10-Q 1 krp-20240331x10q.htm 10-Q
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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, 2024

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 (§232.405 of this chapter) 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 26, 2024, the registrant had outstanding 74,646,476 common units representing limited partner interests and 20,847,295 Class B units representing limited partner interests.

PART I – FINANCIAL INFORMATION

Item 1. Consolidated Financial Statements (Unaudited)

KIMBELL ROYALTY PARTNERS, LP

CONSOLIDATED BALANCE SHEETS

(Unaudited)

March 31, 

December 31, 

2024

2023

ASSETS

Current assets

Cash and cash equivalents

$

39,679,620

$

30,992,670

Oil, natural gas and NGL receivables

54,704,277

59,020,471

Derivative assets

6,073,891

11,427,735

Accounts receivable and other current assets

2,849,066

1,699,536

Total current assets

103,306,854

103,140,412

Property and equipment, net

532,037

589,895

Oil and natural gas properties

Oil and natural gas properties, using full cost method of accounting ($172,373,481 and $222,712,844 excluded from depletion at March 31, 2024 and December 31, 2023, respectively)

2,048,711,692

2,048,690,088

Less: accumulated depreciation, depletion and impairment

(871,067,953)

(827,033,944)

Total oil and natural gas properties, net

1,177,643,739

1,221,656,144

Right-of-use assets, net

2,102,919

2,189,243

Derivative assets

673,728

2,888,051

Loan origination costs, net

6,811,840

7,325,471

Total assets

$

1,291,071,117

$

1,337,789,216

LIABILITIES, MEZZANINE EQUITY AND UNITHOLDERS' EQUITY

Current liabilities

Accounts payable

$

6,854,075

$

6,594,736

Other current liabilities

5,325,703

6,173,314

Derivative liabilities

208,710

Total current liabilities

12,179,778

12,976,760

Operating lease liabilities, excluding current portion

1,795,924

1,887,693

Derivative liabilities

1,438,351

60,094

Long-term debt

285,359,776

294,200,000

Other liabilities

166,667

197,917

Total liabilities

300,940,496

309,322,464

Commitments and contingencies (Note 16)

Mezzanine equity:

Series A preferred units (325,000 units issued and outstanding as of March 31, 2024 and December 31, 2023)

314,818,215

314,423,572

Kimbell Royalty Partners, LP unitholders' equity:

Common units (74,646,476 units and 73,851,458 units issued and outstanding as of March 31, 2024 and December 31, 2023, respectively)

640,371,650

670,530,748

Class B units (20,847,295 units issued and outstanding as of March 31, 2024 and December 31, 2023)

1,042,365

1,042,365

Total Kimbell Royalty Partners, LP unitholders' equity

641,414,015

671,573,113

Non-controlling interest in OpCo

33,898,391

42,470,067

Total unitholders' equity

675,312,406

714,043,180

Total liabilities, mezzanine equity and unitholders' equity

$

1,291,071,117

$

1,337,789,216

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

1

KIMBELL ROYALTY PARTNERS, LP

CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

Three Months Ended March 31, 

2024

2023

Revenue

Oil, natural gas and NGL revenues

$

87,499,509

$

57,416,759

Lease bonus and other income

438,796

437,337

(Loss) gain on commodity derivative instruments, net

(5,704,361)

9,062,376

Total revenues

82,233,944

66,916,472

Costs and expenses

Production and ad valorem taxes

6,531,901

4,277,204

Depreciation and depletion expense

38,166,806

17,563,648

Impairment of oil and natural gas properties

5,963,575

Marketing and other deductions

4,562,944

2,762,039

General and administrative expense

9,447,881

8,278,267

Consolidated variable interest entities related:

General and administrative expense

708,226

Total costs and expenses

64,673,107

33,589,384

Operating income

17,560,837

33,327,088

Other income (expense)

Interest expense

(7,301,330)

(5,463,404)

Consolidated variable interest entities related:

Interest earned on marketable securities in trust account

2,438,837

Net income before income taxes

10,259,507

30,302,521

Income tax expense

922,568

1,402,983

Net income

9,336,939

28,899,538

Distribution and accretion on Series A preferred units

(5,256,287)

Net income and distributions and accretion on Series A preferred units attributable to non-controlling interests

(890,849)

(5,563,418)

Distribution on Class B units

(20,847)

(15,484)

Net income attributable to common units of Kimbell Royalty Partners, LP

$

3,168,956

$

23,320,636

Net income per unit attributable to common units of Kimbell Royalty Partners, LP

Basic

$

0.04

$

0.37

Diluted

$

0.04

$

0.36

Weighted average number of common units outstanding

Basic

72,112,056

62,541,565

Diluted

116,539,624

79,757,979

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

2

KIMBELL ROYALTY PARTNERS, LP

CONSOLIDATED STATEMENTS OF CHANGES IN UNITHOLDERS’ EQUITY

(Unaudited)

Three Months Ended March 31, 2024

Non-controlling

   

Common Units

   

Amount

   

Class B Units

   

Amount

Interest
in OpCo

Total

Balance at January 1, 2024

73,851,458

$

670,530,748

20,847,295

$

1,042,365

$

42,470,067

$

714,043,180

Restricted units repurchased for tax withholding

(292,484)

(4,914,149)

(4,914,149)

Unit-based compensation

1,087,502

3,684,080

3,684,080

Distributions to unitholders

(32,097,985)

(9,462,525)

(41,560,510)

Distribution and accretion on Series A preferred units

(4,108,784)

(1,147,503)

(5,256,287)

Distribution on Class B units

(20,847)

(20,847)

Net income

7,298,587

2,038,352

9,336,939

Balance at March 31, 2024

74,646,476

$

640,371,650

20,847,295

$

1,042,365

$

33,898,391

$

675,312,406

3

KIMBELL ROYALTY PARTNERS, LP

CONSOLIDATED STATEMENTS OF CHANGES IN UNITHOLDERS’ EQUITY — (Continued)

(Unaudited)

Three Months Ended March 31, 2023

Non-controlling

   

Common Units

   

Amount

   

Class B Units

   

Amount

Interest
in OpCo

Total

Balance at January 1, 2023

64,231,833

$

601,841,776

15,484,400

$

774,220

$

(26,106,320)

$

576,509,676

Restricted units repurchased for tax withholding

(279,662)

(4,851,962)

(4,851,962)

Unit-based compensation

998,162

3,170,000

3,170,000

Distributions to unitholders

(31,176,160)

(7,436,615)

(38,612,775)

Distribution on Class B units

(15,484)

(15,484)

Net income

23,336,120

5,563,418

28,899,538

Balance at March 31, 2023

64,950,333

$

592,304,290

15,484,400

$

774,220

$

(27,979,517)

$

565,098,993

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

4

KIMBELL ROYALTY PARTNERS, LP

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

Three Months Ended March 31, 

2024

   

2023

CASH FLOWS FROM OPERATING ACTIVITIES

Net income

$

9,336,939

$

28,899,538

Adjustments to reconcile net income to net cash provided by operating activities:

Depreciation and depletion expense

38,166,806

17,563,648

Impairment of oil and natural gas properties

5,963,575

Amortization of right-of-use assets

86,324

83,157

Amortization of loan origination costs

530,130

516,098

Unit-based compensation

3,684,080

3,170,000

Loss (gain) on derivative instruments, net of settlements

8,737,714

(12,499,601)

Changes in operating assets and liabilities:

Oil, natural gas and NGL receivables

4,316,194

11,058,014

Accounts receivable and other current assets

(1,149,530)

513,812

Accounts payable

312,764

(290,521)

Other current liabilities

(847,611)

255,526

Operating lease liabilities

(91,769)

(85,018)

Consolidated variable interest entities related:

Interest earned on marketable securities in trust account

(2,438,837)

Other assets and liabilities

307,790

Net cash provided by operating activities

69,045,616

47,053,606

CASH FLOWS FROM INVESTING ACTIVITIES

Purchases of property and equipment

(69,763)

(39,798)

Purchase of oil and natural gas properties

(21,605)

(281,844)

Net cash used in investing activities

(91,368)

(321,642)

CASH FLOWS FROM FINANCING ACTIVITIES

Distribution to common unitholders

(32,097,985)

(31,176,160)

Distribution to OpCo unitholders

(9,462,525)

(7,436,615)

Distribution on Series A preferred units

(4,915,069)

Distribution on Class B units

(20,847)

(15,484)

Borrowings on long-term debt

4,959,776

4,000,000

Repayments on long-term debt

(13,800,000)

(13,100,000)

Payment of loan origination costs

(16,499)

Restricted units repurchased for tax withholding

(4,914,149)

(4,851,962)

Net cash used in financing activities

(60,267,298)

(52,580,221)

NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS

8,686,950

(5,848,257)

CASH AND CASH EQUIVALENTS, beginning of period

30,992,670

25,026,568

CASH AND CASH EQUIVALENTS, end of period

$

39,679,620

$

19,178,311

Supplemental cash flow information:

Cash paid for interest

$

6,696,655

$

5,106,816

Non-cash investing and financing activities:

Noncash deemed distribution to Series A preferred units

$

394,643

$

Distribution on Series A preferred units in accounts payable

$

4,861,644

$

Recognition of tenant improvement asset

$

31,250

$

31,250

5

KIMBELL ROYALTY PARTNERS, LP

CONSOLIDATED STATEMENTS OF CASH FLOWS — (Continued)

(Unaudited)

Three Months Ended March 31, 

2024

   

2023

Reconciliation of Cash and Cash Equivalents and Cash Held at Consolidated Variable Interest Entities to the Consolidated Statements of Cash Flows

Cash and cash equivalents

$

39,679,620

$

19,077,381

Cash held at consolidated variable interest entities

100,930

$

39,679,620

$

19,178,311

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

6

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” or “OpCo” 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. 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 consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) for interim financial information and with the instructions to Form 10-Q and pursuant to the rules and regulations of the United States Securities and Exchange Commission (the “SEC”). As a result, the accompanying unaudited interim consolidated financial statements do not include all disclosures required for complete annual financial statements prepared in conformity with GAAP. Accordingly, the accompanying unaudited interim 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, 2023 (the “2023 Form 10-K”), 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 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. The accompanying unaudited interim consolidated financial statements include the accounts of the Partnership and its consolidated subsidiaries. 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.

Use of Estimates

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.

7

Global Conflicts

In February 2022, Russia invaded Ukraine and is still engaged in active armed conflict against the country. In October 2023, armed active conflict escalated in the Middle East between Israel and Hamas and is still active. In April 2024, Iran launched an attack on Israel, further escalating the regional conflict in the Middle East. These conflicts and the sanctions imposed in response have led to regional instability and caused dramatic fluctuations in global financial markets and have increased the level of global economic and political uncertainty, including uncertainty about world-wide oil supply and demand, which in turn has increased volatility in commodity prices. To date, the Partnership has not experienced a material impact to operations or the consolidated financial statements as a result of these conflicts; however, the Partnership will continue to monitor for events that could materially impact them.

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 2023 Form 10-K, 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, 2024.

Consolidation

The Partnership analyzes whether it has a variable interest in an entity and whether that entity is a variable interest entity (“VIE”) to determine whether it is required to consolidate those entities. The Partnership performs the variable interest analysis for all entities in which it has a potential variable interest, which primarily consist of all entities with respect to which the Partnership serves as the sponsor, general partner or managing member, and general partner entities not wholly owned by the Partnership. If the Partnership has a variable interest in the entity and the entity is a VIE, it will also analyze whether the Partnership is the primary beneficiary of this entity and whether consolidation is required.

In evaluating whether it has a variable interest in the entity, the Partnership reviews the equity ownership and the extent to which it absorbs risk created and distributed by the entity, as well as whether the fees charged to the entity are customary and commensurate with the level of effort required to provide services. Fees received by the Partnership are not variable interests if (i) the fees are compensation for services provided and are commensurate with the level of effort required to provide those services, (ii) the service arrangement includes only terms, conditions, or amounts that are customarily present in arrangements for similar services negotiated at arm’s length and (iii) the Partnership’s other economic interests in the VIE held directly and indirectly through its related parties, as well as economic interests held by related parties under common control, where applicable, would not absorb more than an insignificant amount of the entity’s losses or receive more than an insignificant amount of the entity’s benefits. Evaluation of these criteria requires judgment.

For entities determined to be VIEs, the Partnership must then evaluate whether it is the primary beneficiary of such VIEs. To make this determination, the Partnership evaluates its economic interests in the entity specifically determining if the Partnership has both the power to direct the activities of the VIE that most significantly impact the VIE’s economic performance and the obligation to absorb losses or the right to receive benefits that could potentially be significant to the VIE (the “benefits”). When making the determination on whether the benefits received from an entity are significant, the Partnership considers the total economics of the entity, and analyzes whether the Partnership’s share of the economics is significant. The Partnership utilizes qualitative factors, and, where applicable, quantitative factors, while performing the analysis.

VIEs of which the Partnership is the primary beneficiary have been included in the Partnership’s consolidated financial statements. The portion of the consolidated subsidiaries owned by third parties and any related activity is eliminated through non-controlling interests in the consolidated balance sheets and income (loss) attributable to non-controlling interests in the consolidated statements of operations.

Investments Held in Trust by Consolidated Variable Interest Entities

Investments held in trust represented funds raised by Kimbell Tiger Acquisition Corporation (“TGR”), a consolidated special purpose acquisition company, through the TGR’s initial public offering. These funds were held in an

8

actively-traded money market fund, which invested in U.S. Treasury securities. Investments held in trust were classified as trading securities and were presented on the balance sheet at fair value at the end of each reporting period. Gains and losses resulting from the change in fair value of these securities are included in other income (expense)—interest earned on marketable securities in trust account on the accompanying unaudited interim consolidated statements of operations. Interest earned on marketable securities in trust account was $2.4 million for the three months ended March 31, 2023. As discussed further in Note 4, the Partnership completed the dissolution and deconsolidation of TGR (along with related entities) on June 30, 2023.

Recently Issued Accounting Pronouncements

In November 2023, the FASB issued ASU 2023-07, “Segment Reporting (Topic 820): Improvements to Reportable Segment Disclosures.” The amendments in this update apply to all public entities that are required to report segment information in accordance with Topic 280, Segment Reporting. The amendments in this update are effective for fiscal years beginning after December 15, 2023, and interim periods within fiscal years beginning after December 15, 2024. Early adoption is permitted. The Partnership is currently evaluating the impact of the adoption of this update but does not believe it will have a material impact on its financial position, results of operations or liquidity.

In December 2023, the FASB issued ASU 2023-09, “Income Taxes (Topic 740): Improvements to Income Tax Disclosures.” The amendments in this update apply to all entities that are subject to Topic 740, Income Taxes. For public business entities, the amendments in this update are effective for annual periods beginning after December 15, 2024. The Partnership is currently evaluating the impact of the adoption of this update, but does not believe it will have a material impact on its financial position, results of operations or liquidity.

NOTE 3—REVENUE FROM CONTRACTS WITH CUSTOMERS

The Partnership has the right to receive revenues from oil, natural gas and NGL sales obtained by the operator of the wells in which the Partnership owns a mineral or royalty interest. Revenue is recognized at the point control of the product is transferred to the purchaser. Virtually all of the pricing provisions in the Partnership’s contracts are tied to a market index.

The Partnership’s oil, natural gas and NGL sales contracts are generally structured whereby the producer of the properties in which the Partnership owns a mineral or royalty interest sells the Partnership’s proportionate share of oil, natural gas and NGL production to the purchaser and the Partnership collects its percentage royalty based on the revenue generated by the sale of the oil, natural gas and NGL. In this scenario, the Partnership recognizes revenue when control transfers to the purchaser at the wellhead or at the gas processing facility based on the Partnership’s percentage ownership share of the revenue, net of any deductions for gathering and transportation.

The following table disaggregates the Partnership’s oil, natural gas, and NGL revenues for the following periods:

Three Months Ended March 31, 

2024

    

2023

Oil revenue

$

61,627,873

$

33,000,286

Natural gas revenue

14,554,573

19,648,782

NGL revenue

11,317,063

4,767,691

Total Oil, natural gas and NGL revenues

$

87,499,509

$

57,416,759

9

NOTE 4ACQUISITIONS AND SPECIAL PURPOSE ACQUISITION COMPANY

Acquisitions

On September 13, 2023, the Partnership completed the acquisition of all issued and outstanding membership interests of Cherry Creek Minerals LLC pursuant to a securities purchase agreement with LongPoint Minerals II, LLC (the “LongPoint Acquisition”) in a cash transaction valued at approximately $455.0 million. The Partnership funded the cash transaction with borrowings under its secured revolving credit facility and net proceeds from the Preferred Unit Transaction (as defined in Note 10—Preferred Units). The adjusted purchase price of the LongPoint Acquisition includes the total cash consideration of $455.0 million, transactional costs of $7.4 million and less $16.6 million of post-effective net oil, natural gas and NGL revenues earned prior to the closing date. The LongPoint Acquisition was accounted for as an asset acquisition and the allocation of the purchase price was $198.2 million to proved properties and $247.6 million to unevaluated properties.

On May 17, 2023, the Partnership completed the acquisition of certain mineral and royalty assets held by MB Minerals, L.P. and certain of its affiliates (the “MB Minerals Acquisition”). The aggregate consideration for the MB Minerals Acquisition consisted of (i) approximately $48.8 million in cash and (ii) the issuance of (a) 5,369,218 common units of the Operating Company (“OpCo common units”) and an equal number of Class B units representing limited partnership interests in the Partnership (“Class B Units”) and (b) 557,302 common units representing limited partner interests in the Partnership (“common units”). The Partnership funded the cash payment of the purchase price with borrowings under its secured revolving credit facility. The assets acquired in the MB Minerals Acquisition are located in Howard and Borden Counties, Texas. The MB Minerals Acquisition was accounted for as an asset acquisition and the allocation of the purchase price was $60.8 million to proved properties and $74.9 million to unevaluated properties.

Special Purpose Acquisition Company

On February 8, 2022, the Partnership’s previously dissolved special purpose acquisition company and subsidiary, TGR, consummated its $230 million initial public offering. Under the terms of TGR’s governing documents, TGR had until May 8, 2023 to complete a business combination, subject to an option to extend such deadline.

On May 22, 2023, as a result of TGR’s inability to consummate an initial business combination on or prior to May 8, 2023, and pursuant to the terms of its organizational documents, TGR redeemed all of its outstanding shares of Class A common stock of TGR, par value $0.0001 per share (the “Class A common stock”), included as part of the units issued in its initial public offering. The Class A common stock was redeemed on June 22, 2023 and the Partnership completed the dissolution and deconsolidation of TGR (along with related entities) on June 30, 2023 in accordance with the terms of its organizational documents.

NOTE 5DERIVATIVES

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, 2024, 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’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 scheduled trading day for the first nearby month futures contract corresponding to the relevant 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

10

current period and are presented on a net basis within revenue in the accompanying unaudited interim consolidated statements of operations.

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

Three Months Ended March 31, 

2024

2023

Beginning fair value of derivative instruments

$

14,046,982

$

(12,324,076)

(Loss) gain on commodity derivative instruments, net

(5,704,361)

9,062,376

Net cash (received) paid on settlements of derivative instruments

(3,033,353)

3,437,225

Ending fair value of derivative instruments

$

5,309,268

$

175,525

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

2024

2023

Assets:

Current assets

Derivative assets

$

6,073,891

$

11,427,735

Long-term assets

Derivative assets

673,728

2,888,051

Liabilities:

Current liabilities

Derivative liabilities

(208,710)

Long-term liabilities

Derivative liabilities

(1,438,351)

(60,094)

$

5,309,268

$

14,046,982

As of March 31, 2024, 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

April 2024 - December 2024

425,055

$

78.07

$

69.30

$

83.00

January 2025 - December 2025

563,526

$

70.36

$

64.35

$

77.01

January 2026 - March 2026

146,880

$

70.38

$

70.38

$

70.38

Natural Gas Price Swaps

Notional

Weighted Average

Range (per MMBtu)

Volumes (MMBtu)

Fixed Price (per MMBtu)

Low

High

April 2024 - December 2024

3,979,969

$

4.00

$

3.06

$

4.48

January 2025 - December 2025

5,153,291

$

3.81

$

3.50

$

4.37

January 2026 - March 2026

1,296,000

$

4.07

$

4.07

$

4.07

NOTE 6—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 consolidated balance sheets approximated fair value as of March 31, 2024 and December 31, 2023 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.

11

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).

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, 2024 and 2023.

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

The 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, 2024

Assets

Commodity derivative contracts

$

$

6,747,619

$

$

$

6,747,619

Liabilities

Commodity derivative contracts

$

$

(1,438,351)

$

$

$

(1,438,351)

December 31, 2023

Assets

Commodity derivative contracts

$

$

14,315,786

$

$

$

14,315,786

Liabilities

Commodity derivative contracts

$

$

(268,804)

$

$

$

(268,804)

NOTE 7—OIL AND NATURAL GAS PROPERTIES

Oil and natural gas properties consist of the following:

    

March 31, 

December 31, 

2024

2023

Oil and natural gas properties

Proved properties

$

1,876,338,211

$

1,825,977,244

Unevaluated properties

172,373,481

222,712,844

Less: accumulated depreciation, depletion and impairment

(871,067,953)

(827,033,944)

Total oil and natural gas properties

$

1,177,643,739

$

1,221,656,144

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 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

12

determination as to the existence of proved developed 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.

As a result of its full cost ceiling analysis, the Partnership recorded an impairment on its oil and natural gas properties of $6.0 million during the three months ended March 31, 2024. As of March 31, 2024, the 12-month average prices of oil and natural gas were $77.48 per Bbl of oil and $2.45 per Mcf of natural gas. These prices represent a 14.8% and 58.8% decrease, respectively, from the 12-month average prices of oil and natural gas as of March 31, 2023, which were $90.97 per Bbl of oil and $5.95 per Mcf of natural gas. The impairment is primarily attributed to the decline in the 12-month average price of oil and natural gas. The Partnership did not record an impairment on its oil and natural gas properties for the three months ended March 31, 2023.

NOTE 8—LEASES

Substantially all of the Partnership’s leases are long-term operating leases with fixed payment terms and will terminate in June 2029. Currently, the only substantial contractual arrangements that the Partnership has classified as operating leases are the main office spaces used for operations.

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 consolidated balance sheets. Short term operating lease liabilities are included in other current liabilities. The weighted average remaining lease term as of March 31, 2024 is 5.14 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 leases was 6.75% for the three months ended March 31, 2024.

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 consolidated statements of operations for the three months ended March 31, 2024 and 2023. The total operating lease expense recorded for both the three months March 31, 2024 and 2023 was $0.1 million.

Future minimum lease commitments as of March 31, 2024 were as follows:

Total

2024

2025

2026

2027

2028

Thereafter

Operating leases

$

2,590,393

$

366,445

$

497,033

$

507,648

$

511,917

$

496,785

$

210,565

Less: Imputed Interest

 

(439,010)

 

Total

$

2,151,383

 

NOTE 9—LONG-TERM DEBT

On June 13, 2023, the Partnership entered into an Amended and Restated Credit Agreement (the “A&R Credit Agreement”), which amended and restated the Partnership’s existing Credit Agreement, dated as of January 11, 2017 (as amended on July 12, 2018, December 8, 2020, June 7, 2022 and December 15, 2022). The A&R Credit Agreement provides for, among other things, (i) a senior secured reserve-based revolving credit facility in an aggregate maximum principal amount of up to $750.0 million with an initial borrowing base of $400.0 million and an initial aggregate elected commitments amount of up to $400.0 million, including a sub-facility for the issuance of letters of credit of up to $10.0 million and (ii) an extension of the maturity date of the A&R Credit Agreement to June 7, 2027. In connection with the A&R Credit Agreement, the Partnership recorded a loss on extinguishment of debt of $0.5 million as a result of writing off all unamortized loan origination costs associated with the lenders to the Partnership’s existing credit agreement that did not participate in the A&R Credit Agreement.

13

On July 24, 2023, the Partnership entered into Amendment No. 1 (the “First Amendment”) to the A&R Credit Agreement. The amendment amended the A&R Credit Agreement to, among other things, (i) decrease the frequency of and increase the threshold for excess cash determinations from $30.0 million to $50.0 million and (ii) permit the Partnership to issue certain preferred equity interests.

On December 8, 2023, in connection with the November 1, 2023 redetermination, the Partnership entered into Amendment No. 2 (the “Second Amendment”) to the A&R Credit Agreement. The amendment amends the A&R Credit Agreement to, among other things, increase each of the borrowing base and aggregate elected commitments from $400.0 million to $550.0 million.

The secured revolving credit facility bears interest at a rate equal to, at the Partnership’s election, either (i) the Secured Overnight Financing Rate (as defined in the A&R Credit Agreement) plus an applicable margin that varies from 2.75% to 3.75% per annum or (ii) a base rate plus an applicable margin that varies from 1.75% to 2.75% per annum, based on borrowing base utilization.

The secured revolving credit facility is guaranteed by certain of the Partnership’s material subsidiaries and is collateralized by substantially all assets, including the oil and natural gas properties of such subsidiaries, including mortgages on at least 75% of the PV-9 of the proved reserves constituting borrowing base properties as set forth on the Partnership’s most recent reserve report. The borrowing base will be redetermined semi-annually on or about May 1 and November 1 of each year by the Lenders, with one interim unscheduled redetermination available to each of the Partnership and a group of certain Lenders between scheduled redeterminations during each calendar year. The May borrowing base redetermination is currently being conducted and is expected to be finalized by the end of May 2024.

Customary borrowing base reductions and mandatory prepayments are required under the A&R Credit Agreement in connection with certain sales of certain types of borrowing base properties, sales of equity interests in guarantor subsidiaries owning such properties, certain debt issuances or certain types of swap terminations. In addition, Cash Balance (as defined in the First Amendment) above $50.0 million is required to be applied weekly to prepay loans (without a commitment reduction) if not otherwise reduced to zero in a manner permitted by the A&R Credit Agreement.

The Partnership is required to pay a commitment fee of 0.50% per annum on the average daily unused portion of the current aggregate commitments under the secured revolving credit facility. The Partnership is also required to pay customary letter of credit and fronting fees.

The A&R Credit Agreement requires the Partnership to maintain as of the last day of each fiscal quarter: (i) a Debt to EBITDAX Ratio (as defined in the A&R 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 A&R Credit Agreement also contains customary affirmative and negative covenants, including, among other things, as to compliance with laws (including environmental laws and anti-corruption laws), delivery of quarterly and annual financial statements and borrowing base certificates, conduct of business, maintenance of property, maintenance of insurance, entry into certain derivatives contracts, restrictions on the incurrence of liens, indebtedness, asset dispositions, restricted payments, and other customary covenants. These covenants are subject to a number of limitations and exceptions.

Additionally, the A&R Credit Agreement contains customary events of default and remedies for credit facilities of this nature. If the Partnership does not comply with the financial and other covenants in the A&R Credit Agreement, the Lenders may, subject to customary cure rights, require immediate payment of all amounts outstanding under the A&R Credit Agreement and any outstanding unfunded commitments may be terminated.

During the three months ended March 31, 2024, the Partnership borrowed an additional $5.0 million under the secured revolving credit facility and repaid approximately $13.8 million of the outstanding borrowings. As of March 31, 2024, the Partnership’s outstanding balance was $285.4 million. The Partnership was in compliance with all covenants included in the secured revolving credit facility as of March 31, 2024.

As of March 31, 2024, borrowings under the secured revolving credit facility bore interest at SOFR plus a margin of 3.25% or the ABR (as defined in the Amended Credit Agreement) plus a margin of 2.25%. For the three months ended March 31, 2024, the weighted average interest rate on the Partnership’s outstanding borrowings was 8.71%.

14

NOTE 10—PREFERRED UNITS

On August 2, 2023, the Partnership entered into a Series A preferred unit purchase agreement with certain funds managed by affiliates of Apollo (NYSE: APO) (collectively, the “Series A Purchasers”) to issue and sell up to 400,000 Series A Cumulative Convertible Preferred Units representing limited partner interests in the Partnership (the “Series A preferred units”). On September 13, 2023, in connection with the closing of the LongPoint Acquisition, the Partnership completed the private placement of 325,000 Series A preferred units to the Series A Purchasers for $1,000 per Series A preferred unit, resulting in gross proceeds to the Partnership of $325.0 million (the “Preferred Unit Transaction”). The Partnership used the net proceeds from the Preferred Unit Transaction to purchase 325,000 preferred units of the Operating Company. The Operating Company in turn used the net proceeds to fund a portion of the LongPoint Acquisition. The Series A preferred units rank senior to the Partnership’s common units with respect to distribution rights and rights upon liquidation.

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 6.0% per annum plus accrued and unpaid distributions. The Partnership has the right, in any four non-consecutive quarters, to elect not to pay such quarterly distribution in cash and instead have the unpaid distribution amount added to the liquidation preference at the rate of 10.0% per annum. If the Partnership makes such an election in consecutive quarters or if the Partnership fails to pay in full, in cash and when due, any distribution owed to the Series A preferred units or otherwise materially breaches its obligations to the holders of the Series A preferred units, the distribution rate will increase to 20.0% per annum until the accumulated distributions are paid in full in cash, or any such material breach is cured, as applicable. Each holder of Series A preferred units has the right to share in any special distributions by the Partnership of cash, securities or other property pro rata with the common units on an as-converted basis, subject to customary adjustments. The Partnership cannot declare or make any distributions, redemptions or repurchases on any junior securities, including any of their common units, prior to paying the quarterly distribution payable to the Series A preferred units, including any previously accrued and unpaid distributions.

Beginning with the earlier of (i) the second anniversary of the original issuance date and (ii) immediately prior to a liquidation of the Partnership, the Series A Purchasers may, at any time (but not more often than once per quarter), elect to convert all or any portion of their Series A preferred units into a number of common units determined by multiplying the number of Series A preferred units to be converted by the then-applicable conversion rate, provided that (a) any conversion is for an amount of common units with an aggregate value of at least $10.0 million or such lesser amount that covers all of the holders’ remaining Series A preferred units and (b) the closing price of the common units is at least 130% of the conversion price of $15.07, subject to certain anti-dilution adjustments (the “Conversion Price”) for 20 trading days during the 30-trading day period immediately preceding the conversion notice.

At any time on or after the second anniversary of the original issuance date, the Partnership will have the option to convert all or any portion of the Series A preferred units into a number of common units determined by the then-applicable conversion rate, provided that (i) any conversion is for an amount of common units with an aggregate value of at least $10.0 million or such lesser amount that covers all of the holders’ Series A preferred units, (ii) the common units are listed for, or admitted to, trading on a national securities exchange, (iii) the closing price of the common units is at least 160% of the Conversion Price for 20 trading days during the 30-trading day period immediately preceding the conversion notice and (iv) the Partnership has an effective registration statement on file with the SEC covering resales of the underlying common units to be received by the holders of Series A preferred units upon such conversion.

The Series A preferred units are redeemable at the option of the Series A Purchasers after seven years from the effective date of the Series A preferred unit purchase agreement, August 2, 2023. The Series A preferred units may be redeemed by the Partnership at any time or in the event of a change of control. The Series A preferred units may be redeemed for a cash amount per Series A preferred unit equal to the product of (i) the number of outstanding Series A preferred units multiplied by (ii) the greatest of (a) 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), (b) 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 (c) the Series A issue price plus accrued and unpaid distributions.

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For purposes of the Series A preferred units, “Minimum IRR” means as of any measurement date: (i) prior to the fifth anniversary of the original issuance date, a 12.0% internal rate of return with respect to the Series A preferred units; (ii) on or after the fifth anniversary of the original issuance date and prior to the sixth anniversary of the original issuance date, a 13.0% internal rate of return with respect to the Series A preferred units and (iii) on or after the sixth anniversary of the original issuance date, a 14.0% internal rate of return with respect to the Series A preferred units.

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 fifth anniversary of the original issuance date, board appointment rights beginning on the sixth anniversary of the original issuance date, and in the case of events of default with respect to the Series A preferred units, the right to appoint two members of the board beginning on the seventh anniversary of the original issuance date.

The terms of the Series A preferred units contain covenants preventing the Partnership from taking certain actions without the approval of the holders of 662/3% of the outstanding Series A preferred units, voting separately as a class.

NOTE 11—UNITHOLDERS’ EQUITY AND PARTNERSHIP DISTRIBUTIONS

The Partnership has issued units representing limited partner interests. As of March 31, 2024, the Partnership had a total of 74,646,476 common units issued and outstanding and 20,847,295 Class B units outstanding.

On August 7, 2023, the Partnership completed an underwritten public offering of 8,337,500 common units for net proceeds of approximately $110.7 million (the “2023 Equity Offering”). The Partnership used the net proceeds from the 2023 Equity Offering to purchase OpCo common units. The Operating Company in turn used the net proceeds to repay approximately $90.0 million of the outstanding borrowings under the Partnership’s secured revolving credit facility. The Operating Company used the remainder of the net proceeds of the 2023 Equity Offering for general corporate purposes.

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

Common Units

Balance at December 31, 2023

73,851,458

Common units issued under the A&R LTIP (1)

1,087,502

Restricted units repurchased for tax withholding

(292,484)

Balance at March 31, 2024

74,646,476

(1)Includes restricted units granted to certain employees and directors under the Amended and Restated Kimbell Royalty GP, LLC 2017 Long-Term Incentive Plan on February 19, 2024.

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 2024

$

0.49

May 2, 2024

May 13, 2024

May 20, 2024

Q1 2023

$

0.35

May 3, 2023

May 15, 2023

May 22, 2023

For each Class B unit issued, five 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.

Holders of the Class B units are entitled to one vote per share on all matters to be voted upon by the shareholders. Holders of the common units and the Class B units generally vote together as a single class on all matters presented to the Kimbell Royalty Partners, LP unitholders for their vote or approval. Holders of Class B units do not have any right to receive dividends or distributions upon a liquidation or winding up of Kimbell Royalty Partners, LP.  The Class B units and OpCo common units are exchangeable together into an equal number of common units of the Partnership.

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NOTE 12—EARNINGS PER COMMON UNIT

Basic earnings per common unit is calculated by dividing net income attributable to common units by the weighted-average number of common units outstanding during the period. Diluted net income per common unit gives effect, when applicable, to unvested restricted units granted under the Partnership’s A&R LTIP (as defined in Note 13) for its employees and directors and potential conversion of Series A preferred units and Class B units. The Partnership uses the “if-converted” method to determine the potential dilutive effect of exchanges of outstanding Series A preferred units and Class B units (and corresponding units of Kimbell Royalty Partners, LP), and the treasury stock method to determine the potential dilutive effect of vesting of outstanding restricted units granted under the Partnership’s LTIP. The Partnership does not use the two-class method because the Class B units and the unvested restricted units granted under the Partnership’s A&R LTIP are nonparticipating securities.

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

Three Months Ended March 31, 

2024

2023

Net income attributable to common units of Kimbell Royalty Partners, LP

$

3,168,956

$

23,320,636

Distribution and accretion on Series A preferred units

5,256,287

Net income attributable to non-controlling interests in OpCo and distribution on Class B units

911,696

5,578,902

Diluted net income attributable to common units of Kimbell Royalty Partners, LP

$

9,336,939

$

28,899,538

Weighted average number of common units outstanding:

Basic

72,112,056

62,541,565

Effect of dilutive securities:

Series A preferred units

21,566,025

Class B units

20,847,295

15,484,400

Restricted units

2,014,248

1,732,014

Diluted

116,539,624

79,757,979

Net income per unit attributable to common units of Kimbell Royalty Partners, LP

Basic

$

0.04

$

0.37

Diluted

$

0.04

$

0.36

The calculation of diluted net income per share for the three months ended March 31, 2024 includes the conversion of all Series A preferred units and Class B units to common units calculated using the “if-converted” method and units of unvested restricted units calculated using the treasury stock method. The calculation of diluted net income per share for the three months ended March 31, 2023 includes the conversion of all Class B units to common units calculated using the “if-converted” method and units of unvested restricted units calculated using the treasury stock method.

NOTE 13—UNIT-BASED COMPENSATION

The Partnership’s Amended and Restated Kimbell Royalty GP, LLC 2017 Long-Term Incentive Plan (the “A&R LTIP”) authorizes grants of up to 8,241,600 common units in the aggregate to its employees and directors. The restricted units issued under the Partnership’s A&R 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.

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 A&R LTIP to the Partnership’s employees and directors is determined by utilizing the market value of the Partnership’s common units on the respective grant date.

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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, 2023

1,951,430

$

14.763

 

1.525 years

Awarded

1,087,502

15.710

Vested

(965,149)

13.779

Unvested at March 31, 2024 (1)

2,073,783

$

15.718

 

2.294 years

(1)As of March 31, 2024, there was $32.6 million of unrecognized compensation expense associated with unvested restricted units based on the weighted average grant date fair value per unit of $15.718.

NOTE 14—INCOME TAXES

As discussed in Note 1, the Partnership has elected to be taxed as a corporation for United States federal income tax purposes. The non-controlling interest, which represents OpCo common unitholders’, are not subject to federal income taxes.

The Partnership records income taxes for interim periods based on an estimated annual effective tax rate. The estimated annual effective rate is recomputed on a quarterly basis and may fluctuate due to changes in forecasted annual operating income, positive or negative changes to the valuation allowance for net deferred tax assets, changes in forecasted annual income (loss) attributable to non-controlling interest and changes to actual or forecasted permanent book to tax differences. The Partnership’s effective tax rate for the three months ended March 31, 2024 was 9.0%, compared to 4.6% for the three months ended March 31, 2023. The Partnership recorded an income tax expense of $0.9 million and $1.4 million for the three months ended March 31, 2024 and 2023, respectively.

NOTE 15—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”) and K3 Royalties, LLC (“K3 Royalties”), pursuant to which they and Kimbell Operating provide management, administrative and operational services to the Partnership. In addition, under each of their respective services agreements, affiliates of the Partnership’s Sponsors 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, 2024, no monthly services fee was paid to BJF Royalties. During the three months ended March 31, 2024, the Partnership made payments to K3 Royalties in the amount of $30,000.

The Partnership received $27,378 in reimbursements from Rivercrest Capital Management, LLC for shared operating expenses for the three months ended March 31, 2024.

NOTE 16—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, 2024.

NOTE 17—SUBSEQUENT EVENTS

The Partnership has evaluated events that occurred subsequent to March 31, 2024 in the preparation of its unaudited interim consolidated financial statements.

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Distributions

On May 2, 2024, the Board of Directors declared a quarterly cash distribution of $0.49 per common unit and OpCo common unit for the quarter ended March 31, 2024. The Partnership intends to pay this distribution on May 20, 2024 to common unitholders and OpCo common unitholders of record as of the close of business on May 13, 2024.

The Partnership will pay a quarterly cash distribution on the Series A preferred units of approximately $4.9 million for the quarter ended March 31, 2024. The Partnership intends to pay the distribution subsequent to May 13, 2024 and prior to the distribution on the common units and OpCo common units.

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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 in conjunction with our unaudited interim 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, 2023 (the “2023 Form 10-K”).

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

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 being considered and evaluated by the federal government and other regulating bodies;
the continued threat of terrorism and the impact of military and other action and armed conflict, such as the current conflict between Russia and Ukraine and the conflict in the Middle East;
revisions to our reserve estimates as a result of changes in commodity prices, decline curves and other uncertainties;

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impact 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 to the operators of our properties;
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 2023 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. All forward-looking statements are expressly qualified in their entirety by the foregoing cautionary statements.

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. 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, 2024, we owned mineral and royalty interests in approximately 12.2 million gross acres and overriding royalty interests in approximately 4.7 million gross acres, with approximately 54% of our aggregate acres located in the Permian Basin and Mid-Continent. We refer to these non-cost-bearing interests collectively as our “mineral and royalty interests.” As of March 31, 2024, over 99% 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

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were held by production. Our mineral and royalty interests are located in 28 states and in every major onshore basin across the continental United States and include ownership in over 129,000 gross wells, including over 50,000 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 March 31, 2024:

Average Daily

Production

Basin or Producing Region

Gross Acreage

Net Acreage

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

Well Count

Permian Basin

3,336,729

26,928

12,476

50,604

Mid‑Continent

 

5,868,926

48,832

4,095