribution rights are held by Royal and its affiliates, the holders of the incentive distribution rights will have no right to vote in respect of such rights on any matter, unless otherwise required by law, and the holders of the incentive distribution rights shall be deemed to have approved any matter approved by our general partner.

If less than a majority of the incentive distribution rights are held by Royal and its affiliates, the incentive distribution rights will be entitled to vote on all matters submitted to a vote of unitholders, other than amendments and other matters that our general partner determines do not adversely affect the holders of the incentive distribution rights in any material respect. On any matter in which the holders of incentive distribution rights are entitled to vote, such holders will vote together with the subordinated units, prior to the end of the subordination period, or together with the common units, thereafter, in either case as a single class, and such incentive distribution rights shall be treated in all respects as subordinated units or common units, as applicable, when sending notices of a meeting of our limited partners to vote on any matter (unless otherwise required by law), calculating required votes, determining the presence of a quorum or for other similar purposes under our partnership agreement. The relative voting power of the holders of the incentive distribution rights and the subordinated units or common units, depending on which class the holders of incentive distribution rights are voting with, will be set in the same proportion as cumulative cash distributions, if any, in respect of the incentive distribution rights for the four consecutive quarters prior to the record date for the vote bears to the cumulative cash distributions in respect of such class of units for such four quarters.

Status as Limited Partner

By transfer of common units in accordance with our partnership agreement, each transferee of common units shall be admitted as a limited partner with respect to the common units transferred when such transfer and admission are reflected in our books and records. Except as described under “—Limited Liability,” the common units will be fully paid, and unitholders will not be required to make additional contributions.

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Indemnification

Under our partnership agreement, in most circumstances, we will indemnify the following persons, to the fullest extent permitted by law, from and against all losses, claims, damages or similar events:

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our general partner;

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any departing general partner;

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any person who is or was an affiliate of our general partner or any departing general partner;

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any person who is or was a manager, managing member, general partner, director, officer, fiduciary or trustee of our partnership, our subsidiaries, our general partner, any departing general partner or any of their affiliates;

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any person who is or was serving as a manager, managing member, general partner, director, officer, employee, agent, fiduciary or trustee of another person owing a fiduciary duty to us or our subsidiaries;

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any person who controls our general partner or any departing general partner; and

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any person designated by our general partner.

Any indemnification under these provisions will only be out of our assets. Unless our general partner otherwise agrees, it will not be personally liable for, or have any obligation to contribute or lend funds or assets to us to enable us to effectuate, indemnification. We may purchase insurance against liabilities asserted against and expenses incurred by persons for our activities, regardless of whether we would have the power to indemnify the person against liabilities under our partnership agreement.

Reimbursement of Expenses

Our partnership agreement requires us to reimburse our general partner for all direct and indirect expenses it incurs or payments it makes on our behalf and all other expenses allocable to us or otherwise incurred by our general partner in connection with operating our business. Our partnership agreement does not set a limit on the amount of expenses for which our general partner and its affiliates may be reimbursed. These expenses include salary, bonus, incentive compensation and other amounts paid to persons who perform services for us or on our behalf and expenses allocated to our general partner by its affiliates. Our general partner is entitled to determine the expenses that are allocable to us.

Books and Reports

Our general partner is required to keep appropriate books of our business at our principal offices. These books will be maintained for both tax and financial reporting purposes on an accrual basis. For tax and fiscal reporting purposes, our fiscal year is the calendar year.

We will furnish or make available to record holders of our common units, within 105 days after the close of each fiscal year, an annual report containing audited consolidated financial statements and a report on those consolidated financial statements by our independent public accountants. Except for our fourth quarter, we will also furnish or make available summary financial information within 50 days after the close of each quarter. We will be deemed to have made any such report available if we file such report with the SEC on EDGAR or make the report available on a publicly available website that we maintain.

We will furnish each record holder with information reasonably required for federal and state tax reporting purposes within 90 days after the close of each calendar year. This information is expected to be furnished in summary form so that some complex calculations normally required of partners can be avoided. Our ability to furnish this summary information to our unitholders will depend on their cooperation in supplying us with

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specific information. Every unitholder will receive information to assist him in determining his federal and state tax liability and in filing his federal and state income tax returns, regardless of whether the unitholder supplies us with the necessary information.

Right to Inspect Our Books and Records

Our partnership agreement provides that a limited partner can, for a purpose reasonably related to his interest as a limited partner, upon reasonable written demand stating the purpose of such demand and at his own expense, have furnished to him:

•

a current list of the name and last known address of each record holder; and

•

copies of our partnership agreement, our certificate of limited partnership, related amendments and powers of attorney under which they have been executed.

Under our partnership agreement, however, each of our limited partners and other persons who acquire interests in our partnership interests, do not have rights to receive information from us or any of the persons we indemnify as described above under “—Indemnification” for the purpose of determining whether to pursue litigation or assist in pending litigation against us or those indemnified persons relating to our affairs, except pursuant to the applicable rules of discovery relating to the litigation commenced by the person seeking information.

Our general partner may, and intends to, keep confidential from the limited partners trade secrets or other information the disclosure of which our general partner determines is not in our best interests or that we are required by law or by agreements with third parties to keep confidential. Our partnership agreement limits the rights to information that a limited partner would otherwise have under Delaware law.

Registration Rights

Under our partnership agreement, we have agreed to register for resale under the Securities Act and applicable state securities laws any common units, subordinated units or other limited partner interests proposed to be sold by our general partner or any of its affiliates or their assignees if an exemption from the registration requirements is not otherwise available. These registration rights continue for two years following any withdrawal or removal of our general partner. We are obligated to pay all expenses incidental to the registration, excluding underwriting discounts.

In addition, in connection with this offering, we expect to enter into a registration rights agreement with Royal and Holdings. Pursuant to the registration rights agreement, we will be required to file a registration statement to register the common units and subordinated units issued to Royal and Holdings and the common units issuable upon the conversion of the subordinated units upon request of Royal and Holdings. In addition, the registration rights agreement gives Royal piggyback registration rights under certain circumstances. The registration rights agreement also includes provisions dealing with holdback agreements, indemnification and contribution and allocation of expenses. These registration rights are transferable to affiliates of Royal and, in certain circumstances, to third parties. Please read “Units Eligible for Future Sale.”

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UNITS ELIGIBLE FOR FUTURE SALE

After the sale of the common units offered by this prospectus, Royal will hold an aggregate of common units and subordinated units. All of the subordinated units will convert into common units at the end of the subordination period and some may convert earlier. The sale of these common and subordinated units could have an adverse impact on the price of the common units or on any trading market that may develop.

Our common units sold in this offering will generally be freely transferable without restriction or further registration under the Securities Act, except that any common units held by an “affiliate” of ours may not be resold publicly except in compliance with the registration requirements of the Securities Act or under an exemption under Rule 144 of the Securities Act (“Rule 144”) or otherwise. Rule 144 permits securities acquired by an affiliate of the issuer to be sold into the market in an amount that does not exceed, during any three-month period, the greater of:

•

1% of the total number of the securities outstanding; or

•

the average weekly reported trading volume of our common units for the four weeks prior to the sale.

Sales under Rule 144 are also subject to specific manner of sale provisions, holding period requirements, notice requirements and the availability of current public information about us. A person who is not deemed to have been an affiliate of ours at any time during the three months preceding a sale, and who has beneficially owned our common units for at least six months (provided we are in compliance with the current public information requirement), or one year (regardless of whether we are in compliance with the current public information requirement), would be entitled to sell those common units under Rule 144, subject only to the current public information requirement. After beneficially owning Rule 144 restricted units for at least one year, a person who is not deemed to have been an affiliate of ours at any time during the 90 days preceding a sale would be entitled to freely sell those common units without regard to the public information requirements, volume limitations, manner of sale provisions and notice requirements of Rule 144.

Our partnership agreement provides that we may issue an unlimited number of limited partner interests of any type and at any time without a vote of the unitholders. Any issuance of additional common units or other limited partner interests would result in a corresponding decrease in the proportionate ownership interest in us represented by, and could adversely affect the cash distributions to and market price of, common units then outstanding. Please read “The Partnership Agreement—Issuance of Additional Interests.”

Under our partnership agreement and the registration rights agreement that we expect to enter into, our general partner and its affiliates will have the right to cause us to register under the Securities Act and applicable state securities laws the offer and sale of any units that they hold. Subject to the terms and conditions of the partnership agreement and the registration rights agreement, these registration rights allow our general partner and its affiliates or their assignees holding any units to require registration of any of these units and to include any of these units in a registration by us of other units, including units offered by us or by any unitholder. Our general partner and its affiliates will continue to have these registration rights for two years following its withdrawal or removal as our general partner. In connection with any registration of this kind, we will indemnify each unitholder participating in the registration and its officers, directors, and controlling persons from and against any liabilities under the Securities Act or any applicable state securities laws arising from the registration statement or prospectus. We will bear all costs and expenses incidental to any registration, excluding any underwriting discount. Except as described below, our general partner and its affiliates may sell their units in private transactions at any time, subject to compliance with applicable laws.

The executive officers and directors of our general partner and Royal have agreed not to sell any common units they beneficially own for a period of 180 days from the date of this prospectus. Please read “Underwriting” for a description of these lock-up provisions.

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Prior to the completion of this offering, we expect to adopt a new long-term incentive plan. If adopted, we intend to file a registration statement on Form S-8 under the Securities Act to register common units issuable under the long-term incentive plan. This registration statement on Form S-8 is expected to be filed following the effective date of the registration statement of which this prospectus is a part and will be effective upon filing. Accordingly, common units issued under the long-term incentive plan will be eligible for resale in the public market without restriction after the effective date of the Form S-8 registration statement, subject to applicable vesting requirements, Rule 144 limitations applicable to affiliates and the lock-up restrictions described above.

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MATERIAL U.S. FEDERAL INCOME TAX CONSEQUENCES

This section summarizes the material federal income tax consequences that may be relevant to prospective unitholders and is based upon current provisions of the Internal Revenue Code of 1986, as amended (the “Code”), existing and proposed Treasury regulations thereunder (the “Treasury Regulations”), and current administrative rulings and court decisions, all of which are subject to change. Changes in these authorities may cause the federal income tax consequences to a prospective unitholder to vary substantially from those described below, possibly on a retroactive basis. Unless the context otherwise requires, references in this section to “we” or “us” are references to Royal Resources Partners LP and its subsidiaries.

Legal conclusions contained in this section, unless otherwise noted, are the opinion of Kirkland & Ellis LLP and are based on the accuracy of representations made by us to them for this purpose. However, this section does not address all federal income tax matters that affect us or our unitholders and does not describe the application of the alternative minimum tax that may be applicable to certain unitholders. Furthermore, this section focuses on unitholders who are individual citizens or residents of the United States (for federal income tax purposes), who have the U.S. dollar as their functional currency, who use the calendar year as their taxable year, and who hold units as capital assets (generally, property that is held for investment). This section has limited applicability to corporations, partnerships (including entities treated as partnerships for federal income tax purposes), estates, trusts, non-resident aliens or other unitholders subject to specialized tax treatment, such as dealers or traders in securities or currencies, persons holding their units as part of a “straddle,” “hedge,” “conversion transaction” or other risk reduction transaction, tax-exempt institutions, non-U.S. persons, IRAs, employee benefit plans, real estate investment trusts, and mutual funds. Accordingly, we encourage each unitholder to consult the unitholder’s own tax advisor in analyzing the federal, state, local and non-U.S. tax consequences particular to that unitholder resulting from ownership or disposition of units and potential changes in applicable tax laws.

Unless otherwise noted, we are relying on opinions and advice of Kirkland & Ellis LLP with respect to the matters described herein. An opinion of counsel represents only that counsel’s best legal judgment and does not bind the Internal Revenue Service (the “IRS”) or a court. Accordingly, the opinions and statements made herein may not be sustained by a court if contested by the IRS. Any such contest of the matters described herein may materially and adversely impact the market for units and the prices at which our units trade. In addition, our costs of any contest with the IRS will be borne indirectly by our unitholders because the costs will reduce our cash available for distribution. Furthermore, the tax consequences of an investment in us, may be significantly modified by future legislative or administrative changes or court decisions, which may be retroactively applied.

For the reasons described below, Kirkland & Ellis LLP has not rendered an opinion with respect to the following federal income tax issues: (1) the treatment of a unitholder whose units are the subject of a securities loan (e.g., a loan to a “short seller” to cover a short sale of units) (please read “—Tax Consequences of Unit Ownership—Treatment of Securities Loans”); (2) whether our monthly convention for allocating taxable income and losses is permitted by existing Treasury Regulations (please read “—Disposition of Units—Allocations Between Transferors and Transferees”); and (3) whether our method for taking into account Section 743 adjustments is sustainable in certain cases (please read “—Tax Consequences of Unit Ownership—Section 754 Election” and “—Uniformity of Units”).

Taxation of the Partnership

Partnership Status

We expect to be treated as a partnership for U.S. federal income tax purposes and, therefore, generally will not be liable for entity-level federal income taxes. Instead, as described below, each of our unitholders will take into account its respective share of our items of income, gain, loss and deduction in computing its federal income tax liability as if the unitholder had earned such income directly, even if we make no cash distributions to the

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unitholder. Section 7704 of the Code generally provides that publicly traded partnerships will be treated as corporations for federal income tax purposes. However, if 90% or more of a partnership’s gross income for every taxable year it is publicly traded consists of “qualifying income,” the partnership may be treated as a partnership for federal income tax purposes (the “Qualifying Income Exception”). Qualifying income includes income and gains derived from the exploration, production and marketing of certain natural resources, including crude oil, natural gas and products thereof, as well as other types of income such as interest (other than from a financial business) and dividends. We estimate that less than % of our current gross income is not qualifying income; however, this estimate could change from time to time.

Based upon factual representations made by us and our general partner, Kirkland & Ellis LLP is of the opinion that we will be treated as a partnership for federal income tax purposes. The representations made by us and our general partner upon which Kirkland & Ellis LLP has relied in rendering its opinion include, without limitation:

(a) Neither we nor any of our partnership or limited liability company subsidiaries has elected to be treated as a corporation for federal income tax purposes; and

(b) For each taxable year since and including the year of our initial public offering, more than 90% of our gross income has been and will be income of a character that Kirkland & Ellis LLP has opined is “qualifying income” within the meaning of Section 7704(d) of the Code.

We believe that these representations are true and will be true in the future.

If we fail to meet the Qualifying Income Exception, other than a failure that is determined by the IRS to be inadvertent and that is cured within a reasonable time after discovery (in which case the IRS may also require us to make adjustments with respect to our unitholders or pay other amounts), we will be treated as transferring all of our assets, subject to liabilities, to a newly formed corporation, on the first day of the year in which we fail to meet the Qualifying Income Exception, in return for stock in that corporation and then as distributing that stock to our unitholders in liquidation. This deemed contribution and liquidation should not result in the recognition of taxable income by our unitholders or us so long as our liabilities do not exceed the tax basis of our assets.

Thereafter, we would be treated as an association taxable as a corporation for federal income tax purposes.

The present federal income tax treatment of publicly traded partnerships, including us, or an investment in our common units may be modified by administrative or legislative action or judicial interpretation at any time. For example, the Obama administration’s budget proposal for fiscal year 2016 recommends that certain publicly traded partnerships earning income from activities related to fossil fuels be taxed as corporations beginning in 2021. From time to time, members of the U.S. Congress propose and consider substantive changes to the existing federal income tax laws that affect publicly traded partnerships. One such legislative proposal would have eliminated the Qualifying Income Exception upon which we rely for our treatment as a partnership for U.S. federal income tax purposes. In addition, on May 5, 2015, the Department of the Treasury issued proposed Treasury Regulations addressing the application of the “qualifying income” requirement in certain specified circumstances. We do not expect that such proposed Treasury Regulations, if finalized in their current form, would negatively impact our ability to satisfy the “qualifying income” requirement, however, there can be no assurance that future regulations would not impact our ability to satisfy such requirement. We are unable to predict whether any such changes will ultimately be enacted. However, it is possible that a change in law could affect us and may be applied retroactively. Any such changes could negatively impact the value of an investment in our units.

If for any reason we are taxable as a corporation in any taxable year, our items of income, gain, loss and deduction would be taken into account by us in determining the amount of our liability for federal income tax, rather than being passed through to our unitholders. Our taxation as a corporation would materially reduce the

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cash available for distribution to unitholders and thus would likely substantially reduce the value of our units. Any distribution made to a unitholder at a time we are treated as a corporation would be (i) a taxable dividend to the extent of our current or accumulated earnings and profits, then (ii) a nontaxable return of capital to the extent of the unitholder’s tax basis in its units, and thereafter (iii) taxable capital gain.

The remainder of this discussion is based on the opinion of Kirkland & Ellis LLP that we will be treated as a partnership for federal income tax purposes.

Tax Consequences of Unit Ownership

Limited Partner Status

Unitholders who are admitted as limited partners of the partnership, as well as unitholders whose units are held in street name or by a nominee and who have the right to direct the nominee in the exercise of all substantive rights attendant to the ownership of units, will be treated as partners of the partnership for federal income tax purposes. For a discussion related to the risks of losing partner status as a result of securities loans, please read “—Tax Consequences of Unit Ownership—Treatment of Securities Loans.” Unitholders who are not treated as partners in us as described above are urged to consult their own tax advisors with respect to the tax consequences applicable to them under their particular circumstances.

Flow-Through of Taxable Income

Subject to the discussion below under “—Entity-Level Collections of Unitholder Taxes” addressing payments we may be required to make on behalf of our unitholders, we will not pay any federal income tax. Rather, each unitholder will be required to report on its federal income tax return each year its share of our income, gains, losses and deductions for our taxable year or years ending with or within its taxable year. Consequently, we may allocate income to a unitholder even if that unitholder has not received a cash distribution.

Basis of Units

A unitholder’s tax basis in its units initially will be the amount paid for those units increased by the unitholder’s initial allocable share of our liabilities. That basis generally will be (i) increased by the unitholder’s share of our income and any increases in such unitholder’s share of our liabilities, and (ii) decreased, but not below zero, by the amount of all distributions to the unitholder, the unitholder’s share of our losses, and any decreases in the unitholder’s share of our liabilities. The IRS has ruled that a partner who acquires interests in a partnership in separate transactions must combine those interests and maintain a single adjusted tax basis for all of those interests.

Ratio of Taxable Income to Distributions

We estimate that a purchaser of units in this offering who owns those units from the date of closing of this offering through the record date for distributions for the period ending December 31, 2018 will be allocated, on a cumulative basis, an amount of federal taxable income that will be less than % of the cash expected to be distributed on those units with respect to that period. These estimates are based upon the assumption that earnings from operations will approximate the amount required to make the anticipated quarterly distributions on all units and other assumptions with respect to capital expenditures, cash flow, net working capital and anticipated cash distributions. These estimates and assumptions are subject to, among other things, numerous business, economic, regulatory, legislative, competitive and political uncertainties beyond our control. Further, the estimates are based on current tax law and tax reporting positions that we will adopt and which could be changed or with which the IRS could disagree. Accordingly, we cannot assure that these estimates will prove to be correct, and our counsel has not opined on the accuracy of such estimates. The actual ratio of taxable income to cash distributions could be higher or lower than expected, and any differences could be material and could

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affect the value of units. For example, the ratio of taxable income to cash distributions to a purchaser of units in this offering would be higher, and perhaps substantially higher, than our estimate with respect to the period described above if:

•

we distribute less cash than we have assumed in making this projection;

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we make a future offering of units and use the proceeds of the offering in a manner that does not produce additional deductions during the period described above, such as to repay indebtedness outstanding at the time of this offering or to acquire property that is not eligible for depreciation or amortization for federal income tax purposes during such period or that is depreciable or amortizable at a rate significantly slower than the rate applicable to our assets at the time of this offering; or

•

legislation is enacted that limits or repeals certain U.S. federal income tax preferences currently available to oil and gas exploration and production companies (please read “—Tax Treatment of Operations—Recent Legislative Developments”).

Treatment of Distributions

Distributions by us to a unitholder generally will not be taxable to the unitholder, unless such distributions exceed the unitholder’s tax basis in its units, in which case the unitholder generally will recognize gain taxable in the manner described below under “—Disposition of Units.”

Any reduction in a unitholder’s share of our “liabilities” will be treated as a distribution by us of cash to that unitholder. A decrease in a unitholder’s percentage interest in us because of our issuance of additional units may decrease the unitholder’s share of our liabilities. For purposes of the foregoing, a unitholder’s share of our nonrecourse liabilities (liabilities for which no partner bears the economic risk of loss) generally will be based upon that unitholder’s share of the unrealized appreciation (or depreciation) in our assets, to the extent thereof, with any excess liabilities allocated based on the unitholder’s share of our profits. Please read “—Disposition of Units.”

A non-pro rata distribution of money or property (including a deemed distribution as a result of the reallocation of our liabilities described above) may cause a unitholder to recognize ordinary income if the distribution reduces the unitholder’s share of our “unrealized receivables,” including depreciation and depletion recapture and substantially appreciated “inventory items,” both as defined in Section 751 of the Code (“Section 751 Assets”). To the extent of such reduction, the unitholder would be deemed to receive its proportionate share of the Section 751 Assets and exchange such assets with us in return for a portion of the non-pro rata distribution. This deemed exchange generally will result in the unitholder’s recognition of ordinary income in an amount equal to the excess of (1) the non-pro rata portion of that distribution over (2) the unitholder’s tax basis (generally zero) in the Section 751 Assets deemed to be relinquished in the exchange. On October 31, 2014, the Department of the Treasury issued proposed Treasury Regulations with respect to the application of Section 751 of the Code. If such proposed Treasury Regulations are finalized in the future, the application of Section 751 may be different from what is described above. Unitholders are encouraged to consult with their tax advisors regarding the application of Section 751 in the event the proposed Treasury Regulations are finalized.

Limitations on Deductibility of Losses

A unitholder may not be entitled to deduct the full amount of loss we allocate to it because its share of our losses will be limited to the lesser of (i) the unitholder’s tax basis in its units, and (ii) in the case of a unitholder that is an individual, estate, trust or certain types of closely-held corporations, the amount for which the unitholder is considered to be “at risk” with respect to our activities. In general, a unitholder will be at risk to the extent of its tax basis in its units, reduced by (1) any portion of that basis attributable to the unitholder’s share of our liabilities, (2) any portion of that basis representing amounts otherwise protected against loss because of a guarantee, stop loss agreement or similar arrangement and (3) any amount of money the unitholder borrows to acquire or hold its units, if the lender of those borrowed funds owns an interest in us, is related to another

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unitholder or can look only to the units for repayment. A unitholder subject to the at risk limitation must recapture, as income, losses deducted in previous years to the extent that distributions (including distributions deemed to result from a reduction in a unitholder’s share of nonrecourse liabilities) cause the unitholder’s at risk amount to be less than zero at the end of any taxable year.

Losses disallowed to a unitholder or recaptured as a result of the basis or at risk limitations will carry forward and will be allowable as a deduction in a later year to the extent that the unitholder’s tax basis or at risk amount, whichever is the limiting factor, is subsequently increased. Upon a taxable disposition of units, any gain recognized by a unitholder can be offset by losses that were previously suspended by the at risk limitation but not losses suspended by the basis limitation. Any loss previously suspended by the at risk limitation in excess of that gain can no longer be used, and will not be available to offset a unitholder’s salary or active business income.

In addition to the basis and at risk limitations, the passive activity loss limitation rules generally limit the deductibility of losses incurred by individuals, estates, trusts, some closely-held corporations and personal service corporations from “passive activities” (generally, trade or business activities in which the taxpayer does not materially participate). The passive loss limitations are applied separately with respect to each publicly traded partnership. Consequently, any passive losses we generate will be available to offset only passive income generated by us. Passive losses that exceed a unitholder’s share of passive income we generate may be deducted in full when the unitholder disposes of all of its units in a fully taxable transaction with an unrelated party. The passive loss rules generally are applied after other applicable limitations on deductions, including the at risk and basis limitations.

Limitations on Interest Deductions

The deductibility of a non-corporate taxpayer’s “investment interest expense” generally is limited to the amount of that taxpayer’s “net investment income.” Investment interest expense includes:

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interest on indebtedness allocable to property held for investment;

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interest expense allocated against portfolio income; and

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the portion of interest expense incurred to purchase or carry an interest in a passive activity to the extent allocable against portfolio income.

The computation of a unitholder’s investment interest expense will take into account interest on any margin account borrowing or other loan incurred to purchase or carry a unit. Net investment income includes gross income from property held for investment and amounts treated as portfolio income under the passive loss rules, less deductible expenses other than interest directly connected with the production of investment income. Net investment income generally does not include qualified dividend income or gains attributable to the disposition of property held for investment. A unitholder’s share of a publicly traded partnership’s portfolio income and, according to the IRS, net passive income will be treated as investment income for purposes of the investment interest expense limitation.

Entity-Level Collections of Unitholder Taxes

If we are required or elect under applicable law to pay any federal, state, local or non-U.S. tax on behalf of any current or former unitholder or our general partner, we are authorized to treat the payment as a distribution of cash to the relevant unitholder or general partner. Where the tax is payable on behalf of all unitholders or we cannot determine the specific unitholder on whose behalf the tax is payable, we are authorized to treat the payment as a distribution to all current unitholders. Payments by us as described above could give rise to an overpayment of tax on behalf of a unitholder, in which event the unitholder may be entitled to claim a refund of the overpayment amount. Unitholders are urged to consult their tax advisors to determine the consequences to them of any tax payment we make on their behalf.

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Allocation of Income, Gain, Loss and Deduction

Our items of income, gain, loss and deduction generally will be allocated amongst our unitholders in accordance with their percentage interests in us. At any time that distributions are made to the common units in excess of distributions to the subordinated units, or incentive distributions are made to Royal, gross income will be allocated to the recipients to the extent of these distributions. If we have a net loss, that loss will be allocated to the unitholders in accordance with their percentage interests in us to the extent of their positive capital accounts, as adjusted to take into account the unitholders’ share of nonrecourse debt.

Specified items of our income, gain, loss and deduction will be allocated under Section 704(c) of the Code (or the principles of Section 704(c) of the Code) to account for any difference between the tax basis and fair market value of our assets at the time such assets are contributed to us and at the time of any subsequent offering of our units (a “Book-Tax Disparity”). As a result, the federal income tax burden associated with any Book-Tax Disparity immediately prior to an offering generally will be borne by our partners holding interests in us prior to such offering. In addition, items of recapture income will be specially allocated to the extent possible to the unitholder who was allocated the deduction giving rise to that recapture income in order to minimize the recognition of ordinary income by other unitholders.

An allocation of items of our income, gain, loss or deduction, other than an allocation required by the Code to eliminate a Book-Tax Disparity, will generally be given effect for federal income tax purposes in determining a partner’s share of an item of income, gain, loss or deduction only if the allocation has “substantial economic effect.” In any other case, a partner’s share of an item will be determined on the basis of the partner’s interest in us, which will be determined by taking into account all the facts and circumstances, including (i) the partner’s relative contributions to us, (ii) the interests of all the partners in profits and losses, (iii) the interest of all the partners in cash flow and (iv) the rights of all the partners to distributions of capital upon liquidation. Kirkland & Ellis LLP is of the opinion that, with the exception of the issues described in “—Section 754 Election” and “—Disposition of Units—Allocations Between Transferors and Transferees,” allocations of income, gain, loss or deduction under our partnership agreement will be given effect for federal income tax purposes.

Treatment of Securities Loans

A unitholder whose units are loaned (for example, a loan to “short seller” to cover a short sale of units) may be treated as having disposed of those units. If so, such unitholder would no longer be treated for tax purposes as a partner with respect to those units during the period of the loan and may recognize gain or loss from the disposition. As a result, during this period (i) any of our income, gain, loss or deduction allocated to those units would not be reportable by the lending unitholder, and (ii) any cash distributions received by the unitholder as to those units may be treated as ordinary taxable income.

Due to a lack of controlling authority, Kirkland & Ellis LLP has not rendered an opinion regarding the tax treatment of a unitholder that enters into a securities loan with respect to its units. Unitholders desiring to assure their status as partners and avoid the risk of income recognition from a loan of their units are urged to modify any applicable brokerage account agreements to prohibit their brokers from borrowing and lending their units. The IRS has announced that it is studying issues relating to the tax treatment of short sales of partnership interests. Please read “—Disposition of Units—Recognition of Gain or Loss.”

Tax Rates

Under current law, the highest marginal federal income tax rates for individuals applicable to ordinary income and long-term capital gains (generally, gains from the sale or exchange of certain investment assets held for more than one year) are 39.6% and 20%, respectively. These rates are subject to change by new legislation at any time.

In addition, a 3.8% net investment income tax (“NIIT”) may apply to certain net investment income earned by unitholders who are individuals, estates, and trusts. For these purposes, net investment income generally

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includes a unitholder’s allocable share of our income and gain realized by a unitholder from a sale of units. In the case of an individual, the tax will be imposed on the lesser of (i) the unitholder’s aggregate net investment income, or (ii) the amount by which the unitholder’s modified adjusted gross income exceeds $250,000 (if the unitholder is married and filing jointly or a surviving spouse), $125,000 (if married filing separately) or $200,000 (if the unitholder is unmarried or in any other case). In the case of an estate or trust, the tax will be imposed on the lesser of (i) undistributed net investment income, or (ii) the excess adjusted gross income over the dollar amount at which the highest income tax bracket applicable to an estate or trust begins.

Section 754 Election

We will make the election permitted by Section 754 of the Code that permits us to adjust the tax bases in our assets as to specific purchasers of our units under Section 743(b) of the Code. That election is irrevocable without the consent of the IRS. The Section 743(b) adjustment separately applies to each purchaser of units based upon the values and bases of our assets at the time of the relevant purchase, and the adjustment will reflect the purchase price paid. The Section 743(b) adjustment does not apply to a person who purchases units directly from us.

Under our partnership agreement, we are authorized to take a position to preserve the uniformity of units even if that position is not consistent with applicable Treasury Regulations. A literal application of Treasury Regulations governing a 743(b) adjustment attributable to properties depreciable under Section 167 of the Code may give rise to differences in the taxation of unitholders purchasing units from us and unitholders purchasing from other unitholders. If we have any such properties, we intend to adopt methods employed by other publicly traded partnerships to preserve the uniformity of units, even if inconsistent with existing Treasury Regulations, and Kirkland & Ellis LLP has not opined on the validity of this approach. Please read “—Uniformity of Units.”

The IRS may challenge the positions we adopt with respect to depreciating or amortizing the Section 743(b) adjustment we take to preserve the uniformity of units due to lack of controlling authority. Because a unitholder’s tax basis for its units is reduced by its share of our items of deduction or loss, any position we take that understates deductions will overstate a unitholder’s basis in its units, and may cause the unitholder to understate gain or overstate loss on any sale of such units. Please read “—Disposition of Units—Recognition of Gain or Loss.” If a challenge to such treatment were sustained, the gain from the sale of units may be increased without the benefit of additional deductions.

The calculations involved in connection with the Section 754 election are complex and will be made on the basis of assumptions as to the value of our assets and other matters. The IRS could seek to reallocate some or all of any Section 743(b) adjustment we allocated to our assets subject to depreciation or depletion to goodwill or nondepreciable or non-depletable assets. Goodwill, as an intangible asset, is generally amortizable over a longer period of time or under a less accelerated method than our tangible assets. We cannot assure any unitholder that the determinations we make will not be successfully challenged by the IRS or that the resulting deductions will not be reduced or disallowed altogether. Should the IRS require a different tax basis adjustment to be made, and should, in our opinion, the expense of compliance exceed the benefit of the election, we may seek permission from the IRS to revoke our Section 754 election. If permission is granted, a subsequent purchaser of units may be allocated more income than it would have been allocated had the election not been revoked.

Tax Treatment of Operations

Accounting Method and Taxable Year

We will use the year ending December 31 as our taxable year and the accrual method of accounting for federal income tax purposes. Each unitholder will be required to include in its tax return its share of our income, gain, loss and deduction for each taxable year ending within or with its taxable year. In addition, a unitholder who has a taxable year ending on a date other than December 31 and who disposes of all of its units following the close of our taxable year but before the close of its taxable year must include its share of our income, gain,

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loss and deduction in income for its taxable year, with the result that it will be required to include in income for its taxable year its share of more than one year of our income, gain, loss and deduction. Please read “—Disposition of Units—Allocations Between Transferors and Transferees.”

Depletion Deductions

Subject to the limitations on deductibility of losses discussed above (please read “Tax Consequences of Unit Ownership—Limitations on Deductibility of Losses”), common unitholders will be entitled to deductions for the greater of either cost depletion or (if otherwise allowable) percentage depletion with respect to our oil and gas interests. Although the Code requires each common unitholder to compute its own depletion allowance and maintain records of its share of the adjusted tax basis of the underlying property for depletion and other purposes, we intend to furnish each of our common unitholders with information relating to this computation for federal income tax purposes. Each common unitholder, however, remains responsible for calculating its own depletion allowance and maintaining records of its share of the adjusted tax basis of the underlying property for depletion and other purposes.

Percentage depletion is generally available with respect to common unitholders who qualify under the independent producer exemption contained in Section 613A(c) of the Code. For this purpose, an independent producer is a person not directly or indirectly involved in the retail sale of oil, gas, or derivative products or the operation of a major refinery. Percentage depletion is calculated as an amount generally equal to 15% (and, in the case of marginal production, potentially a higher percentage) of the common unitholder’s gross income from the depletable property for the taxable year. The percentage depletion deduction with respect to any oil and gas property is limited to 100% of the taxable income of the common unitholder from the property for each taxable year, computed without the depletion allowance and the domestic production activities deduction. A common unitholder that qualifies as an independent producer may deduct percentage depletion only to the extent the common unitholder’s average daily production of domestic crude oil, or the gas equivalent, does not exceed 1,000 barrels. This depletable amount may be allocated between oil and gas production, with 6,000 cubic feet of domestic gas production regarded as equivalent to one barrel of crude oil. The 1,000-barrel limitation must be allocated among the independent producer and controlled or related persons and family members in proportion to the respective production by such persons during the period in question.

In addition to the foregoing limitations, the percentage depletion deduction otherwise available is limited to 65% of a common unitholder’s total taxable income from all sources for the year, computed without the depletion allowance, the domestic production activities deduction net operating loss carrybacks, or capital loss carrybacks. Any percentage depletion deduction disallowed because of the 65% limitation may be deducted in the following taxable year if the percentage depletion deduction for such year plus the deduction carryover does not exceed 65% of the common unitholder’s total taxable income for that year. The carryover period resulting from the 65% net income limitation is unlimited.

Common unitholders that do not qualify under the independent producer exemption are generally restricted to depletion deductions based on cost depletion. Cost depletion deductions are calculated by (i) dividing the common unitholder’s share of the adjusted tax basis in the underlying mineral property by the number of mineral units (barrels of oil and thousand cubic feet, or Mcf, of gas) remaining as of the beginning of the taxable year and (ii) multiplying the result by the number of mineral units sold within the taxable year. The total amount of deductions based on cost depletion cannot exceed the common unitholder’s share of the total adjusted tax basis in the property.

All or a portion of any gain recognized by a common unitholder as a result of either the disposition by us of some or all of our oil and gas interests or the disposition by the common unitholder of some or all of its units may be taxed as ordinary income to the extent of recapture of depletion deductions, except for percentage depletion deductions in excess of the tax basis of the property. The amount of the recapture is generally limited to the amount of gain recognized on the disposition.

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The foregoing discussion of depletion deductions does not purport to be a complete analysis of the complex legislation and Treasury Regulations relating to the availability and calculation of depletion deductions by the common unitholders. Further, because depletion is required to be computed separately by each common unitholder and not by us, no assurance can be given, and Kirkland & Ellis LLP is unable to express any opinion, with respect to the availability or extent of percentage depletion deductions to the unitholders for any taxable year. We encourage each prospective common unitholder to consult its tax advisor to determine whether percentage depletion would be available to the common unitholder.

Administrative Expenses

Expenses of the partnership will include administrative expenses, the deductibility of which may be subject to limitation. As long as we are not treated as engaged in a trade or business, under applicable rules, administrative expenses attributable to common units will be considered miscellaneous itemized deductions that generally will have to be aggregated with an individual unitholder’s other miscellaneous itemized deductions. These rules disallow itemized deductions that are less than 2% of a taxpayer’s adjusted gross income, and the amount of otherwise allowable itemized deductions will be reduced by the lesser of (i) 3% of (A) adjusted gross income over (B) $305,050 if married and filing jointly, $152,525 if married filing separately or $254,200 if the unitholder is unmarried or in any other case and (ii) 80% of the amount of itemized deductions that are otherwise allowable, or both. It is anticipated that the amount of such administrative expenses will not be significant in relation to the partnership’s income.

Recent Legislative Developments

The Obama Administration’s budget proposals for fiscal years 2015 and 2016 include proposals that would, among other things, eliminate or reduce certain key U.S. federal income tax incentives currently available to oil and natural gas exploration and production companies. These changes include, but are not limited to, (i) the repeal of the percentage depletion allowance for oil and natural gas properties, (ii) the elimination of current deductions for intangible drilling and development costs (“IDCs”), (iii) the elimination of the deduction for certain domestic production activities, and (iv) an extension of the amortization period for certain geological and geophysical expenditures. It is unclear whether these proposals will be introduced into law and, if so, how soon any resulting changes could become effective. The passage of any legislation as a result of these proposals or any other similar changes in U.S. federal income tax laws could eliminate or postpone certain tax deductions that are currently available with respect to oil and natural gas exploration and development, and any such change could increase the taxable income allocable to our unitholders and negatively impact the value of an investment in our units.

Tax Basis, Depreciation and Amortization

The tax basis of our assets will be used for purposes of computing depreciation and cost recovery deductions, if any, and, ultimately, gain or loss on the disposition of those assets. If we dispose of depreciable or depletable property by sale, foreclosure or otherwise, all or a portion of any gain, determined by reference to the amount of depreciation and depletion deductions previously taken, may be subject to the recapture rules and taxed as ordinary income rather than capital gain. Similarly, a unitholder who has taken cost recovery or depreciation deductions with respect to property we own will likely be required to recapture some or all of those deductions as ordinary income upon a sale of its interest in us. Please read “—Tax Consequences of Unit Ownership—Allocation of Income, Gain, Loss and Deduction.”

The costs we incur in offering and selling our units (called “syndication expenses”) must be capitalized and cannot be deducted currently, ratably or upon our termination. While there are uncertainties regarding the classification of costs as organization expenses, which may be amortized by us, and as syndication expenses, which may not be amortized by us, the underwriting discounts and commissions we incur will be treated as syndication expenses. Please read “Disposition of Units—Recognition of Gain or Loss.”

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Valuation and Tax Basis of Our Properties

The federal income tax consequences of the ownership and disposition of units will depend in part on our estimates of the relative fair market values and the tax bases of our assets. Although we may from time to time consult with professional appraisers regarding valuation matters, we will make many of the relative fair market value estimates ourselves. These estimates and determinations of tax basis are subject to challenge and will not be binding on the IRS or the courts. If the estimates of fair market value or basis are later found to be incorrect, the character and amount of items of income, gain, loss or deduction previously reported by unitholders could change, and unitholders could be required to adjust their tax liability for prior years and incur interest and penalties with respect to those adjustments.

Disposition of Units

Recognition of Gain or Loss

A unitholder will be required to recognize gain or loss on a sale of units equal to the difference between the unitholder’s amount realized and tax basis in the units sold. A unitholder’s amount realized generally will equal the sum of the cash and the fair market value of other property it receives plus its share of our liabilities with respect to the units sold. Because the amount realized includes a unitholder’s share of our liabilities, the gain recognized on the sale of units could result in a tax liability in excess of any cash received from the sale.

Except as noted below, gain or loss recognized by a unitholder on the sale or exchange of a unit held for more than one year generally will be taxable as long-term capital gain or loss. However, gain or loss recognized on the disposition of units will be separately computed and taxed as ordinary income or loss under Section 751 of the Code to the extent attributable to Section 751 Assets, such as depreciation or depletion recapture and our “inventory items,” regardless of whether such inventory item is substantially appreciated in value. Ordinary income attributable to Section 751 Assets may exceed net taxable gain realized on the sale of a unit and may be recognized even if there is a net taxable loss realized on the sale of a unit. Thus, a unitholder may recognize both ordinary income and capital gain or loss upon a sale of units. Net capital loss may offset capital gains and, in the case of individuals, up to $3,000 of ordinary income per year.

For purposes of calculating gain or loss on the sale of units, the unitholder’s adjusted tax basis will be adjusted by its allocable share of our income or loss in respect of its units for the year of the sale. Furthermore, as described above, the IRS has ruled that a partner who acquires interests in a partnership in separate transactions must combine those interests and maintain a single adjusted tax basis for all of those interests. Upon a sale or other disposition of less than all of those interests, a portion of that tax basis must be allocated to the interests sold using an “equitable apportionment” method, which generally means that the tax basis allocated to the interest sold equals an amount that bears the same relation to the partner’s tax basis in its entire interest in the partnership as the value of the interest sold bears to the value of the partner’s entire interest in the partnership.

Treasury Regulations under Section 1223 of the Code allow a selling unitholder who can identify units transferred with an ascertainable holding period to elect to use the actual holding period of the units transferred. Thus, according to the ruling discussed in the paragraph above, a unitholder will be unable to select high or low basis units to sell as would be the case with corporate stock, but, according to the Treasury Regulations, it may designate specific units sold for purposes of determining the holding period of the units transferred. A unitholder electing to use the actual holding period of units transferred must consistently use that identification method for all subsequent sales or exchanges of our units. A unitholder considering the purchase of additional units or a sale of units purchased in separate transactions is urged to consult its tax advisor as to the possible consequences of this ruling and application of the Treasury Regulations.

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Specific provisions of the Code affect the taxation of some financial products and securities, including partnership interests, by treating a taxpayer as having sold an “appreciated” financial position, including a partnership interest with respect to which gain would be recognized if it were sold, assigned or terminated at its fair market value, in the event the taxpayer or a related person enters into:

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a short sale;

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an offsetting notional principal contract; or

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a futures or forward contract with respect to the partnership interest or substantially identical property.

Moreover, if a taxpayer has previously entered into a short sale, an offsetting notional principal contract or a futures or forward contract with respect to the partnership interest, the taxpayer will be treated as having sold that position if the taxpayer or a related person then acquires the partnership interest or substantially identical property. The Secretary of the Treasury is authorized to issue Treasury Regulations that treat a taxpayer that enters into transactions or positions that have substantially the same effect as the preceding transactions as having constructively sold the financial position.

Allocations Between Transferors and Transferees

In general, our taxable income or loss will be determined quarterly, will be prorated on a monthly basis and will be subsequently apportioned among the unitholders in proportion to the number of units owned by each of them as of the opening of the applicable exchange on the first business day of the month (the “Allocation Date”). However, gain or loss realized on a sale or other disposition of our assets or, in the discretion of the general partner, any other extraordinary item of income, gain, loss or deduction will be allocated among the unitholders on the Allocation Date in the month in which such income, gain, loss or deduction is recognized. As a result, a unitholder transferring units may be allocated income, gain, loss and deduction realized after the date of transfer.

Although simplifying conventions are contemplated by the Code and most publicly traded partnerships use similar simplifying conventions, the use of this method may not be permitted under existing Treasury Regulations. The Department of the Treasury has issued proposed Treasury Regulations that provide a safe harbor pursuant to which a publicly traded partnership may use a similar monthly simplifying convention to allocate tax items among transferor and transferee unitholders, although such tax items must be prorated on a daily basis. Nonetheless, the proposed regulations do not specifically authorize the use of the proration method we have adopted. Accordingly, Kirkland & Ellis LLP is unable to opine on the validity of this method of allocating income and deductions between transferee and transferor unitholders. If this method is not allowed under the final Treasury Regulations, or only applies to transfers of less than all of the unitholder’s interest, our taxable income or losses could be reallocated among our unitholders. We are authorized to revise our method of allocation between transferee and transferor unitholders, as well as among unitholders whose interests vary during a taxable year, to conform to a method permitted under future Treasury Regulations.

A unitholder who disposes of units prior to the record date set for a cash distribution for that quarter will be allocated items of our income, gain, loss and deduction attributable to the month of disposition but will not be entitled to receive a cash distribution for that period.

Notification Requirements

A unitholder who sells or purchases any of its units is generally required to notify us in writing of that transaction within 30 days after the transaction (or, if earlier, January 15 of the year following the transaction in the case of a seller). Upon receiving such notifications, we are required to notify the IRS of that transaction and to furnish specified information to the transferor and transferee. Failure to notify us of a transfer of units may, in some cases, lead to the imposition of penalties. However, these reporting requirements do not apply to a sale by an individual who is a citizen of the United States and who effects the sale through a broker who will satisfy such requirements.

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Constructive Termination

We will be considered to have “constructively” terminated as a partnership for federal income tax purposes upon the sale or exchange of 50% or more of the total interests in our capital and profits within a twelve-month period. For such purposes, multiple sales of the same unit are counted only once. A constructive termination results in the closing of our taxable year for all unitholders. In the case of a unitholder reporting on a taxable year other than the calendar year, the closing of our taxable year may result in more than twelve months of our taxable income or loss being includable in such unitholder’s taxable income for the year of termination.

A constructive termination occurring on a date other than December 31 generally would require that we file two tax returns for one fiscal year thereby increasing our administration and tax preparation costs. However, pursuant to an IRS relief procedure the IRS may allow a constructively terminated partnership to provide a single Schedule K-1 for the calendar year in which a termination occurs. Following a constructive termination, we would be required to make new tax elections, including a new election under Section 754 of the Code. A termination could also result in penalties if we were unable to determine that the termination had occurred. Moreover, a termination may either accelerate the application of, or subject us to, any tax legislation enacted before the termination that would not otherwise have been applied to us as a continuing, as opposed to a terminating, partnership.

Uniformity of Units

Because we cannot match transferors and transferees of units and for other reasons, we must maintain uniformity of the economic and tax characteristics of the units to a purchaser of these units. In the absence of uniformity, we may be unable to completely comply with a number of federal income tax requirements. Any non-uniformity could have a negative impact on the value of the units. Please read “—Tax Consequences of Unit Ownership—Section 754 Election.”

Our partnership agreement permits our general partner to take positions in filing our tax returns that preserve the uniformity of our units. These positions may include reducing the depreciation, amortization or loss deductions to which a unitholder would otherwise be entitled or reporting a slower amortization of Section 743(b) adjustments for some unitholders than that to which they would otherwise be entitled. Kirkland & Ellis LLP is unable to opine as to the validity of such filing positions.

A unitholder’s basis in units is reduced by its share of our deductions (whether or not such deductions were claimed on an individual income tax return) so that any position that we take that understates deductions will overstate the unitholder’s basis in its units, and may cause the unitholder to understate gain or overstate loss on any sale of such units. Please read “—Disposition of Units—Recognition of Gain or Loss” above and “—Tax Consequences of Unit Ownership—Section 754 Election” above. The IRS may challenge one or more of any positions we take to preserve the uniformity of units. If such a challenge were sustained, the uniformity of units might be affected, and, under some circumstances, the gain from the sale of units might be increased without the benefit of additional deductions.

Tax-Exempt Organizations and Other Investors

Ownership of units by employee benefit plans and other tax-exempt organizations as well as by non-resident alien individuals, non-U.S. corporations and other non-U.S. persons (collectively, “Non-U.S. Unitholders”) raises issues unique to those investors and, as described below, may have materially adverse tax consequences to them. Prospective unitholders that are tax-exempt entities or non-U.S. unitholders should consult their tax advisors before investing in our units. Employee benefit plans and most other tax-exempt organizations, including IRAs and other retirement plans, are subject to federal income tax on unrelated business taxable income. Because our properties will be financed with debt and because we may own working interests in the future, portions of our income may be unrelated business taxable income and may be taxable to a tax-exempt unitholder.

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Non-U.S. unitholders are taxed by the United States on income effectively connected with the conduct of a U.S. trade or business (“effectively connected income”) and on certain types of U.S.-source non-effectively connected income (such as dividends and royalties), unless exempted or further limited by an income tax treaty. Although we currently do not have plans to acquire any working interest or otherwise engage in, or to be treated by the IRS or a court as if we are engaged in, an active trade or business, we may have effectively connected income if we acquire working interests or otherwise engage in an active trade or business. Furthermore, is it probable that we would be deemed to conduct such activities through permanent establishments in the United States within the meaning of applicable tax treaties. Consequently, a non-U.S. unitholder may be required to file federal tax returns to report their share of our income, gain, loss or deduction and pay federal income tax on their share of our net income or gain in a manner similar to a taxable U.S. unitholder. Moreover, under rules concerning withholding on effectively connected income applicable to publicly traded partnerships, distributions to non-U.S. unitholders are subject to withholding at the highest applicable effective tax rate. Even though at the time of the IPO we do not anticipate that income from our royalty interests will be effectively connected income, we will instruct brokers and nominees to withhold on all distributions to non-U.S. holders at the highest applicable effective tax rate based upon the convention for effectively connected income. Non-U.S. holders may be entitled to a refund of all or a portion of this amount. Each non-U.S. unitholder that obtains a taxpayer identification number from the IRS and submits that number to our transfer agent on a Form W-8BEN or Form W-8BEN-E (or applicable substitute form) may obtain credit for these withholding taxes.

In addition, because a non-U.S. unitholder classified as a corporation may be treated as engaged in a United States trade or business, that corporation may be subject to the U.S. branch profits tax at a rate of 30%, in addition to regular federal income tax, on its share of our income and gain as adjusted for changes in the foreign corporation’s “U.S. net equity” to the extent reflected in the corporation’s effectively connected earnings and profits. That tax may be reduced or eliminated by an income tax treaty between the United States and the country in which the foreign corporate unitholder is a “qualified resident.” In addition, this type of unitholder is subject to special information reporting requirements under Section 6038C of the Code.

A non-U.S. unitholder who sells or otherwise disposes of a unit will be subject to federal income tax on gain realized from the sale or disposition of that unit to the extent the gain is effectively connected with a U.S. trade or business of the non-U.S. unitholder. Under a ruling published by the IRS interpreting the scope of “effectively connected income,” gain recognized by a non-U.S. person from the sale of its interest in a partnership that is engaged in a trade or business in the United States will be considered to be effectively connected with a U.S. trade or business. Thus, part or all of a non-U.S. unitholder’s gain from the sale or other disposition of its units may be treated as effectively connected with a unitholder’s indirect U.S. trade or business resulting from its investment in us. Moreover, under the Foreign Investment in Real Property Tax Act, a non-U.S. unitholder generally will be subject to federal income tax upon the sale or disposition of a unit if (i) it owned (directly or indirectly constructively applying certain attribution rules) more than 5% of our units at any time during the five-year period ending on the date of such disposition and (ii) 50% or more of the fair market value of our worldwide real property interests and our other assets used or held for use in a trade or business consisted of U.S. real property interests (which include U.S. real estate (including land, improvements, and certain associated personal property) and interests in certain entities holding U.S. real estate) at any time during the shorter of the period during which such unitholder held the units or the five-year period ending on the date of disposition. More than 50% of our assets may consist of U.S. real property interests. Therefore, non-U.S. unitholders may be subject to federal income tax on gain from the sale or disposition of their units.

Administrative Matters

Information Returns and Audit Procedures

We intend to furnish to each unitholder, within 90 days after the close of each taxable year, specific tax information, including a Schedule K-1, which describes its share of our income, gain, loss and deduction for our preceding taxable year. In preparing this information, which will not be reviewed by Kirkland & Ellis LLP, we

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will take various accounting and reporting positions, some of which have been mentioned earlier, to determine each unitholder’s share of income, gain, loss and deduction. We cannot assure our unitholders that those positions will yield a result that conforms to all of the requirements of the Code, Treasury Regulations or administrative interpretations of the IRS.

The IRS may audit our federal income tax information returns. Neither we nor Kirkland & Ellis LLP can assure prospective unitholders that the IRS will not successfully challenge the positions we adopt, and such a challenge could adversely affect the value of the units. Adjustments resulting from an IRS audit may require each unitholder to adjust a prior year’s tax liability and may result in an audit of the unitholder’s own return. Any audit of a unitholder’s return could result in adjustments unrelated to our returns.

Publicly traded partnerships generally are treated as entities separate from their owners for purposes of federal income tax audits, judicial review of administrative adjustments by the IRS and tax settlement proceedings. The tax treatment of partnership items of income, gain, loss and deduction are determined in a partnership proceeding rather than in separate proceedings of the partners. The Code requires that one partner be designated as the “Tax Matters Partner” for these purposes, and our partnership agreement designates our general partner.

The Tax Matters Partner can extend the statute of limitations for assessment of tax deficiencies against unitholders for items in our returns. The Tax Matters Partner may bind a unitholder with less than a 1% profits interest in us to a settlement with the IRS unless that unitholder elects, by filing a statement with the IRS, not to give that authority to the Tax Matters Partner. The Tax Matters Partner may seek judicial review, by which all the unitholders are bound, of a final partnership administrative adjustment and, if the Tax Matters Partner fails to seek judicial review, judicial review may be sought by any unitholder having at least a 1% interest in profits or by any group of unitholders having in the aggregate at least a 5% interest in profits. However, only one action for judicial review may go forward, and each unitholder with an interest in the outcome may participate in that action.

A unitholder must file a statement with the IRS identifying the treatment of any item on its federal income tax return that is not consistent with the treatment of the item on our return. Intentional or negligent disregard of this consistency requirement may subject a unitholder to substantial penalties.

Nominee Reporting

Persons who hold an interest in us as a nominee for another person are required to furnish to us:

(1) the name, address and taxpayer identification number of the beneficial owner and the nominee;

(2) a statement regarding whether the beneficial owner is:

(a) a non-U.S. person;

(b) a non-U.S. government, an international organization or any wholly owned agency or instrumentality of either of the foregoing; or

(3) the amount and description of units held, acquired or transferred for the beneficial owner; and

(4) specific information including the dates of acquisitions and transfers, means of acquisitions and transfers, and acquisition cost for purchases, as well as the amount of net proceeds from sales.

Brokers and financial institutions are required to furnish additional information, including whether they are U.S. persons and specific information on units they acquire, hold or transfer for their own account. A penalty of $100 per failure, up to a maximum of $1.5 million per calendar year, is imposed by the Code for failure to report that information to us. The nominee is required to supply the beneficial owner of the units with the information furnished to us.

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Accuracy-Related Penalties

Certain penalties may be imposed as a result of an underpayment of tax that is attributable to one or more specified causes, including negligence or disregard of rules or regulations, substantial understatements of income tax and substantial valuation misstatements. No penalty will be imposed, however, for any portion of an underpayment if it is shown that there was a reasonable cause for the underpayment of that portion and that the taxpayer acted in good faith regarding the underpayment of that portion. We do not anticipate that any accuracy related penalties will be assessed against us.

FATCA Withholding Requirements

Under the Foreign Account Tax Compliance Act (“FATCA”), a withholding agent may be required to withhold 30% of any interest, dividends and other fixed or determinable annual or periodical gains, profits and income from sources within the United States (“FDAP Income”) or gross proceeds from the sale of any property of a type which can produce interest or dividends from sources within the United States paid to (i) a foreign financial institution (which includes foreign broker-dealers, clearing organizations, investment companies, hedge funds and certain other investment entities) unless such foreign financial institution agrees to verify, report and disclose its U.S. account holders and meets certain other specified requirements or (ii) a non-financial foreign entity that is a beneficial owner of the payment unless such entity certifies that it does not have any substantial U.S. owners or provides the name, address and taxpayer identification number of each substantial U.S. owner and such entity meets certain other specified requirements or otherwise qualifies for an exemption from this withholding.

The withholding provisions described above currently apply to payments of FDAP Income and will also apply to payments of relevant gross proceeds made on or after January 1, 2017. Each prospective unitholder should consult its own tax advisor regarding these withholding provisions.

State, Local and Other Tax Considerations

In addition to federal income taxes, unitholders may be subject to other taxes, including state and local income taxes, unincorporated business taxes, and estate, inheritance or intangibles taxes that may be imposed by the various jurisdictions in which we conduct business or own property now or in the future, even if you do not live in those jurisdictions. We will initially own assets and conduct business in Texas, which imposes an income tax on corporations and other entities but does not impose a personal income tax. We may also own property or do business in other states in the future that impose income or similar taxes on nonresident individuals. Although an analysis of those various taxes is not presented here, each prospective unitholder should consider their potential impact on its investment in us.

Although you may not be required to file a return and pay taxes in some jurisdictions because your income from that jurisdiction falls below the filing and payment requirement, you may be required to file income tax returns and to pay income taxes in jurisdictions in which we do business or own property and may be subject to penalties for failure to comply with those requirements. It is your responsibility to file all U.S. federal, foreign, state and local tax returns. Our counsel has rendered an opinion solely with respect to certain federal income tax consequences of an investment in our common units. Our counsel’s opinion does not address any other tax consequences with respect to an investment in our common units except those specified herein.

It is the responsibility of each unitholder to investigate the legal and tax consequences, under the laws of pertinent jurisdictions, of his investment in us. We strongly recommend that each prospective unitholder consult, and depend upon, its own tax counsel or other advisor with regard to those matters. Further, it is the responsibility of each unitholder to file all state, local and non-U.S., as well as U.S. federal tax returns that may be required of it. Kirkland & Ellis LLP has not rendered an opinion on the state, local, alternative minimum tax, non-U.S. or other tax consequences of an investment in us.

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INVESTMENT IN ROYAL RESOURCES PARTNERS LP BY EMPLOYEE BENEFIT PLANS

An investment in us by an employee benefit plan is subject to additional considerations because the investments of these plans are subject to the fiduciary responsibility and prohibited transaction provisions of ERISA, restrictions imposed by Section 4975 of the Code, and/or provisions under any federal, state, local, non-U.S. or other laws or regulations that are similar to such provisions of the Code or ERISA (collectively, “Similar Laws”). For these purposes the term “employee benefit plan” includes, but is not limited to, qualified pension, profit-sharing and stock bonus plans, Keogh plans, simplified employee pension plans and tax deferred annuities or individual retirement accounts or annuities (“IRAs”) and entities whose underlying assets are considered to include “plan assets” of such plans, accounts or arrangements. Among other things, consideration should be given to:

•

whether the investment is prudent under Section 404(a)(1)(B) of ERISA and any other applicable Similar Laws;

•

whether in making the investment, the plan will satisfy the diversification requirements of Section 404(a)(1)(C) of ERISA and any other applicable Similar Laws; and

•

whether the investment will result in recognition of unrelated business taxable income by the plan and, if so, the potential after-tax investment return. Please read “Material U.S. Federal Income Tax Consequences—Tax-Exempt Organizations and Other Investors.”

The person with investment discretion with respect to the assets of an employee benefit plan, often called a fiduciary, should determine whether an investment in us is authorized by the appropriate governing instrument and is a proper investment for the plan.

Section 406 of ERISA and Section 4975 of the Code prohibit employee benefit plans from engaging in specified transactions involving “plan assets” with parties that are “parties in interest” under ERISA or “disqualified persons” under the Code with respect to the plan.

In addition to considering whether the purchase of common units is a prohibited transaction, a fiduciary of an employee benefit plan should consider whether the plan will, by investing in us, be deemed to own an undivided interest in our assets, with the result that our operations would be subject to the regulatory restrictions of ERISA, including its prohibited transaction rules, as well as the prohibited transaction rules of the Code and any other applicable Similar Laws.

The Department of Labor regulations provide guidance with respect to whether the assets of an entity in which employee benefit plans acquire equity interests would be deemed “plan assets” under some circumstances. Under these regulations, an entity’s assets would not be considered to be “plan assets” if, among other things:

(1) the equity interests acquired by employee benefit plans are publicly offered securities—i.e., the equity interests are widely held by 100 or more investors independent of the issuer and each other, freely transferable and registered under some provisions of the federal securities laws;

(2) the entity is an “operating company”—i.e., it is primarily engaged in the production or sale of a product or service other than the investment of capital either directly or through a majority-owned subsidiary or subsidiaries; or

(3) there is no significant investment by benefit plan investors, which is defined to mean that less than 25% of the value of each class of equity interest is held by the employee benefit plans referred to above.

Plan fiduciaries contemplating a purchase of common units should consult with their own counsel regarding the consequences under ERISA, the Code and any other applicable Similar Laws in light of the serious penalties imposed on persons who engage in prohibited transactions or other violations.

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UNDERWRITING

Under the terms and subject to the conditions contained in an underwriting agreement with respect to the common units being offered, we have agreed to sell to the underwriters named below, for whom Credit Suisse Securities (USA) LLC is acting as representative, the following respective amounts of common units:


Underwriter		Number of Common Units
Credit Suisse Securities (USA) LLC
Citigroup Global Markets Inc.
Morgan Stanley & Co. LLC
Wells Fargo Securities, LLC
Barclays Capital Inc.
Merrill Lynch, Pierce, Fenner & Smith Incorporated


Total

The underwriting agreement provides that the underwriters are obligated to purchase all of the common units in the offering if any are purchased, other than those units covered by the underwriters’ option to purchase additional units described below. The underwriting agreement also provides that if an underwriter defaults the purchase commitments of non-defaulting underwriters may be increased or the offering may be terminated. The offering of the common units by the underwriters is subject to receipt and acceptance and subject to the underwriters’ right to reject any order in whole or in part.

We have granted to the underwriters a 30-day option to purchase on a pro rata basis up to additional common units at the initial public offering price less the underwriting discounts and commissions. If any common units are purchased pursuant to this option, the underwriters will severally purchase the common units in approximately the same proportion as set forth in the table above.

The underwriters propose to offer the common units initially at the public offering price on the cover page of this prospectus at that price less a selling concession of up to per common unit. After the initial public offering the representatives may change the public offering price and concession.

The following table summarizes the compensation we will pay:

Per Unit

Total

Without
option to
purchase
additional units

With
option to
purchase
additional units

Without
option to
purchase
additional units

With
option to
purchase
additional units

Underwriting Discounts and Commissions paid by us

We estimate that the expenses of the offering, not including the underwriting discounts and commissions, will be approximately $ million. We will also pay up to $ of the reasonable fees and expenses of counsel related to the review by the Financial Industry Regulatory Authority, Inc. of the terms of the sale of the common units offered hereby.

We intend to apply to list our common units on the NYSE under the symbol “ORRI.” The representatives have informed us that they do not expect sales to accounts over which the underwriters have discretionary authority to exceed 5% of the number of common units being offered.

We, our Sponsor, Holdings, our general partner and our general partner’s directors and executive officers have agreed that they will not offer, sell, contract to sell, pledge or otherwise dispose of, directly or indirectly,

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any of our common units or securities convertible into or exchangeable or exercisable for any of our common units, enter into a transaction that would have the same effect, or enter into any swap, hedge or other arrangement that transfers, in whole or in part, any of the economic consequences of ownership of our common units, whether any of these transactions are to be settled by delivery of our common units or other securities, in cash or otherwise, or publicly disclose the intention to make any offer, sale, pledge or disposition, or to enter into any transaction, swap, hedge or other arrangement, without, in each case, the prior written consent of Credit Suisse Securities (USA) LLC for a period of 180 days after the date of this prospectus.

We, our general partner, Holdings and DGK have agreed to indemnify the underwriters against liabilities under the Securities Act, or contribute to payments that the underwriters may be required to make in that respect.

Because the Financial Industry Regulatory Authority views our common units as interests in a direct participation program, this offering is being made in compliance with Rule 2310 of the FINRA rules. Investor suitability with respect to the common units will be judged similarly to the suitability with respect to other securities that are listed for trading on a national securities exchange.

In connection with the offering the underwriters may engage in stabilizing transactions, over-allotment transactions, syndicate covering transactions and penalty bids.

Stabilizing transactions permit bids to purchase the underlying security so long as the stabilizing bids do not exceed a specified maximum.

Over-allotment involves sales by the underwriters of common units in excess of the number of units the underwriters are obligated to purchase, which creates a syndicate short position. The short position may be either a covered short position or a naked short position. In a covered short position, the number of units over-allotted by the underwriters is not greater than the number of units that they may purchase in the over-allotment option. In a naked short position, the number of units involved is greater than the number of units in the over-allotment option. The underwriters may close out any covered short position by either exercising their over-allotment option and/or purchasing units in the open market.

Syndicate covering transactions involve purchases of the common units in the open market after the distribution has been completed in order to cover syndicate short positions. In determining the source of units to close out the short position, the underwriters will consider, among other things, the price of units available for purchase in the open market as compared to the price at which they may purchase units through the over-allotment option. If the underwriters sell more units than could be covered by their exercise of the over-allotment option, which is the equivalent of a naked short position, the position can only be closed out by buying units in the open market. A naked short position is more likely to be created if the underwriters are concerned that there could be downward pressure on the price of the units in the open market after pricing that could adversely affect investors who purchase in the offering.

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

In passive market making, market makers in our common units who are underwriters or prospective underwriters may, subject to limitations, make bids for or purchases of our common units until the time, if any, at which a stabilizing bid is made.

These stabilizing transactions, syndicate covering transactions and penalty bids may have the effect of raising or maintaining the market price of our common units or preventing or retarding a decline in the market price of our common units. As a result the price of our common units may be higher than the price that might otherwise exist in the open market. These transactions may be effected on the NYSE or otherwise and, if commenced, may be discontinued at any time.

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The underwriters and their respective affiliates are full service financial institutions engaged in various activities, which may include sales and trading, commercial and investment banking, advisory, investment management, investment research, principal investment, hedging, market making, brokerage and other financial and non-financial activities and services. Certain of the underwriters and their respective affiliates have provided, and may in the future provide, a variety of these services to us and to persons and entities with relationships to us, for which they received or will receive customary fees and expenses.

In the ordinary course of their various business activities, the underwriters and their respective affiliates, officers, directors and employees may purchase, sell or hold a broad array of investments and actively trade securities, derivatives, loans, commodities, currencies, credit default swaps and other financial instruments for their own account and for the accounts of their customers, and such investment and trading activities may involve or relate to assets, securities and/or instruments of the issuer (directly, as collateral securing other obligations or otherwise) and/or persons and entities with relationships to the issuer. The underwriters and their respective affiliates may also communicate independent research views in respect of such assets, securities or instruments and may at any time hold, or recommend to clients that they should acquire, long and/or short positions in such assets, securities and instruments.

Offering Price Determination

Prior to this offering, there has been no public market for our common units. The initial public offering price will be determined by negotiation between us and the representatives. Among the factors to be considered in determining the initial public offering price of the common units, in addition to prevailing market conditions, will be our historical performance, estimates of our business potential and earnings prospects, an assessment of our management and the consideration of the above factors in relation to the current market valuation of companies in related businesses or which are comparable to us. We cannot assure you, however, that the price at which the common units will sell in the public market after this offering will not be lower than the initial public offering price or that an active trading market in our common units will develop and continue after this offering.

Electronic Distribution

A prospectus in electronic format will be made available on the web sites maintained by one or more of the underwriters, or selling group members, if any, participating in this offering and one or more of the underwriters participating in this offering may distribute prospectuses electronically. The representatives may agree to allocate a number of common units to underwriters and selling group members for sale to their online brokerage account holders. Internet distributions will be allocated by the underwriters and selling group members that will make internet distributions on the same basis as other allocations.

Other than the prospectus in electronic format, the information on any underwriter’s or selling group member’s web site and any information contained in any other web site maintained by an underwriter or selling group member is not part of the prospectus or the registration statement of which this prospectus forms a part, has not been approved and/or endorsed by us or any underwriter or selling group member in its capacity as underwriter or selling group member and should not be relied upon by investors.

We have not authorized and do not authorize the making of any offer of securities through any financial intermediary on their behalf, other than offers made by the underwriters with a view to the final placement of the securities as contemplated in this prospectus. Accordingly, no purchaser of the securities, other than the underwriters, is authorized to make any further offer of the securities on behalf of us or the underwriters.

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Notice to Prospective Investors in Hong Kong

Our common units may not be offered or sold in Hong Kong by means of this prospectus or any other document other than to (a) professional investors as defined in the Securities and Futures Ordinance of Hong Kong (Cap. 571, Laws of Hong Kong) (“SFO”) and any rules made under the SFO or (b) in other circumstances which do not result in this prospectus being deemed to be a “prospectus,” as defined in the Companies Ordinance of Hong Kong (Cap. 32, Laws of Hong Kong) (“CO”), or which do not constitute an offer to the public within the meaning of the CO or the SFO; and no person has issued or had in possession for the purposes of issue, or will issue or has in possession for the purposes of issue, whether in Hong Kong or elsewhere, any advertisement, invitation or document relating to our common units which is directed at, or the contents of which are likely to be accessed or read by, the public of Hong Kong (except if permitted to do so under the securities laws of Hong Kong) other than with respect to our common units which are or are intended to be disposed of only to persons outside Hong Kong or only to professional investors as defined in the SFO.

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LEGAL MATTERS

The validity of our common units and certain other legal matters will be passed upon for us by Kirkland & Ellis LLP, Houston, Texas. Certain legal matters in connection with this offering will be passed upon for the underwriters by Baker Botts L.L.P., Houston, Texas.

EXPERTS

The financial statements of DGK ORRI Holdings, LP as of December 31, 2013 and 2014, and for the years ended December 31, 2013 and 2014, included in this prospectus have been audited by Deloitte & Touche LLP, an independent registered public accounting firm, as stated in their report appearing herein. Such financial statements are included in reliance upon the report of such firm given upon their authority as experts in accounting and auditing.

The balance sheets of Royal Resources Partners LP as of December 31, 2014 and November 11, 2014, included in this prospectus have been audited by Deloitte & Touche LLP, an independent registered public accounting firm, as stated in their report appearing herein. Such financial statements are included in reliance upon the report of such firm given upon their authority as experts in accounting and auditing.

Information included in this prospectus regarding our estimated quantities of oil and gas reserves and the discounted present value of future net cash flows therefrom is based upon estimates of such reserves and present values prepared by W.D. Von Gonten & Co., an independent petroleum engineering firm, as of December 31, 2013 and by Ryder Scott Company, L.P., an independent petroleum engineering firm, as of December 31, 2014. This information is included herein in reliance upon the authority of said firm as experts in these matters.

WHERE YOU CAN FIND MORE INFORMATION

We have filed with the SEC a registration statement on Form S-1 (including the exhibits, schedules and amendments thereto) under the Securities Act with respect to the common units being offered hereunder. This prospectus does not contain all of the information set forth in the registration statement and the exhibits and schedules to the registration statement. For further information with respect to us and our common units, we refer you to the registration statement and the exhibits filed as a part of the registration statement. Statements contained in this prospectus concerning the contents of any contract or any other documents are not necessarily complete. If a contract or document has been filed as an exhibit to the registration statement, we refer you to the copy of the contract or document that has been filed as an exhibit and reference thereto is qualified in all respects by the terms of the filed exhibit. The registration statement, including any exhibits and schedules, may be inspected without charge at the Public Reference Room of the SEC at 100 F Street, N.E., Washington, D.C. 20549, and copies of these materials may be obtained from that office after payment of fees prescribed by the SEC. Information on the operation of the Public Reference Room may be obtained by calling the SEC at 1-800-SEC-0330. The SEC maintains a web site that contains reports, proxy and information statements and other information regarding registrants that file electronically with the SEC at http://www.sec.gov.

As a result of this offering, we will become subject to the full informational requirements of the Exchange Act. We will fulfill our obligations with respect to such requirements by filing period reports and other information with the SEC.

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FORWARD-LOOKING STATEMENTS

Some of the information in this prospectus may contain forward-looking statements. Forward-looking statements give our current expectations, contain projections of results of operations or of financial condition, or forecasts of future events. Words such as “may,” “assume,” “forecast,” “position,” “predict,” “strategy,” “expect,” “intend,” “plan,” “estimate,” “anticipate,” “believe,” “project,” “budget,” “potential,” or “continue,” and similar expressions are used to identify forward-looking statements. They can be affected by assumptions used or by known or unknown risks or uncertainties. Consequently, no forward-looking statements can be guaranteed. When considering these forward-looking statements, you should keep in mind the risk factors and other cautionary statements in this prospectus. Actual results may vary materially. You are cautioned not to place undue reliance on any forward-looking statements. You should also understand that it is not possible to predict or identify all such factors and should not consider the following list to be a complete statement of all potential risks and uncertainties. Factors that could cause our actual results to differ materially from the results contemplated by such forward-looking statements include:

•

our ability to execute our business strategies;

•

the volatility of realized price for oil, natural gas liquids and natural gas;

•

the level of production on the properties underlying our ORRIs;

•

the level of drilling and completion activity by third party operators on the acreage underlying our ORRIs;

•

regional supply and demand factors, delays or interruptions of production;

•

our ability to replace our oil and natural gas reserves;

•

our ability to identify, complete and integrate acquisitions of properties or businesses;

•

general economic, business or industry conditions;

•

competition in the oil and natural gas industry;

•

the ability of our operators to obtain capital or financing needed for development and exploration operations;

•

title defects in the properties underlying our ORRIs;

•

uncertainties with respect to identified drilling locations and estimates of reserves;

•

the availability or cost of rigs, completion crews, equipment, raw materials, supplies, oilfield services or personnel;

•

restrictions on or the availability of the use of water;

•

the availability of transportation facilities;

•

the ability of our operators to comply with applicable governmental laws and regulations and to obtain permits and governmental approvals;

•

federal and state legislative and regulatory initiatives relating to hydraulic fracturing;

•

future operating results;

•

exploration and development drilling prospects, inventories, projects and programs;

•

operating hazards faced by our operators;

•

the ability of our operators to keep pace with technological advancements; and

•

certain factors discussed elsewhere in this prospectus.

All forward-looking statements are expressly qualified in their entirety by the foregoing cautionary statements.

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Large accelerated filer

Accelerated filer

Non-accelerated filer

x (Do not check if a smaller reporting company)

Smaller reporting company

INDEX TO FINANCIAL STATEMENTS

Royal Resources Partners LP S-1/A