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KRP Kimbell Royalty Partners

Filed: 6 May 21, 4:01pm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended March 31, 2021

OR

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 Act:

Title of each class:

Trading symbol(s)

Name of exchange on which registered:

Common Units Representing Limited Partner Interests

KRP

New York Stock Exchange

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 every Interactive Data File required to be submitted 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 such files). Yes   No 

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, 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 

As of April 30, 2021, the registrant had outstanding 39,748,270 common units representing limited partner interests and 20,779,781 Class B units representing limited partner interests.

PART I – FINANCIAL INFORMATION

Item 1. Condensed Consolidated Financial Statements (Unaudited)

KIMBELL ROYALTY PARTNERS, LP

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)

March 31, 

December 31, 

2021

2020

ASSETS

Current assets

Cash and cash equivalents

$

8,124,335

$

9,804,977

Oil, natural gas and NGL receivables

24,768,091

17,552,756

Accounts receivable and other current assets

1,557,818

973,956

Total current assets

34,450,244

28,331,689

Property and equipment, net

2,111,648

1,964,660

Investment in affiliate (equity method)

5,048,254

5,134,951

Oil and natural gas properties

Oil and natural gas properties, using full cost method of accounting ($208,157,655 and $225,681,626 excluded from depletion at March 31, 2021 and December 31, 2020, respectively)

1,149,587,975

1,149,095,232

Less: accumulated depreciation, depletion and impairment

(635,786,468)

(628,102,279)

Total oil and natural gas properties, net

513,801,507

520,992,953

Right-of-use assets, net

3,071,305

3,123,454

Derivative assets

697,068

Loan origination costs, net

4,799,491

5,086,486

Total assets

$

563,979,517

$

564,634,193

LIABILITIES, MEZZANINE EQUITY AND UNITHOLDERS' EQUITY

Current liabilities

Accounts payable

$

1,042,416

$

888,735

Other current liabilities

3,672,874

4,765,161

Derivative liabilities

11,112,053

3,113,178

Total current liabilities

15,827,343

8,767,074

Operating lease liabilities, excluding current portion

2,796,946

2,848,452

Derivative liabilities

8,540,050

3,167,685

Long-term debt

168,534,231

171,550,142

Total liabilities

195,698,570

186,333,353

Commitments and contingencies (Note 15)

Mezzanine equity:

Series A preferred units (55,000 units issued and outstanding as of March 31, 2021 and December 31, 2020)

43,281,567

42,666,102

Unitholders' equity:

Common units (39,769,896 units and 38,918,689 units issued and outstanding as of March 31, 2021 and December 31, 2020, respectively)

251,263,288

257,593,307

Class B units (20,779,781 units issued and outstanding as of March 31, 2021 and December 31, 2020, respectively)

1,038,989

1,038,989

Total unitholders' equity

252,302,277

258,632,296

Noncontrolling interest

72,697,103

77,002,442

Total equity

324,999,380

335,634,738

Total liabilities, mezzanine equity and unitholders' equity

$

563,979,517

$

564,634,193

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

1

KIMBELL ROYALTY PARTNERS, LP

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

Three Months Ended March 31, 

2021

2020

Revenue

Oil, natural gas and NGL revenues

$

36,368,510

$

25,585,439

Lease bonus and other income

186,308

229,319

(Loss) gain on commodity derivative instruments, net

(14,135,728)

10,132,613

Total revenues

22,419,090

35,947,371

Costs and expenses

Production and ad valorem taxes

2,431,830

1,621,743

Depreciation and depletion expense

7,911,148

13,270,683

Impairment of oil and natural gas properties

70,925,731

Marketing and other deductions

3,295,286

2,131,552

General and administrative expense

6,796,385

6,524,311

Total costs and expenses

20,434,649

94,474,020

Operating income (loss)

1,984,441

(58,526,649)

Other income (expense)

Equity income in affiliate

185,080

163,554

Interest expense

(2,095,098)

(1,421,304)

Other income

462,771

Net income (loss) before income taxes

537,194

(59,784,399)

Provision for income taxes

Net income (loss)

537,194

(59,784,399)

Distribution and accretion on Series A preferred units

(1,577,968)

(3,076,684)

Net loss and distributions and accretion on Series A preferred units attributable to noncontrolling interests

357,179

23,584,856

Distribution on Class B units

(20,780)

(24,807)

Net loss attributable to common units

$

(704,375)

$

(39,301,034)

Net loss attributable to common units

Basic

$

(0.02)

$

(1.29)

Diluted

$

(0.02)

$

(1.29)

Weighted average number of common units outstanding

Basic

37,693,469

30,528,819

Diluted

37,693,469

30,528,819

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

2

KIMBELL ROYALTY PARTNERS, LP

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN UNITHOLDERS’ EQUITY

(Unaudited)

Three Months Ended March 31, 2021

Noncontrolling

   

Common Units

   

Amount

   

Class B Units

   

Amount

Interest

Total

Balance at January 1, 2021

38,918,689

$

257,593,307

20,779,781

$

1,038,989

$

77,002,442

$

335,634,738

Restricted units repurchased for tax withholding

(85,360)

(923,587)

(923,587)

Unit-based compensation

936,567

2,692,494

2,692,494

Distributions to unitholders

(7,394,551)

(3,948,160)

(11,342,711)

Distribution and accretion on Series A preferred units

(1,036,432)

(541,536)

(1,577,968)

Distribution on Class B units

(20,780)

(20,780)

Net income

352,837

184,357

537,194

Balance at March 31, 2021

39,769,896

$

251,263,288

20,779,781

$

1,038,989

$

72,697,103

$

324,999,380

Three Months Ended March 31, 2020

Noncontrolling

   

Common Units

   

Amount

   

Class B Units

   

Amount

Interest

Total

Balance at January 1, 2020

23,518,652

$

282,549,841

25,557,606

$

1,277,880

$

281,157,393

$

564,985,114

Common units issued for equity offering

5,000,000

73,601,668

73,601,668

Conversion of Class B units to common units

4,913,559

75,578,037

(4,913,559)

(245,678)

(75,578,037)

(245,678)

Redemption of Series A preferred units

(16,150,018)

(9,697,873)

(25,847,891)

Unit-based compensation

946,638

2,107,587

2,107,587

Distributions to unitholders

(11,122,088)

(9,616,966)

(20,739,054)

Distribution and accretion on Series A preferred units

(1,922,344)

(1,154,340)

(3,076,684)

Distribution on Class B units

(24,807)

(24,807)

Net loss

(37,353,883)

(22,430,516)

(59,784,399)

Balance at March 31, 2020

34,378,849

$

367,263,993

20,644,047

$

1,032,202

$

162,679,661

$

530,975,856

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

3

KIMBELL ROYALTY PARTNERS, LP

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

Three Months Ended March 31, 

2021

   

2020

CASH FLOWS FROM OPERATING ACTIVITIES

Net income (loss)

$

537,194

$

(59,784,399)

Adjustments to reconcile net income (loss) to net cash provided by operating activities:

Depreciation and depletion expense

7,911,148

13,270,683

Impairment of oil and natural gas properties

70,925,731

Amortization of right-of-use assets

71,785

67,470

Amortization of loan origination costs

371,487

266,318

Equity income in affiliate

(185,080)

(163,554)

Cash distribution from affiliate

216,738

Unit-based compensation

2,692,494

2,107,587

Loss (gain) on derivative instruments, net of settlements

12,674,172

(8,978,861)

Changes in operating assets and liabilities:

Oil, natural gas and NGL receivables

(7,215,335)

4,913,049

Accounts receivable and other current assets

(583,862)

(508,985)

Accounts payable

153,681

(450,579)

Other current liabilities

(1,092,287)

(809,594)

Operating lease liabilities

(71,142)

(67,260)

Net cash provided by operating activities

15,480,993

20,787,606

CASH FLOWS FROM INVESTING ACTIVITIES

Purchases of property and equipment

(373,947)

(40,596)

Purchase of oil and natural gas properties

(492,743)

(197,700)

Deposits on oil and natural gas properties

(9,681,408)

Investment in affiliate

(1,274,900)

Cash distribution from affiliate

55,039

17,961

Net cash used in investing activities

(811,651)

(11,176,643)

CASH FLOWS FROM FINANCING ACTIVITIES

Proceeds from equity offering

73,601,668

Redemption of Class B contributions on converted units

(245,678)

Redemption on Series A preferred units

(61,089,600)

Distributions to common unitholders

(7,394,551)

(11,122,088)

Distribution to OpCo unitholders

(3,948,160)

(9,616,966)

Distribution and accretion on Series A preferred units

(962,503)

(1,925,000)

Distribution on Class B units

(20,780)

(24,807)

Borrowings on long-term debt

484,089

71,088,125

Repayments on long-term debt

(3,500,000)

(70,000,000)

Payment of loan origination costs

(84,492)

Restricted units repurchased for tax withholding

(923,587)

Net cash used in financing activities

(16,349,984)

(9,334,346)

NET (DECREASE) INCREASE IN CASH AND CASH EQUIVALENTS

(1,680,642)

276,617

CASH AND CASH EQUIVALENTS, beginning of period

9,804,977

14,204,250

CASH AND CASH EQUIVALENTS, end of period

$

8,124,335

$

14,480,867

Supplemental cash flow information:

Cash paid for interest

$

1,673,361

$

1,126,666

Non-cash investing and financing activities:

Non-cash deemed distribution to Series A preferred units

$

615,465

$

1,151,684

Noncash effect of Series A preferred unit redemption

$

$

25,847,891

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

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KIMBELL ROYALTY PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Unless the context otherwise requires, references to “Kimbell Royalty Partners, LP,” the “Partnership,” or like terms refer to Kimbell Royalty Partners, LP and its subsidiaries. References to the “Operating Company” refer to Kimbell Royalty Operating, LLC. References to the “General Partner” refer to Kimbell Royalty GP, LLC. References to “Kimbell Operating” refer to Kimbell Operating Company, LLC, a wholly owned subsidiary of the General Partner. References to the “Sponsors” refer to affiliates of the Partnership’s founders, Ben J. Fortson, Robert D. Ravnaas, Brett G. Taylor and Mitch S. Wynne, respectively. References to the “Contributing Parties” refer to all entities and individuals, including certain affiliates of the Sponsors, that contributed, directly or indirectly, certain mineral and royalty interests to the Partnership.

NOTE 1—ORGANIZATION AND BASIS OF PRESENTATION

Organization

Kimbell Royalty Partners, LP is 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. Effective as of September 24, 2018, the Partnership has elected to be taxed as a corporation for United States federal income tax purposes. 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 natural gas liquids (“NGL”) from the acreage underlying its interests, net of post-production expenses and taxes. The Partnership is 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. The Partnership’s primary business objective is to provide increasing cash distributions to unitholders resulting from acquisitions from third parties, its Sponsors and the Contributing Parties and from organic growth through the continued development by working interest owners of the properties in which it owns an interest.

Basis of Presentation

The accompanying unaudited interim condensed consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States (“GAAP”) for interim financial information and with the instructions to Form 10-Q and pursuant to the rules and regulations of the U.S. Securities and Exchange Commission. As a result, the accompanying unaudited interim condensed consolidated financial statements do not include all disclosures required for complete annual financial statements prepared in conformity with GAAP. Accordingly, the accompanying unaudited interim condensed consolidated financial statements and related notes should be read in conjunction with the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2020, which contains a summary of the Partnership’s significant accounting policies and other disclosures. In the opinion of management of the General Partner, the unaudited interim condensed consolidated financial statements contain all adjustments necessary to fairly present the financial position and results of operations for the interim periods in accordance with GAAP and all adjustments are of a normal recurring nature. All material intercompany balances and transactions are eliminated in consolidation. The results of operations for any interim period are not necessarily indicative of the results to be expected for the full year.

Preparation of the Partnership’s financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts in the financial statements and notes. Actual results could differ from those estimates.

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.

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KIMBELL ROYALTY PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

COVID-19 Pandemic and Impact on Global Demand for Oil and Natural Gas

The global spread of coronavirus (“COVID-19”) created significant volatility, uncertainty, and economic disruption beginning in the first three months of 2020. On March 11, 2020, the World Health Organization (the “WHO”) declared the ongoing COVID-19 outbreak a pandemic and recommended containment and mitigation measures worldwide. The pandemic has reached more than 200 countries and has resulted in widespread adverse impacts on the global economy, the Partnership’s oil, natural gas, and NGL operators and other parties with whom the Partnership has business relations, including a significant reduction in the global demand for oil and natural gas. This significant decline in demand accelerated following the announcement of price reductions and production increases in March 2020 by members of the Organization of Petroleum Exporting Countries (“OPEC”) and other foreign, oil-exporting countries, raising concerns about global storage capacity. The resulting supply and demand imbalance led to a significantly weaker outlook for oil and gas producers in 2020.

The Partnership has modified certain business practices (including those related to employee travel, employee work locations, and cancellation of physical participation in meetings, events and conferences) to conform to government restrictions and best practices encouraged by the Centers for Disease Control and Prevention (the “CDC”), the WHO and other governmental and regulatory authorities. In mid-March 2020, the Partnership restricted access to its offices to only essential employees, and directed the remainder of its employees to work from home to the extent possible. Beginning in mid-May 2020, the Partnership opened its offices to employees on a voluntary basis, with employees having the option to work from the office or from home. The Partnership will continue to give employees the option to work from the office or from home until the CDC recommends businesses and employers resume to pre-pandemic operations. These restrictions have had minimal impact on the Partnership’s operations to date and have allowed the Partnership to maintain the engagement and connectivity of its personnel, as well as minimize the number of employees in the office.

The ultimate impacts of COVID-19 and the volatility in the oil and natural gas markets on the Partnership’s business, cash flows, liquidity, financial condition and results of operations will depend on a number of factors, including, among others, the ultimate severity of COVID-19, the consequences of governmental and other measures designed to prevent the spread of COVID-19, the development, availability and administration of effective treatments and vaccines, the duration of the pandemic, actions taken by members of OPEC and other foreign, oil-exporting countries, governmental authorities and other thirds parties, workforce availability, and the timing and extent of any return to normal economic and operating conditions.

NOTE 2—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Significant Accounting Policies

For a description of the Partnership’s significant accounting policies, see Note 2 of the consolidated financial statements included in the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2020, as well as the items noted below. There have been no substantial changes in such policies or the application of such policies during the three months ended March 31, 2021, other than those discussed below in Recently Adopted Accounting Pronouncements.

Recently Adopted Accounting Pronouncements

In December 2019, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2019-12, “Income Taxes (Topic 740): Simplifying the Accounting for Income Taxes,” that is expected to reduce cost and complexity related to accounting for income taxes. The Partnership adopted this update on January 1, 2021 and applied it prospectively. The adoption of this update did not have a material impact on the Partnership’s results of operations for the three months ended March 31, 2021.

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KIMBELL ROYALTY PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

NOTE 3ACQUISITIONS AND JOINT VENTURES

Acquisitions

On March 10, 2021, the Partnership completed the acquisition of certain mineral and royalty assets held by Nail Bay Royalties, LLC (“Nail Bay Royalties”) and Oil Nut Bay Royalties, LP for a total purchase price of $0.5 million. The assets acquired were managed by Nail Bay Royalties and Duncan Management, LLC (“Duncan Management”). See Note 13—Related Party Transactions, for further discussion of the Partnership’s relation to each entity.

Joint Ventures

On June 19, 2019, the Partnership entered into a joint venture (the “Joint Venture”) with Springbok SKR Capital Company, LLC and Rivercrest Capital Partners, LP, a related party. The Partnership’s ownership in the Joint Venture is 49.3% and its total capital commitment will not exceed $15.0 million. The Joint Venture is managed by Springbok Operating Company, LLC. The purpose of the Joint Venture is to make direct or indirect investments in royalty, mineral and overriding royalty interests and similar non-cost bearing interests in oil and gas properties, excluding leasehold or working interests. The Partnership utilizes the equity method of accounting for its investment in the Joint Venture. As of March 31, 2021, the Partnership had paid approximately $5.2 million under its capital commitment.

NOTE 4DERIVATIVES

Commodity Derivatives

The Partnership’s ongoing operations expose it to changes in the market price for oil and natural gas. To mitigate the inherent commodity price risk associated with its operations, the Partnership uses oil and natural gas commodity derivative financial instruments. From time to time, such instruments may include variable-to-fixed-price swaps, costless collars, fixed-price contracts, and other contractual arrangements. The Partnership enters into oil and natural gas derivative contracts that contain netting arrangements with each counterparty.

As of March 31, 2021, 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. The Partnership hedges its production based on the amount of debt and/or preferred equity as a percent of its enterprise value. As of March 31, 2021, these economic hedges constituted approximately 34% of daily oil and natural gas production.

The Partnership’s oil fixed price swap transactions are settled based upon the average daily prices for the calendar month of the contract period, and its 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. Changes in the fair values of the Partnership’s commodity derivative instruments are recognized as gains or losses in the current period and are presented on a net basis within revenue in the accompanying unaudited interim condensed consolidated statements of operations.

Interest Rate Swaps

On January 27, 2021, the Partnership entered into an interest rate swap with Citibank, N.A., New York (“Citibank”), which fixed the interest rate on $150.0 million of the notional balance on our secured revolving credit facility (which represented approximately 89% of our outstanding balance as of March 31, 2021), at approximately 3.9% for the period ending on January 29, 2024. The Partnership uses an interest rate swap for the management of interest rate risk exposure, as the interest rate swap effectively converts a portion of the Partnership’s secured revolving credit facility from a floating to a fixed rate. Changes in the fair values of the Partnership’s interest rate swaps are recognized as gains or losses in the current period and are presented on a net basis within other income in the accompanying unaudited interim condensed consolidated statements of operations. As of March 31, 2021, the interest rate swap had a total notional amount of $150.0 million and a fair value of $0.5 million.

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KIMBELL ROYALTY PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

The Partnership has not designated any of its derivative contracts as hedges for accounting purposes. Changes in fair value consisted of the following:

Three Months Ended March 31, 

2021

2020

Beginning fair value of derivative instruments

$

(6,280,863)

$

804,501

(Loss) gain on derivative instruments

(13,672,957)

10,132,613

Net cash paid (received) on settlements of derivative instruments

998,785

(1,153,752)

Ending fair value of derivative instruments

$

(18,955,035)

$

9,783,362

The following table presents the fair value of the Partnership’s derivative contracts for the periods indicated:

March 31, 

December 31, 

Classification

Balance Sheet Location

2021

2020

Assets:

Long-term assets

Derivative assets

$

697,068

$

Liabilities:

Current liabilities

Derivative liabilities

(11,112,053)

(3,113,178)

Long-term liabilities

Derivative liabilities

(8,540,050)

(3,167,685)

$

(18,955,035)

$

(6,280,863)

As of March 31, 2021, the Partnership’s open commodity derivative contracts consisted of the following:

Oil Price Swaps

Notional

Weighted Average

Range (per Bbl)

Volumes (Bbl)

Fixed Price (per Bbl)

Low

High

March 2021 - December 2021

448,902

$

44.23

$

34.95

$

56.10

January 2022 - December 2022

500,552

$

41.86

$

35.65

$

46.00

January 2023 - March 2023

91,854

$

53.38

$

53.38

$

53.38

Natural Gas Price Swaps

Notional

Weighted Average

Range (per MMBtu)

Volumes (MMBtu)

Fixed Price (per MMBtu)

Low

High

April 2021 - December 2021

5,188,150

$

2.45

$

2.33

$

2.58

January 2022 - December 2022

6,357,449

$

2.46

$

2.23

$

2.70

January 2023 - March 2023

1,204,308

$

2.73

$

2.73

$

2.73

NOTE 5—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 noted below. The carrying values of cash, oil, natural gas and NGL receivables, accounts receivable and other current assets and current and long-term liabilities included in the unaudited interim condensed consolidated balance sheets approximated fair value as of March 31, 2021 and December 31, 2020 due to their short-term duration and variable interest rates that approximate prevailing interest rates as of each reporting period. As a result, these financial assets and liabilities are not discussed below.

Level 1— Unadjusted quoted market prices for identical assets or liabilities in active markets.
Level 2—Quoted prices for similar assets or liabilities in non-active markets, or inputs that are observable for the asset or liability, either directly or indirectly, for substantially the full term of the asset or liability.
Level 3—Measurement based on prices or valuations models that require inputs that are both unobservable and significant to the fair value measurement (including the Partnership’s own assumptions in determining fair value).

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KIMBELL ROYALTY PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

Assets and liabilities that are measured at fair value are classified based on the lowest level of input that is significant to the fair value measurement. The Partnership’s assessment of the significance of a particular input to the fair value measurement in its entirety requires judgment and considers factors specific to the asset or liability. The Partnership recognizes transfers between fair value hierarchy levels as of the end of the reporting period in which the event or change in circumstances causing the transfer occurred. The Partnership did not have any transfers between Level 1, Level 2 or Level 3 fair value measurements during the three months ended March 31, 2021 and 2020.

Both the Partnership’s commodity derivative instruments and interest rate swap 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 following tables summarize the Partnership’s assets and liabilities measured at fair value on a recurring basis by the fair value hierarchy:

Fair Value Measurements Using

Level 1

Level 2

Level 3

Effect of
Counterparty Netting

Total

March 31, 2021

Assets

Interest rate swap contracts

$

$

697,068

$

$

$

697,068

Liabilities

Commodity derivative contracts

$

$

(19,447,304)

$

$

$

(19,447,304)

Interest rate swap contracts

$

$

(204,799)

$

$

$

(204,799)

December 31, 2020

Liabilities

Commodity derivative contracts

$

$

(6,280,863)

$

$

$

(6,280,863)

NOTE 6—OIL AND NATURAL GAS PROPERTIES

Oil and natural gas properties consist of the following:

    

March 31, 

December 31, 

2021

2020

Oil and natural gas properties

Proved properties

$

941,430,320

$

923,413,606

Unevaluated properties

208,157,655

225,681,626

Less: accumulated depreciation, depletion and impairment

(635,786,468)

(628,102,279)

Total oil and natural gas properties

$

513,801,507

$

520,992,953

The Partnership assesses all unevaluated properties on a periodic basis for possible impairment. The Partnership assesses properties on an individual basis or as a group if properties are individually insignificant. The assessment includes consideration of the following factors, among others: economic and market conditions; operators’ intent to drill, remaining lease term, geological and geophysical evaluations, operators’ drilling results and activity, the assignment of proved reserves and the economic viability of operator development if proved reserves are assigned. Costs associated with unevaluated properties are excluded from the full cost pool until a determination as to the existence of proved reserves is able to be made. During any period in which these factors indicate an impairment, all or a portion of the associated leasehold costs are transferred to the full cost pool and are then subject to amortization and to the full cost ceiling test. The Partnership transferred $48.6 million to the full cost pool in the first quarter of 2020 as a result of this impairment assessment. The transfer resulted in an additional ceiling test impairment expense for the three months ended March 31, 2020 equal to the amount of the transfer.

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KIMBELL ROYALTY PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

After evaluating certain external factors in the first quarter of 2020, including a significant decline in oil and natural gas prices, as well as longer-term commodity price outlooks, in each case related to reduced demand for oil and natural gas as a result of COVID-19, the announcement of price reductions and production increases in March 2020 by members of OPEC and other foreign, oil-exporting countries, and other supply factors, the Partnership determined that significant drilling uncertainty existed regarding its proved undeveloped (“PUD”) reserves that were included in its total estimated proved reserves as of December 31, 2019, as well as its unevaluated oil and natural gas properties. Specifically, with respect to the Partnership’s PUD reserves (which accounted for approximately 6.1% of total estimated proved reserves as of December 31, 2019), the Partnership determined that it did not have reasonable certainty as to the timing of the development of the PUD reserves and, therefore, recorded an impairment on such properties for the three months ended March 31, 2020. The Partnership did not book PUD reserves in its total estimated proved reserves as of December 31, 2020 and it does not intend to book PUD reserves going forward.

The Partnership did 0t record an impairment on its oil and natural gas properties for the three months ended March 31, 2021. The Partnership recorded an impairment on its oil and natural gas properties of $70.9 million for the three months ended March 31, 2020, which can primarily be attributed to factors mentioned above.

NOTE 7—LEASES

Substantially all of the Partnership’s leases are long-term operating leases with fixed payment terms and will terminate in June 2029. The Partnership’s right-of-use (“ROU”) operating lease assets represent its right to use an underlying asset for the lease term, and its operating lease liabilities represent its obligation to make lease payments. ROU operating lease assets and operating lease liabilities are included in the accompanying unaudited interim condensed consolidated balance sheets. Short term operating lease liabilities are included in other current liabilities. The weighted average remaining lease term as of March 31, 2021 is 8.08 years.

Both the ROU operating lease assets and liabilities are recognized at the present value of the remaining lease payments over the lease term and do not include lease incentives. The Partnership’s leases do not provide an implicit rate that can readily be determined; therefore, the Partnership used a discount rate based on its incremental borrowing rate, which is determined by the information available in the secured revolving credit facility. The incremental borrowing rate reflects the estimated rate of interest that the Partnership would pay to borrow, on a collateralized basis over a similar term, an amount equal to the lease payments in a similar economic environment. The weighted average discount rate used for the operating lease was 6.75% for the three months ended March 31, 2021.

Operating lease expense is recognized on a straight-line basis over the lease term and is included in general and administrative expense in the accompanying unaudited interim condensed consolidated statements of operations for the three months ended March 31, 2021 and 2020. The total operating lease expense recorded for both the three months ended March 31, 2021 and 2020 was $0.1 million, respectively.

Currently, the most substantial contractual arrangements that the Partnership has classified as operating leases are the main office spaces used for operations.

Future minimum lease commitments as of March 31, 2021 were as follows:

Total

2021

2022

2023

2024

2025

Thereafter

Operating leases

$

4,050,131

$

363,626

$

486,045

$

487,787

$

488,725

$

497,033

$

1,726,915

Less: Imputed Interest

 

(973,300)

 

Total

$

3,076,831

 

NOTE 8—LONG-TERM DEBT

On January 11, 2017, the Partnership entered into a credit agreement (the “2017 Credit Agreement”) with Frost Bank, as administrative agent, and the lenders party thereto. On July 12, 2018, the Partnership entered into an amendment

10

Table of Contents

KIMBELL ROYALTY PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

(the “First Credit Agreement Amendment”) to the Partnership’s 2017 Credit Agreement (the 2017 Credit Agreement as amended by the First Credit Agreement Amendment, the “2018 Amended Credit Agreement”).

On December 8, 2020, the Partnership entered into Amendment No. 2 (the “Second Credit Agreement Amendment”) to the 2018 Amended Credit Agreement (the 2018 Amended Credit Agreement as amended by the Second Credit Agreement Amendment, the “Amended Credit Agreement”).

The Second Credit Agreement Amendment amends the 2018 Amended Credit Agreement to, among other things, (i) increase commitments under the Amended Credit Agreement’s senior secured revolving credit facility from $225.0 million to $265.0 million, the availability of which will equal the lesser of the aggregate maximum elected commitments of the lenders up to $500.0 million, subject to the satisfaction of certain conditions and the election of existing lenders to increase commitments or the procurement of additional commitments from new lenders, and the borrowing base, (ii) extend the maturity date under the 2018 Amended Credit Agreement from February 8, 2022 to June 7, 2024, (iii) reflect the change in administrative agent from Frost to with Citibank, N.A., New York (“Citibank”) under the Amended Credit Agreement, (iv) increase the applicable margin under the 2018 Amended Credit Agreement, which varies based upon the level of borrowing base usage, by 1.00% for each applicable level as set forth in the Amended Credit Agreement, such that the applicable margin will range from 2.00% to 3.00% in the case of ABR Loans (as defined in the Amended Credit Agreement) and 3.00% to 4.00% in the case of LIBOR Loans (as defined in the Amended Credit Agreement), (v) provide for a LIBOR (as defined in the Amended Credit Agreement) floor of 0.25%, (vi) modify the Debt to EBITDAX Ratio (as defined in the Amended Credit Agreement) financial covenant to permit the numerator of the Debt to EBITDAX Ratio (as defined in the Amended Credit Agreement) to be calculated as Total Debt (as defined in the Amended Credit Agreement) minus up to $25 million in unrestricted cash held by the Partnership and its restricted subsidiaries and to decreases the maximum permitted Debt to EBITDAX Ratio (as defined in the Amended Credit Agreement) from 4.0 to 1.0 to 3.5 to 1.0, and (vii) modify the conditions permitting restricted distributions to holders of Kimbell Common Units (as defined in the Amended Credit Agreement) including, among other things, a limitation on such distributions to not be in excess of the Partnership’s Projected Cash Available For Distribution (as defined in the Amended Credit Agreement). In connection with our entry into the Second Credit Agreement Amendment, the borrowing base was set at $265.0 million. The borrowing base will be redetermined semi-annually on or about May 1 and November 1 of each year, beginning May 1, 2021, based on the value of the Partnership’s oil and natural gas properties and the oil and natural gas properties of the Partnership’s wholly owned subsidiaries. The May borrowing base redetermination is currently being conducted and is expected to be finalized by the end of May 2021.

The Amended Credit Agreement 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 and OpCo 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 Amended Credit Agreement 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 Amended Credit Agreement) of not more than 3.5 to 1.0; and (ii) a ratio of current assets to current liabilities of not less than 1.0 to 1.0. The Amended Credit Agreement also contains customary events of default, including non-payment, breach of covenants, materially incorrect representations, cross default, bankruptcy and change of control.

During the three months ended March 31, 2021, the Partnership borrowed an additional $0.5 million under the secured revolving credit facility and repaid approximately $3.5 million of the outstanding borrowings. As of March 31, 2021, the Partnership’s outstanding balance was $168.5 million. The Partnership was in compliance with all covenants included in the secured revolving credit facility as of March 31, 2021.

As of March 31, 2021, borrowings under the secured revolving credit facility bore interest at LIBOR plus a margin of 3.50% or the ABR (as defined in the Amended Credit Agreement) plus a margin of 2.50%. For the three months ended March 31, 2021, the weighted average interest rate on the Partnership’s outstanding borrowings was 3.75%.

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KIMBELL ROYALTY PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

NOTE 9—PREFERRED UNITS

In July 2018, the Partnership completed the private placement of 110,000 Series A preferred units to certain affiliates of Apollo Capital Management, L.P. (the “Series A Purchasers”) for $1,000 per Series A preferred unit, resulting in gross proceeds to the Partnership of $110.0 million. Until the conversion of the Series A preferred units into common units or their redemption, holders of the Series A preferred units are entitled to receive cumulative quarterly distributions equal to 7.0% per annum plus accrued and unpaid distributions. In connection with the issuance of the Series A preferred units, the Partnership granted holders of the Series A preferred units board observer rights beginning on the third anniversary of the original issuance date, and board appointment rights beginning the fourth anniversary of the original issuance date and in the case of events of default with respect to the Series A preferred units.

The Series A preferred units are convertible by the Series A Purchasers after two years at a 30% discount to the issue price, subject to certain conditions. The Partnership may redeem the Series A preferred units at any time. The Series A preferred units may be redeemed for a cash amount per Series A preferred unit equal to the product of (a) the number of outstanding Series A preferred units multiplied by (b) the greatest of (i) an amount (together with all prior distributions made in respect of such Series A preferred unit) necessary to achieve the Minimum IRR (as defined below), (ii) an amount (together with all prior distributions made in respect of such Series A preferred unit) necessary to achieve a return on investment equal to 1.2 times with respect to such Series A preferred unit and (iii) the Series A issue price plus accrued and unpaid distributions.

For purposes of the Series A preferred units, “Minimum IRR” means as of any measurement date: (a) prior to the fifth anniversary of the July 12, 2018 (the “Series A Issuance Date”), a 13.0% internal rate of return with respect to the Series A preferred units; (b) on or after the fifth anniversary of the Series A Issuance Date and prior to the sixth anniversary of the Series A Issuance Date, a 14.0% internal rate of return with respect to the Series A preferred units; and (c) on or after the sixth anniversary of the Series A Issuance Date, a 15.0% internal rate of return with respect to the Series A preferred units.

On February 12, 2020, the Partnership completed the redemption of 55,000 Series A preferred units, representing 50% of the then-outstanding Series A preferred units. The Series A preferred units were redeemed at a price of $1,110.72 per Series A preferred unit for an aggregate redemption price of $61.1 million. As the consideration transferred by the Partnership to redeem the Series A preferred units was greater than 50% of the carrying value of the Series A preferred units as of the redemption date and 50% of the original intrinsic value of the beneficial conversion feature, a deemed dividend distribution of $5.7 million was recognized in unitholders’ equity and non-controlling interest during the three months ended March 31, 2020.

The following table summarizes the changes in the number of the Series A preferred units:

Series A

Preferred Units

Balance at December 31, 2020

55,000

Balance at March 31, 2021

55,000

NOTE 10—UNITHOLDERS’ EQUITY AND PARTNERSHIP DISTRIBUTIONS

The Partnership has issued units representing limited partner interests. As of March 31, 2021, the Partnership had a total of 39,769,896 common units issued and outstanding and 20,779,781 Class B units outstanding.

In January 2020, the Partnership completed an underwritten public offering of 5,000,000 common units for net proceeds of approximately $73.6 million (the “2020 Equity Offering”). The Partnership used the net proceeds from the 2020 Equity Offering to purchase OpCo common units. The Operating Company in turn used the net proceeds to repay approximately $70.0 million of the outstanding borrowings under the Partnership’s secured revolving credit facility. In connection with the 2020 Equity Offering, certain selling unitholders sold 750,000 common units pursuant to the exercise of the underwriters’ option to purchase additional common units. The Partnership did not receive any proceeds from the sale of the common units by the selling unitholders.

12

Table of Contents

KIMBELL ROYALTY PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

The following table summarizes the changes in the number of the Partnership’s common units:

Common Units

Balance at December 31, 2020

38,918,689

Common units issued under the LTIP (1)

936,567

Restricted units repurchased for tax withholding

(85,360)

Balance at March 31, 2021

39,769,896

(1)Includes restricted units granted to certain employees, directors and consultants under the Kimbell Royalty GP, LLC 2017 Long-Term Incentive Plan (as amended, the “LTIP”) on February 25, 2021.

The following table presents information regarding the common unit cash distributions approved by the General Partner’s Board of Directors (the “Board of Directors”) for the periods presented:

Amount per

Date

Unitholder

Payment

Common Unit

Declared

Record Date

Date

Q1 2021

$

0.27

April 23, 2021

May 3, 2021

May 10, 2021

Q1 2020

$

0.17

April 24, 2020

May 4, 2020

May 11, 2020

The following table summarizes the changes in the number of the Partnership’s Class B units:

Class B Units

Balance at December 31, 2020

20,779,781

Balance at March 31, 2021

20,779,781

For each Class B unit issued, 5 cents has been paid to the Partnership as additional consideration (the “Class B Contribution”). Holders of the Class B units, are entitled to receive cash distributions equal to 2.0% per quarter on their respective Class B Contribution, subsequent to distributions on the Series A preferred units but prior to distributions on the common units and OpCo common units.

The Class B units and OpCo common units are exchangeable together into an equal number of common units of the Partnership.

NOTE 11—NET LOSS PER COMMON UNIT

Basic loss per common unit is calculated by dividing net loss attributable to common units by the weighted-average number of common units outstanding during the period. Diluted net loss per common unit gives effect, when applicable, to unvested restricted units granted under the Partnership’s LTIP for its employees, directors and consultants and potential conversion of Class B units.

13

Table of Contents

KIMBELL ROYALTY PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

The following table summarizes the calculation of weighted average common units outstanding used in the computation of diluted net loss per common unit:

Three Months Ended March 31, 

2021

2020

Net loss attributable to common units

$

(704,375)

$

(39,301,034)

Weighted average number of common units outstanding:

Basic

37,693,469

30,528,819

Effect of dilutive securities:

Series A preferred units

Class B units

Restricted units

Diluted

37,693,469

30,528,819

Net loss attributable to common units

Basic

$

(0.02)

$

(1.29)

Diluted

$

(0.02)

$

(1.29)

The calculation of diluted net loss per unit for the three months ended March 31, 2021 and 2020 excludes the conversion of Series A preferred units to common units, the conversion of Class B units to common units and 1,900,878 and 1,686,117 shares of unvested restricted units, respectively, because their inclusion in the calculation would be anti-dilutive.

NOTE 12—UNIT-BASED COMPENSATION

The Partnership’s LTIP authorizes grants of up to 4,541,600 common units in the aggregate to its employees, directors and consultants. The restricted units issued under the Partnership’s 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 is treated in the same manner as that of the employees and directors.

Distributions related to the restricted units are paid concurrently with the Partnership’s distributions for common units. The fair value of the Partnership’s restricted units issued under the LTIP to the Partnership’s employees, directors and consultants is determined by utilizing the market value of the Partnership’s common units on the respective grant date. The following table presents a summary of the Partnership’s unvested restricted units.

Weighted

    

Weighted

Average

Average

Grant-Date

Remaining

Fair Value

Contractual

Units

per Unit

Term

Unvested at December 31, 2020

1,276,546

$

13.604

 

1.788 years

Awarded

936,567

10.350

Vested

(312,235)

11.540

Unvested at March 31, 2021

1,900,878

$

12.340

 

2.161 years

NOTE 13—RELATED PARTY TRANSACTIONS

The Partnership currently has a management services agreement with Kimbell Operating, which has separate services agreements with each of BJF Royalties, LLC (“BJF Royalties”), K3 Royalties, LLC (“K3 Royalties”), Nail Bay Royalties and 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

14

Table of Contents

KIMBELL ROYALTY PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

Partnership’s Sponsors may 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 on common units to the Partnership’s unitholders.

During the three months ended March 31, 2021, the Partnership acquired certain assets managed by Nail Bay Royalties and Duncan Management. See Note 3—Acquisitions and Joint Ventures for further detail.

During the three months ended March 31, 2021, 0 monthly services fee was paid to BJF Royalties. During the three months ended March 31, 2021, the Partnership made payments to K3 Royalties, Nail Bay Royalties and Duncan Management in the amount of $30,000, $75,329 and $137,120, respectively. Certain consultants who provide services under management services agreements are granted restricted units under the Partnership’s LTIP.

NOTE 14—ADMINISTRATIVE SERVICES

Management Services Agreement

The Partnership relies upon its officers, directors, Sponsors and outside consultants to further its business operations. The Partnership also hires independent contractors and consultants involved in land, technical, regulatory and other disciplines to assist its officers and directors. See Note 13―Related Party Transactions.

NOTE 15—COMMITMENTS AND CONTINGENCIES

During the normal course of business, the Partnership may experience situations where disagreements occur relating to the ownership of certain mineral or overriding royalty interest acreage. 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 as of March 31, 2021.

NOTE 16—SUBSEQUENT EVENTS

The Partnership has evaluated events that occurred subsequent to March 31, 2021 in the preparation of its unaudited interim condensed consolidated financial statements.

Debt

On April 27, 2021 the Partnership drew down $4.0 million on the senior secured revolving credit facility to fund certain operational expenses.

Distributions

On May 4, 2021, the Partnership paid a quarterly cash distribution on the Series A preferred units of approximately $1.0 million for the quarter ended March 31, 2021.

On May 5, 2021, the Partnership paid a quarterly cash distribution to each Class B unitholder equal to 2.0% of such unitholder’s respective Class B Contribution, resulting in a total quarterly distribution of $20,780 for the quarter ended March 31, 2021.

On April 23, 2021, the Board of Directors declared a quarterly cash distribution of $0.27 per common unit for the quarter ended March 31, 2021. The distribution will be paid on May 10, 2021 to common unitholders and OpCo common unitholders of record as of the close of business on May 3, 2021.

15

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion and analysis of financial condition and results of operations should be read together in conjunction with our unaudited interim condensed consolidated financial statements and notes thereto presented in this Quarterly Report on Form 10-Q (this “Quarterly Report”), as well as our audited financial statements and notes thereto included in our Annual Report on Form 10-K for the year ended December 31, 2020 (the “2020 Form 10-K”).

Unless the context otherwise requires, references to “Kimbell Royalty Partners, LP,” the “Partnership,” “we” or “us” refer to Kimbell Royalty Partners, LP and its subsidiaries. References to the “Operating Company” refer to Kimbell Royalty Operating, LLC. References to the “General Partner” refer to Kimbell Royalty GP, LLC. References to the “Sponsors” refer to affiliates of the Partnership’s founders, Ben J. Fortson, Robert D. Ravnaas, Brett G. Taylor and Mitch S. Wynne, respectively. References to the “Contributing Parties” refer to all entities and individuals, including certain affiliates of the Sponsors, that contributed, directly or indirectly, certain mineral and royalty interests to the Partnership.

Cautionary Statement Regarding Forward-Looking Statements

Certain statements and information in this Quarterly 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 Quarterly 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. All comments concerning our expectations for future revenues and operating results are based on our forecasts for our existing operations and do not include the potential impact of future operations or acquisitions. Factors that could cause our actual results to differ materially from the results contemplated by such forward-looking statements include:

our ability to replace our reserves;
our ability to make, consummate and integrate acquisitions of assets or businesses and realize the benefits or effects of any acquisitions or the timing, final purchase price or consummation of any acquisitions;
our ability to execute our business strategies;
the volatility of realized prices for oil, natural gas and natural gas liquids (“NGLs”), including as a result of actions by, or disputes among or between, members of the Organization of Petroleum Exporting Countries (“OPEC”) and other foreign, oil-exporting countries;
the level of production on our properties;
the level of drilling and completion activity by the operators of our properties;
our ability to forecast identified drilling locations, gross horizontal wells, drilling inventory and estimates of reserves on our properties and on properties we seek to acquire;
regional supply and demand factors, delays or interruptions of production;
industry, economic, business or political conditions, including the energy and environmental proposals supported by the Biden administration and/or the United States Congress, weakness in the capital markets or the ongoing and potential impact to financial markets and worldwide economic activity resulting from the ongoing coronavirus (“COVID-19”) pandemic and related governmental actions;
revisions to our reserve estimates as a result of changes in commodity prices, decline curves and other uncertainties;

16

impacts of impairment expense on our financial statements;
competition in the oil and natural gas industry generally and the mineral and royalty industry in particular;
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 acquire an interest;
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, including the Biden administration’s proposals and recent executive orders focused on addressing climate change;
future operating results;
exploration and development drilling prospects, inventories, projects and programs;
operating hazards faced by the operators of our properties;
the ability of the operators of our properties to keep pace with technological advancements;
uncertainties regarding United States federal income tax law, including the treatment of our future earnings and distributions; and
our ability to maintain effective internal controls over financial reporting and disclosure controls and procedures.

These factors are discussed in further detail in the 2020 Form 10-K under “Item 1A. Risk Factors” in Part I and “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Part II and elsewhere in this Quarterly Report. Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date hereof. We undertake no obligation to publicly update or revise any forward-looking statements after the date they are made, whether as a result of new information, future events or otherwise.

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. Effective as of September 24, 2018, we have elected to be taxed as a corporation for United States federal income tax purposes. 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 third parties, our Sponsors and the Contributing Parties and from organic growth through the continued development by working interest owners of the properties in which we own an interest.

As of March 31, 2021, we owned mineral and royalty interests in approximately 9.1 million gross acres and overriding royalty interests in approximately 4.6 million gross acres, with approximately 60% of our aggregate acres located in the Permian Basin, Mid-Continent and Bakken/Williston Basin. We refer to these non-cost-bearing interests collectively as our “mineral and royalty interests.” As of March 31, 2021, 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 28 states and in

17

every major onshore basin across the continental United States and include ownership in over 97,000 gross wells, including over 41,000 wells in the Permian Basin.

The following table summarizes our ownership in United States basins and producing regions and information about the wells in which we have a mineral or royalty interest as of March 31, 2021:

Average Daily

Average Daily

Production

Production

Basin or Producing Region

Gross Acreage

Net Acreage

(Boe/d)(6:1)(1)

(Boe/d)(20:1)(2)

Well Count

Permian Basin

2,662,777

23,075

2,576

2,079

41,075

Mid‑Continent

 

3,955,148

41,402

1,545

919

11,267

Haynesville

 

786,724

7,665

3,295

1,124

8,861

Appalachia

741,354

23,202

2,040

825

3,208

Bakken

 

1,569,637

6,051

718

603

4,124

Eagle Ford

 

624,148

6,730

1,551

1,223

3,235

Rockies

 

74,152

1,036

729

405

12,359

Other

 

3,232,561

36,694

1,267

709

13,028

Total

 

13,646,501

145,855

13,721

7,887

97,157

(1)“Btu-equivalent” production volumes are presented on an oil-equivalent basis using a conversion factor of six Mcf of natural gas per barrel of “oil equivalent,” which is based on approximate energy equivalency and does not reflect the price or value relationship between oil and natural gas. Please read “Business—Oil and Natural Gas Data—Proved Reserves—Summary of Estimated Proved Reserves” in our 2020 Form 10-K.
(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.

The following table summarizes information about the number of drilled but uncompleted wells (“DUCs”) and permitted locations on acreage in which we have a mineral or royalty interest as of March 31, 2021:

Basin or Producing Region(1)

Gross DUCs

Gross Permits

Net DUCs

Net Permits

Permian Basin

308

258

0.68

0.74

Mid‑Continent

 

102

65

0.34

0.08

Haynesville

 

65

31

0.35

0.04

Appalachia

19

36

0.06

0.12

Bakken

 

154

174

0.25

0.71

Eagle Ford

 

61

73

0.45

0.56

Rockies

 

52

32

0.07

0.29

Total

 

761

669

2.20

2.54

(1)The above table represents drilled but uncompleted wells and permitted locations only, and there is no guarantee that the drilled but uncompleted wells or permitted locations will be developed into producing wells in the future.

18

The following table summarizes estimates of our remaining horizontal drilling inventory by basin as of March 31, 2021:

Basin or Producing Region

Gross Locations(1)

Net Locations(1)

Average Gross Horizontal Wells/DSU(2)

Permian Basin

3,017

19.20

12.0

Mid‑Continent

 

1,489

6.38

6.8

Haynesville

 

1,309

17.04

5.9

Appalachia

247

2.17

7.6

Bakken

 

2,042

4.51

8.5

Eagle Ford

 

1,846

17.28

6.9

Rockies

 

210

1.56

10.5

Total

 

10,160

68.14

8.3

(1)Represents an estimated 15 years of drilling inventory based on the pace of well completions during 2019, which we believe is a more normalized level of activity compared to 2020, which was impacted by the slowdown resulting from COVID-19. These locations only include our major properties and do not include locations from our minor properties, which generally include properties with less than a 0.1% net revenue interest and are time consuming to quantify, but in the estimation of our management, could add up to an additional 20% to our net inventory in the aggregate.
(2)Gross horizontal wells per drilling spacing unit (“DSU”) from our internal reserves database as of March 31, 2021. DSUs vary in size.

Estimates of drilling locations, gross horizontal wells per DSU and years of drilling inventory are inherently uncertain and actual results could differ substantially from these estimates. Please read “—Cautionary Statement Regarding Forward-Looking Statements” and “Risk Factors” elsewhere in this report.

Recent Developments

Debt

On April 27, 2021 we drew down $4.0 million on the senior secured revolving credit facility to fund certain operational expenses.

Quarterly Distributions

On May 4, 2021, we paid a quarterly cash distribution on the Series A preferred units of approximately $1.0 million for the quarter ended March 31, 2021.

Each holder of Class B units has paid five cents per Class B unit to us as an additional capital contribution for the Class B units (such aggregate amount, the “Class B Contribution”) in exchange for Class B units. Each holder of Class B units is entitled to receive cash distributions equal to 2.0% per quarter on their respective Class B Contribution. On May 5, 2021, we paid a quarterly cash distribution to each Class B unitholder, resulting in a total quarterly distribution of $20,780 for the quarter ended March 31, 2021.

On April 23, 2021, the General Partner’s Board of Directors (the “Board of Directors”) declared a quarterly cash distribution of $0.27 per common unit for the quarter ended March 31, 2021. The distribution will be paid on May 10, 2021 to common unitholders and OpCo common unitholders of record as of the close of business on May 3, 2021.

Business Environment

COVID-19 Pandemic and Impact on Global Demand for Oil and Natural Gas

The global spread of COVID-19 created significant volatility, uncertainty, and economic disruption during 2020 and continuing into 2021. On March 11, 2020, the World Health Organization (the “WHO”) declared the ongoing COVID-19 outbreak a pandemic and recommended containment and mitigation measures worldwide. The pandemic has reached more than 200 countries and has resulted in widespread adverse impacts on the global economy, our oil, natural gas, and

19

NGL operators and other parties with whom we have business relations, including a significant reduction in the global demand for oil and natural gas. This significant decline in demand accelerated following the announcement of price reductions and production increases in March 2020 by members of OPEC and other foreign, oil-exporting countries, raising concerns about global storage capacity. The resulting supply and demand imbalance led to a significantly weaker outlook for oil and gas producers and is had a disruptive impact on the oil and natural gas industry. Globally, these conditions led to significant economic contraction during the 2020 period.

Our first priority in our response to this crisis has been and will continue to be the health and safety of our employees, the employees of our business counterparties and the community in which we operate. To address these concerns, we have modified certain business practices (including those related to employee travel, employee work locations, and physical participation in meetings, events and conferences) to conform to government restrictions and best practices encouraged by the Centers for Disease Control and Prevention (the “CDC”), the WHO and other governmental and regulatory authorities. In mid-March 2020, we restricted access to our offices to only essential employees, and directed the remainder of our employees to work from home to the extent possible. Beginning in mid-May 2020 we opened our offices to employees on a voluntary basis, with employees having the option to work from home. We will continue to give employees the option to work from home until the CDC recommends businesses and employers resume to pre-pandemic operations. These restrictions have had minimal impact on our operations to date and have allowed us to maintain the engagement and connectivity of our personnel, as well as minimize the number of employees in the office.

There is considerable uncertainty regarding the extent to which COVID-19 will continue to spread and the extent and duration of governmental and other measures implemented to try to slow the spread of COVID-19, such as large-scale travel bans and restrictions, border closures, quarantines, shelter-in-place orders and business and government shutdowns. While shelter-in-place restrictions subsided in the second half of 2020 and through the first quarter of 2021, the possibility of future restrictions remains. One of the largest impacts of the pandemic has been a significant reduction in global demand for oil and, to a lesser extent, natural gas. This significant decline in demand was met with a sharp decline in oil prices which were exacerbated by the announcement of price reductions and production increases in March 2020 by members of OPEC and other foreign, oil-exporting countries. The resulting supply and demand imbalance has had disruptive impacts on the oil and natural gas exploration and production industry and on other related industries. These industry conditions, coupled with those resulting from the COVID-19 pandemic, has led to significant global economic contraction generally and in our industry in particular.

Oil and natural gas prices have historically been volatile; however, the volatility in the prices for these commodities substantially increased as a result of COVID-19, the OPEC announcements mentioned above and ongoing storage capacity concerns. Oil prices declined sharply in April 2020. Although strip pricing for natural gas has increased meaningfully, the impact of these recent developments on our business and the oil and gas industry is unpredictable. We derived approximately 41% of our revenues and 61% of our production on a Boe/d basis (6:1) from natural gas for the first quarter of 2021, which we believe presents some downside protection against depressed oil prices.

In April 2020, we received notices from two operators regarding well shut-ins and curtailments of production on properties in which we own an interest. The properties were primarily located in the Eagle Ford Shale, and the production attributable to such properties on a Boe/d basis (6:1) represented approximately one percent of our total production for the first quarter of 2020. We received subsequent notice that the curtailment on all Eagle Ford Shale production ceased and production resumed, effective June 1, 2020. We also received notifications of well shut-ins and curtailment in the second quarter of 2020 from additional operators and the production attributable to such properties on a Boe/d basis (6:1) accounted for less than one percent of our total production for the second quarter of 2020. We did not receive any notification of shut-ins or curtailment in the second half of 2020. While we currently do not expect we will receive additional notices, we cannot predict whether additional shut-ins and curtailments of production from our operators will occur if oil and natural gas prices decline or reductions in global demand and storage capacity issues continue or worsen.

The ultimate impacts of COVID-19 and the volatility in the oil and natural gas markets on our business, cash flows, liquidity, financial condition and results of operations will depend on a number of factors, including, among others, the ultimate severity of COVID-19, the consequences of governmental and other measures designed to prevent the spread of COVID-19, the development, availability and administration of effective treatments and vaccines, the duration of the pandemic, actions taken by members of OPEC and other foreign, oil-exporting countries, governmental authorities and other third parties, workforce availability, and the timing and extent of any return to normal economic and operating

20

conditions. For additional discussion regarding the risks associated with the COVID-19 pandemic, see Item 1A “Risk Factors” in Part I, Item 1A. Risk Factors in our 2020 Form 10-K.

Commodity Prices and Demand

Oil and natural gas prices have been historically volatile and may continue to be volatile in the future. As noted above, the supply and demand imbalance resulting from the COVID-19 outbreak and various OPEC announcements, along with the winter storms experienced in parts of the United States in February 2021, have created increased volatility in oil and natural gas prices. The table below demonstrates such volatility for the periods presented as reported by the United States Energy Information Administration (“EIA”).

Three Months Ended
March 31, 2021

Three Months Ended
March 31, 2020

High

    

Low

High

    

Low

Oil ($/Bbl)

$

66.08

$

47.47

$

63.27

$

14.10

Natural gas ($/MMBtu)

$

23.86

$

2.45

$

2.17

$

1.65

On April 30, 2021, the West Texas Intermediate posted price for crude oil was $63.50 per Bbl and the Henry Hub spot market price of natural gas was $2.86 per MMBtu.

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

Three Months Ended March 31, 

2021

    

2020

Oil ($/Bbl)

$

58.09

$

45.54

Natural gas ($/MMBtu)

$

3.50

$

1.90

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 United States Rotary Rig count decreased by 41.4% from 710 active land rigs at March 31, 2020 to 416 active land rigs at March 31, 2021. The 416 active land rigs at March 31, 2021 increased by 25.3% from 332 active land rigs at December 31, 2020.

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According to the Baker Hughes United States Rotary Rig count, rig activity in the 28 states in which we own mineral and royalty interests included 413 active land rigs as of March 31, 2021 compared to 700 active land rigs as of March 31, 2020. The decrease in rig count is directly related to the COVID-19 outbreak and international supply and demand imbalances. See Business EnvironmentCOVID-19 Pandemic and Impact on Global Demand for Oil and Natural Gas for further discussion. The 413 active land rig count at March 31, 2021 increased by 25.2% from 330 active land rigs at December 31, 2020. The increase in rig count from December 31, 2020, is primarily attributable to an uptake in the oil and natural gas market as a result of improved oil and natural gas prices.

The following table summarizes the number of active rigs operating on our acreage by United States basins and producing regions for the periods indicated:

March 31, 

Basin or Producing Region

2021

2020

Permian Basin

23

30

Mid‑Continent

7

13

Haynesville

11

8

Appalachia

2

3

Bakken

2

11

Eagle Ford

3

8

Rockies

2

Other

1

Total

49

75

Sources of Our Revenue

Our revenues are derived from royalty payments we receive from our operators based on the sale of oil, natural gas and NGL production, as well as the sale of NGLs that are extracted from natural gas during processing. Our revenues may vary significantly from period to period as a result of changes in volumes of production sold or changes in commodity prices.

The following table presents the breakdown of our operating income for the following periods:

Three Months Ended March 31, 

2021

    

2020

Royalty income

Oil sales

47

%

58

%

Natural gas sales

41

%

32

%

NGL sales

11

%

9

%

Lease bonus and other income

1

%

1

%

100

%

100

%

We entered into oil and natural gas commodity derivative agreements, beginning January 1, 2018 which extend through March 2023, to establish, in advance, a price for the sale of a portion of the oil, natural gas and NGLs produced from our mineral and royalty interests.

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Non-GAAP Financial Measures

Adjusted EBITDA and Cash Available for Distribution

Adjusted EBITDA and cash available for distribution are used as supplemental non-GAAP financial measures (as defined below) by management and external users of our financial statements, such as industry analysts, investors, lenders and rating agencies. We believe Adjusted EBITDA and cash available for distribution are useful because they allow 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), net of depreciation and depletion expense, interest expense, income taxes, impairment of oil and natural gas properties, non-cash unit-based compensation, change in fair value of open derivative instruments, cash distribution from affiliate and equity income in affiliate. Adjusted EBITDA is not a measure of net income (loss) as determined by 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. We define cash available for distribution as Adjusted EBITDA, less cash needed for debt service and other contractual obligations, tax obligations, fixed charges and reserves for future operating or capital needs that the Board of Directors may determine is appropriate.

Adjusted EBITDA and cash available for distribution should not be considered an alternative to net income (loss), 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 and cash available for distribution may not be comparable to other similarly titled measures of other companies.

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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 (unaudited).

Three Months Ended March 31, 

2021

2020

Reconciliation of net income (loss) to Adjusted EBITDA:

Net income (loss)

$

537,194

$

(59,784,399)

Depreciation and depletion expense

7,911,148

13,270,683

Interest expense

2,095,098

1,421,304

Cash distribution from affiliate

216,738

Provision for income taxes

EBITDA

10,760,178

(45,092,412)

Impairment of oil and natural gas properties

70,925,731

Unit-based compensation

2,692,494

2,107,587

Loss (gain) on derivative instruments, net of settlements

12,674,172

(8,978,861)

Cash distribution from affiliate

55,039

17,961

Equity income in affiliate

(185,080)

(163,554)

Consolidated Adjusted EBITDA

25,996,803

18,816,452

Adjusted EBITDA attributable to noncontrolling interest

(8,921,730)

(7,059,747)

Adjusted EBITDA attributable to Kimbell Royalty Partners, LP

17,075,073

11,756,705

Adjustments to reconcile Adjusted EBITDA to cash available for distribution

Cash interest expense

1,099,087

703,952

Cash distributions on Series A preferred units

632,184

1,202,759

Restricted units repurchased for tax withholding

606,625

Distributions on Class B units

20,780

24,807

Cash available for distribution on common units

$

14,716,397

$

9,825,187

Three Months Ended March 31, 

2021

2020

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

Net cash provided by operating activities

$

15,480,993

$

20,787,606

Interest expense

 

2,095,098

 

1,421,304

Provision for income taxes

Impairment of oil and natural gas properties

 

 

(70,925,731)

Amortization of right-of-use assets

(71,785)

 

(67,470)

Amortization of loan origination costs

 

(371,487)

 

(266,318)

Equity income in affiliate

 

185,080

 

163,554

Unit-based compensation

 

(2,692,494)

 

(2,107,587)

(Loss) gain on derivative instruments, net of settlements

 

(12,674,172)

 

8,978,861

Changes in operating assets and liabilities:

Oil, natural gas and NGL receivables

 

7,215,335

 

(4,913,049)

Accounts receivable and other current assets

 

583,862

 

508,985

Accounts payable

 

(153,681)

 

450,579

Other current liabilities

 

1,092,287

 

809,594

Operating lease liabilities

71,142

 

67,260

EBITDA

10,760,178

(45,092,412)

Add:

Impairment of oil and natural gas properties

 

 

70,925,731

Unit-based compensation

 

2,692,494

 

2,107,587

Loss (gain) on derivative instruments, net of settlements

 

12,674,172

 

(8,978,861)

Cash distribution from affiliate

55,039

17,961

Equity income in affiliate

(185,080)

(163,554)

Consolidated Adjusted EBITDA

25,996,803

18,816,452

Adjusted EBITDA attributable to noncontrolling interest

(8,921,730)

(7,059,747)

Adjusted EBITDA attributable to Kimbell Royalty Partners, LP

$

17,075,073

$

11,756,705

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Factors Affecting the Comparability of Our Results to Our Historical Results

Our historical financial condition and results of operations may not be comparable, either from period to period or going forward, to our future financial condition and results of operations, for the reasons described below.

Ongoing Acquisition Activities

Acquisitions are an important part of our growth strategy, and we expect to pursue acquisitions of mineral and royalty interests from third parties, affiliates of our Sponsors and the Contributing Parties. As a part of these efforts, we often engage in discussions with potential sellers or other parties regarding the possible purchase of or investment in mineral and royalty interests, including in connection with a dropdown of assets from affiliates of our Sponsors and the Contributing Parties. Such efforts may involve participation by us in processes that have been made public and involve a number of potential buyers or investors, commonly referred to as "auction" processes, as well as situations in which we believe we are the only party or one of a limited number of parties who are in negotiations with the potential seller or other party. These acquisition and investment efforts often involve assets which, if acquired or constructed, could have a material effect on our financial condition and results of operations. Material acquisitions that would impact the comparability of our results for the three months ended March 31, 2021 and 2020 include the acquisition of all of the equity interests in Springbok Energy Partners, LLC and Springbok Energy Partners II, LLC (the “Springbok Acquisition”).

Further, the affiliates of our Sponsors and Contributing Parties 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 parties offer them to us. We may decide to fund any acquisition, including any potential dropdowns, with cash, common units, other equity securities, proceeds from borrowings under our secured revolving credit facility or the issuance of debt securities, or any combination thereof. In addition to acquisitions, we also consider from time to time divestitures that may benefit us and our unitholders.

We typically do not announce a transaction until after we have executed a definitive agreement. Past experience has demonstrated that discussions and negotiations regarding a potential transaction can advance or terminate in a short period of time. Moreover, the closing of any transaction for which we have entered into a definitive agreement may be subject to customary and other closing conditions, which may not ultimately be satisfied or waived. Accordingly, we can give no assurance that our current or future acquisition or investment efforts will be successful or that our strategic asset divestitures will be completed. Although we expect the acquisitions and investments we make to be accretive in the long term, we can provide no assurance that our expectations will ultimately be realized. We will not know the immediate results of any acquisition until after the acquisition closes, and we will not know the long-term results for some time thereafter.

Impairment of Oil and Natural Gas Properties

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

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We did not record an impairment on our oil and natural gas properties for the three months ended March 31, 2021. For the three months ended March 31, 2020, we recorded an impairment on our oil and natural gas properties of $70.9 million, which can primarily be attributed to the factors mentioned below.

After evaluating certain external factors in the first quarter of 2020, including a significant decline in oil and natural gas prices related to reduced demand for oil and natural gas as a result of the COVID-19 pandemic, the announcement of price reductions and production increases in March 2020 by members of OPEC and other foreign, oil-exporting countries and other supply factors, as well as longer-term commodity price outlooks, we determined that significant drilling uncertainty existed regarding our proved undeveloped (“PUD”) reserves that were included in our total estimated proved reserves as of December 31, 2019, as well as our unevaluated oil and natural gas properties. Specifically, with respect to our PUD reserves (which accounted for approximately 6.1% of total estimated proved reserves as of December 31, 2019), we determined that we did not have reasonable certainty as to the timing of the development of the PUD reserves and, therefore, recorded an impairment on such properties for the three months ended March 31, 2020. We similarly recorded an impairment on the value of our unevaluated oil and natural gas properties for the three months ended March 31, 2020, which primarily were acquired in various acquisitions since our initial public offering.

Because we do not intend to book PUD reserves going forward, additional impairment charges could be recorded in connection with future acquisitions. Further, if the price of oil, natural gas and NGLs decreases in future periods, we may be required to record additional impairments as a result of the full-cost ceiling limitation.

Results of Operations

The table below summarizes our revenue and expenses and production data for the periods indicated (unaudited).

Three Months Ended March 31, 

2021

2020

Operating Results:

Revenue

Oil, natural gas and NGL revenues

$

36,368,510

$

25,585,439

Lease bonus and other income

186,308

229,319

(Loss) gain on commodity derivative instruments, net

(14,135,728)

10,132,613

Total revenues

22,419,090

35,947,371

Costs and expenses

Production and ad valorem taxes

 

2,431,830

 

1,621,743

Depreciation and depletion expense

 

7,911,148

 

13,270,683

Impairment of oil and natural gas properties

 

 

70,925,731

Marketing and other deductions

 

3,295,286

 

2,131,552

General and administrative expenses

 

6,796,385

 

6,524,311

Total costs and expenses

 

20,434,649

 

94,474,020

Operating income (loss)

 

1,984,441

 

(58,526,649)

Other income (expense)

Equity income in affiliate

185,080

163,554

Interest expense

 

(2,095,098)

 

(1,421,304)

Other income

 

462,771

 

Net income (loss) before income taxes

537,194

(59,784,399)

Provision for income taxes

Net income (loss)

537,194

(59,784,399)

Distribution and accretion on Series A preferred units

(1,577,968)

(3,076,684)

Net loss attributable to noncontrolling interests

357,179

23,584,856

Distribution on Class B units

(20,780)

(24,807)

Net loss attributable to common units

$

(704,375)

$

(39,301,034)

Production Data:

Oil (Bbls)

 

319,649

 

334,149

Natural gas (Mcf)

 

4,500,314

 

4,264,345

Natural gas liquids (Bbls)

 

165,189

 

170,689

Combined volumes (Boe) (6:1)

 

1,234,890

 

1,215,562

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Comparison of the Three Months Ended March 31, 2021 to the Three Months Ended March 31, 2020

Oil, Natural Gas and NGL Revenues

For the three months ended March 31, 2021, our oil, natural gas and NGL revenues were $36.4 million, an increase of $10.8 million from $25.6 million for the three months ended March 31, 2020. The increase in oil, natural gas and NGL revenues was directly related to the increase in the average prices we received for oil, natural gas and NGL production for the three months ended March 31, 2021 as discussed below.

Our revenues are a function of oil, natural gas, and NGL production volumes sold and average prices received for those volumes. The production volumes were 1,234,890 Boe or 13,721 Boe/d, for the three months ended March 31, 2021, an increase of 19,328 Boe or 363 Boe/d, from 1,215,562 Boe or 13,358 Boe/d, for the three months ended March 31, 2020. The increase in production for the three months ended March 31, 2021 was primarily attributable to production associated with the Springbok Acquisition, which accounted for 180,066 Boe or 2,001 Boe/d. The increase was offset by a reduction in production on our other assets as a result of the COVID-19 outbreak and international supply and demand imbalances and, to a lesser extent, the winter storms experienced in parts of the United States in February 2021, which caused the temporary shut-in of certain properties in which we have an interest. See Business EnvironmentCOVID-19 Pandemic and Impact on Global Demand for Oil and Natural Gas for further discussion.

Our operators received an average of $54.52 per Bbl of oil, $3.31 per Mcf of natural gas and $24.45 per Bbl of NGL for the volumes sold during the three months ended March 31, 2021 compared to $45.25 per Bbl of oil, $1.93 per Mcf of natural gas and $13.17 per Bbl of NGL for the volumes sold during the three months ended March 31, 2020. The three months ended March 31, 2021 increased 20.5% or $9.27 per Bbl of oil and 71.5% or $1.38 per Mcf of natural gas as compared to the three months ended March 31, 2020. This change is consistent with prices experienced in the market, specifically when compared to the EIA average price increases of 27.6% or $12.55 per Bbl of oil and 84.2% or $1.60 per Mcf of natural gas for the comparable periods.

Lease Bonus and Other Income

Lease bonus and other income remained flat at $0.2 million for both the three months ended March 31, 2021 and 2020.

(Loss) Gain on Commodity Derivative Instruments

Loss on commodity derivative instruments for the three months ended March 31, 2021 included $13.2 million of mark-to-market losses and $1.0 million of losses on the settlement of commodity derivative instruments compared to $9.0 million of mark-to-market gains and $1.1 million of gains on the settlement of commodity derivative instruments for the three months ended March 31, 2020. We recorded a mark-to-market loss for the three months ended March 31, 2021 as a result of the increase in strip pricing from the three months ended December 31, 2020 to the three months ended March 31, 2021. The mark-to-market gain recorded for the three months ended March 31, 2020 was due to the decrease in the price of oil and natural gas contracts relative to the fixed-price in our open derivative contracts.

Production and Ad Valorem Taxes

Production and ad valorem taxes for the three months ended March 31, 2021 were $2.4 million, an increase of $0.8 million from $1.6 million for the three months ended March 31, 2020. The increase in production and ad valorem taxes was primarily attributable to the Springbok Acquisition and the increase in the average prices we received for oil, natural gas and NGL production for the three months ended March 31, 2021.

Depreciation and Depletion Expense

Depreciation and depletion expense for the three months ended March 31, 2021 was $7.9 million, a decrease of $5.4 million from $13.3 million for the three months ended March 31, 2020. The decrease in depreciation and depletion expense was due to the impairment that was recorded during the year ended December 31, 2020, which significantly reduced our net capitalized oil and natural gas properties.

27

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 reserves are a major component in the calculation of depletion. Our average depletion rate per barrel was $6.22 for the three months ended March 31, 2021, a decrease of $4.64 per barrel from the $10.86 average depletion rate per barrel for the three months ended March 31, 2020. The decrease in the depletion rate was due to the significant impairment that was recorded during the year ended December 31, 2020, which significantly reduced our net capitalized oil and natural gas properties.

Impairment of Oil, Natural Gas and Natural Gas Liquids Expense

We did not record an impairment expense on our oil and natural gas properties for the three months ended March 31, 2021. We recorded an impairment expense on our oil and natural gas properties of $70.9 million during the three months ended March 31, 2020. The impairment recorded during the three months ended March 31, 2020 was due to a significant decline in the trailing twelve month average of oil and natural gas prices, related to reduced demand for oil and natural gas as a result of COVID-19, the announcement of price reductions and production increases in March 2020 by members of OPEC and other foreign, oil-exporting countries, and other supply factors.

Marketing and Other Deductions

Our marketing and other deductions include product marketing expense, which is a post-production expense. Marketing and other deductions for the three months ended March 31, 2021 were $3.3 million, an increase of $1.2 million from $2.1 million for the three months ended March 31, 2020, which was primarily attributable to the Springbok Acquisition.

General and Administrative Expenses

General and administrative expenses for the three months ended March 31, 2021 were $6.8 million, an increase of $0.3 million from $6.5 million for the three months ended March 31, 2020. Included within general and administrative expenses are non-cash expenses for unit-based compensation as a result of the amortization of restricted units that have been issued by us over various periods. The increase in general and administrative expenses was primarily attributable to a $0.6 million increase in unit-based compensation expense, which was partially offset by a $0.3 million decrease in cash general and administrative expenses.

Interest Expense

Interest expense for the three months ended March 31, 2021 was $2.1 million compared to $1.4 million for the three months ended March 31, 2020. The increase in interest expense was primarily due to debt incurred to fund the Springbok Acquisition. The increase in interest expense was partially offset by the decline in the weighted average interest rate from 4.70% during the three months ended March 31, 2020 to 3.75% during the three months ended March 31, 2021.

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. See “Indebtedness” below for further discussion of our secured revolving credit facility.

Cash Distribution Policy

The limited liability company agreement of the Operating Company requires it to distribute all of its cash on hand at the end of each quarter in an amount equal to its available cash for such quarter. In turn, 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. Available cash for each quarter will be determined by the Board of Directors following the end of such quarter. “Available cash,” as used in this context, is defined in the limited liability company agreement of the Operating Company

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and our partnership agreement. We expect that the Operating Company’s available cash for each quarter will generally equal its 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, and we expect that our available cash for each quarter will generally equal our Adjusted EBITDA for the quarter (and will be our proportional share of the available cash distributed by the Operating Company for that quarter), less cash needs for debt service and other contractual obligations, tax obligations, fixed charges and reserves for future operating or capital needs that the Board of Directors may determine is appropriate.

In light of the unprecedented global economic impact resulting from the COVID-19 pandemic, the related impact to the United States oil and natural gas markets and the potential for further curtailments of production, the Board of Directors approved the allocation of 25% of our cash available for distribution on common units for the first quarter of 2021 for the repayment of $5.6 million in outstanding borrowings under our secured revolving credit facility during its determination of “available cash” for the first quarter of 2021. With respect to future quarters, the Board of Directors intends to continue to allocate a portion of our cash available for distribution on common units to the repayment of outstanding borrowings under our secured revolving credit facility and may allocate such cash in other manners in which the Board of Directors determines to be appropriate at the time. The Board of Directors may further change its policy with respect to cash distributions in the future.

We do not currently maintain a material reserve of cash for the purpose of maintaining stability or growth in our quarterly distribution, nor do we intend to incur debt to pay quarterly distributions, although the Board of Directors may change this policy.

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. For example, we issued 2,224,358 common units and 2,497,134 OpCo common units and an equal number of Class B units as partial consideration in connection with the Springbok Acquisition. 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 (i) maintain excess distribution coverage for the purpose of maintaining stability or growth in our quarterly distribution, (ii) otherwise reserve cash for distributions or (iii) incur debt to pay quarterly distributions, although the Board of Directors may do so if they believe it is warranted. See “Recent Developments—Quarterly Distributions” above for discussion of our first quarter 2021 distributions.

Cash Flows

The table below presents our cash flows for the periods indicated.

Three Months Ended March 31, 

2021

   

2020

Cash Flow Data:

Net cash provided by operating activities

$

15,480,993

$

20,787,606

Net cash used in investing activities

 

(811,651)

 

(11,176,643)

Net cash used in financing activities

 

(16,349,984)

 

(9,334,346)

Net (decrease) increase in cash and cash equivalents

$

(1,680,642)

$

276,617

Operating Activities

Our operating cash flow is impacted by many variables, the most significant of which are changes in oil, natural gas and NGL production volumes due to acquisitions or other external factors and changes 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 control and are difficult to predict. Cash flows provided by operating activities for the three months ended March 31, 2021 were $15.5 million, a decrease of $5.3 million compared to $20.8 million for the three months ended March 31, 2020.

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Investing Activities

Cash flows used in investing activities for the three months ended March 31, 2021 decreased by $10.4 million compared to the three months ended March 31, 2020. For the three months ended March 31, 2021, we used $0.5 million primarily to fund the acquisition of assets from Nail Bay Royalties, LLC (“Nail Bay Royalties”) and Oil Nut Bay Royalties, LP (“Oil Nut Bay”) and $0.4 million primarily to fund the renovation of office, partially offset by a $0.05 million cash distribution received in connection with a joint venture (the “Joint Venture”) with Springbok SKR Capital Company, LLC and Rivercrest Capital Partners, LP during the period. For the three months ended March 31, 2020, we used $9.7 million to fund the deposit on oil and natural gas properties and $1.3 million to fund capital commitments of the Joint Venture.

Financing Activities

Cash flows used in financing activities were $16.3 million for the three months ended March 31, 2021, an increase of $7.0 million compared to $9.3 million for the three months ended March 31, 2020. Cash flows used in financing activities for the three months ended March 31, 2021 consists of $12.3 million of distributions paid to holders of common units and OpCo common units, Series A preferred units and Class B units, $3.5 million used to repay borrowings under out secured revolving credit facility, $0.9 million of restricted units repurchased for tax withholding and $0.08 million payment of loan origination costs, partially offset by $0.5 million of additional borrowings under our secured revolving credit facility. Cash flows used in financing activities for the three months ended March 31, 2020 consists of $70.0 million used to repay borrowings under our secured revolving credit facility, $61.1 million to fund the redemption of Series A preferred units and $22.7 million of distributions paid to holders of common units and OpCo common units, Series A preferred units and Class B units, partially offset by $73.6 million in proceeds from the 2020 Equity Offering and $71.1 million of additional borrowings under our secured revolving credit facility.

Capital Expenditures

During the three months ended March 31, 2021, we paid approximately $0.5 million primarily in connection with the acquisition of assets from Nail Bay Royalties and Oil Nut Bay. During the three months ended March 31, 2020, we paid approximately $0.2 million primarily in connection with the acquisition of certain mineral and royalty assets from certain affiliates of Buckhorn Resources GP, LLC.

Indebtedness

On January 11, 2017, we entered into a credit agreement (the “2017 Credit Agreement”) with Frost Bank, as administrative agent, and the lenders party thereto. On July 12, 2018 we entered into an amendment (the “First Credit Agreement Amendment”) to the 2017 Credit Agreement (the 2017 Credit Agreement as amended by the First Credit Agreement Amendment, the “2018 Amended Credit Agreement”). On December 8, 2020, we entered into the Second Credit Agreement Amendment to the 2018 Amended Credit Agreement (the 2018 Amended Credit Agreement as amended by the Second Credit Agreement Amendment, the “Amended Credit Agreement”). Under the Amended Credit Agreement, availability under our secured revolving credit facility will continue to equal the lesser of the aggregate maximum elected commitments of the lenders, which may be increased up to $500.0 million, subject to the satisfaction of certain conditions and the election of existing lenders to increase commitments or the procurement of additional commitments from new lenders, and the borrowing base. The Second Credit Agreement Amendment amended the 2018 Amended Credit Agreement to extend the maturity date thereunder from February 8, 2022 to June 7, 2024.

The Second Credit Agreement Amendment increased aggregate commitments under the 2018 Amended Credit Agreement from $225.0 million to $265.0 million providing for maximum availability of $265.0 million. The Amended Credit Agreement permits aggregate commitments under the secured revolving credit facility to be increased up to $500.0 million, subject to the limitations of our borrowing base and satisfaction of certain conditions, including the election of existing lenders to increase commitments or the procurement of additional commitments from new lenders and the borrowing base. In connection with our entry into the Second Credit Agreement Amendment, the borrowing base was set at $265.0 million. The borrowing base will be redetermined semiannually on May 1 and November 1 of each year, beginning May 1, 2021, based on the value of our oil and natural gas properties and the oil and natural gas properties of our wholly owned subsidiaries. The May borrowing base redetermination is currently being conducted and is expected to be finalized by the end of May 2021.

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The Amended Credit Agreement 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 and OpCo 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 Amended Credit Agreement 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 3.5 to 1.0; and (ii) a ratio of current assets to current liabilities of not less than 1.0 to 1.0. The Amended Credit Agreement 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 31, 2021, we had outstanding borrowings of $168.5 million under the secured revolving credit facility and $96.5 million of available capacity.

For additional information on our secured revolving credit facility, please read Note 8―Long-Term Debt to the unaudited interim condensed consolidated financial statements included in this Quarterly Report.

New and Revised Financial Accounting Standards

The effects of new accounting pronouncements are discussed in Note 2—Summary of Significant Accounting Policies to our unaudited interim condensed consolidated financial statements included elsewhere in this Quarterly Report.

Critical Accounting Policies and Related Estimates

There have been no substantial changes to our critical accounting policies and related estimates from those previously disclosed in our 2020 Form 10-K.

Contractual Obligations and Off-Balance Sheet Arrangements

There have been no significant changes to our contractual obligations previously disclosed in our 2020 Form 10-K. As of March 31, 2021, we did not have any off-balance sheet arrangements. See Note 7—Leases to the unaudited interim condensed consolidated financial statements for additional information regarding our operating leases.

Item 3. 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 commodity prices to be even more volatile in the future as a result of COVID-19, ongoing international supply and demand imbalances and limited international storage capacity. 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.

Our commodity derivative contracts consist of fixed price swaps, under which we receive a fixed price for the contract and pay 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

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Note 4—Derivatives to the unaudited interim condensed consolidated financial statements in Item 1 of this Quarterly Report for additional information regarding our 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 March 31, 2021, we had two counterparties to our derivative contracts, which are also lenders under our secured revolving 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. 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 March 31, 2021, we had total borrowings outstanding under our secured revolving credit facility of $168.5 million. The impact of a 1% increase in the interest rate on this amount of debt could result in an increase in interest expense of approximately $1.7 million annually, assuming that our indebtedness remained constant throughout the year.

On January 27, 2021, we entered into an interest rate swap with Citibank, which fixed the interest rate on $150.0 million of the notional balance on our secured revolving credit facility (which represented approximately 89% of our outstanding balance as of March 31, 2021), at approximately 3.9% for the period ending on January 29, 2024. We use an interest rate swap for the management of interest rate risk exposure, as the interest rate swap effectively converts a portion of our secured revolving credit facility from a floating to a fixed rate. As of March 31, 2021, we recognized a $0.5 million gain on interest rate swaps which is included in other income in the accompanying unaudited interim condensed consolidated statements of operations.

Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

As required by Rule 13a-15(b) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”), we have evaluated, under the supervision and with the participation of the 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 such terms are defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this Quarterly 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 U.S. Securities and Exchange Commission (the “SEC”). Based upon that evaluation, our General Partner’s management, including its principal executive officer and principal financial officer concluded that as of March 31, 2021, our disclosure controls and procedures were effective in ensuring that all information required to be disclosed by us in reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC rules and forms, and that such information is accumulated and communicated to our General Partner’s management, including its principal executive officer and principal financial officer, in a manner that allows timely decisions regarding required disclosure.

Changes in Internal Control over Financial Reporting

There have not been any changes in our internal control over financial reporting that occurred during the quarter ended March 31, 2021 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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PART II – OTHER INFORMATION

Item 1. Legal Proceedings

For a description of the Partnership’s legal proceedings, see Note 15—Commitments and Contingencies to the unaudited interim condensed consolidated financial statements included in Part I of this Quarterly Report and incorporated by reference herein.

Item 1A. Risk Factors

In addition to the risks and uncertainties discussed in this Quarterly Report, particularly those disclosed in Part I, Item 2: Management’s Discussion and Analysis of Financial Condition and Results of Operations, you should carefully consider the risks under the heading “Risk Factors” in Part I, Item 1A. Risk Factors in our 2020 Form 10-K. There have been no material changes to the risk factors previously discussed under the heading “Risk Factors” in Item 1A. Risk Factors in the Partnership’s 2020 Form 10-K. These risks are not the only risks that we face. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial may materially adversely affect our business, financial condition or results of operations.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

The issuance of each of the foregoing securities was exempt from the registration requirements of the Securities Act of 1933, as amended (the “Securities Act”), in reliance upon Section 4(a)(2) of the Securities Act.

Period

Total Number of Common Units Purchased(1)

Average Price Paid per Common Unit

Total Number of Common Units Purchased as Part of Publicly Announced Plans or Programs(2)

Maximum Number of Common Units That May Yet be Purchased Under the Plans or Programs(2)

January 1, 2021 - January 31, 2021

$

February 1, 2021 - February 28, 2021

$

March 1, 2021 - March 31, 2021

85,360

$

10.78

(1)All of the common units shown above were withheld during the three months ended March 31, 2021 to satisfy tax-withholding obligations arising in conjunction with the vesting of restricted units. The required withholding is calculated using the closing sales price per common unit reported by the New York Stock Exchange on the date prior to the applicable vesting date.
(2)We did not have at any time during the quarter ended March 31, 2021, and currently do not have, a common unit repurchase program in place.

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Item 6. Exhibits

Exhibit
Number

      

Description

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

Third Amended and Restated Agreement of Limited Partnership of Kimbell Royalty Partners, LP, dated as of September 23, 2018 (incorporated by reference to Exhibit 3.1 to Kimbell Royalty Partners, LP’s Current Report on Form 8-K filed September 25, 2018)

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 Current Report on Form 8-K filed on February 14, 2017)

3.5

First Amended and Restated Limited Liability Company Agreement of Kimbell Royalty Operating, LLC, dated as of September 23, 2018 (incorporated by reference to Exhibit 3.2 to Kimbell Royalty Partners, LP’s Current Report on Form 8-K filed September 25, 2018)

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

101.INS*

Inline XBRL Instance Document —the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document

101.SCH*

Inline XBRL Taxonomy Extension Schema Document

101.CAL*

Inline XBRL Taxonomy Extension Calculation Linkbase Document

101.DEF*

Inline XBRL Taxonomy Extension Definition Linkbase Document

101.LAB*

Inline XBRL Taxonomy Extension Label Linkbase Document

101.PRE*

Inline XBRL Taxonomy Extension Presentation Linkbase Document

104*

Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101)

*

—filed herewith

**

—furnished herewith

34

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: May 6, 2021

By:

/s/ Robert D. Ravnaas

Name:

Robert D. Ravnaas

Title:

Chief Executive Officer and Chairman

Principal Executive Officer

Date: May 6, 2021

    

By:

/s/ R. Davis Ravnaas

Name:

R. Davis Ravnaas

Title:

President and Chief Financial Officer

Principal Financial Officer

35