Kimbell Royalty Partners, LP (Form: 10-K, Received: 03/09/2018 16:23:48)

WTI

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10‑K


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

For the fiscal year ended: December 31, 2017

☐	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 ☐ No ☒

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

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 ☒ No ☐

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 ☒ No ☐

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. ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non‑accelerated filer, a smaller reporting company or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company” and “emerging growth company” in Rule 12b‑2 of the Exchange Act.


Large accelerated filer	◻	Accelerated filer	◻
Non-accelerated filer	☒	Smaller reporting company	◻
Emerging growth company	☒

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☒

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

The aggregate market value of the registrant’s common units held by non-affiliates of the registrant as of June 30, 2017, was $212.2 million, based on the closing price of such common units of $16.83 as reported on the New York Stock Exchange on such date. The registrant had 16,836,453 common units outstanding as of March 2, 2018.

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Kimbell Royalty Partners, LP

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PART 1
Item 1. Business	9
Item 1A. Risk Factors	30
Item 1B. Unresolved Staff Comments	62
Item 2. Properties	62
Item 3. Legal Proceedings	62
Item 4. Mine Safety Disclosures	62
PART II
Item 5. Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities	63
Item 6. Selected Financial Data	65
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations	68
Item 7A. Quantitative and Qualitative Disclosures about Market Risk	84
Item 8. Financial Statements and Supplementary Data	85
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	85
Item 9A. Controls and Procedures	85
Item 9B. Other Information	86
PART III
Item 10. Directors, Executive Officers and Corporate Governance	87
Item 11. Executive Compensation	91
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters	98
Item 13. Certain Relationships and Related Transactions, and Director Independence	100
Item 14. Principal Accounting Fees and Services	107
PART IV
Item 15. Exhibits, Financial Statement Schedules	108
Item 16. Form 10-K Summary	110
Signatures	111

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GLOSSARY OF TERMS

The following are definitions of certain terms used in this Annual Report on Form 10-K (“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.

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

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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.

Mcf. One thousand cubic feet of natural gas.

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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 NGL. 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 NGLs which geological and engineering data demonstrate with reasonable certainty to be commercially recoverable in future years from known reservoirs under existing economic and operating conditions.

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

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

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 Securities and Exchange Commission (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 NGLs;

the level of production on our properties;

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

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

our ability to replace our reserves;

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

general economic, business or industry conditions;

competition in the oil and natural gas industry;

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

title defects in the properties in which we invest;

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

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

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

the availability of transportation facilities;

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

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

future operating results;

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

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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 services agreements with certain entities controlled by affiliates of our Sponsors and Benny D. Duncan as described herein.

Item 1. Business

Overview

We are a Delaware limited partnership formed in 2015 to own and acquire mineral and royalty interests in oil and natural gas properties throughout the United States of America (“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 NGLs from the acreage underlying our interests, net of post-production expenses and taxes. We are not obligated to fund drilling and completion costs, lease operating expenses or plugging and abandonment costs at the end of a well’s productive life. Our primary business objective is to provide increasing cash 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.

On February 8, 2017, we completed our initial public offering (“IPO”) 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. The mineral and royalty interests making up the Partnership’s initial assets were contributed to the Partnership by the Contributing Parties at the closing of the IPO. As a result, as of December 31, 2016, the Partnership had not yet acquired any of such assets. Unless otherwise indicated, the financial information presented for periods on or after February 8, 2017 refers to the Partnership as a whole. The financial information presented for the periods on or prior to February 7, 2017, is solely that of the Predecessor, Rivercrest Royalties, LLC, and does not include the results of the Partnership as a whole. However, unless otherwise indicated, the reserve data presented in this report is with the respect to all the assets that were contributed to us by the Contributing Parties in connection with our IPO. The mineral and royalty interests underlying the oil, natural gas and NGL production revenues of the Predecessor represented approximately 11% of the Partnership’s total future undiscounted cash flows, based on the reserve report prepared by Ryder Scott Company, L.P. (“Ryder Scott”) as of December 31, 2016.

As of December 31, 2017, we owned mineral and royalty interests in approximately 3.7 million gross acres and overriding royalty interests in approximately 2 million gross acres, with approximately 35% 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, 2017, over 98% 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 50,000 gross producing wells, including over 30,000 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.

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As of December 31, 2017, the estimated proved oil, natural gas and NGL reserves attributable to our interests in our underlying acreage were 20,954 MBoe (49.2% liquids, consisting of 72.4% oil and 27.6% NGLs) based on the reserve report prepared by Ryder Scott. Of these reserves, 73.1% were classified as PDP reserves, 0.4% were classified as PDNP reserves and 26.5% 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 yearly decline rate of 8.8% during the initial five-years. PUD reserves included in this estimate are from 750 gross proved undeveloped locations.

As of December 31, 2016, the estimated proved oil, natural gas and NGL 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% NGLs) 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 had low estimated decline rates. Our Predecessor’s PDP reserves had an average estimated yearly decline rate of 9.6% during the initial five-years. PUD reserves included in this estimate were from 355 gross proved undeveloped locations.

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 NGLs that are extracted from natural gas during processing. As of December 31, 2017, there were over 700 operators actively producing on our acreage, with our top ten operators (Occidental Permian Ltd., XTO Energy, Inc., Aera Energy LLC (a joint venture of Royal Dutch Shell plc and ExxonMobil Corporation), Devon Energy Production Company, LP, Hess Corporation, Chesapeake Operating, Inc., Protégé Energy III LLC, Jonah Energy LLC, Energen Resources Corporation and SEM Operating) together accounting for approximately 45.03% of our combined net income. As of December 31, 2017, there were 19 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.

For the period from February 8, 2017 to December 31, 2017, our revenues were generated 58% from oil sales, 28% from natural gas sales, 11% from NGL sales and 3% from other sales. For the period from January 1, 2017 to February 7, 2017 (the “Predecessor 2017 Period”), our Predecessor’s revenues were generated 55% from oil sales, 36% from natural gas sales and 9% from NGL sales. For the combined year ended December 31, 2017, the revenues were generated 58% from oil sales, 28% from natural gas sales, 11% from NGL sales and 3% from other sales. 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 NGL sales.

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 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, 2017, over 98% of the acreage subject to our mineral and nonparticipating royalty interests

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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 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.

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 IPO, 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 “Item 13. 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 extensive experience in identifying, evaluating and completing strategic acquisitions of mineral and royalty interests. In connection with the closing of our IPO, we entered into a management services agreement with Kimbell Operating, which entered into separate services 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 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 IPO 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

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to third‑party acquisition opportunities we might not otherwise be in a position to pursue. Please read “Item 13. 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 assets consist of diversified mineral and royalty interests. The majority of our assets, 73.5% of our well count and 46.5% 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 NGLs from the acreage underlying our interests, net of post-production expenses and taxes. We are not obligated to fund drilling and completion costs, lease operating expenses or plugging and abandonment costs at the end of a well’s productive life. As such, we benefit from the continued development of the properties we own a 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 66 2 / ₃ % of the members of the General Partner’s Board of Directors (the “Board of Directors”) . 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 IPO, we 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). We believe that this liquidity, along with internally generated cash from operations and access to the public capital markets, will provide us with the financial flexibility to grow our production, reserves and cash generated from operations through strategic acquisitions of mineral and royalty interests and the continued development of our existing assets.

Competitive Strengths

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

Significant diversified portfolio of mineral and royalty interests in mature producing basins and exposure to undeveloped opportunities. We have a diversified, low decline asset base with exposure to high-quality conventional and unconventional plays. As of December 31, 2017, we owned mineral and royalty interests in approximately 3.7 million gross acres and overriding royalty interests in approximately 2 million gross acres, with approximately 35% of our aggregate acres located in the Permian Basin and over 98% 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. The estimated proved oil, natural gas and NGL reserves attributable to our interests in our underlying acreage were 20,954 MBoe (49.2% liquids, consisting of 72.4% oil and 27.6% NGLs) based on the reserve report prepared by Ryder Scott. Of these reserves, 73.1% were classified as PDP reserves, 0.4% were classified as PDNP reserves and 26.5% were classified as PUD reserves. PUD reserves included in this estimate are from 750 gross proved undeveloped locations. As of December 31, 2016, the estimated proved oil, natural gas and NGL 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% NGLs) 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

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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 50,000 gross producing wells, including over 30,000 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 IPO, we 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). As of December 31, 2017, we had $30.8 million outstanding under the facility. 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.

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

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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.

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

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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 and our Predecessor’s 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 mineral and nonparticipating royalty interests. 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.


	December 31, 2017
	Gross	Net	Percent
Basin or Producing Region	Acres	Acres	Leased
Permian Basin (1)	1,764,954	15,741	99	%
Mid‑Continent	408,084	9,438	98	%
Terryville/Cotton Valley/Haynesville	261,762	2,347	98	%
Eagle Ford	182,102	1,968	97	%
Barnett Shale/Fort Worth Basin (2)	216,367	2,335	99	%
Bakken/Williston Basin (3)	86,544	1,485	99	%
San Juan Basin	28,852	141	98	%
Onshore California	8,626	35	68	%
DJ Basin/Rockies/Niobrara	3,967	97	59	%
Illinois Basin	6,351	83	100	%
Other Western (onshore) Gulf Basin	539,625	3,754	98	%
Other TX/LA/MS Salt Basin	144,186	1,476	91	%
Other	93,857	671	92	%
Total (4)	3,745,277	39,571	98	%

(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 78,344 gross (1,423 net) acres in the Bakken/Three Forks.

(4)

Percentage leased represents the weighted average of our leased acres relative to our total acreage in the basins in which we own mineral interests.

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ORRIs

The following table sets forth information about our ORRIs:


	December 31, 2017
	Gross	Net	Percent
Basin or Producing Region	Acres	Acres	Producing
Permian Basin (1)	232,723	2,814	100	%
Mid‑Continent	1,256,382	8,942	98	%
Terryville/Cotton Valley/Haynesville	41,812	779	99	%
Eagle Ford	72,970	597	100	%
Barnett Shale/Fort Worth Basin (2)	54,888	445	100	%
Bakken/Williston Basin (3)	31,554	1,879	100	%
San Juan Basin	47,233	908	98	%
Onshore California	9,626	13	100	%
DJ Basin/Rockies/Niobrara	3,182	102	54	%
Illinois Basin	13,304	1,032	100	%
Other Western (onshore) Gulf Basin	72,870	1,087	100	%
Other TX/LA/MS Salt Basin	22,616	1,140	100	%
Other	147,623	12,027	100	%
Total (4)	2,006,783	31,765	99	%

(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.

(3)

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

(4)

Percentage producing 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 acreage is producing.

Wells

The following table sets forth the well count in which the we had mineral or royalty interest:


Basin or Producing Region		December 31, 2017
Permian Basin		30,209
Mid‑Continent		3,626
Terryville/Cotton Valley/Haynesville		5,138
Eagle Ford		1,267
Barnett Shale/Fort Worth Basin		2,298
Bakken/Williston Basin		499
San Juan Basin		581
Onshore California		757
DJ Basin/Rockies/Niobrara		3,318
Illinois Basin		184
Other		2,587
Total		50,464

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, 2017 and 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.

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He earned a Bachelor of Science Degree in Petroleum Engineering from the Colorado School of Mines in 1983 and a Master 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 U.S. Securities and Exchange Commission (“SEC”) and other industry reserves definitions and guidelines. A copy of Ryder Scott’s estimated proved reserve report as of December 31, 2017 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 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 is 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, 2017 and 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

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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.

Summary of Estimated Proved Reserves

Estimates of reserves as of December 31, 2017 and 2016 were prepared using an average price equal to the unweighted arithmetic average of hydrocarbon prices received on a field-by-field basis on the first day of each month within the year ended December 31, 2017 and 2016, in accordance with SEC guidelines applicable to reserve estimates as of the end of such period. The unweighted arithmetic average first day of the month prices were $51.34 and $42.75 per Bbl for oil and $2.98 and $2.49 per MMBtu for natural gas at December 31, 2017 and 2016, respectively. The price per Bbl for NGLs 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.

The following table presents our and our Predecessor’s estimated proved oil and natural gas reserves:


	Partnership				Predecessor
	December 31,		December 31,		December 31,
	2017		2016		2016
Estimated proved developed reserves:
Oil (MBbls)	5,284		4,879		482
Natural gas (MMcf)	47,500		35,172		4,586
Natural gas liquids (MBbls)	2,202		1,416		150
Total (MBoe)(6:1) (1)	15,403		12,157		1,396
Estimated proved undeveloped reserves:
Oil (MBbls)	2,179		2,331		404
Natural gas (MMcf)	16,416		15,219		2,554
Natural gas liquids (MBbls)	636		566		85
Total (MBoe)(6:1) (1)	5,551		5,434		915
Estimated proved reserves:
Oil (MBbls)	7,463		7,210		886
Natural gas (MMcf)	63,916		50,391		7,140
Natural gas liquids (MBbls)	2,838		1,982		235
Total (MBoe)(6:1) (1)	20,954		17,591		2,311
Percent proved developed	74	%	69	%	60	%

(1)

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 years ended December 31, 2017 and 2016 was used, the conversion factor would be approximately 17.2 Mcf per Bbl of oil. 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

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Hub natural gas from January 3, 2006 to December 31, 2017, as reported by the U.S. Energy Information Administration (“EIA”). During this period, the ratio of the price of oil to the price of natural gas ranged from 5.64 to 56.91. The mean ratios of the price of oil to the price of natural gas were 17.10 and 17.72 for the years ended December 31, 2017 and 2016, 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 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 several variables and assumptions, all of which may vary from actual results, including geologic interpretation, prices, and future production rates and costs. Please read “Risk Factors.”

Additional information regarding our estimated proved reserves can be found in the reserve report as of December 31, 2017, which is included as an exhibit to this report.

Estimated Proved Undeveloped Reserves

As of December 31, 2017, our PUD reserves totaled 2,179 MBbls of oil, 16,416 MMcf of natural gas and 636 MBbls of NGLs, for a total of 5,552 MBoe. As of December 31, 2016, our PUD reserves totaled 2,331 MBbls of oil, 15,219 MMcf of natural gas and 566 MBbls of NGLs, for a total of 5,434 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 NGLs, for a total of 915 MBoe. PUD reserves were converted from undeveloped to developed as the applicable wells began production.

The following tables summarize our changes in PUD reserves (in MBoe):


	Partnership		Predecessor
	December 31, 2017	December 31, 2016	December 31, 2016
Beginning balance	5,434	5,224	892
Acquisitions of reserves	606	4	—
Extensions and discoveries	973	1,227	282
Revisions of previous estimates	(240)	84	(55)
Transfers to estimated proved developed	(1,222)	(1,105)	(204)
Ending balance	5,551	5,434	915

Our PUD reserves as of December 31, 2017 were from 402 vertical wells and 348 horizontal wells. As of December 31, 2017, all of our PUD drilling locations are scheduled to be drilled prior to December 31, 2022. As of December 31, 2017, approximately 0.4% of our total proved reserves were classified as proved developed non-producing.

Changes in PUDs that occurred from December 31, 2016 through December 31, 2017 were primarily due to:

the acquisition of an additional 606 MBoe through five diverse acquisition for approximately $29.3 million of royalty interests across ten states including Texas, Oklahoma, Louisiana, Wyoming, California, North Dakota, Utah, New Mexico, Arkansas, and Kansas.

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additions of approximately 973 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 1,222 MBoe PUD reserves into proved developed reserves as 349 locations (143 horizontal and 206 vertical) were drilled; and

positive revisions of approximately 204 MBoe in PUDs primarily due to modifying PUD drill schedule timing to match current drilling rates and operator projections.

Of the 349 locations that were drilled in 2017, 109 locations were specifically identified by management in its 2016 reserve estimates. The remaining 240 locations were not specifically identified in managements proved undeveloped forecast, but were included in its reserve estimates as being scheduled to be drilled in 2017. These locations include infill drilling in multi‑well units and in some cases, waterflood response, CO ₂ response, well stimulations, flood conformance improvements and pump upgrades. 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, Natural Gas and NGL Production and Pricing

Production and Price History

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


	Partnership		Predecessor		Predecessor
	Period from February 8, 2017 to December 31,		Period from January 1, 2017 to February 7,		Year Ended December 31,
	2017		2017		2016		2015
Production Data:
Oil and condensate (Bbls)		379,182		3,696		55,587		59,321
Natural gas (Mcf)		3,184,861		32,961		496,778		548,386
Natural gas liquids (Bbls)		157,177		1,220		22,360		22,351
Total (Boe)(6:1) (1)		1,067,169		10,410		160,743		173,070
Average daily production (Boe/d)(6:1)		3,264		274		440		474
Total (Boe)(20:1) (2)		695,602		6,564		102,786		109,091
Average daily production (Boe/d)(20:1)		2,127		173		282		299
Average Realized Prices:
Oil and condensate (per Bbl)	$	47.08	$	47.04	$	38.69	$	49.79
Natural gas (per Mcf)	$	2.74	$	3.47	$	2.21	$	2.44
Natural gas liquids (per Bbl)	$	21.50	$	24.61	$	15.99	$	17.56
Average Unit Cost per Boe (6:1)
Production and ad valorem taxes	$	2.30	$	1.89	$	1.74	$	2.47

(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.

(2)

“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 1 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, 2017, the Partnership owned mineral or royalty interests in

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over 50,000 productive wells, which consisted of over 40,000 oil wells and over 10,000 natural gas 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.

Acreage

Mineral and Royalty Interests

The following table sets forth information relating to the acreage underlying our mineral and nonparticipating royalty interests at December 31, 2017:


	Developed		Undeveloped		Total
State	Acreage		Acreage		Acreage
Texas	2,985,247		41,363		3,026,610
Oklahoma	101,081		6,129		107,210
Louisiana	45,679		589		46,268
New Mexico	77,443		1,005		78,448
North Dakota	84,547		720		85,267
Colorado	27,640		1,449		29,089
Wyoming	2,562		640		3,202
Kansas	83,428		1,880		85,308
Montana	2,640		4,681		7,321
Other	261,684		14,870		276,554
Total	3,671,951	(1)	73,326	(2)	3,745,277

(1)

Reflects mineral interests in approximately 3,671,951 total gross (36,932 net) developed acres.

(2)

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

The following table sets forth information relating to our acreage for our ORRIs at December 31, 2017:


	Developed		Undeveloped		Total
State	Acreage		Acreage		Acreage
Texas	1,155,795		680		1,156,475
Oklahoma	491,199		19,000		510,199
Louisiana	34,948		511		35,459
New Mexico	45,610		960		46,570
North Dakota	31,554		—		31,554
Colorado	20,577		1,454		22,031
Wyoming	72,411		—		72,411
Kansas	11,430		—		11,430
Montana	—		—		—
Other	119,927		727		120,654
Total	1,983,451	(1)	23,332	(2)	2,006,783

(1)

Reflects ORRIs in approximately 1,983,450 total gross (31,562 net) developed acres.

(2)

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

Drilling Results

As of December 31, 2017 and 2016, the operators of our properties had over 50,000 and 48,000 gross productive development wells, respectively, on the acreage underlying our mineral and royalty interests. As of December 31, 2016, our Predecessor owned mineral or royalty interests in over 13,000 productive wells. 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 period.

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Competition

The oil and natural gas industry is intensely competitive; we primarily compete with companies for the acquisition of oil and natural gas properties some of whom have greater resources than we do. These companies may be able to pay more for productive oil and natural gas properties and exploratory prospects or to define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. Additionally, many of our competitors are, or are affiliated with, operators that engage in the exploration and production of their oil and 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 Environmental Protection Agency (“EPA”), issue regulations that often require difficult and costly compliance measures that carry substantial administrative, civil and criminal penalties and may result in injunctive obligations for non‑compliance. These laws and regulations may require the acquisition of a permit before drilling commences, restrict the types, quantities and concentrations of various substances that can be released into the environment in connection with drilling and production activities, limit or prohibit construction or drilling activities on certain lands lying within wilderness, wetlands, ecologically sensitive and other protected areas, require action to prevent or remediate pollution from current or former operations, such as plugging abandoned wells or closing earthen pits, result in the suspension or revocation of necessary permits, licenses and authorizations, require that additional pollution controls be installed and impose substantial liabilities for pollution resulting from operations. The strict, 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.

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Non‑Hazardous and Hazardous Waste

The federal Resource Conservation and Recovery Act, as amended (“RCRA”), and comparable state statutes and regulations promulgated thereunder, affect oil and natural gas exploration, development, and production activities by imposing requirements regarding the generation, transportation, treatment, storage, disposal and cleanup of hazardous and non‑hazardous wastes. With federal approval, the individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. 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. Pursuant to a Consent Decree with a coalition of environmental group that filed suit in May2016, EPA must review regulations governing the disposal of certain oil and natural gas drilling wastes under RCRA by March 2019 and either determine revisions to the exemption are not necessary or undertake rulemaking to be completed by July 2021. Any changes in the laws and regulations could have a material adverse effect on the operators of our properties’ capital expenditures and operating expenses, which in turn could affect production from the acreage underlying our mineral and royalty interests and adversely affect our business and prospects.

Remediation

The federal Comprehensive Environmental Response, Compensation and Liability Act, as amended (“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 federal Water Pollution Control Act of 1972 (“Clean Water Act”), the Safe Drinking Water Act (“SDWA”), the Oil Pollution Act (“OPA”), and analogous state laws and regulations promulgated thereunder impose restrictions and strict controls regarding the unauthorized discharge of pollutants, including produced waters and other gas and oil wastes, into regulated waters. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or the state. The Clean Water Act and regulations implemented thereunder also prohibit the discharge of dredge and fill material into regulated waters, including jurisdictional wetlands, unless authorized by an appropriately issued permit. The EPA has issued a final rule 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. In January 2018, the U.S. Supreme Court issued a decision determining that only U.S. district courts have jurisdiction to hear challenges to that rule. As a result of that ruling, the Sixth Circuit stay is expected to be withdrawn, although stays issued by district courts in several states will remain in effect. 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

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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. In February 2018, the agencies also published a final rule adding a February 6, 2020 applicability date to the 2015 rule. The final rule adding this applicability date is currently subject to litigation.

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 greenhouse gases (“GHGs”), including carbon dioxide and methane, present an endangerment to public health and the environment, the EPA has adopted regulations under existing provisions of the federal Clean Air Act that, among other things, require preconstruction and operating permits for certain large stationary sources. 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 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 Climate Agreement (the “Paris Agreement”). 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

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GHG emission reduction goals, every five years beginning in 2020. The Paris Agreement entered into force in November 2016. In June 2017, President Trump announced that the United States will withdraw from the Paris Agreement unless it is renegotiated. The State Department informed the United Nations of the United States’ withdrawal in August 2017. Under the terms of the Paris Agreement, the earliest possible effective withdrawal date is November 2020.

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. That rule was rescinded in December 2017. 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 increased costs to make wells productive.

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

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 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

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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. 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 March 2017, the United States Geological Survey produced an updated seismic hazard survey that forecasted lower earthquake rates in regions of induced activity, but still showed significantly elevated hazards in the central and eastern United States. 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.

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Other Regulation of the Oil and Natural Gas Industry

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

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

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 be enacted by Congress or the various state legislatures, and what effect, if any, the proposals might have on our operations. Sales of crude oil, condensate and NGLs are not currently regulated and are made at market prices.

Drilling and Production

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

the location of wells;

the method of drilling and casing wells;

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

the rates of production or “allowables”;

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

the plugging and abandoning of wells; and

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

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

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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 NGLs are not currently regulated and are made at negotiated prices. Nevertheless, Congress could reenact price controls in the future.

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

Further, interstate and intrastate common carrier oil pipelines must provide service on a non‑discriminatory basis. Under this open access standard, common carriers must offer service to all similarly situated shippers requesting service on the same terms and under the same rates. When oil pipelines operate at full capacity, access is governed by 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. Under our revolving credit facility, we have granted the lenders a lien on substantially all of the mineral and royalty interests of our wholly owned subsidiaries.

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 IPO, we entered into a management services agreement with Kimbell Operating, which entered into separate services 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 “Item 10. Directors, Executive Officers and Corporate Governance” and “Item 13. Certain Relationships and Related Party Transactions, and Director Independence” As of December 31, 2017, Kimbell Operating has approximately 14 employees performing services for our operations and activities.

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 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

There are many factors that could have a material adverse effect on the Partnership’s operating results, financial condition and cash flows. New risks may emerge at any time and the Partnership cannot predict those risks or estimate the extent to which they may affect financial performance. Each of the risks described below could adversely impact the value of the Partnership’s common units.

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 NGL revenues we generate, which is dependent upon the prices that the operators of our properties realize from the sale of oil and natural gas production. In addition, the actual amount of our available cash 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 IPO 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 an 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 NGLs produced from the acreage underlying our interests is sold. The volatility of these prices due to factors beyond our control greatly affects our business, financial condition, results of operations and cash available 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 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.”

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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 66 2 / ₃ % of the members of the Board of Directors, 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 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 NGLs produced from the acreage underlying our interests is sold. The volatility of these prices due to factors beyond our control greatly affects our business, financial condition, results of operations and cash available 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 NGLs. Historically, oil, natural gas and NGL prices have been volatile and are subject to fluctuations in response to changes in supply and demand, market uncertainty and a variety of additional factors that are beyond our control, including:

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

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

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

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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 NGL derivative contracts;

the level of consumer product demand;

weather conditions and other natural disasters;

risks associated with operating drilling rigs;

technological advances affecting energy consumption;

domestic and foreign governmental regulations and taxes;

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

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

the price and availability of alternative fuels; and

overall domestic and global economic conditions.

These factors and the volatility of the energy markets make it extremely difficult to predict future oil and natural gas price movements with any certainty. For example, during the past five years, the posted price for 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 $8.15 per MMBtu in February 2014. On December 29, 2017, the WTI posted price for crude oil was $60.46 per Bbl and the Henry Hub spot market price of natural gas was $3.69 per MMBtu. 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 NGLs or prolonged period of low commodity prices will materially adversely affect our business, financial condition, results of operations and cash available for distribution. We may use various derivative instruments in connection with anticipated oil and natural gas sales to minimize the impact of commodity price fluctuations. However, we cannot always hedge the entire exposure of our operations from commodity price volatility. To the extent we do not hedge against commodity price volatility, or our hedges are not effective, our results of operations and financial position may be diminished.

In addition, lower oil and natural gas prices may reduce the amount of oil and natural gas that can be produced economically by our operators. This scenario may result in our having to make substantial downward adjustments to our

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estimated proved reserves, which could negatively impact our borrowing base and our ability to fund our operations. If this occurs or if production estimates change or exploration or development results deteriorate, successful efforts method of accounting principles may require us to write down, as a non-cash charge to earnings, the carrying value of our oil and natural gas properties. Our operators could also determine during periods of low commodity prices to shut in or curtail production from wells on our properties. In addition, they could determine during periods of low commodity prices to plug and abandon marginal wells that otherwise may have been allowed to continue to produce for a longer period under conditions of higher prices. Specifically, they may abandon any well if they reasonably believe that the well can no longer produce oil or natural gas in commercially paying quantities.

Our derivative activities could result in financial losses and reduce earnings.

To achieve a more predictable cash flow and to reduce our exposure to adverse fluctuations in the prices of oil and natural gas, we currently have entered, and may in the future enter, into derivative contracts for a portion of our future oil and natural gas production, including fixed price swaps, collars and basis swaps. We have not designated and do not plan to designate any of our derivative contracts as hedges for accounting purposes and, as a result, record all derivative contracts on our balance sheet at fair value with changes in fair value recognized in current period earnings. Accordingly, our earnings may fluctuate significantly as a result of changes in the fair value of our derivative contracts. Derivative contracts also expose us to the risk of financial loss in some circumstances, including when:

production less than expected;

the counterparty to the derivative contract defaults on its contract obligation; or

the actual differential between the underlying price in the derivative contract and actual prices received is materially different from that expected.

In addition, these types of derivative contracts can limit the benefit we would receive from increases in the prices for oil and natural gas.

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 natural gas prices increase the cost center ceiling applicable to the subsequent period.

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exemption to exclude these acquired assets from the full-cost ceiling test was appropriate. In making this determination, management considered that the value was based on a transaction conducted in a public offering and that the common units issued by the Partnership as consideration for the properties were attributed the same value as those purchased in the Partnership’s IPO by third-party investors. Additionally, the fair value of the properties acquired at the closing of our IPO was based on forward strip oil and natural gas pricing existing at the date of the IPO and management affirmed that there has not been a material decline to the fair value of these acquired assets since the IPO. The properties acquired at the closing of our IPO have an unamortized cost at December 31, 2017 of $237.2 million. Had management not affirmed the lack of material change to the fair value, the impairment charge recorded would have been $64.3 million as of December 31, 2017. The Partnership will recognize an impairment in the first quarter of 2018 after the exemption has expired, which could materially adversely affect our results of operations for the periods in which such charges are taken.

No impairment expense was recorded by the Predecessor for the period from January 1, 2017 to February 7, 2017 (the “Predecessor 2017 Period”). During the years ended December 31, 2016 and 2015 our Predecessor recorded a non‑cash impairment charges of approximately $5.0 million and $28.7 million, respectively, primarily due to changes in reserve values resulting from the reduction in commodity prices and other factors.

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, 2017, we received revenue from over 700 operators. For the year ended December 31, 2017, we received approximately 45.03% of revenues from the top ten operators of our properties. 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

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the rate of production of the reserves.

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

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

As of December 31, 2017, 26.5% 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 NGLs 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.

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Our failure to successfully identify, complete and integrate acquisitions of properties or businesses would slow our growth and could materially adversely affect our results of operations and cash available 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 NGL prices and their applicable differentials;

development plans;

operating costs; and

potential environmental and other liabilities.

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

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

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

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

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

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

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

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

mistaken assumptions about the overall cost of equity or debt;

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

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

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

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

Our ability to grow depends in part on our ability to make acquisitions that increase our cash generated from our mineral and royalty interests. The acquisition component of our strategy is based, in large part, on our expectation of ongoing acquisitions from industry participants, including our Sponsors and the Contributing Parties. While we believe the Contributing Parties, including affiliates of our Sponsors, will be incentivized through their direct and indirect ownership of common units to offer us the opportunity to acquire additional mineral and royalty interests, including with respect to certain assets for which certain of the Contributing Parties have granted us a right of first offer for a period of three years after the closing of our IPO, 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.

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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 and our Predecessor’s historical estimates of proved reserves and related valuations as of December 31, 2017 and 2016 were prepared by Ryder Scott, an independent petroleum engineering firm, which conducted a well‑by‑well review of all of our properties for the period covered by its reserve report using information provided by us. Over time, we may make material changes to reserve estimates taking into account the results of actual drilling, testing and production and changes in prices. Some of our reserve estimates were made without the benefit of a lengthy production history, which are less reliable than estimates based on a lengthy production history. In estimating our reserves, we and our reserve engineers make certain assumptions that may prove to be incorrect, including assumptions regarding future oil and natural gas prices, production levels and operating and development costs. Any significant variance from these assumptions to actual figures could greatly affect our estimates of reserves, the economically recoverable quantities of oil and natural gas attributable to any particular group of properties, the classifications of reserves based on risk of recovery and estimates of future net cash flows. Numerous changes over time to the assumptions on which our reserve estimates are based, as described above, often result in the actual quantities of oil and natural gas that are ultimately recovered being different from our reserve estimates.

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

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 $50.0 million secured revolving credit facility in connection with our IPO. The secured revolving 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;

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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 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—Revolving Credit Agreement.”

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

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;

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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 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, 2017, the average estimated yearly five‑year decline rate for our existing proved developed producing reserves is 8.8%. 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 the unitholders’ investment in us as opposed to a return on the unitholders’ 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

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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 NGLs from our properties are sold, affect the ability of vendors, suppliers and customers associated with our properties to continue operations and ultimately materially adversely impact our results of operations, financial condition and cash available for distribution.

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

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

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

The oil and natural gas industry is intensely competitive, and the operators of our properties compete with other companies that may have greater resources. Many of these companies explore for and produce oil and natural gas, carry on midstream and refining operations, and market petroleum and other products on a regional, national or worldwide basis. In addition, these companies may have a greater ability to continue exploration activities during periods of low oil and natural gas market prices. Our operators’ larger competitors may be able to absorb the burden of present and future federal, state, local and other laws and regulations more easily than our operators can, which would adversely affect our operators’ competitive position. Our operators may have fewer financial and human resources than many companies in our operators’ industry and may be at a disadvantage in bidding for exploratory prospects and producing oil and natural gas properties.

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

Many key responsibilities within our business have been assigned to a small number of individuals. We rely on our founders for their knowledge of the oil and natural gas industry, relationships within the industry and experience in identifying, evaluating and completing acquisitions. We have entered into a management services agreement with Kimbell Operating, which has entered into separate services 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 services 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

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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.

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 IPO, including title defects.

In connection with our IPO, 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 IPO. 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 IPO, 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 IPO 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 IPO.

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 IPO. 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.

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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 IPO. 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 “Item 13 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 our unitholders that the analogies our operators draw from available data from the wells on our acreage, more fully explored locations or producing fields will be applicable to their drilling locations. Further, initial production rates reported by our or other operators in the areas in which our reserves are located may not be indicative of future or long‑term production rates. Because of these uncertainties, we do not know if the potential drilling locations our operators have identified will ever be drilled or if our operators will be able to produce oil or natural gas from these or any other potential drilling locations. As such, the actual drilling activities of the operators of our properties may materially differ from those presently identified, which could materially adversely affect our business, results of operation and cash available for distribution.

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

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

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

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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.

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.

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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.

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 Clean

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Water Act and OPA (and comparable state laws and regulations that impose requirements related to discharges of pollutants into regulated bodies of water), the RCRA (and comparable state laws that impose requirements for the handling and disposal of waste), the 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.

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 2016, 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

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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 GHGs present an endangerment to public health and the environment, the EPA has adopted regulations under existing provisions of the federal Clean Air Act that, among other things, require preconstruction and operating permits for certain large stationary sources. Facilities required to obtain preconstruction permits for their GHG emissions also will be required to meet “best available control technology” standards that will be established on a case‑by‑case basis. These EPA rulemakings could adversely affect operations on our properties and restrict or delay the ability of our operators to obtain air permits for new or modified sources. In addition, the EPA has adopted rules requiring the monitoring and reporting of GHG emissions from specified onshore oil and natural gas production sources in the United States on an annual basis, which include operations on certain of our properties. These requirements could increase the costs of development and production, reducing the profits available to us and potentially impairing our operator’s ability to economically develop our properties. Please read “Business—Regulation” for a description of the laws and regulations that affect the operators of our properties and that may affect us.

Efforts have been made and continue to be made in the international community toward the adoption of international treaties or protocols that would address global climate change issues. For example, in April 2016, the United States was one of 175 countries to sign the Paris Agreement, which requires member countries to review and “represent a progression” in their intended nationally determined contributions, which set GHG emission reduction goals, every five years beginning in 2020. The Paris Agreement entered into force in November 2016. In June 2017, President Trump announced that the United States will withdraw from the Paris Agreement unless it is renegotiated. The State Department informed the United Nations of the United States’ withdrawal in August 2017. Under the terms of the Paris Agreement, the earliest possible effective withdrawal date is November 2020. Similar 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

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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 our unitholders 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;

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

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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 IPO and during the year ended December 31, 2017, record title to the mineral and royalty interests was held by various unrelated entities. At the closing of our IPO and each subsequent acquisition, a significant amount of these mineral and royalty interests were 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. With each acquisition, we expect the risk of payment suspense to be greatest during the immediately succeeding fiscal quarters due to the number of title transfers that will take place.

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 23.5% 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 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;

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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 IPO, 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 IPO 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 services 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, 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 IPO 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.

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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 IPO, 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 IPO.

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 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 IPO, we entered into a management services agreement with Kimbell Operating, which entered into separate services agreements with certain entities controlled by

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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 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 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:

approved by the conflicts committee of the Board of Directors, 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 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 to be fair and reasonable to us, taking into account the totality of the relationships among the parties involved, including other transactions that may be particularly favorable or advantageous to us.

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In connection with a situation involving a transaction with an affiliate or a conflict of interest, any determination by our General Partner or the conflicts committee must be made in good faith. If an affiliate transaction or the resolution of a conflict of interest is not approved by our common unitholders or the conflicts committee and the Board of Directors 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 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 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.

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, 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.

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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 66 2 / ₃ % of all outstanding common units. Affiliates of our General Partner own or control an aggregate of 23.5% 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, 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 “Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities— Cash Distribution Policy and Restrictions on Distributions.”

In connection with the closing of our IPO, we entered into a management services agreement with Kimbell Operating, which entered into separate services 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 services agreements will reduce the amount of cash available for distribution to our unitholders. Please read “Item 13. Certain Relationships and Related Party Transactions, and Director Independence —Agreements and Transactions with Affiliates in Connection with our Initial Public Offering—Management Services Agreements.”

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

Our General Partner may transfer its general partner interest to a third party without the consent of our unitholders. Furthermore, our partnership agreement does not restrict the ability of the owner of our General Partner to transfer its membership interests in our General Partner to a third party. After any such transfer, the new member or members of our General Partner would then be in a position to replace the Board of Directors and executive officers of our General Partner with its own designees and thereby exert significant control over the decisions taken by the Board of Directors and executive officers of our General Partner. This effectively permits a “change of control” without the vote or consent of the unitholders.

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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 IPO, affiliates of our General Partner own or control up to an aggregate of 23.5% of our common units, and our Sponsors will indirectly own and control our General Partner.

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;

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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 IPO, we had 16,332,708 common units outstanding. As of December 31, 2017, we had 16,509,799 common units outstanding. Sales by holders of a substantial number of our common units in the public markets, 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, the Contributing Parties have registration rights.

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 be influenced by many factors, some of which are beyond our control, including:

changes in commodity prices;

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

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

changes in market valuations of similar companies;

departures of key personnel;

commencement of or involvement in litigation;

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

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

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

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

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

the failure of securities analysts to cover our common units 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.”

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We have incurred and will continue to incur increased costs as a result of being a publicly traded partnership.

As a publicly traded partnership, we have and will continue to incur significant legal, accounting and other expenses that we did not incur prior to our IPO. In addition, the Sarbanes‑Oxley Act of 2002 (the “Sarbanes‑Oxley Act”) and the Dodd‑Frank Act of 2010, as well as rules implemented by the SEC and the New York Stock Exchange (“NYSE”), require, or will require, publicly traded entities to maintain various corporate governance practices that 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 Jumpstart Our Business Act (“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 of 1933, as amended (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 choose 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 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.

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 are or will be successful, able to maintain adequate controls over our financial processes and reporting in the future or able to comply with our obligations under Section 404 of the Sarbanes‑Oxley Act. For example, Section 404 requires 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. Any failure to 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 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

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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 “Item 10. Directors, Executive Officers and Corporate Governance.”

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 a unitholder is an ineligible holder, the common units of such unitholder 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 a unitholder is an ineligible holder, in certain circumstances as set forth in our partnership agreement, the units held by such unitholder 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 Internal Revenue Service (“IRS”) were to treat us as a corporation for federal income tax purposes or we were to become subject to entity‑level taxation for state tax purposes, then our cash available for distribution to our unitholders could be substantially reduced.

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

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

If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our taxable income at the corporate tax rate, which is currently 21.0%. Distributions to our unitholders would generally be taxed again as corporate distributions, and no income, gains, losses or deductions would flow through to our unitholders. Because a tax would be imposed upon us as a corporation, our cash available for distribution to our unitholders 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 our unitholders. Therefore, treatment of us as a corporation or the assessment of a material amount of entity‑level taxation would result in a material reduction in the anticipated cash flow and after‑tax return to the unitholders, likely causing a substantial reduction in the value of our common units.

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The recently enacted 20% deduction for certain pass-through income may not be available for our unitholders’ allocable share of our net income, in which case our unitholders’ tax liability with respect to ownership and disposition of our units may be materially higher than if the deduction is available.

Pursuant to the recently enacted tax reform law known as the Tax Cuts and Jobs Act (“TCJA”), for taxable years beginning after December 31, 2017 and ending on or before December 31, 2025, an individual taxpayer may generally claim a deduction in the amount of 20% of its allocable share of certain publicly traded partnership income, including generally, among other items, the net amount of its items of income, gain, deduction, and loss from a publicly traded partnership’s U.S. trade or business. Because we own only passive mineral and royalty interests, we may not be viewed as engaged in a U.S. trade or business within the meaning of the new law. Therefore, most or all of the income that we now generate, or will generate in the future, may not be qualifying publicly traded partnership income eligible for the 20% deduction. Thus, our unitholders may not be able to claim the 20% deduction on any income allocated from us, and any such claim may be successfully challenged by the IRS. We are continuing to evaluate the extent to which we may qualify for the deduction and possible actions to address the issue. If the deduction is not available, our unitholders’ tax liability from ownership and disposition of our units may be materially higher than if the deduction is available. We urge our unitholders to consult with their tax advisors regarding the availability of the 20% deduction on any income allocated from us. The TCJA is complex and far-reaching and we have not completed our analysis of the impact its enactment has on us. There may be other material adverse effects resulting from the TCJA that we have not identified and that could have an adverse effect on our business, results of operations, financial condition and cash flow.

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 IPO 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.

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Our unitholders are required to pay income taxes on their share of our taxable income even if they do not receive any cash distributions from us. A unitholder’s share of our taxable income, and its relationship to any distributions we make, may be affected by a variety of factors, including our economic performance, transactions in which we engage or changes in law and may be substantially different from any estimate we make in connection with a unit offering.

A unitholder’s allocable share of our taxable income will be taxable to it, which may require the unitholder to pay federal income taxes and, in some cases, state and local income taxes, even if the unitholder receives cash distributions from us that are less than the actual tax liability that results from that income or no cash distributions at all.

A unitholder’s share of our taxable income, and its relationship to any distributions we make, may be affected by a variety of factors, including our economic performance, which may be affected by numerous business, economic, regulatory, legislative, competitive and political uncertainties beyond our control, and certain transactions in which we might engage. For example, we may engage in transactions that produce substantial taxable income allocations to some or all of our unitholders without a corresponding increase in cash distributions to our unitholders, such as a sale or exchange of assets, the proceeds of which are reinvested in our business or used to reduce our debt, or an actual or deemed satisfaction of our indebtedness for an amount less than the adjusted issue price of the debt. A unitholder’s ratio of its share of taxable income to the cash received by it may also be affected by changes in law. For instance, under the TCJA, the net interest expense deductions of certain business entities, including us, are limited to 30% of such entity’s “adjusted taxable income,” which is generally taxable income with certain modifications. If the limit applies, a unitholder’s taxable income allocations will be more (or its net loss allocations will be less) than would have been the case absent the limitation.

From time to time, in connection with an offering of our units, we may state an estimate of the ratio of federal taxable income to cash distributions that a purchaser of units in that offering may receive in a given period. These estimates depend in part on factors that are unique to the offering with respect to which the estimate is stated, so the expected ratio applicable to other units will be different, and in many cases less favorable, than these estimates. Moreover, even in the case of units purchased in the offering to which the estimate relates, the estimate may be incorrect, due to the uncertainties described above, challenges by the IRS to tax reporting positions which we adopt, or other factors. The actual ratio of taxable income to cash distributions could be higher or lower than expected, and any differences could be material and could materially affect the value of the common units.

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

If a unitholder sells its common units, it will recognize a gain or loss for U.S. federal income tax purposes equal to the difference between the amount realized and its tax basis in those common units. Because distributions in excess of a unitholder’s allocable share of our net taxable income decreases the unitholder’s tax basis in its common units, the amount, if any, of such prior excess distributions with respect to the units the unitholder sells will, in effect, become taxable income to the unitholder if the unitholder sell such units at a price greater than its tax basis in those units, even if the price the unitholder receives is less than its 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 a unitholder sells its common units, the unitholder may incur a tax liability in excess of the amount of cash the unitholder receives 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. Under the TCJA, an exempt organization will be required to independently compute its UBTI from each separate unrelated trade or business which may prevent an exempt organization from utilizing losses we allocate to the organization against the organization’s UBTI from other sources and vice versa. 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

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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”).

Under the TCJA, if a unitholder sells or otherwise disposes of a common unit, the transferee is required to withhold 10.0% of the amount realized by the transferor unless the transferor certifies that it is not a foreign person, and we are required to deduct and withhold from the transferee amounts that should have been withheld by the transferee but were not withheld. However, the Department of the Treasury and the IRS have determined that this withholding requirement should not apply to any disposition of a publicly traded interest in a publicly traded partnership (such as us) until regulations or other guidance have been issued clarifying the application of this withholding requirement to dispositions of interests in publicly traded partnerships. Accordingly, while this new withholding requirement does not currently apply to interests in us, there can be no assurance that such requirement will not apply in the future.

Unitholders that are a tax-exempt entities or non‑U.S. persons should consult a 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 unitholders. It also could affect the timing of these tax benefits or the amount of gain from unitholders’ sales of common units and could have a negative impact on the value of our common units or result in audit adjustments to unitholders’ 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 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.

In the event the IRS makes an audit adjustment to our income tax returns and we do not or cannot shift the liability to our unitholders in accordance with their interests in us during the year under audit, we will generally have the ability to request that the IRS reduce the determined underpayment by reducing the suspended passive loss carryovers of our

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unitholders (without any compensation from us to such unitholders), to the extent such underpayment is attributable to a net decrease in passive activity losses allocable to certain partners. Such reduction, if approved by the IRS, will be binding on any affected unitholders.

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.

Unitholders will likely be subject to state and local taxes and return filing requirements in states where they do not live as a result of investing in our common units.

In addition to federal income taxes, unitholders 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 they 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. Unitholders may be required to file state and local income tax returns and pay state and local income taxes in these jurisdictions. Further, unitholders 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 the unitholders responsibility to file all U.S. federal, foreign, state and local tax returns.

Item 1B. Unresolved Staff Comments

None.

Item 2. Properties

The information required by Item 2 is contained in Item 1. Business, and incorporated by reference in this Item 2 by reference thereto.

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.”

The range of high and low intraday sales prices for the Partnership’s common units for the periods indicated, as reported by the NYSE, is as follows:


	High		Low		Distributions (1)
2017
First Quarter (from February 3, 2017 through March 31, 2017)	$	20.89	$	18.06	$	0.23
Second Quarter	$	20.00	$	15.65	$	0.30
Third Quarter	$	17.58	$	15.06	$	0.31
Fourth Quarter	$	17.50	$	15.70	$	0.36

(1)

Represents cash distributions attributable to the quarter. Cash distributions declared in respect of a quarter are paid in the following quarter.

As of March 2, 2018, there were 16,836,453 common units outstanding held by 274 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. We adjusted the amount of our distribution for the period from the closing of our IPO 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 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 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 lower 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 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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issuance of equity and debt securities, although the Board of Directors may choose to reserve a portion of cash generated from operations to finance such acquisitions as well.

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 IPO, we borrowed $1.5 million under our secured revolving credit facility to fund certain transaction expenses and we borrowed an additional $29.3 million to fund asset acquisitions made during the year ended December 31, 2017. 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 IPO, which entered into separate services 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

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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.

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, 2017.

Unregistered Sales of Securities.

None.

Repurchases of Equity Securities.

None.

Item 6. Selected Financial Data

SELECTED FINANCIAL DATA

Kimbell Royalty Partners, LP was formed in October 2015. On February 8, 2017, we completed our IPO 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. The mineral and royalty interests making up the Partnership’s initial assets were contributed to the Partnership by the Contributing Parties at the closing of the IPO. As a result, as of December 31, 2016, the Partnership had not yet acquired any of such assets. Unless otherwise indicated, the financial information presented for periods on or after February 8, 2017 refers to the Partnership as a whole. The financial information presented for the periods on or prior to February 7, 2017, is solely that of the Predecessor, Rivercrest Royalties, LLC, and does not include the results of the Partnership as a whole. The mineral and royalty interests underlying the oil, natural gas and NGL production revenues of our Predecessor represented 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.

The following table sets forth, as of the dates and for the periods indicated, our selected financial information, which is derived from our audited consolidated financial statements for the respective periods. The information should be read in conjunction with “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of

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Operations” and our consolidated financial statements and notes thereto contained in “Item 8. Financial Statements and Supplementary Data.”


	Partnership		Predecessor
	Period from February 8, 2017 to December 31,		Period from January 1, 2017 to February 7,		Year Ended December 31,
	2017		2017		2016		2015		2014
Statement of Operations Data:
Revenue
Oil, natural gas and NGL revenues	$	30,665,092	$	318,310	$	3,606,659	$	4,684,923	$	7,219,822
Loss on commodity derivative instruments		(318,829)		—		—		—		—
Total revenues		30,346,263		318,310		3,606,659		4,684,923		7,219,822
Cost and expenses
Production and ad valorem taxes		2,452,058		19,651		280,474		426,885		568,327
Depreciation, depletion and accretion expense		15,546,341		113,639		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
Marketing and other deductions		1,648,895		110,534		750,792		747,264		526,727
General and administrative expenses		8,191,792		532,035		1,746,218		1,789,884		1,757,377
Total costs and expenses		27,839,086		775,859		9,374,589		35,645,929		14,313,980
Operating income (loss)		2,507,177		(457,549)		(5,767,930)		(30,961,006)		(7,094,158)
Other expense
Interest expense		791,437		39,307		424,841		385,119		302,118
Income (loss) before income taxes		1,715,740		(496,856)		(6,192,771)		(31,346,125)		(7,396,276)
State income taxes		—		—		19,848		(32,199)		16,970
Net income (loss)	$	1,715,740	$	(496,856)	$	(6,212,619)	$	(31,313,926)	$	(7,413,246)
Net income (loss) attributable to common units
Basic	$	0.11	$	(0.82)	$	(10.28)	$	(51.83)	$	(12.27)
Diluted	$	0.10	$	(0.82)	$	(10.28)	$	(51.83)	$	(12.27)
Cash distributions declared and paid	$	0.36		*		*		*		*
Statement of Cash Flows Data:
Net cash provided by (used in):
Operating activities	$	18,573,481	$	186,719	$	1,086,603	$	2,713,133	$	4,038,018
Investing activities	$	(125,910,708)	$	(523)	$	(97,464)	$	(538,640)	$	(53,463,030)
Financing activities	$	112,962,722	$	—	$	(863,000)	$	(2,062,818)	$	39,645,738
Other Financial Data:
Adjusted EBITDA (1)	$	19,170,760	$	(293,488)	$	1,434,234	$	2,325,949	$	4,518,656
Selected Balance Sheet Data:
Cash and cash equivalents	$	5,625,495	$	692,077	$	505,880	$	379,741	$	268,066
Total assets	$	295,291,004	$	19,915,596	$	20,538,731	$	27,905,790	$	58,753,888
Long‑term debt	$	30,843,593	$	10,598,860	$	10,598,860	$	11,448,860	$	9,003,860
Total liabilities	$	33,225,570	$	11,431,068	$	11,906,869	$	13,666,368	$	10,556,272
Predecessor members' equity	$	—	$	8,484,528	$	8,631,862	$	14,239,422	$	48,197,616
Partners' capital	$	262,065,434	$	—	$	—	$	—	$	—

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

(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 (as defined below) financial measure by management and external users of our financial statements, such as industry analysts, investors, lenders and rating agencies. We believe

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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) before interest expense, net of capitalized interest, non‑cash unit‑based compensation, unrealized gains and losses on commodity derivative instruments, 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) as determined by the generally accepted accounting principles in the United States (“GAAP”). We exclude the items listed above from net income (loss) in arriving at Adjusted EBITDA because these amounts can vary substantially from company to company within our industry depending upon accounting methods and book values of assets, capital structures and the method by which the assets were acquired. Certain items excluded from Adjusted EBITDA are significant components in understanding and assessing a company’s financial performance, such as a company’s cost of capital and tax structure, as well as historic costs of depreciable assets, none of which are components of Adjusted EBITDA.

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

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


	Partnership		Predecessor
	Period from February 8, 2017 to December 31,		Period from January 1, 2017 to February 7,		Year Ended December 31,
	2017		2017		2016		2015		2014
Net income (loss)	$	1,715,740	$	(496,856)	$	(6,212,619)	$	(31,313,926)	$	(7,413,246)
Depreciation, depletion and accretion expense		15,546,341		113,639		1,604,208		4,008,730		4,044,802
Interest expense		791,437		39,307		424,841		385,119		302,118
State income taxes		—		—		19,848		(32,199)		16,970
EBITDA		18,053,518		(343,910)		(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		798,413		50,422		605,059		605,059		151,265
Loss on commodity derivative instruments		318,829		—		—		—		—
Adjusted EBITDA	$	19,170,760	$	(293,488)	$	1,434,234	$	2,325,949	$	4,518,656
Adjustments to reconcile Adjusted EBITDA to cash available for distribution
Cash interest expense		455,228		34,505		373,513		333,289		247,921
Capital expenditures		—		—		—		—		—
Cash available for distribution	$	18,715,532	$	(327,993)	$	1,060,721	$	1,992,660	$	4,270,735

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	Partnership		Predecessor
	Period from February 8, 2017 to December 31,		Period from January 1, 2017 to February 7,		Year Ended December 31,
	2017		2017		2016		2015		2015
Reconciliation of net cash provided by operating activities to Adjusted EBITDA:
Net cash provided by operating activities	$	18,573,481	$	186,719	$	1,086,603	$	2,713,133	$	4,038,018
Interest expense		791,437		39,307		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		(57,292)		(4,241)		(46,969)		(40,965)		(34,916)
Amortization of tenant improvement allowance		—		2,864		34,369		14,321		—
Unit-based compensation		(798,413)		(50,422)		(605,059)		(605,059)		(151,265)
Loss on commodity derivative instruments		(318,829)		—		—		—		—
Changes in operating assets and liabilities:
Oil, natural gas and NGL revenues receivable		1,689,609		(14,551)		66,455		(464,877)		373,644
Other receivables		236,673		(333,056)		(1,027,172)		1,365,099		(72,742)
Accounts payable		(316,486)		(247,972)		952,800		(1,604,999)		(77,152)
Other current liabilities		(1,746,662)		77,442		(76,541)		(8,683)		(27,284)
EBITDA	$	18,053,518	$	(343,910)	$	(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		798,413		50,422		605,059		605,059		151,265
Loss on commodity derivative instruments		318,829		—		—		—		—
Adjusted EBITDA	$	19,170,760	$	(293,488)	$	1,434,234	$	2,325,949	$	4,518,656

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

The following discussion and analysis is intended to help the reader understand our business, financial condition, results of operations, liquidity and capital resources and 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 IPO of 5,750,000 common units representing limited partner interests, which included 750,000 common units issued pursuant to the underwriters’ option to purchase additional common units. The mineral and royalty interests comprising our initial assets were contributed to us by the Contributing Parties, including certain affiliates of our Sponsors at the time of our IPO. As a result, as of December 31, 2016, we had not yet acquired any of such assets.

Unless otherwise indicated in this “Management’s Discussion and Analysis of Financial Condition and Results of Operations” the financial information presented for periods on or after February 8, 2017 refers to the Partnership as a whole. The financial information presented for periods on or prior to February 7, 2017 refers only to Rivercrest, the predecessor for accounting purposes, and does not include the results of the Partnership as a whole. The interests underlying the oil, natural gas and NGL production revenues of our Predecessor 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.

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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

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 NGLs from the acreage underlying our interests, net of post‑production expenses and taxes. We are not obligated to fund drilling and completion costs, lease operating expenses or plugging and abandonment costs at the end of a well’s productive life. Our primary business objective is to provide increasing cash distributions to unitholders resulting from acquisitions from our Sponsors, the Contributing Parties and third parties and from organic growth through the continued development by working interest owners of the properties in which we own an interest.

As of December 31, 2017, Kimbell Royalty Partners, LP owned mineral and royalty interests in approximately 3.7 million gross acres and overriding royalty interests in approximately 2 million gross acres, with approximately 35% 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, 2017, over 98% 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 50,000 gross producing wells, including over 30,000 wells in the Permian Basin.

Our Predecessor is a Delaware limited liability company formed on October 25, 2013 to own oil, natural gas and NGL mineral and royalty interests in the United States. In addition to mineral and royalty interests, the Predecessor’s assets include overriding royalty interests. The Predecessor also had non-operated working interests in certain oil and natural gas properties. Prior to the Partnership’s IPO, the Predecessor assigned its non-operated working interests and associated asset retirement obligations (“ARO”) to an affiliated entity that was not contributed to the Partnership.

Recent Developments

2017 Acquisitions

In the second quarter of 2017, we acquired mineral and royalty interests underlying 1.1 million gross acres, 6,881 net royalty acres, for an aggregate purchase price of approximately $16.8 million. The Partnership funded these acquisitions with borrowings under its secured revolving credit facility.

On October 9, 2017, we acquired mineral and royalty interests underlying 8,460 gross acres, 983 net royalty acres, for an aggregate purchase price of approximately $3.9 million in Uintah County, Utah. The Partnership funded this acquisition with borrowings under its secured revolving credit facility.

On November 8, 2017, we acquired mineral and royalty interests underlying 71,410 gross acres, 2,757 net royalty acres, for an aggregate purchase price of approximately $7.3 million in various counties in Arkansas. The Partnership funded this acquisition with borrowings under its secured revolving credit facility.

On December 13, 2017, we acquired a diverse package of mineral and overriding royalty interests for an aggregate purchase price of approximately $1.3 million. The core positions are located in California and Wyoming and the package also includes small interests located in Kansas, Arkansas, Texas and Utah. The Partnership funded this acquisition with borrowings under its secured revolving credit facility.

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Commodity Derivative Instruments

On November 14, 2017, we entered into an International Swaps and Derivatives Association, Inc (“ISDA”) Master Agreement (“Master Agreement”) with Frost Bank for oil and natural gas commodity derivatives for the years ended December 31, 2018 and 2019, effective January 1, 2018 and 2019, respectively, with a trade date of December 12, 2017.

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. For the year ended December 31, 2017, WTI ranged from a low of $42.48 per Bbl on June 21, 2017 to a high of $60.46 per Bbl on December 29, 2017, and for the year ended December 31, 2016, WTI ranged from a low of $26.19 per Bbl on February 11, 2016 to a high of $54.01 per Bbl on December 28, 2016. For the year ended December 31, 2017 the Henry Hub spot market price of natural gas ranged from a low of $2.44 per MMBtu on February 27, 2017 to a high of $3.71 per MMBtu on January 2, 2017, and for the year ended December 31, 2016, the Henry Hub spot market price of natural gas has ranged from a low of $1.49 per MMBtu on March 4, 2016 to a high of $3.80 per MMBtu on December 7, 2016. On February 26, 2018, the WTI posted price for crude oil was $63.81 per Bbl and the Henry Hub spot market price of natural gas was $2.60 per MMBtu.

The following table, as reported by the EIA, sets forth the average prices for oil and natural gas.


	For the Year Ended December 31,
EIA Average Price:	2017		2016		2015
Oil (Bbl)	$	50.80	$	43.14	$	48.69
Natural gas (MMBtu)	$	2.99	$	2.52	$	2.63

Source: EIA.

Rig Count

Drilling on our acreage is dependent upon the exploration and production companies that lease our acreage. As such, we monitor rig counts in an effort to identify existing and future leasing and drilling activity on our acreage.

The Baker Hughes U.S. Rotary Rig count was 929 active rigs at December 31, 2017, a greater than 41% increase from 658 active rigs at December 31, 2016. The 658 active rig count at December 31, 2016 declined 6% from 698 active rigs at December 31, 2015. 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 increased 44% from 590 active rigs at December 31, 2016 to 847 active rigs at December 31, 2017. The 590 active rig count at December 31, 2016 declined 6% from 630 active rigs at December 31, 2015. The active rig count across our acreage at December 31, 2017 totaled 19 rigs, a 27% increase compared to the 15 rigs at year-end 2016.

Sources of Our Revenue

Our revenues and our Predecessor’s revenues are derived from royalty payments we receive from our operators based on the sale of oil, natural gas and NGL production, as well as the sale of NGLs that are extracted from natural gas during processing. For the period from February 8, 2017 to December 31, 2017, our revenues were generated 59% from oil sales, 28% from natural gas sales, 11% from NGL sales and 2% from other sales. For the period from January 1, 2017 to February 7, 2017 (the “Predecessor 2017 Period”), our Predecessor’s revenues were generated 55% from oil sales, 36% from natural gas sales and 9% from NGL sales. For the combined year ended December 31, 2017, the revenues were generated 59% from oil sales, 28% from natural gas sales, 11% from NGL sales and 2% from other sales. 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 NGL sales. For the year ended December 31, 2015, our Predecessor’s revenues were generated 63% from oil

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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.

In the fourth quarter of 2017, we entered into oil and natural gas commodity derivative agreements with Frost Bank for the years ended December 31, 2018 and 2019, effective January 1, 2018 and 2019, respectively. Our Predecessor did not enter into hedging arrangements to establish, in advance, a price for the sale of the oil, natural gas and NGLs produced from our mineral and royalty interests. As a result, our Predecessor may have realized the benefit of any short‑term increase in the price of oil, natural gas and NGLs, but was not protected against decreases in price, and if the price of oil, natural gas and NGLs decreased significantly, our Predecessor’s business, results of operations and cash available for distribution may have been materially adversely effected.

Reserves and Pricing

The table below identifies our and our Predecessor’s proved reserves at December 31, 2017, 2016 and 2015, in each case based on the reserve report prepared by Ryder Scott. The prices used to estimate proved reserves for the respective 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.


	Partnership	Predecessor
	December 31,	December 31,
Estimated Net Proved Reserves:	2017	2016	2015
Oil (MBbls)	7,463	886	958
Natural gas (MMcf)	63,916	7,140	7,166
Natural gas liquids (MBbls)	2,838	235	207
Total (MBoe)(6:1)	20,954	2,311	2,359


	Partnership		Predecessor
	December 31,		December 31,
Unweighted Arithmetic Average First‑Day‑of‑the‑Month Prices	2017		2016		2015
Oil (Bbls)	$	51.34	$	42.75	$	50.28
Natural gas (Mcf)	$	2.98	$	2.49	$	2.59

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 financial condition and results of operations, for the reasons described below:

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

The historical financial statements of our Predecessor included in this Annual Report do not reflect the financial condition or results of operations of the Partnership. Further, these historical financial statements do not give effect to the transactions that were completed in connection with the closing of the Partnership’s IPO. In connection with our IPO, our Predecessor assigned all of its non‑operating working interests to an affiliate that was not contributed to us, and all of the membership interests of our Predecessor were contributed to us in exchange for common units and a portion of the net proceeds from the IPO. In addition, the Contributing Parties directly or indirectly contributed to us the other assets that made up our initial assets in exchange for common units and a portion of the net proceeds from the IPO. The combination of the assets contributed to us by the Contributing Parties was accounted for at fair value as an asset acquisition. The fair value of the purchase price consideration was based upon the fair value of the common units purchased in the Partnership’s IPO by third-party investors.

The historical financial data of our Predecessor included in this “Management’s Discussion and Analysis of Financial Condition and Results of Operations” does not include the results of the Partnership as a whole and may not provide an accurate indication of what our actual results would have been if the transactions completed in connection with

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our IPO had been completed at the beginning of the periods presented or of what our future results of operations are likely to be. The mineral and royalty interests of our Predecessor only represented approximately 11% of our 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

No impairment expense was recorded for the period from February 8, 2017 to December 31, 2017. The substantial majority of our proved oil and natural gas properties that were acquired at the time of the IPO were recorded at fair value as of the IPO. In accordance with SEC guidance, management determined that the fair value of the properties acquired at the closing of the IPO clearly exceeded the related full-cost ceiling limitation beyond a reasonable doubt and received an exemption from the SEC to exclude the properties acquired at the closing of the IPO from the ceiling test calculation. This exemption was effective beginning with the period ended March 31, 2017 and remained effective through December 31, 2017. A component of the exemption received from the SEC is that we were required to assess the fair value of these acquired assets at each reporting period through the term of the exemption to ensure that the inclusion of these acquired assets in the full-cost ceiling test would not be appropriate. As of December 31, 2017, management determined that the exemption to exclude these acquired assets from the full-cost ceiling test was appropriate. In making this determination, management considered that the value was based on a transaction conducted in a public offering and that the common units issued by the Partnership as consideration for the properties were attributed the same value as those purchased in the Partnership’s IPO by third-party investors. Additionally, the fair value of the properties acquired at the closing of our IPO was based on forward strip oil and natural gas pricing existing at the date of the IPO and management affirmed that there has not been a material decline to the fair value of these acquired assets since the IPO. The properties acquired at the closing of our IPO have an unamortized cost at December 31, 2017 of $237.2 million. Had management not affirmed the lack of material change to the fair value, the impairment charge recorded would have been $64.3 million as of December 31, 2017. The Partnership will recognize an impairment in the first quarter of 2018 after the exemption has expired, which could materially adversely affect our results of operations for the periods in which such charges are taken.

No impairment expense was recorded for the Predecessor 2017 Period. During the years ended December 31, 2016 and 2015, our Predecessor recorded a non-cash impairment charge of $5.0 million and $28.7 million, respectively, primarily due to changes in reserve values resulting from the decline 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.

Credit Agreements

In connection with our IPO, 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. As of December 31, 2017, we had borrowed $30.8 million to fund certain IPO-related transaction expenses, our entrance into a management services agreement with Kimbell Operating and the acquisition of mineral and royalty interests for an aggregate purchase price of approximately $29.3 million. For the period from February 8, 2017 to December 31, 2017, we incurred $0.8 million in interest expense.

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In January 2014, our Predecessor entered into a credit agreement with Frost Bank, as lender. For the Predecessor 2017 Period our Predecessor’s interest expense was de minimis and for the years ended December 31, 2016 and 2015 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 IPO.

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 IPO, we entered into a management services agreement with Kimbell Operating, which entered into separate services 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 services 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 services agreements will reduce the amount of cash available for distribution to our unitholders.

Non‑Operated Working Interest Assignment

Prior to the transactions that were completed in connection with the IPO, our Predecessor assigned its non‑operated working interests and associated asset retirement obligations to an affiliated entity that was not contributed to the Partnership. As of the closing of its IPO and through the date of this Annual Report, the Partnership does not own any working interests and does 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 NGLs based on a percentage of revenues from products sold at fixed rates established by federal, state or local taxing authorities. Where available, we benefit from tax credits and exemptions in our various taxing jurisdictions. We are also subject to ad valorem taxes in the counties where our production is located. Ad valorem taxes are jurisdictional taxes levied on the value of oil, natural gas and NGLs minerals and reserves. Rates, methods of calculating property values, and timing of payments vary between taxing authorities.

Depreciation and Depletion

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

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General and Administrative Expense

General and administrative expenses are costs not directly associated with the production of oil, natural gas and NGLs and include the cost of executives and employees and related benefits, office expenses and fees for professional services. In connection with our IPO, we entered into a management services agreement with Kimbell Operating, which entered into separate services 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 services agreements, affiliates of our Sponsors will identify, evaluate and recommend to us acquisition opportunities and negotiate the terms of such acquisitions.

We anticipated incurring incremental general and administrative expenses of approximately $1.5 million 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.

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 0.75% 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.

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Results of Operations

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


	Partnership		Predecessor		Predecessor
	Period from February 8, 2017 to December 31,		Period from January 1, 2017 to February 7,		Year Ended December 31,
	2017		2017		2016		2015
Operating Results:
Revenue
Oil, natural gas and NGL revenues	$	30,665,092	$	318,310	$	3,606,659	$	4,684,923
Loss on commodity derivative instruments		(318,829)		—		—		—
Total revenues		30,346,263		318,310		3,606,659		4,684,923
Costs and expenses
Production and ad valorem taxes		2,452,058		19,651		280,474		426,885
Depreciation, depletion and accretion expense		15,546,341		113,639		1,604,208		4,008,730
Impairment of oil and natural gas properties		—		—		4,992,897		28,673,166
Marketing and other deductions		1,648,895		110,534		750,792		747,264
General and administrative expenses		8,191,792		532,035		1,746,218		1,789,884
Total costs and expenses		27,839,086		775,859		9,374,589		35,645,929
Operating income (loss)		2,507,177		(457,549)		(5,767,930)		(30,961,006)
Other expense
Interest expense		791,437		39,307		424,841		385,119
Income (loss) before income taxes		1,715,740		(496,856)		(6,192,771)		(31,346,125)
State income taxes		—		—		19,848		(32,199)
Net income (loss)	$	1,715,740	$	(496,856)	$	(6,212,619)	$	(31,313,926)
Production Data:
Oil (Bbls)		379,182		3,696		55,587		59,321
Natural gas (Mcf)		3,184,861		32,961		496,778		548,386
Natural gas liquids (Bbls)		157,177		1,220		22,360		22,351
Combined volumes (Boe) (6:1)		1,067,169		10,410		160,743		173,070

Comparison of the Year Ended December 31, 2017 to the Year Ended December 31, 2016 and the Year Ended December 31, 2016 to the Year Ended December 31, 2015

The period presented for the year ended December 31, 2017 includes the results of operations of our Predecessor for the Predecessor 2017 Period and our results of operations for the period from February 8, 2017 to December 31, 2017.

Oil, Natural Gas and Natural Gas Liquids Revenues

For the period from February 8, 2017 to December 31, 2017 and the Predecessor 2017 Period, our and our Predecessor’s oil, natural gas and NGL revenues were $30.7 million and $0.3 million, respectively, for combined revenues of $31.0 million for the year ended December 31, 2017, an increase of $27.4 million, from $3.6 million for the year ended December 31, 2016. The increase in revenues was primarily due to the $247.8 million acquisition of various mineral and royalty interests from the Contributing Parties at the closing of our IPO, the $29.3 million acquisition of various mineral and royalty interests throughout the 2017 period and the relevant production and revenues from those acquired interests.

Our Predecessor’s revenues for the year ended December 31, 2016 decreased by $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 12,327 Boe when compared to production for the year ended December 31, 2015.

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Our and our Predecessor’s revenues are a function of oil, natural gas, and NGL production volumes sold and average prices received for those volumes. The production volumes were 1,067,169 Boe or 3,264 Boe/d and 10,410 Boe or 274 Boe/d, for the period from February 8, 2017 to December 31, 2017 and the Predecessor 2017 Period, respectively. The combined production for the year ended December 31, 2017 was 1,077,579 Boe or 2,952 Boe/d, an increase of 916,836 Boe or 2,512 Boe/d, from 160,743 Boe or 440 Boe/d, for year ended December 31, 2016.

Our Predecessor’s volumes for the year ended December 31, 2016 decreased by 12,326 or 34 Boe/d from 173,070 or 474 Boe/d 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 NGLs experienced through most of 2016.

Our operators received an average of $47.08 per Bbl of oil, $2.74 per Mcf of natural gas and $21.50 per Bbl of NGL for the volumes sold during the period from February 8, 2017 to December 31, 2017. Our Predecessor’s operators received an average of $47.04 per Bbl of oil, $3.47 per Mcf of natural gas and $24.61 per Bbl of NGL for the volumes sold during the Predecessor 2017 Period. For the combined year ended December 31, 2017, the operators received an average of $47.08 per Bbl of oil, $2.74 per Mcf of natural gas and $21.52 per Bbl of NGL for the volumes sold. Average prices received by the operators during the combined year ended December 31, 2017 increased 21.7% or $8.39 per Bbl of oil and 24.0% or $0.53 per Mcf of natural gas as compared to our Predecessor’s operators which received an average of $38.69 per Bbl of oil, $2.21 per Mcf of natural gas and $15.99 per Bbl of NGL for the volumes sold during the year ended December 31, 2016 These increases are consistent with prices experienced in the market, specifically when compared to the EIA average price increases of 17.8% or $7.66 per Bbl of oil and 18.7% or $0.47 per Mcf of natural gas for the comparable periods.

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 NGL for the volumes sold during the year ended December 31, 2015. Average prices received by the Predecessor’s operators during the year ended December 31, 2016 decreased 22.2% or $11.10 per Bbl of oil and 9.4% or $0.23 per Mcf of natural gas as compared to the year ended December 31, 2015.

Production and Ad Valorem Taxes

Our production and ad valorem taxes for the period from February 8, 2017 to December 31, 2017 and the Predecessor 2017 Period were $2.5 million and $0.02 million, respectively. The combined production and ad valorem taxes for the year ended December 31, 2017 were $2.5 million, an increase of $2.2 million from $0.3 million for year ended December 31, 2016. The increase in production and ad valorem taxes was attributable to the $247.8 million acquisition of various mineral and royalty interests from the Contributing Parties at the closing of our IPO, the $29.3 million acquisition of various mineral and royalty interests throughout the 2017 period and the relevant production and revenues from those acquired interests.

For the year ended December 31, 2016, our Predecessor’s production and ad valorem taxes decreased by $0.1 million, from $0.4 million 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 prices.

Depreciation, Depletion and Accretion Expense

Our and our Predecessor’s depreciation, depletion and accretion expense for the period from February 8, 2017 to December 31, 2017 and the Predecessor 2017 Period was $15.5 million and $0.1 million, respectively, for a combined expense of $15.6 million for the year ended December 31, 2017. This was an increase of $14.0 million from our Predecessor’s depreciation, depletion and accretion expense of $1.6 million for the year ended December 31, 2016. The increase in the depreciation, depletion and accretion expense was primarily attributable to the $247.8 million acquisition of various mineral and royalty interests from the Contributing Parties at the closing of our IPO, the $29.3 million acquisition of various mineral and royalty interests throughout the 2017 period and the relevant production from those acquired properties.

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Our Predecessor’s depreciation, depletion and accretion expense decreased by $2.4 million for the year ended December 31, 2016 from $4.0 million for the year ended December 31, 2015.

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 and our Predecessor’s average depletion rate per barrel was $14.43 and $10.31 for the period from February 8, 2017 to December 31, 2017 and the Predecessor 2017 Period, respectively. The combined average depletion rate per barrel for the year ended December 31, 2017 was $14.39, an increase of $4.53 per barrel from an average depletion rate of $9.86 per barrel for the year ended December 31, 2016. The increase in the average depletion rate per barrel was primarily attributable to the $247.8 million acquisition of various mineral and royalty interests from the Contributing Parties at the closing of our IPO, the $29.3 million acquisition of various mineral and royalty interests throughout the 2017 period and the relevant production from those acquired properties.

For the year ended December 31, 2016, our Predecessor’s average depletion rate per barrel decreased by $13.30 from $23.16 for the year ended December 31, 2015. 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 NGL properties for the year ended December 31, 2016.

Impairment of Oil, Natural Gas and Natural Gas Liquids Expense

No impairment expense was recorded for the period from February 8, 2017 to December 31, 2017. See “Factors Affecting the Comparability of Our Results to the Historical Results of Our Predecessor―Impairment of Oil and Natural Gas Properties” for a discussion regarding the exemption of impairment of oil and natural gas properties for the Partnership for the period from February 8, 2017 to December 31, 2017. The Partnership will recognize an impairment in the first quarter of 2018 after the exemption has expired.

Impairments for our Predecessor totaled $5.0 million and $28.7 million for the years ended December 31, 2016 and 2015, respectively, primarily due to the impact that declines in commodity prices had on the value of reserve estimates.

Marketing and Other Deductions

Our marketing and other deductions include product marketing expense, which is a post‑production expense, and our Predecessor’s marketing and other deductions also include lease operating expenses related to its non‑operated working interests. Marketing and other deductions for the period from February 8, 2017 to December 31, 2017 and the Predecessor 2017 Period were $1.6 million and $0.1 million, respectively. The combined marketing and other deductions for the year ended December 31, 2017 were $1.7 million, an increase of $0.9 million from our Predecessor’s marketing and other deductions for the year ended December 31, 2016 of $0.8 million. The increase in marketing and other deductions was attributable the $247.8 million acquisition of various mineral and royalty interests from the Contributing Parties at the closing of our IPO, the $29.3 million acquisition of various mineral and royalty interests throughout the 2017 period and the relevant production and revenues from those acquired interests.

Our Predecessor’s marketing and other deductions for the year ended December 31, 2016 increased by $0.1 million from $0.7 million for the year ended December 31, 2015.

General and Administrative Expense

Our and our Predecessor’s general and administrative expenses for the period from February 8, 2017 to December 31, 2017 and the Predecessor 2017 Period were $8.2 million and $0.5 million, respectively. General and administrative expenses for the combined year ended December 31, 2017 were $8.7 million, an increase of $7.0 million from our Predecessor’s general and administrative expenses of $1.7 million for year ended December 31, 2016. The increase in general and administrative expenses was attributable to the increased costs related to operating the Partnership as a publicly traded entity.

Our Predecessor’s general and administrative expenses for the year ended December 31, 2016 decreased by $0.1 million from $1.8 million for the year ended December 31, 2015. Decreases in general and administrative expenses

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were attributable to the decrease in costs related to the offering of the Partnership from the year ended December 31, 2015 to the year ended December 31, 2016.

Interest Expense

Our and our Predecessor’s interest expense for the period from February 8, 2017 to December 31, 2017 and the Predecessor 2017 Period was $0.8 million and $0.04 million, respectively. The interest expense for the combined year ended December 31, 2017 was $0.8 million as compared to our Predecessor’s interest expense of $0.4 million for the year ended December 31, 2016.

Our Predecessor’s interest expense remained relatively flat at $0.4 million for the years ended December 31, 2016 and 2015.

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, acquisitions and certain IPO-related transaction expenses. In connection with the February 1, 2018 redetermination under the secured revolving credit facility, the borrowing base was reaffirmed at $100.0 million. Aggregate commitments remain at $50.0 million, providing for maximum availability under the secured revolving credit facility of $50.0 million. As of March 2, 2017, we had an outstanding balance of $30.8 million under our secured revolving credit facility.

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 following the end of such quarter. We expect that available cash for each quarter will generally equal or approximate 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 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.

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 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 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 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,

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(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 NGL, changes to working capital or capital expenditures and (iii) cash reserves deemed appropriate by the Board of Directors. 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 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.

On May 2, 2017, the Board of Directors declared a quarterly cash distribution of $0.23 per common unit for the period ended March 31, 2017. The Partnership’s calculated cash available for distribution was $0.18 per common unit for the quarter. However, during the period ended March 31, 2017, pursuant to the contribution agreement entered into by the Contributing Parties prior to the IPO, the Partnership received cash from the Contributing Parties for oil, natural gas and NGL production for periods prior to the IPO. The Board of Directors voted to distribute an additional $0.05 per common unit. The distribution was paid on May 15, 2017 to unitholders of record as of the close of business on May 8, 2017. The amount of the first quarter 2017 distribution was adjusted for the period from the date of the closing of the Partnership’s IPO through March 31, 2017.

On July 28, 2017, the Board of Directors declared a quarterly cash distribution of $0.30 per common unit for the quarter ended June 30, 2017. The Partnership’s calculated cash available for distribution was $0.28 per common unit for the quarter. The Board of Directors voted to distribute an additional $0.02 per common unit due to excess working capital generated primarily from positive prior period production from our operators. The distribution was paid on August 14, 2017 to unitholders of record as of the close of business on August 7, 2017.

On October 27, 2017, the Board of Directors declared a quarterly cash distribution of $0.31 per common unit for the quarter ended September 30, 2017. The distribution was paid on November 13, 2017 to unitholders of record as of the close of business on November 6, 2017.

On January 26, 2018, the Board of Directors declared a quarterly cash distribution of $0.36 per common unit for the quarter ended December 31, 2017. The distribution was paid on February 14, 2018 to unitholders of record as of the close of business on February 7, 2018.

Cash Flows

The following table presents our and our Predecessor’s cash flows for the periods indicated.


	Partnership		Predecessor		Predecessor
	Period from February 8, 2017 to December 31,		Period from January 1, 2017 to February 7,		Year Ended December 31,
	2017		2017		2016		2015
Cash Flow Data:
Cash flows provided by operating activities	$	18,573,481	$	186,719	$	1,086,603	$	2,713,133
Cash flows used in investing activities		(125,910,708)		(523)		(97,464)		(538,640)
Cash flows provided by (used in) financing activities		112,962,722		—		(863,000)		(2,062,818)
Net increase in cash	$	5,625,495	$	186,196	$	126,139	$	111,675

Operating Activities

Our and our Predecessor’s operating cash flow is impacted by many variables, the most significant of which is the change in prices for oil, natural gas and NGLs. Prices for these commodities are determined primarily by prevailing market conditions. Regional and worldwide economic activity, weather and other substantially variable factors influence market conditions for these products. These factors are beyond our and our Predecessor’s control and are difficult to predict. Cash flows provided by operating activities for the period from February 8, 2017 to December 31, 2017 and the Predecessor 2017 Period were $18.6 million and $0.2 million, respectively. Cash flows provided by operating activities for the combined year ended December 31, 2017 were $18.8 million, an increase of $17.7 million compared to our Predecessor’s cash flows provided by operating activities of $1.1 million for the year ended December 31, 2016. The

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increase was largely attributable to the $247.8 million acquisition of various mineral and royalty interests from the Contributing Parties at the closing of our IPO, the $29.3 million acquisition of various mineral and royalty interests throughout the 2017 period and the relevant production and revenues from those acquired interests.

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 NGL sales prices.

Investing Activities

Cash flows used in investing activities for the period from February 8, 2017 to December 31, 2017 were $125.9 million, an increase of $125.8 million compared to our Predecessor’s cash flows used in investing activities for the year ended December 31, 2016 of $0.1 million. Our Predecessor’s cash flows used in investing activities were de minimis for the Predecessor 2017 Period. For the period from February 8, 2017 to December 31, 2017, we used the $96.2 million in proceeds received from our IPO to pay the cash portion of our acquisition of oil and natural gas properties at the IPO and we used $29.3 million to fund the acquisition of various mineral and royalty interests. 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.

Financing Activities

Cash flows provided by financing activities was $113.0 million for the period from February 8, 2017 December 31, 2017 as compared to our Predecessor’s cash used in financing activities of $0.9 million for the year ended December 31, 2016. Our Predecessor did not have any cash flows used in or provided by financing activities for the Predecessor 2017 Period. During the period from February 8, 2017 to December 31, 2017, we received $96.2 million in proceeds from our IPO, we borrowed $30.8 million, paid a distribution to unitholders of $13.8 million and paid loan origination costs of $0.3 million.

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, for the year ended December 31, 2015.

Capital Expenditures

During the period from February 8, 2017 to December 31, 2017, we acquired mineral and royalty interests from the Contributing Parties for common units with a total value at the IPO of $169.1 million and $96.2 million in cash. Additionally, we spent an aggregate amount of $29.3 million for the acquisition of various mineral and royalty interests.

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.

Indebtedness

Revolving Credit Agreement

We entered into a $50.0 million revolving credit facility in connection with our IPO, 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 re-determined semiannually on February 1 and August 1 of each year based

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on the value of our oil and natural gas properties and the oil and natural gas properties of our wholly owned subsidiaries and will mature on February 8, 2022. 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. In connection with the February 1, 2018 redetermination under the secured revolving credit facility, the borrowing base was reaffirmed at $100.0 million. Aggregate commitments remain at $50.0 million providing for maximum availability under the revolving credit facility of $50.0 million.

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 2, 2018, we have borrowed $30.8 million to fund certain IPO-related transaction expenses, our entrance into a management services agreement with Kimbell Operating Company, LLC and the acquisition of various mineral and royalty interests for an aggregate purchase price of approximately $29.3 million.

Contractual Obligations and Off-Balance Sheet Arrangements

As of December 31, 2017, neither we nor our Predecessor had any off-balance sheet arrangements other than operating leases. The following table summarizes the contractual obligations of the Partnership as of December 31, 2017:


			Less than						More than 5
	Total		1 year		1‑3 years		3‑5 years		years
Long-term debt	$	30,843,593	$	-	$	-	$	30,843,593	$	-
Operating leases		429,220		127,506		221,306		80,408		-
Total	$	31,272,813		127,506	$	221,306	$	30,924,001	$	-

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 the 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 and our Predecessor’s financial statements included elsewhere in this Annual Report for additional information regarding these accounting policies.

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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, valuation of commodity derivative financial instruments and equity‑based compensation.

Method of Accounting for Oil and Natural Gas Properties

We account for oil, natural gas and NGL 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 NGL 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 NGL properties are accounted for as adjustments to capitalized costs, with no gain or loss recorded unless the ratio of cost to proved reserves would significantly change.

Depletion of evaluated oil, natural gas and NGL 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 NGL 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 NGL 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 NGL reserves. Oil, natural gas and NGL reserve engineering is a subjective process of estimating underground accumulations of oil, natural gas and NGLs 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

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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 NGLs that are ultimately recovered.

Revenue Recognition

Mineral and royalty interests represent the right to receive revenues from the sale of oil, natural gas and NGLs, less production and ad valorem taxes and post‑production expenses. The pricing of oil, natural gas and NGLs 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 NGLs 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 NGL revenues from our mineral and royalty interests are recognized when the associated product is sold.

Derivatives and Financial Instruments

Our ongoing operations expose us to changes in the market price for oil and natural gas. To mitigate the given commodity price risk associated with its operations, the Partnership entered into oil and natural gas derivative contracts. Entrance into such contracts is dependent upon prevailing or anticipated market conditions. From time to time, such contracts may include fixed-price contracts, variable to fixed price swaps, costless collars, and other contractual arrangements. The impact of these derivative instruments could affect the amount of revenue we ultimately record.

Derivative instruments are recognized at fair value. If a right of offset exists under master netting arrangements and certain other criteria are met, derivative assets and liabilities with the same counterparty are netted on the consolidated balance sheet. Gains and losses arising from changes in the fair value of derivatives are recognized on a net basis in the accompanying consolidated statements of operations within gain (loss) on commodity derivative instruments. We have not designated any of our derivative contracts as hedges for accounting purposes. Although these derivative instruments may expose us to credit risk, we monitor the creditworthiness of our counterparties.

Impairment

The net capitalized costs of proved oil, natural gas and NGL 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 NGL properties less production taxes, ad valorem taxes and gas marketing expenses. To the extent capitalized costs of evaluated oil, natural gas and properties, net of accumulated depreciation, depletion, amortization, impairment and deferred income taxes exceed the discounted future net revenues of proved oil, natural gas and NGL 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 NGL 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 fair value of our restricted units issued under the Kimbell Royalty GP, LLC 2017 Long-Term Incentive Plan (“LTIP”) to our employees and directors is determined by utilizing the market value of our common units on the respective grant date. The restricted units issued to non-employee consultants will utilize current market value of our common units for the awards and apply mark-to-market accounting until vesting occurs. The LTIP and related accounting policies are defined and described more fully in Note 9—Unit-Based Compensation in our audited consolidation financial statements included elsewhere in this Annual Report.

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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.

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 NGL production of our operators. Realized pricing is primarily driven by the prevailing worldwide price for crude oil and spot market prices applicable to our natural gas production. Pricing for oil, natural gas and NGL production has been volatile and unpredictable for several years, and we expect this volatility to continue in the future. The prices that our operators receive for production depend on many factors outside of our or their control. To reduce the impact of fluctuations in oil and natural gas prices on our revenues, we entered into commodity derivative contracts to reduce our exposure to price volatility of oil and natural gas. The counterparty to the contracts is an unrelated third party.

At December 31, 2017 , our commodity derivative contracts consisted of fixed price swaps, under which the Partnership receives a fixed price for the contract and pays a floating market price to the counterparty over a specified period for a contracted volume.

Our oil fixed price swap transactions are settled based upon the average daily prices for the calendar month of the contract period, and our natural gas fixed price swap transactions are settled based upon the last day settlement of the first nearby month futures contract of the contract period. Settlement for oil derivative contracts occurs in the succeeding month and natural gas derivative contracts are settled in the production month.

Because we have not designated any of our derivative contracts as hedges for accounting purposes, changes in fair values of our derivative contracts will be recognized as gains and losses in current period earnings. As a result, our current period earnings may be significantly affected by changes in the fair value of our commodity derivative contracts. Changes in fair value are principally measured based on future prices as of period-end compared to the contract price. See Note 4—Derivatives to the consolidated financial statements in Item 8 of this report for additional information regarding the Partnership’s commodity derivatives.

Counterparty and Customer Credit Risk

Our derivative contracts expose us to credit risk in the event of nonperformance by counterparties. While we do not require our counterparties to our derivative contracts to post collateral, we do evaluate the credit standing of such counterparties as we deem appropriate. This evaluation includes reviewing a counterparty’s credit rating and latest financial information. As of December 31, 2017, we had one counterparty, which is also the lender under our credit facility.

As an owner of mineral and royalty interests, we have no control over the volumes or method of sale of oil, natural gas and NGLs produced and sold from the underlying properties. During the period from February 8, 2017 to December 31, 2017, one purchaser accounted for approximately 14% of our oil, natural gas and NGL revenues. During the year ended December 31, 2016, three purchasers accounted for approximately 20%, 13% and 10% of our Predecessor’s oil, natural gas and NGL revenues. It is believed that the loss of any single purchaser would not have a material adverse effect on our results of operations.

Interest Rate Risk

We will have exposure to changes in interest rates on our indebtedness. As of December 31, 2017, we had total borrowings outstanding under our secured revolving credit facility of $30.8 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 $0.3 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 Partnership’s consolidated financial statements required by this item are included in this report beginning 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, 2017.

Management’s Report on Internal Control Over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal control over financial reporting. Our internal control over financial reporting is a process designed under the supervision of our principal executive officer and principal financial officer to provide reasonable assurance regarding the reliability of financial reporting and the preparation of our financial statements for external purposes in accordance with generally accepted accounting principles

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

As of December 31, 2017, our management assessed the effectiveness of our internal control over financial reporting based on the criteria for effective internal control over financial reporting established by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”) in Internal Control—Integrated Framework (2013). Management’s assessment included an evaluation of the design of our internal control over financial reporting and testing of the operational effectiveness of our internal control over financial reporting. Based on this assessment, management has concluded that, as of December 31, 2017, the Partnership’s internal control over financial reporting is effective based on those criteria.

Attestation Report of the Registered Public Accounting Firm

This Annual Report does not include an attestation report of our independent registered public accounting firm due to rules of the SEC. 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.

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Changes in Internal Control over Financial Reporting

There were no changes in our internal control over financial reporting during the quarter ended December 31, 2017 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Item 9B. Other Information

Amendment to the Duncan Services Agreement

On March 7, 2018, Kimbell Operating Kimbell Operating entered into Amendment No. 1 (the “Duncan Amendment”) to the services agreement with Duncan Management, LLC (“Duncan Management”). The services agreement with Duncan management contemplates that the monthly services fee thereunder is subject to annual redetermination and adjustment and that Kimbell Operating and Duncan Management will renegotiate the monthly services fee in good faith. The Duncan Amendment amends the services agreement with Duncan Management to reflect the result of such renegotiation, which is a downward adjustment to the services fee from $54,872 per month to $43,498 per month. All other material terms and conditions of the services agreement with Duncan Management were unchanged.

Amendment to the K3 Royalties Services Agreement

On March 7, 2018, Kimbell Operating, entered into Amendment No. 1 (the “K3 Amendment”) to the services agreement with K3 Royalties, LLC (“K3 Royalties”). The K3 Amendment amends the services agreement with K3 Royalties to authorize K3 Royalties to provide additional services, including assistance with business development and relationship management between past and future sellers of mineral assets and the Partnership and assistance with current and future relations with the Kimbell Art Foundation. All other material terms and conditions of the services agreement with K3 Royalties were unchanged.

Amendment to the Nail Bay Royalties Services Agreement

On March 7, 2018, Kimbell Operating entered into Amendment No. 1 (the “Nail Bay Amendment”) to the services agreement with Nail Bay Royalties, LLC (“Nail Bay Royalties”). The services agreement with Nail Bay Royalties contemplates that the monthly services fee thereunder is subject to annual redetermination and adjustment and that Kimbell Operating and Nail Bay Royalties will renegotiate the monthly services fee in good faith. The Nail Bay Amendment amends the services agreement with Nail Bay Royalties to reflect the result of such renegotiation, which is a downward adjustment to the services fee from $41,961 per month to $29,736 per month. All other material terms and conditions of the services agreement with Nail Bay Royalties were unchanged.

Amendment to the Steward Royalties Services Agreement

On March 7, 2018, Kimbell Operating entered into Amendment No. 1 (the “Steward Amendment”) to the services agreement with Steward Royalties, LLC (“Steward Royalties”). The services agreement with Steward Royalties contemplates that the monthly services fee thereunder is subject to annual redetermination and adjustment and that Kimbell Operating and Steward will renegotiate the monthly services fee in good faith. The Steward Amendment amends the services agreement with Steward Royalties to reflect the result of such renegotiation, which is an upward adjustment to the services fee from $10,417 per month to $10,833 per month. All other material terms and conditions of the services agreement with Steward Royalties were unchanged.

Amendment to the Taylor Companies Services Agreement

On March 7, 2018, Kimbell Operating entered into Amendment No. 1 (the “Taylor Amendment”) to the services agreement with Taylor Companies Mineral Management, LLC (“Taylor Companies”). The services agreement with Taylor Companies contemplates that the monthly services fee thereunder is subject to annual redetermination and adjustment and that Kimbell Operating and Taylor Companies will renegotiate the monthly services fee in good faith. The Taylor Amendment amends the services agreement with Taylor Companies to reflect the result of such renegotiation, which is an

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upward adjustment to the services fee from $33,333 per month to $43,905 per month. All other material terms and conditions of the services agreement with Taylor Companies were unchanged.

The foregoing descriptions are not complete and are qualified in their entirety by reference to the full text of the amendments, which are filed as exhibits to this Annual Report on Form 10-K and incorporated herein by reference.

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 as of December 31, 2017. 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	Position With Our General Partner
Robert D. Ravnaas	60	Chief Executive Officer and Chairman of the Board of Directors
R. Davis Ravnaas	32	President and Chief Financial Officer
Matthew S. Daly	45	Chief Operating Officer
Jeff McInnis	41	Chief Accounting Officer
Brett G. Taylor	57	Executive Vice Chairman of the Board of Directors
Benny D. Duncan	75	Director
Ben J. Fortson	85	Director
T. Scott Martin	67	Director
Mitch S. Wynne	59	Director
William H. Adams III	59	Independent Director
C.O. Ted Collins, Jr.	79	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 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 from 2014 until December 2017, and as President and director of Rivercrest Royalties, LLC from 2013 until our IPO, 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 from October 2015 until our IPO. 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.

Matthew S. Daly. Matthew S. Daly was appointed Chief Operating Officer of our General Partner in May 2017. Mr. Daly has served as Senior Vice President—Corporate Development of our General Partner since September 2016.

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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.

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 from May 2015 until our IPO. 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.

Brett G. Taylor. Brett G. Taylor was appointed as Executive Vice Chairman of the Board of Directors 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

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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.

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. passed away on January 27, 2018. Mr. Collins was an independent director and a member of the audit committee of our General Partner. We have begun a search for a third independent director to serve on the Board of Directors and the audit committee of our General Partner.

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 IPOs, secondary offerings and public debt transactions. In February 2017, Mr. Stone accepted a ministry 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.

Board Leadership Structure

Robert D. Ravnaas currently serves as the Chief Executive Officer and Chairman of the Board of Directors. The Board of Directors 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 are appointed

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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 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. Our corporate governance guidelines are available on our website at http://www.kimbellrp.com under “Investor Relations—Corporate Governance.”

Committees of the Board of Directors

The Board of Directors has an audit committee and a conflicts and compensation committee. 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 IPO. 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 available on our website at http://www.kimbellrp.com under “Investor Relations—Corporate Governance.”

Conflicts and Compensation Committee

In accordance with the terms of our partnership agreement, at least two members of the Board of Directors 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 and awards, if any, under our long‑term incentive plan. Our conflicts and compensation committee charter is available on our website at http://www.kimbellrp.com under “Investor Relations—Corporate Governance.”

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. Based solely on a review of the copies of such reports furnished to us and written representations that no other reports were required, we believe that during the period from February 8, 2017 to December 31, 2017 all our directors and executive officers complied on a timely basis with all applicable filing requirements under Section 16(a) of

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the Exchange Act, except that a Form 4 was filed late by Messrs. Duncan and Martin to report transactions on November 29, 2017. On February 14, 2018, Mr. Duncan reported his receipt of common units through a distribution on a Form 4 and Mr. Martin reported his disposition of common units on a Form 5.

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.

Item 11. Executive Compensation and Other Information

Compensation Discussion and Analysis

We are providing compensation disclosure that satisfies the requirements applicable to emerging growth companies, as defined in the JOBS Act. 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 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. The compensation for all our executive officers is indirectly paid by us pursuant to the management services agreement with Kimbell Operating as described in Item 13. Certain Relationships and Related Transactions, and Director Independence — Management Services Agreements.

We and our General Partner were formed in October 2015, and we did not complete our IPO, 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 years ended December 31, 2016 and 2015. Accordingly, we are not presenting any compensation for historical periods prior to the year ended December 31, 2017.

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The table below provides information concerning the annual compensation of our named executive officers (our “Named Executive Officers” or “NEOs”) for the year ended December 31, 2017. As an emerging growth company, our NEOs include the Chief Executive Officer and our other two most highly compensated officers.


			Short Term				Other
Name and Principal Position	Salary (1)		Incentive Bonus		Unit Awards (2)		Compensation (3)		Total
Robert D. Ravnaas	$	275,562	$	125,000	$	423,765	$	123,809	$	948,136
(Chairman and Chief Executive Officer)
R. Davis Ravnaas	$	253,355	$	120,000	$	423,765	$	13,809	$	810,929
(President and Chief Financial Officer)
Matthew S. Daly	$	159,359	$	75,000	$	53,502	$	1,743	$	289,604
(Chief Operating Officer)

(1)

Each of Messrs. Robert D. Ravnaas, R. Davis Ravnaas and Matthew S. Daly began to receive compensation from our general partner following the consummation of our IPO on February 8, 2017. Therefore, the amounts shown for the year ended December 31, 2017 represent the salary earned by each NEO for his partial year of service.

(2)

Amounts for 2017 reflect the grant date fair value of our common units, computed based on the average of the opening and closing price on the grant date at $18.72 per common unit.

(3)

Amounts reflect (i) for Mr. Robert D. Ravnaas: include $110,000 as part of the service agreement with Steward Royalties and Partnership distributions received from the awarded LTIP units of $13,809; (ii) for Mr. R. Davis Ravnaas: Partnership distributions received from the awarded LTIP units of $13,809; and (iii) for Mr. Daly: Partnership distributions received from the awarded LTIP units of $1,743.

For the year ended December 31, 2017, the principal elements of compensation provided to our NEOs were base salaries, short-term incentive bonuses (“STI Bonuses”) and LTIP awards.

Base Salary

Base salaries are generally set at levels deemed necessary to attract and retain individuals with superior talent commensurate with their relative expertise and experience.

Short-Term Incentive Bonuses

The STI Bonuses provide our NEOs with an incentive in the form of an annual cash bonus to achieve our overall qualitative business goals. For the 2017 fiscal year, Messrs. Robert D. Ravnaas, R. Davis Ravnaas and Matthew S. Daly had an annual target bonus amount of $125,000, $120,000 and $75,000, respectively. The actual amount of Messrs. Robert D. Ravnaas’, R. Davis Ravnaas’ and Matthew Daly’s annual bonuses are determined by the Conflicts and Compensation Committee in its sole discretion and may be higher or lower than their target amounts. The amounts of Messrs. Robert D. Ravnaas, R. Davis Ravnaas and Matthew S. Daly’s bonuses for fiscal year 2017 are set forth under the “Bonus” column in the table below.

The bonuses for each of Messrs. Robert D. Ravnaas, R. Davis Ravnaas and Matthew S. Daly were based on their target bonus, qualitative performance and other discretionary factors, including achievement of strategic objectives, goals in compliance and ethics and teamwork within the Partnership. A variety of qualitative factors that vary by year and are given different weights in different years depending on facts and circumstances were considered, with no single factor being determinative to the overall bonus decision. The factors considered by the Conflicts and Compensation Committee in connection with Messrs. Robert D. Ravnaas’, R. Davis Ravnaas’ and Matthew S. Daly’s fiscal year 2017 bonuses are discussed in more detail below.

In making the bonus determinations for Messrs. Robert D. Ravnaas, R. Davis Ravnaas and Matthew S. Daly, other qualitative factors taken into account included performance in internal and public financial reporting, budgeting and forecasting processes, compliance and infrastructure and investment and cost-savings initiatives. Non-financial factors considered also included, among other items, providing strategic leadership and direction for the Partnership, including corporate governance matters, managing the strategic direction of the Partnership, increasing operational efficiency, expanding our asset base and communicating to investors and other important constituencies.

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For fiscal year 2017, after considering the factors described above and management’s recommendations, the Conflicts and Compensation Committee determined that the bonuses for Messrs. Robert D. Ravnaas, R. Davis Ravnaas and Matthew S. Daly would be set at amounts equal to 100% of their annual target bonus amounts. This is reflected in the Conflicts and Compensation Committee’s and management’s assessment that overall corporate performance and discretionary factors justified payment of such bonus to each of them based on their and the Partnership’s performance during the fiscal year. Specifically, the Conflicts and Compensation Committee set the amount of Mr. Robert D. Ravnaas’ bonus after considering the quality of his individual performance in managing the overall operations and resources of the Partnership, Mr. R. Davis Ravnaas’ bonus after considering the quality of his individual performance in running the partnership-wide finance function and the amount of Mr. Matthew S. Daly’s bonus after considering the quality of his individual performance in running the ongoing business operations as well as the performance of the Partnership.

Long-Term Incentive Awards

The Board granted awards under the LTIP t o our NEOs on May 12, 2017, consisting of 48,132 restricted common units. Each award is subject to the terms and conditions of the award agreement that we entered into with the applicable NEO. The restricted common units vest in one-third installments on each of the first three anniversaries of the grant date, subject to the grantee’s continuous service through each applicable vesting date. Upon a grantee’s termination of service for any reason other than death or disability, all unvested restricted units will be immediately forfeited as of the date of termination. In the case of termination resulting from death or disability, all unvested restricted units will become fully vested as of the date of termination.

The following table reflects information regarding outstanding unvested common units held by our NEOs as of December 31, 2017.


	Unit Awards
	Number of Restricted	Market Value of Restricted
	Common Units that	Common Units that
Name	have not vested (1)	have not vested (2)
Robert D. Ravnaas	22,637	$	367,851
(Chairman and Chief Executive Officer)
R. Davis Ravnaas	22,637	$	367,851
(President and Chief Financial Officer)
Matthew S. Daly	2,858	$	46,443
(Chief Operating Officer)

(1)

The NEO’s outstanding restricted common units will vest in accordance with the schedule set forth above under “Long-Term Incentive Awards” so long as the NEO remains employed by the Partnership or one of its affiliates through such dates.

(2)

Reflects the market value of our common units computed based on the closing price, $16.25, of our common units on December 29, 2017, the last NYSE market trading day of the year ended December 31, 2017.

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

Additional Narrative Disclosure

Health, Welfare and Additional Benefits

Our NEOs are eligible to participate in the employee benefit plans and programs that the Partnership offers to its employees, subject to the terms and eligibility requirements of those plans.

Retirement Benefits

We have not maintained, and do not currently maintain, a defined benefit pension plan, a nonqualified deferred compensation plan or a 401(k)-plan providing for retirement benefits.

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Long‑Term Incentive Plan

In order to incentivize our management and directors to continue to grow our business, the Board of Directors adopted a 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 IPO to provide maximum flexibility with respect to the design of compensatory arrangements for individuals providing services to us. We filed a registration statement on Form S‑8 on May 12, 2017 for shares issued pursuant to the LTIP.

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 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 Board of Directors appointed the Conflicts and Compensation committee to administer the LTIP, which we refer to 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 number 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 individual becomes a non‑employee director).

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.

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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.

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.

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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

Notwithstanding the foregoing, if the Participant remains in Continuous Service as of the date of a Change in Control, any unvested restricted common units will be vested as of the date of such Change in Control. For this purpose, “Change in Control” means, and shall be deemed to have occurred upon the occurrence of one or more of the following events: (i) any “person” or “group” within the meaning of those terms as used in Sections 13(d) and 14(d)(2) of the Exchange Act, other than Kimbell GP Holdings, LLC or their respective Affiliates, shall become the beneficial owner, by way of merger, consolidation, recapitalization, reorganization or otherwise, of 50% or more of the combined voting power of the equity interests in the Partnership; (ii) the limited partners of the Partnership approve, in one or a series of transactions, a plan of complete liquidation of the Partnership; (iii) the sale or other disposition by either the Partnership of all or substantially all of its assets in one or more transactions to any Person other than the Partnership or an Affiliate of the Partnership; or (iv) a transaction resulting in a Person other than the Partnership or an Affiliate of the Partnership being the general partner of the Partnership.

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 IPO or own any of the mineral and royalty assets that make up our initial assets, until February 2017. As such, neither we nor our General Partner accrued or paid any obligations with respect to compensation for directors of our General Partner during the years ended December 31, 2016 and 2015.

Officers or employees of the Partnership who also serve as directors of our general partner will not receive additional compensation for such service. Each director of our general partner who is not employed by Kimbell Operating or engaged by Kimbell Operating through a Master Service Agreement (a “non-employee director”) receives the following cash compensation:

An annual base retainer fee of $60,000 per year;

an additional retainer of $15,000 per year if such director serves as the chairperson of the Audit Committee; and

an additional retainer of $15,000 per year if such director serves as the chairperson of the Conflicts and Compensation Committee

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In addition to cash compensation, our non-employee directors receive annual equity-based compensation under the LTIP. Each non-employee director was granted 1,904 fully vested common units on August 14, 2017. Each such award has an aggregate grant date value equal to $30,000. Future annual equity-based compensation under the LTIP will be granted to our non-employee directors, vesting ratably over three years from the respective grant dates.

All retainers are paid in cash on a quarterly basis in arrears. Our non-employee directors do not receive any meeting fees, but each director is reimbursed for travel and miscellaneous expenses to attend meetings and activities of the Board or its committees.

The following table provides information concerning the compensation of our non-employee directors for the fiscal year ended December 31, 2017.


						All Other
Name	Fees Earned		Unit Awards		Compensation		Total
Brett G. Taylor (1)	$	-	$	423,765	$	366,667	$	790,432
Benny D. Duncan (2)	$	-	$	29,988	$	1,065,167	$	1,095,155
Ben J. Fortson (3)	$	-	$	423,765	$	-	$	423,765
T. Scott Martin (4)	$	40,000	$	29,988	$	-	$	69,988
Mitch S. Wynne (5)	$	-	$	423,765	$	110,000	$	533,765
William H. Adams III (6)	$	47,500	$	29,988	$	-	$	77,488
C.O. Ted Collins, Jr. (4)	$	40,000	$	29,988	$	-	$	69,988
Craig Stone (6)	$	52,500	$	29,988	$	-	$	82,488

(1)

Mr. Taylor’s Unit Awards reflect the grant date fair value of our common units, computed based on the average of the opening and closing price on the grant date at $18.72 per common unit. Mr. Taylor’s All Other Compensation consists of the payments in the amount of $366,667 made to Taylor Companies as described in Item 13. Certain Relationships and Related Transactions, and Director Independence-Management Services Agreements .

(2)

Mr. Duncan’s Unit Awards reflect the grant date fair value of our common units, computed based on the average of the opening and closing price on the grant date at $15.75 per common unit. Mr. Duncan’s All Other Compensation consists of the payments in the amount of $603,591 and $461,576 made to Duncan Management Company and Nail Bay Royalties, respectively, as described in Item 13. Certain Relationships and Related Transactions, and Director Independence-Management Services Agreements .

(3)

Mr. Fortson’s Unit Awards reflect the grant date fair value of our common units, computed based on the average of the opening and closing price on the grant date at $18.72 per common unit.

(4)

Mr. Martin’s and Mr. Collins’ Paid in Cash amounts include the annual cash retainer fee for each non-employee director during fiscal 2017, as more fully explained above. Unit Awards reflect the grant date fair value of our common units, computed based on the average of the opening and closing price on the grant date at $15.75 per common unit.

(5)

Mr. Wynne’s Unit Awards reflect the grant date fair value of our common units, computed based on the average of the opening and closing price on the grant date at $18.72 per common unit. Mr. Wynne’s All Other Compensation consists of the payments in the amount of $110,000 made to K3 Royalties as described in Item 13. Certain Relationships and Related Transactions, and Director Independence-Management Services Agreements .

(6)

Mr. Adams’ and Mr. Stone’s Paid in Cash amounts include the annual cash retainer fee and committee chair fees for each non-employee director and during fiscal 2017, as more fully explained above. Unit Awards reflect the grant date fair value of our common units, computed based on the average of the opening and closing price on the grant date at $15.75 per common unit.

Compensation Committee Interlocks and Insider Participation

The Conflicts and Compensation Committee members includes the following members: Mr. William H. Adams III, as Chairman, and Mr. Craig Stone.

None of our officers or employees will be members of the Compensation Committee. None of our executive officers serve on the board of directors or compensation committee of a company that has an executive officer that serves on our Board or Compensation Committee. No member of our Board is an executive officer of a company in which one of our executive officers serves as a member of the board of directors or compensation committee of that company.

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Conflicts and Compensation Committee Report

The Conflicts and Compensation Committee has reviewed and discussed with management the Compensation Discussion and Analysis. Based on the review and discussions, the Conflicts and Compensation Committee recommends to the Board of Directors that the Compensation Discussion and Analysis be included in this Form 10-K.

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 as of January 31, 2018 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.


		Percentage of
	Common Units	Common Units
	Beneficially	Beneficially
Name of Beneficial Owner	Owned	Owned
Kimbell Art Foundation (1)	2,953,258	17.5	%
Fidelity Management and Research Company (2)	958,900	5.7	%
Yorktown X Associates, LLC (3)	925,634	5.5	%
Robert D. Ravnaas (4)	186,639	1.1	%
R. Davis Ravnaas (5)	61,116	*	%
Matthew S. Daly	11,829	*	%
Jeff McInnis	15,510	*	%
Brett G. Taylor (6)	214,566	1.3	%
Benny D. Duncan (7)	294,825	1.8	%
Ben J. Fortson (8)	3,049,768	18.1	%
T. Scott Martin	13,087	*	%
Mitch S. Wynne (9)	110,669	*	%
William H. Adams III	12,654	*	%
C.O. Ted Collins, Jr.	22,570	*	%
Craig Stone	6,382	*	%
All directors and executive officers as a group (12 persons)	3,999,615	23.8	%

* 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 2,953,258 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 245 Summer Street, 14 th Floor, Boston, Massachusetts, 02210.

(3)

The address for this beneficial owner 410 Park Avenue, 19 th Floor, New York, New York, 10022.

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(4)

Robert D. Ravnaas is a partner or member in certain entities that directly or indirectly hold, in the aggregate, approximately 598,951 common units. Mr. R. Ravnaas has sole voting and investment power with respect to 84,417 common units. Mr. R. Ravnaas does not have voting or investment power with the respect to the other common units held by such entities. Mr. R. Ravnaas’ pecuniary interest in such entities is an aggregate of approximately 153,630 common units, 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.

(5)

R. Davis Ravnaas is a partner or member in certain entities that hold, in the aggregate, approximately 92,627 common units. 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 21,787 common units, 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.

(6)

Brett G. Taylor is the sole trustee of and may be deemed to have voting and investment power over the 80,092 common units owned by Brett G. Taylor Royalty Trust. Mr. Taylor is the Sole Member of and may be deemed to have voting and investment power over the 37,999 common units owned by BGT Minerals, LLC. Mr. 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. In addition, Mr. Taylor is a partner or member in an entity that holds, in the aggregate, approximately 16,326 additional common units. Mr. Taylor does not have voting or investment power with respect to such entity. Mr. Taylor’s pecuniary interest in such entity is an aggregate of approximately 1,143 additional common units and Mr. Taylor disclaims beneficial ownership of the common units that may be deemed to be owned by such entity except to the extent of his pecuniary interest therein.

(7)

Mr. Duncan directly owns 111,039 common units. Mr. Duncan’s minor children own 2,894 common units over which Mr. Duncan may be deemed to have voting and investment power. Mr. Duncan is the Sole Manager of and may be deemed to have voting and investment power over the 1,837 common units that may be deemed to be owned by GSEF, LLC. Mr. Duncan is the Sole Manager of and may be deemed to have voting and investment power over the 168 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 3,769 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 654 common units that may be deemed to be owned by, Gorda Sound, LLC. Mr. Duncan is the Sole Manager of, and may be deemed to have voting and investment power over the 7,604 common units that may be deemed to be owned by, Oil Nut Bay, LLC. Mr. Duncan is the Sole Manager of and may be deemed to have voting and investment power over the 9,913 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 160,677 common units owned by, Trunk Bay Royalty Partners, Ltd. Each of Bitter End, 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 individual except to the extent of their pecuniary interest therein.

(8)

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 2,953,258 common units owned by the Kimbell Art Foundation. Mr. Fortson is the trustee of and may be deemed to have voting and investment power over the 17,341 common units owned by Mattie K. Carter Trust. Mr. Fortson and is the trustee of and may be deemed to have voting and investment power over the 14,440 common units owned by certain trusts for which he serves as the trustee. 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 all such common units except to the extent of his pecuniary interest therein.

(9)

Mitch S. Wynne is the trustee of and may be deemed to have voting and investment power over the 27,539 common units owned by MSW Investment Trust. Mr. Wynne is the trustee of and may be deemed to have voting and investment power over the 2,000 common units owned by David Mitchell Wynne Asset Trust. Mr. Wynne is the co-trustee of and may be deemed to have voting and investment power over the 11,916 common units owned by certain niece’s and nephew’s trusts. Mr. Wynne disclaims beneficial ownership of all such common units except to the extent of his pecuniary interest therein.

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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.

Equity Compensation Plan Information

In connection with the consummation of our IPO on February 3, 2017, the Board of Directors adopted the Kimbell Royalty Partners, LP Long Term Incentive Plan. The following table provides certain information with respect to this plan as of December 31, 2017:


	Number of
	Securities to be	Weighted	Number of Securities
	Issued Upon	-Average	Remaining Available for
	Exercise of	Exercise Price	Future Issuance Under
	Outstanding	of Outstanding	Equity Compensation
	Options,	Options,	Plans (Excluding
	Warrants	Warrants and	Securities Reflected in
	and Rights(1)	Rights	Column(a))
	(a)	(b)	(c)
Equity compensation plans approved by unitholders	167,571	16.250	1,874,029
Equity compensation plans not approved by unitholders	—	—	—
Total	167,571	16.250	1,874,029

(1)

The long-term incentive plan currently permits the grant of awards covering an aggregate of 2,041,600 units of which, 167,571 restricted and common units have been granted.

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

Agreements and Transactions with Affiliates in Connection with Initial Public Offering

In connection with our IPO, 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. Available cash generally means:

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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);

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 66 2 / ₃ % of the members of the Board of Directors, 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.

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Contribution Agreement

In connection with our IPO, 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 IPO, 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 IPO;

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 IPO. 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 IPO, 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

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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 IPO 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 IPO.

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 IPO. 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 IPO, 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 services 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 “—Services Agreements with Our Sponsors” and “—Other Services Agreements,” except that neither party to the agreement may terminate unless all of the services agreements with the Sponsor Managers and the Non‑Sponsor Managers have terminated. During 2017, we paid 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 services agreements with the Sponsor Managers and the Non‑Sponsor Managers.

Services Agreements with Our Sponsors

Services. In connection with the closing of our IPO, Kimbell Operating entered into services agreements with BJF Royalties, LLC (“BJF Royalties”), Steward Royalties, Taylor Companies and K3 Royalties (collectively, 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:

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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, 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 with our sponsors, past and future sellers of mineral assets and the Kimbell Art Foundation.

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 services agreements with the Sponsor Managers, Kimbell Operating paid to Steward Royalties, Taylor Companies and K3 Royalties a monthly services fee of approximately $10,417, $33,333 and $10,000, respectively, for the period from February 8, 2017 to December 31, 2017. The services agreements were amended on March 7, 2018 to provide that Kimbell Operating will pay to Steward Royalties and Taylor Companies a monthly services fee of approximately $10,833 and $43,905, respectively, for the period from January 1, 2018 to December 31, 2018. K3 Royalties will continue to receive a monthly services fee of $10,000 for the period from January 1, 2018 to December 31, 2018. These 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, 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 services 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 services 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 IPO, the applicable Sponsor Manager may terminate its services agreement, or the provision of any service thereunder, upon at least 180 days’ notice to Kimbell Operating.

The applicable Sponsor Manager may terminate its services 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 services 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 services

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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 services 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 services agreement is the termination of the applicable agreement as described in the third bullet point above.

Indemnification. Under the services 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 services 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 services agreement. The Sponsor Managers do not have corresponding indemnification obligations with respect to Kimbell Operating.

Other Services Agreements

Management Services. In connection with the closing of our IPO, Kimbell Operating entered into services agreements with Nail Bay Royalties and Duncan Management (collectively, 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 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 services agreements with the Non‑Sponsor Managers, Kimbell Operating paid to Nail Bay Royalties and Duncan Management a monthly services fee of approximately $41,960 and $54,870, respectively, for the year period from February 8, 2017 to December 31, 2017. The services agreements were amended on March 7, 2018, to provide that Kimbell Operating will pay to Nail Bay Royalties and Duncan Management a monthly services fee of approximately $29,736 and $43,500, respectively, for the period from January 1, 2018 to December 31, 2018. These 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, 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 services 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 services 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 IPO, the applicable Non‑Sponsor Manager may terminate its services 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 services agreement upon a default by Kimbell Operating, which includes (i) Kimbell Operating’s failure to perform any of its material obligations under

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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 services 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 services 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 services 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 services agreement is the termination of the applicable agreement as described in the third bullet point above.

Indemnification. Under the services 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 applicable services 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 services 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 IPO, 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 served as President of Cawley, Gillespie & Associates, Inc. from 2011 until February 2017. Cawley, Gillespie & Associates, Inc. performed certain petroleum engineering services for the benefit of the Partnership. Compensation for such services totaled $123,393, $618,989 and $785,594 for the Predecessor 2017 Period and years ended December 31, 2016 and 2015, respectively. Mr. R. Ravnaas indirectly received a percentage of Cawley, Gillespie & Associates, Inc.’s revenues through his participation in the company’s employee bonus pool. In the aggregate, he received approximately $246,000 attributable to fees paid by the Partnership for the years ended December 31, 2016 and 2015.

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 approximately $320,000.

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

The Board of Directors 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 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.

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

Director Independence

Our Board of Directors has determined that William H. Adams III 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 audit committee’s charter requires the audit committee to approve in advance all audit and non-audit services to be provided by Grant Thornton LLP. All services reported in the audit, audit-related, tax and all other fees categories below with respect to our annual reports for the years ended December 31, 2017 and 2016 were approved by the audit committee. The following table sets forth audit and non-audit fees we have paid to Grant Thornton LLP for the periods indicated (in thousands).


	Partnership		Predecessor
	Period from February 8, 2017 to December 31,		Period from January 1, 2017 to February 7,		Year Ended December 31,
	2017		2017		2016
Audit Fees (1)	$	294,775	$	98,050	$	737,684
Audit-Related Fees (2)		37,100		—		—
Tax Fees (3)		—		—		—
All Other Fees (4)		—		—		—
Total	$	331,875	$	98,050	$	737,684

(1) Audit fees relate to professional services rendered in connection with the audit of our Annual Report, quarterly review of our Quarterly Reports, 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.

(a)(3) List of Exhibits

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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 3.3 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 †	—	Form of Kimbell Royalty GP, LLC 2017 Long-Term Incentive Plan Restricted Unit Agreement (incorporated by reference to Exhibit 10.1 to Kimbell Royalty Partners, LP’s Form 8-K filed on May 11, 2017)
10.3 †	—	Form of Kimbell Royalty GP, LLC 2017 Long-Term Incentive Plan Director Unit Agreement (incorporated by reference to Exhibit 10.2 to Kimbell Royalty Partners, LP’s Form 10-Q filed on August 14, 2017)
10.4* †	—	Form of Kimbell Royalty GP, LLC 2017 Long-Term Incentive Plan 2018 Restricted Unit Agreement
10.5	—	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)
10.6 †	—	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)
10.7 †	—	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)
10.8 †	—	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)
10.9* †	—	Amendment No. 1 to Management Services Agreement, dated March 7, 2018, by and between Duncan Management, LLC and Kimbell Operating Company, LLC
10.10 †	—	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)
10.11* †	—	Amendment No. 1 to Management Services Agreement, dated March 7, 2018, by and between K3 Royalties, LLC and Kimbell Operating Company, LLC
10.12 †	—	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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10.13* †	—	Amendment No. 1 to Management Services Agreement, dated March 7, 2017, by and between Nail Bay Royalties, LLC and Kimbell Operating Company, LLC
10.14 †	—	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)
10.15* †	—	Amendment No. 1 to Management Services Agreement, dated March 7, 2018, by and between Steward Royalties , LLC and Kimbell Operating Company, LLC
10.16 †	—	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)
10.17* †	—	Amendment No. 1 to Management Services Agreement, dated March 7, 2018, by and between Taylor Companies Mineral Management, LLC and Kimbell Operating Company, LLC
21.1*	—	List of Subsidiaries of Kimbell Royalty Partners, LP
23.1*	—	Consent of Grant Thornton LLP
23.2*	—	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, 2017
101.INS**	—	XBRL Instance Document
101.SCH**	—	XBRL Taxonomy Extension Schema Document
101.CAL**	—	XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF**	—	XBRL Taxonomy Extension Definition Linkbase Document
101.LAB**	—	XBRL Taxonomy Extension Label Linkbase Document
101.PRE**	—	XBRL Taxonomy Extension Presentation Linkbase Document

* —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).

Item 16. Form 10-K Summary

The Partnership has elected not to include summary information.

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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 9, 2018	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 9, 2018

/s/ R. Davis Ravnaas
R. Davis Ravnaas	President and Chief Financial Officer (Principal
	Financial Officer)	March 9, 2018

/s/ Jeff McInnis	Chief Accounting Officer
Jeff McInnis	(Principal Accounting Officer)	March 9, 2018

/s/ William H. Adams III
William H. Adams III	Director	March 9, 2018

/s/ Benny D. Duncan
Benny D. Duncan	Director	March 9, 2018

/s/ Ben J. Fortson
Ben J. Fortson	Director	March 9, 2018

/s/ T. Scott Martin
T. Scott Martin	Director	March 9, 2018

/s/ Craig Stone
Craig Stone	Director	March 9, 2018

/s/ Brett G. Taylor
Brett G. Taylor	Director	March 9, 2018

/s/ Mitch S. Wynne
Mitch S. Wynne	Director	March 9, 2018

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INDEX TO FINANCIAL STATEMENTS


Report of Independent Registered Public Accounting Firm	F- 2

Consolidated Balance Sheets at December 31, 2017 and 2016	F- 3

Consolidated Statements of Operations for the Period from February 8, 2017 through December 31, 2017, the Period from January 1, 2017 through February 7, 2017 and the Years Ended December 31, 2016 and 2015	F- 4

Consolidated Statements of Changes in Partners’ Capital for the Period from February 8, 2017 through December 31, 2017 and Members’ Equity for the Period from January 1, 2017 through February 7, 2017 and the Years Ended December 31, 2016 and 2015	F- 5

Consolidated Statements of Cash Flows for the Period from February 8, 2017 through December 31, 2017, the Period from January 1, 2017 through February 7, 2017 and the Years Ended December 31, 2016 and 2015	F- 6

Notes to Consolidated Financial Statements	F- 7

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Board of Directors and Unitholders

Kimbell Royalty Partners, LP

Opinion on the financial statements

We have audited the accompanying consolidated balance sheets of Kimbell Royalty Partners, LP (a Delaware limited partnership) and subsidiaries (the “Partnership”) as of December 31, 2017 and December 31, 2016, the related consolidated statements of operations, changes in partners’ capital and predecessor members’ equity, and cash flows for the period from February 8, 2017 to December 31, 2017 (Partnership), January 1, 2017 to February 7, 2017 (Predecessor), and the years ended December 31, 2016 and December 31, 2015 (Predecessor), and the related notes (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Partnership as of December 31, 2017 and December 31, 2016, and the results of its operations and its cash flows for the period from February 8, 2017 to December 31, 2017 (Partnership), January 1, 2017 to February 7, 2017 (Predecessor), and the years ended December 31, 2016 and December 31, 2015 (Predecessor), in conformity with accounting principles generally accepted in the United States of America.

Basis for opinion

These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on the Partnership’s financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (“PCAOB”) and are required to be independent with respect to the Partnership in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Partnership is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Partnership’s internal control over financial reporting. Accordingly, we express no such opinion.

Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

/s/ GRANT THORNTON LLP

We have served as the Partnership’s auditor since 2015.

Dallas, Texas

March 9, 2018

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KIMBELL ROYALTY PARTNERS, LP

CONSOLIDATED BALANCE SHEETS


	Partnership		Predecessor
	December 31,		December 31,
	2017		2016
ASSETS
Current assets
Cash and cash equivalents	$	5,625,495	$	505,880
Oil, natural gas and NGL receivables		6,792,837		474,103
Accounts receivable and other current assets		236,673		344,368
Total current assets		12,655,005		1,324,351
Property and equipment, net		165,232		261,568
Oil and natural gas properties
Oil and natural gas properties, using full cost method of accounting		297,609,797		70,888,121
Less: accumulated depreciation, depletion, accretion and impairment		(15,394,238)		(51,948,355)
Total oil and natural gas properties		282,215,559		18,939,766
Loan origination costs, net		255,208		13,046
Total assets	$	295,291,004	$	20,538,731

LIABILITIES AND PARTNERS' CAPITAL (PREDECESSOR MEMBERS' EQUITY)
Current liabilities
Accounts payable	$	316,486	$	1,030,862
Other current liabilities		1,746,662		112,508
Commodity derivative liabilities		183,957		—
Asset retirement obligations		—		27,013
Total current liabilities		2,247,105		1,170,383
Asset retirement obligations		—		14,468
Other liabilities		—		123,158
Long-term debt		30,843,593		10,598,860
Commodity derivative liabilities		134,872		—
Total liabilities		33,225,570		11,906,869
Commitments and contingencies
Predecessor members' equity		—		8,631,862
Partners' capital		262,065,434		—
Total liabilities and partners' capital (predecessor members' equity)	$	295,291,004	$	20,538,731

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

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KIMBELL ROYALTY PARTNERS, LP

CONSOLIDATED STATEMENTS OF OPERATIONS


	Partnership		Predecessor
	Period from February 8, 2017 to December 31,		Period from January 1, 2017 to February 7,		Year Ended December 31,
	2017		2017		2016		2015
Revenue
Oil, natural gas and NGL revenues	$	30,665,092	$	318,310	$	3,606,659	$	4,684,923
Loss on commodity derivative instruments		(318,829)		—		—		—
Total revenues		30,346,263		318,310		3,606,659		4,684,923
Costs and expenses
Production and ad valorem taxes		2,452,058		19,651		280,474		426,885
Depreciation, depletion and accretion expense		15,546,341		113,639		1,604,208		4,008,730
Impairment of oil and natural gas properties		—		—		4,992,897		28,673,166
Marketing and other deductions		1,648,895		110,534		750,792		747,264
General and administrative expense		8,191,792		532,035		1,746,218		1,789,884
Total costs and expenses		27,839,086		775,859		9,374,589		35,645,929
Operating income (loss)		2,507,177		(457,549)		(5,767,930)		(30,961,006)
Other expense
Interest expense		791,437		39,307		424,841		385,119
Income (loss) before income taxes		1,715,740		(496,856)		(6,192,771)		(31,346,125)
State income taxes		—		—		19,848		(32,199)
Net income (loss)	$	1,715,740	$	(496,856)	$	(6,212,619)	$	(31,313,926)

Net income (loss) attributable to common units
Basic	$	0.11	$	(0.82)	$	(10.28)	$	(51.83)
Diluted	$	0.10	$	(0.82)	$	(10.28)	$	(51.83)
Weighted average number of common units outstanding
Basic		16,336,871		604,137		604,137		604,137
Diluted		16,455,602		604,137		604,137		604,137

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

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KIMBELL ROYALTY PARTNERS, LP

CONSOLIDATED STATEMENTS OF CHANGES IN PARTNERS’ CAPITAL AND PREDECESSOR MEMBERS’ EQUITY


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

Distribution to members		—		(3,249,327)

Unit-based compensation		—		605,059

Net income		—		(31,313,926)

Members' equity - December 31, 2015 - Predecessor		604,137		14,239,422

Unit-based compensation		—		605,059

Net income		—		(6,212,619)

Members' equity - December 31, 2016 - Predecessor		604,137		8,631,862

Unit-based compensation		—		50,422

Net loss		—		(496,856)

Transfer of membership units to Rivercrest Royalties Holdings, LLC		(604,137)		(98,988)


Partners' capital - February 8, 2017 - Partnership		—		8,086,440

Common units issued to Predecessor in exchange for oil and natural gas properties		1,191,974		—

Common units issued to contributors in exchange for oil and natural gas properties		9,390,734		169,033,212

Common units sold to public		5,750,000		103,500,000

Underwriting discount and structuring fee incurred at initial public offering		—		(7,245,000)

Distributions to unitholders		—		(13,823,371)

Unit-based compensation		177,091		798,413

Net income		—		1,715,740

Partners' capital - December 31, 2017 - Partnership		16,509,799	$	262,065,434

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

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KIMBELL ROYALTY PARTNERS, LP

CONSOLIDATED STATEMENTS OF CASH FLOWS


	Partnership		Predecessor
	Period from February 8, 2017 to December 31,		Period from January 1, 2017 to February 7,		Year Ended December 31,
	2017		2017		2016		2015
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss)	$	1,715,740	$	(496,856)	$	(6,212,619)	$	(31,313,926)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and accretion expense		15,546,341		113,639		1,604,208		4,008,730
Impairment of oil and natural gas properties		—		—		4,992,897		28,673,166
Amortization of loan origination costs		57,292		4,241		46,969		40,965
Amortization of tenant improvement allowance		—		(2,864)		(34,369)		(14,321)
Unit-based compensation		798,413		50,422		605,059		605,059
Loss on commodity derivative instruments		318,829		—		—		—
Changes in operating assets and liabilities:
Oil, natural gas and NGL receivables		(1,689,609)		14,551		(66,455)		464,877
Accounts receivable and other current assets		(236,673)		333,056		1,027,172		(1,365,099)
Accounts payable		316,486		247,972		(952,800)		1,604,999
Other current liabilities		1,746,662		(77,442)		76,541		8,683
Net cash provided by operating activities		18,573,481		186,719		1,086,603		2,713,133
CASH FLOWS FROM INVESTING ACTIVITIES
Purchases of property and equipment		(61,932)		—		(19,305)		(31,960)
Purchase of oil and natural gas properties		(125,848,776)		(523)		(78,159)		(506,680)
Net cash used in investing activities		(125,910,708)		(523)		(97,464)		(538,640)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from initial public offering		96,255,000		—		—		—
Distributions to unitholders / members		(13,823,371)		—		—		(4,507,818)
Borrowings on long-term debt		30,843,593		—		—		3,050,000
Repayments on long-term debt		—		—		(850,000)		(605,000)
Payment of loan origination costs		(312,500)		—		(13,000)		—
Net cash provided by (used in) financing activities		112,962,722		—		(863,000)		(2,062,818)
NET INCREASE IN CASH AND CASH EQUIVALENTS		5,625,495		186,196		126,139		111,675
CASH AND CASH EQUIVALENTS, beginning of period		—		505,880		379,741		268,066
CASH AND CASH EQUIVALENTS, end of period	$	5,625,495	$	692,076	$	505,880	$	379,741
Supplemental cash flow information:
Cash paid for interest	$	455,228	$	34,505	$	373,513	$	333,289
Cash paid for taxes	$	—	$	5,355	$	25,892	$	7,358
Non-cash 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 consolidated financial statements.

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KIMBELL ROYALTY PARNTERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1—ORGANIZATION

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

On February 8, 2017, the Partnership completed its initial public offering (“IPO”) of 5,750,000 common units representing limited partner interests, which included 750,000 common units issued pursuant to the underwriters’ option to purchase additional common units. The mineral and royalty interests making up the Partnership’s initial assets were contributed to the Partnership by the Contributing Parties at the closing of the IPO. As a result, as of December 31, 2016, the Partnership had not yet acquired any of such assets. Unless otherwise indicated, the financial information presented for periods on or after February 8, 2017 refers to the Partnership as a whole. The financial information presented for the periods on or prior to February 7, 2017, is solely that of the Predecessor, Rivercrest Royalties, LLC, and does not include the results of the Partnership as a whole. The mineral and royalty interests underlying the oil, natural gas and natural gas liquids (“NGLs”) production revenues of the Predecessor represented approximately 11% of the Partnership’s total future undiscounted cash flows, based on the reserve report prepared by Ryder Scott Company, L.P. (“Ryder Scott”) as of December 31, 2016.

The Predecessor is a Delaware limited liability company formed on October 25, 2013 to own mineral and royalty interests in the United States of America (‘‘United States’’). In addition to mineral and royalty interests, the Predecessor’s assets include overriding royalty interests. These non-cost-bearing interests are collectively referred to as ‘‘mineral and royalty interests.’’ The Predecessor also had non-operated working interests in certain oil and natural gas properties. Prior to the Partnership’s IPO, the Predecessor assigned its non-operated working interests and associated asset retirement obligations (“ARO”) to an affiliated entity that was not contributed to the Partnership.

NOTE 2—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation

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

Segment Reporting

The Partnership 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 Partnership’s chief operating decision maker allocates resources and assesses performance based upon financial information of the Partnership as a whole.

Management Estimates

The preparation of the consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets, 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. Significant estimates made in preparing these financial statements include the estimate of uncollected revenues and unpaid expenses from mineral and royalty interests in properties operated by nonaffiliated entities, the estimates of proved oil, natural gas and NGL reserves and related present value estimates of future net cash flows from those properties, valuation of commodity derivative financial instruments and equity‑based compensation.

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KIMBELL ROYALTY PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

The discounted present value of the proved oil, natural gas and NGL 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 NGL 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 ceiling test 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.

Reclassification of Prior Period Presentation

Certain prior period amounts have been reclassified for consistency with the current period presentation. These reclassifications had no effect on previously reported net income (loss), total cash flows from operations or working capital.

Cash and Cash Equivalents

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

Accounts Receivable

Oil, natural gas and NGL receivables consists of revenue payments due to the Partnership from its mineral and royalty interests. Under the terms of the contribution agreement entered into by and among the Partnership and the Contributing Parties prior to the IPO, the Partnership is entitled to receive royalty payments with respect to the acquired properties on and after February 1, 2017. The Predecessor’s other current assets include amounts due as reimbursement for costs incurred by the Predecessor. The Partnership estimates and records an allowance for doubtful accounts when failure to collect the receivable is considered probable based on the relevant facts and circumstances surrounding the receivable. As of December 31, 2017, and 2016, no allowance for doubtful accounts is deemed necessary based upon a review of current receivables and the lack of historical write offs.

Derivative Financial Instruments

The Partnership’s ongoing operations expose it to changes in the market price for oil and natural gas. To manage risks related to fluctuations in prices attributable to its projected oil and natural gas production, the Partnership entered into oil and natural gas derivative contracts. Entrance into such contracts is dependent upon prevailing or anticipated market conditions.

Derivative instruments are recognized at fair value. If a right of offset exists under master netting arrangements and certain other criteria are met, derivative assets and liabilities with the same counterparty are netted on the consolidated balance sheet. The Partnership does not specifically designate derivative instruments as cash flow hedges, even though they reduce its exposure to changes in oil and natural gas prices; therefore, gains and losses arising from changes in the fair value of derivatives are recognized on a net basis in the consolidated statement of operations within loss on commodity derivative instruments.

Property and Equipment

Property and equipment includes office furniture and equipment, leasehold improvements, and computer hardware and equipment and is stated at historical cost. Depreciation and amortization are calculated using the straight-

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KIMBELL ROYALTY PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

line method over expected useful lives ranging from three to seven years. Leasehold improvements are depreciated over the shorter of the expected useful life or the term of the underlying lease.

Oil and Natural Gas Properties

The Partnership follows the full cost method of accounting for costs related to its oil and natural gas 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 capitalized costs to the aggregate of the present value of future net revenues attributable to proved oil, natural gas and NGL reserves discounted at 10% plus the lower of cost or market value of unproved properties. The Partnership has not assigned any value to unproved properties in which it holds an interest. The full cost ceiling is evaluated at the end of each period.

While the quantities of proved reserves require substantial judgment, the associated prices of oil, natural gas and NGL reserves that are included in the discounted present value of the 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. The present value is not necessarily an indication of the fair value of the reserves. Oil, natural gas and NGL prices have historically been volatile, and the prevailing prices at any given time may not reflect the Partnership’s or the industry’s forecast of future prices.

The substantial majority of the Partnership’s proved oil and natural gas properties that were acquired at the time of the IPO were recorded at fair value as of the IPO. The fair value of these acquired assets was based on the common units issued to the Contributing Parties, other than the Predecessor, multiplied by the IPO price per common unit plus the net proceeds of the IPO that were distributed to the Contributing Parties, excluding the value of any common units or net proceeds distributed to the Predecessor. In accordance with SEC guidance, management determined the fair value of the acquired properties clearly exceeded the related full-cost ceiling limitation beyond a reasonable doubt and received an exemption from the SEC to exclude the properties acquired at the closing of the IPO from the ceiling test calculation. This exemption was effective beginning with the period ended March 31, 2017 and will remain effective through December 31, 2017. A component of the exemption received from the SEC is that we were required to assess the fair value of these acquired assets at each reporting period through the term of the exemption to ensure that the inclusion of these acquired assets in the full-cost ceiling test would not be appropriate. As of December 31, 2017, management determined that the exemption to exclude these acquired assets from the full-cost ceiling test was appropriate. In making this determination, management considered that the value was based on a transaction conducted in a public offering and that the common units issued by the Partnership as consideration for the properties were attributed the same value as those purchased in the Partnership’s IPO by third-party investors. Additionally, the fair value of the properties acquired at the closing of our IPO was based on forward strip oil and natural gas pricing existing at the date of the IPO, and management affirmed that there has not been a material decline to the fair value of these acquired assets since the IPO. The properties acquired at the closing of our IPO have an unamortized cost at December 31, 2017 of $237.2 million. Had management not affirmed the lack of material change to the fair value, the impairment charge recorded would have been $64.3 million as of December 31, 2017. The Partnership will recognize an impairment in the first quarter of 2018 after the exemption has expired. All of the Partnership’s oil and natural gas properties are subject to the full-cost ceiling test. No impairment expense was recorded for the period from February 8, 2017 to December 31, 2017.

No impairment expense was recorded by the Predecessor for the period from January 1, 2017 to February 7, 2017 (the “Predecessor 2017 Period”). During the years ended December 31, 2016 and 2015, our Predecessor recorded a non-cash impairment charge of $5.0 million and $28.7 million, respectively, primarily due to changes in reserve values resulting from the decline in commodity prices and other factors.

The Partnership’s oil and natural gas properties are depleted on the unit-of-production method using estimates of proved oil, natural gas and NGL reserves. Sales or other dispositions of oil and gas properties are accounted for as

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KIMBELL ROYALTY PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

adjustments to capitalized costs, with no gain or loss recorded unless the ratio of cost to estimated proved reserves would significantly change. No gains or losses were recorded for the period from February 8, 2017 to December 31, 2017, the Predecessor 2017 Period, or the years ended December 31, 2016 and 2015.

Due to the nature of the Partnership’s and the Predecessor’s mineral and royalty interests, there are no exploratory activities pending determination, and no exploratory costs were charged to expense for the period from February 8, 2017 to December 31, 2017, the Predecessor 2017 Period, or the years ended December 31, 2016 and 2015.

Other Current Liabilities

At December 31, 2017 and 2016, the Partnership’s and Predecessor’s other current liabilities consisted of the following:


	Partnership		Predecessor
	December 31,		December 31,
	2017		2016
Accrued ad valorem taxes	$	531,664	$	-
Revenue payable		509,125		-
Accrued revenue processing fees		344,314		-
Accrued interest expense		278,925		-
Other current liabilities		82,634		112,508
Total current liabilities	$	1,746,662	$	112,508

Asset Retirement Obligations

Prior to the transactions that were completed in connection with the closing of the Partnership’s IPO, the Predecessor assigned its non-operated working interests and associated ARO to an affiliated entity that was not contributed to the Partnership. The Predecessor’s ARO reflects the present value of estimated costs of dismantlement, removal, site reclamation, and similar activities associated with the Predecessor’s non-operated working interests in oil and natural gas properties.

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

Other Long-Term Liabilities

The Predecessor’s other long-term liabilities consist of a tenant improvement allowance granted at the effective date of the lease for the Partnership’s office space. This allowance was accounted for as a deferred incentive and was being amortized over the term of the lease as a reduction to rent expense. The deferred incentive was fully realized through the transactions that were completed in connection with the closing of the Partnership’s IPO and is not recognized in the Partnership’s financial statements.

Income Taxes

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

Texas imposes a franchise tax, commonly referred to as the Texas margin tax, which is considered an income tax, at a rate of 0.75% on gross revenues less certain deductions, as specifically set forth in the Texas margin tax statute. The Partnership and the Predecessor incurred de minimis amounts of state income taxes during 2017 and 2016.

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KIMBELL ROYALTY PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

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. The Partnership and the Predecessor had no uncertain tax positions at December 31, 2017 and 2016.

The Partnership and Predecessor recognizes interest and penalties related to uncertain tax positions in income tax expense. For the period from February 8, 2017 to December 31, 2017, the Predecessor 2017 Period, and the years ended December 31, 2016 and 2015, the Partnership and the Predecessor did not recognize any interest or penalty expense related to uncertain tax positions.

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

At times, the Partnership 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 Partnership has not experienced any losses related to amounts in excess of federally insured limits.

During the period from February 8, 2017 to December 31, 2017, one purchaser accounted for approximately 14% of oil, natural gas and NGL sales revenue. During the year ended December 31, 2016, three purchasers accounted for approximately 20%, 13% and 10% of oil, natural gas and NGL sales revenue.

Revenue Recognition

The Partnership 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 mineral and royalty interests, the Partnership is entitled to a portion of the revenues received from the production of oil, natural gas and associated NGLs from the underlying acreage, net of post-production expenses and taxes. The pricing of oil, natural gas and NGL sales from the properties is primarily determined by supply and demand in the marketplace and can fluctuate considerably.

To the extent actual volumes and prices of oil, natural gas and NGLs 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 oil, natural gas, and NGL receivables in the accompanying consolidated balance sheets. 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 Partnership measures and reports certain assets and liabilities on a fair value basis and has classified and disclosed its fair value measurements using the levels of the fair value hierarchy. The carrying amount of cash and cash equivalents, accounts receivable, accounts payable, and other current liabilities as reflected in the consolidated 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. See Note 5 for further discussion of the Partnership’s fair value measurements.

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KIMBELL ROYALTY PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

Recently Issued Accounting Pronouncements

In January 2017, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2017-01, “Business Combinations—Clarifying the Definition of a Business.” This update apples to all entities that must determine whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. The update requires that when substantially all of the fair value of the gross assets acquired (or disposed of) is concentrated in a single identifiable asset or a group of similar identifiable assets, the transaction should not be accounted for as a business. This update will be effective for financial statements issued for fiscal years beginning after December 31, 2017, including interim periods within those fiscal years. This update should be and will be applied prospectively on or after the effective date. The adoption of this update will change the process that the Partnership uses to evaluate whether it has acquired a business or an asset. This update is not expected to have a material impact on the Partnership’s financial statements or results of operations.

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 Partnership does not believe this standard will have a material impact on its financial statements.

In April 2016, the FASB issued ASU 2016-10, “Revenue from Contracts with Customers—Identifying Performance Obligations and Licensing.” This update clarifies two principles of Accounting Standards Codification (“ASC”) Topic 606, identifying performance obligations and the licensing implementation guidance. This standard has the same effective date as ASU 2016-08, the revenue recognition standard discussed below. The adoption of this standard is not expected to have a material impact on the Partnership's financial position, results of operations and liquidity.

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 Partnership adopted this standard effective at the issuance of its restricted units under the Kimbell Royalty GP, LLC 2017 Long-Term Incentive Plan (“LTIP”) on May 12, 2017. The Partnership elected to account for forfeitures as they occur as a result of adopting this standard.

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 Partnership believes the primary impact of adopting this standard will be the recognition of assets and liabilities on the balance sheet for current operating leases.

In May 2014, the FASB issued ASU 2014-09, “Revenue from Contracts with Customers’ (Topic 606).” an ASU on a comprehensive new revenue recognition standard that will supersede 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

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KIMBELL ROYALTY PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

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.

As of December 31, 2017, we have substantially completed our evaluation of our sources of revenue and the impact of this accounting standards update on our consolidated results of operations, financial position, cash flows and financial disclosures for any potential changes in revenue recognition upon adoption of the new standard, and based on evaluations to-date, the implementation of the new standard will not have a material impact on the consolidated financial statements and disclosures . The Partnership has also completed its review of the information technology and internal control changes that will be required to implement the new standard based on the results of its contract review process. The Partnership will not be required to alter its existing information technology and internal controls outside of ongoing contract review processes in order to identify impacts of future revenue contracts entered into by the Partnership. Additionally, the Partnership does not anticipate the disclosure requirements under the Accounting Standards Update to have a material change on how it presents information regarding its revenue streams. The Partnership intends to use the full retrospective approach upon adoption of the new guidance on the effective date of January 1, 2018 and does not anticipate recording or disclosing any material transition adjustments upon adoption.

NOTE 3—ACQUISITIONS

In the second quarter of 2017, the Partnership acquired mineral and royalty interests underlying 1.1 million gross acres, 6,881 net royalty acres, for an aggregate purchase price of approximately $16.8 million. The Partnership funded these acquisitions with borrowings under its secured revolving credit facility.

On October 9, 2017, the Partnership acquired mineral and royalty interests underlying 8,460 gross acres, 983 net royalty acres, for an aggregate purchase price of approximately $3.9 million in Uintah County, Utah. The Partnership funded this acquisition with borrowings under its secured revolving credit facility.

On November 8, 2017, the Partnership acquired mineral and royalty interests underlying 71,410 gross acres, 2,757 net royalty acres, for an aggregate purchase price of approximately $7.3 million in various counties in Arkansas. The Partnership funded this acquisition with borrowings under its secured revolving credit facility.

On December 13, 2017, the Partnership acquired a diverse package of mineral and overriding royalty interests for an aggregate purchase price of approximately $1.3 million. The core positions are located in California and Wyoming and the package also includes small interests located in Kansas, Arkansas, Texas and Utah. The Partnership funded this acquisition with borrowings under its secured revolving credit facility.

NOTE 4—DERIVATIVES

To reduce the impact of fluctuations in oil and natural gas prices on revenues, the Partnership entered into commodity derivative contracts for the years ended December 31, 2018 and 2019, effective January 1, 2018 and 2019, respectively, with a trade date of December 12, 2017, as to reduce its exposure to price volatility of oil and natural gas. The Partnership entered into oil and natural gas derivative instrument contracts that contain netting arrangements. The counterparty to the contracts is an unrelated third party.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

The Partnership has not designated any of its derivative contracts as hedges for accounting purposes. The Partnership records all derivative contracts at fair value. Changes in the fair values of the Partnership’s derivative instruments are presented on a net basis in the accompanying consolidated statement of operations and consisted of the following:


	Period from February 8, 2017 to December 31,
	2017
Beginning fair value of commodity derivative instruments	$	—
Loss on commodity derivative instruments		(318,829)
Ending fair value of commodity derivative instruments	$	(318,829)

At December 31, 2017 , the Partnership’s commodity derivative contracts consisted of fixed price swaps, under which the Partnership receives a fixed price for the contract and pays a floating market price to the counterparty over a specified period for a contracted volume.

At December 31, 2017, the Partnership’s open commodity derivative contracts consisted of the following:

Oil Price Swaps


	Notional	Weighted Average
	Volumes (MBbls)	Fixed Price (per Bbl)
January 2018 - December 2018	43,070	$	56.00
January 2019 - December 2019	43,070	$	53.07

Natural Gas Price Swaps


	Notional	Weighted Average
	Volumes (MMBtu)	Fixed Price (per MMBtu)
January 2018 - December 2018	352,590	$	2.71
January 2019 - December 2019	352,590	$	2.76

NOTE 5—FAIR VALUE MEASUREMENTS

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.

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KIMBELL ROYALTY PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

The Partnership’s commodity derivative instruments are classified within Level 2. The fair values of the Partnership’s oil and natural gas fixed price swaps are based upon inputs that are either readily available in the public market, such as oil and natural gas futures prices, volatility factors and discount rates, or can be corroborated from active markets.

The Predecessor’s 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 Predecessor’s ARO for the Predecessor 2017 Period.

NOTE 6—LONG-TERM DEBT

In connection with its IPO, the Partnership entered into a $50.0 million secured revolving credit facility that is secured by substantially all of its assets and the assets of its wholly owned subsidiaries. Availability under the secured revolving credit facility equals the lesser of the aggregate maximum commitments of the lenders and the borrowing base. The borrowing base will be re-determined semi-annually on February 1 and August 1 of each year based on the value of the Partnership’s oil and natural gas properties and the oil and natural gas properties of its wholly owned subsidiaries. In connection with the February 1, 2018 redetermination under the secured revolving credit facility, the borrowing base was reaffirmed at $100.0 million. Aggregate commitments remain at $50.0 million providing for maximum availability under the revolving credit facility of $50.0 million. The secured revolving credit facility permits aggregate commitments 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 matures on February 8, 2022.

The secured revolving credit facility contains various affirmative, negative and financial maintenance covenants. These covenants limit the Partnership’s 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 the Partnership to maintain the following financial ratios or to reduce the Partnership’s indebtedness if the Partnership is unable to comply with such ratios: (i) a Debt to EBITDAX Ratio (as 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 December 31, 2017, the Partnership’s outstanding balance was $30.8 million. The Partnership was in compliance with all covenants included in the secured revolving credit facility as of December 31, 2017.

During the period from February 8, 2017 to December 31, 2017, borrowings under the secured revolving credit facility bore interest at LIBOR plus a margin of 2.25% and Prime Rate (as defined in the secured revolving credit facility) plus a margin of 1.25%. For the period from February 8, 2017 to December 31, 2017, the weighted average interest rate on the Partnership’s outstanding borrowings was 3.94%.

On January 31, 2014, the Predecessor entered into a credit agreement with Frost Bank for up to a $50.0 million revolving credit facility. The credit facility was subject to borrowing base restrictions and was collateralized by certain properties. The borrowing base on the Predecessor’s credit facility was $20.0 million with interest 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. As of December 31, 2016, the Predecessor had outstanding advances on long-term debt totaling $10.6 million. On February 8, 2017, the Predecessor repaid the entire outstanding principal and interest balance on the credit facility with cash proceeds from the sale of the Predecessor’s mineral and royalty interests to the Partnership.

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KIMBELL ROYALTY PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

NOTE 7—COMMON UNITS

On February 8, 2017, the Partnership completed its IPO of 5,750,000 common units representing limited partner interests, which included 750,000 common units issued pursuant to the underwriters’ option to purchase additional common units. The mineral and royalty interests making up the initial assets were contributed to the Partnership by the Contributing Parties at the time of the IPO. On May 12, 2017, the Partnership issued 163,324 restricted units under the LTIP.

On May 2, 2017, the General Partner’s Board of Directors (the “Board of Directors”) declared a quarterly cash distribution of $0.23 per common unit for the period ended March 31, 2017. The distribution was paid on May 15, 2017 to unitholders of record as of the close of business on May 8, 2017. The amount of the first quarter 2017 distribution was adjusted for the period from the date of the closing of the Partnership’s IPO through March 31, 2017.

On July 28, 2017, the Board of Directors declared a quarterly cash distribution of $0.30 per common unit for the quarter ended June 30, 2017. The distribution was paid on August 14, 2017 to unitholders of record as of the close of business on August 7, 2017.

On August 9, 2017, the Board of Directors, upon the advice and recommendation of the Conflicts and Compensation Committee of the Board of Directors, approved the grant of (i) common units in an amount equal to $30,000 each to certain non-employee directors of the Partnership under the LTIP, which were fully vested as of the grant date, and (ii) a total of 4,247 restricted units to certain consultants under the LTIP. Such grants were made on August 11, 2017.

As of December 31, 2017, 16,509,799 common units of the Partnership were outstanding.

During the year ended December 31, 2015, the Predecessor made distributions to members totaling $3.2 million. The Predecessor made no distributions during the year ended December 31, 2016.

NOTE 8—EARNINGS PER UNIT

Basic earnings per unit (“EPU”) is calculated by dividing net income (loss) by the weighted-average number of common units outstanding during the period. Diluted net income (loss) per common unit gives effect, when applicable, to unvested common units granted under the Partnership’s LTIP for its employees, directors and consultants and unvested options granted under the Predecessor’s long-term incentive plan as described in Note 9—Unit-Based Compensation. For the Predecessor 2017 period and the years ended December 31, 2016 and 2015, the effect of the 110,000 options issued under the Predecessor’s long-term incentive plan were anti-dilutive. Therefore, the options issued under the Predecessor’s long-term incentive plan were not included in the diluted EPU calculation on the consolidated statements of operations for those periods.

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KIMBELL ROYALTY PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

The following table summarizes the calculation of weighted average common shares outstanding used in the computation of diluted earnings (loss) per share:


	Partnership		Predecessor
	Period from February 8, 2017 to December 31,		Period from January 1, 2017 to February 7,		Year Ended December 31,
	2017		2017		2016		2015
Net income (loss)	$	1,715,740	$	(496,856)	$	(6,212,619)	$	(31,313,926)

Net income (loss) attributable to common units
Basic	$	0.11	$	(0.82)	$	(10.28)	$	(51.83)
Diluted	$	0.10	$	(0.82)	$	(10.28)	$	(51.83)
Weighted average number of common units outstanding
Basic		16,336,871		604,137		604,137		604,137
Diluted		16,455,602		604,137		604,137		604,137

NOTE 9—UNIT-BASED COMPENSATION

The Partnership’s LTIP authorizes grants of up to 2,041,600 common units in the aggregate to its employees, directors and consultants. The restricted units issued under our LTIP generally vest in one-third installments on each of the first three anniversaries of the grant date, subject to the grantee’s continuous service through the applicable vesting date. Compensation expense for such awards will be recognized over the term of the service period on a straight-line basis over the requisite service period for the entire award. Management elects not to estimate forfeiture rates and to account for forfeitures in compensation cost when they occur. Compensation expense for consultants will be accrued for services provided during the intervening periods between the grant and vesting dates, utilizing then-current fair values for the awards and applying mark-to-market accounting until actual vesting occurs.

Distributions related to the restricted units are paid concurrently with our distributions for common units. The fair value of our restricted units issued under our LTIP to our employees and directors is determined by utilizing the market value of our common units on the respective grant date. The restricted units issued to non-employee consultants will utilize current market value of our common units for the awards and apply mark-to-market accounting until vesting occurs. The following table presents a summary of the Partnership’s unvested common units.


		Weighted		Weighted		Weighted
		Average		Average		Average
		Grant-Date		Market-Date		Remaining
		Fair Value		Fair Value		Contractual
	Units	per Unit		per Unit		Term
Unvested at February 8, 2017	—	$	—	$	—	—
Granted - service condition employees	143,318		18.655		—	—
Granted - service condition consultants	24,253		—		16.250	—
Granted - non-employee directors	9,520				16.250
Vested	(9,520)		—		—	—
Forfeited	—		—		—	—
Exercised	—		—		—	—
Unvested at December 31, 2017	167,571	$	18.655	$	16.250	1.364 years

Prior to the IPO, the Predecessor had a long-term incentive plan that provided for the issuance of up to 110,000 membership units in the form of options as compensation for services performed for the Predecessor. The options carried a distribution right, whereby the option holder received distributions that were commensurate with those given to holders of membership units.

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KIMBELL ROYALTY PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

A summary of the Predecessor’s option activity as of February 7, 2017 is as follows:


				Weighted
		Weighted		Average
		Average		Remaining
		Exercise		Contractual
	Units	Price		Term
Outstanding, December 31, 2016	110,000	$	100	8.00 years
Granted	—		—	—
Forfeited	—		—	—
Exercised	—		—	—
Outstanding, February 7, 2017	110,000	$	100	7.92 years
Exercisable, February 7, 2017	—	$	—	—

For the Predecessor 2017 Period and the years ended December 31, 2016 and 2015, total compensation expense for awards under the long-term incentive plan was $0.05 million, $0.6 million and $0.6 million respectively, and is included general and administrative expenses in the consolidated statements of operations. In connection with the transactions that were completed at the closing of the Partnership’s IPO, the outstanding options to purchase membership units under the Predecessor’s long-term incentive plan expired and were not converted to units in the Partnership.

NOTE 10—ASSET RETIREMENT OBLIGATIONS

Prior to the transactions that were completed in connection with the IPO, the Predecessor assigned its non-operated working interests and associated ARO to an affiliated entity that was not contributed to the Partnership. As of the closing of its IPO and through the date of this Annual Report, the Partnership did not own any working interests and did not have any ARO or any lease operating expenses as a working interest owner.

NOTE 11—RELATED PARTY TRANSACTIONS

In connection with the IPO, the Partnership entered into a management services agreement with Kimbell Operating, which entered into separate services agreements with Steward Royalties, LLC (“Steward Royalties”), Taylor Companies Mineral Management, LLC (“Taylor Companies”), K3 Royalties, LLC (“K3 Royalties”), Nail Bay Royalties, LLC (“Nail Bay Royalties”) and Duncan Management, LLC (“Duncan Management”) pursuant to which they and Kimbell Operating provide management, administrative and operational services to the Partnership. In addition, under each of their respective services agreements, affiliates of the Partnership’s Sponsors will identify, evaluate and recommend to the Partnership acquisition opportunities and negotiate the terms of such acquisitions. Amounts paid to Kimbell Operating and such other entities under their respective services agreements will reduce the amount of cash available for distribution to the Partnership’s unitholders. During the period from February 8, 2017 to December 31, 2017, the Partnership made payments to Steward Royalties, Taylor Companies, K3 Royalties, Nail Bay Royalties and Duncan Management in the amount of $297,917, $366,667, $110,000, $461,576 and $603,590, respectively. Certain consultants who provide services under the above mentioned management services agreements were granted restricted units under the Partnership’s LTIP on May 12, 2017. As of December 31, 2017, the Partnership had an outstanding receivable from certain employees of $12,550, which is included in accounts receivable and other current assets in the accompanying audited consolidated balance sheet.

During the Predecessor 2017 Period and the years ended December 31, 2016 and 2015, the Predecessor had certain related party receivables and payables; however, such amounts are de minimis at December 31, 2016 and 2015.

NOTE 12—ADMINISTRATIVE SERVICES

The Partnership relies upon its officers, directors, Sponsors and outside consultants to further its business efforts. The Partnership 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 Board of Directors and their affiliated entities. See Note 11―Related Party Transactions.

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KIMBELL ROYALTY PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

NOTE 13—COMMITMENTS AND CONTINGENCIES

Leases

The Partnership leases certain office space under non-cancelable operating leases that end at various dates through 2022. The Partnership recognizes rent expense on a straight-line basis over the lease term. Rent expense is included in general and administrative expense and was de minimis for all periods presented on the consolidated statements of operations.

Future minimum lease commitments under non-cancelable leases are as follows as of December 31, 2017:


Years Ending December 31,
2018	$	127,506
2019		130,180
2020		91,126
2021		50,784
2022		29,624
Thereafter		-
Total	$	429,220

Litigation

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

NOTE 14—SUBSEQUENT EVENTS

The Partnership has evaluated events that occurred subsequent to December 31, 2017 in the preparation of its financial statements.

On January 26, 2018, the Board of Directors, upon the advice and recommendation of the Conflicts and Compensation Committee of the Board of Directors, approved the grant of a total of 326,654 restricted units to certain employees, directors and consultants under the LTIP. Such grants were made on January 29, 2018.

NOTE 15—SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION (UNAUDITED)

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

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KIMBELL ROYALTY PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

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:


	Partnership		Predecessor
	December 31,		December 31,
	2017		2016
Oil, natural gas and NGL interests
Proved	$	297,609,797	$	70,888,121
Total oil, natural gas and NGL interests		297,609,797		70,888,121
Accumulated depreciation, depletion, accretion and impairment		(15,394,238)		(51,948,355)
Net oil, natural gas and NGL interests capitalized	$	282,215,559	$	18,939,766

Costs incurred in oil and natural gas activities

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


	Partnership		Predecessor
	Period from February 8, 2017 to December 31,		Period from January 1, 2017 to February 7,		Year Ended December 31,
	2017		2017		2016		2015
Acquisition costs
Proved properties	$	297,609,797	$	—	$	—	$	42,000
Total		297,609,797		—		—		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	$	297,609,797	$	—	$	78,159	$	506,680

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 NGLs. 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 Partnership or Predecessor’s oil, natural gas and NGL operations.


	Partnership		Predecessor
	Period from February 8, 2017 to December 31,		Period from January 1, 2017 to February 7,		Year Ended December 31,
	2017		2017		2016		2015
Oil, natural gas and NGL revenues	$	30,665,092	$	318,310	$	3,606,659	$	4,684,923
Production and ad valorem taxes		(2,452,058)		(19,651)		(280,474)		(426,885)
Depreciation, depletion and accretion expense		(15,394,238)		(113,639)		(1,604,208)		(4,008,730)
Impairment of oil and natural gas properties		-		-		(4,992,897)		(28,673,166)
Marketing and other deductions		(1,648,895)		(110,534)		(750,792)		(747,264)
Results of operations from oil, natural gas and NGLs	$	11,169,901	$	74,486	$	(4,021,712)	$	(29,171,122)

The following tables summarize the net ownership interest in the proved oil, natural gas and NGL reserves and the standardized measure of discounted future net cash flows related to the proved oil, natural gas and NGL reserves, and the estimates were prepared by the Partnership based on reserve reports prepared by Ryder Scott for the years ended December 31, 2017 and 2016. The standardized measure presented here excludes income taxes, as the tax basis for the

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KIMBELL ROYALTY PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

properties is not applicable on a go-forward basis. The proved oil, natural gas and NGL 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 barrel 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 Partnership’s net proved oil, natural gas and NGL reserves and changes in net proved oil, natural gas and NGL reserves attributable to the oil, natural gas and NGL properties, which are located in multiple states are summarized below:


	Crude Oil and		Natural Gas
	Condensate	Natural Gas	Liquids	Total
	(MBbls)	(MMcf)	(MBbls)	(MBOE)
Net proved reserves at January 1, 2016	6,827	51,734	1,647	17,096
Revisions of previous estimates (1)	131	(852)	335	324
Purchase of minerals in place (2)	45	90	9	69
Extensions, discoveries and other additions (3)	637	2,851	115	1,227
Production	(430)	(3,433)	(124)	(1,126)
Net proved reserves at December 31, 2016	7,210	50,390	1,982	17,590
Revisions of previous estimates (1)	(193)	(1,535)	666	217
Purchase of minerals in place (4)	362	16,312	274	3,355
Extensions, discoveries and other additions (5)	505	2,261	91	973
Production	(421)	(3,512)	(175)	(1,181)
Net proved reserves at December 31, 2017	7,463	63,916	2,838	20,954

Net Proved Developed Reserves
December 31, 2016	4,879	35,172	1,416	12,157
December 31, 2017	5,284	47,501	2,202	15,403

Net Proved Undeveloped Reserves
December 31, 2016	2,331	15,218	566	5,433
December 31, 2017	2,179	16,415	636	5,551

(1)

Revisions of previous estimates include technical revisions due to changes in commodity prices, historical and projected performance and other factors.

(2)

Includes the acquisition of three contiguous Eagle Ford drilling units in Karnes County, Texas.

(3)

Includes discoveries and additions primarily related to active drilling on our acreage primarily in the Permian Basin.

(4)

Includes the acquisition of $29.3 million of mineral and royalty interests, the largest of which being a package in the Anadarko Basin, and also includes additional mineral and royalty interests in Texas, Louisiana, Wyoming, California, North Dakota, Utah, New Mexico, Arkansas, and Kansas.

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KIMBELL ROYALTY PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

(5)

Includes discoveries and additions primarily related to active drilling on our acreage primarily in the Permian Basin, Eagle Ford Shale.

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 (in thousands):


	Year Ended December 31,
	2017		2016
Future cash inflows	$	562,967	$	414,004
Future production costs		(45,652)		(32,034)
Future state margin taxes		(2,790)		(2,051)
Future net cash flows		514,525		379,919
Less 10% annual discount to reflect timing of cash flows		(298,973)		(220,643)
Standard measure of discounted future net cash flows	$	215,552	$	159,276

Reserve estimates and future cash flows are based on the average market prices for sales of oil, natural gas and NGL adjusted for basis differentials, on the first calendar day of each month during the year. The average prices used for 2017 and 2016 were $51.34 and $42.75 per barrel for crude oil and $2.98 and $2.49 per Mcf for natural gas, respectively.

Future production costs are computed primarily by the Partnership’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 NGL 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 NGL reserves of the properties are as follows (in thousands):


	Year Ended December 31,
	2017		2016
Standardized measure - beginning of year	$	159,275	$	180,083
Sales, net of production costs		(29,288)		(24,280)
Net changes of prices and production costs related to future production		21,946		(23,321)
Extensions, discoveries and improved recovery, net of future production costs		10,064		11,253
Revisions of previous quantity estimates, net of related costs		2,248		2,974
Net changes in state margin taxes		301		(112)
Accretion of discount		15,928		18,008
Purchases of reserves in place		23,309		1,097
Timing differences and other		11,769		(6,426)
Standardized measure - end of year	$	215,552	$	159,276

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KIMBELL ROYALTY PARTNERS, LP

SELECTED QUARTERLY FINANCIAL DATA - UNAUDITED

Selected Quarterly Financial Information—Unaudited

Quarterly financial data was as follows for the periods indicated.


	Predecessor		Partnership
	First Quarter		First Quarter		Second Quarter		Third Quarter		Fourth Quarter
2017
Total revenue	$	318,310	$	4,553,344	$	7,751,998	$	8,351,399	$	10,008,351
Net (loss) income	$	(496,856)	$	283,218	$	251,651	$	119,029	$	1,061,842
Net income attributable to common units
Basic	$	(0.82)	$	0.02	$	0.02	$	0.01	$	0.06
Diluted	$	(0.82)	$	0.02	$	0.02	$	0.01	$	0.06
Cash distributions declared and paid	$	*	$	0.23	$	0.30	$	0.31	$	0.36
Total assets	$	*	$	279,419,440	$	289,918,996	$	290,406,599	$	295,291,004
Long-term debt	$	*	$	3,877,500	$	18,265,090	$	22,214,090	$	30,843,593
Partners' capital	$	*	$	273,657,870	$	270,288,690	$	265,893,106	$	262,065,434

			Predecessor
			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 common units
Basic			$	(6.70)	$	(1.99)	$	(1.27)	$	(0.32)
Diluted			$	(6.70)	$	(1.99)	$	(1.27)	$	(0.32)
Cash distributions declared and paid			$	*	$	*	$	*	$	*
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
Predecessor members' equity			$	10,341,124	$	9,293,104	$	8,675,203	$	8,631,862

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

F-23

Exhibit 10.11

AMENDMENT NO. 1 TO THE

MANAGEMENT SERVICES AGREEMENT

THIS AMENDMENT NO. 1 TO THE MANAGEMENT SERVICES AGREEMENT (this “ Amendment ”) is executed on March 7, 2018, but made effective as of January 1, 2018 (the “ Effective Date ”) by and between K3 Royalties, LLC, a Texas limited liability company (the “ Manager ”), and Kimbell Operating Company, LLC, a Delaware limited liability company (“ Kimbell Operating ”). The Manager and Kimbell Operating are sometimes referred to in this Amendment each as a “ Party ” and collectively as the “ Parties .”

W I T N E S S E T H:

WHEREAS , the Parties entered into that certain Management Services Agreement effective as of February 8, 2017 (the “ Management Services Agreement ”); and

WHEREAS , pursuant to Section 13.2 of the Management Services Agreement, the Parties desire to amend the Management Services Agreement, as set forth herein.

NOW, THEREFORE , in consideration of the premises set forth above and the respective covenants, agreements and conditions contained in this Amendment, as well as other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the Parties agree to amend the Management Services Agreement as set forth below.

ARTICLE I
AMENDMENT OF MANAGEMENT SERVICES AGREEMENT

Section 1.1 Definitions . Capitalized terms used but not defined in this Amendment shall have the meanings ascribed to such terms in the Management Services Agreement.

Section 1.2 Amendment of the Management Services Agreement . Effective as of the Effective Date, Kimbell Operating and the Manager hereby amend Schedule A to the Management Services Agreement by adding the following to the list of Services that may be required from the Manager with respect to the Serviced Properties and the identification, evaluation and recommendation of opportunities for an Acquisition and any related negotiation of such opportunities.

“3. Assist with business development and relationship management between past and future sellers of mineral assets and the Partnership.

4. Assist with current and future relations with the Kimbell Art Foundation.”

ARTICLE II
MISCELLANEOUS

Section 2.1 Incorporation into Management Services Agreement . The terms of this Amendment shall be incorporated by reference in the Management Services Agreement as though set forth in full therein. In the event of any inconsistency between the provisions of this Amendment and any other provision of the Management Services Agreement, the terms and provisions of this Amendment shall govern and control. Except to the extent specifically amended or superseded by the terms of this Amendment, all of the provisions of the Management Services Agreement shall remain in full force and effect to the extent in effect on the date hereof. The Management Services Agreement, as modified by this Amendment, constitutes the complete agreement between Kimbell Operating and the Manager and supersedes any prior written or oral agreements, writings, communications or understandings of Kimbell Operating and the Manager with respect to the subject matter thereof.

Section 2.2 Severability . If any provision of this Amendment is invalid, illegal or incapable of being enforced by any rule of applicable Law, or public policy, all other conditions and provisions of this Amendment shall nevertheless remain in full force and effect so long as the economic or legal substance of the transactions contemplated by this Amendment are not affected in any manner materially adverse to any Party. Upon such determination that any term or other provision is invalid, illegal or incapable of being enforced, the Parties shall negotiate in good faith to modify this Amendment so as to effect the original intent of the Parties as closely as possible in a mutually acceptable manner in order that the transactions contemplated by this Amendment are consummated as originally contemplated to the fullest extent possible.

Section 2.3 Assignment . Neither Party may assign, transfer or otherwise alienate this Amendment or any of its rights, interests or obligations under this Amendment (whether by operation of Law or otherwise) without the consent of the other Party. Any attempted assignment, transfer or alienation in violation of this Amendment shall be null, void and ineffective.

Section 2.4 Counterparts . This Amendment may be executed in one or more counterparts (including by facsimile or other electronic transmission), each of which shall be deemed an original, but all of which together shall constitute one instrument.

Section 2.5 Governing Law; Jurisdiction; Waiver of Jury Trial. The Parties agree and consent to the application of the governing law, jurisdiction and waiver of jury trial provisions set forth in Section 13.8 of the Management Services Agreement in respect of this Amendment.

[ Signatures of the Parties follow on the next page. ]

IN WITNESS WHEREOF, the Parties have executed this Amendment on, and effective as of, the Effective Date:

K3 ROYALTIES, LLC

By:

/s/ Mitch S. Wynne

Name: Mitch S. Wynne

Title: Manager

KIMBELL OPERATING COMPANY, LLC

By:

/s/ Matthew S. Daly

Name: Matthew S. Daly

Title: Chief Operating Officer

Signature Page to Amendment No. 1

to Management Services Agreement

Exhibit 10.13

AMENDMENT NO. 1 TO THE

MANAGEMENT SERVICES AGREEMENT

THIS AMENDMENT NO. 1 TO THE MANAGEMENT SERVICES AGREEMENT (this “ Amendment ”) is executed on March 7, 2018, but made effective as of January 1, 2018 (the “ Effective Date ”) by and between Nail Bay Royalties, LLC, a Texas limited liability company (the “ Manager ”), and Kimbell Operating Company, LLC, a Delaware limited liability company (“ Kimbell Operating ”). The Manager and Kimbell Operating are sometimes referred to in this Amendment each as a “ Party ” and collectively as the “ Parties .”

W I T N E S S E T H:

WHEREAS , the Parties entered into that certain Management Services Agreement effective as of February 8, 2017 (the “ Management Services Agreement ”); and

WHEREAS , pursuant to Sections 3.5 and 13.2 of the Management Services Agreement, the Parties desire to amend the Management Services Agreement, as set forth herein.

ARTICLE I
AMENDMENT OF MANAGEMENT SERVICES AGREEMENT

Section 1.1 Definitions . Capitalized terms used but not defined in this Amendment shall have the meanings ascribed to such terms in the Management Services Agreement.

Section 1.2 Amendment of the Management Services Agreement . Effective as of the Effective Date, Kimbell Operating and the Manager hereby amend and restate Section 2.3(a) of the Management Services Agreement in its entirety as follows:

“As consideration for the Services rendered hereunder, Kimbell Operating shall pay to the Manager each month, in advance, a fee that shall represent a reasonable allocation of all projected costs (including its own overhead and general and administrative costs and expenses and those of its Affiliates) to be incurred by the Manager in providing such Services and that may be adjusted pursuant to Section 3.5 (the “ Services Fee ”). The Services Fee for the year ending December 31, 2018 shall be $29,736.42 per month. For the avoidance of doubt, in no event shall the Services Fee include any Tax passed on to Kimbell Operating pursuant to Section 3.4 hereof.”

ARTICLE II
MISCELLANEOUS

[ Signatures of the Parties follow on the next page. ]

IN WITNESS WHEREOF, the Parties have executed this Amendment on, and effective as of, the Effective Date:

NAIL BAY ROYALIES, LLC

By:

/s/ Benny D. Duncan

Name: Benny D. Duncan

Title: Manager

KIMBELL OPERATING COMPANY, LLC

By:

/s/ Matthew S. Daly

Name: Matthew S. Daly

Title: Chief Operating Officer

Signature Page to Amendment No. 1

to Management Services Agreement

Exhibit 10.15

AMENDMENT NO. 1 TO THE

MANAGEMENT SERVICES AGREEMENT

THIS AMENDMENT NO. 1 TO THE MANAGEMENT SERVICES AGREEMENT (this “ Amendment ”) is executed on March 7, 2018, but made effective as of January 1, 2018 (the “ Effective Date ”) by and between Steward Royalties, LLC, a Texas limited liability company (the “ Manager ”), and Kimbell Operating Company, LLC, a Delaware limited liability company (“ Kimbell Operating ”). The Manager and Kimbell Operating are sometimes referred to in this Amendment each as a “ Party ” and collectively as the “ Parties .”

W I T N E S S E T H:

WHEREAS , the Parties entered into that certain Management Services Agreement effective as of February 8, 2017 (the “ Management Services Agreement ”); and

WHEREAS , pursuant to Sections 3.5 and 13.2 of the Management Services Agreement, the Parties desire to amend the Management Services Agreement, as set forth herein.

ARTICLE I
AMENDMENT OF MANAGEMENT SERVICES AGREEMENT

Section 1.1 Definitions . Capitalized terms used but not defined in this Amendment shall have the meanings ascribed to such terms in the Management Services Agreement.

“As consideration for the Services rendered hereunder, Kimbell Operating shall pay to the Manager each month, in advance, a fee that shall represent a reasonable allocation of all projected costs (including its own overhead and general and administrative costs and expenses and those of its Affiliates) to be incurred by the Manager in providing such Services and that may be adjusted pursuant to Section 3.5 (the “ Services Fee ”). The Services Fee for the year ending December 31, 2018 shall be $10,833.33 per month. For the avoidance of doubt, in no event shall the Services Fee include any Tax passed on to Kimbell Operating pursuant to Section 3.4 hereof.”

ARTICLE II
MISCELLANEOUS

[ Signatures of the Parties follow on the next page. ]

IN WITNESS WHEREOF, the Parties have executed this Amendment on, and effective as of, the Effective Date:

STEWARD ROYALTIES, LLC

By:

/s/ Robert D. Ravnaas

Name: Robert D. Ravnaas

Title: President

KIMBELL OPERATING COMPANY, LLC

By:

/s/ Matthew S. Daly

Name: Matthew S. Daly

Title: Chief Operating Officer

Signature Page to Amendment No. 1

to Management Services Agreement

Exhibit 10.17

AMENDMENT NO. 1 TO THE

MANAGEMENT SERVICES AGREEMENT

THIS AMENDMENT NO. 1 TO THE MANAGEMENT SERVICES AGREEMENT (this “ Amendment ”) is executed on March 7, 2018, but made effective as of January 1, 2018 (the “ Effective Date ”) by and between Taylor Companies Mineral Management, LLC, a Texas limited liability company (the “ Manager ”), and Kimbell Operating Company, LLC, a Delaware limited liability company (“ Kimbell Operating ”). The Manager and Kimbell Operating are sometimes referred to in this Amendment each as a “ Party ” and collectively as the “ Parties .”

W I T N E S S E T H:

WHEREAS , the Parties entered into that certain Management Services Agreement effective as of February 8, 2017 (the “ Management Services Agreement ”); and

WHEREAS , pursuant to Sections 3.5 and 13.2 of the Management Services Agreement, the Parties desire to amend the Management Services Agreement, as set forth herein.

ARTICLE I
AMENDMENT OF MANAGEMENT SERVICES AGREEMENT

Section 1.1 Definitions . Capitalized terms used but not defined in this Amendment shall have the meanings ascribed to such terms in the Management Services Agreement.

“As consideration for the Services rendered hereunder, Kimbell Operating shall pay to the Manager each month, in advance, a fee that shall represent a reasonable allocation of all projected costs (including its own overhead and general and administrative costs and expenses and those of its Affiliates) to be incurred by the Manager in providing such Services and that may be adjusted pursuant to Section 3.5 (the “ Services Fee ”). The Services Fee for the year ending December 31, 2018 shall be $43,904.58 per month. For the avoidance of doubt, in no event shall the Services Fee include any Tax passed on to Kimbell Operating pursuant to Section 3.4 hereof.”

ARTICLE II
MISCELLANEOUS

[ Signatures of the Parties follow on the next page. ]

IN WITNESS WHEREOF, the Parties have executed this Amendment on, and effective as of, the Effective Date:

TAYLOR COMPANIES MINERAL MANAGEMENT, LLC

By:

/s/ Brett G. Taylor

Name: Brett G. Taylor

Title: President

KIMBELL OPERATING COMPANY, LLC

By:

/s/ Matthew S. Daly

Name: Matthew S. Daly

Title: Chief Operating Officer

Signature Page to Amendment No. 1

to Management Services Agreement

Exhibit 10.4

KimbelL Royalty GP, LLC

2017 LONG-TERM INCENTIVE PLAN

RESTRICTED UNIT AGREEMENT

This Restricted Unit Agreement (“Agreement”) between Kimbell Royalty GP, LLC (the “Company”) and _______ (the “Participant”), regarding an award (“Award”) of __________ Restricted Units (as defined in the Kimbell Royalty GP, LLC 2017 Long-Term Incentive Plan (the “Plan”)) granted to the Participant on January 29, 2018 (the “Grant Date”), such number of Restricted Units subject to adjustment as provided in the Plan, and further subject to the following terms and conditions:

1. Relationship to Plan . This Award is subject to all of the terms, conditions and provisions of the Plan and administrative interpretations thereunder, if any, which have been adopted by the Committee thereunder and are in effect on the date hereof. Except as otherwise provided herein, capitalized terms shall have the same meanings ascribed to them under the Plan.

2. Vesting Schedule. Except as otherwise provided herein or the Plan, the Restricted Units shall vest in one-third installments on each of April 2, 2019, April 2, 2020, and April 2, 2021, subject to the Participant’s Continuous Service (as defined below) through each applicable vesting date. The number of Restricted Units that vest as of each date described above will be rounded down to the nearest whole Restricted Unit, with any remaining Restricted Units to vest with the final installment. Notwithstanding the foregoing, if the Participant remains in Continuous Service as of the date of a Change in Control, any unvested Restricted Units will be vested as of the date of such Change in Control. For this purpose, “Change in Control” means, and shall be deemed to have occurred upon the occurrence of one or more of the following events: (i) any “person” or “group” within the meaning of those terms as used in Sections 13(d) and 14(d)(2) of the Exchange Act, other than Kimbell GP Holdings, LLC or their respective Affiliates, shall become the beneficial owner, by way of merger, consolidation, recapitalization, reorganization or otherwise, of 50% or more of the combined voting power of the equity interests in the Company or the Partnership; (ii) the limited partners of the Partnership approve, in one or a series of transactions, a plan of complete liquidation of the Partnership; (iii) the sale or other disposition by either the Company or the Partnership of all or substantially all of its assets in one or more transactions to any Person other than the Company or an Affiliate of the Company; or (iv) a transaction resulting in a Person other than the Company or an Affiliate of the Company being the general partner of the Partnership.

3. Forfeiture of Award. If the Participant’s Continuous Service terminates for any reason all unvested Restricted Units shall be immediately forfeited as of the date of the Participant’s termination; provided, however, the Restricted Units shall become fully vested with respect to all of the Restricted Units subject to this Award if the Participant’s Continuous Service is terminated due to death or Disability. For this purpose, “Continuous Service” means Participant’s uninterrupted status as an Employee, Consultant or Director of the Company or any Affiliate of the Company or the Partnership. For the avoidance of doubt, a transfer of service between Affiliates of the Company or the Partnership, or a transition between status as an Employee, Consultant or Director, shall not be deemed as termination of Continuous Service.

4. Delivery of Units; Rights as Unitholder . The Restricted Units will be evidenced, at the sole option and in the sole discretion of the Committee, either (i) in book-entry form in the Participant’s name in the Unit register of the Partnership maintained by the Partnership’s transfer agent or (ii) a unit certificate issued in the Participant’s name. The Participant shall have voting rights and shall be entitled to receive all distributions made by the Partnership as if such Restricted Units were Units free and clear of any restrictions. As soon as administratively feasible following the vesting of the Restricted Units, the restrictions on transfer of any vested Units shall lapse and the Units, if not previously forfeited pursuant to Section 3, will become freely transferable under this Agreement and the Plan, subject only to such further limitations on transfer, if any, as may exist under applicable law or any other agreement binding upon Participant.

5. Code Section 83(b) Election. The Participant shall be permitted to make an election under Section 83(b) of the Code, to include an amount in income in respect of the Award of Restricted Units in accordance with the requirements of Section 83(b) of the Code. If the Participant makes an election under Section 83(b) of the Code, the Participant hereby agrees to deliver a copy of such election to the Company promptly after filing such election with the Internal Revenue Service.

6. Assignment of Award. The Participant’s rights under this Agreement and the Plan are personal and no assignment or transfer of the Participant’s rights under and interest in this Award may be made by the Participant other than by will, by beneficiary designation, by the laws of descent and distribution or by a qualified domestic relations order. Except to the extent expressly permitted by the preceding sentence, any purported sale, pledge, assignment, transfer, attachment or encumbrance of the Restricted Units or any interest or right therein shall be null, void and unenforceable against the Partnership, the Company, and their respective Affiliates.

7. Withholding . No issuance of vested Units shall occur or be made pursuant to this Agreement until the Participant has paid or made arrangements approved by the Committee to satisfy all the Participant’s federal, state and other governmental withholding tax obligations. For purposes of this Section, unless the Participant makes other arrangements or is subsequently notified to the contrary, the Partnership or applicable Affiliate will satisfy the Participant’s obligations with respect to any tax withholding by withholding or repurchasing a number of vested Units having a then-Fair Market Value equal to such tax withholding obligations. With the consent of the Committee, the Participant may elect to have the Company withhold or purchase, as applicable, from Restricted Units that would otherwise vest or with respect to which an election under Section 83(b) of the Code has been made a number of Restricted Units with a Fair Market Value equal to the product of the maximum federal marginal rate that could be applicable to the Participant and the Fair Market Value of the Restricted Units otherwise vesting or delivered, as applicable.

8. No Guarantee of Continuous Service . No provision of this Agreement shall confer any right upon the Participant to Continuous Service.

9. Governing Law . This Agreement shall be governed by, construed, and enforced in accordance with the laws of the State of Delaware.

-2-

10. Amendment. This Agreement cannot be modified, altered or amended, except by an agreement, in writing, signed by both the Company and the Participant.

11. Clawback . Notwithstanding any provision in this Agreement to the contrary, to the extent required by (a) applicable law, including, without limitation, the requirements of the Dodd-Frank Wall Street Reform and Consumer Protection Act of 2010, any Securities and Exchange Commission rule or any applicable securities exchange listing standards and/or (b) any policy that may be adopted or amended by the Board from time to time, all Restricted Units granted hereunder shall be subject to forfeiture, repurchase, recoupment and/or cancellation to the extent necessary to comply with such law(s) and/or policy.

12. Counterparts . The Agreement may be executed in one or more counterparts, each of which shall be deemed an original and all of which together shall constitute one instrument. Delivery of an executed counterpart of the Agreement by facsimile or pdf attachment to electronic mail shall be effective as delivery of a manually executed counterpart of the Agreement.

13. Severability . If a court of competent jurisdiction determines that any provision of this Agreement is invalid or unenforceable, then the invalidity or unenforceability of such provision shall not affect the validity or enforceability of any other provision of this Agreement, and all other provisions shall remain in full force and effect.

14. Entire Agreement . The Plan and this Agreement represent the entire agreement between the Participant and the Company with respect to the subject matter hereof, and supersede and are in full substitution for any and all prior agreements or understandings, whether oral or written, relating to the subject matter hereof.

[signatures on next page]

-3-

		KIMBELL ROYALTY GP, LLC
Date: 1/30/18	By:
	Name:
	Title:

The Participant hereby accepts the foregoing Agreement, subject to the terms and provisions of the Plan and administrative interpretations thereof referred to above.

			PARTICIPANT:

Date:
			Participant Name & Signature

Signature Page to Restricted Unit Agreement

Exhibit 10.9

AMENDMENT NO. 1 TO THE

MANAGEMENT SERVICES AGREEMENT

THIS AMENDMENT NO. 1 TO THE MANAGEMENT SERVICES AGREEMENT (this “ Amendment ”) is executed on March 7, 2018, but made effective as of January 1, 2018 (the “ Effective Date ”) by and between Duncan Management, LLC, a Texas limited liability company (the “ Manager ”), and Kimbell Operating Company, LLC, a Delaware limited liability company (“ Kimbell Operating ”). The Manager and Kimbell Operating are sometimes referred to in this Amendment each as a “ Party ” and collectively as the “ Parties .”

W I T N E S S E T H:

WHEREAS , the Parties entered into that certain Management Services Agreement effective as of February 8, 2017 (the “ Management Services Agreement ”); and

WHEREAS , pursuant to Sections 3.5 and 13.2 of the Management Services Agreement, the Parties desire to amend the Management Services Agreement, as set forth herein.

ARTICLE I
AMENDMENT OF MANAGEMENT SERVICES AGREEMENT

Section 1.1 Definitions . Capitalized terms used but not defined in this Amendment shall have the meanings ascribed to such terms in the Management Services Agreement.

“As consideration for the Services rendered hereunder, Kimbell Operating shall pay to the Manager each month, in advance, a fee that shall represent a reasonable allocation of all projected costs (including its own overhead and general and administrative costs and expenses and those of its Affiliates) to be incurred by the Manager in providing such Services and that may be adjusted pursuant to Section 3.5 (the “ Services Fee ”). The Services Fee for the year ending December 31, 2018 shall be $43,498.42 per month. For the avoidance of doubt, in no event shall the Services Fee include any Tax passed on to Kimbell Operating pursuant to Section 3.4 hereof.”

ARTICLE II
MISCELLANEOUS

[ Signatures of the Parties follow on the next page. ]

IN WITNESS WHEREOF, the Parties have executed this Amendment on, and effective as of, the Effective Date:

DUNCAN MANAGEMENT, LLC

By:

/s/ Benny D. Duncan

Name: Benny D. Duncan

Title: Manager

KIMBELL OPERATING COMPANY, LLC

By:

/s/ Matthew S. Daly

Name: Matthew S. Daly

Title: Chief Operating Officer

Signature Page to Amendment No. 1

to Management Services Agreement

Exhibit 21.1

Subsidiaries of Kimbell Royalty Partners, LP


Entity Name		Jurisdiction
Kimbell Intermediate Holdings, LLC		Delaware
Kimbell Intermediate GP, LLC		Delaware
Kimbell Royalty Holdings, LLC		Delaware
Rivercrest Royalties, LLC		Delaware
Rochester Minerals, L.P.		Texas
Hochstetter, L.P.		Texas
Oakwood Minerals I, L.P.		Texas
RCPTX, Ltd.		Texas
OGM Partners I		Texas

Exhibit 23.1

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We have issued our report dated March 9, 2018, with respect to the consolidated financial statements included in the Annual Report of Kimbell Royalty Partners, LP on Form 10-K for the year ended December 31, 2017. We consent to the incorporation by reference of said report in the Registration Statement of Kimbell Royalty Partners, LP on Form S-8 (File No. 333-217986).

/s/ GRANT THORNTON LLP

Dallas, Texas

March 9, 2018

Exhibit 23.2

621 SEVENTEENTH STREET SUITE 1550 DENVER, COLORADO 80293 TELEPHONE (303) 623-9147

FAX (303) 623-4258

CONSENT OF INDEPENDENT PETROLEUM ENGINEERS

We hereby consent to the incorporation by reference in the registration statement on Form S-8 (Registration No. 333-217986) of Kimbell Royalty Partners, LP of our letter dated February 14, 2018, relating to estimates of proved reserves, future production and income attributable certain royalty interests of Kimbell Royalty Partners, LP as of December 31, 2017.

		/s/ Ryder Scott Company, L.P.
		RYDER SCOTT COMPANY, L.P.
		TBPE Firm Registration No. F-1580

Denver, Colorado

March 9, 2018

Exhibit 31.1

CERTIFICATION PURSUANT TO SECTION 302 OF

THE SARBANES-OXLEY ACT OF 2002

I, Robert D. Ravnaas, certify that:

I have reviewed this Annual Report on Form 10-K of Kimbell Royalty Partners, LP;

Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a)

Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b)

Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c)

Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d)

Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a)

All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b)

Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: March 9, 2018

/s/ Robert D. Ravnaas

Chief Executive Officer and Chairman of the Board of Directors of Kimbell Royalty GP, LLC, the general partner of Kimbell Royalty Partners, LP

(Principal Executive Officer)

Exhibit 31.2

CERTIFICATION PURSUANT TO SECTION 302 OF

THE SARBANES-OXLEY ACT OF 2002

I, R. Davis Ravnaas, certify that:

I have reviewed this Annual Report on Form 10-K of Kimbell Royalty Partners, LP;

(a)

(b)

(c)

(d)

(a)

(b)

Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: March 9, 2018

/s/ R. Davis Ravnaas

President and Chief Financial Officer of Kimbell Royalty GP, LLC the general partner of Kimbell Royalty Partners, LP

(Principal Financial Officer)

Exhibit 32.1

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Annual Report of Kimbell Royalty Partners, LP (the “Partnership”) on Form 10-K for the period ended December 31, 2017 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Robert D. Ravnaas, Chief Executive Officer and Chairman of the Board of Directors of Kimbell Royalty GP, LLC, the general partner of the Partnership, certify, pursuant to 18 U.S.C. §1350, as adopted pursuant to §906 of the Sarbanes-Oxley Act of 2002, that to the best of my knowledge:

(1) The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Partnership.

Date: March 9, 2018

/s/ Robert D. Ravnaas

Chief Executive Officer and Chairman of the Board of Directors of Kimbell Royalty GP, LLC, the general partner of Kimbell Royalty Partners, LP

(Principal Executive Officer)

Exhibit 32.2

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Annual Report of Kimbell Royalty Partners, LP (the “Partnership”) on Form 10-K for the period ended December 31, 2017 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, R. Davis Ravnaas, Chief Financial Officer of Kimbell Royalty GP, LLC, the general partner of the Partnership, certify, pursuant to 18 U.S.C. §1350, as adopted pursuant to §906 of the Sarbanes-Oxley Act of 2002, that to the best of my knowledge:

(1) The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Partnership.

Date: March 9, 2018

/s/ R. Davis Ravnaas

President and Chief Financial Officer of Kimbell Royalty GP, LLC, the general partner of Kimbell Royalty Partners, LP

(Principal Financial Officer)

Exhibit 99.1

KIMBELL ROYALTY PARTNERS, LP

Estimated

Future Reserves and Income

Attributable to Certain

Royalty Interests

SEC Parameters

As of

December 31, 2017

/s/ Scott Wilson /seal/

Scott J. Wilson, P.E., MBA

Colorado License No. 36112

Senior Vice President

RYDER SCOTT COMPANY, L.P.

TBPE Firm Registration No. F-1580

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS



TBPE REGISTERED ENGINEERING FIRM F-1580
621 SEVENTEENTH STREET SUITE 1550	DENVER, COLORADO 80293	TELEPHONE (303) 623-9147

February 14, 2018

Kimbell Royalty Partners, LP

777 Taylor Street, Suite 810

Fort Worth, Texas 76102

Gentlemen:

At your request, Ryder Scott Company, L.P. (Ryder Scott) has prepared an estimate of the proved reserves, future production, and income attributable to certain royalty interests of Kimbell Royalty Partners, LP, (KRP) as of December 31, 2017. The diverse inventory of royalty interests are located primarily in the state of Texas, but with other interests in 20 other states. The reserves and income data were estimated based on the definitions and disclosure guidelines of the United States Securities and Exchange Commission (SEC) contained in Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released January 14, 2009 in the Federal Register (SEC regulations). Our third party study, completed on February 14, 2018 and presented herein, was prepared for public disclosure by KRP in filings made with the SEC in accordance with the disclosure requirements set forth in the SEC regulations.

The properties evaluated by Ryder Scott represent 100 percent of the total net proved liquid hydrocarbon reserves and 100 percent of the total net proved gas reserves of KRP as of December 31, 2017.

The estimated reserves and future net income amounts presented in this report, as of December 31, 2017, are related to hydrocarbon prices. The hydrocarbon prices used in the preparation of this report are based on the average prices during the 12-month period prior to the “as of date” of this report, determined as the unweighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period, unless prices were defined by contractual arrangements, as required by the SEC regulations. Actual future prices may vary significantly from the prices required by SEC regulations; therefore, volumes of reserves actually recovered and the amounts of income actually received may differ significantly from the estimated quantities presented in this report. The results of this study are summarized as follows.

1100 LOUISIANA, SUITE 4600	HOUSTON, TEXAS 77002-5218	TEL (713) 651-9191	FAX (713) 651-0849
1015 4TH STREET S.W. SUITE 600	CALGARY, ALBERTA T2R 1J4	TEL (403) 262-2799	FAX (403) 262-2790

Kimbell Royalty Partners, LP

February 14, 2018

Page 2

SEC PARAMETERS

Estimated Net Reserves and Income Data

Certain Royalty Interests of

Kimbell Royalty Partners, LP

As of December 31, 2017

	Proved
	Developed						Total
	Producing		Non-Producing		Undeveloped		Proved
Net Remaining Reserves
Oil/Condensate – MBarrels		5,261		23		2,179		7,463
Plant Products – MBarrels		2,186		16		636		2,838
Gas – MMCF		47,166		335		16,415		63,916

Income Data ($M)
Future Gross Revenue	$	385,362	$	2,134	$	147,046	$	534,542
Deductions		12,368		51		4,807		17,226
Future Net Income (FNI)	$	372,994	$	2,083	$	142,239	$	517,316

Discounted FNI @ 10%	$	165,111	$	1,187	$	52,045	$	218,343

Liquid hydrocarbons are expressed in standard 42 gallon barrels and shown herein as thousands of barrels (MBarrels). All gas volumes are reported on an “as sold” basis expressed in millions of cubic feet (MMCF) at the official temperature and pressure bases of the areas in which the gas reserves are located. In this report, the revenues, deductions, and income data are expressed as thousands of U.S. dollars ($M).

The estimates of the reserves, future production, and income attributable to properties in this report were prepared using the economic software package ARIES TM Petroleum Economics and Reserves Software, a copyrighted program of Halliburton. Ryder Scott has found this program to be generally acceptable, but notes that certain summaries and calculations may vary due to rounding and may not exactly match the sum of the properties being summarized. Furthermore, one line economic summaries may vary slightly from the more detailed cash flow projections of the same properties, also due to rounding. The rounding differences are not material.

The future gross revenue is after the deduction of production taxes. Since the evaluation includes only royalty interests there are only deductions for ad valorem taxes, while the normal direct costs of operating the wells, recompletion costs, and development costs are used only to estimate economic lives. The future net income is before the deduction of general administrative overhead, and has not been adjusted for outstanding loans that may exist nor does it include any adjustment for cash on hand or undistributed income.

Liquid hydrocarbon reserves account for approximately 73 percent and gas reserves account for the remaining 27 percent of total future gross revenue from proved reserves.

The discounted future net income shown above was calculated using a discount rate of 10 percent per annum compounded monthly. Future net income was discounted at five other discount rates which were also compounded monthly. These results are shown in summary form as follows.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

Kimbell Royalty Partners, LP

February 14, 2018

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		Discounted Future Net Income ($M)
		As of December 31, 2017
Discount Rate		Total
Percent		Proved

5		$306,800
15		$170,588
20		$140,720
25		$120,258
30		$105,358

The results shown above are presented for your information and should not be construed as our estimate of fair market value.

Reserves Included in This Report

The proved reserves included herein conform to the definitions as set forth in the Securities and Exchange Commission’s Regulations Part 210.4-10(a). An abridged version of the SEC reserves definitions from 210.4-10(a) entitled “Petroleum Reserves Definitions” is included as an attachment to this report.

The various reserve status categories are defined under the attachment entitled “Petroleum Reserves Status Definitions and Guidelines” in this report. The proved developed non-producing reserves included herein consist of the behind pipe category.

No attempt was made to quantify or otherwise account for any accumulated gas production imbalances that may exist. The proved gas volumes presented herein do not include volumes of gas consumed in operations as reserves.

Reserves are “estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations.” All reserve estimates involve an assessment of the uncertainty relating the likelihood that the actual remaining quantities recovered will be greater or less than the estimated quantities determined as of the date the estimate is made. The uncertainty depends chiefly on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data. The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved. Unproved reserves are less certain to be recovered than proved reserves and may be further sub-classified as probable and possible reserves to denote progressively increasing uncertainty in their recoverability. At KRP’s request, this report addresses only the proved reserves attributable to the properties evaluated herein.

Proved oil and gas 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.” The proved reserves included herein were estimated using deterministic methods. The SEC has defined reasonable certainty for proved reserves, when based on deterministic methods, as a “high degree of confidence that the quantities will be recovered.”

Reserve estimates will generally be revised only as additional geologic or engineering data become available or as economic conditions change. For proved reserves, the SEC states that “as changes due to increased availability of geoscience (geological, geophysical, and geochemical),

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February 14, 2018

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engineering, and economic data are made to the estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.” Moreover, estimates of proved reserves may be revised as a result of future operations, effects of regulation by governmental agencies or geopolitical or economic risks. Therefore, the proved reserves included in this report are estimates only and should not be construed as being exact quantities, and if recovered, the revenues therefrom, and the actual costs related thereto, could be more or less than the estimated amounts.

KRP’s operations may be subject to various levels of governmental controls and regulations. These controls and regulations may include, but may not be limited to, matters relating to land tenure and leasing, the legal rights to produce, drilling and production practices, environmental protection, marketing and pricing policies, royalties, various taxes and levies including income tax, and are subject to change from time to time. Such changes in governmental regulations and policies may cause volumes of proved reserves actually recovered and amounts of proved income actually received to differ significantly from the estimated quantities.

The estimates of proved reserves presented herein were based upon a detailed study of the properties in which KRP owns a royalty interest; however, we have not made any field examination of the properties. No consideration was given in this report to potential environmental liabilities that may exist nor were any costs included for potential liabilities to restore and clean up damages, if any, caused by past operating practices.

Estimates of Reserves

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 set forth by the Securities and Exchange Commission’s Regulations Part 210.4-10(a). 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 individually or in combination by the reserve evaluator in the process of estimating the quantities of reserves. Reserve evaluators must select the method or combination of methods which in their professional judgment is most appropriate given the nature and amount of reliable geoscience and engineering data available at the time of the estimate, the established or anticipated performance characteristics of the reservoir being evaluated, and the stage of development or producing maturity of the property.

In many cases, the analysis of the available geoscience and engineering data and the subsequent interpretation of this data may indicate a range of possible outcomes in an estimate, irrespective of the method selected by the evaluator. When a range in the quantity of reserves is identified, the evaluator must determine the uncertainty associated with the incremental quantities of the reserves. If the reserve quantities are estimated using the deterministic incremental approach, the uncertainty for each discrete incremental quantity of the reserves is addressed by the reserve category assigned by the evaluator. Therefore, it is the categorization of reserve quantities as proved, probable and/or possible that addresses the inherent uncertainty in the estimated quantities reported. For proved reserves, uncertainty is defined by the SEC as reasonable certainty wherein the “quantities actually recovered are much more likely than not to be achieved.” The SEC states that “probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.” The SEC states that

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February 14, 2018

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“possible reserves are those additional reserves that are less certain to be recovered than probable reserves and the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves.” All quantities of reserves within the same reserve category must meet the SEC definitions as noted above.

Estimates of reserves quantities and their associated reserve categories may be revised in the future as additional geoscience or engineering data become available. Furthermore, estimates of reserves quantities and their associated reserve categories may also be revised due to other factors such as changes in economic conditions, results of future operations, effects of regulation by governmental agencies or geopolitical or economic risks as previously noted herein.

The proved reserves for the properties included herein were estimated by performance methods or analogy. One hundred percent of the proved producing reserves attributable to producing wells and/or reservoirs were estimated by performance methods. These performance methods include decline curve analysis which utilized extrapolations of historical production and pressure data available through October 2017 in those cases where such data were and considered to be definitive. The data utilized in this analysis were furnished to Ryder Scott by KRP and were considered sufficient for the purpose thereof.

One hundred percent of the proved developed non-producing and undeveloped reserves included herein were estimated by analogy. The data utilized from the analogues were considered sufficient for the purpose thereof.

To estimate economically recoverable proved oil and gas reserves and related future net cash flows, we consider many factors and assumptions including, but not limited to, the use of reservoir parameters derived from geological, geophysical and engineering data which cannot be measured directly, economic criteria based on current costs and SEC pricing requirements, and forecasts of future production rates. Under the SEC regulations 210.4-10(a)(22)(v) and (26), proved reserves must be anticipated to be economically producible from a given date forward based on existing economic conditions including the prices and costs at which economic producibility from a reservoir is to be determined. While it may reasonably be anticipated that the future prices received for the sale of production and the operating costs and other costs relating to such production may increase or decrease from those under existing economic conditions, such changes were, in accordance with rules adopted by the SEC, omitted from consideration in making this evaluation.

KRP has informed us that they have furnished us all of the material accounts, records, geological and engineering data, and reports and other data required for this investigation. In preparing our forecast of future proved production and income, we have relied upon data furnished by KRP with respect to property interests owned, production and well tests from examined wells, normal direct costs of operating the wells or leases, other costs such as transportation and/or processing fees, ad valorem and production taxes, recompletion and development costs, development plans, abandonment costs after salvage, product prices based on the SEC regulations, adjustments or differentials to product prices, geological structural and isochore maps, well logs, core analyses, and pressure measurements. Ryder Scott reviewed such factual data for its reasonableness; however, we have not conducted an independent verification of the data furnished by KRP. We consider the factual data used in this report appropriate and sufficient for the purpose of preparing the estimates of reserves and future net revenues herein.

In summary, we consider the assumptions, data, methods and analytical procedures used in this report appropriate for the purpose hereof, and we have used all such methods and procedures that we consider necessary and appropriate to prepare the estimates of reserves herein. The proved

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February 14, 2018

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reserves included herein were determined in conformance with the United States Securities and Exchange Commission (SEC) Modernization of Oil and Gas Reporting; Final Rule, including all references to Regulation S-X and Regulation S-K, referred to herein collectively as the “SEC Regulations.” In our opinion, the proved reserves presented in this report comply with the definitions, guidelines and disclosure requirements as required by the SEC regulations.

Future Production Rates

For wells currently on production, our forecasts of future production rates are based on historical performance data. If no production decline trend has been established, future production rates were held constant, or adjusted for the effects of curtailment where appropriate, until a decline in ability to produce was anticipated. An estimated rate of decline was then applied to depletion of the reserves. If a decline trend has been established, this trend was used as the basis for estimating future production rates.

Test data and other related information were used to estimate the anticipated initial production rates for those wells or locations that are not currently producing. For reserves not yet on production, sales were estimated to commence at an anticipated date furnished by KRP. Wells or locations that are not currently producing may start producing earlier or later than anticipated in our estimates due to unforeseen factors causing a change in the timing to initiate production. Such factors may include delays due to weather, the availability of rigs, the sequence of drilling, completing and/or recompleting wells and/or constraints set by regulatory bodies.

The future production rates from wells currently on production or wells or locations that are not currently producing may be more or less than estimated because of changes including, but not limited to, reservoir performance, operating conditions related to surface facilities, compression and artificial lift, pipeline capacity and/or operating conditions, producing market demand and/or allowables or other constraints set by regulatory bodies.

Hydrocarbon Prices

The hydrocarbon prices used herein are based on SEC price parameters using the average prices during the 12-month period prior to the “as of date” of this report, determined as the unweighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period, unless prices were defined by contractual arrangements. For hydrocarbon products sold under contract, the contract prices, including fixed and determinable escalations, exclusive of inflation adjustments, were used until expiration of the contract. Upon contract expiration, the prices were adjusted to the 12-month unweighted arithmetic average as previously described.

KRP furnished us with the above mentioned average prices in effect on December 31, 2017. These initial SEC hydrocarbon prices were determined using the 12-month average first-day-of-the-month benchmark prices appropriate to the geographic area where the hydrocarbons are sold. These benchmark prices are prior to the adjustments for differentials as described herein. The table below summarizes the “benchmark prices” and “price reference” used for the geographic area included in the report. In certain geographic areas, the price reference and benchmark prices may be defined by contractual arrangements

The product prices which were actually used to determine the future gross revenue for each property reflect adjustments to the benchmark prices for gravity, quality, local conditions, and/or

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

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February 14, 2018

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distance from market, referred to herein as “differentials.” The differentials used in the preparation of this report were furnished to us by KRP. The differentials furnished to us were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of the data used by KRP to determine these differentials.

In addition, the table below summarizes the net volume weighted benchmark prices adjusted for differentials and referred to herein as the “average realized prices.” The average realized prices shown in the table below were determined from the total future gross revenue before production taxes and the total net reserves for the geographic area and presented in accordance with SEC disclosure requirements for each of the geographic areas included in the report.

Geographic Area	Product	Price Reference	Average Benchmark Prices	Average Proved Realized Prices
North America
	Oil/Condensate	WTI Cushing	$51.34/BBL	$47.85/BBL
United States	Plant Products	WTI Cushing	$51.34/BBL	$19.26/BBL
	Gas	Henry Hub	$2.98/MMBTU	$2.37/MCF

The effects of derivative instruments designated as price hedges of oil and gas quantities are not reflected in our individual property evaluations.

Costs

Estimated operating costs for the leases and wells in this report were furnished by KRP and are based on the operating expense reports of the operators of the properties and include only those costs directly applicable to the leases or wells. Because these are not working interests, no operating costs are included for KRP’s interests, but are considered in estimates to accurately reflect economic lives of each entity. The operating costs furnished to us were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of the operating cost data used by KRP. No deduction was made for loan repayments, interest expenses, or exploration and development prepayments that were not charged directly to the leases or wells.

Development costs were not incorporated into these cash flows since KRP does not own working interests. Typical development costs were considered when reviewing the estimates of undeveloped inventory which includes new development in basins with a historical record of continuous development and used similarly as the operating costs in determining these are economically recoverable reserves.

The proved developed non-producing and undeveloped reserves in this report have been incorporated herein in accordance with KRP’s estimates of the operator’s expectations to develop these reserves as of December 31, 2017. Development activities are subject to specific operator and partner AFE processes, Joint Operating Agreement (JOA) requirements or other administrative approvals external to KRP. Additionally, KRP has informed us that they are not aware of any legal, regulatory, or political obstacles that would significantly alter their estimates of development plans. While these plans could change from those under existing economic conditions as of December 31, 2017, such changes

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February 14, 2018

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were, in accordance with rules adopted by the SEC, omitted from consideration in making this evaluation.

Current costs used by KRP were held constant throughout the life of the properties.

Standards of Independence and Professional Qualification

Ryder Scott is an independent petroleum engineering consulting firm that has been providing petroleum consulting services throughout the world since 1937. Ryder Scott is employee-owned and maintains offices in Houston, Texas; Denver, Colorado; and Calgary, Alberta, Canada. We have over eighty engineers and geoscientists on our permanent staff. By virtue of the size of our firm and the large number of clients for which we provide services, no single client or job represents a material portion of our annual revenue. We do not serve as officers or directors of any privately-owned or publicly-traded oil and gas company and are separate and independent from the operating and investment decision-making process of our clients. This allows us to bring the highest level of independence and objectivity to each engagement for our services.

Ryder Scott actively participates in industry-related professional societies and organizes an annual public forum focused on the subject of reserves evaluations and SEC regulations. Many of our staff have authored or co-authored technical papers on the subject of reserves related topics. We encourage our staff to maintain and enhance their professional skills by actively participating in ongoing continuing education.

Prior to becoming an officer of the Company, Ryder Scott requires that staff engineers and geoscientists have received professional accreditation in the form of a registered or certified professional engineer’s license or a registered or certified professional geoscientist’s license, or the equivalent thereof, from an appropriate governmental authority or a recognized self-regulating professional organization.

We are independent petroleum engineers with respect to KRP. Neither we nor any of our employees have any financial interest in the subject properties and neither the employment to do this work nor the compensation is contingent on our estimates of reserves for the properties which were reviewed.

The results of this study, presented herein, are based on technical analysis conducted by teams of geoscientists and engineers from Ryder Scott. The professional qualifications of the undersigned, the technical person primarily responsible for overseeing the evaluation of the reserves information discussed in this report, are included as an attachment to this letter.

Terms of Usage

The results of our third party study, presented in report form herein, were prepared in accordance with the disclosure requirements set forth in the SEC regulations and intended for public disclosure as an exhibit in filings made with the SEC.

We have provided KRP with a digital version of the original signed copy of this report letter. In the event there are any differences between the digital version included in filings made by KRP and the original signed report letter, the original signed report letter shall control and supersede the digital version.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

Kimbell Royalty Partners, LP

February 14, 2018

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The data and work papers used in the preparation of this report are available for examination by authorized parties in our offices. Please contact us if we can be of further service.

	Very truly yours,

	RYDER SCOTT COMPANY, L.P.
	TBPE Firm Registration No. F-1580

	/s/ Scott Wilson /seal/

	Scott J. Wilson, P.E., MBA
	Colorado License No. 36112
	Senior Vice President

SJW (FWZ)/pl

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

Professional Qualifications of Primary Technical Person

The conclusions presented in this report are the result of technical analysis conducted by teams of geoscientists and engineers from Ryder Scott Company, L.P. Mr. Scott James Wilson was the primary technical person responsible for the estimate of the reserves, future production, and income presented herein.

Mr. Wilson, an employee of Ryder Scott Company, L.P. (Ryder Scott) since 2000, is a Senior Vice President responsible for coordinating and supervising staff and consulting engineers of the company in ongoing reservoir evaluation studies worldwide. Before joining Ryder Scott, Mr. Wilson served in a number of engineering positions with Atlantic Richfield Company. For more information regarding Mr. Wilson's geographic and job specific experience, please refer to the Ryder Scott Company website at http://www.ryderscott.com/Experience/Employees.

Mr. Wilson earned a Bachelor of Science degree in Petroleum Engineering from the Colorado School of Mines in 1983 and an MBA in Finance from the University of Colorado in 1985, graduating from both with High Honors. He is a registered Professional Engineer by exam in the States of Alaska, Colorado, Texas and Wyoming. He is also an active member of the Society of Petroleum Engineers; serving as co-Chairman of the SPE Reserves and Economics Technology Interest Group, and Gas Technology Editor for SPE's Journal of Petroleum Technology. He is a member and past chairman of the Denver section of the Society of Petroleum Evaluation Engineers. Mr. Wilson has published several technical papers and is the primary inventor of three US patents.

In addition to gaining experience and competency through prior work experience, the Wyoming Board of Professional Engineers requires a minimum of fifteen hours of continuing education annually, including at least one hour in the area of professional ethics, which Mr. Wilson fulfills. As part of his continuing education hours, Mr. Wilson attended an internally presented sixteen hours of formalized training as well as a public forum relating to the definitions and disclosure guidelines contained in the United States Securities and Exchange Commission Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released January 14, 2009 in the Federal Register. Mr. Wilson attended additional hours of formalized external training covering such topics as the SPE/WPC/AAPG/SPEE Petroleum Resources Management System, reservoir engineering and petroleum economics evaluation methods, procedures and software and ethics for consultants.

Based on his educational background, professional training and more than 30 years of practical experience in the estimation and evaluation of petroleum reserves, Mr. Wilson has attained the professional qualifications as a Reserves Estimator and Reserves Auditor set forth in Article III of the “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information” promulgated by the Society of Petroleum Engineers as of February 19, 2007.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

PETROLEUM RESERVES DEFINITIONS

As Adapted From:

RULE 4-10(a) of REGULATION S-X PART 210

UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC)

PREAMBLE

On January 14, 2009, the United States Securities and Exchange Commission (SEC) published the “Modernization of Oil and Gas Reporting; Final Rule” in the Federal Register of National Archives and Records Administration (NARA). The “Modernization of Oil and Gas Reporting; Final Rule” includes revisions and additions to the definition section in Rule 4-10 of Regulation S-X, revisions and additions to the oil and gas reporting requirements in Regulation S-K, and amends and codifies Industry Guide 2 in Regulation S-K. The “Modernization of Oil and Gas Reporting; Final Rule”, including all references to Regulation S-X and Regulation S-K, shall be referred to herein collectively as the “SEC regulations”. The SEC regulations take effect for all filings made with the United States Securities and Exchange Commission as of December 31, 2009, or after January 1, 2010. Reference should be made to the full text under Title 17, Code of Federal Regulations, Regulation S-X Part 210, Rule 4-10(a) for the complete definitions (direct passages excerpted in part or wholly from the aforementioned SEC document are denoted in italics herein).

Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. All reserve estimates involve an assessment of the uncertainty relating the likelihood that the actual remaining quantities recovered will be greater or less than the estimated quantities determined as of the date the estimate is made. The uncertainty depends chiefly on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data. The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved. Unproved reserves are less certain to be recovered than proved reserves and may be further sub-classified as probable and possible reserves to denote progressively increasing uncertainty in their recoverability. Under the SEC regulations as of December 31, 2009, or after January 1, 2010, a company may optionally disclose estimated quantities of probable or possible oil and gas reserves in documents publicly filed with the SEC. The SEC regulations continue to prohibit disclosure of estimates of oil and gas resources other than reserves and any estimated values of such resources in any document publicly filed with the SEC unless such information is required to be disclosed in the document by foreign or state law as noted in §229.1202 Instruction to Item 1202.

Reserves estimates will generally be revised only as additional geologic or engineering data become available or as economic conditions change.

Reserves may be attributed to either natural energy or improved recovery methods. Improved recovery methods include all methods for supplementing natural energy or altering natural forces in the reservoir to increase ultimate recovery. Examples of such methods are pressure maintenance, natural gas cycling, waterflooding, thermal methods, chemical flooding, and the use of miscible and immiscible displacement fluids. Other improved recovery methods may be developed in the future as petroleum technology continues to evolve.

Reserves may be attributed to either conventional or unconventional petroleum accumulations. Petroleum accumulations are considered as either conventional or unconventional based on the nature of their in-place characteristics, extraction method applied, or degree of processing prior to sale.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

PETROLEUM RESERVES DEFINITIONS

Page 2

Examples of unconventional petroleum accumulations include coalbed or coalseam methane (CBM/CSM), basin-centered gas, shale gas, gas hydrates, natural bitumen and oil shale deposits. These unconventional accumulations may require specialized extraction technology and/or significant processing prior to sale.

Reserves do not include quantities of petroleum being held in inventory.

Because of the differences in uncertainty, caution should be exercised when aggregating quantities of petroleum from different reserves categories.

RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(26) defines reserves as follows:

Reserves. Reserves are estimated remaining quantities of oil and 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 gas or related substances to market, and all permits and financing required to implement the project.

Note to paragraph (a)(26): 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).

PROVED RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(22) defines proved oil and gas reserves as follows:

Proved oil and gas reserves. Proved oil and gas 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—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. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

(i) The area of the reservoir considered as proved includes:

(A) The area identified by drilling and limited by fluid contacts, if any, and

(B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

PETROLEUM RESERVES DEFINITIONS

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PROVED RESERVES (SEC DEFINITIONS) CONTINUED

(ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.

(iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.

(iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:

(A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and

(B) The project has been approved for development by all necessary parties and entities, including governmental entities.

(v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

PETROLEUM RESERVES STATUS DEFINITIONS AND GUIDELINES

As Adapted From:

RULE 4-10(a) of REGULATION S-X PART 210

UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC)

and

PETROLEUM RESOURCES MANAGEMENT SYSTEM (SPE-PRMS)