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TABLE OF CONTENTS
INDEX TO FINANCIAL STATEMENTS

Table of Contents

As filed with the Securities and Exchange Commission on January 6, 2017

Registration No. 333-             


UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549



FORM S-1
REGISTRATION STATEMENT
UNDER
THE SECURITIES ACT OF 1933



Kimbell Royalty Partners, LP
(Exact name of registrant as specified in its charter)



Delaware
(State or other jurisdiction of
incorporation or organization)
  1311
(Primary Standard Industrial
Classification Code Number)
  47-5505475
(I.R.S. Employer
Identification No.)

777 Taylor Street, Suite 810
Fort Worth, Texas 76102
(817) 945-9700

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



R. Davis Ravnaas
President and Chief Financial Officer
Kimbell Royalty Partners, LP
777 Taylor Street, Suite 810
Fort Worth, Texas 76102
(817) 945-9700

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



Copies to:

Joshua Davidson
Jason A. Rocha
Baker Botts L.L.P.
One Shell Plaza
910 Louisiana Street
Houston, Texas 77002
Tel: (713) 229-1234
Fax: (713) 229-1522

 

William N. Finnegan IV
John M. Greer
Latham & Watkins LLP
811 Main Street, Suite 3700
Houston, Texas 77002
Tel: (713) 546-5400
Fax: (713) 546-5401



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.    o

          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.    o

          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.    o

          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.    o

          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.

Large accelerated filer o   Accelerated filer o   Non-accelerated filer ý
(Do not check if a
smaller reporting company)
  Smaller reporting company o



CALCULATION OF REGISTRATION FEE

       
 
Title of Each Class of Securities
to be Registered

  Proposed Maximum
Aggregate Offering
Price (1)(2)

  Amount of
Registration Fee

 

Common units representing limited partner interests

  $100,000,000   $11,590.00

 

(1)
Includes common units issuable upon exercise of the underwriters' option to purchase additional common units.

(2)
Estimated solely for the purpose of calculating the registration fee pursuant to Rule 457(o).

          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.

   


Table of Contents

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 January 6, 2017

PROSPECTUS

GRAPHIC

Kimbell Royalty Partners, LP

              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 in this offering. 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 have been approved to list our common units on the New York Stock Exchange, subject to official notice of issuance, under the symbol "KRP." We are an "emerging growth company" as that term is used in the Jumpstart Our Business Startups Act.

            Investing in our common units involves a high degree of risk. Before buying any common units, you should carefully read the discussion of material risks of investing in our common units in "Risk Factors" beginning on page 31. These risks include the following:

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

    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. We will not have a minimum quarterly distribution or employ structures intended to consistently maintain or increase distributions over time and could pay no distribution with respect to any particular quarter.

    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 acreage underlying our interests 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 business, financial condition, results of operations and cash available for distribution.

    We depend on unaffiliated operators for all of the exploration, development and production on the properties in which we own mineral and royalty interests. Substantially all of our revenue is derived from royalty payments made by these operators. A reduction in the expected number of wells to be drilled on the acreage underlying our interests by these operators or the failure of these operators to adequately and efficiently develop and operate the underlying acreage could materially adversely affect our results of operations and cash available for distribution.

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

    Our general partner and its affiliates, including our Sponsors and their respective affiliates, have conflicts of interest with us and limited duties to us and our unitholders, and they may favor their own interests to the detriment of us and our unitholders. Additionally, we have no control over the business decisions and operations of our Sponsors and their respective affiliates, which are under no obligation to adopt a business strategy that favors us.

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

    Our partnership agreement replaces fiduciary duties applicable to a corporation with contractual duties and restricts the remedies available to holders of our common units for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty.

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

    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.

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



 
  Per
Common Unit
  Total  

Initial public offering price

  $     $    

Underwriting discount (1)

  $     $    

Proceeds to Kimbell Royalty Partners, LP (before expenses)

  $     $    

(1)
Excludes an aggregate structuring fee equal to         % of the gross proceeds of this offering payable to Raymond James & Associates, Inc. Please read "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 solely to cover over-allotments.

            The underwriters expect to deliver the common units to purchasers on or about                           , 2017 through the book-entry facilities of The Depository Trust Company.



Joint Book-Running Managers

RAYMOND JAMES   RBC CAPITAL MARKETS   STIFEL

Co-Managers

STEPHENS INC.   WUNDERLICH



Prospectus dated                           , 2017


Table of Contents

GRAPHIC



TABLE OF CONTENTS

PRESENTATION OF FINANCIAL AND OPERATING DATA

  v

INDUSTRY AND MARKET DATA

  v

SUMMARY

  1

Overview

  1

Our Assets

  5

Our Properties

  6

Business Strategies

  8

Competitive Strengths

  10

Management

  11

Summary of Conflicts of Interest and Duties

  12

Emerging Growth Company Status

  12

Risk Factors

  13

Formation Transactions

  16

Principal Executive Offices

  16

Organizational Structure After the Formation Transactions

  17

The Offering

  18

Summary Historical and Unaudited Pro Forma Condensed Combined Financial Data

  24

Non-GAAP Financial Measures

  26

Summary Reserve Data

  29

Summary Production Data

  30

RISK FACTORS

  31

Risks Related to Our Business

  31

Risks Inherent in an Investment in Us

  56

Tax Risks to Common Unitholders

  69

USE OF PROCEEDS

  74

CAPITALIZATION

  75

DILUTION

  76

CASH DISTRIBUTION POLICY AND RESTRICTIONS ON DISTRIBUTIONS

  78

General

  78

Unaudited Pro Forma Cash Available for Distribution for the Year Ended December 31, 2015 and the Twelve Months Ended September 30, 2016

  80

Estimated Cash Available for Distribution for the Twelve Months Ending December 31, 2017

  83

HOW WE PAY DISTRIBUTIONS

  94

General

  94

Method of Distributions

  95

Common Units

  95

General Partner Interest

  95

SELECTED HISTORICAL AND UNAUDITED PRO FORMA FINANCIAL DATA

  96

Non-GAAP Financial Measures

  98

i


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

  101

Overview

  101

Business Environment

  101

Sources of Our Revenue

  102

Reserves and Pricing

  103

Adjusted EBITDA

  103

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

  104

Principal Components of Our Cost Structure

  105

Predecessor Results of Operations

  107

Comparison of the Nine Months Ended September 30, 2016 to the Nine Months Ended September 30, 2015

  107

Comparison of the Year Ended December 31, 2015 to the Year Ended December 31, 2014

  109

Liquidity and Capital Resources

  111

Internal Controls and Procedures

  115

New and Revised Financial Accounting Standards

  115

Critical Accounting Policies

  116

Off-Balance Sheet Arrangements

  119

Quantitative and Qualitative Disclosure about Market Risk

  119

BUSINESS

  120

Overview

  120

Our Assets

  123

Business Strategies

  125

Competitive Strengths

  127

Our Properties

  128

Oil and Natural Gas Data

  132

Oil and Natural Gas Production Prices and Production Costs

  136

Competition

  138

Seasonal Nature of Business

  139

Regulation

  139

Title to Properties

  148

Employees

  148

Facilities

  148

Legal Proceedings

  148

MANAGEMENT

  149

Management of Kimbell Royalty Partners, LP

  149

Executive Officers and Directors of Our General Partner

  150

Director Independence

  153

Board Leadership Structure

  154

Board Role in Risk Oversight

  154

ii


Committees of the Board of Directors

  154

EXECUTIVE COMPENSATION AND OTHER INFORMATION

  156

Compensation Discussion and Analysis

  156

Long-Term Incentive Plan

  157

Director Compensation

  160

SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

  161

CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

  162

Distributions and Payments to Our Sponsors, the Contributing Parties, Our General Partner and their Respective Affiliates

  162

Agreements and Transactions with Affiliates in Connection with this Offering

  164

Procedures for Review, Approval and Ratification of Transactions with Related Persons

  170

CONFLICTS OF INTEREST AND DUTIES

  171

Conflicts of Interest

  171

Duties of Our General Partner

  177

DESCRIPTION OF OUR COMMON UNITS

  182

Our Common Units

  182

Transfer Agent and Registrar

  182

Transfer of Common Units

  182

Listing

  183

THE PARTNERSHIP AGREEMENT

  184

Organization and Duration

  184

Purpose

  184

Cash Distributions

  184

Capital Contributions

  185

Adjustments to Capital Accounts Upon Issuance of Additional Common Units

  185

Voting Rights

  185

Applicable Law; Forum, Venue and Jurisdiction

  186

Limited Liability

  187

Issuance of Additional Partnership Interests

  188

Amendment of the Partnership Agreement

  188

Certain Provisions of the Agreement Governing our General Partner

  191

Merger, Consolidation, Conversion, Sale or Other Disposition of Assets

  191

Dissolution

  192

Liquidation and Distribution of Proceeds

  193

Withdrawal or Removal of Our General Partner

  193

Transfer of General Partner Interest

  194

Transfer of Ownership Interests in Our General Partner

  194

Change of Management Provisions

  194

Limited Call Right

  194

Meetings; Voting

  195

Status as Limited Partner

  196

Ineligible Holders; Redemption

  196

Indemnification

  196

Reimbursement of Expenses

  197

Books and Reports

  197

iii


Right to Inspect Our Books and Records

  198

UNITS ELIGIBLE FOR FUTURE SALE

  199

MATERIAL U.S. FEDERAL INCOME TAX CONSEQUENCES

  201

Partnership Status

  202

Limited Partner Status

  204

Tax Consequences of Unit Ownership

  204

Tax Treatment of Operations

  211

Disposition of Common Units

  214

Uniformity of Units

  216

Tax-Exempt Organizations and Other Investors

  217

Administrative Matters

  218

State, Local, Foreign and Other Tax Considerations

  222

INVESTMENT IN KIMBELL ROYALTY PARTNERS, LP BY EMPLOYEE BENEFIT PLANS

  224

Prohibited Transaction Issues

  224

Plan Asset Issues

  225

UNDERWRITING

  226

Option to Purchase Additional Common Units

  226

Discounts and Expenses

  227

Indemnification

  227

Lock-Up Agreements

  227

Stabilization

  228

Relationships

  228

Discretionary Accounts

  229

Directed Unit Program

  229

Listing

  229

Determination of Initial Offering Price

  229

Electronic Prospectus

  230

FINRA Conduct Rules

  230

Selling Restrictions

  230

LEGAL MATTERS

  231

EXPERTS

  231

WHERE YOU CAN FIND MORE INFORMATION

  232

FORWARD-LOOKING STATEMENTS

  233

INDEX TO FINANCIAL STATEMENTS

  F-1

APPENDIX A—FORM OF AMENDED AND RESTATED AGREEMENT OF LIMITED PARTNERSHIP OF KIMBELL ROYALTY PARTNERS, LP

  A-1

APPENDIX B—GLOSSARY OF TERMS

  B-1



        We and the underwriters have not authorized anyone to provide any information or to make any representations other than those contained in this prospectus or in any free writing prospectuses we have prepared. We and the underwriters take no responsibility for, and can provide no assurance as to the reliability of, any other information that others may give you. 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.

iv



PRESENTATION OF FINANCIAL AND OPERATING DATA

        Unless otherwise indicated, the historical financial information presented in this prospectus is that of our predecessor, Rivercrest Royalties, LLC. The pro forma financial information in this prospectus is derived from the unaudited condensed combined pro forma financial statements included elsewhere in this prospectus which reflect, among other things, the financial statements of our predecessor and the acquisition of assets to be contributed to us by the Kimbell Art Foundation, Trunk Bay Royalty Partners, Ltd., Oil Nut Bay Royalties, LP, Gorda Sound Royalties, LP and Bitter End Royalties, LP, RCPTX, Ltd., and French Capital Partners, Ltd., which make up a portion of the Contributing Parties. Please read the unaudited condensed combined pro forma financial statements included elsewhere in this prospectus.

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


INDUSTRY AND MARKET DATA

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

v


Table of Contents



SUMMARY

        This summary highlights selected information contained elsewhere in this prospectus. It does not contain all the information you should consider before investing in our common units. You should carefully read the entire prospectus, including "Risk Factors" and the historical and unaudited pro forma condensed combined financial statements and related notes included elsewhere in this prospectus, before making an investment decision. The information presented in this prospectus assumes an initial public offering price of $         per 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 do not exercise their option to purchase additional common units.

        Unless the context otherwise requires, references in this prospectus to "Kimbell Royalty Partners, LP," "our partnership," "we," "our," "us" or like terms refer to Kimbell Royalty Partners, LP and its subsidiaries. References to "our general partner" refer to Kimbell Royalty GP, LLC. References to "our Sponsors" refer to affiliates of our founders, Ben J. Fortson, Robert D. Ravnaas, Brett G. Taylor and Mitch S. Wynne, respectively. References to "Kimbell Holdings" refer to Kimbell GP Holdings, LLC, a jointly owned subsidiary of our Sponsors and the parent of our general partner. References to the "Contributing Parties" refer to all entities and individuals, including affiliates of our Sponsors, that are contributing, directly or indirectly, certain mineral and royalty interests to us. References to "our predecessor" refer to Rivercrest Royalties, LLC, our predecessor for accounting purposes. References to "Kimbell Operating" refer to Kimbell Operating Company, LLC, a wholly owned subsidiary of our general partner, which will enter into separate service agreements with certain entities controlled by Benny D. Duncan and Messrs. R. Ravnaas, Taylor and Wynne as described herein.


Kimbell Royalty Partners, LP

Overview

        We are a Delaware limited partnership formed to own and acquire mineral and royalty interests in oil and natural gas properties throughout the United States. As an owner of mineral and royalty interests, we are entitled to a portion of the revenues received from the production of oil, natural gas and associated natural gas liquids from the acreage underlying our interests, net of post-production expenses and taxes. We are not obligated to fund drilling and completion costs, lease operating expenses or plugging and abandonment costs at the end of a well's productive life. Our primary business objective is to provide increasing cash distributions to unitholders resulting from acquisitions from our Sponsors, the Contributing Parties and third parties and from organic growth through the continued development by working interest owners of the properties in which we own an interest.

        As of December 31, 2015, we owned mineral and royalty interests in approximately 3.7 million gross acres and overriding royalty interests in approximately 0.9 million gross acres, with approximately 44% of our aggregate acres located in the Permian Basin. We refer to these non-cost-bearing interests collectively as our "mineral and royalty interests." As of December 31, 2015, over 95% of the acreage subject to our mineral and royalty interests was leased to working interest owners (including 100% of our overriding royalty interests), and substantially all of those leases were held by production. Our mineral and royalty interests are located in 20 states and in nearly every major onshore basin across the continental United States and include ownership in over 48,000 gross producing wells, including over 29,000 wells in the Permian Basin. For the six months ended June 30, 2016, approximately 52.6% of our production was from the Permian Basin, Eagle Ford, Terryville/Cotton Valley/Haynesville and the Bakken/Williston Basin, which are some of the most active areas in the country. The geographic breadth

1


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of our assets gives us exposure to potential production and reserves from new and existing plays. Over the long term, we expect working interest owners will continue to develop our acreage through infill drilling, horizontal drilling, hydraulic fracturing, recompletions and secondary and tertiary recovery methods. As an owner of mineral and royalty interests, we benefit from the continued development of the properties in which we own an interest without the need for investment of additional capital by us.

        Certain members of our management team have completed over 160 acquisitions of mineral and royalty interests and have significant experience in identifying, evaluating and completing strategic acquisitions. Mr. R. Ravnaas, our Chief Executive Officer, and our directors Messrs. Fortson, Taylor and Wynne, who we refer to collectively as our founders, began actively acquiring mineral and royalty interests in 1998 when they began to jointly acquire mineral and royalty interests in conventional onshore U.S. basins. They initially focused on mineral and royalty interests in the Permian Basin, and later expanded their acquisition efforts to several other basins. Beginning in 2000, this group expanded to include nearly all the Contributing Parties. Our founders have focused on acquiring properties characterized by long-life, shallow decline production and significant oil and natural gas reserves.

        For the 15-year period ended December 31, 2015, the net oil and net natural gas production from our assets, including acquisitions, has grown at a compound annual growth rate of 16.8% and 19.2%, respectively. The chart below shows the compound annual growth rate of production from our mineral and royalty interests for such period:


Net Production Growth (Including Acquisitions) (2001-2015)

GRAPHIC


    Note:    Net oil and net natural gas production information was gathered from state reporting records. Natural gas liquids, which are not reported by the states, are excluded from the chart.

2


Table of Contents

        For the 15-year period ended December 31, 2015, the net oil and net natural gas production from our assets has grown organically (assuming we had acquired all of our interests on January 1, 2001 and made no additional acquisitions) at a compound annual growth rate of 3.2% and 1.0%, respectively. The chart below shows the compound annual growth rate attributable to our combined mineral and royalty interests as if we had acquired all of such interests on January 1, 2001 and made no additional acquisitions.


Organic Net Production Growth (2001-2015)

GRAPHIC


    Note:    Net oil and net natural gas production information was gathered from state reporting records. Natural gas liquids, which are not reported by the states, are excluded from the chart.

        As of December 31, 2015, the estimated proved oil, natural gas and natural gas liquids reserves attributable to our interests in our underlying acreage were 18,120 MBoe (52.4% liquids, consisting of 79.7% oil and 20.3% natural gas liquids) based on a reserve report prepared by Ryder Scott Company, L.P., an independent petroleum engineering firm ("Ryder Scott"). Of these reserves, 70.4% were classified as proved developed producing ("PDP") reserves, 0.8% were classified as proved developed non-producing ("PDNP") reserves and 28.8% were classified as proved undeveloped ("PUD") reserves. The properties underlying our mineral and royalty interests typically have low estimated decline rates. Our PDP reserves have an average estimated initial five-year decline rate of 10%. PUD reserves included in this estimate are from 759 gross proved undeveloped locations. For the six months ended June 30, 2016, our average daily net production was 3,317 Boe/d.

3


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        For the year ended December 31, 2015, on a pro forma basis, our revenues were derived 63.0% from oil sales, 30.0% from natural gas sales and 7.0% from natural gas liquid sales. Our revenues are derived from royalty payments we receive from the operators of our properties 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 December 31, 2015, we had over 700 operators on our acreage, with our top ten operators (Occidental Permian Ltd., Newfield Exploration Company, Range Resources Corporation/Memorial Resource Development Corp., Aera Energy LLC (a joint venture of Royal Dutch Shell plc and ExxonMobil Corporation), XTO Energy, Inc., Jonah Energy LLC, Campbell Development Group, LLC, EOG Resources, Inc., Chesapeake Energy Corporation and Devon Energy Corporation) together accounting for approximately 46.9% of our combined discounted future net income (discounted at 10%). 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 and natural gas liquids prices have historically been volatile, and we do not currently hedge our exposure to changes in commodity prices.

        We believe that one of our key strengths is our management team's extensive experience in acquiring and managing mineral and royalty interests. Our management team and board of directors, which includes our founders, have a long history of creating value. We expect our business model to allow us to integrate significant acquisitions into our existing organizational structure quickly and cost-efficiently. In particular, Messrs. R. Ravnaas, Taylor and Wynne average over 30 years sourcing, engineering, evaluating, acquiring and managing mineral and royalty interests. In connection with this offering, we will enter into a management services agreement with Kimbell Operating, which will enter into separate service agreements with certain entities controlled by Messrs. R. Ravnaas, Taylor and Wynne, pursuant to which they will identify, evaluate and recommend to us acquisition opportunities and negotiate the terms of such acquisitions. Please read "Certain Relationships and Related Party Transactions—Agreements and Transactions with Affiliates in Connection with this Offering—Management Services Agreements."

        Upon completion of this offering, our Sponsors will indirectly own and control our general partner, and the Contributing Parties will own an aggregate of approximately           % of our outstanding common units (excluding any common units purchased by officers and directors of our general partner under our directed unit program). The Contributing Parties, including affiliates of our Sponsors, will retain a diverse portfolio of mineral and royalty interests with production and reserve characteristics similar to the assets we will own at the closing of this offering. In connection with this offering and pursuant to the contribution agreement that we have entered into with our Sponsors and the Contributing Parties, certain of the Contributing Parties have granted us a right of first offer for a period of three years after the closing of this offering with respect to certain mineral and royalty interests in the Permian Basin, the Bakken/Williston Basin and the Marcellus Shale. We believe the Contributing Parties, including affiliates of our Sponsors, will be incentivized through their direct or indirect ownership of common units to offer us the opportunity to acquire additional mineral and royalty interests from them in the future. Such Contributing Parties, however, have no obligation to sell any assets to us or to accept any offer that we may make for such assets, and we may decide not to acquire such assets even if such Contributing Parties offer them to us. In addition, under the contribution agreement, we have a right to participate, at our option and on substantially the same or better terms, in up to 50% of any acquisitions, other than de minimis acquisitions, for which Messrs. R. Ravnaas, Taylor and Wynne provide, directly or indirectly, any oil and gas diligence, reserve engineering or other business services. Please read "Certain Relationships and Related Party

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Transactions—Agreements and Transactions with Affiliates in Connection with this Offering—Contribution Agreement."

Our Assets

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

Mineral Interests

        Mineral interests are real property interests that are typically perpetual and grant ownership to all of the oil and natural gas lying below the surface of the property, as well as the right to explore, drill and produce oil and natural gas on that property or to lease such rights to a third party. Mineral owners typically grant oil and gas leases to operators for an initial three-year term with an upfront cash payment to the mineral owners known as a lease bonus. Under the lease, the mineral owner retains a royalty interest entitling it to a cost-free percentage (usually ranging from 20-25%) of production or revenue from production. The lease can be extended beyond the initial term with continuous drilling, production or other operating activities. When production or drilling ceases on the leased property, the lease is typically terminated, subject to certain exceptions, and all mineral rights revert back to the mineral owner who can then lease the exploration and development rights to another party. We also own royalty interests that have been carved out of mineral interests and are known as nonparticipating royalty interests. Nonparticipating royalty interests are typically perpetual and have rights similar to mineral interests, including the right to a cost-free percentage of production revenues for minerals extracted from the acreage, without the associated executive right to lease and the right to receive lease bonuses.

        We combine our mineral and nonparticipating royalty assets into one category because they share many of the same characteristics due to the nature of the underlying interest. For example, we receive similar royalties from operators with respect to our mineral interests or nonparticipating royalty interests as long as such interests are subject to an oil and gas lease. As of December 31, 2015, over 95% of the acreage subject to our mineral and nonparticipating royalty interests was leased. When evaluating our business, our management team does not distinguish between mineral and nonparticipating royalty interests on leased acreage due to the similarity of the royalties received by the interests.

Overriding Royalty Interests

        In addition to mineral interests, we also own overriding royalty interests, which are royalty interests that burden the working interests of a lease and represent the right to receive a fixed, cost-free percentage of production or revenue from production from a lease. Overriding royalty interests, or ORRIs, typically remain in effect until the associated lease expires, and because substantially all of the underlying leases are perpetual so long as production in paying quantities perpetuates the leasehold, substantially all of our overriding royalty interests are likewise perpetual.

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Our Properties

        The following table summarizes our ownership in U.S. basins and producing regions:

 
  Gross Acreage as of
December 31, 2015
   
 
 
  Average Daily
Production for
Six Months Ended
June 30,
2016 (2) (Boe/d)
 
Basin or Producing Region   Mineral
Interests (1)
  ORRIs  

Permian Basin (3)

    1,764,954     232,723     934  

Mid-Continent

    336,481     139,513     200  

Terryville/Cotton Valley/Haynesville

    261,762     41,812     267  

Eagle Ford

    180,367     72,970     469  

Barnett Shale/Fort Worth Basin (4)

    216,367     54,888     422  

Bakken/Williston Basin (5)

    82,704     31,554     73  

San Juan Basin

    28,852     47,233     229  

Onshore California

    7,666     9,286     109  

DJ Basin/Rockies/Niobrara

    3,967     3,182     360  

Illinois Basin

    6,351     13,304     52  

Other Western (onshore) Gulf Basin

    539,625     71,435     158  

Other TX/LA/MS Salt Basin

    144,186     22,616     9  

Other

    93,857     133,093     33  

Total

    3,667,139     873,609     3,317  

(1)
Includes both mineral and nonparticipating royalty interests.

(2)
"Btu-equivalent" production volumes are presented on an oil-equivalent basis using a conversion factor of six Mcf of natural gas per barrel of "oil equivalent," which is based on approximate energy equivalency and does not reflect the price or value relationship between oil and natural gas. Please read "Business—Oil and Natural Gas Data—Proved Reserves—Summary of Estimated Proved Reserves."

(3)
Includes mineral interests and overriding royalty interests in approximately 740,244 gross acres and 149,173 gross acres, respectively, in the Wolfcamp/Bone Spring.

(4)
Includes mineral interests and overriding royalty interests in approximately 198,229 gross acres and 50,217 gross acres, respectively, in the Barnett Shale.

(5)
Includes mineral interests and overriding royalty interests in approximately 74,504 gross acres and 29,813 gross acres, respectively, in the Bakken/Three Forks.
    Permian Basin.  The Permian Basin extends from southeastern New Mexico into west Texas and is currently one of the most active drilling regions in the United States. It includes three geologic provinces: the Midland Basin to the east, the Delaware Basin to the west, and the Central Basin in between. The Permian Basin consists of mature legacy onshore oil and liquids-rich natural gas reservoirs and has been actively drilled over the past 90 years. The extensive operating history, favorable operating environment, mature infrastructure, long reserve life, multiple producing horizons, horizontal development potential and liquids-rich reserves make the Permian Basin one of the most prolific oil-producing regions in the United States. Our acreage underlies prospective areas for the Wolfcamp play in the Midland and Delaware Basins, the Spraberry formation in the Midland Basin, and the Bone Springs formation in the Delaware Basin, which are among the most active plays in the country.

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    Mid-Continent.  The Mid-Continent is a broad area containing hundreds of fields in Arkansas, Kansas, Louisiana, New Mexico, Oklahoma, Nebraska and Texas and including the Granite Wash, Cleveland and the Mississippi Lime formations. The Anadarko Basin is a structural basin centered in the western part of Oklahoma and the Texas Panhandle, extending into southwestern Kansas and southeastern Colorado. A key feature of the Anadarko Basin is the stacked geologic horizons including the Cana-Woodford and Springer shale in the SCOOP and STACK.

    Terryville/Cotton Valley/Haynesville.  We own a substantial position in the core of the Terryville Field. Our mineral interests are leased and operated by Range Resources Corporation/Memorial Resource Development Corp. Producing since 1954, the Terryville Field is one of the most prolific natural gas fields in North America. Redevelopment of the field with horizontal drilling and modern completion techniques has resulted in high recoveries relative to drilling and completion costs, high initial production rates with high liquids yields, and long reserve life with multiple stacked producing zones.

    Eagle Ford.  The Eagle Ford shale formation stretches across South Texas and includes some of the most economic and productive areas in the United States. The Eagle Ford contains significant amounts of hydrocarbons and is considered the source rock, or the original source, for much of the oil and natural gas contained in the Austin Chalk Basin. The Eagle Ford shale formation has benefitted from improvements in horizontal drilling and hydraulic fracturing.

    Barnett Shale/Fort Worth Basin.  The Fort Worth Basin is a major petroleum producing geological system that is primarily located in north central Texas and southwestern Oklahoma. This area is best known for the Barnett Shale, which was one of the first shale plays to utilize horizontal drilling and hydraulic fracturing, and is one of the most productive sources of shale gas. In addition to the Barnett Shale, this area is also known for the Marble Falls, Mississippi Lime, Bend Conglomerate and Caddo plays.

    Bakken/Williston Basin.  The Williston Basin stretches through North Dakota, the northwest part of South Dakota, and eastern Montana and is best known for the Bakken/Three Forks shale formations. The Bakken ranks as one of the largest oil developments in the United States in the past 40 years. Development of the Bakken became commercial on a large scale over the past ten years with the advent of horizontal drilling and hydraulic fracturing.

    San Juan Basin.  The San Juan Basin is located in the Four Corners region of the southwestern United States, stretching over 4,600 square miles and encompassing much of northwestern New Mexico, southwestern Colorado and parts of Arizona and Utah. Most gas production in the basin comes from the Fruitland Coalbed Methane Play, with the remainder derived from the Mesaverde and Dakota tight gas plays. The San Juan Basin is the most productive coalbed methane basin in North America.

    Onshore California.  The majority of our mineral and royalty interests in California are in the Ventura Basin. The Ventura Basin has been active since the early 1900s and is one of the largest oil fields in California. The Ventura Basin contains multiple stacked formations throughout its depths, and a considerable inventory of existing re-development opportunities, as well as new play discovery potential.

    DJ Basin/Rockies/Niobrara.  The Denver-Julesburg Basin, also known as the DJ Basin, is a geologic basin centered in eastern Colorado stretching into southeast Wyoming, western

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      Nebraska and western Kansas. The area includes the Wattenberg Gas Field, one of the largest natural gas deposits in the United States, and the Niobrara formation. The Niobrara includes three separate zones and stretches from the DJ Basin up into the Powder River Basin in Wyoming. Development in this area is currently focused on horizontal drilling in the Niobrara and Codell formations.

    Illinois Basin.  The Illinois Basin extends across most of Illinois, Indiana, Kentucky and parts of Tennessee. The Illinois Basin is a mature area dominated by conventional oil production with some coalbed methane production. The Bridgeport, Cypress, Aux Vasses, Ste. Genevieve, Ullin, Fort Payne and New Albany are some of the formations with a current commercial focus in the Illinois Basin.

    Other.  Our other assets are primarily located in the Western Gulf (onshore) Basin and the Louisiana-Mississippi Salt Basins. The Western Gulf region ranges from South Texas through southeastern Louisiana and includes a variety of conventional and unconventional plays. The Louisiana-Mississippi Salt Basins range from northern Louisiana and southern Arkansas through south central Mississippi, southern Alabama and the Florida Panhandle.

Business Strategies

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

    Acquire additional mineral and royalty interests from our Sponsors and the Contributing Parties.  Following the completion of this offering, the Contributing Parties, including affiliates of our Sponsors, will continue to own significant mineral and royalty interests in oil and gas properties. We believe our Sponsors and the Contributing Parties view our partnership as part of their growth strategy. In addition, we believe their direct or indirect ownership in us will incentivize them to offer us additional mineral and royalty interests from their existing asset portfolios in the future. In connection with this offering and pursuant to the contribution agreement, certain of the Contributing Parties have granted us a right of first offer for a period of three years after the closing of this offering with respect to certain mineral and royalty interests in the Permian Basin, the Bakken/Williston Basin and the Marcellus Shale. These mineral and royalty interests include ownership in over 4,000 gross producing wells in 10 states. Such Contributing Parties, however, have no obligation to sell any assets to us or to accept any offer that we may make for such assets, and we may decide not to acquire such assets even if such Contributing Parties offer them to us. Please read "Certain Relationships and Related Party Transactions—Agreements and Transactions with Affiliates in Connection with this Offering—Contribution Agreement."

    Acquire additional mineral and royalty interests from third parties and leverage our relationships with our Sponsors and the Contributing Parties to grow our business.  We intend to make opportunistic acquisitions of mineral and royalty interests that have substantial resource and organic growth potential and meet our acquisition criteria, which include (i) mineral and royalty interests in high-quality producing acreage that enhance our asset base, (ii) significant amounts of recoverable oil and natural gas in

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      place with geologic support for future production and reserve growth and (iii) a geographic footprint complementary to our diverse portfolio.

      Our Sponsors and their affiliates have significant experience in identifying, evaluating and completing strategic acquisitions of mineral and royalty interests. In connection with the closing of this offering, we will enter into a management services agreement with Kimbell Operating, which will enter into separate service agreements with certain entities controlled by Messrs. R. Ravnaas, Taylor and Wynne, pursuant to which they will identify, evaluate and recommend to us acquisition opportunities and negotiate the terms of such acquisitions. We believe that these individuals' knowledge of the oil and natural gas industry, relationships within the industry and experience in identifying, evaluating and completing acquisitions will provide us opportunities to grow through strategic and accretive acquisitions that complement or expand our asset portfolio.

      We also may have opportunities to acquire mineral or royalty interests from third parties jointly with our Sponsors and the Contributing Parties. In connection with this offering and pursuant to the contribution agreement that we have entered into with our Sponsors and the Contributing Parties, we have a right to participate, at our option and on substantially the same or better terms, in up to 50% of any acquisitions, other than de minimis acquisitions, for which Messrs. R. Ravnaas, Taylor and Wynne provide, directly or indirectly, any oil and gas diligence, reserve engineering or other business services. We believe this arrangement will give us access to third-party acquisition opportunities we might not otherwise be in a position to pursue. Please read "Certain Relationships and Related Party Transactions—Agreements and Transactions with Affiliates in Connection with this Offering—Contribution Agreement."

    Benefit from reserve, production and cash flow growth through organic production growth and development of our mineral and royalty interests to grow distributions.  Our initial assets consist of diversified mineral and royalty interests. For the six months ended June 30, 2016, approximately 52.6% of our production was from the Permian Basin, Eagle Ford, Terryville/Cotton Valley/Haynesville and the Bakken/Williston Basin, which are some of the most active areas in the country. Over the long term, we expect working interest owners will continue to develop our acreage through infill drilling, horizontal drilling, hydraulic fracturing, recompletions and secondary and tertiary recovery methods. As an owner of mineral and royalty interests, we are entitled to a portion of the revenues received from the production of oil, natural gas and associated natural gas liquids from the acreage underlying our interests, net of post-production expenses and taxes. We are not obligated to fund drilling and completion costs, lease operating expenses or plugging and abandonment costs at the end of a well's productive life. As such, we benefit from the continued development of the properties we own a mineral or royalty interest in without the need for investment of additional capital by us, which we expect to increase our distributions over time.

    Maintain a conservative capital structure and prudently manage our business for the long term.  We are committed to maintaining a conservative capital structure that will afford us the financial flexibility to execute our business strategies on an ongoing basis. The limited liability company agreement of our general partner will contain provisions that prohibit certain actions without a supermajority vote of at least 662/3% of the members of the board of directors of our general partner. Among the actions requiring a supermajority vote will be the incurrence of borrowings in excess of 2.5 times our Debt to EBITDAX Ratio for the preceding four quarters and the issuance of any partnership

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      interests that rank senior in right of distributions or liquidation to our common units. Please read "The Partnership Agreement—Certain Provisions of the Agreement Governing our General Partner." We expect to enter into a $50.0 million secured revolving credit facility with an accordion feature permitting aggregate commitments under the facility to be increased up to $100.0 million (subject to the satisfaction of certain conditions and the procurement of additional commitments from new or existing lenders), which will be minimally drawn at the closing of this offering. We initially expect to use borrowings under the secured revolving credit facility for general partnership purposes, including the repayment of certain transaction expenses at the closing of this offering. We believe that this liquidity, along with internally generated cash from operations and access to the public capital markets, will provide us with the financial flexibility to grow our production, reserves and cash generated from operations through strategic acquisitions of mineral and royalty interests and the continued development of our existing assets.

Competitive Strengths

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

    Significant diversified portfolio of mineral and royalty interests in mature producing basins and exposure to undeveloped opportunities.  We have a diversified, low decline asset base with exposure to high-quality conventional and unconventional plays. As of December 31, 2015, we owned mineral and royalty interests in approximately 3.7 million gross acres and overriding royalty interests in approximately 0.9 million gross acres, with approximately 44% of our aggregate acres located in the Permian Basin. As of December 31, 2015, over 95% of the acreage subject to our mineral and royalty interests was leased to working interest owners (including 100% of our overriding royalty interests), and substantially all of those leases were held by production. As of December 31, 2015, the estimated proved oil, natural gas and natural gas liquids reserves attributable to our interests in our underlying acreage were 18,120 MBoe (52.4% liquids, consisting of 79.7% oil and 20.3% natural gas liquids) based on the reserve report prepared by Ryder Scott. Of these reserves, 70.4% were classified as PDP reserves, 0.8% were classified as PDNP reserves and 28.8% were classified as PUD reserves. PUD reserves included in this estimate are from 759 gross proved undeveloped locations. The geographic breadth of our assets gives us exposure to potential production and reserves from new and existing plays without further required investment on our behalf. We believe that we will continue to benefit from these cost-free additions to production and reserves for the foreseeable future as a result of technological advances and continuing interest by third-party producers in development activities on our acreage.

    Exposure to many of the leading resource plays in the United States.  We expect the operators of our properties to continue to drill new wells and to complete drilled but uncompleted wells on our acreage, which we believe should substantially offset the natural production declines from our existing wells. We believe that our operators have significant drilling inventory remaining on the acreage underlying our mineral or royalty interest in multiple resource plays. Our mineral and royalty interests are located in 20 states and in nearly every major onshore basin across the continental United States and include ownership in over 48,000 gross producing wells, including over 29,000 wells in the Permian Basin. For the six months ended June 30, 2016, approximately 52.6% of our production was from the Permian Basin, Eagle Ford, Terryville/Cotton

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      Valley/Haynesville and the Bakken/Williston Basin, which are some of the most active areas in the country.

    Financial flexibility to fund expansion.  Our conservative capital structure after this offering will permit us to maintain financial flexibility to allow us to opportunistically purchase strategic mineral and royalty interests, subject to the supermajority vote provisions of the limited liability company agreement of our general partner. We expect to enter into a $50.0 million secured revolving credit facility with an accordion feature permitting aggregate commitments under the facility to be increased up to $100.0 million (subject to the satisfaction of certain conditions and the procurement of additional commitments from new or existing lenders), which will be minimally drawn at the closing of this offering. Please read "Management's Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Indebtedness—New Revolving Credit Agreement" for further information. We believe that we will be able to expand our asset base through acquisitions utilizing our credit facility, internally generated cash from operations and access to the public capital markets.

    Experienced and proven management team with a track record of making acquisitions.  The members of our management team and board of directors have an average of over 30 years of oil and gas experience. Our management team and board of directors, which includes our founders, have a long history of buying mineral and royalty interests in high-quality producing acreage throughout the United States. Certain members of our management team have managed a significant investment program, investing in over 160 acquisitions. We believe we have a proven competitive advantage in our ability to source, engineer, evaluate, acquire and manage mineral and royalty interests in high-quality producing acreage.

Management

        We are managed and operated by the board of directors and executive officers of our general partner, Kimbell Royalty GP, LLC, a wholly owned subsidiary of Kimbell Holdings, which is a jointly owned subsidiary of our Sponsors. As a result of controlling our general partner, our Sponsors 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"). All three 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 connection with the closing of this offering, we will enter into a management services agreement with Kimbell Operating, which will enter into separate service agreements with certain entities controlled by Messrs. Duncan, R. Ravnaas, Taylor and Wynne, pursuant to which they and Kimbell Operating will provide management, administrative and operational services to us. In addition, under each of their respective service agreements, Messrs. R. Ravnaas, Taylor and Wynne will identify, evaluate and recommend to us acquisition opportunities and negotiate the terms of such acquisitions. Neither we, our general partner nor our subsidiaries will have any employees. Although certain of the employees that conduct our business will be employed by Kimbell Operating, we sometimes refer to these individuals in this prospectus as our employees. In addition, certain of the executive officers and directors of our general partner currently serve as executive officers or directors of our Sponsors, the Contributing Parties and

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Kimbell Operating. Please read "Management" and "Certain Relationships and Related Party Transactions."

Summary of Conflicts of Interest and Duties

        Under our partnership agreement, our general partner has a duty to manage us in a manner it believes is in, or not adverse to, our best interests. However, because our general partner is an indirect wholly owned subsidiary of our Sponsors, the officers and directors of our general partner also have a duty to manage the business of our general partner in a manner that is beneficial to Kimbell Holdings and its parents, our Sponsors. In addition, certain of our executive officers and directors will provide management, administrative and operational services to us pursuant to service agreements with Kimbell Operating. Our partnership agreement does not limit our Sponsors' or their respective affiliates' ability to compete with us and, subject to the 50% participation right included in the contribution agreement that we have entered into with our Sponsors and the Contributing Parties, neither our Sponsors nor the Contributing Parties have any obligation to present business opportunities to us. Pursuant to the limited liability company agreement of Kimbell Holdings, the right of each of Messrs. Fortson, R. Ravnaas, Taylor and Wynne (and their designated successors) to serve as a director of our general partner is conditioned upon the applicable person not competing with us, our general partner, and our and its respective subsidiaries. As a result of these relationships, conflicts of interest may arise in the future between us and our unitholders, on the one hand, and our general partner and its affiliates, including our Sponsors, on the other hand. For a more detailed description of the conflicts of interest and duties of our general partner, please read "Risk Factors—Risks Inherent in an Investment in Us" and "Conflicts of Interest and Duties."

        Delaware law provides that Delaware limited partnerships may, in their partnership agreements, expand, restrict or eliminate the fiduciary duties owed by our general partner to limited partners and the partnership. Our partnership agreement contains various provisions replacing the fiduciary duties that would otherwise be owed by our general partner with contractual standards governing the duties of our general partner and contractual methods of resolving conflicts of interest. The effect of these provisions is to restrict the remedies available to unitholders for actions taken by our general partner that might otherwise constitute breaches of its fiduciary duties. Our partnership agreement also provides that affiliates of our general partner, including Kimbell Operating and our Sponsors and their respective affiliates, are not restricted from competing with us (subject to the non-competition provision of the limited liability company agreement of Kimbell Holdings). By purchasing a common unit, the purchaser agrees to be bound by the terms of our partnership agreement, and pursuant to the terms of our partnership agreement, each holder of common units consents to various actions and potential conflicts of interest contemplated in our partnership agreement that might otherwise be considered a breach of fiduciary or other duties under Delaware law. Please read "Conflicts of Interest and Duties—Duties of Our General Partner" for a description of the fiduciary duties imposed on our general partner by Delaware law, the replacement of those duties with contractual standards under our partnership agreement and certain legal rights and remedies available to holders of our common units. For a description of our 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

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specified exemptions from reporting and other regulatory requirements that are otherwise generally applicable to other public companies. These exemptions include:

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

    an exemption from compliance with any new requirements adopted by the Public Company Accounting Oversight Board ("PCAOB"), requiring mandatory audit firm rotation or supplement to the auditor's report in which the auditor would be required to provide additional information about the audit and the financial statements of the issuer;

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

    reduced disclosure of executive compensation.

        In addition, Section 102 of the JOBS Act also provides that an emerging growth company can use the extended transition period provided in Section 7(a)(2)(B) of the Securities Act of 1933, as amended (the "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 date on which we have issued more than $1.0 billion of non-convertible debt over a three-year period; (iii) the last day of the fiscal year following the fifth anniversary of our initial public offering; or (iv) the date on which we have qualified as a "large accelerated filer," which refers to when we (w) have an aggregate worldwide market value of voting and non-voting common units held by our non-affiliates of $700 million or more, as of the last business day of our most recently completed second fiscal quarter, (x) have been subject to the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended (the "Exchange Act"), for a period of at least 12 calendar months, (y) have filed at least one annual report pursuant to Section 13(a) or 15(d) of the Exchange Act and (z) are no longer be eligible to use the requirements for "smaller reporting companies," as defined in the Exchange Act, for our annual and quarterly reports.

Risk Factors

        An investment in our common units involves a high degree of risk. You should carefully consider the risks described in "Risk Factors" and the other information in this prospectus before deciding whether to invest in our 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.

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Risks Related to Our Business

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

    The assumptions underlying the forecast of cash available for distribution that we include in "Cash Distribution Policy and Restrictions on Distributions—Estimated Cash Available for Distribution for the Twelve Months Ending December 31, 2017" are inherently uncertain and are subject to significant business, economic, financial, regulatory, environmental and competitive risks and uncertainties that could cause actual results to differ materially from those forecasted.

    The 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. We will not have a minimum quarterly distribution or employ structures intended to consistently maintain or increase distributions over time and could pay no distribution with respect to any particular quarter.

    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 acreage underlying our interests 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 business, financial condition, results of operations and cash available for distribution.

    We depend on unaffiliated operators for all of the exploration, development and production on the properties in which we own mineral and royalty interests. Substantially all of our revenue is derived from royalty payments made by these operators. A reduction in the expected number of wells to be drilled on the acreage underlying our interests by these operators or the failure of these operators to adequately and efficiently develop and operate the underlying acreage could materially adversely affect our results of operations and cash available for distribution.

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

Risks Inherent in an Investment in Us

    Our general partner and its affiliates, including our Sponsors and their respective affiliates, have conflicts of interest with us and limited duties to us and our unitholders, and they may favor their own interests to the detriment of us and our unitholders. Additionally, we have no control over the business decisions and operations of our Sponsors and their respective affiliates, which are under no obligation to adopt a business strategy that favors us.

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

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    Our partnership agreement replaces fiduciary duties applicable to a corporation with contractual duties and restricts the remedies available to holders of our common units for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty.

    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.

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

    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, the Contributing Parties and their respective affiliates and permitted transferees).

    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 may be reimbursed. The amount and timing of such reimbursements will be determined by our general partner.

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

    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.

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

Tax Risks to Common Unitholders

    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 ("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.

    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.

    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.

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Formation Transactions

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

    the Contributing Parties will contribute, directly or indirectly, certain mineral and royalty interests to us;

    we will issue an aggregate             common units, representing a         % limited partner interest in us, to the Contributing Parties;

    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 underwriting discount and structuring fee in connection with this offering and use the net proceeds from this offering in the manner described under "Use of Proceeds";

    we expect to enter into a new $50.0 million secured revolving credit facility and to borrow approximately $1.5 million at the closing of this offering to fund certain transaction expenses, as described in "Management's Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Indebtedness—New Revolving Credit Agreement"; and

    we will enter into a management services agreement with Kimbell Operating, which will enter into separate service agreements with certain entities controlled by Messrs. Duncan, R. Ravnaas, Taylor and Wynne, pursuant to which they and Kimbell Operating will provide management, administrative and operational services to us.

        We refer to these transactions collectively as the "formation transactions."

        The aggregate number of common units to be issued to the Contributing Parties 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 the Contributing Parties by the number to be purchased by the underwriters in connection with such exercise. 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 the Contributing Parties. Any common units not purchased by the underwriters pursuant to their option will be issued to the Contributing Parties 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 make a distribution to the Contributing Parties.

Principal Executive Offices

        Our principal executive offices are located at 777 Taylor Street, Suite 810, Fort Worth, Texas 76102 and our telephone number is (817) 945-9700. Our website address will be                      . 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

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the SEC. Information on our website is not incorporated by reference into this prospectus and does not constitute a part of this prospectus.

Organizational Structure After the Formation Transactions

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

GRAPHIC


(1)
The Sponsors are affiliates of our founders, Messrs. Fortson, R. Ravnaas, Taylor and Wynne.

(2)
The Contributing Parties include entities and individuals, including affiliates of our Sponsors, that are contributing, directly or indirectly, certain mineral and royalty interests to us.

(3)
Kimbell Operating will enter into separate service agreements with certain entities controlled by Messrs. Duncan, R. Ravnaas, Taylor and Wynne for the provision of certain management, administrative and operational services. In addition, the entities controlled by Messrs. R. Ravnaas, Taylor and Wynne will provide certain acquisition services to us. Please read "Certain Relationships and Related Party Transactions—Agreements and Transactions with Affiliates in Connection with this Offering—Management Services Agreements."

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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).

Option 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. 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 the Contributing Parties at the expiration of the option for no additional consideration. 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 the Contributing Parties. Any common units not purchased by the underwriters pursuant to their option will be issued to the Contributing Parties 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.

 

In addition, our general partner will own a non-economic general partner interest in us.

Use of proceeds

 

We will receive 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 structuring fee payable by us in connection with this offering. We intend to use the net proceeds of this offering to make a distribution to the Contributing Parties.

 

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 the estimated underwriting discount and structuring fee. 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 the Contributing Parties. Please read "Use of Proceeds."

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Cash distributions

 

Within 60 days after the end of each quarter, beginning with the quarter ending                      , 2017, we expect to pay distributions to unitholders of record on the applicable record date. We expect our first distribution will consist of available cash (as described below) for the period from the closing of this offering through                      , 2017.

 

Our partnership agreement requires us to distribute all of our cash on hand at the end of each quarter, less reserves established by our general partner. We refer to this cash as "available cash," and we define its meaning in our partnership agreement, in the glossary of terms attached as Appendix B and in "How We Pay Distributions." We expect that available cash for each quarter will generally equal our Adjusted EBITDA for the quarter, less cash needed for debt service and other contractual obligations and fixed charges and reserves for future operating or capital needs that the board of directors may determine is appropriate.

 

Unlike a number of other master limited partnerships, we do not currently intend to retain cash from our operations for capital expenditures necessary to replace our existing oil and natural gas reserves or otherwise maintain our asset base (replacement capital expenditures), primarily due to our expectation that the continued development of our properties and completion of drilled but uncompleted wells by working interest owners will substantially offset the natural production declines from our existing wells. The board of directors of our general partner may change our distribution policy and decide to withhold replacement capital expenditures from cash available for distribution, which would reduce the amount of cash available for distribution in the quarter(s) in which any such amounts are withheld. Over the long term, if our reserves are depleted and our operators become unable to maintain production on our existing properties and we have not been retaining cash for replacement capital expenditures, the amount of cash generated from our existing properties will decrease and we may have to reduce the amount of distributions payable to our unitholders. To the extent that we do not withhold replacement capital expenditures, a portion of our cash available for distribution will represent a return of your capital.

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It is our intent, subject to market conditions, to finance acquisitions of mineral and royalty interests that increase our asset base largely through external sources, such as borrowings under our secured revolving credit facility and the issuance of equity and debt securities, although the board of directors of our general partner may choose to reserve a portion of cash generated from operations to finance such acquisitions as well. The limited liability company agreement of our general partner will contain provisions that prohibit certain actions without a supermajority vote of at least 662/3% of the members of the board of directors of our general partner. Among the actions requiring a supermajority vote will be the reservation of a portion of cash generated from operations to finance such acquisitions. We do not currently intend to maintain excess distribution coverage for the purpose of maintaining stability or growth in our quarterly distribution or otherwise reserve cash for distributions, or to incur debt to pay quarterly distributions, although the board of directors of our general partner may change this policy.

 

Because our partnership agreement will require us to distribute an amount equal to all available cash we generate each quarter, our unitholders will have direct exposure to fluctuations in the amount of cash generated by our business. We expect that the amount of our quarterly distributions, if any, will fluctuate based on variations in, among other factors, (i) the performance of the operators of our properties, (ii) earnings caused by, among other things, fluctuations in the price of oil, natural gas and natural gas liquids, changes to working capital or capital expenditures and (iii) cash reserves deemed appropriate by the board of directors of our general partner. Such variations in the amount of our quarterly distributions may be significant and could result in our not making any distribution for any particular quarter. We will not have a minimum quarterly distribution or employ structures intended to consistently maintain or increase distributions over time.

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Based upon our forecast for the twelve months ending December 31, 2017, and assuming the board of directors of our general partner declares distributions in accordance with our initial cash distribution policy, we expect that our aggregate distributions for the twelve months ending December 31, 2017 will be approximately $              million, or $             per common unit. Please read "Cash Distribution Policy and Restrictions on Distributions—Estimated Cash Available for Distribution for the Twelve Months Ending December 31, 2017." Unanticipated events may occur which could materially adversely affect the actual results we achieve during the forecast period. Consequently, our actual results of operations, cash reserve requirements and financial condition during the forecast period may vary from the forecast, and such variations may be material. Prospective investors are cautioned not to place undue reliance on our forecast and should make their own independent assessment of our future results of operations and financial condition. In addition, the board of directors of our general partner may be required to, or may elect to, eliminate our distributions for various reasons, including reduced prices or demand for oil and natural gas. Please read "Risk Factors."

 

For a calculation of our ability to pay distributions to unitholders based on our pro forma results of operations for the year ended December 31, 2015 and the twelve months ended September 30, 2016, please read "Cash Distribution Policy and Restrictions on Distributions—Unaudited Pro Forma Cash Available for Distribution for the Year Ended December 31, 2015 and the Twelve Months Ended September 30, 2016." Our pro forma cash available for distribution generated during the year ended December 31, 2015 and the twelve months ended September 30, 2016 would have been $16.3 million and $10.9 million, respectively. However, the pro forma cash available for distribution information for the year ended December 31, 2015 and the twelve months ended September 30, 2016 that we include in this prospectus does not necessarily reflect the actual cash that would have been available for distribution with respect to each of these periods.

Subordinated units

 

None.

Incentive distribution rights

 

None.

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 Partnership Interests."

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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 completion of this offering, affiliates of our Sponsors 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) (excluding any common units purchased by officers and directors of our general partner under our directed unit program), and our Sponsors will indirectly own and control our general partner. Please read "The Partnership Agreement—Voting Rights."

Limited call right

 

If at any time our general partner and its affiliates (including our Sponsors and their respective 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 our 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,         , 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. Because of the nature of our business and the expected variability of our quarterly distributions, however, the ratio of our taxable income to distributions may vary significantly from one year to another. Please read "Material U.S. Federal Income Tax Consequences—Tax Consequences of Unit Ownership" for the basis of this estimate.

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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."

Directed unit program

 

The underwriters have reserved up to 10% of the common units being offered by this prospectus for sale at the initial public offering price to directors and officers of our general partner, the Contributing Parties and their affiliates, individuals providing services to us and certain other persons associated with us. Any purchases they do make will reduce the number of common units available to the general public. Please read "Underwriting—Directed Unit Program."

Exchange listing

 

We have been approved to list our common units on the NYSE, subject to official notice of issuance, under the symbol "KRP."

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Summary Historical and Unaudited Pro Forma Condensed Combined Financial Data

        Kimbell Royalty Partners, LP was formed in October 2015. In this prospectus, we present the historical financial statements of Rivercrest Royalties, LLC, our predecessor for accounting purposes. We refer to this entity as "our predecessor." The following table presents summary historical financial data of our predecessor and summary unaudited pro forma financial data of Kimbell Royalty Partners, LP as of the dates and for the years indicated.

        The summary historical financial data of our predecessor presented as of and for the years ended December 31, 2015 and 2014 are derived from the audited historical financial statements of our predecessor included elsewhere in this prospectus. The summary historical financial data presented as of September 30, 2016 and for the nine months ended September 30, 2016 and 2015 are derived from the unaudited historical financial statements of our predecessor included elsewhere in this prospectus.

        The summary unaudited pro forma financial data presented as of and for the nine months ended September 30, 2016 and 2015 and for the year ended December 31, 2015 are derived from our unaudited pro forma financial statements included elsewhere in this prospectus and give effect to the following transactions, which we refer to as the "pro forma formation transactions":

    The assignment by our predecessor and associated entities to certain of their affiliates of certain non-operated working interests and net profits interests that will not be contributed to us;

    Our acquisition of assets to be contributed by our predecessor and the Kimbell Art Foundation, Trunk Bay Royalty Partners, Ltd., Oil Nut Bay Royalties, LP, Gorda Sound Royalties, LP and Bitter End Royalties, LP, RCPTX, Ltd., and French Capital Partners, Ltd. (but not by the other Contributing Parties);

    The issuance by us of an aggregate of           common units to all the Contributing Parties;

    The issuance by us of             common units to the public in this offering at an assumed initial public offering price of $             per common unit, which is the mid-point of the range set forth on the cover of the prospectus;

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

    Our expected entrance into a new $50.0 million secured revolving credit facility with an accordion feature permitting aggregate commitments under the facility to be increased up to $100.0 million (subject to the satisfaction of certain conditions and the procurement of additional commitments from new or existing lenders), pursuant to which we expect to borrow approximately $1.5 million at the closing of this offering to fund certain transaction expenses; and

    Our entrance into a management services agreement with Kimbell Operating, which will enter into separate service agreements with certain entities controlled by Messrs. Duncan, R. Ravnaas, Taylor and Wynne.

        The unaudited pro forma condensed combined balance sheet as of September 30, 2016 assumes the events described above occurred as of September 30, 2016. The unaudited pro

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forma condensed combined statements of operations for the nine months ended September 30, 2016 and the year ended December 31, 2015 assume the events described above occurred as of January 1, 2015.

        We have not given pro forma effect to our acquisition of assets to be contributed by the Contributing Parties other than our predecessor, the Kimbell Art Foundation, Trunk Bay Royalty Partners, Ltd., Oil Nut Bay Royalties, LP, Gorda Sound Royalties, LP and Bitter End Royalties, LP, RCPTX, Ltd., and French Capital Partners, Ltd., which excluded assets represent approximately 25% of our future undiscounted cash flows, based on the reserve report prepared by Ryder Scott as of December 31, 2015.

        We have not given pro forma effect to incremental general and administrative expenses of approximately $1.5 million that we expect to incur annually as a result of operating as a publicly traded partnership, such as expenses associated with SEC reporting requirements, including annual and quarterly reports to unitholders, tax return and Schedule K-1 preparation and distribution expenses, Sarbanes-Oxley Act compliance expenses, expenses associated with listing on the NYSE, independent auditor fees, independent reserve engineer fees, legal fees, investor relations expenses, registrar and transfer agent fees, director and officer insurance expenses and director and officer compensation expenses.

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

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

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  Kimbell Royalty
Partners, LP
Pro Forma
  Predecessor Historical  
 
   
   
  Nine
Months
Ended
September 30,
   
   
 
 
  Nine
Months
Ended
September 30,
2016
   
  Year Ended
December 31,
 
 
  Year Ended
December 31,
2015
 
 
  2016   2015   2015   2014  

Statement of Operations Data:

                                     

Revenue:

                                     

Oil, natural gas and NGL revenues

  $ 15,354,458   $ 26,691,028   $ 2,572,477   $ 3,670,930   $ 4,684,923   $ 7,219,822  

Cost and expenses:

                                     

Production and ad valorem taxes

    1,284,194     2,199,404     203,567     214,150     426,885     568,327  

Depreciation, depletion and accretion expense

    9,586,455     18,164,181     1,244,023     2,969,502     4,008,730     4,044,802  

Impairment of oil and natural gas properties

    4,982,739     27,749,669     4,992,897     25,796,352     28,673,166     7,416,747  

Marketing and other deductions

    1,247,964     1,271,104     570,521     590,637     747,264     526,727  

General and administrative expenses

    3,659,341     5,079,796     1,252,001     1,127,926     1,789,884     1,757,377  

Total costs and expenses

    20,760,693     54,464,154     8,263,009     30,698,567     35,645,929     14,313,980  

Operating loss

    (5,406,235 )   (27,773,126 )   (5,690,532 )   (27,027,637 )   (30,961,006 )   (7,094,158 )

Interest expense

    227,737     308,343     314,081     282,372     385,119     302,118  

Loss before income taxes

    (5,633,972 )   (28,081,469 )   (6,004,613 )   (27,310,009 )   (31,346,125 )   (7,396,276 )

State income taxes

            13,401     11,557     (32,199 )   16,970  

Net income (loss)

  $ (5,633,972 ) $ (28,081,469 ) $ (6,018,014 ) $ (27,321,566 ) $ (31,313,926 ) $ (7,413,246 )

Statement of Cash Flows Data:

                                     

Net cash provided by (used in):

                                     

Operating activities

              $ 956,793   $ 2,317,594   $ 2,713,133   $ 4,038,018  

Investing activities

              $ (93,899 ) $ (503,989 ) $ (538,640 ) $ (53,463,030 )

Financing activities

              $ (563,000 ) $ (1,762,973 ) $ (2,062,818 ) $ 39,645,738  

Other Financial Data:

                                     

Adjusted EBITDA (1)

  $     $     $ 1,000,183   $ 2,192,012   $ 2,325,949   $ 4,518,656  

Selected Balance Sheet Data:

                                     

Cash and cash equivalents

  $           $ 679,635   $ 318,698   $ 379,741   $ 268,066  

Total assets

  $           $ 20,784,733   $ 30,753,412   $ 27,905,790   $ 58,753,888  

Long-term debt

  $     $     $ 10,898,860   $ 10,998,860   $ 11,448,860   $ 9,003,860  

Total liabilities

  $           $ 12,109,530   $ 12,672,894   $ 13,666,368   $ 10,556,272  

Members' equity

  $           $ 8,675,203   $ 18,080,518   $ 14,239,422   $ 48,197,616  

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

Non-GAAP Financial Measures

Adjusted EBITDA

        Adjusted EBITDA is used as a supplemental non-GAAP financial measure by management and external users of our financial statements, such as industry analysts, investors, lenders and rating agencies. We believe Adjusted EBITDA is useful because it allows us to more effectively evaluate our operating performance and compare the results of our operations period to period

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without regard to our financing methods or capital structure. In addition, management uses Adjusted EBITDA to evaluate cash flow available to pay distributions to our unitholders.

        We define Adjusted EBITDA as net income (loss) plus interest expense, net of capitalized interest, non-cash unit-based compensation, impairment of oil and natural gas properties, income taxes and depreciation, depletion and accretion expense. Adjusted EBITDA is not a measure of net income (loss) or net cash provided by operating activities as determined by GAAP. We exclude the items listed above from net income (loss) in arriving at Adjusted EBITDA because these amounts can vary substantially from company to company within our industry depending upon accounting methods and book values of assets, capital structures and the method by which the assets were acquired. Certain items excluded from Adjusted EBITDA are significant components in understanding and assessing a company's financial performance, such as a company's cost of capital and tax structure, as well as historic costs of depreciable assets, none of which are components of Adjusted EBITDA.

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

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

 
  Kimbell Royalty
Partners, LP
Pro Forma
  Predecessor Historical  
 
   
   
  Nine
Months
Ended
September 30,
   
   
 
 
  Nine
Months
Ended
September 30,
2016
   
  Year Ended
December 31,
 
 
  Year Ended
December 31,
2015
 
 
  2016   2015   2015   2014  

Net income (loss)

  $ (5,633,972 ) $ (28,081,469 ) $ (6,018,014 ) $ (27,321,566 ) $ (31,313,926 ) $ (7,413,246 )

Depreciation, depletion and accretion expenses

    9,586,455     18,164,181     1,244,023     2,969,502     4,008,730     4,044,802  

Interest expense

    227,737     308,343     314,081     282,372     385,119     302,118  

Income taxes

            13,401     11,557     (32,199 )   16,970  

EBITDA

    4,180,220     (9,608,945 )   (4,446,509 )   (24,058,135 )   (26,952,276 )   (3,049,356 )

Impairment of oil and natural gas properties

    4,982,739     27,749,669     4,992,897     25,796,352     28,673,166     7,416,747  

Unit-based compensation

                453,795     453,795     605,059     151,265  

Adjusted EBITDA

  $     $     $ 1,000,183   $ 2,192,012   $ 2,325,949   $ 4,518,656  

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  Predecessor Historical  
 
  Nine
Months
Ended
September 30,
  Year Ended
December 31,
 
 
  2016   2015   2015   2014  

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

                         

Net cash provided by operating activities

  $ 956,793   $ 2,317,594   $ 2,713,133   $ 4,038,018  

Interest expense

    314,081     282,372     385,119     302,118  

State income taxes

    13,401     11,557     (32,199 )   16,970  

Impairment of oil and natural gas properties

    (4,992,897 )   (25,796,352 )   (28,673,166 )   (7,416,747 )

Amortization of loan origination costs

    (34,245 )   (30,724 )   (40,965 )   (34,916 )

Amortization of tenant improvement allowance

    25,777         14,321      

Unit-based compensation

    (453,795 )   (453,795 )   (605,059 )   (151,265 )

Changes in operating assets and liabilities:

                         

Oil, natural gas and NGL revenues receivable

    (11,258 )   (377,448 )   (464,877 )   373,644  

Other receivables

    (1,246,269 )   600,579     1,371,540      

Other current assets

            (6,441 )   (72,742 )

Accounts payable

    1,071,453     (568,430 )   (1,604,999 )   (77,152 )

Other current liabilities

    (89,550 )   (43,488 )   (8,683 )   (27,284 )

EBITDA

  $ (4,446,509 ) $ (24,058,135 ) $ (26,952,276 ) $ (3,049,356 )

Add:

                         

Impairment of oil and natural gas properties            

    4,992,897     25,796,352     28,673,166     7,416,747  

Unit-based compensation

    453,795     453,795     605,059     151,265  

Adjusted EBITDA

  $ 1,000,183   $ 2,192,012   $ 2,325,949   $ 4,518,656  

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Summary Reserve Data

        The following table presents our estimated proved oil and natural gas reserves as of December 31, 2015 based on the reserve report prepared by Ryder Scott. The reserve report was prepared in accordance with the rules and regulations of the SEC. You should refer to "Risk Factors—Risks Related to Our Business—"Our estimated reserves are based on many assumptions that may prove to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves" and the other risks set forth in "Risk Factors," "Business—Oil and Natural Gas Data—Proved Reserves," "Business—Oil and Natural Gas Production Prices and Production Costs—Production and Price History" and "Management's Discussion and Analysis of Financial Condition and Results of Operations" in evaluating the material presented below.

 
  December 31,
2015 (1)
 

Estimated proved developed reserves:

       

Oil (MBbls)

    5,336  

Natural gas (MMcf)

    35,910  

Natural gas liquids (MBbls)

    1,575  

Total (MBoe)(6:1) (2)

    12,896  

Estimated proved undeveloped reserves:

       

Oil (MBbls)

    2,237  

Natural gas (MMcf)

    15,808  

Natural gas liquids (MBbls)

    352  

Total (MBoe)(6:1) (2)

    5,224  

Estimated proved reserves:

       

Oil (MBbls)

    7,573  

Natural gas (MMcf)

    51,718  

Natural gas liquids (MBbls)

    1,927  

Total (MBoe)(6:1) (2)

    18,120  

Percent proved developed

    71 %

(1)
Estimates of reserves as of December 31, 2015 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, 2015, in accordance with SEC guidelines applicable to reserve estimates as of the end of such period. The unweighted arithmetic average first day of the month prices were $50.28 per Bbl for oil and $2.59 per MMBtu for natural gas at December 31, 2015. 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 net revenue interest in our properties. Although we believe these estimates are reasonable, actual future production, cash flows, taxes, development expenditures, production costs and quantities of recoverable oil and natural gas reserves may vary substantially from these estimates.

(2)
Estimated proved reserves are presented on an oil-equivalent basis using a conversion of six Mcf per barrel of "oil equivalent." This conversion is based on energy equivalence and not price or value equivalence. If a price equivalent conversion based on the twelve-month average prices for the year ended December 31, 2015 was used, the conversion factor would be approximately 19.4 Mcf per Bbl of oil. In this prospectus, we supplementally provide "value-equivalent" production information or volumes presented on an oil-equivalent basis using a conversion factor of 20 Mcf of natural gas per barrel of "oil equivalent," which is the conversion factor we use in our business. For a discussion of the 20-to-1 conversion factor, please read footnote 3 to the Mineral Interests table under "Business—Our Properties—Material Basins and Producing Regions—Mineral Interests."

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Summary Production Data

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

 
  Nine Months
Ended
September 30,
2016
  Year Ended
December 31,
2015
  Year Ended
December 31,
2014
 

Predecessor Production Data:

                   

Oil and condensate (Bbls)

    41,548     59,321     50,570  

Natural gas (Mcf)

    343,078     548,386     515,130  

Natural gas liquids (Bbls)

    17,458     22,351     17,991  

Total (Boe)(6:1) (1)

    116,186     173,070     154,416  

Average daily production (Boe/d)(6:1)

    424     474     423  

Predecessor Average Realized Prices:

                   

Oil and condensate (per Bbl)

  $ 38.11   $ 49.79   $ 87.25  

Natural gas (per Mcf)

  $ 2.14   $ 2.44   $ 4.22  

Natural gas liquids (per Bbl)

  $ 14.56   $ 17.56   $ 35.26  

Predecessor Average Unit Cost per Boe (6:1)

                   

Production and ad valorem taxes

  $ 1.75   $ 2.47   $ 3.68  

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

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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 pay 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 December 31, 2017 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 December 31, 2017—Assumptions and Considerations." If our price or production assumptions prove to be inaccurate, our actual distributions for the twelve months ending December 31, 2017 may be significantly lower than our forecasted distributions and we may not be able to pay a distribution at all. Substantially all of the cash we have to distribute each quarter depends upon the amount of oil, natural gas and natural gas liquids revenues we generate, which is dependent upon the prices that the operators of our properties realize from the sale of oil and natural gas production. In addition, the actual amount of our available cash we will have to distribute each quarter will be reduced by replacement capital expenditures we make, payments in respect of our debt instruments and other contractual obligations, general and administrative expenses and fixed charges and reserves for future operating or capital needs that the board of directors may determine are appropriate.

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

The assumptions underlying the forecast of cash available for distribution that we include in "Cash Distribution Policy and Restrictions on Distributions—Estimated Cash Available for Distribution for the Twelve Months Ending December 31, 2017" are inherently uncertain and are subject to significant business, economic, financial, regulatory, environmental and competitive risks and uncertainties that could cause actual results to differ materially from those forecasted.

        The forecast of cash available for distribution set forth in "Cash Distribution Policy and Restrictions on Distributions—Estimated Cash Available for Distribution for the Twelve Months Ending December 31, 2017" includes our forecast of results of operations, Adjusted EBITDA and cash available for distribution for the twelve months ending December 31, 2017. We estimate that our total cash available for distribution for the twelve months ending December 31, 2017 will be approximately $24.6 million, as compared to approximately $16.3 million for the year ended December 31, 2015 and approximately $10.9 million for the twelve months ended

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September 30, 2016, respectively, on a pro forma basis. The forecast has been prepared by our management. Neither our independent registered public accounting firm nor any other independent registered public accounting firm has compiled, examined or performed any procedures with respect to the forecast, expressed any opinion or given any other form of assurance on such information or its achievability or assumed any responsibility for the forecast. The assumptions underlying the forecast are inherently uncertain and are subject to significant business, economic, financial, regulatory, environmental and competitive risks and uncertainties that could cause actual results to differ materially from those forecasted. If the forecasted results are not achieved, we would not be able to pay the forecasted annual distribution, in which event the market price of our common units may decline materially. Our actual results may differ materially from the forecasted results presented in this prospectus. Investors should review the forecast of our results of operations for the twelve months ending December 31, 2017 together with the other information included elsewhere in this prospectus, including "Risk Factors" and "Management's Discussion and Analysis of Financial Condition and Results of Operations." The pro forma available cash information for the year ended December 31, 2015 and for the twelve months ended September 30, 2016 do not reflect the actual cash that we would have generated over the course of those periods.

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 paying 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. For example, we may have significant capital expenditures in the future. While these items may not affect our profitability in a quarter, they would reduce the amount of cash available for distribution with respect to such quarter. As a result, we may pay cash distributions during periods in which we record net losses for financial accounting purposes and may be unable to pay cash distributions during periods in which we record net income.

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

        Kimbell Royalty Partners, LP was formed in October 2015. Our predecessor, Rivercrest Royalties, LLC, was formed in October 2013. We do not have historical financial statements with respect to our mineral and royalty interests for periods prior to their acquisition by the Contributing Parties. As a result, with respect to some of our assets, there is only limited historical financial information available upon which to base your evaluation of our performance.

The amount of our quarterly cash distributions, if any, may vary significantly both quarterly and annually and will be directly dependent on the performance of our business. We will not have a minimum quarterly distribution or employ structures intended to consistently maintain or increase distributions over time and could pay no distribution with respect to any particular quarter.

        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. 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 acreage underlying our interests is sold, and we do not currently hedge these commodity prices. The volatility of these prices due to factors beyond our control

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greatly affects our business, financial condition, results of operations and cash available for distribution." We will not have a minimum quarterly distribution or employ structures intended to consistently maintain or increase distributions over time. 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 will vary significantly from quarter to quarter and may be zero. Please read "Cash Distribution Policy and Restrictions on Distributions."

Our partnership agreement requires that we distribute all of our available cash, which could limit our ability to grow and make acquisitions.

        Our partnership agreement requires that we distribute all of our available cash each quarter. As a result, we will have limited cash available to reinvest in our business or to fund acquisitions, and we will rely primarily upon external financing sources, including commercial bank borrowings and the issuance of debt and equity securities, to fund our acquisitions and growth capital expenditures. As such, to the extent we are unable to finance growth externally, our distribution policy will significantly impair our ability to grow.

        To the extent we issue additional units in connection with any acquisitions or growth capital expenditures or as in-kind distributions, 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 in right of distributions or liquidation to our common units. The incurrence of commercial borrowings or other debt to finance our growth strategy would result in increased interest expense, which, in turn, would reduce the available cash that we have to distribute to our unitholders. Please read "Cash Distribution Policy and Restrictions on Distributions."

The limited liability company agreement of our general partner will contain restrictive covenants, governance and other provisions that may restrict our ability to pursue our business strategies.

        The limited liability company agreement of our general partner, which will be controlled by our Sponsors, will contain provisions that prohibit certain actions without a supermajority vote of at least 662/3% of the members of the board of directors of our general partner, including:

    the incurrence of borrowings in excess of 2.5 times our Debt to EBITDAX Ratio for the preceding four quarters;

    the reservation of a portion of cash generated from operations to finance acquisitions;

    modifications to the definition of "Available Cash" in our partnership agreement; and

    the issuance of any partnership interests that rank senior in right of distributions and liquidation to our common units.

        Please read "The Partnership Agreement—Certain Provisions of the Agreement Governing our General Partner."

        Upon the closing of this offering, the board of directors of our general partner will have nine members. Therefore, the vote of four directors would be sufficient to prevent us from

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undertaking the items discussed above. These restrictions may limit our ability to obtain future financings and acquire additional oil and gas properties. We may also be prevented from taking advantage of business opportunities that arise because of the limitations that these restrictions impose on us. Our inability to execute financings or acquire additional properties may materially adversely affect our results of operations and cash available for distribution.

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 acreage underlying our interests 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 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, natural gas and natural gas liquids. Historically, oil, natural gas and natural gas liquids prices have been volatile and are subject to fluctuations in response to changes in supply and demand, market uncertainty and a variety of additional factors that are beyond our control, including:

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

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

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

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

    the price and quantity of foreign imports;

    the level of U.S. domestic production;

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

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

    the ability of Iran to increase the export of oil and natural gas upon the relaxation of international sanctions;

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

    the level of consumer product demand;

    weather conditions and other natural disasters;

    risks associated with operating drilling rigs;

    technological advances affecting energy consumption;

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    domestic and foreign governmental regulations and taxes;

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

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

    the price and availability of alternative fuels; and

    overall domestic and global economic conditions.

        These factors and the volatility of the energy markets make it extremely difficult to predict future oil and natural gas price movements with any certainty. For example, during the past five years, the posted price for West Texas Intermediate light sweet crude oil, which we refer to as West Texas Intermediate ("WTI"), has ranged from a low of $26.19 per Bbl in February 2016 to a high of $113.93 per Bbl in April 2011, and the Henry Hub spot market price of natural gas has ranged from a low of $1.49 per MMBtu in March 2016 to a high of $7.63 per MMBtu in February 2014. On September 30, 2016, the WTI posted price for crude oil was $48.24 per Bbl and the Henry Hub spot market price of natural gas was $2.84 per MMBtu. Additionally, natural gas liquids prices have declined from approximately $29.46 Boe in January 2015 to $28.65 Boe in August 2016. The reduction in prices has been caused by many factors, including increases in oil and natural gas production and reserves from unconventional (shale) reservoirs, without an offsetting increase in demand, as well as actions by the Organization of Petroleum Exporting Countries to maintain or raise production levels. The International Energy Agency forecasts continued low global demand growth in 2017. This environment could cause prices to remain at current levels or to fall to lower levels. Any substantial decline in the price of oil, natural gas and natural gas liquids or prolonged period of low commodity prices will materially adversely affect our business, financial condition, results of operations and cash available for distribution.

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

        Accounting rules require that we periodically review the carrying value of our properties for possible impairment. Based on specific market factors and circumstances at the time of prospective impairment reviews, and the continuing evaluation of development plans, production data, economics and other factors, we may be required to write down the carrying value of our properties. The net capitalized costs of proved oil and natural gas properties are subject to a full cost ceiling limitation for which the costs are not allowed to exceed their related estimated future net revenues discounted at 10%. To the extent capitalized costs of evaluated oil and natural gas properties, net of accumulated depreciation, depletion, amortization and impairment, exceed estimated discounted future net revenues of proved oil and natural gas reserves, the excess capitalized costs are charged to expense. The risk that we will be required to recognize impairments of our oil and natural gas properties increases during periods of low commodity prices. In addition, impairments would occur if we were to experience sufficient downward adjustments to our estimated proved reserves or the present value of estimated future net revenues. An impairment recognized in one period may not be reversed in a subsequent period even if higher oil and gas prices increase the cost center ceiling applicable to the subsequent period. During the nine months ended September 30, 2016 and the years ended December 31, 2015 and December 31, 2014, our predecessor recorded non-cash impairment charges of approximately $5.0 million, $28.7 million and $7.4 million, respectively, primarily

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due to changes in reserve values resulting from the drop in commodity prices and other factors. We may incur impairment charges in the future, which could materially adversely affect our results of operations for the periods in which such charges are taken.

We 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 price of oil, natural gas and natural gas liquids.

        We have not entered into hedging arrangements to establish, in advance, a price for the sale of the oil, natural gas and natural gas liquids produced from our properties, and we may not enter into such arrangements in the future. As a result, although we may realize the benefit of any short-term increase in the price of oil, natural gas and natural gas liquids, we will not be protected against decreases in the price of oil, natural gas and natural gas liquids or prolonged periods of low commodity prices, which could materially adversely affect our business, results of operation and cash available for distribution.

In the future, we may enter into hedging transactions, which may not be effective in reducing the volatility of our cash flows.

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

We depend on unaffiliated operators for all of the exploration, development and production on the properties in which we own mineral and royalty interests. Substantially all of our revenue is derived from royalty payments made by these operators. A reduction in the expected number of wells to be drilled on the acreage underlying our interests by these operators or the failure of these operators to adequately and efficiently develop and operate the underlying acreage could materially adversely affect our results of operations and cash available for distribution.

        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. As of December 31, 2015, we received revenue from over 700 operators. On a pro forma basis for the year ended December 31, 2015 and for the nine months ended September 30, 2016, we received approximately 53.3% and 49.0% of our revenue from the top ten operators of our properties, respectively. If these operators do not adequately and efficiently perform operations or act in ways that are beneficial to us, our production and revenues could decline. The operators of our properties are often not obligated to undertake any development activities. In the absence of a specific contractual obligation, any development and production activities will be subject to their sole discretion (subject, however, to certain implied obligations to develop

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imposed by state law). The operators of our properties could determine to drill and complete fewer wells on our acreage than we currently expect. The success and timing of drilling and development activities on our properties, and whether the operators elect to drill any additional wells on our acreage, depends on a number of factors that will be largely outside of our control, including:

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

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

    prevailing commodity prices;

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

    the operators' expertise, operating efficiency and financial resources;

    approval of other participants in drilling wells;

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

    the selection of technology;

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

    the rate of production of the reserves.

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

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

        As of December 31, 2015, 28.8% of our total estimated proved reserves were proved undeveloped reserves and may not be ultimately developed or produced by the operators of our properties. Recovery of proved undeveloped reserves requires significant capital expenditures and successful drilling operations by the operators of our properties. The reserve data included in the reserve report of our independent petroleum engineer assume that substantial capital expenditures by the operators of our properties are required to develop such reserves. We typically do not have access to the estimated costs of development of these reserves or the scheduled development plans of our operators. We take into consideration the estimated costs of development or the scheduled development plans from any development provisions in the relevant lease agreement and the historical drilling activity, rig locations, production data and

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permit trends, as well as investor presentations and other public statements of our operators. The development of such reserves may take longer and may require higher levels of capital expenditures from the operators than we anticipate. Delays in the development of our reserves, increases in costs to drill and develop such reserves or decreases or continued volatility in commodity prices will reduce the future net revenues of our estimated proved undeveloped reserves and may result in some projects becoming uneconomical for the operators of our properties. In addition, delays in the development of reserves could force us to reclassify certain of our proved reserves as unproved reserves.

We may not be able to terminate our leases if any of the operators of the properties in which we own mineral interests declare bankruptcy, and we may experience delays and be unable to replace operators that do not make royalty payments.

        A failure on the part of the operators of the properties in which we own mineral interests to make royalty payments typically gives us the right to terminate the lease, repossess the property and enforce payment obligations under the lease. If we repossessed any of the properties in which we own mineral interests, we would seek a replacement operator. However, we might not be able to find a replacement operator and, if we did, we might not be able to enter into a new lease on favorable terms within a reasonable period of time. In addition, the outgoing operator could be subject to bankruptcy proceedings that could prevent the execution of a new lease or the assignment of the existing lease to another operator. In addition, if we enter into a new lease, the replacement operator may not achieve the same levels of production or sell oil, natural gas or natural gas liquids at the same price as the operator it replaced.

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

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

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

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

    recoverable reserves;

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

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    development plans;

    operating costs; and

    potential environmental and other liabilities.

        The accuracy of these assessments is inherently uncertain and we may not be able to identify attractive acquisition opportunities. In connection with these assessments, we perform a review of the subject properties that we believe to be generally consistent with industry practices, given the nature of our interests. Our review will not reveal all existing or potential problems nor will it permit us to become sufficiently familiar with the properties to assess fully their deficiencies and capabilities. Inspections are often not performed on every well, and environmental problems, such as groundwater contamination, are not necessarily observable even when an inspection is undertaken. Even when problems are identified, the seller may be unwilling or unable to provide effective contractual protection against all or part of the problems. Even if we do identify attractive acquisition opportunities, we may not be able to complete the acquisition or do so on commercially acceptable terms. Unless our operators further develop our existing properties, we will depend on acquisitions to grow our reserves, production and cash flow.

        There is intense competition for acquisition opportunities in our industry. Competition for acquisitions may increase the cost of, or cause us to refrain from, completing acquisitions. Our ability to complete acquisitions is dependent upon, among other things, our ability to obtain debt and equity financing and, in some cases, regulatory approvals. Further, these acquisitions may be in geographic regions in which we do not currently hold assets, which could result in unforeseen operating difficulties. In addition, if we acquire interests in new states, we may be subject to additional and unfamiliar legal and regulatory requirements. Compliance with regulatory requirements may impose substantial additional obligations on us and our management, cause us to expend additional time and resources in compliance activities and increase our exposure to penalties or fines for non-compliance with such additional legal requirements. Further, the success of any completed acquisition will depend on our ability to integrate effectively the acquired business into our existing business. The process of integrating acquired businesses may involve unforeseen difficulties and may require a disproportionate amount of our managerial and financial resources. In addition, possible future acquisitions may be larger and for purchase prices significantly higher than those paid for earlier acquisitions.

        No assurance can be given that we will be able to identify suitable acquisition opportunities, negotiate acceptable terms, obtain financing for acquisitions on acceptable terms or successfully acquire identified targets. Our failure to minimize any unforeseen difficulties could materially adversely affect our financial condition and cash available for distribution. The inability to effectively manage these acquisitions could reduce our focus on subsequent acquisitions, which, in turn, could negatively impact our growth and cash available for distribution.

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

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

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

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

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

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

    mistaken assumptions about the overall cost of equity or debt;

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

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

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

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

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

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

        Project areas on our properties are in various stages of development, ranging from project areas with current drilling or production activity to project areas that have limited drilling or production history. If the wells in the process of being completed do not produce sufficient revenues or if dry holes are drilled, our financial condition, results of operations and cash available for distribution may be materially adversely affected.

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

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

        Our historical estimates of proved reserves and related valuations as of December 31, 2015 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 and changes in prices. Some of our reserve estimates were made without the benefit of a lengthy production history, which are less reliable than estimates based on a lengthy production history. In estimating our reserves, we and our reserve engineers make certain assumptions that may prove to be incorrect, including assumptions regarding future oil and natural gas prices, production levels and operating and development costs. Any significant variance from these assumptions to actual figures could greatly affect our estimates of reserves, the economically recoverable quantities of oil and natural gas attributable to any particular group of properties, the classifications of reserves based on risk of recovery and estimates of future net cash flows. Numerous changes over time to the assumptions on which our reserve estimates are based, as described above, often result in the actual quantities of oil and natural gas that are ultimately recovered being different from our reserve estimates.

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

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

        SEC rules require that, subject to limited exceptions, proved undeveloped reserves may only be booked if they relate to wells scheduled to be drilled within five years after the date of booking. This requirement has limited and may continue to limit our ability to book additional proved undeveloped reserves as the operators of our properties pursue their drilling programs. Moreover, we may be required to write down our proved undeveloped reserves if those wells are not drilled within the required five-year timeframe. Furthermore, we typically do not have access to the drilling schedules of our operators and make our determinations about their estimated drilling schedules from any development provisions in the relevant lease agreement and the historical drilling activity, rig locations, production data and permit trends, as well as investor presentations and other public statements of our operators.

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

        Upon completion of this offering, we expect to enter into a $50.0 million secured revolving credit facility with an accordion feature permitting aggregate commitments under the facility to be increased up to $100.0 million (subject to the satisfaction of certain conditions and the procurement of additional commitments from new or existing lenders). Our secured revolving credit facility will be secured by substantially all of our assets. We expect our secured revolving credit facility will contain various covenants and restrictive provisions that will limit our ability to, among other things:

    incur or guarantee additional debt;

    make distributions on, or redeem or repurchase, common units, including if an event of default or borrowing base deficiency exists;

    make certain investments and acquisitions;

    incur certain liens or permit them to exist;

    enter into certain types of transactions with affiliates;

    merge or consolidate with another company; and

    transfer, sell or otherwise dispose of assets.

        We expect our secured revolving credit facility will also contain covenants requiring us to maintain the following financial ratios or to reduce our indebtedness if we are unable to comply with such ratios: (i) a Debt to EBITDAX Ratio (as more fully defined in the secured revolving credit facility) of not more than 4.0 to 1.0; and (ii) a ratio of current assets to current liabilities of not less than 1.0 to 1.0. Our ability to meet those financial ratios and tests can be affected by events beyond our control. These restrictions may also limit our ability to obtain future financings to withstand a future downturn in our business or the economy in general, or to otherwise conduct necessary corporate activities. We may also be prevented from taking advantage of business opportunities that arise because of the limitations that the restrictive covenants under our secured revolving credit facility will impose on us.

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

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

        We further anticipate that our secured revolving credit facility will limit the amounts we can borrow up to a borrowing base amount, which the lenders, in their sole discretion, determine on a semi-annual basis based upon projected revenues from the oil and natural gas properties securing our loan. The borrowing base will be determined based on our oil and gas properties and the oil and gas properties of our wholly owned subsidiaries. We expect to have non-wholly owned subsidiaries whose assets are not subject to a lien and not included in borrowing base valuations. The lenders can unilaterally adjust the borrowing base and the borrowings permitted to be outstanding under our secured revolving credit facility. Any increase in the borrowing base requires the consent of the lenders holding 100% of the commitments. If the requisite number of lenders do not agree to an increase, then the borrowing base will be the lowest borrowing base acceptable to such lenders. Decreases in the available borrowing amount could result from declines in oil and natural gas prices, operating difficulties or increased costs, declines in reserves, lending requirements or regulations or certain other circumstances. Outstanding borrowings in excess of the borrowing base must be repaid, or we must pledge other oil and natural gas properties as additional collateral after applicable grace periods. We do not expect to have any substantial unpledged properties, and we may not have the financial resources in the future to make mandatory principal prepayments required under our secured revolving credit facility.

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

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

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

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

    our access to the capital markets may be limited;

    our borrowing costs may increase;

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

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

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

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

        Producing oil and natural gas wells are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Our future oil and natural gas reserves and the operators' production thereof and our cash generated from operations and ability to pay distributions are highly dependent on the successful development and exploitation of our current reserves. Based on our reserve report as of December 31, 2015, the average estimated five-year decline rate for our existing proved developed producing reserves is 10%. However, the production decline rates of our properties may be significantly higher than currently estimated if the wells on our properties do not produce as expected. We may also not be able to acquire additional reserves to replace the current and future production of our properties at economically acceptable terms, which could materially adversely affect our business, financial condition, results of operations and cash available for distribution.

        We are unlikely to be able to sustain or increase distributions without making accretive acquisitions or capital expenditures that maintain or grow our asset base. We will need to make substantial capital expenditures to maintain and grow our asset base, which will reduce our cash available for distribution. We do not intend to retain cash from our operations for replacement capital expenditures primarily due to our expectation that the continued development of our properties and completion of drilled but uncompleted wells by working interest owners will substantially offset the natural production declines from our existing wells. Please read "Cash Distribution Policy and Restrictions on Distributions."

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

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

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

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

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

        Many key responsibilities within our business have been assigned to a small number of individuals. We rely on our founders for their knowledge of the oil and natural gas industry, relationships within the industry and experience in identifying, evaluating and completing acquisitions. In connection with the closing of this offering, we will enter into a management services agreement with Kimbell Operating, which will enter into separate service agreements

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with certain entities controlled by Messrs. Duncan, R. Ravnaas, Taylor and Wynne, pursuant to which they and Kimbell Operating will provide management, administrative and operational services to us. In addition, under each of their respective service agreements, Messrs. R. Ravnaas, Taylor and Wynne will identify, evaluate and recommend to us acquisition opportunities and negotiate the terms of such acquisitions. The loss of their services, or the services of one or more members of our executive team or those providing services to us pursuant to a contract, could materially adversely affect our business. Further, we do not maintain "key person" life insurance policies on any of our executive team or other key personnel. As a result, we are not insured against any losses resulting from the death of these key individuals.

Increased costs of capital could materially adversely affect our business.

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

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

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

A terrorist attack or armed conflict could harm our business.

        Terrorist activities, anti-terrorist activities and other armed conflicts involving the United States or other countries may adversely affect the United States and global economies. If any of these events occur, the resulting political instability and societal disruption could reduce overall demand for oil and natural gas, potentially putting downward pressure on demand for our 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 if infrastructure integral to our operators is destroyed or damaged, they may experience a significant disruption in their operations. Any such disruption could materially adversely affect our financial condition, results of operations and cash available for distribution.

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

        We may not elect to incur the expense of retaining lawyers to examine the title to the mineral interest. Rather, we may rely upon the judgment of oil and gas lease brokers or landmen who perform the fieldwork in examining records in the appropriate governmental office before attempting to acquire a lease in a specific mineral interest. The existence of a material title deficiency can render an interest worthless and can materially adversely affect our results of

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operations, financial condition and cash available for distribution. No assurance can be given that we will not suffer a monetary loss from title defects or title failure. Additionally, undeveloped acreage has greater risk of title defects than developed acreage. If there are any title defects or defects in assignment of leasehold rights in properties in which we hold an interest, we will suffer a financial loss.

The Contributing Parties will have limited indemnity obligations to us for liabilities arising out of the ownership and operation of our assets prior to the closing of this offering, including title defects.

        In connection with this offering, we have entered into a contribution agreement with the Contributing Parties that will govern, among other things, their obligation to indemnify us for certain liabilities associated with the entities and assets being contributed to us in connection with this offering. Under the contribution agreement, the Contributing Parties will be required, severally but not jointly, to indemnify us (i) for a period of one year following the closing of this offering, for breaches of specified representations and warranties related to, among other things, (x) their authority to enter into the transactions contemplated by the contribution agreement and (y) the capitalization of the entities that will be contributed to us; and (ii) for any federal, state and local income tax liabilities attributable to the ownership and operation of the mineral and royalty interests and the associated entities prior to the closing of this offering until 30 days after the applicable statute of limitations. In addition, pursuant to the contribution agreement, the Contributing Parties will, severally but not jointly, indemnify us for losses arising from certain liens and title defects created during their ownership of the entities and assets contributed to us in connection with this offering.

        Except as otherwise described above, the Contributing Parties are not required to indemnify us for breaches of any other representations and warranties under the contribution agreement, including breaches related to other title matters, consents and permits or compliance with environmental laws, and such other representations and warranties will not survive the closing of this offering. Moreover, the representations, warranties and indemnities provided by the Contributing Parties are subject to significant limitations, including indemnity caps, and may not protect us against all liabilities or other problems associated with the entities and assets being contributed to us in connection with this offering. For example, the existence of a material title deficiency covering a material amount of our assets can render a lease worthless and could materially adversely affect our financial condition, results of operations and cash available for distribution. We do not obtain title insurance covering mineral leaseholds, and our failure to cure any title defects may delay or prevent us from realizing the benefits of ownership of the mineral interest, which may adversely impact our ability in the future to increase production and reserves. Additionally, undeveloped acreage has greater risk of title defects than developed acreage. If there are any title defects, or defects in the assignment of leasehold rights in properties in which we hold an interest, our business, results of operations and cash available for distribution may be adversely affected.

        The indemnities that the Contributing Parties have agreed to provide under the contribution agreement may be inadequate to fully compensate us for losses we may suffer or incur as a result of liabilities arising out of the ownership and operation of our assets prior to the closing of this offering. Even if we are insured or indemnified against such risks, we may be responsible for costs or penalties to the extent our insurers or indemnitors do not fulfill their obligations to us, and the payment of any such costs or penalties could be significant. The occurrence of any losses that are neither indemnified for under the contribution agreement nor covered under our insurance plans could materially adversely affect our financial condition, results of operations

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and cash available for distribution. Please read "Certain Relationships and Related Party Transactions—Agreements and Transactions with Affiliates in Connection with this Offering—Contribution Agreement—Indemnification."

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

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

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

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

        Leases on oil and natural gas properties typically have a term of three to five years, after which they expire unless, prior to expiration, production is established within the spacing units covering the undeveloped acres. Any reduction in our operators' drilling programs, either through a reduction in capital expenditures or the unavailability of drilling rigs, could result in the loss of acreage through lease expirations which may terminate our overriding royalty interests derived from such leases. If our royalties are derived from mineral interests and production or drilling ceases on the leased property, the lease is typically terminated, subject to certain exceptions, and all mineral rights revert back to us and we will have to seek new lessees to explore and develop such mineral interests. Any such losses of our operators or lessees could materially and adversely affect the growth of our financial condition, results of operations and cash available for distribution.

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

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

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

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

        Ultimately, the success of these drilling and completion techniques can only be evaluated over time as more wells are drilled and production profiles are established over a sufficiently long time period. If our operators' drilling results are weaker than anticipated or they are unable to execute their drilling program on our properties because of capital constraints, lease expirations, access to gathering systems, or declines in oil and natural gas prices, our operating and financial results in these areas may be lower than we anticipate. Further, as a result of any of these developments we could incur material write-downs of our oil and natural gas properties and the value of our undeveloped acreage could decline, and our results of operations and cash available for distribution could be materially adversely affected.

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The marketability of oil and natural gas production is dependent upon transportation and other facilities, certain of which neither we nor the operators of our properties control. If these facilities are unavailable, our operators' operations could be interrupted and our results of operations and cash available for distribution could be materially 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 the operators of our properties control these third party transportation facilities and our operators' access to them may be limited or denied. Insufficient production from the wells on our acreage or a significant disruption in the availability of third party transportation facilities or other production facilities could adversely impact our 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 or our operators' control, such as pipeline interruptions due to maintenance, excessive pressure, inability of downstream processing facilities to accept unprocessed gas, physical damage to the gathering system or transportation system or lack of contracted capacity on such systems. The curtailments arising from these and similar circumstances may last from a few days to several months. In many cases, we and our operators are provided with limited notice, if any, as to when these curtailments will arise and the duration of such curtailments. Any such shut in or curtailment, or an inability to obtain favorable terms for delivery of the oil and natural gas produced from our acreage, could materially adversely affect our financial condition, results of operations and cash available for distribution.

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

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

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

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

    the establishment of maximum rates of production from wells;

    the spacing of wells;

    the plugging and abandonment of wells; and

    the removal of related production equipment.

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

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

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

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

        The operators of our properties may incur significant delays, costs and liabilities as a result of environmental and occupational health and safety laws and regulations applicable to their exploration, development and production activities on our properties. These delays, costs and liabilities could arise under a wide range of federal, regional, state and local laws and regulations relating to protection of the environment and worker health and safety. These laws, regulations, and enforcement policies have become increasingly strict over time, resulting in longer waiting periods to receive permits and other regulatory approvals, and we believe this trend will continue. These laws include, but are not limited to, the federal Clean Air Act (and comparable state laws and regulations that impose obligations related to air emissions), the federal Water Pollution Control Act of 1972 ("Clean Water Act") and Oil Pollution Act ("OPA") (and comparable state laws and regulations that impose requirements related to discharges of pollutants into regulated bodies of water), the federal Resource Conservation and Recovery Act, as amended ("RCRA") (and comparable state laws that impose requirements for the handling and disposal of waste), the federal Comprehensive Environmental Response, Compensation and Liability Act, as amended ("CERCLA"), also known as the "Superfund" law, and the community right to know regulations under Title III of the act (and comparable state laws that regulate the

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cleanup of hazardous substances that may have been released at properties currently or previously owned or operated by our operators or at locations our operators sent waste for disposal and comparable state laws that require organization and/or disclosure of information about hazardous materials our operators use or produce), the federal Occupational Safety and Health Act (which establishes workplace standards for the protection of health and safety of employees and requires a hazardous communications program) and the Endangered Species Act and the Migratory Bird Treaty Act (and comparable state laws that seek to ensure activities do not jeopardize endangered or threatened animals, fish, plant species by limiting or prohibiting construction activities in areas that are inhabited by such species and penalizing the taking, killing or possession of migratory birds).

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

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

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

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

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

        Certain governmental reviews have been conducted or are underway that focus on the potential environmental impacts of hydraulic fracturing. These ongoing or proposed studies could spur initiatives to further regulate hydraulic fracturing and could ultimately make it more difficult or costly for the operators of our properties to perform fracturing and increase the costs of compliance and doing business. Additional legislation or regulation could also make it easier for parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process could adversely affect groundwater. There has also been increasing public controversy regarding hydraulic fracturing with regard to the use of fracturing fluids, impacts on drinking water supplies, the use of water and the potential for impacts to surface water, groundwater and the environment generally. A number of lawsuits and enforcement actions have been initiated at the state level implicating hydraulic fracturing practices. The imposition of stringent new regulatory and permitting requirements related to the practice of hydraulic fracturing could significantly increase our cost of doing business, could create adverse effects on our operators, including creating delays related to the issuance of permits and, depending on the specifics of any particular proposal that is enacted, could be material.

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

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

        In response to findings that emissions of carbon dioxide, methane and other greenhouse gases ("GHGs") present an endangerment to public health and the environment, the EPA has adopted regulations under existing provisions of the federal Clean Air Act that, among other things, require preconstruction and operating permits for certain large stationary sources. Facilities required to obtain preconstruction permits for their GHG emissions also will be

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required to meet "best available control technology" standards that will be established on a case-by-case basis. These EPA rulemakings could adversely affect operations on our properties and restrict or delay the ability of our operators to obtain air permits for new or modified sources. In addition, the EPA has adopted rules requiring the monitoring and reporting of GHG emissions from specified onshore oil and natural gas production sources in the United States on an annual basis, which include operations on certain of our properties. These requirements could increase the costs of development and production, reducing the profits available to us and potentially impairing our operator's ability to economically develop our properties. Please read "Business—Regulation" for a description of the laws and regulations that affect the operators of our properties and that may affect us.

        Efforts have been made and continue to be made in the international community toward the adoption of international treaties or protocols that would address global climate change issues. For example, in April 2016, the United States was one of 175 countries to sign the Paris Agreement, which requires member countries to review and "represent a progression" in their intended nationally determined contributions, which set GHG emission reduction goals, every five years beginning in 2020. The Paris Agreement entered into force in November 2016. The United States is one of more than 70 nations that has ratified or otherwise indicated that it intends to comply with the agreement. These and other initiatives or regulatory changes could result in increased costs of development and production, reducing the profits available to us and potentially impairing our operators' ability to economically develop our properties.

        While Congress has from time to time considered legislation to reduce emissions of GHGs, there has not been significant activity in the form of adopted legislation to reduce GHG emissions at the federal level in recent years. In the absence of federal climate legislation, a number of state and regional efforts have emerged that are aimed at tracking or reducing GHG emissions by means of cap and trade programs. These programs typically require major sources of GHG emissions to acquire and surrender emission allowances in return for emitting those GHGs. Although it is not possible at this time to predict how legislation or new regulations that may be adopted to address GHG emissions would impact our business, any future laws and regulations imposing reporting obligations on, or limiting emissions of GHGs from, our operators' equipment and operations could require them to incur costs to reduce emissions of GHGs associated with their operations. In addition, substantial limitations on GHG emissions could adversely affect demand for the oil and natural gas produced from our properties. Restrictions on emissions of methane or carbon dioxide that may be imposed in various states, as well as state and local climate change initiatives, could adversely affect the oil and natural gas industry, and, at this time, it is not possible to accurately estimate how potential future laws or regulations addressing GHG emissions would impact our business.

        Finally, increasing concentrations of GHGs in the Earth's atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods, and other climatic events; if any of these effects were to occur, they could materially adversely affect our properties and operations.

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

        The drilling activities of the operators of our properties will be subject to many risks. For example, we will not be able to assure you that wells drilled by the operators of our properties will be productive. Drilling for oil and natural gas often involves unprofitable efforts, not only

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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:

    unusual or unexpected geological formations;

    loss of drilling fluid circulation;

    title problems;

    facility or equipment malfunctions;

    unexpected operational events;

    shortages or delivery delays of equipment and services;

    compliance with environmental and other governmental requirements; and

    adverse weather conditions.

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

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

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

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

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

Risks Inherent in an Investment in Us

Our general partner and its affiliates, including our Sponsors and their respective affiliates, have conflicts of interest with us and limited duties to us and our unitholders, and they may favor their own interests to the detriment of us and our unitholders. Additionally, we have no control over the business decisions and operations of our Sponsors and their respective affiliates, which are under no obligation to adopt a business strategy that favors us.

        Upon the completion of this offering, affiliates of our Sponsors will own a         % limited partner interest in us (or          % if the underwriters' option to purchase additional common units is exercised in full) (excluding any common units purchased by officers and directors of our general partner under our directed unit program), and our Sponsors will indirectly own and control our general partner. Our general partner has sole responsibility for conducting our business and managing our operations. Although our general partner has a duty to manage us in a manner that is in, or not adverse to, the best interests of us and our unitholders, the directors and officers of our general partner also have a duty to manage our general partner in a manner that is beneficial to Kimbell Holdings and its parents, our Sponsors. Conflicts of interest may arise between our Sponsors and their respective affiliates, including our general partner, on the one hand, and us and our unitholders, on the other hand. In resolving these conflicts, our general partner may favor its own interests and the interests of its affiliates, including our Sponsors and their respective affiliates, over the interests of our unitholders. These conflicts include, among others, the following situations:

    neither our partnership agreement nor any other agreement requires our Sponsors or the Contributing Parties to pursue a business strategy that favors us or utilizes our assets

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      (subject to the non-competition provision of the limited liability company agreement of Kimbell Holdings), which could involve decisions by our Sponsors to undertake acquisition opportunities for themselves, and the directors and officers of our Sponsors and the Contributing Parties have a fiduciary duty to make these decisions in the best interests of our Sponsors and such Contributing Parties, which may be contrary to our interests;

    our Sponsors may change their strategy or priorities in a way that is detrimental to our future growth and acquisition opportunities;

    many of the officers and directors of our general partner are also officers or directors of, and equity owners in, our Sponsors and the Contributing Parties and will owe fiduciary duties to our Sponsors and the Contributing Parties and their respective owners;

    our partnership agreement does not limit our Sponsors' or their respective affiliates' ability to compete with us and, subject to the 50% participation right included in the contribution agreement that we have entered into with our Sponsors and the Contributing Parties, neither our Sponsors nor the Contributing Parties have any obligation to present business opportunities to us (subject to the non-competition provision of the limited liability company agreement of Kimbell Holdings), and although certain of the Contributing Parties have granted us a right of first offer for a period of three years after the closing of this offering with respect to certain mineral and royalty interests in the Permian Basin, the Bakken/Williston Basin and the Marcellus Shale, and such Contributing Parties are under no obligation to offer such assets to us;

    our Sponsors may be constrained by the terms of their current or future debt instruments from taking actions, or refraining from taking actions, that may be in our best interests;

    our partnership agreement replaces the fiduciary duties that would otherwise be owed by our general partner with contractual standards governing its duties, limiting our general partner's liabilities; and restricting the remedies available to our unitholders for actions that, without the limitations, might constitute breaches of fiduciary duty;

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

    contracts between us, on the one hand, and our general partner and its affiliates, on the other hand, may not be the result of arm's length negotiations;

    disputes may arise under agreements we have with our general partner or its affiliates;

    our general partner will determine the amount and timing of acquisitions and dispositions, borrowings, issuance of additional partnership securities and the creation, reduction or increase of cash reserves, each of which can affect the amount of cash that is distributed to our unitholders;

    our general partner will determine which costs incurred by it or 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 any of these entities on our behalf;

    we will enter into a management services agreement with Kimbell Operating, which will enter into separate service agreements with certain entities controlled by Messrs. Duncan, R. Ravnaas, Taylor and Wynne, pursuant to which they and Kimbell Operating will provide management, administrative and operational services to us, and such entities will also provide these services to certain other entities, including certain of the Contributing Parties;

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

    our general partner may exercise its right to call and purchase all of the common units not owned by it and its affiliates if it and its affiliates own more than 80% of our common units;

    our general partner controls the enforcement of obligations owed to us by our general partner and its affiliates, including under the contribution agreement and other agreements with our Sponsors and the Contributing Parties; and

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

Our partnership agreement does not restrict our Sponsors and their respective affiliates, the Contributing Parties, or affiliates of our general partner from competing with us.

        Our partnership agreement provides that our general partner is restricted from engaging in any business activities other than acting as our general partner and those activities incidental to its ownership of interests in us. Affiliates of our general partner are not prohibited from owning projects or engaging in businesses that compete directly or indirectly with us. Similarly, our partnership agreement does not limit our Sponsors' or their respective affiliates' ability to compete with us and, subject to the 50% participation right included in the contribution agreement that we have entered into with our Sponsors and the Contributing Parties, neither our Sponsors nor the Contributing Parties have any obligation to present business opportunities to us. Pursuant to the limited liability company agreement of Kimbell Holdings, the right of each of Messrs. Fortson, R. Ravnaas, Taylor and Wynne (and their designated successors) to serve as a director of our general partner is conditioned upon the applicable person not competing with us, our general partner, and our and its respective subsidiaries. Affiliates of our Sponsors currently hold interests in, and may make investments in and purchases of, entities that acquire and own mineral and royalty interests. Our Sponsors and their respective affiliates will be under no obligation to make any acquisition opportunities available to us, except as provided for under the contribution agreement.

        Under 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 our Sponsors and their respective affiliates, or the Contributing Parties. 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

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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 holders 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.

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

        Neither we, our general partner nor our subsidiaries have any employees, and we rely solely on Kimbell Operating to manage us and operate our assets. In connection with this offering, we will enter into a management services agreement with Kimbell Operating, which will enter into separate service agreements with certain entities controlled by Messrs. Duncan, R. Ravnaas, Taylor and Wynne, pursuant to which they and Kimbell Operating will provide management, administrative and operational services to us.

        Kimbell Operating will also provide substantially similar services and personnel to other entities, including certain of the Contributing Parties, and, as a result, may not have sufficient human, technical and other resources to provide those services at a level that it would be able to provide to us if it did not provide similar services to these other entities. Additionally, Kimbell Operating may make internal decisions on how to allocate its available resources and expertise that may not always be in our best interest compared to those of other entities or other affiliates of our general partner. There is no requirement that Kimbell Operating favor us over these other entities in providing its services. If the employees of Kimbell Operating 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 fiduciary duties applicable to a corporation with contractual duties and restricts the remedies available to holders of our common units for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty.

        Our partnership agreement contains provisions that replace fiduciary duties applicable to a corporation with contractual duties and restrict the remedies available to unitholders for actions

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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:

    whenever our general partner (acting in its capacity as our general partner), the board of directors of our general partner or any committee thereof (including the conflicts committee) makes a determination or takes, or declines to take, any other action in their respective capacities, our general partner, the board of directors of our general partner and any committee thereof (including the conflicts committee), as applicable, is required to make such determination, or take or decline to take such other action, in good faith, meaning that it subjectively believed that the decision was in, or not adverse to, our best interests, and, except as specifically provided by our partnership agreement, will not be subject to any other or different standard imposed by our partnership agreement, Delaware law, or any other law, rule or regulation, or at equity;

    our general partner will not have any liability to us or our unitholders for decisions made in its capacity as a general partner so long as such decisions are made in good faith;

    our general partner and its officers and directors will not be liable for monetary damages 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 our general partner or its officers and directors, as the case may be, acted in bad faith or engaged in fraud or willful misconduct or, in the case of a criminal matter, acted with knowledge that the conduct was criminal; and

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

    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;

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

    determined by the board of directors of our general partner to be on terms no less favorable to us than those generally being provided to or available from third parties; or

    determined by the board of directors of our general partner to be fair and reasonable to us, taking into account the totality of the relationships among the parties involved, including other transactions that may be particularly favorable or advantageous to us.

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        In connection with a situation involving a transaction with an affiliate or a conflict of interest, any determination by our general partner or the conflicts committee 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 and the board of directors of our general partner determines that the resolution or course of action taken with respect to the affiliate transaction or conflict of interest satisfies either of the standards set forth in the third and fourth sub bullet points above, 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 any limited partner or the partnership challenging such determination, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption. Please read "Conflicts of Interest and Duties—Conflicts of Interest."

Our partnership agreement replaces our general partner's fiduciary duties to holders of our common units with contractual standards governing its duties.

        Our partnership agreement contains provisions that eliminate the fiduciary standards to which our general partner would otherwise be held by state fiduciary duty law and replaces those duties with several different contractual standards. 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, free of any duties to us and our unitholders other than the implied contractual covenant of good faith and fair dealing, which means that a court will enforce the reasonable expectations of the partners where the language in the partnership agreement does not provide for a clear course of action. This provision 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:

    how to allocate corporate opportunities among us and its other affiliates;

    whether to exercise its limited call right;

    whether to seek approval of the resolution of a conflict of interest by the conflicts committee of the board of directors of our general partner or by the unitholders;

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

    whether to sell or otherwise dispose of any units or other partnership interests it owns; and

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

        By purchasing a common unit, a common unitholder agrees to become bound by the provisions in the partnership agreement, including the provisions discussed above. Please read "Conflicts of Interest and Duties—Duties of Our General Partner."

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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, our unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management's decisions regarding our business. Our 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 our Sponsors, as a result of such Sponsors controlling our general partner, and not by our unitholders. Please read "Management—Management of Kimbell Royalty 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 our 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. The vote of the holders of at least 662/3% of all outstanding common units is required to remove our general partner. Following the closing of this offering, affiliates of our Sponsors will own         % of our common units (or         % of our common units, if the underwriters exercise their option to purchase additional common units in full) (excluding any common units purchased by officers and directors of our general partner under our directed unit program), and our Sponsors will indirectly own and control 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, the Contributing Parties and their respective 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 and their transferees, the Contributing Parties, their respective affiliates and 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. Our partnership agreement also contains provisions limiting the ability of common unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting the ability of our common unitholders to influence the manner or direction of management.

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 may be reimbursed. The amount and timing of such reimbursements will be determined by our general partner.

        Prior to paying any distribution on our common units, we will reimburse our general partner and its affiliates, including Kimbell Operating pursuant to its management services agreement discussed below, for all expenses they incur and payments they make on our behalf.

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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."

        In connection with the closing of this offering, we will also enter into a management services agreement with Kimbell Operating, which will enter into separate service agreements with certain entities controlled by Messrs. Duncan, R. Ravnaas, Taylor and Wynne, pursuant to which they and Kimbell Operating will provide management, administrative and operational services to us. Amounts paid to Kimbell Operating and such other entities under their respective service agreements will reduce the amount of cash available for distribution to our unitholders. Please read "Certain Relationships and Related Party Transactions—Agreements and Transactions with Affiliates in Connection with this Offering—Management Services Agreements."

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.

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 pay 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."

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Increases in interest rates may cause the market price of our common units to decline.

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

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 (including our Sponsors and their respective affiliates) own more than 80% of our 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 our 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 Exchange Act. Upon the completion of this offering, affiliates of our Sponsors will own         % of our common units (excluding any common units purchased by officers and directors of our general partner under our directed unit program), and our Sponsors will indirectly own and control our general partner. 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

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us of additional common units or other equity interests of equal or senior rank will have the following effects:

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

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

    the ratio of our taxable income to distributions may increase;

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

    the market price of the common units may decline.

        Please read "The Partnership Agreement—Issuance of Additional Partnership Interests."

There are no limitations in our partnership agreement on our ability to issue units ranking senior in right of distributions or liquidation to our common units.

        In accordance with Delaware law and the provisions of our partnership agreement, we may issue additional partnership interests that rank senior in right of distributions, liquidation or voting to our common units. 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 materially adversely affected by sales of substantial amounts of our common units in the public or private markets, including sales by our Sponsors and the Contributing Parties.

        After this offering, we will have                  common units outstanding, including our common units that we are selling in this offering that may be resold in the public market immediately.             of the                  common units to be issued to certain of the Contributing Parties, including affiliates of our Sponsors, 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 our Sponsors, certain of the Contributing Parties 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 the Contributing Parties. 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 our 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

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public offering price. Additionally, the lack of liquidity may result in wide bid-ask spreads, contribute to significant fluctuations in the market price of our common units and limit the number of investors who are able to buy our 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 our 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:

    changes in commodity prices;

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

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

    changes in market valuations of similar companies;

    departures of key personnel;

    commencement of or involvement in litigation;

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

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

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

    variations in the amount of our quarterly cash distributions to our unitholders;

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

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

    future sales of our common units; and

    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.

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Before we are able to pay 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 $1.5 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 that apply to other public companies.

        We are an "emerging growth company" as defined in the JOBS Act. For as long as we are an emerging growth company, which may be up to five full fiscal years, unlike other public companies, we will not be required to, among other things, (1) provide an auditor's attestation report on the effectiveness of our system of internal control over financial reporting pursuant to Section 404(b) of the Sarbanes-Oxley Act, (2) comply with any new requirements adopted by the PCAOB requiring mandatory audit firm rotation or a supplement to the auditor's report in which the auditor would be required to provide additional information about the audit and the financial statements of the issuer, (3) comply with any new audit rules adopted by the PCAOB after April 5, 2012 unless the SEC determines otherwise or (4) provide certain disclosure regarding executive compensation required of larger public companies.

        In addition, Section 102 of the JOBS Act also provides that an "emerging growth company" can use the extended transition period provided in Section 7(a)(2)(B) of the Securities Act for complying with new or revised accounting standards. An "emerging growth company" can therefore delay the adoption of certain accounting standards until those standards would otherwise apply to private companies. 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. Section 107 of the JOBS Act provides that our decision to opt out of the extended transition period for complying with new or revised accounting standards is irrevocable.

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 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

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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. However, for as long as we are an "emerging growth company" under the JOBS Act, our independent registered public accounting firm will not be required to attest to the effectiveness of our internal control over financial reporting. We must comply with Section 404 (except for the requirement for an auditor's attestation report) beginning with our fiscal year ending  . 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.

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

        We have been approved to list our common units on the NYSE, subject to official notice of issuance. Because we will be a publicly traded partnership, the NYSE does not require us to have, and we do not intend 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. Additionally, any future issuance of common units or other securities, including to affiliates, will not be subject to the NYSE's shareholder approval rules that apply to corporations. 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. These provisions may have the effect of discouraging lawsuits against us and our general partner's officers and directors.

Our general partner may amend our partnership agreement, as it determines necessary or advisable, to permit our 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 or the nationality, citizenship or other related status of our limited partners (and their owners, to the extent relevant) and to

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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 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—Ineligible Holders; 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. A change in our business 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. Several states have subjected, or 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.

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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, from time to time, the President and members of Congress propose and consider substantive changes to the existing U.S. federal income tax laws that affect publicly traded partnerships, including elimination of partnership tax treatment for publicly traded partnerships. Any modification to the federal income tax laws and interpretations thereof may or may not be retroactively applied and could make it more difficult or impossible for us to meet the exception to be treated as a partnership for federal income tax purposes. Please read "Material U.S. Federal Income Tax Consequences—Partnership Status."

        On May 5, 2015, the U.S. Treasury Department and the IRS issued proposed regulations (the "Proposed Regulations") regarding qualifying income under Section 7704(d)(1)(E) of the Internal Revenue Code of 1986, as amended (the "Code"). The Proposed Regulations provide an exclusive list of industry-specific rules regarding the qualifying income exception, including whether an activity constitutes the exploration, development, production and marketing of natural resources. Income earned from a royalty interest is not specifically enumerated as a qualifying income activity in the Proposed Regulations. However, we believe that royalty income is qualifying income for purposes of Section 7704 of the Code since it is "derived" from the exploration, development, production and marketing of natural resources, and Baker Botts L.L.P. is of the opinion that such income constitutes qualifying income, notwithstanding the Proposed Regulations. Further, the Proposed Regulations are proposed only to apply to income earned in a taxable year beginning on or after the date that the Proposed Regulations are published as final regulations. Therefore, prior to being published as final regulations, the Proposed Regulations are generally not applicable to any income that we earn. The U.S. Treasury Department and the IRS may clarify that royalty income is qualifying income for purposes of Section 7704 of the Code; however, there are no assurances that the Proposed Regulations, when published as final regulations, will not take a position that is contrary to our interpretation of Section 7704 of the Code.

        We are unable to predict whether any of these changes or other proposals will ultimately be enacted or adopted. Any such changes could negatively impact the value of an investment in our common units. For further discussion of the importance of our treatment as a partnership for federal income tax purposes, please read "Material U.S. Federal Income Tax Consequences—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

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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 some 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 for U.S. federal income tax purposes 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 Common 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 or annuities 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 U.S. federal income tax returns and pay tax on their share of our taxable income if it is treated as income effectively connected with the conduct of a U.S. trade or business ("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 our common units.

        Because we cannot match transferors and transferees of our common units, and because of other reasons, we will adopt depreciation and amortization positions that may not conform to all aspects of existing Treasury regulations ("Treasury Regulations"). Our counsel is unable to opine as to the validity of this approach. A successful IRS challenge to those positions could adversely

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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 business 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 business day of each month, instead of on the basis of the date a particular unit is transferred. Although simplifying conventions are contemplated by the Code and most publicly traded partnerships use similar simplifying conventions, the use of this proration method may not be permitted under existing Treasury Regulations. The U.S. Treasury Department recently adopted final Treasury Regulations allowing similar monthly simplifying conventions. However, the final Treasury Regulations do not specifically authorize the use of the proration method we will adopt. If the IRS were to challenge our proration method, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders. Baker Botts L.L.P. has not rendered an opinion with respect to whether our monthly convention for allocating taxable income and losses is permitted by existing Treasury Regulations. Please read "Material U.S. Federal Income Tax Consequences—Disposition of Common Units—Allocations Between Transferors and Transferees."

If the IRS makes audit adjustments to our income tax returns for tax years beginning after 2017, it may collect any resulting taxes (including any applicable penalties and interest) directly from us, in which case our cash available for distribution to our unitholders might be substantially reduced.

        Pursuant to the Bipartisan Budget Act of 2015, if the IRS makes audit adjustments to our income tax returns for tax years beginning after 2017, it may collect any resulting taxes (including any applicable penalties and interest) directly from us. We will generally have the ability to shift any such tax liability to our unitholders in accordance with their interests in us during the year under audit, but there can be no assurance that we will be able to do so under all circumstances. If we are required to make payments of taxes, penalties and interest resulting from audit adjustments, our cash available for distribution to our unitholders might be substantially reduced.

A unitholder whose common units are loaned to a "short seller" to cover a short sale of common units may be considered as having disposed of those common units. If so, he would no longer be treated for federal income tax purposes as a partner with respect to those common units during the period of the loan and may recognize gain or loss from the disposition.

        Because a unitholder whose common units are loaned to a "short seller" to cover a short sale of common units may be considered as having disposed of the loaned common units, he may no longer be treated for federal income tax purposes as a partner with respect to those

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common 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 to the short seller, any of our income, gain, loss or deduction with respect to those common units may not be reportable by the unitholder and any cash distributions received by the unitholder as to those common 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 cover a short sale of common units; therefore, our unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller are urged to consult a tax advisor to discuss whether it is advisable to modify any applicable brokerage account agreements to prohibit their brokers from loaning their common units.

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 technically terminated our partnership 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. For purposes of determining whether the 50% threshold has been met, multiple sales of the same interest will be counted only once. Our technical termination would, among other things, result in the closing of our taxable year for all unitholders, which would result in us filing two tax returns (and our unitholders could receive two Schedules K-1 if relief was not available and/or granted by the IRS to provide one Schedule K-1 to unitholders for the year notwithstanding two partnership tax years) for one fiscal year and, in the event we acquire depreciable property in the future, could result in a deferral of depreciation deductions allowable in computing our taxable income. In the case of a unitholder reporting on a taxable year other than a fiscal year ending December 31, 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 we would be treated as a new partnership for 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 Common Units—Constructive Termination" for a discussion of the consequences of our termination for federal income tax purposes.

You will likely 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 will likely 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 20 states, many of which impose a personal income tax and also impose income taxes on corporations and other entities. 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. 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. It is your responsibility to file all U.S. federal, foreign, state and local tax returns. Our counsel has not rendered an opinion on the foreign, state or local tax consequences of an investment in our common units.

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USE OF PROCEEDS

        We will receive 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 structuring fee payable by us in connection with this offering. We intend to use the net proceeds of this offering to make a distribution to the Contributing Parties.

        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 the Contributing Parties. Any common units not purchased by the underwriters pursuant to their option will be issued to the Contributing Parties 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 the estimated underwriting discount and structuring fee. 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 the Contributing Parties.

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

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CAPITALIZATION

        The following table shows our cash and cash equivalents and capitalization as of September 30, 2016:

    on a historical basis for our predecessor; and

    on a pro forma basis to reflect among other things, the portion of our initial assets to be contributed by the Kimbell Art Foundation, Trunk Bay Royalty Partners, Ltd., Oil Nut Bay Royalties, LP, Gorda Sound Royalties, LP and Bitter End Royalties, LP, RCPTX, Ltd., and French Capital Partners, Ltd. (but not by the other Contributing Parties), the offering and the application of the net proceeds from this offering as described under "Use of Proceeds."

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

 
  As of September 30, 2016  
 
  Predecessor   Kimbell Royalty
Partners, LP
 
 
  Historical   Pro Forma  

Cash and cash equivalents

  $ 679,635   $    

Long-term debt

  $ 10,898,860   $    

Members' equity/partners' capital:

             

Members' equity

  $ 8,675,203   $    

General partner

           

Common units

           

Total members' equity/partners' capital

  $ 8,675,203   $    

Total capitalization

  $ 19,574,063   $    

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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 structuring fee payable by us in connection with this offering, our pro forma net tangible book value as of September 30, 2016 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 (1)

        $    

Pro forma net tangible book value per common unit before the offering (2)

  $          

Decrease 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 (3)

             

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

        $    

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

(2)
Determined by dividing the pro forma net tangible book value of the contributed assets and liabilities by the number of common units to be issued to the Contributing Parties for their contribution of assets and liabilities to us.

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

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

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

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

 
  Units Acquired   Total
Consideration
 
(dollars in millions)
  Number   Percent   Amount   Percent  

Contributing Parties (1)

            % $         %

Purchasers in this offering

            %      (2)     %

Total

          100 % $       100 %

(1)
Reflects the value of the assets to be contributed to us by the Contributing Parties recorded at historical cost. Book value of the consideration provided by the Contributing Parties, as of September 30, 2016, after giving effect to the formation transactions, is as follows:

 
  (in thousands)  

Book value of net assets contributed

  $    

Less: Distribution to the Contributing Parties from net proceeds of this offering

       

Total consideration

  $    
(2)
Reflects the net proceeds of this offering after deducting the estimated underwriting discount and structuring fee payable by us in connection with this offering, and assumes the underwriter's option to purchase additional common units is not exercised.

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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. Please read "—Estimated Cash Available for Distribution for the Twelve Months Ending December 31, 2017—Assumptions and Considerations" below. In addition, you should read "Forward-Looking Statements" and "Risk Factors" for information regarding statements that do not relate strictly to historical or current facts and certain risks inherent in our business.

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

General

Our Cash Distribution Policy

        Our partnership agreement will require us to distribute all of our cash on hand at the end of each quarter in an amount equal to our available cash for such quarter, beginning with the quarter ending                      , 2017. Our first distribution, however, will include available cash for the period from the closing of this offering through                      , 2017. Available cash for each quarter will be determined by the board of directors of our general partner following the end of such quarter. We define available cash in our partnership agreement, in the glossary of terms attached as Appendix B and in "How We Pay Distributions." We expect that available cash for each quarter will generally equal our Adjusted EBITDA for the quarter, less cash needed for debt service and other contractual obligations and fixed charges and reserves for future operating or capital needs that the board of directors may determine is appropriate. We do not currently intend to maintain excess distribution coverage for the purpose of maintaining stability or growth in our quarterly distribution or otherwise to reserve cash for distributions, nor do we intend to incur debt to pay quarterly distributions.

        Unlike a number of other master limited partnerships, we do not currently intend to retain cash from our operations for capital expenditures necessary to replace our existing oil and natural gas reserves or otherwise maintain our asset base (replacement capital expenditures), primarily due to our expectation that the continued development of our properties and completion of drilled but uncompleted wells by working interest owners will substantially offset the natural production declines from our existing wells. Although we expect no or limited organic growth at current commodity prices, we believe that our operators have significant drilling inventory remaining on the acreage underlying our mineral or royalty interest in multiple resource plays that will provide a solid base for organic growth when commodity prices increase. The board of directors of our general partner may decide to withhold replacement capital expenditures from cash available for distribution, which would reduce the amount of cash available for distribution in the quarter(s) in which any such amounts are withheld. Over the long term, if our reserves are depleted and our operators become unable to maintain production on our existing properties and we have not been retaining cash for replacement capital expenditures, the amount of cash generated from our existing properties will decrease and we may have to reduce the amount of distributions payable to our unitholders. To the extent that we do not withhold replacement capital expenditures, a portion of our cash available for distribution will represent a return of your capital.

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

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

        There is no guarantee that we will pay cash distributions to our unitholders each quarter. Our cash distribution policy is subject to certain restrictions, including the following:

    Following the formation transactions, we expect to borrow approximately $1.5 million under our secured revolving credit facility to fund certain transaction expenses. We anticipate that our credit agreement and any future debt agreements will contain certain financial tests and covenants that we would have to satisfy. We may also be prohibited from paying distributions if an event of default or borrowing base deficiency exists under our secured revolving credit facility. If we are unable to satisfy the restrictions under any future debt agreements, we could be prohibited from paying a distribution to you notwithstanding our stated distribution policy.

    Our business performance may be volatile, and our cash flows may be less stable, than the business performance and cash flows of most publicly traded partnerships. As a result, our quarterly cash distributions may be volatile and may vary quarterly and annually.

    We will not have a minimum quarterly distribution or employ structures intended to maintain or increase quarterly distributions over time. Furthermore, none of our limited partner interests, including those held by the Contributing Parties, will be subordinate in right of distribution payment to the common units sold in this offering.

    Our general partner will have the authority to establish cash reserves for the prudent conduct of our business, and the establishment of, or increase in, those reserves could result in a reduction in cash distributions to our unitholders. Our partnership agreement does not set a limit on the amount of cash reserves that our general partner may establish. Any decision to establish cash reserves made by our general partner will be binding on our unitholders.

    Prior to paying any distributions on our units, we will reimburse our general partner and its affiliates, including Kimbell Operating pursuant to its management services agreement discussed below, for all direct and indirect expenses they incur on our behalf. Our partnership agreement provides that our general partner will determine the expenses that are allocable to us, but does not limit the amount of expenses for which our general partner and its affiliates may be reimbursed. In addition, we will enter into a management services agreement with Kimbell Operating, which will enter into separate service agreements with certain entities controlled by Messrs. Duncan, R. Ravnaas, Taylor and Wynne, pursuant to which they and Kimbell Operating will provide management, administrative and operational services to us. The reimbursement of expenses and payment of fees, if any, to our general partner and its affiliates, including Kimbell

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      Operating, and to such other entities providing services to us and Kimbell Operating, will reduce the amount of cash to pay distributions to our unitholders.

    Under Section 17-607 of the Delaware Act, we may not pay 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 commercial or other factors as well as increases in general and administrative expenses, principal and interest payments on our outstanding debt, tax expenses, working capital requirements and anticipated cash needs.

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

        We expect to pay our distributions within 60 days of the end of each quarter. Our first distribution will include available cash for the period from the closing of this offering through                      , 2017.

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

    "Unaudited Pro Forma Cash Available for Distribution," in which we present our unaudited estimate of the amount of pro forma cash available for distribution we would have had for the year ended December 31, 2015 and the twelve months ended September 30, 2016 had this offering and the pro forma formation transactions been consummated at the beginning of such period, in each case, based on our pro forma condensed combined financial statements included elsewhere in this prospectus; and

    "Estimated Cash Available for Distribution," in which we provide our unaudited forecast of cash available for distribution for the twelve months ending December 31, 2017.

Unaudited Pro Forma Cash Available for Distribution for the Year Ended December 31, 2015 and the Twelve Months Ended September 30, 2016

        We estimate that we would have generated $16.3 million and $10.9 million of pro forma cash available for distribution for the year ended December 31, 2015 and the twelve months ended September 30, 2016, respectively. Assuming we do not retain cash from operations for capital expenditures, this amount would have resulted in an aggregate annual distribution equal to $             for the year ended December 31, 2015 and $             for the twelve months ended September 30, 2016.

        Our unaudited pro forma cash available for distribution for each of the year ended December 31, 2015 and the twelve months ended September 30, 2016 includes an incremental $1.5 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: expenses associated with SEC reporting requirements, including annual and quarterly reports to unitholders, tax return and Schedule K-1 preparation and distribution expenses, Sarbanes-Oxley Act compliance expenses, expenses associated with

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listing on the NYSE, independent auditor fees, independent reserve engineer fees, legal fees, investor relations expenses, registrar and transfer agent fees, director and officer insurance expenses and director and officer compensation expenses. These incremental general and administrative expenses are not reflected in the historical financial statements of our predecessor or our pro forma financial statements included elsewhere in this prospectus.

        We based the pro forma adjustments upon currently available information and specific estimates and assumptions. The pro forma amounts below do not purport to present our results of operations had this offering and related formation transactions been completed as of the date indicated. In addition, cash available 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 distribution 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 and Unaudited Pro Forma Financial Data," "Management's Discussion and Analysis of Financial Condition and Results of Operations" and the audited historical financial statements and the accompanying notes included elsewhere in this prospectus.

        The following table illustrates, on a pro forma basis, for the year ended December 31, 2015 and for the twelve months ended September 30, 2016, the amount of cash that would have been available for distribution to our unitholders, assuming that this offering and the pro forma formation transactions had been consummated at the beginning of such period. All of the amounts for the year ended December 31, 2015 and the twelve months ended September 30, 2016 in the table below are estimates.

        Assets from the Contributing Parties (other than our predecessor, the Kimbell Art Foundation, Trunk Bay Royalty Partners, Ltd., Oil Nut Bay Royalties, LP, Gorda Sound Royalties, LP and Bitter End Royalties, LP, RCPTX, Ltd., and French Capital Partners, Ltd.) are not reflected in the pro forma financial statements. Financial statements relating to these additional assets that will be contributed to us at the consummation of this offering have not been audited and therefore are not presented in the pro forma cash available for distribution for the year ended December 31, 2015 and the twelve months ended September 30, 2016.

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Kimbell Royalty Partners, LP
Pro Forma Cash Available for Distribution

 
  Year Ended
December 31,
2015
  Twelve Months
Ended
September 30,
2016
 

Revenue:

             

Oil, natural gas and NGL revenues

  $ 26,691,028   $ 21,096,031  

Costs and Expenses

             

Production and ad valorem taxes

    2,199,404     1,989,121  

Depreciation and depletion expenses

    18,164,181     14,165,486  

Impairment of oil and natural gas properties

    27,749,669     7,751,957  

Marketing and other deductions (1)

    1,271,104     1,429,759  

General and administrative expenses

    5,079,796     5,051,218  

Total costs and expenses

  $ 54,464,154   $ 30,387,541  

Operating loss

  $ (27,773,126 ) $ (9,291,510 )

Other expense:

             

Interest expense (2)

    308,343     308,343  

Pro forma net loss (3)

  $ (28,081,469 ) $ (9,599,853 )

Adjustments to reconcile to pro forma Adjusted EBITDA:

             

Depreciation and depletion expenses

    18,164,181     14,165,486  

Impairment of oil and natural gas properties

    27,749,669     7,751,957  

Interest expense (2)

    308,343     308,343  

Adjusted EBITDA (4)

  $ 18,140,724   $ 12,625,933  

Adjustments to reconcile pro forma Adjusted EBITDA to cash available for distribution:

             

Less:

             

Incremental general and administrative expenses (5)

    (1,471,000 )   (1,471,000 )

Cash interest expense (2)

    (286,808 )   (286,808 )

Capital expenditures (6)

    (42,000 )    

Cash available for distribution

  $ 16,340,916   $ 10,868,125  

Cash reserves

         

Aggregate distributions to:

             

Common units held by the public

             

Common units held by the Contributing Parties

             

Total distributions on common units

  $     $    

(1)
Includes the reclassification of our predecessor's state income taxes into marketing and other deductions of ($32,199) and $11,557 for the year ended December 31, 2015 and for the twelve months ended September 30, 2016, respectively.

(2)
Interest expense is based on expected borrowings of $1.5 million at the closing of this offering to fund certain transaction expenses, inclusive of cash expenses of commitment fees and non-cash amortization of debt issuance costs. Cash interest expense does not include non-cash amortization of debt issuance costs.

(3)
Net loss for the year ended December 31, 2015 gives effect to the pro forma adjustments reflected in our unaudited pro forma condensed combined financial statements included elsewhere is this prospectus.

(4)
Adjusted EBITDA is a financial measure not presented in accordance with U.S. GAAP. For a definition of Adjusted EBITDA and reconciliation to its most directly comparable financial measure calculated in accordance with U.S.

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    GAAP, please read "Summary—Summary Historical and Unaudited Pro Forma Condensed Combined Financial Data—Non-GAAP Financial Measures."

(5)
Reflects incremental general and administrative expenses that we expect to incur as a result of operating as a publicly traded partnership that are not reflected in our pro forma financial statements.

(6)
Our capital expenditures during 2015 were funded with cash from operating activities. Historically, we did not make a distinction between maintenance capital expenditures and expansion capital expenditures. 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, over the long term, working interest owners will continue to develop our acreage through infill drilling, hydraulic fracturing, recompletions and secondary and tertiary recovery methods, 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.

Estimated Cash Available for Distribution for the Twelve Months Ending December 31, 2017

        During the twelve months ending December 31, 2017, we estimate that we will generate $24.6 million of cash available for distribution. In "—Assumptions and Considerations" below, we discuss the major assumptions underlying this estimate. The cash available for distribution discussed in the forecast should not be viewed as management's projection of the actual cash available for distribution that we will generate during the twelve months ending December 31, 2017. 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 cash available for distribution, 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 $24.6 million of cash available for distribution for the twelve months ending December 31, 2017. 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, financial, regulatory, environmental and competitive risks and uncertainties that could cause actual results to differ materially from those contained in the prospective financial information. Accordingly, there can be no assurance that the prospective results are indicative of our future performance or that actual results will not differ materially from those presented in

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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 December 31, 2017 should not be regarded as a representation by us or the underwriters or any other person that we will pay 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 December 31, 2017. The assumptions that we believe are relevant to particular line items in the table below are explained in the corresponding footnotes and in "—Assumptions and Considerations."

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

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        The following table illustrates the amount of cash available for distribution that we estimate that we will generate for the twelve months ending December 31, 2017 and for each quarter during that twelve-month period that would be available for distribution to our unitholders. All of the amounts for the twelve months ending December 31, 2017 in the table below are estimates and include the assets to be contributed to us at the consummation of this offering.


Kimbell Royalty Partners, LP
Estimated Cash Available for Distribution
(Unaudited)

 
  Three Months
Ending
March 31,
2017
  Three Months
Ending
June 30,
2017
  Three Months
Ending
September 30,
2017
  Three Months
Ending
December 31,
2017
  Twelve
Months
Ending
December 31,
2017
 

Revenue:

                               

Oil, natural gas and NGL revenues

  $ 9,429,875   $ 9,224,287   $ 8,995,004   $ 8,935,872   $ 36,585,038  

Cost and expenses:

                               

Production and ad valorem taxes

    679,051     662,321     647,396     643,259     2,632,027  

Depreciation and depletion expenses

    3,384,449     3,296,540     3,214,621     3,203,057     13,098,667  

Marketing and other deductions

    680,192     664,843     641,812     638,359     2,625,206  

General and administrative expenses (1)

    1,618,753     1,618,753     1,618,753     1,618,753     6,475,012  

Total costs and expenses

  $ 6,362,445   $ 6,242,457   $ 6,122,582   $ 6,103,428   $ 24,830,912  

Operating income

  $ 3,067,430   $ 2,981,830   $ 2,872,422   $ 2,832,444   $ 11,754,126  

Other expense:

                               

Interest expense (2)

    87,327     87,327     87,327     87,327     349,308  

Net Income

  $ 2,980,103   $ 2,894,503   $ 2,785,095   $ 2,745,117   $ 11,404,818  

Adjustments to reconcile to pro forma Adjusted EBITDA:

                               

Depreciation and depletion expenses

    3,384,449     3,296,540     3,214,621     3,203,057     13,098,667  

Interest expense (2)

    87,327     87,327     87,327     87,327     349,308  

Adjusted EBITDA (3)

  $ 6,451,879   $ 6,278,370   $ 6,087,043   $ 6,035,500   $ 24,852,793  

Adjustments to reconcile Adjusted EBITDA to cash available for distribution:

                               

Cash interest expense (2)

    71,702     71,702     71,702     71,702     286,808  

Capital expenditures (4)

                     

Cash available for distribution

  $ 6,380,177   $ 6,206,668   $ 6,015,341   $ 5,963,798   $ 24,565,985  

Cash reserves

                     

Aggregate distributions to:

                               

Common units held by the public

                               

Common units held by the Contributing Parties

                               

Total distributions on common units

  $     $     $     $     $    

(1)
Includes the $1.5 million in incremental general and administrative expenses that we expect to incur as a result of operating as a publicly traded partnership that are not reflected in our pro forma financial statements. Please read "—Assumptions and Considerations."

(2)
Interest expense is based on expected borrowings of $1.5 million at the closing of this offering to fund certain transaction expenses, inclusive of cash expenses of commitment fees and non-cash amortization of debt issuance costs. Cash interest expense does not include non-cash amortization of debt issuance costs.

(3)
Adjusted EBITDA is a financial measure not presented in accordance with U.S. GAAP. For a definition of Adjusted EBITDA and reconciliation to its most directly comparable financial measure calculated in accordance with U.S. GAAP, please read

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    "Summary—Summary Historical and Unaudited Pro Forma Condensed Combined Financial Data—Non-GAAP Financial Measures."

(4)
Historically, we did not make a distinction between maintenance capital expenditures and expansion capital expenditures. 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, over the long term, working interest owners will continue to develop our acreage through infill drilling, hydraulic fracturing, recompletions and secondary and tertiary recovery methods, 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. This would reduce the amount of cash available for distribution.

Assumptions and Considerations

        Based upon the specific assumptions outlined below, we expect to generate cash available for distribution in an amount sufficient to allow us to pay $             per common unit on all of our outstanding units for the twelve months ending December 31, 2017.

        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.

General Considerations

        Substantially all of the anticipated increase in our estimated distributable cash flow for the twelve months ending December 31, 2017, compared to the pro forma year ended December 31, 2015 and the pro forma twelve months ended September 30, 2016, is primarily attributable to:

        Assets from Contributing Parties not reflected in pro forma financial statements.    Our estimate of cash available for distribution for the twelve months ending December 31, 2017 includes the additional assets that will be contributed to us at the consummation of this offering and which have not been audited and therefore are not presented in the pro forma cash available for distribution for the year ended December 31, 2015 and the twelve months ended September 30, 2016. These additional assets represent approximately 25% of our future undiscounted cash flows, based on the reserve report prepared by Ryder Scott as of December 31, 2015. During the year ended December 31, 2015 and the twelve months ended September 30, 2016, the operators on the properties reflected in our pro forma financial statements produced volumes of 917,751 Boe and 904,921 Boe, respectively, compared to our forecast of 1,076,524 Boe for the twelve months ending December 31, 2017. The volume increase reflected in the forecast compared to the year ended December 31, 2015 and the twelve months

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ended September 30, 2016 is 17.3% and 19.0%, respectively. The volume increase for these periods is primarily attributable to the addition of the assets discussed above offset by a slight decline in forecasted volumes attributable to both the additional assets and those reflected in the pro forma financial statements.

        Commodity prices.    During the year ended December 31, 2015 and the twelve months ended September 30, 2016, our average realized price per Boe was $29.08 and $23.31, respectively, compared to the estimated weighted average NYMEX strip price of $33.98 per Boe for the twelve months ending December 31, 2017 as of December 27, 2016, based on our forecasted production volumes. Our average realized price per Boe gives effect to the differentials between published oil and natural gas prices and the prices actually received for the oil and natural gas production. These differentials may vary significantly due to market conditions, transportation, gathering and processing costs, quality of production and other factors. The price increase reflected in the forecast compared to the year ended December 31, 2015 and the twelve months ended September 30, 2016 is 16.9% and 45.8%, respectively.

        Cash available for distribution.    We estimate an $8.2 million increase in cash available for distribution for the twelve months ending December 31, 2017 as compared to the year ended December 31, 2015. The 17.3% increase in production volumes accounts for $4.6 million of the increase and the 16.9% increase in estimated price per Boe accounts for $5.3 million, offset by $1.4 million in estimated increased marketing and other deductions and $0.4 million in estimated increased production and ad valorem taxes. We do not expect the addition of our other assets at the consummation of this offering from the other Contributing Parties to result in significant additional general and administrative expenses because these Contributing Parties have invested in substantially the same assets as those that are reflected in our pro forma financial statements, and therefore the management and administration of these properties is not expected to burden our general and administrative expenses in a significant manner.

        We estimated a $13.7 million increase in cash available for distribution for the twelve months ending December 31, 2017 when compared to the twelve months ended September 30, 2016. The increase was primarily attributable to the 19.0% increase in production volumes which accounted for $4.0 million of the increase and the 45.8% increase in price per Boe accounted for $11.5 million, offset by $1.2 million in increased marketing and other deductions and $0.6 million in increased production and ad valorem taxes.

Operations and Revenue

        Oil, natural gas and natural gas liquids revenues.    Substantially all our revenues are a function of oil, natural gas and natural gas liquids production volumes sold and average prices received for those volumes. Based on the production and pricing information included below, we estimate that our oil, natural gas and natural gas liquids revenues for the twelve months ending December 31, 2017 will be $36.6 million. For information on the effect of changes in prices and productions volumes, please read "—Sensitivity Analysis."

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        Production.    The following table sets forth information regarding production on the properties underlying our interests for the twelve months ended December 31, 2015, September 30, 2016 and for the twelve months ending December 31, 2017:

 
  Twelve Months Ended   Twelve
Months
Ending
 
 
  December 31,
2015
  September 30,
2016
  December 31,
2017
 

Production:

                   

Oil (Bbls)

    363,346     346,373     413,424  

Natural Gas (Mcf)

    2,573,681     2,670,300     3,270,301  

Natural gas liquids (Bbls)

    125,458     113,497     118,049  

Combined volumes (BOE)

    917,751     904,921     1,076,524  

Average daily production:

   
 
   
 
   
 
 

Oil (Bbl/d)

    995     946     1,133  

Natural gas (Mcf/d)

    7,051     7,296     8,960  

Natural gas liquids (Bbl/d)

    344     310     323  

Combined volumes (BOE/d)

    2,514     2,472     2,949  

        We estimate that oil and natural gas production from the properties underlying our interests for the twelve months ending December 31, 2017 will be 1,077 MBOE. We estimate the average daily production for the three months ending March 31, 2017, June 30, 2017, September 30, 2017 and December 31, 2017, will be 3,091 BOE/d, 2,977 BOE/d, 2,872 BOE/d and 2,861 BOE/d, respectively.

        We own a diversified portfolio of interests in oil and natural gas properties. Substantially all our revenues are a function of oil and natural gas production volumes sold and average prices received for those volumes. Our forecasted production is derived from existing wells on our assets and from new wells projected to begin producing during the year. Although we lack the influence of a working interest partner in the drilling schedule for PUD locations, we are able to forecast a drilling schedule for PUD reserves based on a multi-factor analysis, which we believe provides a reasonable basis for our estimations. As part of this multi-factor analysis, we obtain information from state regulatory agencies and third-party sources regarding production data on a well-by-well basis for each basin and play in which we own assets, including updates on each well's status throughout the drilling process. We examine this information on an acquisition-by-acquisition basis and devote resources to our analysis in proportion to the relative size of the acquisitions. We also review information regarding permits granted to our operators and rig activity and location on our acreage, in each case prioritizing review of our most significant operators and locations. Our ability to monitor permit trends, rig activity and rig location on our acreage is a critical component of our analysis. On a basin and play-wide perspective, we are able to determine where our operators deploy their assets by reviewing, among other things, our operators' publicly announced allotment of capital expenditures, proposed number of new wells drilled each year and additional spacing testing. Access to this information, including permits granted, wells spudded, wells drilled to total depth and wells completed and waiting for first connection, enables us to track well development through all phases of exploration and production on the acreage in each basin and play in which we own an interest.

        We also review investor presentations and other public statements of our operators before booking undeveloped reserves and have general discussions with what we believe to be a

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representative sampling of our operators to ascertain their reserve booking plans. On a pro forma basis for the year ended December 31, 2015, our top ten operators accounted for approximately 53.3% of our revenue. Information regarding reserve booking plans was gathered for all of these operators. We believe that the public statements and guidance by the operators of our acreage regarding future drilling activity, coupled with the historical information we gather, enable us to forecast a drilling schedule for PUD locations.

        Prices.    The table below illustrates the relationship between average realized sales prices and the estimated weighted average of the monthly NYMEX strip prices as of December 27, 2016 for the twelve months ending December 31, 2017 (held constant throughout the period):

Forecasted average oil sales prices:

       

NYMEX-WTI oil price per Bbl

  $ 55.97  

Differential to NYMEX-WTI oil per Bbl (1)

  $ (4.67 )

Realized oil sales price per Bbl

  $ 51.30  

Forecasted average natural gas liquids sales prices:

   
 
 

NYMEX-WTI oil price per Bbl

  $ 55.97  

Differential to NYMEX-WTI oil per Bbl (1)

  $ (34.93 )

Realized natural gas liquids sales price per Bbl

  $ 21.04  

Forecasted average natural gas sales prices:

   
 
 

NYMEX-Henry Hub per price MMBtu

  $ 3.61  

Differential to NYMEX-Henry Hub natural gas (1)

  $ 0.33  

Realized natural gas sales price per Mcf

  $ 3.94  

Total weighted average combined realized price (per BOE)

 
$

33.98
 

(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 December 31, 2017:

Production taxes

  $ 1,653  

Ad valorem taxes

  $ 979  

Total production and ad valorem taxes

  $ 2,632  

Production and ad valorem taxes as a percentage of revenue

    7.2%  

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

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valuation of the underlying reserves generally fluctuate with the price, therefore, the cost of ad valorem taxes generally correlate to the changes in oil, natural gas and NGL revenues.

        Depreciation and depletion expenses.    We estimate that our depreciation and depletion expenses for the twelve months ending December 31, 2017 will be $13.1 million. The forecasted depreciation and depletion expense is based on the production estimates in our reserve reports. The per BOE depletion rate is $12.17.

        Marketing and other deductions.    We estimate that our marketing and other deductions for the twelve months ending December 31, 2017 will be $2.6 million. The forecasted marketing and other deductions is based on our historical marketing and other deductions applied to our forecasted production, which is based on our reserve reports.

        General and administrative expenses.    We estimate that our general and administrative expenses for the twelve months ending December 31, 2017 will be $6.5 million, including $2.1 million owed pursuant to the terms of service agreements with Kimbell Operating and affiliates of our Sponsors and an incremental $1.5 million of general and administrative expenses we expect to incur as a result of becoming a publicly traded partnership.

        Interest expense.    We estimate that we will have $349,308 in interest expense for the twelve months ending December 31, 2017. The new $50.0 million secured revolving credit facility we expect to enter into in connection with the closing of this offering is forecasted to have $1.5 million of borrowings outstanding, which we expect to use to fund certain transaction expenses at the closing of this offering. We will incur a commitment fee of $242,500 and amortization of deferred finance costs of $62,500.

Financing

        At the closing of this offering, we expect to enter into a $50.0 million secured revolving credit facility with an accordion feature permitting aggregate commitments under the facility to be increased up to $100.0 million (subject to the satisfaction of certain conditions and the procurement of additional commitments from new or existing lenders). We expect that the unused portion of the secured revolving credit facility will be subject to a commitment fee equal to 50 basis points.

Capital Expenditures

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

Regulatory, Industry and Economic Factors

        Our forecast for the twelve months ending December 31, 2017 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;

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

    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 December 31, 2017 of $              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 December 31, 2017 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 December 31, 2017.

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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 December 31, 2017.

 
  Percentage of Forecasted Annual
Production
 

Forecasted annual production:

    90 %   100 %   110 %

Oil (Bbls)

    372,082     413,424     454,767  

Natural Gas (Mcf)

    2,943,271     3,270,301     3,597,332  

Natural gas liquids (Bbls)

    106,244     118,049     129,854  

Combined volumes (BOE)

    968,871     1,076,524     1,184,176  

Forecasted average daily production:

   
 
   
 
   
 
 

Oil (Bbl/d)

    1,019     1,133     1,246  

Natural gas (Mcf/d)

    8,064     8,960     9,856  

Natural gas liquids (Bbl/d)

    291     323     356  

Combined volumes (BOE/d)

    2,654     2,949     3,244  

Forecasted average oil sales prices:

   
100

%
 
100

%
 
100

%

NYMEX-WTI oil price per Bbl

  $ 55.97   $ 55.97   $ 55.97  

Realized oil sales price per Bbl

  $ 51.30   $ 51.30   $ 51.30  

NYMEX-WTI oil price per Bbl

 
$

55.97
 
$

55.97
 
$

55.97
 

Realized natural gas liquids sales price per Bbl

  $ 21.04   $ 21.04   $ 21.04  

Forecasted average natural gas sales prices:

   
 
   
 
   
 
 

NYMEX-Henry Hub natural gas price per MMBtu

  $ 3.61   $ 3.61   $ 3.61  

Realized natural gas sales price per Mcf

  $ 3.94   $ 3.94   $ 3.94  

Revenue:

   
 
   
 
   
 
 

Oil, natural gas and NGL revenues

  $ 32,926   $ 36,585   $ 40,243  

Cost and expenses:

   
 
   
 
   
 
 

Production and ad valorem taxes

    2,369     2,632     2,895  

Depreciation and depletion expenses

    11,789     13,099     14,409  

Marketing and other deductions

    2,363     2,625     2,888  

General and administrative expenses (1)

    6,475     6,475     6,475  

Total costs and expenses

  $ 22,996   $ 24,831   $ 26,667  

Operating income

  $ 9,930   $ 11,754   $ 13,576  

Other expense:

   
 
   
 
   
 
 

Interest expense (2)

    349     349     349  

Net Income

  $ 9,581   $ 11,405   $ 13,227  

Adjustments to reconcile to pro forma Adjusted EBITDA:

                   

Depreciation and depletion expenses

    11,789     13,099     14,409  

Interest expense (2)

    349     349     349  

Adjusted EBITDA (3)

  $ 21,719   $ 24,853   $ 27,985  

Adjustments to reconcile Adjusted EBITDA to cash available for distribution:

                   

Cash interest expense (2)

    287     287     287  

Capital expenditures

             

Cash available for distribution

  $ 21,432   $ 24,566   $ 27,698  

Cash reserves

             

Aggregate distributions to:

                   

Common units held by the public

                   

Common units held by the Contributing Parties

                   

Total distributions on common units

                   

(1)
Includes the $1.5 million in incremental general and administrative expenses that we expect to incur as a result of operating as a publicly traded partnership that are not reflected in our pro forma financial statements. Please read "—Assumptions and Considerations."

(2)
Interest expense is based on expected borrowings of $1.5 million at the closing of this offering to fund certain transaction expenses, inclusive of cash expenses of commitment fees and non-cash amortization of debt issuance costs. Cash interest expense does not include non-cash amortization of debt issuance costs.

(3)
Adjusted EBITDA is a financial measure not presented in accordance with U.S. GAAP. For a definition of Adjusted EBITDA and reconciliation to its most directly comparable financial measure calculated in accordance with U.S. GAAP, please read "Summary—Summary Historical and Unaudited Pro Forma Condensed Combined Financial Data—Non-GAAP Financial Measures."

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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 December 31, 2017. 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)

    413,424     413,424     413,424  

Natural Gas (Mcf)

    3,270,301     3,270,301     3,270,301  

Natural gas liquids (Bbls)

    118,049     118,049     118,049  

Combined volumes (BOE)

    1,076,524     1,076,524     1,076,524  

Forecasted average daily production:

   
 
   
 
   
 
 

Oil (Bbl/d)

    1,133     1,133     1,133  

Natural gas (Mcf/d)

    8,960     8,960     8,960  

Natural gas liquids (Bbl/d)

    323     323     323  

Combined volumes (BOE/d)

    2,949     2,949     2,949  

 

 
  Percentage Change in Commodity Price  

Forecasted average oil sales prices:

    90 %   100 %   110 %

NYMEX-WTI oil price per Bbl

  $ 50.37   $ 55.97   $ 61.57  

Realized oil sales price per Bbl

  $ 46.17   $ 51.30   $ 56.42  

NYMEX-WTI oil price per Bbl

 
$

50.37
 
$

55.97
 
$

61.57
 

Realized natural gas liquids sales price per Bbl

  $ 18.93   $ 21.04   $ 23.14  

Forecasted average natural gas sales prices:

   
 
   
 
   
 
 

NYMEX-Henry Hub natural gas price per MMBtu

  $ 3.25   $ 3.61   $ 3.97  

Realized natural gas sales price per Mcf

  $ 3.55   $ 3.94   $ 4.34  

Revenue:

   
 
   
 
   
 
 

Oil, natural gas and NGL revenues

  $ 32,926   $ 36,585   $ 40,243  

Cos