Kimbell Royalty Partners, LP - Annual Report: 2016 (Form 10-K)

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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

x ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended: December 31, 2016

o TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from to

Commission file number: 001-38005

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)

Securities registered pursuant to Section 12(b) of the Exchange Act:

Title of class		Name of each exchange on which registered
Common Units Representing Limited Partner Interests		New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Exchange Act: None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes o No x

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Act. Yes o No x

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes o No x

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes x No o

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. x

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 x
(Do not check if a
smaller reporting company)

Smaller reporting company o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No x

As of June 30, 2016, the last business day of the registrant’s most recently completed second quarter, the registrant’s equity was not listed on a domestic exchange or over-the-counter market. The registrant’s common units began trading on the New York Stock Exchange on February 3, 2017.

As of March 29, 2017, 16,332,708 common units of the registrant were outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

None

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Kimbell Royalty Partners, LP

TABLE OF CONTENTS

Glossary of Oil and Natural Gas Terms	2
PART 1	8
Item 1. Business	8
Item 1A. Risk Factors	30
Item 1B. Unresolved Staff Comments	60
Item 2. Properties	61
Item 3. Legal Proceedings	61
Item 4. Mine Safety Disclosures	61

PART II	62
Item 5. Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities	62
Item 6. Selected Financial Data	64
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations	67
Item 7A. Quantitative and Qualitative Disclosures about Market Risk	81
Item 8. Financial Statements and Supplementary Data	82
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	82
Item 9A. Controls and Procedures	82
Item 9B. Other Information	83

PART III	83
Item 10. Directors, Executive Officers and Corporate Governance	83
Item 11. Executive Compensation	87
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters	91
Item 13. Certain Relationships and Related Transactions, and Director Independence	94
Item 14. Principal Accounting Fees and Services	101

PART IV	102
Exhibit Index	102
Signatures	104

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GLOSSARY OF TERMS

The following are definitions of certain terms used in this Annual Report.

Available cash. For any quarter ending prior to liquidation:

(a) the sum of:

(1) all cash and cash equivalents of Kimbell Royalty Partners, LP and its subsidiaries on hand at the end of that quarter; and

(2) as determined by the general partner of Kimbell Royalty Partners, LP, all cash or cash equivalents of Kimbell Royalty Partners, LP and its subsidiaries on hand on the date of determination of available cash for that quarter resulting from working capital borrowings made after the end of that quarter;

(b) less the amount of cash reserves established by the general partner of Kimbell Royalty Partners, LP to:

(1) provide for the proper conduct of the business of Kimbell Royalty Partners, LP and its subsidiaries (including reserves for future capital expenditures and for future credit needs of Kimbell Royalty Partners, LP and its subsidiaries) after that quarter;

(2) comply with applicable law or any debt instrument or other agreement or obligation to which Kimbell Royalty Partners, LP or any of its subsidiaries is a party or its assets are subject; and

(3) provide funds for distributions for any one or more of the next four quarters; provided, however, that disbursements made by Kimbell Royalty Partners, LP or any of its subsidiaries or cash reserves established, increased or reduced after the end of that quarter but on or before the date of determination of available cash for that quarter shall be deemed to have been made, established, increased or reduced, for purposes of determining available cash, within that quarter if the general partner of Kimbell Royalty Partners, LP so determines.

Notwithstanding the foregoing, “available cash” with respect to the quarter in which the liquidation date occurs and any subsequent quarter shall equal zero.

Basin. A large depression on the earth’s surface in which sediments accumulate.

Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume.

Boe. Barrels of oil equivalent, with six thousand cubic feet of natural gas being equivalent to one barrel of oil.

Boe/d. Boe per day.

British Thermal Unit (Btu). The quantity of heat required to raise the temperature of one pound of water by one degree Fahrenheit.

Completion. The process of treating a drilling well followed by the installation of permanent equipment for the production of natural gas or oil, or in the case of a dry hole, the reporting of abandonment to the appropriate agency.

Condensate. Liquid hydrocarbons associated with the production of a primarily natural gas reserve.

Crude oil. Liquid hydrocarbons retrieved from geological structures underground to be refined into fuel sources.

Deterministic method. The method of estimating reserves or resources under which a single value for each parameter (from the geoscience, engineering, or economic data) in the reserves calculation is used in the reserves estimation procedure.

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Developed acreage. The number of acres that are allocated or assignable to productive wells or wells capable of production.

Development costs. Capital costs incurred in the acquisition, exploitation and exploration of proved oil and natural gas reserves divided by proved reserve additions and revisions to proved reserves.

Development well. A well drilled within the proved area of an oil and natural gas reservoir to the depth of a stratigraphic horizon known to be productive.

Differential. An adjustment to the price of oil or natural gas from an established spot market price to reflect differences in the quality and/or location of oil or natural gas.

Dry hole or dry well. A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes.

Economically producible. A resource that generates revenue that exceeds, or is reasonably expected to exceed, the costs of the operation.

Electrical log. Provide information on porosity, hydraulic conductivity, and fluid content of formations drilled in fluid-filled boreholes.

Exploration. A drilling or other project which may target proven or unproven reserves (such as probable or possible reserves).

Extension well. A well drilled to extend the limits of a known reservoir.

Field. An area consisting of either a single reservoir or multiple reservoirs, all grouped on or related to the same individual geological structural feature and/or stratigraphic condition.

Formation. A layer of rock which has distinct characteristics that differs from nearby rock.

Fracturing. The process of creating and preserving a fracture or system of fractures in a reservoir rock typically by injecting a fluid under pressure through a wellbore and into the targeted formation.

Gross acres or gross wells. The total acres or wells, as the case may be, in which a working interest is owned.

Horizontal drilling. A drilling technique used in certain formations where a well is drilled vertically to a certain depth and then drilled at a right angle within a specified interval.

Hydraulic fracturing. A process used to stimulate production of hydrocarbons. The process involves the injection of water, sand, and chemicals under pressure into the formation to fracture the surrounding rock and stimulate production.

Lease bonus. Usually a one-time payment made to a mineral owner as consideration for the execution of an oil and natural gas lease.

Lease operating expense. All direct and allocated indirect costs of lifting hydrocarbons from a producing formation to the surface constituting part of the current operating expenses of a working interest. Such costs include labor, superintendence, supplies, repairs, maintenance, allocated overhead charges, workover, insurance, and other expenses incidental to production, but exclude lease acquisition or drilling or completion expenses.

MBbl/d. MBbl per day.

MBbls. One thousand barrels of oil or other liquid hydrocarbons.

MBoe. One thousand barrels of oil equivalent, determined using a ratio of six Mcf of natural gas to one Bbl of oil.

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Mcf. One thousand cubic feet of natural gas.

Mineral interests. Real-property interests that grant ownership of the oil and natural gas under a tract of land and the rights to explore for, drill for, and produce oil and natural gas on that land or to lease those exploration and development rights to a third party.

MMBtu. One million British Thermal Units.

MMcf. One million cubic feet of natural gas.

Net acres. The sum of the fractional working interest owned in gross acres.

Net revenue interest. An owner’s interest in the revenues of a well after deducting proceeds allocated to royalty, overriding royalty and other non-cost-bearing interests.

Natural gas. A combination of light hydrocarbons that, in average pressure and temperature conditions, is found in a gaseous state. In nature, it is found in underground accumulations, and may potentially be dissolved in oil or may also be found in its gaseous state.

Natural gas liquids or NGLs. Hydrocarbons found in natural gas which may be extracted as liquefied petroleum gas and natural gasoline.

Nonparticipating royalty interest. A type of non-cost-bearing royalty interest, which is carved out of the mineral interest and represents the right, which is typically perpetual, to receive a fixed cost-free percentage of production or revenue from production, without an associated right to lease.

Oil. Crude oil and condensate.

Oil and natural gas properties. Tracts of land consisting of properties to be developed for oil and natural gas resource extraction.

Operator. The individual or company responsible for the exploration and/or production of an oil or natural gas well or lease. Refers to the operator of record and any lessor or working interest holder for which the operator is acting.

Overriding royalty interest or ORRI. A fractional, undivided interest or right of participation in the oil or natural gas, or in the proceeds from the sale of the oil or gas, produced from a specified tract or tracts, which are limited in duration to the terms of an existing lease and which are not subject to any portion of the expense of development, operation or maintenance.

Pad drilling. The practice of drilling multiple wellbores from a single surface location.

PDP. Proved developed producing.

Play. A set of discovered or prospective oil and/or natural gas accumulations sharing similar geologic, geographic and temporal properties, such as source rock, reservoir structure, timing, trapping mechanism and hydrocarbon type.

Plugging and abandonment. Refers to the sealing off of fluids in the strata penetrated by a well so that the fluids from one stratum will not escape into another or to the surface. Regulations of all states require plugging of abandoned wells.

Pooling. The majority of our producing acreage is pooled with third-party acreage. Pooling refers to an operator’s consolidation of multiple adjacent leased tracts, which may be covered by multiple leases with multiple lessors, in order to maximize drilling efficiency or to comply with state mandated well spacing requirements. Pooling dilutes our royalty in a given well or unit, but it also increases both the acreage footprint and the number of wells in which we have an economic interest. To estimate our total potential drilling locations in a given play, we include third-party acreage that is pooled with our acreage.

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Production costs. The production or operational costs incurred while extracting and producing, storing, and transporting oil and/or natural gas. Typical of these costs are wages for workers, facilities lease costs, equipment maintenance, logistical support, applicable taxes and insurance.

PUD. Proved undeveloped.

Productive well. A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of the production exceed production expenses and taxes.

Prospect. A specific geographic area which, based on supporting geological, geophysical or other data and also preliminary economic analysis using reasonably anticipated prices and costs, is deemed to have potential for the discovery of commercial hydrocarbons.

Proved developed reserves. Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.

Proved developed producing reserves. Reserves expected to be recovered from existing completion intervals in existing wells.

Proved reserves. The estimated quantities of oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be commercially recoverable in future years from known reservoirs under existing economic and operating conditions.

Proved undeveloped reserves. Proved reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion.

Recompletion. The process of re-entering an existing wellbore that is either producing or not producing and completing new reservoirs in an attempt to establish or increase existing production.

Reserves. Reserves are estimated remaining quantities of oil and natural gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and natural gas or related substances to the market and all permits and financing required to implement the project. Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).

Reservoir. A porous and permeable underground formation containing a natural accumulation of producible natural gas and/or oil that is confined by impermeable rock or water barriers and is separate from other reservoirs.

Resource play. A set of discovered or prospective oil and/or natural gas accumulations sharing similar geologic, geographic and temporal properties, such as source rock, reservoir structure, timing, trapping mechanism and hydrocarbon type.

Royalty interest. An interest that gives an owner the right to receive a portion of the resources or revenues without having to carry any costs of development.

SCOOP. South Central Oklahoma Oil Province.

Seismic data. Seismic data is used by scientists to interpret the composition, fluid content, extent, and geometry of rocks in the subsurface. Seismic data is acquired by transmitting a signal from an energy source, such as dynamite or water, into the earth. The energy so transmitted is subsequently reflected beneath the earth’s surface and a receiver is used to collect and record these reflections.

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Shale. A fine grained sedimentary rock formed by consolidation of clay- and silt-sized particles into thin, relatively impermeable layers. Shale can include relatively large amounts of organic material compared with other rock types and thus has the potential to become rich hydrocarbon source rock. Its fine grain size and lack of permeability can allow shale to form a good cap rock for hydrocarbon traps.

Spacing. The distance between wells producing from the same reservoir. Spacing is often expressed in terms of acres, e.g., 40-acre spacing, and is often established by regulatory agencies.

STACK. Sooner Trend, Anadarko Basin, Canadian and Kingfisher counties, Oklahoma.

Standardized measure. The present value of estimated future net revenue to be generated from the production of proved reserves, determined in accordance with the rules and regulations of the SEC (using prices and costs in effect as of the date of estimation), less future development, production and income tax expenses, and discounted at 10% per annum to reflect the timing of future net revenue. Because we are a limited partnership, we are generally not subject to federal or state income taxes and thus make no provision for federal or state income taxes in the calculation of our standardized measure. Standardized measure does not give effect to derivative transactions.

Tight formation. A formation with low permeability that produces natural gas with low flow rates for long periods of time.

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

Wellbore. The hole drilled by the bit that is equipped for oil or natural gas production on a completed well.

Working interest. An operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and receive a share of production and requires the owner to pay a share of the costs of drilling and production operations.

WTI. West Texas Intermediate oil, which is a light, sweet crude oil, characterized by an American Petroleum Institute gravity, of API gravity, between 39 and 41 and a sulfur content of approximately 0.4 weight percent that is used as a benchmark for the other crude oils.

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Cautionary Statement Regarding Forward-Looking Statements

Certain statements and information in this Annual Report may constitute forward-looking statements. Forward-looking statements give our current expectations, contain projections of results of operations or of financial condition, or forecasts of future events. Words such as “may,” “assume,” “forecast,” “position,” “predict,” “strategy,” “expect,” “intend,” “plan,” “estimate,” “anticipate,” “believe,” “project,” “budget,” “potential,” or “continue,” and similar expressions are used to identify forward-looking statements. They can be affected by assumptions used or by known or unknown risks or uncertainties. Consequently, no forward-looking statements can be guaranteed. When considering these forward-looking statements, you should keep in mind the risk factors and other cautionary statements in this Annual Report. Actual results may vary materially. You are cautioned not to place undue reliance on any forward-looking statements. You should also understand that it is not possible to predict or identify all such factors and should not consider the following list to be a complete statement of all potential risks and uncertainties. Factors that could cause our actual results to differ materially from the results contemplated by such forward-looking statements include:

· our ability to execute our business strategies;

· the volatility of realized prices for oil, natural gas and natural gas liquids;

· the level of production on our properties;

· the level of drilling and completion activity by the operators of our properties;

· regional supply and demand factors, delays or interruptions of production;

· our ability to replace our reserves;

· our ability to identify and complete acquisitions of assets or businesses;

· general economic, business or industry conditions;

· competition in the oil and natural gas industry;

· the ability of the operators of our properties to obtain capital or financing needed for development and exploration operations;

· title defects in the properties in which we invest;

· uncertainties with respect to identified drilling locations and estimates of reserves;

· the availability or cost of rigs, completion crews, equipment, raw materials, supplies, oilfield services or personnel;

· restrictions on or the availability of the use of water in the business of the operators of our properties;

· the availability of transportation facilities;

· the ability of the operators of our properties to comply with applicable governmental laws and regulations and to obtain permits and governmental approvals;

· federal and state legislative and regulatory initiatives relating to the environment, hydraulic fracturing and other matters affecting the oil and gas industry;

· future operating results;

· exploration and development drilling prospects, inventories, projects and programs;

· operating hazards faced by the operators of our properties;

· the ability of the operators of our properties to keep pace with technological advancements; and

· certain factors discussed elsewhere in this report.

All forward-looking statements are expressly qualified in their entirety by the foregoing cautionary statements.

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PART 1

Unless the context otherwise requires, references 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 contributed, directly or indirectly, certain mineral and royalty interests to us. References to “our predecessor” refer to Rivercrest Royalties, LLC, our predecessor for accounting and financial reporting purposes. References to “Kimbell Operating” refer to Kimbell Operating Company, LLC, a wholly owned subsidiary of our general partner, which entered into separate service agreements with certain entities controlled by affiliates of our Sponsors and Benny D. Duncan as described herein.

On February 8, 2017, we completed our initial public offering of 5,750,000 common units representing limited partner interests, which included 750,000 common units pursuant to the underwriters’ option to purchase additional common units. Concurrently with the closing of our initial public offering, the mineral and royalty interests making up our initial assets were contributed to us by the Contributing Parties. As a result, as of December 31, 2016, Kimbell Royalty Partners, LP had not yet acquired any of such assets. Unless otherwise indicated, the historical financial information presented in this report is solely that of our predecessor, Rivercrest Royalties, LLC. However, unless otherwise indicated, the reserve and operational data presented in this report is with respect to all the assets that were contributed to us by the Contributing Parties in connection with our IPO. Operational data that is presented as of a date prior to February 8, 2017, it is presented on a combined basis as if the contribution of the assets had already occurred.

Item 1. Business

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.

We completed our initial public offering on February 8, 2017. In connection with the closing of our initial public offering, we acquired all of our initial assets. As a result, we did not own any of our initial assets, including those of our predecessor, prior to February 8, 2017. We will make our first quarterly distribution within 45 days after the quarter ending March 31, 2017. We will adjust the amount of that distribution for the period from the closing of our initial public offering through March 31, 2017, based on the actual length of the period. Our common unitholders will not receive any distribution based on any period prior to our initial public distribution, including any period in 2016.

As of March 29, 2017, Kimbell Royalty Partners, LP 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, 2016, 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. The geographic breadth 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.

As of December 31, 2016, the estimated proved oil, natural gas and natural gas liquids reserves attributable to our interests in our underlying acreage were 17,590 MBoe (52.3% liquids, consisting of 78.4% oil and 21.6% natural gas liquids) based on the reserve report prepared by Ryder Scott. Of these reserves, 67.9% were classified as PDP reserves, 1.2% were classified as PDNP reserves and 30.9% were classified as 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 9.6%. PUD reserves included in this estimate are from 543 gross proved undeveloped locations.

As of December 31, 2016, the estimated proved oil, natural gas and natural gas liquids reserves attributable solely to our predecessor’s interests in its underlying acreage were 2,311 MBoe (48.5% liquids, consisting of 79.0% oil and 21.0% natural gas liquids) based on the reserve report prepared by Ryder Scott. Of these reserves, 58.9% were classified as PDP reserves, 1.5% were classified as PDNP reserves and 39.6% were classified as PUD reserves. The properties underlying our predecessor’s mineral and royalty interests typically have low estimated decline rates. Our predecessor’s PDP reserves have an average estimated initial five-year decline rate of 9.6%. PUD reserves included in this estimate are from 355 gross proved undeveloped locations.

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For the year ended December 31, 2016, our predecessor’s revenues were derived 60% from oil sales, 30% from natural gas sales and 10% 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, 2016, our predecessor had over 200 operators on its acreage, with its top ten operators (Jonah Energy LLC, Newfield Exploration Company, Hess Corporation, Denbury Resources, XTO Energy, Inc., Memorial Production Partners, Stanolind Oil & Gas, Devon Energy Corporation, Occidental Permian Ltd., and Continental Resources) together accounting for approximately 58.0% of our predecessor’s combined discounted future net income (discounted at 10%). As of December 31, 2016, the Contributing Parties had over 700 operators on the acreage contributed to us, with our top ten operators (Occidental Permian Ltd., Range Resources Corporation / Memorial Resource Development Corp., Aera Energy LLC (a joint venture of Royal Dutch Shell plc and ExxonMobil Corporation), Protégé Energy III LLC, Jonah Energy LLC, XTO Energy, Inc., Chesapeake Energy Corporation, EOG Resources, Inc., Campbell Development Group, LLC, and Apache Corporation) together accounting for approximately 47.6% of our combined discounted future net income (discounted at 10%). As of March 20, 2017, there were 24 rigs operating on our acreage compared to 15 rigs on our acreage as of December 29, 2016. 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.

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, 2016, 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 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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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. The Contributing Parties, including affiliates of our Sponsors, 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 our initial public offering, certain of the Contributing Parties granted us a right of first offer for a period of three years 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, and Director Independence—Agreements and Transactions with Affiliates in Connection with our Initial Public 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 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 our initial public offering, we entered into a management services agreement with Kimbell Operating, which entered into separate service agreements with certain entities controlled by affiliates of our Sponsors, 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

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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 our initial public offering and pursuant to the contribution agreement that we 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, and Director Independence—Agreements and Transactions with Affiliates in Connection with our Initial Public 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. A majority of our assets, 76.8% of our well count and 58.8% of our gross acreage are 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 contains 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 are 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 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.” In connection with our initial public offering, we entered 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). 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.

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Competitive Strengths

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

· Significant diversified portfolio of 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 March 29, 2017, Kimbell Royalty Partners, LP 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, 2016, 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, 2016, the estimated proved oil, natural gas and natural gas liquids reserves attributable to our interests in our underlying acreage were 17,590 MBoe (52.3% liquids, consisting of 78.4% oil and 21.6% natural gas liquids) based on the reserve report prepared by Ryder Scott. Of these reserves, 67.9% were classified as PDP reserves, 1.2% were classified as PDNP reserves and 30.9% were classified as PUD reserves. PUD reserves included in this estimate are from 543 gross proved undeveloped locations. As of December 31, 2016, the estimated proved oil, natural gas and natural gas liquids reserves attributable to our predecessor’s interests in our underlying acreage were 2,311 MBoe (48.5% liquids, consisting of 79.0% oil and 21.0% natural gas liquids) based on the reserve report prepared by Ryder Scott. Of these reserves, 58.9% were classified as PDP reserves, 1.5% were classified as PDNP reserves and 39.6% were classified as PUD reserves. PUD reserves included in this estimate are from 355 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.

· Financial flexibility to fund expansion. We believe that our conservative capital structure 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. In connection with our initial public offering, we entered 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), which was minimally drawn at the closing of our initial public 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.

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Our Properties

Material Basins and Producing Regions

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

· 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.

· 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 that the Contributing Parties acquired in 2007. 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 along with the Marcellus and Haynesville Shales. 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.

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· 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 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.

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

Mineral Interests

The following table sets forth information about our and our predecessor’s mineral interests:

	Kimbell Royalty Partners, LP as of December 31, 2016				Predecessor as of December 31, 2016
Basin or Producing Region	Gross Acres	Net Acres	Percent Leased		Gross Acres	Net Acres	Percent Leased
Permian Basin (1)	1,764,954	15,741	99	%	41,488	542	98	%
Mid-Continent	336,481	9,115	97	%	18,586	2,181	83	%
Terryville/Cotton Valley/Haynesville	261,762	2,347	98	%	18,131	72	98	%
Eagle Ford	182,102	1,968	97	%	21,718	169	100	%
Barnett Shale/Fort Worth Basin (2)	216,367	2,335	99	%	23,320	44	93	%
Bakken/Williston Basin (3)	82,704	1,455	99	%	49,354	1,383	98	%
San Juan Basin	28,852	141	98	%	671	17	0	%
Onshore California	7,666	27	64	%	835	1	100	%
DJ Basin/Rockies/Niobrara	3,967	97	59	%	—	—	—
Illinois Basin	6,351	83	100	%	—	—	—
Other Western (onshore) Gulf Basin	539,625	3,754	98	%	23,888	276	99	%
Other TX/LA/MS Salt Basin	144,186	1,476	91	%	15,889	203	30	%
Other	93,857	671	95	%	7,537	246	40	%
Total	3,668,874	39,396	98	%(4)	221,417	5,132	90	% (4)

Note: 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.

Note: Numbers may not add up to total amounts due to rounding.

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(1) Includes mineral interests in approximately 740,244 gross (6,723 net) acres in the Wolfcamp/Bone Spring.

(2) Includes mineral interests in approximately 198,229 gross (1,762 net) acres in the Barnett Shale.

(3) Includes mineral interests in approximately 74,504 gross (1,393 net) acres in the Bakken/Three Forks.

(4) This figure represents the weighted average of our leased acres relative to our total acreage in the basins in which we own mineral interests.

ORRIs

The following table sets forth information about our ORRIs:

	Kimbell Royalty Partners, LP as of December 31, 2016				Predecessor as of December 31, 2016
Basin or Producing Region	Gross Acres	Net Acres	Percent Producing		Gross Acres	Net Acres	Percent Producing
Permian Basin (1)	232,723	2,814	100	%	29,027	169	100	%
Mid-Continent	139,513	2,067	86	%	2,541	22	100	%
Terryville/Cotton Valley/Haynesville	41,812	779	99	%	1,523	62	64	%
Eagle Ford	72,970	597	100	%	19,506	25	100	%
Barnett Shale/Fort Worth Basin (2)	54,888	445	100	%	1,866	2	100	%
Bakken/Williston Basin (3)	31,554	1,879	100	%	13,444	1,657	100	%
San Juan Basin	47,233	908	98	%	145	7	100	%
Onshore California	9,286	9	100	%	—	—
DJ Basin/Rockies/Niobrara	3,182	102	54	%	1,654	91	12	%
Illinois Basin	13,304	1,032	100	%	—	—
Other Western (onshore) Gulf Basin	71,435	1,086	100	%	13,110	50	100	%
Other TX/LA/MS Salt Basin	22,616	1,140	100	%	11,586	500	100	%
Other	133,093	10,854	99	%	52,170	3,670	99	%
Total	873,609	23,711	97	% (4)	146,571	6,255	98	% (4)

Note: Numbers may not add up to total amounts due to rounding.

(1) Includes overriding royalty interests in approximately 149,173 gross (1,614 net) acres in the Wolfcamp/Bone Spring.

(2) Includes overriding royalty interests in approximately 50,217 gross (389 net) acres in the Barnett Shale.

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(3) Includes overriding royalty interests in approximately 29,813 gross (1,792 net) acres in the Bakken/Three Forks.

(4) This figure represents the weighted average of our acres that are producing relative to our total acreage in the basins in which we own ORRIs. Virtually all of this acreage is producing.

Wells

The following table sets forth information about the wells in which the Contributing Parties and our predecessor had a mineral or royalty interest as of December 31, 2016:

Mineral and Royalty Interests

Basin or Producing Region	Kimbell Royalty Partners, LP as of December 31, 2016 Well Count	Predecessor as of December 31, 2016 Well Count
Permian Basin	30,202	9,616
Mid-Continent	2,358	112
Terryville/Cotton Valley/Haynesville	5,120	229
Eagle Ford	1,252	95
Barnett Shale/Fort Worth Basin	2,297	639
Bakken/Williston Basin	468	291
San Juan Basin	563	—
Onshore California	239	75
DJ Basin/Rockies/Niobrara	2,988	2,410
Illinois Basin	187	—
Other	2,570	251
Total	48,244	13,718

Oil and Natural Gas Data

Proved Reserves

Evaluation and Review of Estimated Proved Reserves

Our and our predecessor’s historical reserve estimates as of December 31, 2016 were prepared by Ryder Scott, an independent petroleum engineering firm. Ryder Scott is a third party engineering firm and does not own an interest in any of our properties and is not employed by us on a contingent basis.

Within Ryder Scott, the technical person primarily responsible for preparing the reserve estimates set forth in the reserve report incorporated herein is Mr. Scott Wilson, who has been practicing petroleum-engineering consulting at Ryder Scott since 2000. Mr. Wilson is a registered Professional Engineer in the States of Alaska, Colorado, Texas and Wyoming. He earned a Bachelor of Science Degree in Petroleum Engineering from the Colorado School of Mines in 1983 and a Masters of Business Administration in Finance from the University of Colorado in 1985. As technical principal, Mr. Wilson meets or exceeds the education, training, and experience requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers and is proficient in applying industry standard practices to engineering evaluations as well as in applying SEC and other industry reserves definitions and guidelines. A copy of Ryder Scott’s estimated proved reserve report as of December 31, 2016 is attached as an exhibit to this Annual Report.

Our Chief Executive Officer, Robert D. Ravnaas, has agreed to provide us with reserve engineering services. Mr. R. Ravnaas is a petroleum engineer with over 30 years of reservoir and operations experience. Mr. R. Ravnaas and certain engineers and geoscience professionals under his supervision worked closely with our independent reserve engineers to ensure the integrity, accuracy and timeliness of the data used to calculate our proved reserves relating to our mineral and royalty interests. Mr. R. Ravnaas met with our independent reserve engineers periodically during the period covered by the reserve report to discuss the assumptions and methods used in the proved reserve estimation process. We provide historical information to the independent reserve engineers for our properties such as ownership interest, oil and gas production, well test data, commodity prices and operating and development costs. Operating and development costs

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are not realized to our interest but are used to calculate the economic limit life of the wells. These costs are estimated and checked by our independent reserve engineers.

Mr. R. Ravnaas is primarily responsible for the preparation of our reserves. In addition, the preparation of our proved reserve estimates are completed in accordance with internal control procedures, including the following:

· review and verification of historical production data, which data is based on actual production as reported by the operators of our properties;

· preparation of reserve estimates by Mr. R. Ravnaas or under his direct supervision;

· review by Mr. R. Ravnaas of all of our reported proved reserves at the close of each quarter, including the review of all significant reserve changes and all new proved undeveloped reserves additions;

· verification of property ownership by our land department; and

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

Under SEC rules, proved reserves are those quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs and under existing economic conditions, operating methods and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. If deterministic methods are used, the SEC has defined reasonable certainty for proved reserves as a “high degree of confidence that the quantities will be recovered.” All of our proved reserves as of December 31, 2016 were estimated using a deterministic method. The estimation of reserves involves two distinct determinations. The first determination results in the estimation of the quantities of recoverable oil and gas and the second determination results in the estimation of the uncertainty associated with those estimated quantities in accordance with the definitions established under SEC rules. The process of estimating the quantities of recoverable oil and gas reserves relies on the use of certain generally accepted analytical procedures. These analytical procedures fall into three broad categories or methods: (1) performance-based methods, (2) volumetric-based methods and (3) analogy. These methods may be used singularly or in combination by the reserve evaluator in the process of estimating the quantities of reserves. The proved reserves for our properties were estimated by performance methods, analogy or a combination of both methods. All proved producing reserves attributable to producing wells were estimated by performance methods. These performance methods include, but may not be limited to, decline curve analysis, which utilized extrapolations of available historical production and pressure data. All proved developed non-producing and undeveloped reserves were estimated by the analogy method.

To estimate economically recoverable proved reserves and related future net cash flows, Ryder Scott considered many factors and assumptions, including the use of reservoir parameters derived from geological, geophysical and engineering data which cannot be measured directly, economic criteria based on current costs and the SEC pricing requirements and forecasts of future production rates. To establish reasonable certainty with respect to our estimated proved reserves, the technologies and economic data used in the estimation of our proved reserves included production and well test data, downhole completion information, geologic data, electrical logs, radioactivity logs, core analyses, available seismic data and historical well cost and production cost data.

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Summary of Estimated Proved Reserves

The following table presents our and our predecessor’s estimated proved oil and natural gas reserves as of December 31, 2016:

	Kimbell Royalty Partners, LP December 31, 2016 (1)		Kimbell Royalty Partners, LP December 31, 2015		Predecessor December 31, 2016 (1)
Estimated proved developed reserves:
Oil (MBbls)	4,879		5,336		482
Natural gas (MMcf)	35,172		35,910		4,586
Natural gas liquids (MBbls)	1,416		1,575		150
Total (MBoe)(6:1) (2)	12,157		12,896		1,396
Estimated proved undeveloped reserves:
Oil (MBbls)	2,331		2,237		404
Natural gas (MMcf)	15,219		15,808		2,554
Natural gas liquids (MBbls)	566		352		85
Total (MBoe)(6:1) (2)	5,434		5,224		915
Estimated proved reserves:
Oil (MBbls)	7,210		7,573		886
Natural gas (MMcf)	50,391		51,718		7,140
Natural gas liquids (MBbls)	1,982		1,927		235
Total (MBoe)(6:1) (2)	17,590		18,120		2,311
Percent proved developed	69	%	71	%	60	%

(1) Estimates of reserves as of December 31, 2016 and 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, 2016 and 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 $42.75 and $50.28 per Bbl for oil and $2.49 and $2.59 per MMBtu for natural gas at December 31, 2016 and 2015, respectively. The price per Bbl for natural gas liquids was modeled as a percentage of oil price, which was derived from historical accounting data. Reserve estimates do not include any value for probable or possible reserves that may exist, nor do they include any value for undeveloped acreage. The reserve estimates represent our 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, 2016 and 2015 was used, the conversion factor would be approximately 17.7 and 19.4 Mcf per Bbl of oil, respectively. In this Annual Report, 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. We are providing this measure supplementally because we believe this conversion factor represents an estimation of value equivalence over time and better correlates with the respective contribution of oil and natural gas to our revenues. We use the 20-to-1 conversion factor as we assess our business, including analysis of our financial and production performance, strategic decisions to purchase additional properties and budgeting. We do not adjust the 20-to-1 ratio to reflect current pricing, because the significant volatility in the conversion ratio makes it difficult for us to compare results across periods. By reviewing our aggregate production on a constant 20-to-1 basis, which removes the variability of price fluctuations but generally approximates price equivalence over recent periods, we are able to compare production data from period to period as well as the relative contribution of oil and natural gas to our revenues. The 20-to-1 conversion factor approximates the mean ratio of the price of WTI oil to the price of Henry Hub natural gas from January 3, 2006 to December 31, 2016, as reported by the EIA. During this period, the ratio of the price of oil to the price of natural gas ranged from 5.97 to 55.85. The mean ratios of the price of oil to the price of natural gas were 17.72 and 18.75 for the year ended December 31, 2016 and December 31, 2015, respectively. Due to the variability of the prices of oil and natural gas, there is no standard conversion ratio for value equivalence, and the 20-to-1 ratio presented here may not accurately reflect the ratio of oil prices to natural gas prices for a given period.

The foregoing reserves are all located within the continental United States. Reserve engineering is and must be recognized as a subjective process of estimating volumes of economically recoverable oil and natural gas that cannot be

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measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation. As a result, the estimates of different engineers often vary. In addition, the results of drilling, testing, and production may justify revisions of such estimates. Accordingly, reserve estimates often differ from the quantities of oil and natural gas that are ultimately recovered. Estimates of economically recoverable oil and natural gas and of future net revenues are based on a number of variables and assumptions, all of which may vary from actual results, including geologic interpretation, prices, and future production rates and costs. Please read “Risk Factors.”

Additional information regarding our and our predecessor’s estimated proved reserves can be found in the reserve report as of December 31, 2016, which is included as an exhibit to this report.

Estimated Proved Undeveloped Reserves

As of December 31, 2016, our PUD reserves totaled 2,331 MBbls of oil, 15,219 MMcf of natural gas and 566 MBbls of natural gas liquids, for a total of 5,434 MBoe. As of December 31, 2015, our PUD reserves totaled 2,237 MBbls of oil, 15,808 MMcf of natural gas and 352 MBbls of natural gas liquids, for a total of 5,224 MBoe. PUD reserves will be converted from undeveloped to developed as the applicable wells begin production.

As of December 31, 2016, our predecessor’s PUD reserves totaled 404 MBbls of oil, 2,554 MMcf of natural gas and 85 MBbls of natural gas liquids, for a total of 915 MBoe. As of December 31, 2015, our predecessor’s PUD reserves totaled 413 MBbls of oil, 2,446 MMcf of natural gas and 71 MBbls of natural gas liquids, for a total of 892 MBoe. PUD reserves will be converted from undeveloped to developed as the applicable wells begin production.

The following tables summarize our changes in PUD reserves during the year ended December 31, 2016 (in MBoe):

	Proved Undeveloped Reserves (1)
	Kimbell Royalty Partners, LP (1)		Predecessor (1)
Balance, December 31, 2015	5,224		892
Acquisitions of reserves	4		—
Extensions and discoveries	1,227		282
Revisions and previous estimates	84		(55	)
Transfers to estimated proved developed	(1,105	)	(204	)
Balance, December 31, 2016	5,434		915

(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. Please read “—Summary of Estimated Proved Reserves.”

Our proved undeveloped reserves as of December 31, 2016 were from 235 vertical wells and 308 horizontal wells. As of December 31, 2016, all of our PUD drilling locations are scheduled to be drilled prior to December 31, 2021. As of December 31, 2016, approximately 1.2% of our total proved reserves were classified as proved developed non-producing.

Changes in PUDs that occurred from December 31, 2015 through December 31, 2016 were primarily due to:

· the acquisition of an additional 4 MBoe through one acquisition for approximately $600,000 of royalty interests in three contiguous Encana Corporation operated Eagle Ford drilling units in Karnes County, Texas consisting of 15 horizontal wells producing from lower and upper Eagle Ford zones.

· additions of approximately 1,227 MBoe, as well locations were converted from probable to proved undeveloped, as offset drilling proved our acreage and projected drilling dates fell within five years of the effective date of the report.

· the conversion of approximately 1,105 MBoe PUD reserves into proved developed reserves as 308 locations (90 horizontal and 218 vertical) were drilled; and

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· positive revisions of approximately 84 MBoe in PUDs primarily due to new accounting methods to account for NGL volumes for properties not owned by our predecessor.

Of the 308 locations that were drilled in 2016, 64 locations were specifically identified by management in its 2015 reserve estimates, and all such locations were actually drilled in 2016. The remaining 244 locations were included in management’s proved undeveloped forecast in its reserve estimates as being scheduled to be drilled in 2016. These locations include infill drilling in multi-well units and in some cases, waterflood response, CO2 response, well stimulations, flood conformance improvements and pump upgrades. Management historically has not included conversions from multi-well units in its reserve estimates due to the time required to calculate such information (and related costs) and because management seeks to present a conservative estimate of its PUDs. Management’s forecasts for its multi-well units are based on a multi-factor analysis that includes reviewing information from state regulatory agencies and other third-party sources, including publicly disclosed data by the operators, as well as management’s experience with the units.

Our predecessor’s proved undeveloped reserves as of December 31, 2016 were from 225 vertical wells and 130 horizontal wells. As of December 31, 2016, all of our predecessor’s PUD drilling locations are scheduled to be drilled prior to December 31, 2021. As of December 31, 2016, approximately 1.5% of our predecessor’s total proved reserves were classified as proved developed non-producing.

Changes in our predecessor’s PUDs that occurred from December 31, 2015 through December 31, 2016 were primarily due to:

· additions of approximately 282 MBoe, as well locations were converted from probable to proved undeveloped, as offset drilling proved our acreage and projected drilling dates fell within five years of the effective date of the report.

· the conversion of approximately 204 MBoe PUD reserves into proved developed reserves as 201 locations (51 horizontal and 150 vertical) were drilled; and

· negative revisions of approximately 84 MBoe in PUDs primarily due to decreased commodity pricing between 2015 and 2016.

Of the 201 locations that were drilled in 2016, 36 locations were specifically identified by management in its 2015 reserve estimates, and all such locations were actually drilled in 2016. The remaining 165 locations were included in management’s proved undeveloped forecast in its reserve estimates as being scheduled to be drilled in 2016. These locations include infill drilling in multi-well units and in some cases, waterflood response, CO2 response, well stimulations, flood conformance improvements and pump upgrades. Management historically has not included conversions from multi-well units in its reserve estimates due to the time required to calculate such information (and related costs) and because management seeks to present a conservative estimate of its PUDs. Management’s forecasts for its multi-well units are based on a multi-factor analysis that includes reviewing information from state regulatory agencies and other third-party sources, including publicly disclosed data by the operators, as well as management’s experience with the units.

Oil and Natural Gas Production Prices and Production Costs

Production and Price History — Predecessor

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

	Predecessor Historical
	For the Years Ended December 31,
	2016	2015		2014
Production Data:
Oil and condensate (Bbls)	55,587	59,321		50,570
Natural gas (Mcf)	496,778	548,386		515,130
Natural gas liquids (Bbls)	22,360	22,351		17,991
Total (Boe)(6:1) (2)	160,743	173,070		154,416
Average daily production (Boe/d)(6:1)	440	474		423
Total (Boe)(20:1) (3)	102,786	109,091		94,318
Average daily production (Boe/d)(20:1)	282	299		258
Average Realized Prices:
Oil and condensate (per Bbl)	38.69	$	49.79	$	87.25
Natural gas (per Mcf)	2.21	$	2.44	$	4.22
Natural gas liquids (per Bbl)	15.99	$	17.56	$	35.26
Average Unit Cost per Boe (6:1)
Production and ad valorem taxes	1.74	$	2.47	$	3.68

(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.

(3) “Value-equivalent” production volumes are 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 2 to the Summary of Estimated Proved Reserves table under “Oil and Natural Gas Data—Proved Reserves—Summary of Estimated Proved Reserves.”

Productive Wells

Productive wells consist of producing wells, wells capable of production, and exploratory, development, or extension wells that are not dry wells. As of December 31, 2016, the Contributing Parties owned mineral or royalty interests in over 48,000 productive wells, which consisted of over 39,000 oil wells and over 8,000 natural gas wells. As of December 31, 2016, our predecessor owned mineral or royalty interests in over 13,000 productive wells which consisted of over 10,000 oil wells and over 2,000 natural gas wells.

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Acreage

Mineral and Royalty Interests

The following table sets forth information relating to the acreage underlying our and our predecessor’s mineral interests as of December 31, 2016:

	Kimbell Royalty Partners, LP Mineral Interests (1)(2)					Predecessor Mineral Interests (1)(2)
State	Developed Acreage		Undeveloped Acreage		Total Acreage	Developed Acreage		Undeveloped Acreage		Total Acreage
Texas	2,985,247		41,363		3,026,610	127,064		2,013		129,077
Oklahoma	101,081		6,129		107,210	9,191		3,139		12,330
Louisiana	45,679		589		46,268	5,716		370		6,086
New Mexico	77,443		1,005		78,448	1,631		605		2,236
North Dakota	80,707		720		81,427	48,477		720		49,197
Colorado	27,639		1,450		29,089	—		671		671
Wyoming	2,562		640		3,202	—		—		—
Kansas	83,428		1,880		85,308	—		—		—
Montana	2,640		4,681		7,321	1,520		4,681		6,201
Other	189,122		14,869		203,991	4,571		11,048		15,619
Total	3,595,548	(3)	73,326	(4)	3,668,874	198,170	(5)	23,247	(6)	221,417

(1) Includes both mineral and nonparticipating royalty interests.

(2) Numbers may not add up to total amounts due to rounding.

(3) Reflects mineral interests in approximately 3,595,548 total gross (36,570 net) developed acres.

(4) Reflects mineral interests in approximately 73,326 total gross (2,639 net) undeveloped acres.

(5) Reflects mineral interests in approximately 198,170 total gross (4,012 net) developed acres.

(6) Reflects mineral interests in approximately 23,247 total gross (1,120 net) undeveloped acres.

The following table sets forth information relating to our acreage for our and our predecessor’s ORRIs as of December 31, 2016:

	Kimbell Royalty Partners, LP ORRIs (1)					Predecessor ORRIs (1)
State	Developed Acreage		Undeveloped Acreage		Total Acreage	Developed Acreage		Undeveloped Acreage		Total Acreage
Texas	478,602		680		479,282	64,477		40		64,517
Oklahoma	50,239		19,000		69,239	160		—		160
Louisiana	34,948		511		35,459	504		511		1,014
New Mexico	45,610		960		46,570	2,040		—		2,040
North Dakota	31,554		—		31,554	13,444		—		13,444
Colorado	20,577		1,454		22,031	5,306		1,454		6,760
Wyoming	70,044		—		70,044	44,966		—		44,966
Kansas	10,640		—		10,640	—		—		—
Montana	—		—		—	—		—		—
Other	108,062		727		108,789	12,942		727		13,669
Total	850,276	(2)	23,332	(3)	873,609	143,839	(4)	2,732	(5)	146,571

(1) Numbers may not add up to total amounts due to rounding.

(2) Reflects ORRIs in approximately 850,276 total gross (23,509 net) developed acres.

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(3) Reflects ORRIs in approximately 23,332 total gross (202 net) undeveloped acres.

(4) Reflects ORRIs in approximately 143,839 total gross (6,151 net) developed acres.

(5) Reflects ORRIs in approximately 2,732 total gross (104 net) undeveloped acres.

Drilling Results

As of December 31, 2016 and 2015, the operators of our properties had over 48,000 gross productive development wells on the acreage underlying our mineral and royalty interests. As of December 31, 2014, the operators of our properties had over 36,000 gross productive development wells on the acreage underlying our mineral and royalty interests. As a holder of mineral and royalty interests, we generally are not provided information as to whether any wells drilled on the properties underlying our acreage are classified as exploratory. We are not aware of any dry holes drilled on the acreage underlying our mineral and royalty interests during the relevant periods.

Competition

The oil and natural gas industry is intensely competitive; we primarily compete with companies for the acquisition of oil and natural gas properties some of whom have greater resources than we do. These companies may be able to pay more for productive oil and natural gas properties and exploratory prospects or to define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. Additionally, many of our competitors are, or are affiliated with, operators that engage in the exploration and production of their oil and gas properties, which allows them to acquire larger assets that include operated properties. Our larger or more integrated competitors may be able to absorb the burden of existing, and any changes to, federal, state and local laws and regulations more easily than we can, which would adversely affect our competitive position. These companies may also have a greater ability to continue exploration activities during periods of low oil and natural gas market prices. Our ability to acquire additional properties in the future will be dependent upon our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. In addition, because we have fewer financial and human resources than many companies in our industry, we may be at a disadvantage in bidding for exploratory prospects and producing oil and natural gas properties.

Seasonal Nature of Business

Generally, demand for oil and natural gas decreases during the summer months and increases during the winter months. Seasonal weather conditions and lease stipulations can limit drilling and producing activities and other oil and natural gas operations in a portion of our operating areas. These seasonal anomalies can pose challenges for the operators of our properties in meeting well drilling objectives and can increase competition for equipment, supplies and personnel during the spring and summer months, which could lead to shortages and increase costs or delay operations.

Regulation

The following disclosure describes regulation directly associated with operators of oil and natural gas properties, including our current operators, and other owners of working interests in oil and natural gas properties.

Oil and natural gas operations are subject to various types of legislation, regulation and other legal requirements enacted by governmental authorities. This legislation and regulation affecting the oil and natural gas industry is under constant review for amendment or expansion. Some of these requirements carry substantial penalties for failure to comply. The regulatory burden on the oil and natural gas industry increases the cost of doing business.

Environmental Matters

Oil and natural gas exploration, development and production operations are subject to stringent laws and regulations governing the discharge of materials into the environment or otherwise relating to protection of the environment or occupational health and safety. These laws and regulations have the potential to impact production on our properties, which could materially adversely affect our business and our prospects. Numerous federal, state and local governmental agencies, such as the EPA, issue regulations that often require difficult and costly compliance measures that carry substantial administrative, civil and criminal penalties and may result in injunctive obligations for non-compliance. These laws and regulations may require the acquisition of a permit before drilling commences, restrict the types, quantities and concentrations of various substances that can be released into the environment in connection

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with drilling and production activities, limit or prohibit construction or drilling activities on certain lands lying within wilderness, wetlands, ecologically sensitive and other protected areas, require action to prevent or remediate pollution from current or former operations, such as plugging abandoned wells or closing earthen pits, result in the suspension or revocation of necessary permits, licenses and authorizations, require that additional pollution controls be installed and impose substantial liabilities for pollution resulting from operations. The strict, joint and several liability nature of such laws and regulations could impose liability upon the operators of our properties regardless of fault. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances, hydrocarbons or other waste products into the environment. Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent and costly pollution control or waste handling, storage, transport, disposal or cleanup requirements could materially adversely affect our business and prospects.

Non-Hazardous and Hazardous Waste

The RCRA, and comparable state statutes and regulations promulgated thereunder, affect oil and natural gas exploration, development, and production activities by imposing requirements regarding the generation, transportation, treatment, storage, disposal and cleanup of hazardous and non-hazardous wastes. With federal approval, the individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. Administrative, civil and criminal penalties can be imposed for failure to comply with waste handling requirements. Although most wastes associated with the exploration, development and production of oil and natural gas are exempt from regulation as hazardous wastes under RCRA, these wastes typically constitute nonhazardous solid wastes that are subject to less stringent requirements. From time to time, the EPA and state regulatory agencies have considered the adoption of stricter disposal standards for nonhazardous wastes, including crude oil and natural gas wastes. Moreover, it is possible that some wastes generated in connection with exploration and production of oil and gas that are currently classified as nonhazardous may, in the future, be designated as “hazardous wastes,” resulting in the wastes being subject to more rigorous and costly management and disposal requirements. On May 4, 2016, a coalition of environmental groups filed a lawsuit against EPA in the U.S. District Court for the District of Columbia for failing to update regulations governing the disposal of certain oil and natural gas drilling wastes. Any changes in the laws and regulations could have a material adverse effect on the operators of our properties’ capital expenditures and operating expenses, which in turn could affect production from the acreage underlying our mineral and royalty interests and adversely affect our business and prospects.

Remediation

The CERCLA and analogous state laws, generally impose strict, joint and several liability, without regard to fault or legality of the original conduct, on classes of persons who are considered to be responsible for the release of a “hazardous substance” into the environment. These persons include the current owner or operator of a contaminated facility, a former owner or operator of the facility at the time of contamination, and those persons that disposed or arranged for the disposal of the hazardous substance at the facility. Under CERCLA and comparable state statutes, persons deemed “responsible parties” may be subject to strict, joint and several liability for the costs of removing or remediating previously disposed wastes (including wastes disposed of or released by prior owners or operators) or property contamination (including groundwater contamination), for damages to natural resources and for the costs of certain health studies. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. In addition, the risk of accidental spills or releases could expose the operators of the acreage underlying our mineral interests to significant liabilities that could have a material adverse effect on the operators’ businesses, financial condition and results of operations. Liability for any contamination under these laws could require the operators of the acreage underlying our mineral interests to make significant expenditures to investigate and remediate such contamination or attain and maintain compliance with such laws and may otherwise have a material adverse effect on their results of operations, competitive position or financial condition.

Water Discharges

The Clean Water Act, the SDWA, the OPA, and analogous state laws and regulations promulgated thereunder impose restrictions and strict controls regarding the unauthorized discharge of pollutants, including produced waters and other gas and oil wastes, into regulated waters. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or the state. The Clean Water Act and regulations implemented

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thereunder also prohibit the discharge of dredge and fill material into regulated waters, including jurisdictional wetlands, unless authorized by an appropriately issued permit. The EPA has issued final rules outlining its position on the federal jurisdictional reach over waters of the United States, but this rule has been stayed nationwide by the U.S. Sixth Circuit Court of Appeals until ongoing litigation regarding the rule is settled. Additionally, on February 28, 2017, President Trump issued an executive order directing the EPA and the U.S. Army Corps of Engineers to review and, consistent with applicable law, to initiate rulemaking to rescind or revise the rule. The EPA and the U.S. Army Corps of Engineers published a notice of intent to review and rescind or revise the rule on March 6, 2017. At this time, it is unclear what impact these actions will have on the implementation of the rule.

In addition, spill prevention, control and countermeasure plan requirements under federal law require appropriate containment berms and similar structures to help prevent the contamination of navigable waters in the event of a petroleum hydrocarbon tank spill, rupture or leak. The EPA has also adopted regulations requiring certain oil and natural gas exploration and production facilities to obtain individual permits or coverage under general permits for storm water discharges, and in June 2016, the EPA finalized effluent limitation guidelines for the discharge of wastewater from hydraulic fracturing.

The OPA is the primary federal law for oil spill liability. The OPA contains numerous requirements relating to the prevention of and response to petroleum releases into regulated waters, including the requirement that operators of offshore facilities and certain onshore facilities near or crossing waterways must develop and maintain facility response contingency plans and maintain certain significant levels of financial assurance to cover potential environmental cleanup and restoration costs. The OPA subjects owners of facilities to strict, joint and several liability for all containment and cleanup costs and certain other damages arising from a release, including, but not limited to, the costs of responding to a release of oil into surface waters.

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

Air Emissions

The federal Clean Air Act, and comparable state laws and regulations, regulate emissions of various air pollutants through the issuance of permits and the imposition of other requirements. The EPA has developed, and continues to develop, stringent regulations governing emissions of air pollutants at specified sources. New facilities may be required to obtain permits before work can begin, and existing facilities may be required to obtain additional permits and incur capital costs in order to remain in compliance. For example, most recently in May 2016, the EPA finalized additional regulations under the federal Clean Air Act that established new emission control requirements for oil and natural gas production and processing operations, which is discussed in more detail below in “—Regulation of Hydraulic Fracturing.” These laws and regulations may increase the costs of compliance for oil and natural gas producers and impact production of the acreage underlying our mineral and royalty interests, and federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with air permits or other requirements of the federal Clean Air Act and associated state laws and regulations. Moreover, obtaining or renewing permits has the potential to delay the development of oil and natural gas projects.

Climate Change

In response to findings that emissions of GHGs, including carbon dioxide and methane, present an endangerment to public health and the environment, the EPA has adopted regulations under existing provisions of the federal Clean Air Act that, among other things, require preconstruction and operating permits for certain large stationary sources. In addition, the EPA has adopted rules requiring the monitoring and reporting of GHGs from certain onshore oil and natural gas production sources on an annual basis. As a result of this continued regulatory focus, future GHG regulations of the oil and gas industry remain a possibility.

Congress has from time to time considered adopting legislation to reduce emissions of GHGs and many states have already taken legal measures to reduce emissions of GHGs primarily through the planned development of GHG emission inventories and/or regional GHG cap and trade programs. Although Congress has not adopted such legislation at this time, it may do so in the future and many states continue to pursue regulations to reduce GHG emissions. Additionally, efforts have been made and continue to be made in the international community toward the adoption of

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international treaties or protocols that would address global climate change issues. Most recently in 2015, the United States participated in the United Nations Conference on Climate Change, which led to the creation of the Paris Agreement. 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.

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

In addition, one potential consequence of climate change could be increased severity of extreme weather conditions such as more intense hurricanes, thunderstorms, tornados and snow or ice storms, as well as rising sea levels. Another possible consequence of climate change is increased volatility in seasonal temperatures. Extreme weather conditions can interfere with production and increase costs and damage resulting from extreme weather may not be fully insured. However, at this time, we are unable to determine the extent to which climate change may lead to increased storm or weather hazards affecting our business.

Regulation of Hydraulic Fracturing

Hydraulic fracturing is an important and common practice that is used to stimulate production of hydrocarbons from tight formations. The process involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production. Hydraulic fracturing operations have historically been overseen by state regulators as part of their oil and natural gas regulatory programs. However, on May 9, 2014, the EPA announced an advance notice of proposed rulemaking under the Toxic Substances Control Act, relating to chemical substances and mixtures used in oil and natural gas exploration or production. Further, in March 2015, the Bureau of Land Management (“BLM”) adopted a rule requiring, among other things, public disclosure to the BLM of chemicals used in hydraulic fracturing operations after fracturing operations have been completed and would strengthen standards for wellbore integrity and management of fluids that return to the surface during and after fracturing operations on federal and Indian lands. On June 22, 2016, a federal district judge in Wyoming struck down the rule, finding that BLM lacked the authority to promulgate environmental regulations relating to hydraulic fracturing. The federal government has appealed this decision to the 10th Circuit Court of Appeals. In addition, legislation has been introduced before Congress that would provide for federal regulation of hydraulic fracturing and would require disclosure of the chemicals used in the fracturing process. If enacted, these or similar bills could result in additional permitting requirements for hydraulic fracturing operations as well as various restrictions on those operations. These permitting requirements and restrictions could result in delays in operations at well sites and also increased costs to make wells productive.

On August 16, 2012, the EPA approved final regulations under the federal Clean Air Act that establish new air emission controls for oil and natural gas production and natural gas processing operations. Specifically, the EPA’s rule package includes New Source Performance Standards to address emissions of sulfur dioxide and volatile organic compounds (“VOCs”) and a separate set of emission standards to address hazardous air pollutants frequently associated with oil and natural gas production and processing activities. The final rule seeks to achieve a 95% reduction in VOCs emitted by requiring the use of reduced emission completions or “green completions” on all hydraulically-fractured natural gas wells constructed or refractured after January 1, 2015. The rules also establish specific new requirements regarding emissions from compressors, controllers, dehydrators, storage tanks and other production equipment. In May 2016, the EPA finalized similar rules that impose VOC emissions limits on certain oil and natural gas operations that were previously unregulated, including hydraulically fractured oil wells, as well as methane emissions limits for certain new or modified oil and natural gas emissions sources.

In addition, governments have studied the environmental aspects of hydraulic fracturing practices. For example, in December 2016, the EPA issued its final report on a study it had conducted over several years regarding the effects of hydraulic fracturing on drinking water sources. The final report, contrary to several previously published draft reports issued by the EPA, found instances in which impacts to drinking water may occur, including situations involving large volume spills and inadequate mechanical integrity of wells. However, the report also noted significant data gaps that prevented the EPA from determining the extent or severity of these impacts. The U.S. Department of Energy has conducted an investigation into practices the agency could recommend to better protect the environment from drilling

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using hydraulic-fracturing completion methods. Additionally, certain members of Congress have called upon the U.S. Government Accountability Office to investigate how hydraulic fracturing might adversely affect water resources, the SEC to investigate the natural-gas industry and any possible misleading of investors or the public regarding the economic feasibility of pursuing natural gas deposits in shale formations by means of hydraulic fracturing, and the EIA to provide a better understanding of that agency’s estimates regarding natural gas reserves, including reserves from shale formations, as well as uncertainties associated with those estimates. These studies, depending on their degree of pursuit and whether any meaningful results are obtained, could spur initiatives to further regulate hydraulic fracturing under the SDWA or other regulatory authorities.

Several states have adopted, or are considering adopting, regulations that could restrict or prohibit hydraulic fracturing in certain circumstances and/or require the disclosure of the composition of hydraulic fracturing fluids. For example, the Texas Legislature adopted legislation requiring oil and gas operators to publicly disclose the chemicals used in the hydraulic fracturing process, effective as of September 1, 2011. Further, in May 2013, the Texas Railroad Commission issued a “well integrity rule,” which updates the requirements for drilling, putting pipe down, and cementing wells. The rule also includes new testing and reporting requirements, such as: (i) the requirement to submit cementing reports after well completion or after cessation of drilling, whichever is later; and (ii) the imposition of additional testing on wells less than 1,000 feet below usable groundwater. The well integrity rule took effect in January 2014. Local governments also may seek to adopt ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular or prohibit the performance of well drilling in general or hydraulic fracturing in particular.

There has been increasing public controversy regarding hydraulic fracturing with regard to the use of fracturing fluids, impacts on drinking water supplies, use of water and the potential for impacts to surface water, groundwater and the environment generally. A number of lawsuits and enforcement actions have been initiated across the country implicating hydraulic fracturing practices. State and federal regulatory agencies recently have focused on a possible connection between 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. Most recently, in March 2016, the United States Geological Survey identified six states with the most significant hazards from induced seismicity, including Arkansas, Colorado, Kansas, New Mexico, Oklahoma and Texas, where many of our properties are located. In addition, a number of lawsuits have been filed, most recently in Oklahoma, alleging that disposal well operations have caused damage to neighboring properties or otherwise violated state and federal rules regulating waste disposal. These developments could result in additional regulation and restrictions on the use of injection wells and hydraulic fracturing. Such regulations and restrictions could cause delays and impose additional costs and restrictions on the operators of our properties and on their waste disposal activities.

If new laws or regulations that significantly restrict hydraulic fracturing and related activities are adopted, such laws could make it more difficult or costly to perform fracturing to stimulate production from tight formations as well as make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process could adversely affect groundwater. In addition, if hydraulic fracturing is further regulated at the federal or state level, fracturing activities could become subject to additional permitting and financial assurance requirements, more stringent construction specifications, increased monitoring, reporting and recordkeeping obligations, plugging and abandonment requirements and also to attendant permitting delays and potential increases in costs. Such legislative changes could cause operators to incur substantial compliance costs, and compliance or the consequences of any failure to comply by operators could have a material adverse effect on our financial condition and results of operations. At this time, it is not possible to estimate the impact on our business of newly enacted or potential federal or state legislation governing hydraulic fracturing.

Other Regulation of the Oil and Natural Gas Industry

The oil and natural gas industry is extensively regulated by numerous federal, state and local authorities. Legislation affecting the oil and natural gas industry is under constant review for amendment or expansion, frequently

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increasing the regulatory burden. Also, numerous departments and agencies, both federal and state, are authorized by statute to issue rules and regulations that are binding on the oil and natural gas industry and its individual members, some of which carry substantial penalties for failure to comply. Although the regulatory burden on the oil and natural gas industry increases the cost of doing business, these burdens generally do not affect us any differently or to any greater or lesser extent than they affect other companies in the industry with similar types, quantities and locations of production.

The availability, terms and cost of transportation significantly affect sales of oil and natural gas. The interstate transportation of oil and natural gas and the sale for resale of natural gas is subject to federal regulation, including regulation of the terms, conditions and rates for interstate transportation, storage and various other matters, primarily by the Federal Energy Regulatory Commission (“FERC”). Federal and state regulations govern the price and terms for access to oil and natural gas pipeline transportation. FERC’s regulations for interstate oil and natural gas transmission in some circumstances may also affect the intrastate transportation of oil and natural gas.

Although oil and natural gas prices are currently unregulated, Congress historically has been active in the area of oil and natural gas regulation. We cannot predict whether new legislation to regulate oil and natural gas might be proposed, what proposals, if any, might actually be enacted by Congress or the various state legislatures, and what effect, if any, the proposals might have on our operations. Sales of crude oil, condensate and natural gas liquids are not currently regulated and are made at market prices.

Drilling and Production

The operations of the operators of our properties are subject to various types of regulation at the federal, state and local level. These types of regulation include requiring permits for the drilling of wells, drilling bonds and reports concerning operations. The state, and some counties and municipalities, in which we operate also regulate one or more of the following:

· the location of wells;

· the method of drilling and casing wells;

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

· the rates of production or “allowables”

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

· the plugging and abandoning of wells; and

· notice to, and consultation with, surface owners and other third parties.

State laws regulate the size and shape of drilling and spacing units or proration units governing the pooling of oil and natural gas properties. Some states allow forced pooling or integration of tracts to facilitate exploration while other states rely on voluntary pooling of lands and leases. In some instances, forced pooling or unitization may be implemented by third parties and may reduce our interest in the unitized properties. In addition, state conservation laws establish maximum rates of production from oil and natural gas wells, generally prohibit the venting or flaring of natural gas and impose requirements regarding the ratability of production. These laws and regulations may limit the amount of oil and natural gas that the operators of our properties can produce from our wells or limit the number of wells or the locations at which operators can drill. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, natural gas and natural gas liquids within its jurisdiction. States do not regulate wellhead prices or engage in other similar direct regulation, but we cannot assure you that they will not do so in the future. The effect of such future regulations may be to limit the amounts of oil and natural gas that may be produced from our wells, negatively affect the economics of production from these wells or to limit the number of locations operators can drill.

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Federal, state and local regulations provide detailed requirements for the abandonment of wells, closure or decommissioning of production facilities and pipelines and for site restoration in areas where the operators of our properties operate. The U.S. Army Corps of Engineers and many other state and local authorities also have regulations for plugging and abandonment, decommissioning and site restoration. Although the U.S. Army Corps of Engineers does not require bonds or other financial assurances, some state agencies and municipalities do have such requirements.

Natural Gas Sales and Transportation

FERC has jurisdiction over the transportation and sale for resale of natural gas in interstate commerce by natural gas companies under the Natural Gas Act of 1938 (“NGA”) and the Natural Gas Policy Act of 1978. Since 1978, various federal laws have been enacted which have resulted in the complete removal of all price and non-price controls for sales of domestic natural gas sold in “first sales.”

Under the Energy Policy Act of 2005, FERC has substantial enforcement authority to prohibit the manipulation of natural gas markets and enforce its rules and orders, including the ability to assess substantial civil penalties. FERC also regulates interstate natural gas transportation rates and service conditions and establishes the terms under which the operators of our properties may use interstate natural gas pipeline capacity, as well as the revenues the operators of our properties receive for sales of natural gas and release of natural gas pipeline capacity. Interstate pipeline companies are required to provide nondiscriminatory transportation services to producers, marketers and other shippers, regardless of whether such shippers are affiliated with an interstate pipeline company. FERC’s initiatives have led to the development of a competitive, open access market for natural gas purchases and sales that permits all purchasers of natural gas to buy gas directly from third party sellers other than pipelines.

Gathering service, which occurs upstream of jurisdictional transmission services, is regulated by the states onshore and in state waters. Section 1(b) of the NGA exempts natural gas gathering facilities from regulation by FERC under the NGA. Although its policy is still in flux, FERC has in the past reclassified certain jurisdictional transmission facilities as non-jurisdictional gathering facilities, which may increase the operators’ costs of transporting gas to point-of-sale locations. This may, in turn, affect the costs of marketing natural gas that the operators of our properties produce.

Historically, the natural gas industry has been very heavily regulated; therefore, we cannot guarantee that the less stringent regulatory approach currently pursued by FERC and Congress will continue indefinitely into the future nor can we determine what effect, if any, future regulatory changes might have on our natural gas related activities.

Oil Sales and Transportation

Sales of crude oil, condensate and natural gas liquids are not currently regulated and are made at negotiated prices. Nevertheless, Congress could reenact price controls in the future.

Crude oil sales are affected by the availability, terms and cost of transportation. The transportation of oil in common carrier pipelines is also subject to rate regulation. FERC regulates interstate oil pipeline transportation rates under the Interstate Commerce Act and intrastate oil pipeline transportation rates are subject to regulation by state regulatory commissions. The basis for intrastate oil pipeline regulation, and the degree of regulatory oversight and scrutiny given to intrastate oil pipeline rates, varies from state to state. Insofar as effective interstate and intrastate rates are equally applicable to all comparable shippers, we believe that the regulation of oil transportation rates will not affect our operations in any materially different way than such regulation will affect the operations of our competitors.

Further, interstate and intrastate common carrier oil pipelines must provide service on a non-discriminatory basis. Under this open access standard, common carriers must offer service to all similarly situated shippers requesting service on the same terms and under the same rates. When oil pipelines operate at full capacity, access is governed by prorationing provisions set forth in the pipelines’ published tariffs. Accordingly, we believe that our access to oil pipeline transportation services will not materially differ from our competitors’ access to oil pipeline transportation services.

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State Regulation

Texas regulates the drilling for, and the production, gathering and sale of, oil and natural gas, including imposing severance taxes and requirements for obtaining drilling permits. Texas currently imposes a 4.6% severance tax on the market value of oil production and a 7.5% severance tax on the market value of natural gas production. States also regulate the method of developing new fields, the spacing and operation of wells and the prevention of waste of oil and natural gas resources.

States may regulate rates of production and may establish maximum daily production allowables from oil and natural gas wells based on market demand or resource conservation, or both. States do not regulate wellhead prices or engage in other similar direct economic regulation, but we cannot assure you that they will not do so in the future. Should direct economic regulation or regulation of wellhead prices by the states increase, this could limit the amount of oil and natural gas that may be produced from our wells and the number of wells or locations the operators of our properties can drill.

The petroleum industry is also subject to compliance with various other federal, state and local regulations and laws. Some of those laws relate to resource conservation and equal employment opportunity. We do not believe that compliance with these laws will have a material adverse effect on our business.

Title to Properties

We believe that the title to our assets is satisfactory in all material respects. Although title to these properties is subject to encumbrances in some cases, such as customary interests generally retained in connection with the acquisition of real property, customary royalty interests and contract terms and restrictions, liens under operating agreements, liens related to environmental liabilities associated with historical operations, liens for current taxes and other burdens, easements, restrictions, and minor encumbrances customary in the oil and natural gas industry, we believe that none of these liens, restrictions, easements, burdens, and encumbrances will materially detract from the value of these properties or from our interest in these properties.

Employees

The officers of our general partner manage our operations and activities. However, neither we, our general partner nor our subsidiaries have employees. In connection with the closing of our initial public offering, we entered into a management services agreement with Kimbell Operating, which entered into separate service agreements with certain entities controlled by affiliates of our Sponsors and Mr. Duncan, pursuant to which they and Kimbell Operating provide management, administrative and operational services for us, including the operation of our properties. Please read “Management” and “Certain Relationships and Related Party Transactions, and Director Independence” As of March 28, 2017, Kimbell Operating has approximately 10 employees performing services for our operations and activities. We believe that Kimbell Operating has a satisfactory relationship with those employees.

Additional Information

We were formed on October 30, 2015 as a Delaware limited partnership. Our principal executive offices are located at 777 Taylor Street, Suite 810, Fort Worth, Texas 76102. We electronically file various reports with the Securities and Exchange Commission (“SEC”), including annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to such reports. The public may read and copy any materials that we file with the SEC at the SEC’s Public Reference Room at 100 F Street, N.E., Washington, D.C. 20549. The public may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. The SEC also maintains an internet site that contains reports and information statements, and other information regarding issuers that file electronically with the SEC at www.sec.gov. Additionally, information about us, including our reports filed with the SEC, is available through our website at www.kimbellrp.com. These reports are accessible at no charge through our website and are made available as soon as reasonably practicable after such material is filed with or furnished to the SEC. Our website and the information contained on that site, or connected to that site, are not incorporated by reference into this report.

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Item 1A. 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 Annual Report 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. 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.

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 and we completed our initial public offering in February 2017. 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 greatly affects our business, financial condition, results of operations and cash available for distribution.” We do 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

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variable expenses, future quarterly distributions paid to our unitholders will vary significantly from quarter to quarter and may be zero. Please read “Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities—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.

The limited liability company agreement of our general partner contains 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 is controlled by our Sponsors, contains 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 or liquidation to our common units.

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

The board of directors of our general partner is made up of nine members. Therefore, the vote of four directors would be sufficient to prevent us from 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;

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· 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;

· 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 $110.62 per Bbl in September 2013, and the Henry Hub spot market price of natural gas has ranged from a low of $1.49 per MMBtu in March 2016 to a high of $7.63 per MMBtu in February 2014. On March 20, 2017, the WTI posted price for crude oil was $47.79 per Bbl and the Henry Hub spot market price of natural gas was $2.93 per MMBtu. Additionally, natural gas liquids prices have fluctuated from approximately $29.46 Boe in January 2015 to $35.09 Boe in October 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.

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We will be required to take write-downs of the carrying values of our properties 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.

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 years ended December 31, 2016, 2015 and 2014, our predecessor recorded non-cash impairment charges of approximately $5.0 million, $28.7 million and $7.4 million, respectively, primarily 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 may be required to recognize a material impairment of our oil and natural gas properties in the quarter ending March 31, 2017 as a result of our initial public offering.

All of our oil and natural gas properties that were acquired in connection with the consummation of our initial public offering are subject to a step-up in value based on the fair value given to those assets at the initial public offering. In calculating the fair value of our assets (as reflected in our pro forma financial statements in the prospectus for our initial public offering), we utilized a forward oil and natural gas price curve and applied a discount rate to future net revenues that was based on the yield of our common units at the pricing of our initial public offering (which was 8.05%). However, these factors are significantly different from those that we must use in performing our full cost ceiling test in the future, which will require us to use a historical twelve-month average price and a 10% discount rate, which is higher than the initial yield on our common units. Furthermore, using the historical twelve-month average price will result in a lower average price than using the forward oil and natural gas price curve.

Therefore, based on the application of the SEC reserve pricing rules, the application of a 10% discount rate to future net revenues and the step-up in value of our assets, in each case as described above, we currently estimate that a non-cash impairment charge in excess of $100 million could be recognized in the quarter ending March 31, 2017. This potential impairment charge could materially affect our results of operations for such period. This non-cash impairment charge would not have an effect on the amount of cash available to distribute at each quarter end date. We intend to seek an exemption from the SEC staff in applying the test described above in the quarter ending March 31, 2017, but there is no guarantee that the exemption will be granted.

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

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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, 2016, our predecessor received revenue from over 200 operators. For the years ended December 31, 2016 and 2015, our predecessor received approximately 64.2% and 67.8% of its revenues from the top ten operators of its 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 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.

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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, 2016, 31% 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 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;

· development plans;

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· 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.

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

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

If we are unable to make acquisitions on economically acceptable terms from 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 our initial public 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.

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 predecessor’s and our historical estimates of proved reserves and related valuations as of December 31, 2016 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

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first-day-of-the-month price for each month, and costs in effect on the date of the estimate, holding the prices and costs constant throughout the life of the properties. Actual future prices and costs may differ materially from those used in the present value estimate, and future net present value estimates using then current prices and costs may be significantly less than the current estimate. In addition, the 10% discount factor we use when calculating discounted future net cash flows may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the oil and natural gas industry in general.

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

SEC rules require that, subject to limited exceptions, proved undeveloped reserves may only be booked if they relate to wells scheduled to be drilled within five years after the date of booking. This requirement has limited and may continue to limit our ability to book additional proved undeveloped reserves as the operators of our properties pursue their drilling programs. Moreover, we may be required to write down our proved undeveloped reserves if those wells are not drilled within the required five-year timeframe. Furthermore, we typically do not have access to the drilling schedules of our 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.

We entered into a new $50.0 million secured revolving credit facility in connection with our initial public offering. The secured reolving credit facility includes 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 is secured by substantially all of our assets. Our secured revolving credit facility contains various covenants and restrictive provisions that 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.

Our secured revolving credit facility also contains 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 impose on us.

A failure to comply with the provisions of our secured revolving credit facility could result in an event of default, which could enable the lenders to declare, subject to the terms and conditions of our secured revolving credit facility, any outstanding principal of that debt, together with accrued and unpaid interest, to be immediately due and payable. If the payment of the debt is accelerated, cash flows from our operations may be insufficient to repay such debt in full, and our unitholders could experience a partial or total loss of their investment. Our secured revolving credit

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facility contains 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.

Our secured revolving credit facility limits 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 is determined based on our oil and gas properties and the oil and gas properties of our wholly owned subsidiaries. We 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 have substantial unpledged properties, and we may not have the financial resources in the future to make mandatory principal prepayments required under our secured revolving credit facility.

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

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

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

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

· our access to the capital markets may be limited;

· our borrowing costs may increase;

· we 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 oil and natural gas reserves and the operators’ production thereof and our

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cash generated from operations and ability to pay distributions are highly dependent on the successful development and exploitation of our current reserves. As of December 31, 2016, 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.

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.

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.

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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. We have entered into a management services agreement with Kimbell Operating, which has entered into separate service agreements with certain entities controlled by affiliates of our Sponsors and Benny Duncan, pursuant to which they and Kimbell Operating provide management, administrative and operational services to us. In addition, under each of their respective service agreements, affiliates of our Sponsors 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. In addition to the service providers who provide substantial services to us under our services agreement with Kimbell Operating, we rely on third party service providers to perform some of our data entry, investor relations and other functions. If the programs or systems used by our third party service providers are not adequately functioning, we could experience loss of important data. Any of the foregoing consequences could materially adversely affect our business.

A terrorist attack or armed conflict could harm our business.

Terrorist activities, anti-terrorist activities and other armed conflicts involving the United States or other countries may adversely affect the United States and global economies. If any of these events occur, the resulting political instability and societal disruption could reduce overall demand for oil and natural gas, potentially putting downward pressure on demand for our 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 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.

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

In connection with our initial public offering, we entered into a contribution agreement with the Contributing Parties that governs, among other things, their obligation to indemnify us for certain liabilities associated with the entities and assets contributed to us in connection with our initial public offering. Under the contribution agreement, the Contributing Parties are required, severally but not jointly, to indemnify us (i) for a period of one year following the closing of our initial public 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 were 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 our initial public offering until 30 days after the applicable statute of limitations. In addition, pursuant to the contribution agreement, the Contributing Parties, severally but not jointly, indemnified 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 our initial public 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 did not survive the closing of our initial public 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 contributed to us. 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 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 our initial public 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 and cash available for distribution. Please read “Certain Relationships and Related Party Transactions, and Director Independence—Agreements and Transactions with Affiliates in Connection with our Initial Public 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

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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.

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.

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.

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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 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.

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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.

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. For example, in December 2106, the EPA released its final report on the potential impacts of hydraulic fracturing on drinking water resources, concluding that hydraulic fracturing activities can impact drinking water resources under certain circumstances, including large volume spills and inadequate mechanical integrity of wells. These and other 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 Environmental Protection Agency (“EPA”) has adopted regulations under existing provisions of the federal Clean Air Act that, among other things, require preconstruction and operating permits for certain large stationary sources. Facilities required to obtain preconstruction permits for their GHG emissions also will be required to meet “best available control technology” standards that will be established on a case-by-case basis. These EPA rulemakings could adversely affect operations on our properties and restrict or delay the ability of our operators to obtain air permits for new or modified sources. In addition, the EPA has

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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 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;

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· 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.

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 our acquisition of the assets in connection with our initial public offering, record title to the mineral and royalty interests that comprise our initial assets was held by various unrelated entities. At the closing of our initial public offering, a significant amount of these mineral and royalty interests was conveyed to us or our subsidiaries as asset assignments, and we or our subsidiaries became 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 ending March 31, 2017 and the immediately succeeding fiscal quarters due to the number of title transfers that will take place upon the closing of our initial public 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.

Affiliates of our general partner own or control up to an aggregate of 20.9% of our common units, and our Sponsors 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

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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, which could involve decisions by our Sponsors to undertake acquisition opportunities for themselves or any other investment partnership that they control, 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 owe fiduciary duties to our Sponsors, or any other investment partnership that they control, 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 entered into with our Sponsors and the Contributing Parties in connection with our initial public offering, neither our Sponsors nor the Contributing Parties have any obligation to present business opportunities to us, 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 our initial public offering with respect to certain mineral and royalty interests in the Permian Basin, the Bakken/Williston Basin and the Marcellus Shale, 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 these 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 determines 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 determines which costs incurred by it or its affiliates are reimbursable by us;

· our partnership agreement does not restrict our general partner from causing us to reimburse 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 have entered into a management services agreement with Kimbell Operating, which has entered into separate service agreements with certain entities controlled by affiliates of our Sponsors and Mr. Duncan, pursuant to which they and Kimbell Operating provide management, administrative and operational

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services to us, and such entities 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 entered into in connection with our initial public offering 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 or the Contributing Parties from competing with us. Certain of our directors and officers may in the future spend significant time serving, and may have significant duties with, investment partnerships or other private entities that compete with us in seeking out acquisitions and business opportunities and, accordingly, may have conflicts of interest in allocating time or pursuing business opportunities.

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 entered into with our Sponsors and the Contributing Parties in connection with our initial public offering, neither our Sponsors nor the Contributing Parties have any obligation to present business opportunities to us.

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. In addition, certain of our officers and directors, including the individuals who control our Sponsors, may in the future hold similar positions with investment partnerships or other private entities that are in the business of identifying and acquiring mineral and royalty interests. In such capacities, these individuals would likely devote significant time to such other businesses and would be compensated by such other businesses for the services rendered to them. The positions of these directors and officers may give rise to duties that are in conflict with duties owed to us. In addition, these individuals may become aware of business opportunities that may be appropriate for presentation to us as well as the other entities with which they are or may be affiliated. Due to these potential future affiliations, they may have duties to present potential business opportunities to those entities prior to presenting them to us, which could cause additional conflicts of interest. Our Sponsors and their respective affiliates are under no obligation to make any acquisition opportunities available to us, except as provided for under the contribution agreement entered into in connection with our initial public offering.

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, 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 does not have any duty to communicate or offer such opportunity to us. Any such person or entity is not liable to us or to any limited partner for breach of any fiduciary duty or other duty by reason of the fact that such person or entity pursues or acquires such opportunity for itself, directs such opportunity to another person or entity or does not communicate such opportunity or information to us. This may create actual and potential conflicts of interest between us and affiliates of our general partner and result in less than favorable treatment of us and 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

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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 permits our general partner to limit its liability, 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, also provides substantially similar services to other entities and thus is not 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 our initial public offering, we entered into a management services agreement with Kimbell Operating, which entered into separate service agreements with certain entities controlled by affiliates of our Sponsors and Mr. Duncan, pursuant to which they and Kimbell Operating provide management, administrative and operational services to us.

Kimbell Operating also provides 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 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 unlawful; 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:

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

· 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.

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.

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.

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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 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 “Certain Relationships and Related Party Transactions, and Director Independence” 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. Our general partner may not be removed unless such removal is both (i) for cause and (ii) approved by the vote of the holders of not less than 662/3% of all outstanding common units. Affiliates of our general partner own or control an aggregate of 20.9% of our common units, and our Sponsors 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 and their respective affiliates 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. 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 our initial public offering, we entered into a management services agreement with Kimbell Operating, which entered into separate service agreements with certain entities controlled by affiliates of our Sponsors and Mr. Duncan, pursuant to which they and Kimbell Operating 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, and Director Independence—Agreements and Transactions with Affiliates in Connection with our Initial Public Offering—Management Services Agreements.”

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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.

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.

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 not less than the then-current market price of the common units, as calculated in accordance with our partnership agreement. 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 our initial public offering, affiliates of our general partner own or control up to an aggregate of 20.9% of our common units, and our Sponsors will indirectly own and control our general partner.

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

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

· 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.

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.

As a result of our initial public offering, we have 16,332,708 common units outstanding. All the common units issued to the Contributing Parties in our initial public offering, including affiliates of our Sponsors, are subject to resale restrictions under a 180-day lock-up agreement set forth in the contribution agreement entered into in connection with our initial public offering. The lock-up restrictions may not be waived by us without the consent of certain of the underwriters. In addition, any common units held by our Sponsors are subject to a lock-up agreement with the underwriters. These lock-up periods will expire by their terms on August 7, 2017. 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 our initial public 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.

The price of our common units may fluctuate significantly, and unitholders could lose all or part of their investment.

The market price of our common units may decline below the initial public offering price. The market price of our common units may 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;

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· 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 our initial public 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 have incurred and will in the future incur increased costs as a result of being 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 our initial public offering. In addition, the Sarbanes-Oxley Act and the Dodd-Frank Act of 2010, as well as rules implemented by the SEC and the NYSE, require, or will require, publicly traded entities to adopt various corporate governance practices that will further increase our costs. Before we are able to 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.

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 our initial public offering, our predecessor was not required to file reports with the SEC. Effective internal controls are necessary for us to provide reliable financial reports, prevent fraud and operate successfully as a publicly traded partnership. If we cannot provide reliable financial reports or prevent fraud, our reputation and operating results would be harmed. We cannot be certain that our efforts to develop and maintain our internal controls will be successful, that we will be able to maintain adequate controls over our financial processes and reporting in the future or

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that we will be able to comply with our obligations under Section 404 of the Sarbanes-Oxley Act. For example, Section 404 will require us, among other things, to annually review and report on, and our independent registered public accounting firm to attest to, the effectiveness of our internal controls over financial reporting. However, for as long as we are an “emerging growth company” under the JOBS Act, our independent registered public accounting firm will not be required to attest to the effectiveness of our internal control over financial reporting. We must comply with Section 404 (except for the requirement for an auditor’s attestation report) beginning with our fiscal year ending December 31, 2018. 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.

Because we are a publicly traded partnership, the NYSE does not require us to have, and we do not 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. 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.

If you are an ineligible holder, your common units may be subject to redemption.

We have adopted certain requirements regarding those investors who may own our common units. Ineligible holders are limited partners whose nationality, citizenship or other related status would create a substantial risk of cancellation or forfeiture of any property in which we have an interest, as determined by our general partner with the advice of counsel. If you are an ineligible holder, in certain circumstances as set forth in our partnership agreement, your units may be redeemed by us at the then-current market price. The redemption price will be paid in cash or by delivery of a promissory note, as determined by our general partner.

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 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

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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.

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.

On January 24, 2017, the IRS and the U.S. Department of the Treasury published in the Federal Register final regulations (the “Final Regulations”) regarding qualifying income under Section 7704(d)(1)(E) of the Code. The Final Regulations apply to taxable years beginning after January 19, 2017. The Final Regulations provide that income earned from a royalty interest is qualifying income. Under current law and the Final Regulations, we believe that our royalty income is qualifying income and that we satisfy the qualifying income requirement for us to be treated as a partnership for U.S. federal income tax purposes. However, there are no assurances that current law or the Final Regulations will not be revised to take a position that is contrary to our interpretation.

We are unable to predict whether any of these changes or any other proposals will ultimately be enacted or adopted. Any such changes could negatively impact the value of an investment in our common units.

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 the prospectus for our initial public offering or from the positions we take. It may be necessary to resort to administrative or court proceedings to sustain some or all of our counsel’s conclusions or the positions we take. A court may not agree with some or all of our counsel’s conclusions or positions we take. Any contest with the IRS may materially and adversely impact the market for our common units and the price at which they trade. Moreover, the costs of any contest between us and the IRS will result in a reduction in cash available for distribution to our unitholders and thus will be borne indirectly by our unitholders.

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

You will be required to pay federal income taxes and, in 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.

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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.

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.

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 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.

We 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 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 have adopted. 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.

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

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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. As a result, our current unitholders may bear some or all of the tax liability resulting from such audit adjustments, even if such unitholders did not own units in us during the year under audit. 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 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 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.

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 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.

Item 1B. Unresolved Staff Comments

None.

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Item 2. Properties

The information required by Item 2 is contained in Item 1. Business.

Item 3. Legal Proceedings

Although we may, from time to time, be involved in various legal claims arising out of our operations in the normal course of business, we do not believe that the resolution of these matters will have a material adverse impact on our financial condition or results of operations.

Items 4. Mine Safety Disclosures

Not applicable.

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Part II

Item 5. Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities

Our common units are listed on the NYSE under the symbol “KRP.” As of December 31, 2016, our common units were not listed on a domestic exchange or over-the-counter market. Our common units began trading on the NYSE on February 3, 2017, and therefore, we have not set forth quarterly information with respect to the high and low prices for our common units.

On March 29, 2017, the last sales price of our common units, as reported on the NYSE, was $19.50 per unit.

As of March 29, 2017, there were 16,332,708 common units outstanding held by 50 holders of record. Because many of our common units are held by brokers and other institutions on behalf of unitholders, we are unable to estimate the total number of unitholders represented by these holders of record.

Cash Distribution Policy and Restrictions on Distributions

Our partnership agreement requires 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 March 31, 2017. We will adjust the amount of our distribution for the period from the closing of our initial public offering through March 31, 2017, based on the actual length of the period. 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. 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 generally 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 generally intend to incur debt to pay quarterly distributions, although the board of directors of our general partner may choose to do so if they believe it is warranted.

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. If they believe it is warranted, the board of directors of our general partner may 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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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 in connection with our initial public offering, we borrowed $1.5 million under our secured revolving credit facility to fund certain transaction expenses. Our credit agreement contains certain financial tests and covenants that we 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 do 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 our common units.

· 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 entered into a management services agreement with Kimbell Operating in connection with our initial public offering, which entered into separate service agreements with certain entities controlled by affiliates of our Sponsors and Mr. Duncan, pursuant to which they and Kimbell Operating 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 Operating, and to such other entities providing services to us and Kimbell Operating, 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 45 days of the end of each quarter. We will adjust the amount of our distribution for the period from the closing of our initial public offering through March 31, 2017, based on the actual length of the period.

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Securities Authorized for Issuance under Equity Compensation Plans.

See “Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters” for information regarding our equity compensation plans as of December 31, 2016.

Unregistered Sales of Securities.

In connection with our formation in October 2015, we issued (i) the non-economic general partner interest in us to Kimbell Royalty GP, LLC and (ii) a 100% limited partner interest in us to Rivercrest Royalties, LLC for an aggregate of $1,000. These issuances were exempt from registration under Section 4(a)(2) of the Securities Act.

On December 20, 2016, we entered into a Contribution, Conveyance, Assignment and Assumption Agreement with Kimbell Royalty GP, LLC, Kimbell Intermediate GP, LLC, Kimbell Intermediate Holdings, LLC, Kimbell Royalty Holdings, LLC and the other parties named therein, pursuant to which we agreed to issue common units and distribute the net proceeds of the initial public offering to the Contributing Parties in connection with such Contributing Parties’ contribution of certain assets to us at or prior to the closing of the initial public offering. The common units were issued in reliance on the exemptions for sales of securities not involving a public offering, as set forth in Rule 506(b) promulgated under the Securities Act and in Section 4(a)(2) of the Securities Act.

Use of Proceeds from Registered Securities.

On February 3, 2017, we completed our IPO of common units pursuant to our registration statement on Form S-1 declared effective by the SEC on February 2, 2017. Raymond James & Associates, Inc. acted as representative of the underwriters and Raymond James & Associates, Inc., RBC Capital Markets, LLC, Stifel, Nicolaus & Company, Incorporated, acted as the joint book-running managers in the offering. Pursuant to the registration statement, we registered the offer and sale of 5,750,000 units of our $18.00 common units, which included 5,000,000 units sold by us, and 750,000 units subject to an option granted to the underwriters by the selling unitholder. The sale of the units in our IPO and the sale of units covered by the option closed on February 8, 2016. Our IPO terminated upon completion of the closing.

The net proceeds of our IPO, based on the public offering price of $18.00 per unit, were approximately $96.3 million. As described in the prospectus, we used the proceeds to make a cash distribution to the entities and individuals that contributed, directly or indirectly, certain mineral and royalty interests to us in connection with the offering.

Repurchases of Equity Securities. None.

Equity Compensation Plan

The required information can be found in Part III, Item 12.

Item 6. Selected Financial Data

SELECTED FINANCIAL DATA

Kimbell Royalty Partners, LP was formed in October 2015. On February 8, 2017, we completed our initial public offering of 5,750,000 common units representing limited partner interests, which included 750,000 common units pursuant to the underwriters’ option to purchase additional common units. Concurrently with the closing of our initial public offering, the mineral and royalty interests making up our initial assets were contributed to us by the Contributing Parties. As a result, as of December 31, 2016, Kimbell Royalty Partners, LP had not yet acquired any of such assets. In this Annual Report, 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 selected historical financial data of our predecessor.

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The selected historical financial data of our predecessor presented as of and for the years ended December 31, 2016 and 2015 are derived from the audited historical financial statements of our predecessor included elsewhere in this Annual Report. The selected historical financial data below should be read in conjunction with “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Item 8. Financial Statements and Supplementary Data.”

The interests underlying the oil, natural gas and natural gas liquids production revenues of our predecessor only represent approximately 11% of our partnership’s total future undiscounted cash flows, based on the reserve report prepared by Ryder Scott as of December 31, 2016.

	Predecessor Historical
	Year Ended December 31,
	2016			2015			2014
Statement of Operations Data:
Revenue:
Oil, natural gas and NGL revenues	$	3,606,659		$	4,684,923		$	7,219,822
Cost and expenses:
Production and ad valorem taxes	280,474			426,885			568,327
Depreciation, depletion and accretion expense	1,604,208			4,008,730			4,044,802
Impairment of oil and natural gas properties	4,992,897			28,673,166			7,416,747
Operating expense	750,792			747,264			526,727
General and administrative expenses	1,746,218			1,789,884			1,757,377
Total costs and expenses	9,374,589			35,645,929			14,313,980
Operating loss	(5,767,930		)	(30,961,006		)	(7,094,158		)
Interest expense	424,841			385,119			302,118
Loss before income taxes	(6,192,771		)	(31,346,125		)	(7,396,276		)
State income taxes	19,848			(32,199		)	16,970
Net loss	$	(6,212,619	)	$	(31,313,926	)	$	(7,413,246	)
Statement of Cash Flows Data:
Net cash provided by (used in):
Operating activities	$	1,086,603		$	2,713,133		$	4,038,018
Investing activities	$	(97,464	)	$	(538,640	)	$	(53,463,030	)
Financing activities	$	(863,000	)	$	(2,062,818	)	$	39,645,738
Other Financial Data:
Adjusted EBITDA (1)	$	1,434,234		$	2,325,949		$	4,518,656
Selected Balance Sheet Data:
Cash and cash equivalents	$	505,880		$	379,741		$	268,066
Total assets	$	20,538,731		$	27,905,790		$	58,753,888
Long-term debt	$	10,598,860		$	11,448,860		$	9,003,860
Total liabilities	$	11,906,869		$	13,666,368		$	10,556,272
Members’ equity	$	8,631,862		$	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 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.

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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.

	Predecessor Historical
	For the Years Ended December 31,
	2016			2015			2014
Net loss	$	(6,212,619	)	$	(31,313,926	)	$	(7,413,246	)
Depreciation, depletion and accretion expense	1,604,208			4,008,730			4,044,802
Interest expense	424,841			385,119			302,118
Income taxes	19,848			(32,199		)	16,970
EBITDA	(4,163,722		)	(26,952,276		)	(3,049,356		)
Impairment of oil and natural gas properties	4,992,897			28,673,166			7,416,747
Unit-based compensation	605,059			605,059			151,265
Adjusted EBITDA	$	1,434,234		$	2,325,949		$	4,518,656

	Predecessor Historical
	For the Years Ended December 31,
	2016			2015			2014
Reconciliation of net cash provided by operating activities to Adjusted EBITDA:
Net cash provided by operating activities	$	1,086,603		$	2,713,133		$	4,038,018
Interest expense	424,841			385,119			302,118
State income taxes	19,848			(32,199		)	16,970
Impairment of oil and natural gas properties	(4,992,897		)	(28,673,166		)	(7,416,747		)
Amortization of loan origination costs	(46,969		)	(40,965		)	(34,916		)
Amortization of tenant improvement allowance	34,369			14,321			—
Unit-based compensation	(605,059		)	(605,059		)	(151,265		)
Changes in operating assets and liabilities:
Oil, natural gas and NGL revenues receivable	66,455			(464,877		)	373,644
Other receivables	(1,027,172		)	1,371,540			—
Other current assets	—			(6,441		)	(72,742		)
Accounts payable	952,800			(1,604,999		)	(77,152		)
Other current liabilities	(76,541		)	(8,683		)	(27,284		)
EBITDA	$	(4,163,722	)	$	(26,952,276	)	$	(3,049,356	)
Add:
Impairment of oil and natural gas properties	4,992,897			28,673,166			7,416,747
Unit-based compensation	605,059			605,059			151,265
Adjusted EBITDA	$	1,434,234		$	2,325,949		$	4,518,656

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ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion should be read together with “Item 6. Selected Financial Data” and “Item 8. Financial Statements and Supplementary Data” and related notes included elsewhere in this Annual Report.

On February 8, 2017, we completed our initial public offering of 5,750,000 common units representing limited partner interests, which included 750,000 common units pursuant to the underwriters’ option to purchase additional common units. Concurrently with the closing of our initial public offering, the mineral and royalty interests making up our initial assets were contributed to us by the Contributing Parties. As a result, as of December 31, 2016, Kimbell Royalty Partners, LP had not yet acquired any of such assets. Unless otherwise indicated, the historical financial information in this “Management’s Discussion and Analysis of Financial Condition and Results of Operations” reflects only the historical financial results of our predecessor, Rivercrest Royalties, LLC, and does not include the results of the Partnership as a whole. The interests underlying the oil, natural gas and natural gas liquids production revenues of our predecessor only represent approximately 11% of our partnership’s total future undiscounted cash flows, based on the reserve report prepared by Ryder Scott as of December 31, 2016.

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

Overview

Kimbell Royalty Partners, LP is 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.

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Business Environment

Commodity Prices and Demand

Oil and natural gas prices have been historically volatile and may continue to be volatile in the future. In late 2014, prices for oil and natural gas declined precipitously, and prices remained low throughout 2015 and for the majority of 2016 until rebounding in the fourth quarter of 2016. WTI has ranged from a low of $26.19 per Bbl in February 2016 to a high of $107.52 per Bbl in June 2014, 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 December 30, 2016, the WTI posted price for crude oil was $53.75] per Bbl and the Henry Hub spot market price of natural gas was $3.71 per MMBtu.

The following table, as reported by the EIA, sets forth the average prices for oil and natural gas for the years ended December 31, 2016, 2015 and 2014:

Average	For the Years Ended December 31,
Prices:	2016		2015		2014
Oil (Bbl)	$	43.14	$	48.69	$	93.26
Natural gas (MMBtu)	$	2.52	$	2.63	$	4.39
Natural gas liquids (Bbl)	$	27.91	$	27.69	$	29.29

Source: EIA.

Rig Count

The Baker Hughes U.S. Rotary Rig count was 756 active rigs at March 3, 2017, a greater than 8% increase from 698 active rigs at December 31, 2015. The 698 active rig count at December 31, 2015 is a greater than 61% decline from 1,811 active rigs at December 31, 2014. In addition, according to the Baker Hughes U.S. Rotary Rig count, rig activity in the 20 states in which we own mineral and royalty interests has increased, with a greater than 9% increase from 630 active rigs at December 31, 2015 to 687 active rigs at March 3, 2017.

Sources of Our Revenue

Our revenues are derived from royalty payments we receive from our operators based on the sale of oil, natural gas and natural gas liquids production, as well as the sale of natural gas liquids that are extracted from natural gas during processing. Our predecessor’s revenues are primarily derived from mineral and royalty interests, which, together with its non-operated working interests (which were not contributed to us), we refer to as “Interests.” For the year ended December 31, 2016, our predecessor’s revenues were generated 60% from oil sales, 30% from natural gas sales and 10% from natural gas liquid sales. For the year ended December 31, 2015, our predecessor’s revenues were generated 63% from oil sales, 29% from natural gas sales and 8% from natural gas liquid sales. Our revenues may vary significantly from period to period as a result of changes in volumes of production sold or changes in commodity prices.

Neither we nor our predecessor 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 mineral and royalty interests. As a result, we may realize the benefit of any short-term increase in the price of oil, natural gas and natural gas liquids, but we will not be protected against decreases in price, and if the price of oil, natural gas and natural gas liquids decreases significantly, our business, results of operation and cash available for distribution may be materially adversely effected. We may enter into hedging arrangements in the future.

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Reserves and Pricing

The table below identifies our predecessor’s proved reserves at December 31, 2016, 2015 and 2014, in each case based on our management’s estimates. The prices used to estimate proved reserves for all periods were held constant throughout the life of the properties and have been adjusted for quality, transportation fees, geographical differentials, marketing bonuses or deductions and other factors affecting the price received at the wellhead.

Predecessor Estimated Net Proved	As of December 31,
Reserves:	2016	2015	2014
Oil (MBbls)	886	958	1,115
Natural gas (MMcf)	7,140	7,166	7,898
Natural gas liquids (MBbls)	235	207	213
Total (MBoe)	2,311	2,360	2,644

	Unweighted Arithmetic Average First-Day-of-the-Month Prices
	As of December 31,
	2016		2015		2014
Oil (Bbls)	$	42.75	$	50.28	$	94.99
Natural gas (Mcf)	$	2.49	$	2.59	$	4.35

Adjusted EBITDA

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 the income (loss) 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 flows provided by operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP. Our computations of Adjusted EBITDA may not be comparable to other similarly titled measures of other companies.

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

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

No Effect Given to Formation Transactions in connection with Initial Public Offering

The historical financial statements included in this Annual Report of our predecessor, Rivercrest Royalties, LLC, do not reflect the financial condition or results of operations of Kimbell Royalty Partners, LP. These historical financial statements do not give effect to the formation transactions that were completed in connection with the initial public offering of Kimbell Royalty Partners, LP. In connection with our initial public offering, our predecessor assigned all of its non-operating working interests to an affiliate that was not contributed to us and the member of our

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predecessor contributed all of its membership interests in Rivercrest Royalties, LLC to us in exchange for common units and a portion of the net proceeds from the offering. In addition, the Contributing Parties directly or indirectly contributed to us the other assets that make up our initial assets in exchange for common units and a portion of the net proceeds from the offering. The combination of the assets contributed to us by the Contributing Parties was accounted for at fair value as asset acquisitions. The fair value of the purchase consideration was based upon the fair value of the common units issued in the formation transactions.

The historical financial data of our predecessor included in this “Management’s Discussion and Analysis of Financial Condition and Results of Operations” does not include the results of Kimbell Royalty Partners and may not give you an accurate indication of what our actual results would have been if these formation transactions had been completed at the beginning of the periods presented or of what our future results of operations are likely to be. The interests underlying the oil, natural gas and natural gas liquids production revenues of our predecessor only represent approximately 11% of our partnership’s total future undiscounted cash flows, based on the reserve report prepared by Ryder Scott as of December 31, 2016.

Impairment of Oil and Natural Gas Properties

During the years ended December 31, 2016 and December 31, 2015, our predecessor recorded non-cash impairment charges of approximately $5.0 million and $28.7 million, respectively, primarily 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.

Therefore, based on the application of the SEC reserve pricing rules, the application of a 10% discount rate to future net revenues and the step-up in value of our assets, in each case as described above, we currently estimate that a non-cash impairment charge in excess of $100 million could be recognized in the quarter ending March 31, 2017. This potential impairment charge could materially affect our results of operations for such period. However, this non-cash impairment charge will not have an effect on the amount of cash available for distribution at each quarter end date. We intend to seek an exemption from the SEC staff in applying the test described above in the quarter ending March 31, 2017, but there is no guarantee that the exemption will be granted.

Credit Agreements

In January 2014, our predecessor entered into a credit agreement with Frost Bank, as lender. For the year ended December 31, 2016, our predecessor’s interest expense was $0.4 million. Our predecessor had outstanding borrowings of $10.6 million as of December 31, 2016. We did not assume any indebtedness of our predecessor in connection with the initial public offering. In connection with our initial public offering, we entered 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

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from new or existing lenders). Please read “Liquidity and Capital Resources-Indebtedness.” At the closing of our initial public offering, we borrowed $1.5 million to fund certain transaction related expenses and our entrance into a management services agreement with Kimbell Operating Company, LLC.

Acquisition Opportunities

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

Management Services Agreements

In connection with our initial public offering, we entered into a management services agreement with Kimbell Operating, which entered into separate service agreements with certain entities controlled by affiliates of our Sponsors and Mr. Duncan, pursuant to which they and Kimbell Operating provide management, administrative and operational services to us. In addition, under each of their respective service agreements, affiliates of our Sponsors will identify, evaluate and recommend to us acquisition opportunities and negotiate the terms of such acquisitions. 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.

Non-Operated Working Interest Assignment

Prior to the formation transactions, our predecessor assigned its non-operated working interests and associated asset retirement obligations to an affiliated company. As of the closing of its initial public offering, Kimbell Royalty Partners, LP did not own any working interests and did not have any asset retirement obligations or any lease operating expenses as a working interest owner.

Principal Components of Our Cost Structure

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

Production and Ad Valorem Taxes

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

Depreciation and Depletion

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

General and Administrative Expense

General and administrative expenses are costs not directly associated with the production of oil, natural gas and natural gas liquids and include the cost of executives and employees and related benefits, office expenses and fees for professional services. In connection with our initial public offering, we entered into a management services agreement with Kimbell Operating, which entered into separate service agreements with certain entities controlled by affiliates of our Sponsors and Mr. Duncan, pursuant to which they and Kimbell Operating provide management, administrative and

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operational services to us. In addition, under each of their respective service agreements, affiliates of our Sponsors will identify, evaluate and recommend to us acquisition opportunities and negotiate the terms of such acquisitions.

We anticipate incurring incremental general and administrative expenses of approximately $1.5 million that we expect to incur annually as a result of operating as a publicly traded 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. These incremental general and administrative expenses are not reflected in the historical financial statements of our predecessor.

Interest Expense

For the year ended December 31, 2016, our predecessor’s interest expense was $0.4 million. Our predecessor had outstanding borrowings of $10.6 million as of December 31, 2016. We did not assume any indebtedness of our predecessor in connection with our initial public offering. In connection with the initial public offering, we have entered 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). At the closing of our initial public offering, we borrowed $1.5 million to fund certain transcation expenses and our entrance into a management services agreement with Kimbell Operating Company, LLC. Please read “Liquidity and Capital Resources-Indebtedness.”

Income Tax Expense

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

Texas imposes a franchise tax (commonly referred to as the Texas margin tax, which is considered an income tax) at a rate of 0.95% on gross revenues less certain deductions, as specifically set forth in the Texas margin tax statute. A significant portion of our mineral and royalty interests are located in Texas basins and producing regions.

Predecessor Results of Operations

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

Predecessor Results of Operations

	Predecessor Results of Operations
	For the Years Ended December 31,
	2016			2015			2014
Operating Results:
Oil, natural gas and NGL revenues	$	3,606,659		$	4,684,923		$	7,219,822
Costs and expenses
Production and ad valorem taxes	280,474			426,885			568,327
Depreciation, depletion and accretion expense	1,604,208			4,008,730			4,044,802
Impairment of oil and natural gas properties	4,992,897			28,673,166			7,416,747
Operating expense	750,792			747,264			526,727
General and administrative expenses	1,746,218			1,789,884			1,757,377
Total costs and expenses	9,374,589			35,645,929			14,313,980
Operating income (loss)	(5,767,930		)	(30,961,006		)	(7,094,158		)
Interest expense	424,841			385,119			302,118
Income (loss) before income taxes	(6,192,771		)	(31,346,125		)	(7,396,276		)
State income taxes	19,848			(32,199		)	16,970
Net income (loss)	$	(6,212,619	)	$	(31,313,926	)	$	(7,413,246	)
Production Data:
Oil (Bbls)	55,587			59,321			50,570
Natural gas (Mcf)	496,778			548,386			515,130
Natural gas liquids (Bbls)	22,360			22,351			17,991
Combined volumes (Boe) (6:1)	160,743			173,070			154,416
Average daily combined volumes (Boe/d) (6:1)	440			474			423

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Comparison of the Year Ended December 31, 2016 to the Year Ended December 31, 2015

Oil, Natural Gas and Natural Gas Liquids Revenues

Our predecessor’s revenues for the year ended December 31, 2016 was $3.6 million, a decrease of $1.1 million, from $4.7 million for the year ended December 31, 2015. Our predecessor’s decrease in revenues was primarily due to the industry-wide steep declines in the price of oil, natural gas and natural gas liquids experienced through most of 2016, coupled with a decrease in production for the year ended December 31, 2016 of 10,345 Boe when compared to production for the year ended December 31, 2015. This decrease in production for the year ended December 31, 2016 when compared to production for the year ended December 31, 2015 was primarily due to decreased drilling on our predecessor’s interests during the year ended December 31, 2016 due to the industry wide steep declines in the price of oil, natural gas and natural gas liquids experienced through most of 2016.

Our predecessor’s revenues are a function of oil, natural gas, and natural gas liquids production volumes sold and average prices received for those volumes. Our predecessor’s production volumes for the year ended December 31, 2016 were 160,743 Boe, or 440 Boe/d, a decrease from 173,070 Boe, or 474 Boe/d, for the year ended December 31, 2015. Our predecessor’s operators received an average of $38.69 per Bbl of oil, $2.21 per Mcf of natural gas and $15.99 per Bbl of natural gas liquids for the volumes sold during the year ended December 31, 2016. Our predecessor’s operators received an average of $49.79 per Bbl of oil, $2.44 per Mcf of natural gas and $17.56 per Bbl of natural gas liquids and for the volumes sold during the year ended December 31, 2015.

Production and Ad Valorem Taxes

Our predecessor’s production and ad valorem taxes decreased by $146,411 to $280,474 for the year ended December 31, 2016, from $426,885 for the year ended December 31, 2015. The decrease in production and ad valorem taxes was attributable to a decline in oil, natural gas and natural gas liquids revenues.

Depreciation, Depletion and Accretion Expense

Our predecessor’s depreciation, depletion and accretion expense decreased by $2.4 million to $1.6 million for the year ended December 31, 2016 from $4.0 million for the year ended December 31, 2015. The average depletion rate per barrel was $9.86 and $23.16 for the years ended December 31, 2016 and 2015, respectively. The decrease in the average depletion rate per barrel was primarily attributable to a $28.7 million impairment recorded on oil, natural gas and natural gas liquids properties in 2015, which resulted in a lower depletable base in oil, natural gas and natural gas liquids properties for the year ended December 31, 2016. Depletion is the amount of cost basis of oil and natural gas properties at the beginning of a period attributable to the volume of hydrocarbons extracted during such period, calculated on a units-of-production basis. Estimates of proved developed producing reserves are a major component in the calculation of depletion. Our predecessor has historically adjusted its depletion rates in the fourth quarter of each year based upon the year end reserve report and other times during the year when circumstances indicate that there has been a significant change in reserves or costs.

Impairment of Oil, Natural Gas and Natural Gas Liquids Expense

Our predecessor utilizes the full cost method of accounting for our oil and natural gas properties. Under the full cost method, capitalized costs are subject to a ceiling test, which limits such pooled costs to the aggregate of the present value of future net revenues attributable to proved oil, natural gas and natural gas liquids reserves discounted at 10%, plus the lower of cost or market value of unproved properties. Our predecessor does not assign any value to unproved properties in which it holds an Interest. The full cost ceiling is evaluated at the end of each fiscal quarter and additionally when events indicate possible impairment. Impairments totaled $5.0 million for the year ended December 31, 2016 primarily due to changes in reserve values resulting from the continued decline in commodity prices during most of 2016. Impairments totaled $28.7 million for the year ended December 31, 2015 primarily due to the impact that declines in commodity prices had on the value of reserve estimates.

Marketing and Other Deductions

Our predecessor’s marketing and other deductions includes product marketing expense, which is a post-production expense, and lease operating expenses related to its non-operated working interests. Our predecessor’s

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marketing and other deductions for the years ended December 31, 2016 and 2015 were $0.8 million and $0.7 million, respectively.

General and Administrative Expense

Our predecessor’s general and administrative expenses for the year ended December 31, 2016 were $1.7 million, a decrease of $0.1 million from $1.8 million for the year ended December 31, 2015. Decreases in general and administrative expenses were attributable to the decreased cost related to the offering of Kimbell Royalty Partners, LP from the year ended December 31, 2015 to the year ended December 31, 2016.

Interest Expense

Our predecessor’s interest expense for the year ended December 31, 2016 was $424,841, an increase of $39,722 from $385,119 for the year ended December 31, 2015. The increase of $39,722 was attributable to average outstanding debt of $11.1 million for the year ended December 31, 2016 as compared to the average outstanding debt of $10.6 million for the year ended December 31, 2015.

State Income Taxes

Our predecessor’s state income taxes for the year ended December 31, 2016 were $19,848, an increase of $52,047, as compared to a net credit of $32,199 for the year ended December 31, 2015. This change was due to income tax credits received during the year ended December 31, 2015 from states for overpayments of income tax payments made by our predecessor in prior years. Our predecessor operates within legal structures that are disregarded for federal and most state income tax purposes. Our predecessor’s income tax expense primarily consists of income taxes on our predecessor’s oil, natural gas and natural gas liquids revenue in Texas and other states in which our predecessor holds interests in oil, natural gas and natural gas liquids producing properties.

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

Oil, Natural Gas and Natural Gas Liquids Revenues

Our predecessor’s revenues for the year ended December 31, 2015 were $4.7 million, a decrease of $2.5 million, from $7.2 million for the year ended December 31, 2014. Our predecessor’s decrease in oil, natural gas and natural gas liquids revenues was primarily due to the sharp decline in commodity prices experienced over the second half of 2014 and through the year ended December 31, 2015, partially offset by an increase in production of 18,654 Boe year over year.

Our predecessor’s revenues are a function of oil, natural gas, and natural gas liquids production volumes sold and average prices received for those volumes. Our predecessor’s production volumes for the year ended December 31, 2015 were 173,070 Boe, or 474 Boe/d, an increase from 154,416 Boe, or 423 Boe/d, for the year ended December 31, 2014. The increase in production volumes was primarily due to acquisitions of Interests during the second half of 2014 and a full year of production on the Interests during 2015. Our predecessor’s operators received an average of $49.79 per Bbl of oil, $2.44 per Mcf of natural gas and $17.56 per Bbl of natural gas liquids and for the volumes sold for the year ended December 31, 2015. Our predecessor’s operators received an average of $87.25 per Bbl of oil, $4.22 per Mcf of natural gas and $35.26 per Bbl of natural gas liquids for the volumes sold for the year ended December 31, 2014.

Production and Ad Valorem Taxes

Our predecessor’s production and ad valorem taxes decreased to $0.4 million for the year ended December 31, 2015, a decrease of $0.2 million, from $0.6 million for the year ended December 31, 2014. The decrease in production and ad valorem taxes was attributable to the sharp decline in commodity prices experienced throughout the industry beginning in the fourth quarter of 2014 through the beginning of the first quarter of 2016 and lower estimated mineral reserve valuations.

Depreciation, Depletion and Accretion Expense

Our predecessor’s depreciation, depletion and accretion expense remained relatively flat at $4.0 million for the year ended December 31, 2015, consistent with the $4.0 million for the year ended December 31, 2014. The average

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depletion rate per barrel was $23.16 and $26.19 for the year ended December 31, 2015 and 2014, respectively. The decrease in the average depletion rate per barrel was primarily attributable to the $7.4 million impairment recorded on our predecessor’s oil, natural gas and natural gas liquids properties in 2014, which resulted in a lower depletable base in oil, natural gas and natural gas liquids properties for the year ended December 31, 2015. The decrease in the depletable base was offset by an increase in production from 154,416 Boe for the year ended December 31, 2014 to 173,070 Boe for the year ended December 31, 2015.

Impairment of Oil, Natural Gas and Natural Gas Liquids Expense

Our predecessor’s impairments totaled $28.7 million for the year ended December 31, 2015 primarily due to changes in reserve values resulting from the continued sharp decline in commodity prices and other factors in the last half of 2014 and through 2015. Impairments totaled $7.4 million for the year ended December 31, 2014 primarily due to the impact that declines in commodity prices had on the value of our predecessor’s reserve estimates.

Marketing and Other Deductions

Our predecessor’s marketing and other deductions for the year ended December 31, 2015 were $0.7 million compared to $0.5 million for the year ended December 31, 2014. Marketing and other deductions includes product marketing expense, which is a post-production expense, and lease operating expenses related to its non-operated working interests. Increases in marketing and other deductions were primarily due to a full year of operations during the year ended December 31, 2015 for the majority of our predecessor’s oil, natural gas and natural gas liquids properties. A significant portion of the oil, natural gas and natural gas liquids properties were not held for the entirety of the year ended December 31, 2014 as the acquisition of these oil, natural gas and natural gas liquid properties were made during the year ended December 31, 2014.

General and Administrative Expense

Our predecessor’s general and administrative expenses for the year ended December 31, 2015 were $1.8 million, which is consistent with general and administrative expenses for the year ended December 31, 2014.

Interest Expense

Our predecessor’s interest expense for the year ended December 31, 2015 was $0.4 million, an increase of $0.1 million from the year ended December 31, 2014. The increase in interest expense is due to increased borrowings under our predecessor’s credit facility.

State Income Taxes

Our predecessor’s state income taxes for the year ended December 31, 2015 were a net credit of $32,199, a change of $49,169, as compared to a $16,970 expense for the year ended December 31, 2014. This change was due to income tax credits received during the year ended December 31, 2015 from states for overpayments of income tax payments made by our predecessor in prior years. Our predecessor’s income tax expense primarily consists of income taxes on our predecessor’s oil, natural gas and natural gas liquids revenue in Texas and other states in which our predecessor holds interests in oil, natural gas and natural gas liquids producing properties.

Liquidity and Capital Resources

Overview

Our primary sources of liquidity are cash flows from operations and equity and debt financings and our primary uses of cash are for distributions to our unitholders and for growth capital expenditures, including the acquisition of mineral and royalty interests in oil and natural gas properties. We have entered 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), to initially be used for general partnership purposes, including working capital and acquisitions and certain transaction expenses. Following the formation transactions in connection with our initial public offering, we borrowed $1.5 million under our secured revolving credit facility.

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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.” Available cash for each quarter will be determined by the board of directors of our general partner following the end of such quarter. We expect that available cash for each quarter will generally equal our Adjusted EBITDA for the quarter, less cash needed for debt service and other contractual obligations and fixed charges and reserves for future operating or capital needs, including replacement or growth capital expenditures, that the board of directors may determine is appropriate.

Unlike a number of other master limited partnerships, we do not generally 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. If they believe it is warranted, the board of directors of our general partner may withhold replacement capital expenditures from cash available for distribution, which would reduce the amount of cash available for distribution in the period(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.

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 do so if they believe it is warranted.

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. The board of directors of our general partner may change our distribution policy at any time at its discretion, without unitholder approval, and could elect not to pay distributions for one or more quarters.

Predecessor Cash Flows

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

	For the Years Ended December 31,
	2016			2015			2014
Cash Flow Data:
Cash flows provided by operating activities	$	1,086,603		$	2,713,133		$	4,038,018
Cash flows used in investing activities	(97,464		)	(538,640		)	(53,463,030		)
Cash flows provided by (used in) financing activities	(863,000		)	(2,062,818		)	39,645,738
Net increase (decrease) in cash	$	126,139		$	111,675		$	(9,779,274	)

Operating Activities (Predecessor)

Our predecessor’s operating cash flow is impacted by many variables, the most significant of which is the change in prices for oil, natural gas and natural gas liquids. Prices for these commodities are determined primarily by

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prevailing market conditions. Regional and worldwide economic activity, weather and other substantially variable factors influence market conditions for these products. These factors are beyond our and our predecessor’s control and are difficult to predict. The decreases in cash flows provided by operating activities for the year ended December 31, 2016 as compared to the year ended December 31, 2015 of $1.6 million were largely attributable to lower oil, natural gas and natural gas liquids sales prices.

The decrease in cash flows provided by operating activities for the year ended December 31, 2015 as compared to the year ended December 31, 2014 of $1.3 million was largely attributable to lower oil, natural gas and natural gas liquids sales prices.

Investing Activities (Predecessor)

The purchase of Interests in producing oil and gas properties and office equipment accounted for our predecessor’s cash outlays for investing activities. For the year ended December 31, 2016, our predecessor used $0.1 million for investing activities compared to $0.5 million for the year ended December 31, 2015. The $0.4 million decrease was due to less drilling activity on our predecessor’s working interest properties during the year ended September 30, 2016.

Cash used in investing activities was $0.5 million for the year ended December 31, 2015 as compared to $53.5 million for the year ended December 31, 2014. This decrease is due to the fact that our predecessor made no acquisitions during the year ended December 31, 2015, compared to the six acquisitions of Interests our predecessor made during the year ended December 31, 2014.

Financing Activities (Predecessor)

Cash used in financing activities was $0.9 million for the year ended December 31, 2016 as compared to cash used in financing activities of $2.1 million for the year ended December 31, 2015. During the year ended December 31, 2016, our predecessor repaid $0.9 million of long-term debt. Our predecessor borrowed $3.0 million in long-term debt, offset by $4.5 million in distributions to members and repayments on long-term debt of $0.6 million, in the year ended December 31, 2015.

Cash used in financing activities was $2.1 million for the year ended December 31, 2015 as compared to cash provided by financing activities of $39.6 million for the year ended December 31, 2014. Decreases in financing activities of $41.7 million were primarily attributable to a decrease of $34.1 million in proceeds from issuance of membership units, an additional $1.1 million in distributions to members, and $42.0 million less in borrowings on long term debt offset by a decrease of $35.4 million in repayments on long-term debt.

Capital Expenditures

During the year ended December 31, 2016, our predecessor spent $0.1 million on lease and well equipment related to our working interests and office equipment. During the year ended December 31, 2015, our predecessor spent $0.5 million on additional costs from the 2014 acquisitions of Interests, lease and well equipment and intangible drilling costs related to our working interests and office equipment. During the year ended December 31, 2014, our predecessor spent $53.5 million on acquisitions of Interests.

Indebtedness

Predecessor Credit Facility

Our predecessor entered into a credit agreement with Frost Bank for up to $50.0 million. The credit facility is subject to borrowing base restrictions and is collateralized by certain properties. The borrowing base is $20 million with interest payable monthly on Alternate Base Rate loans or at the end of the interest period on any Eurodollar loans. As of December 31, 2016, our predecessor’s total indebtedness on its credit agreement was approximately $10.6 million with an average interest rate of 3.39%. The loan matures in January 2018. The credit facility contains certain restrictive covenants. As of December 31, 2016, the Company was in compliance with all of the covenants included in the credit facility. On February 7, 2017, our predecessor repaid the entire outstanding principal and interest balance on the credit facility with cash proceeds from the sale of our predecessor’s mineral and royalty and overriding royalty interests to

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Kimbell Royalty Partners, LP. For further information on our predecessor’s indebtedness, refer to Note 3 in our predecessor’s audited financial statements. We did not assume any indebtedness of our predecessor in connection with the formation transactions.

New Revolving Credit Agreement

We entered into a $50.0 million revolving credit facility in connection with our initial public offering, which is secured by substantially all of our assets and the assets of our wholly owned subsidiaries. Under the secured revolving credit facility, availability under the facility will equal the lesser of the aggregate maximum commitments of the lenders and the borrowing base. The borrowing base will be determined based on the value of our oil and natural gas properties and the oil and gas properties of our wholly owned subsidiaries. The oil and gas properties of our non-wholly owned subsidiaries are not subject to a lien and will not be included in borrowing base valuations. The secured revolving credit facility permits aggregate commitments under the facility to be increased to $100.0 million, subject to the satisfaction of certain conditions and the procurement of additional commitments from new or existing lenders.

The secured revolving credit facility contains various affirmative, negative and financial maintenance covenants. These covenants limit our ability to, among other things, incur or guarantee additional debt, make distributions on, or redeem or repurchase, common units, make certain investments and acquisitions, incur certain liens or permit them to exist, enter into certain types of transactions with affiliates, merge or consolidate with another company and transfer, sell or otherwise dispose of assets. The secured revolving credit facility also contains 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. The secured revolving credit facility also contains customary events of default, including non-payment, breach of covenants, materially incorrect representations, cross-default, bankruptcy and change of control. As of March [29], 2016, we have borrowed $1.5 million to fund certain transaction related expenses and our management services agreement with Kimbell Operating Company, LLC.

Predecessor Contractual Obligations

The following table summarizes the contractual obligations of our predecessor as of December 31, 2016:

Predecessor Contractual Obligations

(in thousands)

	Total		Less than 1 year		1-3 years		3-5 years		More than 5 years
Long-term debt (1)	$	10,988,103	$	359,301	$	10,628,802	$	—	$	—
Operating leases	283,564		77,176		206,388		—		—
Total	$	11,271,667	436,477		$	10,835,190	$	—	$	—

(1) Our predecessor’s credit agreement matures in January 2018. Includes principal as well as interest payments. For purposes of calculating future interest on the credit facility, assumes no change in balance or rate from December 31, 2016.

Internal Controls and Procedures

We are not currently required to comply with the SEC’s rules implementing Section 404 of the Sarbanes-Oxley Act, and are therefore not required to make a formal assessment of the effectiveness of our internal controls over financial reporting for that purpose. We are required to comply with the SEC’s rules implementing Section 302 of the Sarbanes-Oxley Act, which will require our management to certify financial and other information in our quarterly and annual reports and provide an annual management report on the effectiveness of our internal controls over financial reporting. We must comply with Section 404 (except for the requirement for an auditor’s attestation report) beginning with our fiscal year ending December 31, 2018. To comply with the requirements of being a public company, we will

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need to implement additional controls, reporting systems and procedures and hire additional accounting, finance and legal staff.

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

New and Revised Financial Accounting Standards

We qualify as an “emerging growth company” pursuant to the provisions of the JOBS Act, enacted on April 5, 2012. Section 107 of the JOBS Act provides that an “emerging growth company” can take advantage of the extended transition period provided in Section 7(a)(2)(B) of the Securities Act for complying with new or revised accounting standards. However, we chose to “opt out” of such extended transition period, and as a result, we will comply with new or revised accounting standards on the relevant dates on which adoption of such standards is required for non-emerging growth companies. Our election to “opt out” of the extended transition period is irrevocable.

The effects of new accounting pronouncements are discussed in Note 2-Summary of Significant Accounting Policies within our predecessor’s financial statements included elsewhere in this Annual Report.

Critical Accounting Policies

The discussion and analysis of our financial condition and results of operations are based upon the historical financial statements of our predecessor, which have been prepared in accordance with GAAP. Certain of our accounting policies involve judgments and uncertainties to such an extent that there is a reasonable likelihood that materially different amounts would have been reported under different conditions, or if different assumptions had been used. The following discussions of critical accounting estimates, including any related discussion of contingencies, address all important accounting areas where the nature of accounting estimates or assumptions could be material due to the levels of subjectivity and judgment necessary to account for highly uncertain matters or the susceptibility of such matters to change. Below, we have provided expanded discussion of our more significant accounting policies.

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

Use of Estimates

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

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

Method of Accounting for Oil and Natural Gas Properties

We account for oil, natural gas and natural gas liquids producing activities using the full cost method of accounting. Accordingly, all costs incurred in the acquisition, exploration and development of proved oil, natural gas and natural gas liquids properties, including the costs of abandoned properties, dry holes, geophysical costs and annual lease rentals are capitalized. Sales or other dispositions of oil, natural gas and natural gas liquids properties are accounted for

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as adjustments to capitalized costs, with no gain or loss recorded unless the ratio of cost to proved reserves would significantly change.

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

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

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

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

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

Revenue Recognition

Mineral and royalty interests represent the right to receive revenues from the sale of oil, natural gas and natural gas liquids, less production and ad valorem taxes and post-production expenses. The pricing of oil, natural gas and natural gas liquids from the properties in which we own a mineral or royalty interest is primarily determined by supply and demand in the marketplace and can fluctuate considerably. As an owner of mineral and royalty interests, we have no involvement or operational control over the volumes and method of sale of the oil, natural gas and natural gas liquids produced and sold from the property. We have no rights or obligations to explore, develop or operate the property and do not incur any of the costs of exploration, development and operation of the property.

Oil, natural gas and natural gas liquids revenues from our Interests are recognized when the associated product is sold.

Impairment

The net capitalized costs of proved oil, natural gas and natural gas liquids properties are subject to a full cost ceiling limitation in which the costs are not allowed to exceed their related estimated future net revenues discounted at 10%. Estimated future net revenues are calculated as estimated future revenues from oil, natural gas and natural gas liquids properties less production taxes, ad valorem taxes and gas marketing expenses. To the extent capitalized costs of

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evaluated oil, natural gas and natural gas liquids properties, net of accumulated depreciation, depletion, amortization, impairment and deferred income taxes exceed the discounted future net revenues of proved oil, natural gas and natural gas liquids reserves, less any related income tax effects, the excess capitalized costs are charged to expense. In calculating future net revenues, prices are calculated as the average oil, natural gas and natural gas liquids prices during the preceding 12-month period prior to the end of the current reporting period, determined as the unweighted arithmetic average first-day-of-the-month prices for the prior 12-month period and costs used are those as of the end of the appropriate quarterly period.

Accounting for Unit-Based Compensation

We measure unit-based compensation grants at their grant date fair value and related compensation expense is recognized over the vesting period of the grant. The long-term incentive plan and related accounting policies are defined and described more fully in Note 6 in our predecessor’s audited historical financial statements. The determination of the fair value of an award requires significant estimates and subjective judgments regarding, among other things, the appropriate option pricing model, the expected life of the award and forfeiture rate assumptions. In the event unit options are awarded, estimates of the fair value of unit options granted are completed using a Black-Scholes option valuation model, which requires us to make several assumptions. There were no unit options granted during the years ended December 31, 2016 and 2015.

Inflation

Inflation in the United States has been relatively low in recent years and did not have a material impact on results of operations for the period from January 1, 2014 through December 31, 2016.

Off-Balance Sheet Arrangements

As of December 31, 2016, neither we nor our predecessor had any off-balance sheet arrangements other than operating leases.

Item 7A. Quantitative and Qualitative Disclosures about Market Risk

Commodity Price Risk

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

Credit Risk

As an owner of mineral and royalty interests, we have no control over the volumes or method of sale of oil, natural gas and natural gas liquids produced and sold from the underlying properties. During the year ended December 31, 2016, three purchasers accounted for approximately 20%, 13% and 10% of our predecessor’s oil, natural gas and natural gas liquids revenues. During the year ended December 31, 2015, three purchasers accounted for approximately 19%, 13% and 10% of oil, natural gas and natural gas liquids sales revenue. It is believed that the loss of any single purchaser would not have a material adverse effect on our results of operations.

Interest Rate Risk

We will have exposure to changes in interest rates on our indebtedness. As of December 31, 2016, our predecessor had total borrowings outstanding under its credit facility of $10.6 million. The impact of a 1% increase in the interest rate on this amount of debt would result in an increase in interest expense of approximately $0.1 million annually, assuming that our indebtedness remained constant throughout the year. We do not currently have any interest rate hedges in place.

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Item 8. Financial Statements and Supplementary Data

The information required here begins on page F-1.

Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

None.

Item 9A. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

As required by Rule 13a-15(b) under the Exchange Act, we have evaluated, under the supervision and with the participation of management of our general partner, including our general partner’s principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this Annual Report. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we file or submit under the Exchange Act is accumulated and communicated to management, including our general partner’s principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized, and reported within the time periods specified in the rules and forms of the SEC. Based upon that evaluation, our general partner’s principal executive officer and principal financial officer concluded that our disclosure controls and procedures were effective as of December 31, 2016.

Management’s Report on Internal Control Over Financial Reporting

This Annual Report on Form 10-K does not include a report on management’s assessment regarding internal control over financial reporting due to a transition period established by the rules of the SEC for newly public companies.

Attestation Report of the Registered Public Accounting Firm

This Annual Report on Form 10-K does not include an attestation report of our independent registered public accounting firm due to a transition period established by the rules of the SEC for newly public companies. Further, our independent registered public accounting firm will not be required to formally attest to the effectiveness of our internal controls over financial reporting for as long as we are an “emerging growth company” pursuant to the provisions of the JOBS Act.

Changes in Internal Control over Financial Reporting

There were no changes in our internal control over financial reporting during the quarter ended December 31, 2016 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Prior to our initial public offering, we were not required to comply with the SEC’s rules implementing Section 404 of the Sarbanes-Oxley Act, and were therefore not required to make a formal assessment of the effectiveness of our internal controls over financial reporting for that purpose. Upon becoming a public company, we will be required to comply with the SEC’s rules implementing Section 302 of the Sarbanes-Oxley Act, which will require our management to certify financial and other information in our quarterly and annual reports and provide an annual management report on the effectiveness of our internal controls over financial reporting. We will not be required to make our first assessment of our internal controls over financial reporting until the year following our first annual report required to be filed with the SEC. To comply with the requirements of being a public company, we will need to implement additional financial and management controls, reporting systems and procedures.

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company” pursuant to the provisions of the JOBS Act or as long as we are a non-accelerated filer. Please read “Summary—Emerging Growth Company Status” and “Risk Factors—Risks Inherent in an Investment in Us—For as long as we are an emerging growth company, we will not be required to comply with certain disclosure requirements that apply to other public companies.”

Item 9B. Other Information

None.

PART III

Item 10. Directors, Executive Officers and Corporate Governance

The following table shows information for the executive officers, directors and director nominees of our general partner. Directors hold office until their successors have been elected or qualified or until the earlier of their death, resignation, removal or disqualification. Executive officers serve at the discretion of the board. Messrs. R. Ravnaas and D. Ravnaas are father and son, respectively, and Messrs. Fortson and Wynne are father-in-law and son-in-law, respectively.

Name	Age (as of December 31, 2016)	Position With Our General Partner
Robert D. Ravnaas	59	Chief Executive Officer and Chairman of the Board of Directors
R. Davis Ravnaas	31	President and Chief Financial Officer
Jeff McInnis	40	Chief Accounting Officer
Matthew S. Daly	44	Senior Vice President—Corporate Development
Brett G. Taylor	56	Executive Vice Chairman of the Board of Directors
Benny D. Duncan	74	Director
Ben J. Fortson	84	Director
T. Scott Martin	66	Director
Mitch S. Wynne	58	Director
William H. Adams III	58	Independent Director
C.O. Ted Collins, Jr.	78	Independent Director
Craig Stone	54	Independent Director

Robert D. Ravnaas. Robert D. Ravnaas was appointed Chief Executive Officer of our general partner and Chairman of the board of directors of our general partner in November 2015. Mr. R. Ravnaas served as President of Cawley, Gillespie & Associates, Inc., a petroleum engineering firm, from 2011 until February 2017. He has also served as President and director of Rivercrest Royalties II, LLC since 2014, and as President and director of Rivercrest Royalties, LLC since 2013, and he is a partial owner of certain of the Contributing Parties. Prior to joining Cawley, Gillespie & Associates, Inc. in 1983, he worked as a Production Engineer for Amoco Production Company from 1981 to 1983. Mr. R. Ravnaas received a Bachelor of Science degree with special honors in Chemical Engineering from the University of Colorado at Boulder and a Master of Science degree in Petroleum Engineering from the University of Texas at Austin. He is a registered professional engineer in Texas and a member of the Society of Petroleum Engineers, the Society of Petroleum Evaluation Engineers and the American Association of Petroleum Geologists. Mr. R. Ravnaas was selected to serve as a director because of his broad knowledge of, and extensive experience in, the oil and gas industry.

R. Davis Ravnaas. R. Davis Ravnaas was appointed President and Chief Financial Officer of our general partner in November 2015. Mr. D. Ravnaas co-founded Rivercrest Royalties, LLC in October 2013, served as Vice President and Chief Financial Officer from November 2013 to October 2015 and has served as President and Chief Financial Officer of Rivercrest Royalties, LLC since October 2015. He has also served as Vice President and Chief Financial Officer of Rivercrest Royalties II, LLC since August 2014, and he is a partial owner of certain of the Contributing Parties. From 2010 to 2012, Mr. D. Ravnaas was responsible for sourcing, evaluating and monitoring investments in energy and industrials companies as an associate investment professional with Crestview Partners, a New York based private equity fund with $6.0 billion under management. Mr. D. Ravnaas left Crestview Partners in 2012 to attend the Stanford Graduate School of Business, where he earned his Master in Business Administration in 2014. Mr. D. Ravnaas also has an AB in Economics from Princeton University and a MSc in Finance and Economics from the London School of Economics.

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Jeff McInnis. Jeff McInnis was appointed Chief Accounting Officer of our general partner in November 2015. Mr. McInnis has served as Chief Accounting Officer of Rivercrest Royalties, LLC since May 2015. From June 2014 until May 2015, Mr. McInnis worked as an independent consultant, advising oil and gas companies on accounting and financial reporting matters. Previously, he was Director of Financial Reporting at JP Energy Partners LP, a midstream master limited partnership, from 2012 to June 2014. From 2010 to 2012, Mr. McInnis was Controller at Hill & Hill Production, a suite of private, family-run entities concentrated on exploration and production oil and gas ventures. Additionally, he held positions at PricewaterhouseCoopers LLP in their Assurance group from 2003 to 2006 and again from 2009 to 2010 and as a Transaction Services Manager from 2006 to 2009, during which time he specialized in providing services to a variety of public and private clients. From 2001 to 2003, he was an International Accounting Analyst at Triton Energy Limited. Mr. McInnis has a Bachelor of Business Administration degree in Accounting and Finance and a Master of Accounting degree from Texas Christian University and is a certified public accountant.

Matthew S. Daly. Matthew S. Daly was appointed Senior Vice President—Corporate Development of our general partner effective September 2016. Mr. Daly has also served as Senior Vice President—Corporate Development of Rivercrest Royalties, LLC since August 2016. From 2014 to 2016, Mr. Daly served as Senior Analyst—Energy at Hirzel Capital Management LLC, a Dallas-based hedge fund, where he managed public energy investments. From 2004 to 2013, he served as Senior Analyst—Energy at Kleinheinz Capital Partners, Inc., where he managed public and private energy investments and assisted with macro hedging trades. From 2002 to 2004, Mr. Daly was a Vice President—Mergers and Acquisitions at Lazard Frères & Co. in New York City. Mr. Daly has a Bachelor of Business Administration from the University of Texas at Austin and a Master of Business Administration from the University of Chicago Booth School of Business and is a certified public accountant.

Brett G. Taylor. Brett G. Taylor was appointed as Executive Vice Chairman of the board of directors of our general partner in November 2015. Mr. Taylor has over 33 years of experience in the oil and gas industry as a petroleum landman. He began his career at Texas Oil and Gas Corporation from 1982 to 1985. He then spent thirteen years at Fortson Oil Company, where he served as Land Manager and Vice President—Land from 1985 to 1998. In 1998, Mr. Taylor co-founded, with Joe B. Neuhoff, Neuhoff-Taylor Royalty Company and began acquiring producing royalties and minerals. He has also served as President and Chief Executive Officer of various Taylor Companies since 1998, and certain of such companies are Contributing Parties. In 1999, Messrs. Taylor, Fortson and R. Ravnaas co-founded Kimbell Royalty Partners group, which is led by the Kimbell Art Foundation. Mr. Taylor has a Bachelor of Business Administration—Petroleum Land Management degree from the University of Texas at Austin and is a member of the American Association of Professional Landmen. Mr. Taylor was selected to serve as a director because of his broad knowledge of land management, oil and gas title, due diligence and related matters.

Benny D. Duncan. Benny D. Duncan was appointed as a director of our general partner in November 2016. Mr. Duncan has over 50 years of experience in the oil and gas industry. He began his career with Vaughn Petroleum, Inc. and its subsidiaries (“VPI”) as Assistant Land Manager from 1961 through 1970. Mr. Duncan joined First National Bank of Dallas in 1970 as Land Manager and Engineering Technician and later served as Assistant Vice President—Trust Oil and Gas Division until 1975. Mr. Duncan then returned to VPI, where he served in various operational positions from 1975 to 1990, including as Director and Land Manager, Executive Vice President and Chief Operating Officer, and President. In 1994, Mr. Duncan was actively involved in the formation of Vaughn Petroleum Royalty Partners, Ltd. (“VPRP”). He served as Manager of VPRP’s properties in 1999, and he has continued to manage such properties since their sale in 2004. Between 2005 and 2009, Mr. Duncan formed: Trunk Bay Royalty Partners, Ltd., Bitter End Royalties, LP, Oil Nut Bay Royalties, LP, Nail Bay Royalties, LLC and Gorda Sound Royalties, LP, which make up a portion of the Contributing Parties. He has served as manager of (i) Trunk Bay, LLC, the general partner of Trunk Bay Royalty Partners, Ltd., since 2005; (ii) Bitter End, LLC, the general partner of Bitter End Royalties, LP, since 2008; (iii) Oil Nut Bay, LLC, the general partner of Oil Nut Bay Royalties, LP, since 2008; (iv) Nail Bay Royalties, LLC since 2009; and (v) Gorda Sound, LLC, the general partner of Gorda Sound Royalties, LP, since 2009. Mr. Duncan studied business administration at Arlington State College (now the University of Texas at Arlington). He is an active member of the American Association of Professional Landmen and the Dallas Petroleum Club. Mr. Duncan was selected to serve as a director because of his broad knowledge of, and extensive experience in, the oil and gas industry.

Ben J. Fortson. Ben J. Fortson was appointed as a director of our general partner in November 2015. He has nearly 60 years of experience in the oil and gas industry. Mr. Fortson has served as President and Chief Executive Officer of Fortson Oil Company since 1986 and has been Vice President and Chief Investment Officer of the Kimbell Art Foundation, a Contributing Party, since 1975. Mr. Fortson has served on the Board of Trustees of the Kimbell Art Foundation since 1964. He is also a trustee and Vice President of the Burnett Foundation, a member of the Exchange Club of Fort Worth, a Trustee Emeritus of Texas Christian University and an Emeritus Member of the All-American Wildcatters. Mr. Fortson has a Bachelor of Arts degree from the Texas Christian University. Mr. Fortson was selected to serve as a director because of his broad knowledge of, and extensive experience in, the oil and gas industry.

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T. Scott Martin. T. Scott Martin was appointed as a director of our general partner in November 2015. Mr. Martin has served as Chief Executive Officer of our predecessor since July 2014 and Chief Executive Officer and Chairman of EE3 LLC since 2013. He has also served as Chairman of the board of directors of Rivercrest Royalties II, LLC since July 2015. He has over 35 years of experience in the oil and gas industry. Mr. Martin founded Ellora Energy LLC in 1995 and was Chairman and Chief Executive Officer of Ellora Energy Inc. from 2002 to 2010. Before that, he was Chief Operating Officer of Alta Energy Corporation from 1992 to 1994, Chief Executive Officer of TPEX Exploration, Inc. from 1990 to 1992 and a consulting engineer at BWAB, Inc. from 1985 to 1990. Mr. Martin began his career in the oil and gas industry in 1979 at Amoco Production Company. Mr. Martin has a Bachelor of Arts degree in Biology from Colorado College and a degree in Chemical Engineering from the University of Colorado at Boulder. He is a member of the Society of Petroleum Engineers and the Independent Petroleum Association of America. Mr. Martin was selected to serve as a director because of his broad knowledge of, and extensive experience in, the oil and gas industry.

Mitch S. Wynne. Mitch S. Wynne was appointed as a director of our general partner in November 2015. He has been President and owner of Wynne Petroleum Co. since 1992. Mr. Wynne has been engaged in the oil and gas industry for 35 years. In 2013, he founded MSW Royalties, LLC, a Contributing Party, where he serves as manager. Mr. Wynne served on the board of Inspire Insurance Solutions from 1997 to 2002, Millers Mutual Insurance in 1997 and the All Saints’ Episcopal School from 1994 to 1996. He has also served on the board of the Union Gospel Mission in Fort Worth since 2010. Mr. Wynne has a Bachelor of Arts degree in Political Science from Washington and Lee University. Mr. Wynne was selected to serve as a director because of his broad knowledge of, and extensive experience in, the oil and gas industry.

William H. Adams III. William H. Adams III was appointed as a director of our general partner effective as of the date that our common units were first listed on the NYSE. Since 2007, Mr. Adams has served as Chairman and Principal Owner of Texas Appliance Supply, Inc., a wholesale and retail appliance distribution company. From 1981 to 2006, Mr. Adams held a variety of positions in the commercial and energy banking sector, including as Executive Regional President of Texas Bank in Fort Worth and as President of Frost Bank—Arlington. From 2001 to 2010, Mr. Adams served as a member of the board of directors of XTO Energy, Inc., and he currently serves as a member of the board of directors of Morningstar Partners, a private oil and gas production company. Mr. Adams has a Bachelor of Business Administration in Finance from Texas Tech University. Mr. Adams was selected to serve as a director because of his extensive experience in the energy banking sector and as a former director of a public oil and gas company.

C.O. Ted Collins, Jr. C.O. Ted Collins, Jr. was appointed as a director of our general partner effective as of the date that our common units were first listed on the NYSE. Mr. Collins has over 57 years of experience in the oil and gas industry, and he has been an independent oil and gas producer since 2000. Mr. Collins previously served as President of Collins & Ware Inc. from 1988 to 2000. From 1982 to 1988, Mr. Collins served as President of Enron Oil & Gas Co. and HNG Oil Company. From 1969 to 1982, he served as Executive Vice President of American Quasar Petroleum Company. Mr. Collins also serves as a member of the board of directors of Energy Transfer Equity, LP, Oasis Petroleum Corp., CLL Global Research Foundation and RSP Permian, Inc. Mr. Collins is a past President of the Permian Basin Petroleum Association, the Permian Basin Landmen’s Association and the Petroleum Club of Midland, and has served as Chairman of the Midland Wildcat Committee since 1984. Mr. Collins has a Bachelor of Science in Geological Engineering from the University of Oklahoma. Mr. Collins was selected to serve as a director because of his broad knowledge of, and extensive experience in, the oil and gas industry, as well as his prior experience as a director of the general partner of a master limited partnership.

Craig Stone. Craig Stone was appointed as a director of our general partner effective as of the date that our common units were first listed on the NYSE. Mr. Stone concluded a 30-year career with Ernst & Young LLP when he retired effective September 2015. Prior to his retirement from Ernst & Young LLP, Mr. Stone was an audit partner and the Fort Worth Managing Partner at Ernst & Young LLP. Over the course of his career, he has served many public oil and gas clients and assisted in numerous mergers, acquisitions and public offerings, including initial public offerings, secondary offerings and public debt transactions. In February 2017, Mr. Stone accepted a position with the Hills Church where he oversees and manages construction and campus expansion and enhancement plans. He has a Bachelor of Sciences in Accounting from Abilene Christian University and is a certified public accountant. Mr. Stone was selected to serve as a director because of his extensive financial experience with public oil and gas companies.

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Board Leadership Structure

Robert D. Ravnaas currently serves as the Chief Executive Officer and Chairman of the board of directors of our general partner. The board of directors of our general partner has no policy with respect to the separation of the offices of chairman of the board of directors and chief executive officer. Instead, that relationship is defined and governed by the limited liability company agreement of our general partner, which permits the same person to hold both offices. Directors of the board of directors of our general partner are appointed by Kimbell Holdings, which is jointly owned by our Sponsors. Accordingly, unlike holders of common stock in a corporation, our unitholders will have only limited voting rights on matters affecting our business or governance, subject in all cases to any specific unitholder rights contained in our partnership agreement.

Board Role in Risk Oversight

Our corporate governance guidelines provide that the board of directors of our general partner is responsible for reviewing the process for assessing the major risks facing us and the options for their mitigation. This responsibility is largely satisfied by the audit committee, which is responsible for reviewing and discussing with management and our registered public accounting firm our major risk exposures and the policies management has implemented to monitor such exposures, including our financial risk exposures and risk management policies.

Committees of the Board of Directors

The board of directors of our general partner has an audit committee and a conflicts committee. We do not have a compensation committee, but rather that the board of directors of our general partner has authority over compensation matters. The board may also have such other committees as they determine from time to time.

Audit Committee

We are required to have an audit committee of at least three members, and all its members are required to meet the independence and experience standards established by the NYSE and Rule 10A-3 promulgated under the Exchange Act, subject to certain transitional relief during the one-year period following consummation of our initial public offering. The audit committee is composed of William H. Adams III and Craig Stone. The audit committee assists the board of directors in its oversight of the integrity of our financial statements and our compliance with legal and regulatory requirements and partnership policies and controls. The audit committee has the sole authority to retain and terminate our independent registered public accounting firm, approves all auditing services and related fees and the terms thereof performed by our independent registered public accounting firm, and pre-approves any non-audit services and tax services to be rendered by our independent registered public accounting firm. The audit committee is also responsible for confirming the independence and objectivity of our independent registered public accounting firm. Our independent registered public accounting firm is given unrestricted access to the audit committee and our management, as necessary.

Each of Messrs. Adams and Stone is deemed to be “financially literate” as defined by the listing standards of NYSE, and Mr. Stone is deemed an “audit committee financial expert,” as defined in SEC regulations. Our audit committee charter is posted on the “Corporate Governance” section of our website.

Conflicts Committee

In accordance with the terms of our partnership agreement, at least two members of the board of directors of our general partner will serve on our conflicts committee to review specific matters that may involve conflicts of interest. The conflicts committee is currently composed of William H. Adams III and Craig Stone. The members of our conflicts committee cannot be officers or employees of our general partner or directors, officers or employees of its affiliates or the Contributing Parties, and must meet the independence and experience standards established by the NYSE and the Exchange Act to serve on an audit committee of a board of directors. In addition, the members of our conflicts committee cannot own any interest in our general partner, its affiliates or the Contributing Parties or any interest in us or our subsidiaries other than common units or awards, if any, under our long-term incentive plan.

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Code of Business Conduct and Ethics

We have adopted a Code of Business Conduct and Ethics applicable to all employees, directors and officers. Our Code of Business Conduct and Ethics covers topics including, but not limited to, conflicts of interest, insider dealing, competition, discrimination and harassment, confidentiality, bribery and corruption, sanctions and compliance procedures. Our Code of Business Conduct and Ethics covers topics including, but not limited to, conflicts of interest, gifts and disclosure controls. Our Code of Business Conduct and Ethics are posted on the “Corporate Governance” section of our website.

Section 16(a) Beneficial Ownership Reporting Compliance

Section 16(a) of the Exchange Act requires directors, executive officer and persons who beneficially own more than 10 percent of a registered class of our equity securities to file with the SEC initial reports of ownership and reports or changes in ownership of such equity securities. Such persons are also required to furnish us with copies of all Section 16(a) forms that they file. During the year ended December 31, 2016, we did not have a registered class of equity securities.

Item 11. Executive Compensation

Compensation Discussion and Analysis

We and our general partner were formed in October 2015 and we did not complete our initial public offering, or own any of the mineral and royalty assets that make up our initial assets, until February 2017. As a result, neither we nor our general partner accrued or paid any obligations with respect to management compensation or retirement benefits for the directors and executive officers of our general partner during the year ended December 31, 2016. Accordingly, we are not presenting any compensation for historical periods. We do not have a compensation committee. The board of directors of our general partner has authority over compensation matters.

Our general partner has the sole responsibility for conducting our business and for managing our operations, and its board of directors and executive officers make decisions on our behalf. We do not and will not directly employ any of the persons responsible for managing our business. Our general partner’s executive officers manage and operate our business as part of the services provided by Kimbell Operating to our general partner under a management services agreement. All of our general partner’s executive officers and other employees necessary to operate our business are employed and compensated by Kimbell Operating or an entity with which Kimbell Operating arranges for the provision of services, subject to reimbursement by our general partner. The compensation for all of our executive officers is indirectly paid by us to the extent provided for in our partnership agreement because we reimburse our general partner for payments it makes to Kimbell Operating.

Certain of the executive officers of our general partner have responsibilities to both us and our Sponsors, certain of the Contributing Parties or Kimbell Operating, and these executive officers will allocate their time between managing our business and managing the respective businesses of our Sponsors, certain of the Contributing Parties and Kimbell Operating. Although we bear an allocated portion of Kimbell Operating’s costs of providing compensation and benefits to Kimbell Operating employees who serve as the executive officers of our general partner and provide services to us, our general partner, and not us, have control over such costs and establishes or directs the compensation policies or practices of Kimbell Operating. All compensation-related decisions for Kimbell Operating, including all determinations with respect to any awards that may be made to our executive officers, key employees and independent directors under any long-term incentive plan we adopt, are made by the board of directors of our general partner or a committee thereof that may be established for such purpose.

Please read the description of the long-term incentive plan we adopted prior to the completion of our initial public offering below under the heading “—Long-Term Incentive Plan.”

The executive officers of our general partner, as well as the employees of our Sponsors, the Contributing Parties and Kimbell Operating who provide services to us, may participate in employee benefit plans and arrangements sponsored by our Sponsors, the Contributing Parties and Kimbell Operating, including plans that may be established in

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the future. In accordance with the terms of our partnership agreement, we reimburse our general partner for compensation related expenses it determines are attributable to the portion of the executive’s time dedicated to providing services to us. Except with respect to any awards granted under our long-term incentive plan, we expect that compensation paid or awarded by us in 2017 will consist only of the portion of compensation that is allocated to us and our general partner pursuant to our general partner’s allocation methodology and subject to the terms of the partnership agreement and our management services agreement with Kimbell Operating.

In the future, as our general partner formulates and implements the compensation programs for our executive officers, our general partner or Kimbell Operating may provide different or additional compensation components, benefits or perquisites to our executive officers, to ensure they are provided with a balanced, comprehensive and competitive compensation structure.

Long-Term Incentive Plan

In order to incentivize our management and directors to continue to grow our business, the board of directors of our general partner adopted a long-term incentive plan (“LTIP”) for employees, officers, consultants and directors of our general partner, Kimbell Operating and their respective affiliates, who perform services for us. Our general partner implemented the LTIP prior to the completion of our initial public offering to provide maximum flexibility with respect to the design of compensatory arrangements for individuals providing services to us. As of the date of filing of this report, neither we nor our general partner have made any decisions regarding any specific grants under the LTIP. We expect to file a registration statement on Form S-8 in the near term and to make decisions with respect to initial grants under the LTIP the second quarter of 2017.

The description of the LTIP set forth below is a summary of the material features of the LTIP. This summary, however, does not purport to be a complete description of all the provisions of the LTIP. This summary is qualified in its entirety by reference to the LTIP, which has been filed as an exhibit to a Form 8-K.

The purpose of the LTIP is to provide a means to attract and retain individuals who are essential to our growth and profitability and to encourage them to devote their best efforts to advancing our business by affording such individuals a means to acquire and maintain ownership of awards, the value of which is tied to the performance of our common units. The LTIP provides for the grant of unit options, unit appreciation rights, restricted units, unit awards, phantom units, distribution equivalent rights and cash awards (collectively, “awards”). These awards are intended to align the interests of employees, officers, consultants and directors with those of our unitholders and to give such individuals the opportunity to share in our long-term performance. Any awards that are made under the LTIP will be approved by the board of directors of our general partner or a committee thereof that may be established for such purpose. We are responsible for the cost of awards granted under the LTIP.

Administration

The LTIP is administered by the board of directors of our general partner or an alternative committee appointed by the board of directors of our general partner, which we refer to together as the “committee” for purposes of this summary. The committee administers the LTIP pursuant to its terms and all applicable state, federal, or other rules or laws. The committee has the power to determine to whom and when awards will be granted, determine the amount of awards (measured in cash or of our common units), proscribe and interpret the terms and provisions of each award agreement (the terms of which may vary), accelerate the vesting provisions associated with an award, delegate duties under the LTIP and execute all other responsibilities permitted or required under the LTIP. In the event that the committee is not comprised of “non-employee directors” within the meaning of Rule 16b-3 under the Exchange Act, we expect that the full board of directors or a subcommittee of two or more non-employee directors will administer all awards granted to individuals that are subject to Section 16 of the Exchange Act.

Securities to be Offered

The maximum aggregate number of common units that may be issued pursuant to any and all awards under the LTIP shall not exceed 2,041,600 common units, subject to adjustment due to recapitalization or reorganization, or related to forfeitures or expiration of awards, as provided under the LTIP. Under the LTIP, the maximum aggregate grant date fair value of awards granted to a non-employee director of our general partner, in such individual’s capacity as a non-employee director, during any calendar year will not exceed $500,000 (or $600,000 in the first year in which an

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individual becomes a non-employee director). We expect that our board of directors, or a committee thereof, will approve the grant of awards equivalent to a maximum of [ ] common units in connection with any awards granted in the second quarter of 2017.

If any common units subject to any award are not issued or transferred, or cease to be issuable or transferable for any reason, including (but not exclusively) because units are withheld or surrendered in payment of taxes or any exercise or purchase price relating to an award or because an award is forfeited, terminated, expires unexercised, is settled in cash in lieu of common units, or is otherwise terminated without a delivery of units, those common units will again be available for issue, transfer, or exercise pursuant to awards under the LTIP, to the extent allowable by law. Common units to be delivered pursuant to awards under our LTIP may be common units acquired by our general partner in the open market, from any other person, directly from us, or any combination of the foregoing.

Awards

Unit Options

We may grant unit options to eligible persons. Unit options are rights to acquire common units at a specified price. The exercise price of each unit option granted under the LTIP will be stated in the unit option agreement and may vary; provided, however, that, the exercise price for a unit option must not be less than 100% of the fair market value per common unit as of the date of grant of the unit option. Unit options may be exercised in the manner and at such times as the committee determines for each unit option and the term of the unit option will not exceed ten years. The committee will determine the methods and form of payment for the exercise price of a unit option and the methods and forms in which common units will be delivered to a participant.

Unit Appreciation Rights

A unit appreciation right is the right to receive, in cash or in common units, as determined by the committee, an amount equal to the excess of the fair market value of one common unit on the date of exercise over the grant price of the unit appreciation right. The committee will be able to make grants of unit appreciation rights and will determine the time or times at which a unit appreciation right may be exercised in whole or in part. The exercise price of each unit appreciation right granted under the LTIP will be stated in the unit appreciation right agreement and may vary; provided, however, that, the exercise price must not be less than 100% of the fair market value per common unit as of the date of grant of the unit appreciation right. The term of the unit appreciation right will not exceed ten years.

Restricted Units

A restricted unit is a grant of a common unit subject to a risk of forfeiture, performance conditions, restrictions on transferability and any other restrictions imposed by the committee in its discretion. Restrictions may lapse at such times and under such circumstances as determined by the committee. Unless otherwise determined by the committee, a common unit distributed in connection with a unit split or unit dividend, and other property distributed as a dividend, will generally be subject to restrictions and a risk of forfeiture to the same extent as the restricted unit with respect to which such common unit or other property has been distributed. Unless otherwise determined by the committee, each restricted unit will be entitled to receive distributions in the same manner as other outstanding common units.

Unit Awards

The committee will be authorized to grant common units that are not subject to restrictions. The committee may grant unit awards to any eligible person in such amounts as the committee, in its sole discretion, may select.

Phantom Units

Phantom units are rights to receive common units, cash or a combination of both at the end of a specified period. The committee may subject phantom units to restrictions (which may include a risk of forfeiture) to be specified in the phantom unit agreement that may lapse at such times determined by the committee. Phantom units may be satisfied by delivery of common units, cash equal to the fair market value of the specified number of common units covered by the phantom unit or any combination thereof determined by the committee. Cash distribution equivalents may be paid during or after the vesting period with respect to a phantom unit, as determined by the committee.

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Distribution Equivalent Rights

The committee will be able to grant distribution equivalent rights in tandem with awards under the LTIP (other than unit awards or an award of restricted units), or distribution equivalent rights may be granted alone. Distribution equivalent rights entitle the participant to receive cash equal to the amount of any cash distributions made by us during the period the distribution equivalent right is outstanding. Payment of cash distributions pursuant to a distribution equivalent right issued in connection with another award may be subject to the same vesting terms as the award to which it relates or different vesting terms, in the discretion of the committee.

Miscellaneous

Tax Withholding

At our discretion, and subject to conditions that the committee may impose, the payment of any applicable taxes with respect to an award may be satisfied by withholding from any payment related to an award or by the withholding of common units issuable pursuant to the award based on the fair market value of our common units in each case up to the maximum statutory rate.

Anti-Dilution Adjustments

In the event that any distribution, recapitalization, split, reverse split, reorganization, merger, consolidation, split-up, spin-off, combination, repurchase or exchange of our common units, issuance of warrants or other rights to purchase our common units or other similar transaction or event affects our common units, then a corresponding and proportionate adjustment shall be made in accordance with the terms of the LTIP, as appropriate, with respect to the maximum number of units available under the LTIP, the number of units that may be acquired with respect to an award, and, if applicable, the exercise price of an award, in order to prevent dilution or enlargement of awards as a result of such events.

Change of Control

The effect, if any, of a change of control on outstanding awards will be described in the applicable award agreement.

Termination of Employment or Service

The consequences of the termination of a participant’s employment, consulting arrangement or membership on the board of directors will be determined by the committee in the terms of the relevant award agreement.

Director Compensation

We and our general partner were formed in October 2015 and we did not complete our initial public offering, or own any of the mineral and royalty assets that make up our initial assets, until February 2017.As such, did not accrued or paid any obligations with respect to compensation for directors of our general partner during the year ended December 31, 2016.

Messrs. R. Ravnaas, Duncan, Fortson, Taylor and Wynne will not receive cash compensation for their service as directors of our general partner. The other directors of our general partner, including Messrs. Adams, Collins, Martin and Stone, will receive compensation as set by our general partner’s board of directors. Such individuals receive a compensation package that consists of an annual cash retainer of $60,000 plus an additional annual payment of $15,000 for the chairperson of each committee. In addition, our directors are reimbursed for out-of-pocket expenses in connection with attending meetings of the board of directors or its committees. Each director may receive grants of equity-based awards under the LTIP from time to time for so long as he serves as a director.

Each member of the board of directors of our general partner is indemnified for his actions associated with being a director to the fullest extent permitted under Delaware law.

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Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters

The following table presents information regarding the beneficial ownership of our common units immediately following our initial public offering and the other formation transactions by:

· our general partner;

· each of our general partner’s directors and executive officers;

· each unitholder known by us to beneficially hold 5% or more of our common units; and

· all of our general partner’s directors and executive officers as a group.

Beneficial ownership is determined under the rules of the SEC and generally includes voting or investment power with respect to securities. Unless otherwise noted, the address for each beneficial owner listed below is 777 Taylor Street, Suite 810, Fort Worth, Texas 76102.

Name of Beneficial Owner	Common Units Beneficially Owned	Percentage of Common Units Beneficially Owned
Kimbell Art Foundation (1)	2,710,690	16.6	%
Rivercrest Royalties Holdings, LLC (2)	1,191,974	7.3	%
Trunk Bay Royalty Partners, Ltd. (3)	1,050,889	6.4	%
BGT Royalty Partners, LP (4)	983,630	6.0	%
French Capital Partners, Ltd. (5)	830,475	5.1	%
Robert D. Ravnaas (6)	233,514	1.4	%
R. Davis Ravnaas (7)	21,757	*	%
Jeff McInnis	2,777	*	%
Matthew S. Daly	—	—	%
Brett G. Taylor (8)	108,402	*	%
Benny D. Duncan (9)	1,950,733	11.9	%
Ben J. Fortson (10)	2,787,095	17.1	%
T. Scott Martin (11)	9,041	*	%
Mitch S. Wynne (12)	291,635	1.8	%
William H. Adams III	1,500	*	%
C.O. Ted Collins, Jr.	16,666	*	%
Craig Stone	—	—	%
All directors, director nominees and executive officers as a group (12 persons)	5,423,120	33.2	%

* Less than 1%

(1) The address for this beneficial owner is 301 Commerce Street, Suite 2300, Fort Worth, Texas 76102. Ben J. Fortson is Vice President and Chief Investment Officer of the Kimbell Art Foundation, and he was delegated authority to manage the investment assets of the Kimbell Art Foundation and, therefore, may be deemed to have voting and investment power over the 2,710,690 common units owned by the Kimbell Art Foundation. Mr. Fortson disclaims beneficial ownership of such common units.

(2) The address for this beneficial owner is 777 Taylor Street, Suite 810, Fort Worth, Texas, 76102. Robert D. Ravnaas is a manager and President, R. Davis Ravnaas is Vice President and T. Scott Martin is a manager of Rivercrest Royalties Holdings, LLC; however, none of Messrs. R. Ravnaas, D. Ravnaas or Martin has voting or investment power with respect to such entity. Each of Messrs. R. Ravnaas, D. Ravnaas and Martin disclaims beneficial ownership of such common units except to the extent of his pecuniary interest therein.

(3) The address for this beneficial owner is P.O. Box 671099, Dallas, Texas 75367. Trunk Bay, LLC is the general partner of, and may be deemed to have voting and investment power over common units owned by, Trunk Bay Royalty Partners, Ltd. Benny D. Duncan is the Sole Manager of, and may be deemed to have voting and investment power over common units that may be deemed to be owned by, Trunk Bay, LLC. Each of Trunk Bay, LLC and Mr. Duncan disclaims beneficial ownership of such common units except to the extent of their pecuniary interest therein.

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(4) The address for this beneficial owner is 2777 N. Stemmons Fwy, Suite 1133, Dallas, Texas 75207. BGT Royalty Partners Genpar, LLC is the general partner of BGT Royalty Partners, LP and may be deemed to beneficially own the common units beneficially owned by BGT Royalty Partners, LP. Robert D. Ravnaas and Brett G. Taylor are Co-Presidents of BGT Royalty Partners Genpar, LLC; however, neither Mr. R. Ravnaas nor Mr. Taylor has voting or investment power with respect to such entity. Each of Messrs. R. Ravnaas and Taylor disclaims beneficial ownership of such common units except to the extent of his pecuniary interest therein.

(5) The address for this beneficial owner is P.O. Box 11327, Midland, Texas 79701. Marcia French is the managing member of, and may be deemed to have voting and investment power over the 830,475 common units that may be deemed to be owned by, French Capital Management, LLC. French Capital Management, LLC is the general partner of French Capital Partners, Ltd. and therefore may be deemed to beneficially own the 830,475 common units owned by French Capital Partners, Ltd.

(6) Robert D. Ravnaas is a partner or member in certain entities that hold, in the aggregate, approximately 2,970,981 common units, or 18.2%. Mr. R. Ravnaas does not have voting or investment power with respect to such entities. Mr. R. Ravnaas’ pecuniary interest in such entities is an aggregate of approximately 233,514 common units, or 1.4%, and Mr. R. Ravnaas disclaims beneficial ownership of the common units that may be deemed to be owned by such entities except to the extent of his pecuniary interest therein.

(7) R. Davis Ravnaas is a partner or member in certain entities that hold, in the aggregate, approximately 2,232,410 common units, or 13.7%. Mr. D. Ravnaas does not have voting or investment power with respect to such entities. Mr. D. Ravnaas’ pecuniary interest in such entities is an aggregate of approximately 21,757 common units, or 0.1%, and Mr. D. Ravnaas disclaims beneficial ownership of the common units that may be deemed to be owned by such entities except to the extent of his pecuniary interest therein.

(8) Brett G. Taylor is the Sole Member of, and may be deemed to have voting and investment power over the 2,172 common units owned by, BRD Royalty Holdings LLC. Brett G. Taylor is the sole trustee of, and may be deemed to have voting and investment power over the 68,021 common units owned by, Brett G. Taylor Royalty Trust. Brett G. Taylor Royalty Trust owns a 50% membership interest in, and may be deemed to have voting and investment power over the 1,441 common units owned by, FWA Partners, LLC, and Mr. Taylor, as the sole trustee of Brett G. Taylor Royalty Trust, may be deemed to have voting and investment power over such common units. Each of Mr. Taylor, with respect to the common units owned by BRD Royalty Holdings LLC, Brett G. Taylor Royalty Trust and FWA Partners, LLC, and Brett G. Taylor Royalty Trust, with respect to the common units owned by FWA Partners, LLC, disclaims beneficial ownership of such common units except to the extent of their pecuniary interest therein. In addition, Mr. Taylor is a partner or member in certain entities that hold, in the aggregate, approximately 1,314,933 additional common units, or 8.1%. Mr. Taylor does not have voting or investment power with respect to such entities. Mr. Taylor’s pecuniary interest in such entities is an aggregate of approximately 37,488 additional common units, or 0.2%, and Mr. Taylor disclaims beneficial ownership of the common units that may be deemed to be owned by such entities except to the extent of his pecuniary interest therein.

(9) The address for this beneficial owner is P.O. Box 671099, Dallas, Texas 75367. Benny D. Duncan is the Sole Member of, and may be deemed to have voting and investment power over the 20,053 common units that may be deemed to be owned by, Eagle Management, LLC. Eagle Management, LLC is the general partner of, and may be deemed to have voting and investment power over the 20,053 common units owned by, Eagle Minerals LP. Mr. Duncan is the Sole Manager of, and may be deemed to have voting and investment power over the 18,709 common units that may be deemed to be owned by, Bitter End, LLC. Bitter End, LLC is the general partner of, and may be deemed to have voting and investment power over the 18,709 common units owned by, Bitter End Royalties, LP. Mr. Duncan is the Sole Manager of, and may be deemed to have voting and investment power over the 122,472 common units that may be deemed to be owned by, Gorda Sound, LLC. Gorda Sound, LLC is the general partner of, and may be deemed to have voting and investment power over the 122,472 common units owned by, Gorda Sound Royalties, L.P. Mr. Duncan is the Sole Manager of, and may be deemed to have voting and investment power over the 738,610 common units that may be deemed to be owned by, Oil Nut Bay, LLC. Oil Nut Bay, LLC is the general partner of, and may be deemed to have voting and investment power over the 738,610 common units owned by, Oil Nut Bay Royalties, LP. Mr. Duncan is the Sole Manager of, and may be deemed to have voting and investment power over the 1,050,889 common units that may be deemed to be owned by, Trunk Bay, LLC. Trunk Bay, LLC is the general partner of, and may be deemed to have voting and investment power over the 1,050,889 common units owned by, Trunk Bay Royalty Partners, Ltd. Each of Eagle Management, LLC, Bitter End, LLC, Gorda Sound, LLC, Oil Nut Bay, LLC, Trunk Bay, LLC and Mr. Duncan disclaims beneficial ownership of the common units that may be deemed to be owned by such entities or individuals except to the extent of their pecuniary interest therein.

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(10) Ben J. Fortson is Vice President and Chief Investment Officer of the Kimbell Art Foundation, and he was delegated authority to manage the investment assets of the Kimbell Art Foundation and, therefore, may be deemed to have voting and investment power over the 2,710,690 common units owned by the Kimbell Art Foundation. Mr. Fortson and his wife are the sole directors and officers of, and may be deemed to have voting and investment power over the 1,301 common units owned by, BK GenPar, Inc. Mr. Fortson disclaims beneficial ownership of such common units except to the extent of his pecuniary interest therein. In addition, Mr. Fortson is a partner or member in certain entities that hold, in the aggregate, approximately 1,114,641 additional common units, or 6.8%. Mr. Fortson does not have voting or investment power with respect to such entities. Mr. Fortson’s pecuniary interest in such entities is an aggregate of approximately 75,104 additional common units, or 0.5%, and Mr. Fortson disclaims beneficial ownership of the common units that may be deemed to be owned by such entities except to the extent of his pecuniary interest therein.

(11) T. Scott Martin is a partner or member in certain entities that hold, in the aggregate, approximately 2,187,479 common units, or 13.4%. Mr. Martin does not have voting or investment power with respect to such entities. Mr. Martin’s pecuniary interest in such entities is an aggregate of approximately 5,708 common units, or 0.03%, and Mr. Martin disclaims beneficial ownership of the common units that may be deemed to be owned by such entities except to the extent of his pecuniary interest therein.

(12) Mitch S. Wynne is a partner or member in certain entities that hold, in the aggregate, approximately 1,400,489 common units, or 8.6%. Mr. Wynne does not have voting or investment power with respect to such entities. Mr. Wynne’s pecuniary interest in such entities is an aggregate of approximately 291,635 common units, or 1.8%, and Mr. Wynne disclaims beneficial ownership of the common units that may be deemed to be owned by such entities except to the extent of his pecuniary interest therein.

The following table sets forth the beneficial ownership of equity interests in our general partner:

Name of Beneficial Owner (1)	Membership Interest
Kimbell GP Holdings, LLC (2)	100	%
Robert D. Ravnaas (3)	33.33	%
Brett G. Taylor (3)	33.33	%
Mitch S. Wynne / Ben J. Fortson (3)	33.33	%

(1) The address for each beneficial owner in this table is 777 Taylor Street, Suite 810, Fort Worth, Texas 76102.

(2) Kimbell GP Holdings, LLC is controlled by entities affiliated with Robert D. Ravnaas, Brett G. Taylor, Mitch S. Wynne and Ben J. Fortson.

(3) Messrs. R. Ravnaas, Taylor, Wynne and Fortson, by virtue of their indirect ownership interest in Kimbell GP Holdings, LLC, which owns our general partner, may be deemed to beneficially own the non-economic general partner interest in us held by our general partner. Each of Messrs. R. Ravnaas, Taylor, Wynne and Fortson disclaims beneficial ownership of this interest.

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Equity Compensation Plan Information

In connection with the consummation of our initial public offering on February 3, 2017, the board of directors of our general partner adopted the Kimbell Royalty Partners, LP Long Term Incentive Plan. The following table provides certain information with respect to this plan as of March 29, 2017:

	Number of Securities to be Issued Upon Exercise of Outstanding Options, Warrants and Rights(1) (a)	Weighted -Average Exercise Price of Outstanding Options, Warrants and Rights (b)	Number of Securities Remaining Available for Future Issuance Under Equity Compensation Plans (Excluding Securities Reflected in Column(a)) (c)
Equity compensation plans approved by unitholders	—	n/a	2,041,600
Equity compensation plans not approved by unitholders	—	n/a	—

Total	—	n/a	2,041,600

(1)The long-term incentive plan currently permits the grant of awards covering an aggregate of 2,041,600 units

Item 13. Certain Relationships and Related Transactions, and Director Independence

Agreements and Transactions with Affiliates in Connection with Initial Public Offering

In connection with our initial public offering, we entered into certain agreements and transactions with our Sponsors, the Contributing Parties and their respective affiliates, as described in more detail below. These agreements and transactions were not the result of arm’s-length negotiations and they, or any of the transactions that they provide for, were not effected on terms at least as favorable to the parties to these agreements as could have been obtained from unaffiliated third parties. Because some of these agreements relate to formation transactions that, by their nature, would not occur in a third-party situation, it is not possible to determine what the differences would be in the terms of these transactions when compared to the terms of transactions with an unaffiliated third party. We believe the terms of these agreements to be comparable to the terms of agreements used in similarly structured transactions.

How We Pay Distributions

Our partnership agreement requires that, within 45 days after the end of each quarter, we distribute all of our available cash to unitholders of record on the applicable record date. We will adjust the amount of our distribution for the period from the closing of our initial public offering through March 31, 2017, based on the actual length of the period. Available cash generally means:

· the sum of:

· all of our and our subsidiaries’ cash and cash equivalents on hand at the end of that quarter; and

· as determined by our general partner, all of our and our subsidiaries’ cash or cash equivalents on hand on the date of determination of available cash for that quarter resulting from working capital borrowings (as described below) made after the end of that quarter;

· less the amount of cash reserves established by our general partner to:

· provide for the proper conduct of our business (including reserves for our future capital expenditures and for our future credit needs);

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· comply with applicable law or any debt instrument or other agreement or obligation to which we or our subsidiaries are a party or to which our or our subsidiaries’ assets are subject; or

· provide funds for distributions to our unitholders and to our general partner for any one or more of the next four quarters;

Working capital borrowings are generally borrowings incurred under a credit facility, commercial paper facility or similar financing arrangement that are used solely for working capital purposes or to pay distributions to unitholders, and with the intent of the borrower to repay such borrowings within 12 months with funds other than additional working capital borrowings.

In addition, 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, 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 or liquidation to our common units.

Method of Distributions

We intend to distribute available cash to our unitholders, pro rata. Our partnership agreement permits, but does not require, us to borrow to pay distributions. Accordingly, there is no guarantee that we will pay any distribution on the units in any quarter.

Common Units

Each common unit will be entitled to receive cash distributions to the extent we distribute available cash. Common units will not accrue arrearages. Our partnership agreement allows us to issue an unlimited number of additional equity interests of equal or senior rank.

General Partner Interest

Our general partner owns a non-economic general partner interest in us and therefore will not be entitled to receive cash distributions. However, it may acquire common units and other partnership interests in the future and will be entitled to receive pro rata distributions in respect of those partnership interests.

Contribution Agreement

In connection with our initial public offering, we entered into a contribution agreement with our Sponsors and the Contributing Parties that effected the transfer of the mineral and royalty interests owned by the Contributing Parties to us and the use of the net proceeds of our initial public offering, and also addressed the following matters:

· our right of first offer to acquire mineral and royalty interests owned by certain of the Contributing Parties for a period of three years after the closing of our initial public offering;

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· our option to participate in certain acquisitions by the Contributing Parties of mineral and royalty interests;

· our Sponsors’ and the Contributing Parties’ registration rights with respect to the registration and sale of common units held by them or their affiliates; and

· the Contributing Parties’ obligation to indemnify us for certain limited matters associated with the mineral and royalty interests and associated entities, and our obligation to indemnify the Contributing Parties for certain limited matters related to the mineral and royalty interests and associated entities to the extent they are not required to indemnify us.

Right of First Offer. Under the contribution agreement, if certain of the Contributing Parties decide to sell, transfer or otherwise dispose of certain mineral and royalty interests in the Permian Basin, the Bakken/Williston Basin and the Marcellus Shale, they will provide us with the opportunity to make the first offer on such assets. The right of first offer will have a three-year term from the closing of our initial public offering. The consummation and timing of any acquisition by us of the interests covered by our right of first offer will depend upon, among other things, the Contributing Parties’ decision to sell any of the assets covered by our right of first offer and our ability to reach an agreement with the Contributing Parties’ on price and other terms. Accordingly, we can provide no assurance whether, when or on what terms we will be able to successfully consummate any future acquisitions pursuant to our right of first offer, and the Contributing Parties are under no obligation to accept any offer that we may choose to make.

Participation Right. Pursuant to 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. Unless consented to in writing by our general partner on our behalf, the participation right shall be on terms and conditions substantially the same as or better than the acquisition by our Sponsors and the Contributing Parties. The participation right will last for so long as any of our Sponsors or their respective affiliates control our general partner.

Registration Rights. Pursuant to the contribution agreement, the Contributing Parties have specified demand and piggyback participation rights with respect to the registration and sale of common units held by them or their affiliates. At any time following the time when we are eligible to file a registration statement on Form S-3, each of our Sponsors has the right to cause us to prepare and file a registration statement on Form S-3 with the SEC covering the offering and sale of common units held by its affiliates. We are not obligated to effect more than one such demand registration in any 12-month period or two such demand registrations in the aggregate. If we propose to file a registration statement pursuant to a Sponsor’s demand registration discussed above, the Contributing Parties may request to “piggyback” onto such registration statement in order to offer and sell common units held by them or their affiliates. We have agreed to pay all registration expenses in connection with such demand and piggyback registrations. Registration expenses do not include underwriters’ compensation, stock transfer taxes or counsel fees.

Indemnification. The Contributing Parties made representations and warranties to us regarding their respective mineral and royalty interests and the associated entities. In addition, the Contributing Parties are, severally but not jointly, obligated to indemnify us for certain limited matters, including as follows:

· (i) For a period of one year following the closing of our initial public offering, the Contributing Parties will indemnify us 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 our initial public offering until 30 days after the applicable statute of limitations. This indemnification obligation is capped at ten percent of the net proceeds received by any such Contributing Party with respect to the entity or asset that is subject to such claim for indemnification. 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 did not survive the closing of our initial public offering.

· In addition, the Contributing Parties will 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 our initial

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public offering. This indemnification obligation is capped at the net proceeds received by any such Contributing Party with respect to the entity or asset that is subject to such claim for indemnification.

We have agreed to indemnify the Contributing Parties for breaches of specified representation and warranties and for events and conditions associated with the ownership or operation of the mineral and royalty interests and the associated entities (other than any liabilities for which the Contributing Parties are specifically required to indemnify us as described above). Our indemnification obligation for breaches of specified representations and warranties is capped at ten percent of the aggregate net proceeds received by all of the Contributing Parties. Our indemnification obligation for all other liabilities is capped at the aggregate net proceeds received by all of the Contributing Parties.

Management Services Agreements

Management Services Agreement with Kimbell Operating

In connection with the closing of our initial public offering, we entered into a management services agreement with Kimbell Operating, pursuant to which Kimbell Operating provides management, administrative, operational and acquisition services to us, including via the service agreements with the Sponsor Managers and the Non-Sponsor Managers (each as defined below). The management services agreement with Kimbell Operating is under terms and conditions similar to those described below in “—Service Agreements with Our Sponsors” and “—Other Service Agreements,” except that neither party to the agreement may terminate unless all of the service agreements with the Sponsor Managers and the Non-Sponsor Managers have terminated. We will initially pay to Kimbell Operating a monthly services fee equal to $327,667, which amount represents an estimated allocation of all projected costs to be incurred by Kimbell Operating in providing such services to us, including pursuant to the service agreements with the Sponsor Managers and the Non-Sponsor Managers.

Service Agreements with Our Sponsors

Services. In connection with the closing of our initial public offering, Kimbell Operating entered into service agreements with BJF Royalties, LLC (“BJF Royalties”), Steward Royalties, LLC (“Steward Royalties”), Taylor Companies Mineral Management, LLC (“Taylor Companies”) and K3 Royalties, LLC (“K3 Royalties” and together with BJF Royalties, Steward Royalties and Taylor Companies, the “Sponsor Managers”), which are entities controlled by Messrs. Fortson, R. Ravnaas, Taylor and Wynne, respectively. Pursuant to these agreements, the Sponsor Managers provide management, administrative and operational services to Kimbell Operating. In addition, the Sponsor Managers or their affiliates provide acquisition services to us, including identifying, evaluating and recommending to us acquisition opportunities and any related negotiating of such opportunities. The services to be provided by each Sponsor Manager are as set forth below:

· BJF Royalties: For all of our assets and the assets of our affiliates, BJF Royalties assists in sourcing, evaluating and recommending acquisitions, and assisting with business development opportunities related to potential acquisitions and other strategic transactions.

· Steward Royalties: For all of our assets and the assets of our affiliates, Steward Royalties assists in sourcing, evaluating (including providing pricing guidance, reservoir engineering analysis, and geological work), and negotiating acquisition opportunities for us; and provides ongoing petroleum engineering services.

· Taylor Companies:

· Taylor Companies assists in sourcing, evaluating (including directing all land and legal due diligence) and negotiating acquisition opportunities for us; assists in notifying and providing recorded transfer documents for newly acquired properties; assists in retaining outside legal counsel and landmen in connection with acquisition opportunities; maintains land and legal records with respect to newly acquired properties; and performs certain additional services with respect to newly acquired properties.

· In addition, with respect to certain of our subsidiaries and assets, Taylor Companies provides management services including: negotiating and executing leases, right of way agreements,

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pooling orders and similar agreements and orders; providing certain recordkeeping services; resolving title issues; receiving and disbursing royalty and other payments; and providing certain additional accounting, title, human resources, regulatory compliance and other services.

· K3 Royalties: For all of our assets and the assets of our affiliates, K3 Royalties assists in sourcing, evaluating and recommending acquisitions, and assists with business development, investor and public relations and relationship management between private side royalty investors and us.

The Sponsor Managers have the exclusive right to provide the acquisition services listed above in connection with acquisitions by us, as well as the exclusive right to provide any additional management services reasonably required with respect to properties newly acquired by us.

Service Fees and Reimbursement. Under the service agreements with the Sponsor Managers, Kimbell Operating initially pays to Steward Royalties, Taylor Companies and K3 Royalties a monthly services fee equal to $33,000, $33,000 and $10,000, respectively, which amounts represent an estimated allocation of all projected costs to be incurred by such Sponsor Manager in providing services to Kimbell Operating. BJF Royalties will not receive a monthly services fee in connection with providing its services. Subject to the approval of the board of directors of our general partner, the monthly services fee will be adjusted (i) annually, (ii) in the event of any sale of serviced properties or (iii) in the event of the provision of any additional management services (including with respect to acquisitions of new properties). In addition, Kimbell Operating is required to reimburse each Sponsor Manager for all other reasonable costs and expenses (including, but not limited to, third-party expenses and expenditures) that such Sponsor Manager incurs on behalf of Kimbell Operating in providing services. If Kimbell Operating terminates a service agreement for any reason other than the Sponsor Manager’s default (as described below), then Kimbell Operating will also reimburse the applicable Sponsor Manager for its reasonable costs and expenses incurred in connection with such termination.

Term and Termination. The initial term of the service agreement with the Sponsor Managers is five years, after which date they will continue on a year-to-year basis unless terminated by Kimbell Operating or by the applicable Sponsor Manager upon 90 days’ notice, except as otherwise stated below:

· After the second anniversary of our initial public offering, the applicable Sponsor Manager may terminate its service agreement, or the provision of any service thereunder, upon at least 180 days’ notice to Kimbell Operating.

· The applicable Sponsor Manager may terminate its service agreement upon a default by Kimbell Operating, which includes (i) Kimbell Operating’s failure to perform any of its material obligations under the agreement, where such default continues unremedied for a period of 15 days after notice thereof, and (ii) the occurrence of certain events relating to the bankruptcy or insolvency of Kimbell Operating.

· Kimbell Operating may terminate a service agreement upon a default by the applicable Sponsor Manager, upon 15 days’ notice to such Sponsor Manager. A Sponsor Manager is in default upon the occurrence of any gross negligence or willful misconduct of such Sponsor Manager in performing services under its service agreement, which results in material harm to us and our affiliates, including Kimbell Operating (the “Partnership Service Group”).

· Kimbell Operating or the Sponsor Manager may terminate the applicable service agreement if, at any time, the Sponsors or their affiliates no longer control our general partner, upon at least 90 days’ notice to the other party.

Kimbell Operating’s only remedy for a Sponsor Manager’s default under its service agreement is the termination of the applicable agreement as described in the third bullet point above.

Indemnification. Under the service agreements with the Sponsor Managers, Kimbell Operating agreed to indemnify each Sponsor Manager, its affiliates and any of their respective employees, officers, directors and agents from and against all liability, demands, claims, actions or causes of action, assessments, losses, damages, costs and expenses (including legal fees) resulting from or arising out of (i) any material breach by Kimbell Operating of the applicable service agreement or (ii) the personal injury, death, property damage or liability of any member of the Partnership Service Group, any third party or any of their respective employees, officers, directors and agents arising from,

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connected with or under the applicable service agreement. The Sponsor Managers do not have corresponding indemnification obligations with respect to Kimbell Operating.

Other Service Agreements

Management Services. In connection with the closing of our initial public offering, Kimbell Operating entered into service agreements with Nail Bay Royalties, LLC (“Nail Bay Royalties”) and Duncan Management, LLC (“Duncan Management” and together with Nail Bay Royalties, the “Non-Sponsor Managers”), which are entities controlled by Mr. Duncan. Pursuant to these agreements, the Non-Sponsor Managers provide management, administrative and operational services to Kimbell Operating. These services include, with respect to the serviced properties: negotiating and executing leases, right of way agreements, pooling orders and similar agreements and orders; providing certain recordkeeping services; resolving title issues; collecting and disbursing payments and rendering related audit, accounting and bookkeeping services; monitoring drilling and production activities; assisting in preparing certain federal and state tax forms; and providing certain additional accounting, title, human resources, regulatory compliance and other services.

Service Fees and Reimbursement. Under the service agreements with the Non-Sponsor Managers, Kimbell Operating will initially pay to Nail Bay Royalties and Duncan Management a monthly services fee of approximately $41,960 and $54,870, respectively, which amounts represent an estimated allocation of all projected costs to be incurred by such Non-Sponsor Manager in providing services to Kimbell Operating. Subject to the approval of the board of directors of our general partner, the monthly services fee will be adjusted (i) annually, (ii) in the event of any sale of serviced properties or (iii) in the event of the provision of any additional services by the Non-Sponsor Manager. In addition, Kimbell Operating is required to reimburse each Non-Sponsor Manager for all other reasonable costs and expenses (including, but not limited to, third-party expenses and expenditures) that such Non-Sponsor Manager incurs on behalf of Kimbell Operating in providing services. If Kimbell Operating terminates a service agreement for any reason other than the Non-Sponsor Manager’s default (as described below), then Kimbell Operating will also reimburse the applicable Non-Sponsor Manager for its reasonable costs and expenses incurred in connection with such termination.

Term and Termination. The initial term of the service agreements with the Non-Sponsor Managers is be five years, after which date they will continue on a year-to-year basis unless terminated by us or by the applicable Non-Sponsor Manager upon 90 days’ notice, except as otherwise stated below:

· After the second anniversary of our initial public offering, the applicable Non-Sponsor Manager may terminate its service agreement, or the provision of any service thereunder, upon at least 180 days’ notice to Kimbell Operating.

· The applicable Non-Sponsor Manager may terminate its service agreement upon a default by Kimbell Operating, which includes (i) Kimbell Operating’s failure to perform any of its material obligations under the agreement, where such default continues unremedied for a period of 15 days after notice thereof, and (ii) the occurrence of certain events relating to the bankruptcy or insolvency of Kimbell Operating.

· Kimbell Operating may terminate a service agreement upon a default by the applicable Non-Sponsor Manager, upon 15 days’ notice to such Non-Sponsor Manager. A Non-Sponsor Manager is in default upon the occurrence of any gross negligence or willful misconduct of such Sponsor Manager in performing services under its service agreement, which results in material harm to any member of the Partnership Service Group.

· Kimbell Operating or the Non-Sponsor Manager may terminate the applicable service agreement upon the sale of all or substantially all of the properties serviced thereunder, upon at least 90 days’ notice to the other party.

Kimbell Operating’s only remedy for a Non-Sponsor Manager’s default under its service agreement is the termination of the applicable agreement as described in the third bullet point above.

Indemnification. Under the service agreements with the Non-Sponsor Managers, Kimbell Operating agreed to indemnify each Non-Sponsor Manager, its affiliates and any of their respective employees, officers, directors and agents from and against all liability, demands, claims, actions or causes of action, assessments, losses, damages, costs and expenses (including legal fees) resulting from or arising out of (i) any material breach by Kimbell Operating of the

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applicable service agreement or (ii) the personal injury, death, property damage or liability of any member of the Partnership Service Group, any third party or any of their respective employees, officers, directors and agents arising from, connected with or under the applicable service agreement. The Non-Sponsor Managers do not have corresponding indemnification obligations with respect to Kimbell Operating.

Limited Liability Company Agreement of Kimbell Holdings

In connection with the closing of our initial public offering, our Sponsors entered into the limited liability company agreement of Kimbell Holdings. Kimbell Holdings is the sole member of our general partner. Pursuant to Kimbell Holdings’ limited liability company agreement, for so long as Messrs. Fortson, R. Ravnaas, Taylor and Wynne (or their designated successors) serve as directors of Kimbell Holdings, such persons will also serve as directors of our general partner.

Other Transactions and Relationships with Related Persons

Family members of certain of our general partner’s executive officers and directors serve as officers or employees of our general partner and Kimbell Operating. Rand P. Ravnaas, the son of Robert D. Ravnaas and the brother of R. Davis Ravnaas, serves as Vice President—Business Development of our general partner and Kimbell Operating, and he is a partial owner of certain of the Contributing Parties. In addition, Peter Alcorn, the son-in-law of Mitch Wynne, serves as Vice President—Land of our general partner and Kimbell Operating, and he is a partial owner of certain of the Contributing Parties. Each of these family members will participate in the LTIP and receive compensation comprising a base salary and bonuses commensurate with other similarly-situated employees.

Robert D. Ravnaas has served as President of Cawley, Gillespie & Associates, Inc. from 2011 until February 2016. Cawley, Gillespie & Associates, Inc. performs certain petroleum engineering services for the benefit of the Partnership. Compensation for such services totaled $618,989, $785,594 and $0 in fiscal years 2016, 2015 and 2014, respectively. Mr. R. Ravnaas indirectly receives a percentage of Cawley, Gillespie & Associates, Inc.’s revenues through his participation in the company’s employee bonus pool. In the aggregate, he has received approximately $246,000 attributable to fees paid by the Partnership in fiscal years 2016, 2015 and 2014.

John Wynne, the son of Mitch S. Wynne, acts as the Partnership’s agent at Higginbotham Insurance & Financial Services, which provides director and officer insurance to the Partnership. John Wynne will derive a commission of approximately $18,900 on the placement of the Partnership’s insurance coverage. The Partnership’s annual premium expense is estimated to be approximately $450,000.

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

The board of directors of our general partner has adopted policies for the review, approval and ratification of transactions with related persons. The board has adopted a written code of business conduct and ethics, under which a director is expected to bring to the attention of our chief executive officer or the board any conflict or potential conflict of interest that may arise between the director or any affiliate of the director, on the one hand, and us or our general partner on the other. The resolution of any conflict or potential conflict should, at the discretion of the board in light of the circumstances, be determined by a majority of the disinterested directors.

If a conflict or potential conflict of interest arises between our general partner or its affiliates, including our Sponsors or their respective affiliates, on the one hand, and us or our unitholders, on the other hand, the resolution of any such conflict or potential conflict should be addressed by the board of directors of our general partner in accordance with the provisions of our partnership agreement. At the discretion of the board in light of the circumstances, the resolution may be determined by the board in its entirety or by the conflicts committee.

Under our code of business conduct and ethics, executive officers are required to avoid conflicts of interest unless approved by the board of directors of our general partner.

The code of business conduct and ethics described above was adopted in connection with the closing of our initial public offering, and as a result, the transactions described above were not reviewed according to such procedures.

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Director Independence

Our board of directors has determined that William H. Adams III, C.O. Ted Collins, Jr. and Craig Stone are independent under the independence standards of the NYSE.

Item 14. Principal Accounting Fees and Services

We have engaged Grant Thornton LLP as our independent registered public accounting firm. The following table sets forth fees we have paid to Grant Thornton LLP for the year ended December 31, 2016.

Audit and Non-Audit Fees

	2016
	(in thousands)
Audit Fees(1)	$	738
Audit-Related Fees(2)	—
Tax Fees(3)	—
All Other Fees(4)	—

Total	$	738

(1)	Audit fees relate to professional services rendered in connection with the audit of our 2016 annual financial statements on our Form 10-K as well as the audit of our annual financial statements and quarterly review of financial statements included in our Registration Statement on Form S-1 filed with the SEC.

(2)	Audit-related fees relate to assurance and related services that are reasonably related to the performance of the audit or review of our financial statements or that are traditionally performed by the independent auditor, such as employee benefit plan audits, agreed upon procedures required to comply with financial, accounting or regulatory reporting and assistance with internal control documentation requirements.

(3)	Tax fees relate to professional services rendered in connection with tax audits and tax consulting and planning services.

(4)	All other fees represent fees for services not classifiable under the other categories listed in the table above.

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PART IV

Item 15. Exhibits, Financial Statement Schedules

(a)(1) Financial Statements

Our Consolidated Financial Statements are included under Part II, Item 8 of this Annual Report. For a listing of these statements and accompanying notes, please read “Index to Financial Statements” on page F-1 of this Annual Report.

(a)(2) Financial Statement Schedules

All schedules have been omitted because they are either not applicable, not required or the information called for therein appears in the consolidated financial statements or notes thereto.

EXHIBIT INDEX

Exhibit Number		Description
2.1	—	Contribution, Conveyance, Assignment and Assumption Agreement, dated as of December 20, 2016, by and among Kimbell Royalty Partners, LP, Kimbell Royalty GP, LLC, Kimbell Intermediate GP, LLC, Kimbell Intermediate Holdings, LLC, Kimbell Royalty Holdings, LLC, and the other parties named therein (incorporated by reference to Exhibit 2.1 to Kimbell Royalty Partners, LP’s Registration Statement on Form S-1 (File No. 333-215458) filed on January 6, 2017)
3.1	—	Certificate of Limited Partnership of Kimbell Royalty Partners, LP (incorporated by reference to Exhibit 3.1 to Kimbell Royalty Partners, LP’s Registration Statement on Form S-1 (File No. 333-215458) filed on January 6, 2017)
3.2	—	First Amended and Restated Agreement of Limited Partnership of Kimbell Royalty Partners LP, dated as of February 8, 2017 (incorporated by reference to Exhibit 3.1 to Kimbell Royalty Partners, LP’s Form 8-K filed on February 14, 2017)
3.3	—	Certificate of Formation of Kimbell Royalty GP, LLC (incorporated by reference to Exhibit 3.2 to Kimbell Royalty Partners, LP’s Registration Statement on Form S-1 (File No. 333-215458) filed on January 6, 2017)
3.4	—	First Amended and Restated Limited Liability Company Agreement of Kimbell Royalty GP, LLC, dated as of February 8, 2017 (incorporated by reference to Exhibit 3.2 to Kimbell Royalty Partners, LP’s Form 8-K filed on February 14, 2017)
10.1	—	Kimbell Royalty GP, LLC 2017 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.1 to Kimbell Royalty Partners, LP’s Form 8-K filed on February 7, 2017)
10.2	—	Credit Agreement, dated as of January 11, 2017, among Kimbell Royalty Partners, LP, the several lenders from time to time parties thereto and Frost Bank, as administrative agent and sole arranger (incorporated by reference to Exhibit 10.1 to Kimbell Royalty Partners, LP’s Amendment No. 1 to Registration Statement on Form S-1 (File No. 333-215458) filed on January 17, 2017)
10.3†	—	Management Services Agreement, dated February 8, 2017, by and among Kimbell Royalty Partners, LP, Kimbell Royalty GP, LLC, Kimbell Royalty Holdings, LLC and Kimbell Operating Company, LLC (incorporated by reference to Exhibit 10.1 to Kimbell Royalty Partners, LP’s Form 8-K filed on February 14, 2017)
10.4†	—	Management Services Agreement , dated February 8, 2017, by and between BJF Royalties, LLC and Kimbell Operating Company, LLC (incorporated by reference to Exhibit 10.2 to Kimbell Royalty Partners, LP’s Form 8-K filed on February 14, 2017)
10.5†	—	Management Services Agreement, dated February 8, 2017, by and between Duncan Management, LLC and Kimbell Operating Company, LLC (incorporated by reference to Exhibit 10.3 to Kimbell Royalty Partners, LP’s Form 8-K filed on February 14, 2017)
10.6†	—	Management Services Agreement, dated February 8, 2017, by and between K3 Royalties, LLC and Kimbell Operating Company, LLC (incorporated by reference to Exhibit 10. 4 to Kimbell Royalty Partners, LP’s Form 8-K filed on February 14, 2017)
10.7†	—	Management Services Agreement, dated February 8, 2017, by and between Nail Bay Royalties, LLC and Kimbell Operating Company, LLC (incorporated by reference to Exhibit 10.5 to Kimbell Royalty Partners, LP’s Form 8-K filed on February 14, 2017)

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10.8†	—	Management Services Agreement, dated February 8, 2017, by and between Steward Royalties, LLC and Kimbell Operating Company, LLC (incorporated by reference to Exhibit 10.6 to Kimbell Royalty Partners, LP’s Form 8-K filed on February 14, 2017)
10.9†	—	Management Services Agreement, dated February 8, 2017, by and between Taylor Companies Mineral Management, LLC and Kimbell Operating Company, LLC (incorporated by reference to Exhibit 10.7 to Kimbell Royalty Partners, LP’s Form 8-K filed on February 14, 2017)
21.1*	—	List of subsidiaries of Kimbell Royalty Partners, LP
23.7*	—	Consent of Ryder Scott Company, L.P.
23.8*	—	Consent of Ryder Scott Company, L.P.
31.1*	—	Certification of Chief Executive Officer pursuant to Rule 13a-14(a)/15d-14(a) under the Securities Exchange Act of 1934
31.2*	—	Certification of Chief Financial Officer pursuant to Rule 13a-14(a)/15d-14(a) under the Securities Exchange Act of 1934
32.1**	—	Certification of Chief Executive Officer pursuant to 18. U.S.C. Section 1350
32.2**	—	Certification of Chief Financial Officer pursuant to 18. U.S.C. Section 1350
99.1*	—	Report of Ryder Scott Company, L.P. as of December 31, 2016
99.2*	—	Report of Ryder Scott Company, L.P. as of December 31, 2016

* —filed herewith

** —furnished herewith

†—Management contract or compensatory plan or arrangement required to be filed as an exhibit to this 10-K pursuant to Item 15(b).

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SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

	Kimbell Royalty Partners, LP

	By:	Kimbell Royalty GP, LLC
		its general partner
Date: March 30, 2017
	By:	/s/ Robert D. Ravnaas
		Name:	Robert D. Ravnaas
		Title:	Chief Executive Officer and Chairman

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

Name	Title	Date

/s/ Robert D. Ravnaas	Chairman of the Board of Directors and Chief
Robert D. Ravnaas	Executive Officer (Principal Executive Officer)	March 30, 2017

/s/ R. Davis Ravnaas
R. Davis Ravnaas	President and Chief Financial Officer (Principal
	Financial Officer)	March 30, 2017

/s/ Jeff McInnis	Chief Accounting Officer
Jeff McInnis	(Principal Accounting Officer)	March 30, 2017

/s/ William H. Adams III
William H. Adams III	Director	March 30, 2017

/s/ C.O. Ted Collins, Jr.
C.O. Ted Collins, Jr.	Director	March 30, 2017

/s/ Benny D. Duncan
Benny D. Duncan	Director	March 30, 2017

/s/ Ben J. Fortson
Ben J. Fortson	Director	March 30, 2017

/s/ T. Scott Martin
T. Scott Martin	Director	March 30, 2017

/s/ Craig Stone
Craig Stone	Director	March 30, 2017

/s/ Brett G. Taylor
Brett G. Taylor	Director	March 30, 2017

/s/ Mitch S. Wynne
Mitch S. Wynne	Director	March 30, 2017

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INDEX TO FINANCIAL STATEMENTS

Kimbell Royalty Partners, LP

Report of Independent Registered Public Accounting Firm	F-2

Balance Sheets as of December 31, 2016 and 2015	F-3

Statement of Operations for the Year Ended December 31, 2016 and for the Period from Inception (October 30, 2015) to December 31, 2015	F-4

Statement of Changes in Partners’ Capital for the Year Ended December 31, 2016 and for the Period from Inception (October 30, 2015) to December 31, 2015	F-5

Statement of Cash Flows for the Year Ended December 31, 2016 and for the Period from Inception (October 30, 2015) to December 31, 2015	F-6

Notes to Financial Statements	F-7

Rivercrest Royalties, LLC

Report of Independent Registered Public Accounting Firm	F-8

Balance Sheets as of December 31, 2016 and 2015	F-9

Statements of Operations for the Years Ended December 31, 2016 and 2015	F-10

Statements of Changes in Members’ Equity for the Years Ended December 31, 2016 and 2015	F-11

Statements of Cash Flows for the Years Ended December 31, 2016 and 2015	F-12

Notes to Financial Statements	F-13

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Board of Directors and Unitholders

Kimbell Royalty Partners, LP

We have audited the accompanying balance sheets of Kimbell Royalty Partners, LP (the “Partnership”) as of December 31, 2016 and 2015, and the related statements of operations, changes in partners’ capital, and cash flows for the year ended December 31, 2016 and for the period from inception (October 30, 2015) to December 31, 2015. These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. We were not engaged to perform an audit of the Partnership’s internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Partnership’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Kimbell Royalty Partners, LP as of December 31, 2016 and 2015, and the results of its operations and its cash flows for the year ended December 31, 2016 and for the period from inception (October 30, 2015) to December 31, 2015 in conformity with accounting principles generally accepted in the United States of America.

/s/ GRANT THORNTON LLP

Dallas, Texas

March 30, 2017

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KIMBELL ROYALTY PARTNERS, LP

BALANCE SHEETS

	As of December 31,
	2016		2015
Assets
Current assets
Cash and cash equivalents	$	234	$	318
Total assets	$	234	$	318
Partners’ capital
General partners’ capital	$	—	$	—
Common units	234		318
Total partners’ capital	$	234	$	318

The accompanying notes are an integral part of these financial statements.

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KIMBELL ROYALTY PARTNERS, LP

STATEMENTS OF OPERATIONS

	For the Year Ended December 31,			For the Period from Inception (October 30, 2015) to December 31,
	2016			2015
Oil, natural gas and NGL revenues	$	—		$	—

General and administrative expenses	84			682

Net loss	$	(84	)	$	(682	)

The accompanying notes are an integral part of these financial statements.

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KIMBELL ROYALTY PARTNERS, LP

STATEMENT OF CHANGES IN PARTNERS’ CAPITAL

	Total
Partners’ capital - October 30, 2015	$	—
Contributions from members	1,000
Net loss	(682		)
Partners’ capital - December 31, 2015	$	318
Net loss	(84		)
Partners’ capital - December 31, 2016	$	234

The accompanying notes are an integral part of these financial statements.

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KIMBELL ROYALTY PARTNERS, LP

STATEMENT OF CASH FLOWS

	For the Year Ended December 31, 2016			For the Period from Inception (October 30, 2015) to December 31, 2015
Cash flows from operating activities
Net loss	$	(84	)	$	(682	)
Net cash used in operating activities	(84		)	(682		)
Cash flow from financing activities	—			1,000
Contributions from members
Net cash provided by financing activities	—			1,000
Increase (decrease) in cash and cash equivalents	(84		)	318
Cash and cash equivalents, beginning of period	318			—
Cash and cash equivalents, end of period	$	234		$	318

The accompanying notes are an integral part of these financial statements.

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KIMBELL ROYALTY PARTNERS, LP

NOTES TO FINANCIAL STATEMENTS

For the Year Ended December 31, 2016 and the Period

from Inception (October 30, 2015) to December 31, 2015

NOTE 1—ORGANIZATION

Kimbell Royalty Partners, LP (the ‘‘Partnership’’) was formed on October 30, 2015. The Partnership has adopted a fiscal year-end of December 31. In connection with its formation, the Partnership issued a non-economic general partner interest in the Partnership to Kimbell Royalty GP, LLC.

NOTE 2—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Use of Estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, as well as certain financial statement disclosures. The Partnership evaluates estimates and assumptions on an ongoing basis using historical experience and other factors, including the current economic and commodity price environment. While management believes that the estimates and assumptions used in the preparation of the financial statements are appropriate, actual results could differ from these estimates.

Subsequent Events

The Partnership has evaluated events that occured subsequent to December 31, 2016 in preparing its financial statements. See Note 4—Subsequent Events.

NOTE 3—COMMITMENTS AND CONTINGENCIES

Legal Contingencies

As of the date of these financial statements, the Partnership had no outstanding commitments and contingencies.

NOTE 4—SUBSEQUENT EVENTS

On February 8, 2017, Kimbell Royalty Partners, LP completed our initial public offering of common units pursuant to our registration statement on Form S-1 declared effective by the SEC on February 2, 2017. The net proceeds of our initial public offering, based on the public offering price of $18.00 per unit, were approximately $96.3 million. As described in the Prospectus, the Partnership used the proceeds to make a cash distribution to the entities and individuals that contributed, directly or indirectly, certain mineral and royalty interests to the Partnership in connection with the prospectus for our initial public offering.

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Board of Directors and Unitholders

Kimbell Royalty Partners, LP

We have audited the accompanying balance sheets of Rivercrest Royalties, LLC (a Delaware limited liability company) (the “Company”) as of December 31, 2016 and 2015, and the related statements of operations, changes in members’ equity, and cash flows for each of the two years in the period ended December 31, 2016. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. We were not engaged to perform an audit of the Company’s internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Rivercrest Royalties, LLC as of December 31, 2016 and 2015, and the results of its operations and its cash flows for each of the two years in the period ended December 31, 2016 in conformity with accounting principles generally accepted in the United States of America.

/s/ GRANT THORNTON LLP

Dallas, Texas

March 30, 2017

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RIVERCREST ROYALTIES, LLC

BALANCE SHEETS

	As of December 31,
	2016			2015
ASSETS

Current assets
Cash and cash equivalents	$	505,880		$	379,741
Oil, natural gas and NGL receivables	474,103			407,648
Other receivables	344,368			1,371,540

Total current assets	1,324,351			2,158,929

Property and equipment, net	261,568			347,815

Oil and natural gas properties
Oil and natural gas properties (full cost method)	70,888,121			70,809,962
Less: accumulated depreciation, depletion, accretion and impairment	(51,948,355		)	(45,457,931		)
Total oil and natural gas properties	18,939,766			25,352,031

Loan origination costs, net	13,046			47,015

TOTAL ASSETS	$	20,538,731		$	27,905,790

LIABILITIES AND MEMBERS’ EQUITY

Current liabilities
Accounts payable	$	1,030,862		$	1,983,662
Other current liabilities	112,508			35,967
Asset retirement obligation, current portion	27,013			1,223

Total current liabilities	1,170,383			2,020,852

Asset retirement obligation, net of current portion	14,468			39,129

Other liabilities	123,158			157,527

Long-term debt	10,598,860			11,448,860

TOTAL LIABILITIES	11,906,869			13,666,368

Commitments and contingencies

Members’ equity	8,631,862			14,239,422

TOTAL LIABILITIES AND MEMBERS’ EQUITY	$	20,538,731		$	27,905,790

The accompanying notes are an integral part of these financial statements.

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RIVERCREST ROYALTIES, LLC

STATEMENTS OF OPERATIONS

	For the Years Ended December 31,
	2016			2015

Oil, natural gas and NGL revenues	$	3,606,659		$	4,684,923

Costs and expenses
Production and ad valorem taxes	280,474			426,885
Depreciation, depletion and accretion expenses	1,604,208			4,008,730
Impairment of oil and natural gas properties	4,992,897			28,673,166
Operating expenses	750,792			747,264
General and administrative expenses	1,746,218			1,789,884

Total costs and expenses	9,374,589			35,645,929

Operating loss	(5,767,930		)	(30,961,006		)

Interest expense	424,841			385,119

Loss before income taxes	(6,192,771		)	(31,346,125		)

State income taxes	19,848			(32,199		)

Net loss	$	(6,212,619	)	$	(31,313,926	)

Net loss attributable to common unit:
Basic and diluted	$	(10.28	)	$	(51.83	)
Weighted average number of member units outstanding
Basic and diluted	604,137			604,137

The accompanying notes are an integral part of these financial statements.

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RIVERCREST ROYALTIES, LLC

STATEMENTS OF CHANGES IN MEMBERS’ EQUITY

	Units	Total
Members’ equity - January 1, 2015	604,137	$	48,197,616

Distributions to members	—	(3,249,327		)

Unit-based compensation	—	605,059

Net loss	—	(31,313,926		)

Members’ equity - December 31, 2015	604,137	$	14,239,422

Unit-based compensation	—	605,059

Net loss	—	(6,212,619		)

Members’ equity - December 31, 2016	604,137	$	8,631,862

The accompanying notes are an integral part of these financial statements.

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RIVERCREST ROYALTIES, LLC

STATEMENTS OF CASH FLOWS

	For the Year Ended December 31,
	2016			2015
Cash flows from operating activities
Net loss	$	(6,212,619	)	$	(31,313,926	)
Adjustments to reconcile net loss to net cash from operating activities:
Depreciation, depletion and accretion expenses	1,604,208			4,008,730
Impairment of oil and natural gas properties	4,992,897			28,673,166
Amortization of loan origination costs	46,969			40,965
Amortization of tenant improvement allowance	(34,369		)	(14,321		)
Unit-based compensation	605,059			605,059
Changes in operating assets and liabilities:
Oil, natural gas and NGL receivables	(66,455		)	464,877
Other receivables	1,027,172			(1,365,099		)
Accounts payable	(952,800		)	1,604,999
Other current liabilities	76,541			8,683
Net cash provided by operating activities	1,086,603			2,713,133

Cash flows from investing activities
Purchases of property and equipment	(19,305		)	(31,960		)
Purchase of oil and natural gas properties	(78,159		)	(506,680		)
Net cash used in investing activities	(97,464		)	(538,640		)

Cash flow from financing activities
Distributions to members	—			(4,507,818		)
Borrowings on long-term debt	—			3,050,000
Repayments on long-term debt	(850,000		)	(605,000		)
Payment of loan origination costs	(13,000		)	—
Net cash used in financing activities	(863,000		)	(2,062,818		)

Increase in cash and cash equivalents	126,139			111,675

Cash and cash equivalents, beginning of period	379,741			268,066

Cash and cash equivalents, end of period	$	505,880		$	379,741

Supplemental cash flow information:
Cash paid for interest	$	373,513		$	333,289
Cash paid for taxes	$	25,892		$	7,358

Noncash investing and financing activities:
Capital expenditures and consideration payable included in accounts payable and other liabilities	$	(37	)	$	151,558
Capital expenditures through tenant improvement allowance	$	—		$	171,848

The accompanying notes are an integral part of these financial statements.

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RIVERCREST ROYALTIES, LLC

NOTES TO FINANCIAL STATEMENTS

For the Years Ended December 31, 2016 and 2015

NOTE 1—ORGANIZATION

Rivercrest Royalties, LLC (the ‘‘Company’’) is a Delaware limited liability company formed on October 25, 2013. The Company is a Fort Worth, Texas based owner of oil, natural gas and natural gas liquids mineral and royalty interests in the United States of America (‘‘United States’’). In addition to mineral and royalty interests, the Company’s assets include overriding royalty interests. These non-cost-bearing interests are collectively referred to as ‘‘mineral and royalty interests.’’ The Company also has non-operated working interests in certain oil and natural gas properties, which together with the mineral and royalty interests, we refer to as the ‘‘Interests.’’ The Company has Interests in nearly every major onshore basin across the continental United States.

NOTE 2—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation

The Company’s year-end is December 31. The accompanying financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (‘‘U.S. GAAP’’). A summary of the significant accounting policies applied in the preparation of the accompanying financial statements follows.

Segment Reporting

The Company operates in a single operating and reportable segment. Operating segments are defined as components of an enterprise for which separate financial information is evaluated regularly by the chief operating decision maker in deciding how to allocate resources and assess performance. The Company’s chief operating decision maker allocates resources and assesses performance based upon financial information at the Company level.

Management Estimates

The preparation of financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, as well as certain financial statement disclosures. The Company evaluates estimates and assumptions on an ongoing basis using historical experience and other factors, including the current economic and commodity price environment. While management believes that the estimates and assumptions used in the preparation of the financial statements are appropriate, actual results could differ from these estimates. Significant estimates made in preparing these financial statements include the estimate of uncollected revenues and unpaid expenses from Interests in properties operated by nonaffiliated entities and the estimate of proved oil, natural gas and natural gas liquids reserves and related present value estimates of future net cash flows from those properties.

The discounted present value of the proved oil, natural gas and natural gas liquids reserves is a major component of the ceiling test calculation and requires many subjective judgments. Estimates of reserves are forecasts based on engineering and geological analyses. Different reserve engineers could reach different conclusions as to estimated quantities of oil, natural gas and natural gas liquids reserves based on the same information.

The passage of time provides more qualitative and quantitative information regarding reserve estimates, and revisions are made to prior estimates based on updated information. However, there can be no assurance that more significant revisions will not be necessary in the future. Significant downward revisions could result in an impairment representing a noncash charge to income. In addition to the impact on the calculation of the ceiling test, estimates of proved reserves are also a major component of the calculation of depletion.

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RIVERCREST ROYALTIES, LLC

NOTES TO FINANCIAL STATEMENTS (Continued)

For the Years Ended December 31, 2016 and 2015

NOTE 2—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

Cash and Cash Equivalents

The Company considers all highly liquid instruments purchased with a maturity date of three months or less to be cash and cash equivalents.

Accounts Receivable

Oil, natural gas and NGL receivables consists of revenue payments due to us from our Interests. Other receivables are amounts due as reimbursement for costs incurred by the Company. These reimbursable costs included in accounts receivable were $333,056 and $1,356,937 at December 31, 2016 and 2015, respectively. The Company estimates portions of these receivables for which failure to collect is probable based on the relevant facts and circumstances surrounding the receivable. As of December 31, 2016, and 2015, no allowance for doubtful accounts is deemed necessary based upon the lack of historical write offs and review of current receivables.

Property and Equipment

Other property and equipment includes furniture, fixtures, office equipment, leasehold improvements, and computer software and is stated at historical cost. Depreciation and amortization are calculated using the straight-line method over expected useful lives ranging from three to seven years. Leasehold improvements are depreciated over the shorter of the term of the underlying lease. Depreciation expense totaled $105,552 and $7,551 during the years ended December 31, 2016 and 2015, respectively. As of December 31, 2016, property and equipment consisted of the following:

Computer hardware and equipment	$	8,927
Office furniture and equipment	42,337
Leasehold improvements	323,407
Less: accumulated depreciation	(113,103		)
Property and equipment, net	$	261,568

Oil and Natural Gas Properties

The Company follows the full cost method of accounting for costs related to its oil, natural gas and natural gas liquids properties. Under this method, all such costs are capitalized and amortized on an aggregate basis over the estimated lives of the properties using the unit-of-production method.

The capitalized costs are subject to a ceiling test, which limits such pooled costs to the aggregate of the present value of future net revenues attributable to proved oil, natural gas and natural gas liquids reserves discounted at 10% plus the lower of cost or market value of unproved properties. The Company did not assign any value to unproved properties in which it holds an interest. The full cost ceiling is evaluated at the end of each period and additionally when events indicate possible impairment.

While the quantities of proved reserves require substantial judgment, the associated prices of oil, natural gas and natural gas liquids reserves that are included in the discounted present value of our reserves are objectively determined. The ceiling test calculation requires use of the unweighted arithmetic average of the first day of the month price during the 12-month period ending on the balance sheet date and costs in effect as of the last day of the accounting period, which are generally held constant for the life of the properties. As a result, the present value is

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RIVERCREST ROYALTIES, LLC

NOTES TO FINANCIAL STATEMENTS (Continued)

For the Years Ended December 31, 2016 and 2015

NOTE 2—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

not necessarily an indication of the fair value of the reserves. Oil, natural gas and natural gas liquids prices have historically been volatile, and the prevailing prices at any given time may not reflect the Company’s or the industry’s forecast of future prices.

During the years ended December 31, 2016 and 2015, management’s estimates and the cost ceiling analysis established that the Company’s proved properties required the recording of an impairment. The Company recorded an impairment expense of $4,992,897 and $28,673,166 for the years ended December 31, 2016 and 2015, respectively, as a result of reductions in estimated proved reserves and reduced commodity prices.

The Company’s properties are being depleted on the unit-of-production method using estimates of proved oil, natural gas and natural gas liquids reserves. Sales or other dispositions of oil and gas properties are accounted for as adjustments to capitalized costs, with no gain or loss recorded unless the ratio of cost to estimated proved reserves would significantly change.

Proceeds from other dispositions of oil, natural gas and natural gas liquids properties are credited to the full cost pool. No gains or losses were recorded for the years ended December 31, 2016 and 2015.

Due to the nature of the Company’s Interests, there are no exploratory activities pending determination, and no exploratory costs were charged to expense for the years ended December 31, 2016 and 2015.

Asset Retirement Obligations

The Company’s asset retirement obligation (‘‘ARO’’) reflects the present value of estimated costs of dismantlement, removal, site reclamation, and similar activities associated with the Company’s non-operated working interests in oil and natural gas properties.

Fair values of legal obligations to retire and remove long-lived assets are recorded when the obligation is incurred. When the liability is initially recorded, the Company capitalizes this cost by increasing the carrying amount of the related property and equipment. Over time, the liability is accreted for the change in its present value and the capitalized cost in oil and natural gas properties is depleted based on units of production consistent with the related asset.

Loan Origination Costs

The Company records costs associated with establishing its debt facilities as loan origination costs and amortizes such costs over the terms of the respective loans.

Other Long-Term Liabilities

Other long-term liabilities consist of the tenant improvement allowance granted at the effective date of the lease for the Company’s office space. This allowance is accounted for as a deferred incentive and will be amortized over the term of the lease as a reduction to future rent expense.

Income Taxes

The Company is a limited liability company and is taxed as a partnership under the Internal Revenue Code whereby the Company’s members are taxed on their proportionate share of taxable income. The financial statements, therefore, do not include a provision for federal income taxes.

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RIVERCREST ROYALTIES, LLC

NOTES TO FINANCIAL STATEMENTS (Continued)

For the Years Ended December 31, 2016 and 2015

NOTE 2—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

Texas imposes a franchise tax (commonly referred to as the Texas margin tax, which is considered an income tax) at a rate of 0.95% on gross revenues less certain deductions, as specifically set forth in the Texas margin tax statute. During the years ended December 31, 2016 and 2015, the Company incurred income taxes in Texas and other states amounting to $19,848 and $8,111, respectively. During the year ended December 31, 2015, the Company was refunded $40,310 from states for overpayments of income tax payments made in prior years. These refunds are recognized in the statements of operations as an offset to state income tax expense.

Uncertain tax positions are recognized in the financial statements only if that position is more-likely-than-not of being sustained upon examination by taxing authorities, based on the technical merits of the position. At December 31, 2016 and 2015, the Company had no uncertain tax positions.

The Company recognizes interest and penalties related to uncertain tax positions in income tax expense. For the years ended December 31, 2016 and 2015, the Company did not recognize any interest or penalty expense related to uncertain tax positions.

The Company has filed all tax returns to date that are currently due. Tax years after December 31, 2013 remain subject to possible examination by taxing authorities although no such examination has been requested.

Concentration of Credit Risk

The Company has no involvement or operational control over the volumes and method of sale of oil, natural gas and natural gas liquids produced and sold from the properties. It is believed that the loss of any single customer would not have a material adverse effect on the results of operations.

At times, the Company maintains deposits in federally insured financial institutions in excess of federally insured limits. Management monitors the credit ratings and concentration of risk with these financial institutions on a continuing basis to safeguard cash deposits. The Company has not experienced any losses related to amounts in excess of federally insured limits.

During the year ended December 31, 2016, three purchasers accounted for approximately 20%, 13% and 10% of oil, natural gas and natural gas liquids sales revenue. During the year ended December 31, 2015, three purchasers accounted for approximately 19%, 13% and 10% of oil, natural gas and natural gas liquids sales revenue.

Limited Liability Company

As a limited liability company, the members of the Company are not liable for the liabilities or other obligations of the Company, and the Company will continue perpetually until terminated pursuant to statute or any provisions of its limited liability company agreement (the ‘‘Company Agreement’’).

Revenue Recognition

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

As an owner of Interests, the Company is entitled to a portion of the revenues received from the production of oil, natural gas and associated natural gas liquids from the underlying acreage, net of post-production expenses and taxes. The pricing of oil, natural gas and natural gas liquids sales from the properties is primarily determined by

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RIVERCREST ROYALTIES, LLC

NOTES TO FINANCIAL STATEMENTS (Continued)

For the Years Ended December 31, 2016 and 2015

NOTE 2—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

supply and demand in the marketplace and can fluctuate considerably. The Company has no involvement or operational control over the volumes and method of sale of oil, natural gas and natural gas liquids produced and sold from the properties.

To the extent actual volumes and prices of oil, natural gas and natural gas liquids are unavailable for a given reporting period because of timing or information not received from third parties, the expected sales volume and prices for these properties are estimated and recorded within accounts receivable in the accompanying consolidated balance sheet. Differences between estimates of revenue and the actual amounts are adjusted and recorded in the period that the actual amounts are known.

Fair Value Measurements

The carrying amount of cash and cash equivalents, accounts receivable, and accounts payable, as reflected in the balance sheets, approximate fair value because of the short-term maturity of these instruments. The carrying amount reported for long-term debt represents fair value as the interest rates approximate current market rates. These estimated fair values may not be representative of actual values of the financial instruments that could have been realized or that will be realized in the future.

Fair value is defined as the price that would be received to sell an asset or the price paid to transfer a liability in an orderly transaction between market participants at the measurement date. Fair value measurements are based upon inputs that market participants use in pricing an asset or liability, which are characterized according to a hierarchy that prioritizes those inputs based on the degree to which they are observable. Observable inputs represent market data obtained from independent sources, whereas unobservable inputs reflect a company’s own market assumptions, which are used if observable inputs are not reasonably available without undue cost and effort. The three input levels of the fair value hierarchy are as follows:

· Level 1—quoted market prices for identical assets or liabilities in active markets.

· Level 2—quoted market prices for similar assets or liabilities in active markets; quoted prices for identical or similar assets or liabilities in markets that are not active; inputs other than quoted prices that are observable for the asset or liability and inputs derived principally from or corroborated by observable market data by correlation or other means.

· Level 3—unobservable inputs for the asset or liability.

The ARO is classified within Level 3 as the fair value is estimated using discounted cash flow projections using numerous estimates, assumptions and judgments regarding such factors as the existence of a legal obligation for an ARO, estimated amounts and timing of settlements, the credit-adjusted risk-free rate to be used and inflation rates. See Note 10 for the summary of changes in the fair value of the ARO for the years ended December 31, 2016 and 2015.

Recently Issued Accounting Pronouncements

In January 2017, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2017-04, “Simplifying the Test of Goodwill Impairment.” ASU 2017-04 simplifies the quantitative goodwill impairment test requirements by eliminating the requirement to calculate the implied fair value of goodwill (Step 2 of the current goodwill impairment test). Instead, a company would record an impairment charge based on the excess of a reporting unit’s carrying value over its fair value (measured in Step 1 of the current goodwill impairment test). This update is effective for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years, and early adoption is permitted. Entities will apply the standard’s provisions

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RIVERCREST ROYALTIES, LLC

NOTES TO FINANCIAL STATEMENTS (Continued)

For the Years Ended December 31, 2016 and 2015

NOTE 2—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

prospectively. The Company does not believe this standard will have a material quantitative effect on the financial statements.

In June 2016, the FASB issued ASU 2016-13, “Measurement of Credit Losses on Financial Instruments.” ASU 2016-13 changes the impairment model for most financial assets and certain other instruments, including trade and other receivables, held-to-maturity debt securities and loans, and requires entities to use a new forward-looking expected loss model that will result in the earlier recognition of allowances for losses. This update is effective for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years. Early adoption is permitted for a fiscal year beginning after December 15, 2018, including interim periods within that fiscal year. Entities will apply the standard’s provisions as a cumulative-effect adjustment to retained earnings as of the beginning of the first reporting period in which the guidance is adopted. The Company does not believe this standard will have a material impact on its financial statements.

In March 2016, the FASB issued ASU 2016-09, “Improvements to Employee Share-Based Payment Accounting.” ASU 2016-09 simplifies several aspects of the accounting for share-based payment transactions, including accounting for income taxes, forfeitures and statutory tax withholding requirements, as well as certain classification changes in the statement of cash flows. This update is effective for fiscal years beginning after December 15, 2016, including interim periods within that fiscal year. The Company does not believe this standard will have a material impact on its financial statements.

In February 2016, the FASB issued ASU 2016-02, “Leases.” ASU 2016-02 requires the recognition of lease assets and lease liabilities by lessees for those leases currently classified as operating leases and makes certain changes to the way lease expenses are accounted for. This update is effective for fiscal years beginning after December 15, 2018, including interim periods within that fiscal year. This update should be applied using a modified retrospective approach, and early adoption is permitted. The Company is evaluating the new guidance and has not determined the impact this standard may have on its financial statements.

In May 2014, the FASB issued ASU 2014-09, “Revenue From Contracts with Customers’ (TOPIC 606).” an accounting standards update on a comprehensive new revenue recognition standard that will supersede Accounting Standards Codification (‘‘ASC’’) 605, Revenue Recognition. The new accounting guidance creates a framework under which an entity will allocate the transaction price to separate performance obligations and recognize revenue when each performance obligation is satisfied. Under the new standard, entities will be required to use judgment and make estimates, including identifying performance obligations in a contract, estimating the amount of variable consideration to include in the transaction price, allocating the transaction price to each separate performance obligation, and determining when an entity satisfies its performance obligations. The standard allows for either ‘‘full retrospective’’ adoption, meaning that the standard is applied to all of the periods presented with a cumulative catch-up as of the earliest period presented, or ‘‘modified retrospective’’ adoption, meaning the standard is applied only to the most current period presented in the financial statements with a cumulative catch-up as of the current period.

The Partnership has not identified any revenue streams that would be materially impacted and does not expect the adoption of this standard to have a material effect on our financial statements. The Company is still evaluating the impact that the new accounting guidance will have on its financial statements and related disclosures and has not yet determined the method by which it will adopt the standard.

NOTE 3—LONG-TERM DEBT

On January 31, 2014, the Company entered into a credit agreement with Frost Bank for up to a $50,000,000 revolving credit facility. The credit facility is subject to borrowing base restrictions and is collateralized by certain properties. The initial borrowing base was $10,000,000. Interest is payable monthly on Alternate Base Rate loans or at the end of the interest period on any Eurodollar loans, with all principal and unpaid interest due at maturity on January 15, 2018.

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RIVERCREST ROYALTIES, LLC

NOTES TO FINANCIAL STATEMENTS (Continued)

For the Years Ended December 31, 2016 and 2015

NOTE 3—LONG-TERM DEBT (Continued)

The credit facility provides for access to standby and/or commercial letters of credit up to an aggregate sum of $1,000,000. The credit facility also provides for commitment fees of 0.50% calculated on the difference between the borrowing base and the aggregate outstanding loans under the credit facility.

The credit facility is subject to semi-annual redeterminations of the borrowing base to be performed on February 1 and August 1 of each year. In addition to the scheduled semi-annual borrowing base redeterminations, the lenders or the Company have the right to redetermine the borrowing base at any time, provided that no party can request more than one such redetermination between the regularly scheduled borrowing base redeterminations. The determination of the borrowing base is subject to a number of factors including quantities of proved oil, natural gas and natural gas liquids reserves, Frost Bank’s price assumptions and other various factors. Frost Bank can redetermine the borrowing base to a lower level than the current borrowing base if they determine that the oil, natural gas and natural gas liquids reserves, at the time of redetermination, are inadequate to support the borrowing base then in effect.

On May 12, 2014, the Company and Frost Bank amended the credit facility to increase the borrowing base to $20,000,000 and to change certain covenants. At December 31, 2016 and 2015, the Company had outstanding advances on long-term debt totaling $10,598,860 and $11,448,860, respectively. The Company was required to pay loan origination fees totaling $13,000 during the year ended December 31, 2016. These loan origination fees are being amortized over the term of the credit agreement. At December 31, 2016 and 2015, the weighted average interest rate on the Company’s outstanding advances was 3.39% and 3.03%.

On January 28, 2016, the Company and Frost Bank amended the credit facility to decrease the borrowing base to $13,000,000 and to change certain covenants.

On May 23, 2016, the Company and Frost Bank amended the credit facility to extend the maturity date of the credit facility to January 15, 2018.

On February 7, 2017, the Company repaid the entire outstanding principal and interest balance on the credit facility with cash proceeds from the sale of the Company’s mineral, royalty and overriding royalty interests to Kimbell Royalty Partners, LP (“KRP”). See Note 11 for additional information on the sale of the company’s oil, natural gas and natural gas liquids properties to KRP.

The credit facility contains certain restrictive covenants. The Company was in compliance with all of the covenants included in the credit facility as of December 31, 2016.

NOTE 4—COMMON UNITS

Limited Call Right

The Company Agreement provides for a limited call right. If at any time any person owns more than 90% of the then issued and outstanding membership interests of any class, such person will have the right, which it may assign in whole or in part to any of its affiliates or to the Company, to acquire all, but not less than all, of the remaining membership interests of the class held by unaffiliated persons as of a record date to be selected by the Company’s Board of Managers (the ‘‘Board of Managers’’), on at least 10 but not more than 60 days’ notice. Unitholders are not entitled to dissenters’ rights of appraisal under the Company Agreement or applicable Delaware law if this limited call right is exercised.

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RIVERCREST ROYALTIES, LLC

NOTES TO FINANCIAL STATEMENTS (Continued)

For the Years Ended December 31, 2016 and 2015

NOTE 4—COMMON UNITS (Continued)

Distributions

The Company may distribute funds of the Company that the Board of Managers reasonably determines are not needed for payment of existing or foreseeable Company obligations and expenditures at such times and in such amounts as the Board of Managers determines to be appropriate. Distributions are made to all unitholders pro rata in accordance with their respective sharing ratios. During the years ended December 31, 2016 and 2015, the Company made distributions to members totaling $0 and $3,249,327, respectively.

NOTE 5—EARNINGS PER UNIT

The earnings per unit (‘‘EPU’’) on the statements of operations is based on the net income of the Company for the years ended December 31, 2016 and December 31, 2015, since this is the amount of net income that is attributable to the Company’s common units.

Payments made to the Company’s unitholders are determined in relation to the cash distribution policy described in Note 4—Common Units.

Basic EPU is calculated by dividing net income by the weighted-average number of common units outstanding during the period. Diluted net income per common unit gives effect, when applicable, to unvested common units granted under the Company’s long-term incentive plan described in Note 6—Unit-Based Compensation. At December 31, 2016 and December 31, 2015, the effect of the 110,000 options issued under the Company’s long-term incentive plan would be anti-dilutive. Therefore, the options issued under the Company’s long-term incentive plan were not included in the diluted EPU calculation on the statements of operations.

	For the Years Ended December 31,
	2016			2015
Net loss attributable to the period	$	(6,212,619	)	$	(31,313,926	)
Net loss per common unit, basic and diluted	$	(10.28	)	$	(51.83	)
Weighted-average common units outstanding, basic and diluted	604,137			604,137

NOTE 6—UNIT-BASED COMPENSATION

On October 1, 2014, the Board of Managers approved and adopted a long-term incentive plan that provided for the issuance of up to 110,000 membership units in the form of options.

Certain unitholders were granted options as compensation for services they performed for the Company. The options vest upon the first to occur of five years from the grant date or upon a change in control of the Company. The options expire ten years from the grant date. The options carry a distribution right, whereby the option holder receives distributions that are commensurate with those given to holders of membership units. The option agreement also specifies the option holder will receive a cumulative catch-up payment for distributions made to unitholders since inception of the Company to the date of grant. The Company has recognized compensation expense for the cumulative catch-up distribution payments in the period paid and the vesting of the options ratably over the vesting period.

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RIVERCREST ROYALTIES, LLC

NOTES TO FINANCIAL STATEMENTS (Continued)

For the Years Ended December 31, 2016 and 2015

NOTE 6—UNIT-BASED COMPENSATION (Continued)

The fair value of each option award was estimated on the date of grant using the Black-Scholes option pricing model and using certain assumptions. The risk-free interest rate represents the U.S. Treasury bill rate for the expected life of the related unit options. The expected distribution represents the Company’s historical and anticipated cash distributions over the expected life of the unit options. The grant date fair value of the options was $27.50 per unit, based on a grant date of October 1, 2014, which was determined with the following assumptions:

Expected volatility (1)	55	%
Expected distributions (2)	7	%
Expected term (in years)	5
Risk free interest rate (3)	1.69	%

(1) Because the Company’s membership units have no trading history, the Company does not have sufficient information available on which to base a reasonable and supportable estimate of the expected volatility of its unit price. As a result, the Company used an average historical volatility of the Company’s peer group over a time period consistent with its expected term assumption. The Company’s peer group was determined based upon industry peers with similar business models.

(2) At the time of the unit grant, the Company had historically paid a 7% distribution.

(3) Based on the yields of U.S. Department of Treasury instruments with similar expected lives.

A summary of the unit option activity as of December 31, 2016, is as follows:

	Units	Weighted- Average Exercise Price		Weighted- Average Remaining Contractual Term
Outstanding, December 31, 2015	110,000	$	100	8.75 years
Granted	—	—
Forfeited	—	—
Exercised	—	—
Outstanding, December 31, 2016	110,000	$	100	8.00 years
Exercisable, December 31, 2016	—	$	—

For the years ended December 31, 2016 and 2015, total compensation expense for awards under the long-term incentive plan was $605,059 and $605,059 respectively, and is included general and administrative expenses in the statements of operations. Unrecognized compensation expense was $1,663,914, which will be recognized on a straight-line basis over the remaining vesting period of the options. As of December 31, 2016, no units have been forfeited from awards made under the long-term incentive plan. As of December 31, 2016, there were no additional units available for future issuance under the long-term incentive plan.

NOTE 7—RELATED PARTY TRANSACTIONS

During the years ended December 31, 2016 and 2015, the Company had certain related party receivables and payables; however, such amounts are de minimis at December 31, 2016 and 2015.

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RIVERCREST ROYALTIES, LLC

NOTES TO FINANCIAL STATEMENTS (Continued)

For the Years Ended December 31, 2016 and 2015

NOTE 8—ADMINISTRATIVE SERVICES

The Company relies upon its officers, directors and outside consultants to further its business efforts. The Company also hires independent contractors and consultants involved in land, technical, regulatory and other disciplines to assist its officers and directors. Certain administrative services are being provided by individuals on the Company’s Board of Managers and their affiliated entities.

NOTE 9—COMMITMENTS

Effective August 1, 2015, the Company entered into a lease for office space under a non-cancelable operating lease that expires on July 31, 2020. Future minimum rental payments under this non-cancelable operating lease agreement are:

Years Ending December 31,
2017	$	77,176
2018	78,638
2019	80,684
2020	47,066
Total	$	283,564

Rental expense for the years ended December 31, 2016 and 2015 was $13,734 and $24,826, respectively. During the year ended December 31, 2016, the Company’s rent expense included only the Company’s allocated portion of the total rental expense for the lease for office space. The remaining portion of the rental expense for the lease for the office space was reimbursed by the other Contributors of Kimbell Royalty Partners, LP.

Management is not aware of any legal, environmental or other commitments or contingencies that would have a material effect on the Company’s financial condition, results of operations or liquidity.

NOTE 10—ASSET RETIREMENT OBLIGATIONS

The asset retirement obligations (‘‘ARO’’) liability reflects the present value of estimated costs of dismantlement, removal, site reclamation, and similar activities associated with the Company’s non-operated working interest in oil, natural gas and natural gas liquids properties. The Company utilizes current retirement costs to estimate the expected cash outflows for retirement obligations. The Company estimates the ultimate productive life of the properties, a risk-adjusted discount rate, and an inflation factor in order to determine the current present value of this obligation. To the extent future revisions to these assumptions impact the present value of the existing ARO liability, a corresponding adjustment is made to the oil and natural gas property balance. The following table describes changes to the Company’s ARO liability:

	As of December 31,
	2016		2015
Asset retirement obligation at beginning of year	$	40,352	$	39,532
Accretion expense	1,129		820
Asset retirement obligation at end of year	$	41,481	$	40,352

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RIVERCREST ROYALTIES, LLC

NOTES TO FINANCIAL STATEMENTS (Continued)

For the Years Ended December 31, 2016 and 2015

NOTE 11—SUBSEQUENT EVENTS

The Partnership has evaluated events that occured subsequent to December 31, 2016 in the preparation of its financial statements.

On February 3, 2017, the Company sold 100% of its mineral, royalty and overriding royalty interests to KRP for cash and common units in KRP. Also on February 3, 2017, the Company’s non-operating working interests were assigned to Rivercrest Royalties Holdings, LLC, an affiliated entity with a member unit allocation similar to that of the Company.

NOTE 12—SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION (UNAUDITED)

The Company has only one reportable operating segment, which is oil and gas producing activities in the United States. See the Company’s accompanying statements of operations for information about results of operations for oil and gas producing activities.

Capitalized oil and natural gas costs

Aggregate capitalized costs related to oil and natural gas production activities with applicable accumulated depreciation, depletion and amortization are as follows:

	As of December 31,
	2016			2015

Oil, natural gas and NGL interests Proved	$	70,888,121		$	70,809,962
Total oil, natural gas and NGL interests	70,888,121			70,809,962
Accumulated depletion and impairment	(51,948,355		)	(45,457,931		)
Net oil, natural gas and NGL interests capitalized	$	18,939,766		$	25,352,031

Costs incurred in oil and natural gas activities

Costs incurred in oil, natural gas and natural gas liquids acquisition and development activities are as follows:

	For the Years Ended December 31,
	2016		2015
Acquisition costs
Proved properties	$	—	$	42,000
Total	—		42,000
Development costs
Proved properties	78,159		464,680
Total	78,159		464,680
Total costs incurred on oil, natural gas and NGL activities	$	78,159	$	506,680

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RIVERCREST ROYALTIES, LLC

NOTES TO FINANCIAL STATEMENTS (Continued)

For the Years Ended December 31, 2016 and 2015

NOTE 12—SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION (UNAUDITED)

(Continued)

Results of Operations from Oil, Natural Gas and Natural Gas Liquids Producing Activities

The following schedule sets forth the revenues and expenses related to the production and sale of oil, natural gas and natural gas liquids. It does not include any interest costs or general and administrative costs and, therefore, is not necessarily indicative of the contribution to the net operating results of the Company’s oil, natural gas and natural gas liquids operations.

	December 31,
	2016			2015
Oil, natural gas and NGL revenues	$	3,606,659		$	4,684,923
Production and ad valorem taxes	(280,474		)	(426,885		)
Operating expense	(750,792		)	(747,264		)
Depletion	(1,604,208		)	(4,008,730		)
Impairment	(4,992,897		)	(28,673,166		)
Results of operations from oil, natural gas and NGLs	$	(4,021,712	)	$	(29,171,122	)

The following tables summarize the net ownership interest in the proved oil, natural gas and natural gas liquids reserves and the standardized measure of discounted future net cash flows related to the proved oil, natural gas and natural gas liquids reserves, and the estimates were prepared by the Company based on management’s estimates for the years ended December 31, 2016 and 2015. The standardized measure presented here excludes income taxes, as the tax basis for the properties is not applicable on a go-forward basis. The proved oil, natural gas and natural gas liquids reserve estimates and other components of the standardized measure were determined in accordance with the authoritative guidance of the FASB and the SEC.

Proved Oil, Natural Gas and Natural Gas Liquids Reserve Quantities

Proved reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations. Proved developed reserves are proved reserves that can be expected to be recovered through existing wells with existing equipment and operating methods, or in which the cost of the required equipment is relatively minor compared to the cost of a new well. Proved undeveloped reserves are proved reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

A barrels of equivalent (‘‘Boe’’) conversion ratio of six thousand cubic feet per barrel (6mcf/bbl) of natural gas to barrels of oil equivalence is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. All Boe conversions in the report are derived from converting gas to oil in the ratio mix of six thousand cubic feet of gas to one barrel of oil.

The net proved oil, natural gas and natural gas liquid reserves and changes in net proved oil, natural gas and natural gas liquid reserves attributable to the oil, natural gas and natural gas liquids properties, which are located in multiple states are summarized below:

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RIVERCREST ROYALTIES, LLC

NOTES TO FINANCIAL STATEMENTS (Continued)

For the Years Ended December 31, 2016 and 2015

NOTE 12—SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION (UNAUDITED)

(Continued)

	Crude Oil and				Natural Gas
	Condensate		Natural Gas		Liquids		Total
	(MBbls)		(MMcf)		(MBbls)		(MBOE)
Net proved reserves at January 1, 2015	1,115		7,898		213		2,644
Revisions of previous estimates	(98	)	(184	)	16		(111	)
Production	(59	)	(548	)	(22	)	(173	)
Net proved reserves at December 31, 2015	958		7,166		207		2,360
Revisions of previous estimates	(16	)	471		50		113
Production	(56	)	(497	)	(22	)	(162	)
Net proved reserves at December 31, 2016	886		7,140		235		2,311

Net Proved Developed Reserves
December 31, 2015	545		4,720		136		1,468
December 31, 2016	482		4,586		150		1,396

Net Proved Undeveloped Reserves
December 31, 2015	413		2,446		71		892
December 31, 2016	404		2,554		85		915

Revisions represent changes in previous reserves estimates, either upward or downward, resulting from new information normally obtained from development drilling and production history or resulting from a change in economic factors, such as commodity prices, operating costs or development costs.

Standardized Measure

The standardized measure of discounted future net cash flows before income taxes related to the proved oil, natural gas and natural gas liquids reserves of the properties is as follows:

	For the Years Ended December 31,
	2016			2015
	(in thousands)
Future cash inflows	$	49,654		$	59,972
Future production costs	(4,566		)	(5,490		)
Future net cash flows	45,088			54,482
Less 10% annual discount to reflect timing of cash flows	(25,891		)	(31,112		)
Standard measure of discounted future net cash flows	$	19,197		$	23,370

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RIVERCREST ROYALTIES, LLC

NOTES TO FINANCIAL STATEMENTS (Continued)

For the Years Ended December 31, 2016 and 2015

NOTE 12—SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION (UNAUDITED)

(Continued)

Reserve estimates and future cash flows are based on the average market prices for sales of oil, natural gas and natural gas liquids adjusted for basis differentials, on the first calendar day of each month during the year. The average prices used for 2016 and 2015 were $42.75 and $44.26 per barrel for crude oil and condensate and $2.49 and $2.02 per Mcf for natural gas, respectively.

Future production costs are computed primarily by the Company’s petroleum engineers by estimating the expenditures to be incurred in developing and producing the proved oil and gas reserves at the end of the year, based on year-end costs and assuming continuation of existing economic conditions. As mentioned above, the standardized measure presented here does not include the effects of income taxes, as the tax basis for the properties is not applicable on a go-forward basis. A discount factor of 10% was used to reflect the timing of future net cash flows. The standardized measure of discounted future net cash flows is not intended to represent the replacement cost or fair value of the properties. An estimate of fair value would also take into account, among other things, the recovery of reserves not presently classified as proved, anticipated future changes in prices and costs, and a discount factor more representative of the time value of money and the risks inherent in oil, natural gas and natural gas liquids reserve estimates.

Changes in Standardized Measure

Changes in the standardized measure of discounted future net cash flows before income taxes related to the proved oil, natural gas and natural gas liquids reserves of the properties are as follows:

	For the Years Ended December 31,
	2016			2015
	(in thousands)
Standardized measure - beginning of year	$	23,370		$	50,764
Sales, net of production costs	(3,326		)	(4,258		)
Net changes of prices and production costs related to future production	(3,525		)	(25,570		)
Revisions of previous quantity estimates,net of related costs	939			(1,100		)
Accretion of discount	2,337			5,076
Timing differences and other	(598		)	(1,542		)
Standardized measure - end of year	$	19,197		$	23,370

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Table of Contents

RIVERCREST ROYALTIES, LLC

SELECTED QUARTERLY FINANCIAL DATA - UNAUDITED

Selected Quarterly Financial Information—Unaudited

Quarterly financial data was as follows for the periods indicated.

	First Quarter			Second Quarter			Third Quarter			Fourth Quarter
2016
Total revenue	$	755,653		$	847,740		$	969,084		$	1,034,182
Net loss	(4,049,563		)	(1,199,285		)	(769,166		)	(194,605		)
Net loss attributable to the general partner and common units subsequent to initial public offering	*			*			*			*
Net loss attributable to common units per unit (basic)	*			*			*			*
Net loss attributable to common units per unit (diluted)	*			*			*			*
Cash distributions declared and paid per limited partner unit	*			*			*			*
Total assets	22,387,175			21,404,751			20,784,733			20,538,731
Long-term debt	11,298,860			11,198,860			10,898,860			10,598,860
Members’ equity	10,341,124			9,293,104			8,675,203			8,631,862

2015
Total revenue	$	1,273,836		$	1,103,405		$	1,293,689		$	1,013,993
Net loss	(18,165,264		)	(1,068,271		)	(8,088,031		)	(3,992,360		)
Net loss attributable to the general partner and common units subsequent to initial public offering	*			*			*			*
Net loss attributable to common units per unit (basic)	*			*			*			*
Net loss attributable to common units per unit (diluted)	*			*			*			*
Cash distributions declared and paid per limited partner unit	*			*			*			*
Total assets	40,149,806			39,365,482			30,753,412			27,905,790
Long-term debt	9,598,860			10,698,860			10,998,860			11,448,860
Members’ equity	28,933,876			26,767,130			18,080,518			14,239,422

* Information is not applicable for the periods prior to the initial public offering.

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