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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 June 30, 2023

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 July 28, 2023, the registrant had outstanding 65,507,635 common units representing limited partner interests and 20,853,618 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)

June 30, 

December 31, 

2023

2022

ASSETS

Current assets

Cash and cash equivalents

$

20,779,119

$

24,635,718

Oil, natural gas and NGL receivables

45,006,388

46,993,711

Derivative assets

1,794,888

Accounts receivable and other current assets

3,135,807

3,562,912

Total current assets

70,716,202

75,192,341

Property and equipment, net

771,872

953,781

Oil and natural gas properties

Oil and natural gas properties, using full cost method of accounting ($125,601,085 and $207,695,343 excluded from depletion at June 30, 2023 and December 31, 2022, respectively)

1,602,199,705

1,465,985,718

Less: accumulated depreciation, depletion and impairment

(749,745,922)

(712,716,951)

Total oil and natural gas properties, net

852,453,783

753,268,767

Right-of-use assets, net

2,357,665

2,525,323

Derivative assets

1,580,439

754,786

Loan origination costs, net

6,308,398

3,004,104

Assets of consolidated variable interest entities:

Cash

390,850

Investments held in trust

240,621,146

Prepaid expenses

35,201

Total assets

$

934,188,359

$

1,076,746,299

LIABILITIES, MEZZANINE EQUITY AND UNITHOLDERS' EQUITY

Current liabilities

Accounts payable

$

1,369,894

$

1,210,337

Other current liabilities

8,340,805

4,909,510

Derivative liabilities

428,560

12,646,720

Total current liabilities

10,139,259

18,766,567

Operating lease liabilities, excluding current portion

2,066,030

2,236,361

Derivative liabilities

170,529

432,142

Long-term debt

269,600,000

233,015,911

Other liabilities

260,417

322,917

Liabilities of consolidated variable interest entities:

Other current liabilities

512,725

Deferred underwriting commissions

8,050,000

Total liabilities

282,236,235

263,336,623

Commitments and contingencies (Note 15)

Mezzanine equity:

Redeemable non-controlling interest in Kimbell Tiger Acquisition Corporation

236,900,000

Kimbell Royalty Partners, LP unitholders' equity:

Common units (65,507,635 units and 64,231,833 units issued and outstanding as of June 30, 2023 and December 31, 2022, respectively)

596,177,270

601,841,776

Class B units (20,853,618 and 15,484,400 units issued and outstanding as of June 30, 2023 and December 31, 2022, respectively)

1,042,681

774,220

Total Kimbell Royalty Partners, LP unitholders' equity

597,219,951

602,615,996

Non-controlling interest (deficit) in OpCo

54,732,173

(26,106,320)

Total equity

651,952,124

576,509,676

Total liabilities, mezzanine equity and unitholders' equity

$

934,188,359

$

1,076,746,299

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 June 30, 

Six Months Ended June 30, 

2023

2022

2023

2022

Revenue

Oil, natural gas and NGL revenues

$

56,981,614

$

78,591,469

$

114,398,373

$

143,675,372

Lease bonus and other income

2,041,189

1,213,322

2,478,526

1,867,452

Gain (Loss) on commodity derivative instruments, net

1,729,459

(7,094,127)

10,791,835

(39,077,647)

Total revenues

60,752,262

72,710,664

127,668,734

106,465,177

Costs and expenses

Production and ad valorem taxes

5,404,955

5,002,794

9,682,159

9,023,705

Depreciation and depletion expense

19,656,855

11,273,960

37,220,503

22,033,124

Marketing and other deductions

2,907,459

4,063,004

5,669,498

7,571,070

General and administrative expense

7,925,159

7,866,176

16,203,426

14,455,435

Consolidated variable interest entities related:

General and administrative expense

219,473

590,500

927,699

1,329,959

Total costs and expenses

36,113,901

28,796,434

69,703,285

54,413,293

Operating income

24,638,361

43,914,230

57,965,449

52,051,884

Other income (expense)

Equity income in affiliate

3,385,325

3,634,733

Interest expense

(6,341,118)

(3,323,290)

(11,804,522)

(6,201,145)

Loss on extinguishment of debt

(480,244)

(480,244)

Other (expense) income

(180,765)

898,207

(180,765)

3,966,657

Consolidated variable interest entities related:

Interest earned on marketable securities in trust account

1,069,854

223,135

3,508,691

324,521

Net income before income taxes

18,706,088

45,097,607

49,008,609

53,776,650

Income tax expense

909,057

1,803,441

2,312,040

2,075,240

Net income

17,797,031

43,294,166

46,696,569

51,701,410

Net income attributable to non-controlling interests in OpCo

(4,297,442)

(5,424,092)

(9,860,860)

(6,482,769)

Distribution on Class B units

(31,601)

(8,211)

(47,085)

(25,821)

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

$

13,467,988

$

37,861,863

$

36,788,624

$

45,192,820

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

Basic

$

0.24

$

0.66

$

0.61

$

0.54

Diluted

$

0.23

$

0.55

$

0.59

$

0.42

Weighted average number of common units outstanding

Basic

63,274,492

55,424,930

62,910,053

50,710,073

Diluted

82,959,981

65,543,669

81,263,101

65,323,279

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)

Six Months Ended June 30, 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

Units issued for acquisition

557,302

8,654,900

5,369,218

268,461

83,383,956

92,307,317

Unit-based compensation

3,289,740

3,289,740

Distributions to unitholders

(22,732,617)

(5,349,476)

(28,082,093)

Distribution on Class B units

(31,601)

(31,601)

Accretion of redeemable non-controlling interest in Kimbell Tiger Acquisition Corporation and write-off of deferred underwriting commissions

1,192,969

379,768

1,572,737

Net income

13,499,589

4,297,442

17,797,031

Balance at June 30, 2023

65,507,635

$

596,177,270

20,853,618

$

1,042,681

$

54,732,173

$

651,952,124

3

KIMBELL ROYALTY PARTNERS, LP

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

(Unaudited)

Six Months Ended June 30, 2022

Non-controlling

Non-controlling

   

Common Units

   

Amount

   

Class B Units

   

Amount

Interest
in OpCo

Interest
in TGR

Total

Balance at January 1, 2022

47,162,773

$

328,717,841

17,611,579

$

880,579

$

19,251,361

$

$

348,849,781

Costs associated with equity offering

(325,508)

(325,508)

Conversion of Class B units to common units

9,357,919

161,424,103

(9,357,919)

(467,896)

(161,424,103)

(467,896)

Restricted units repurchased for tax withholding

(193,604)

(3,344,828)

(3,344,828)

Unit-based compensation

963,835

2,194,342

2,194,342

Distributions to unitholders

(17,450,226)

(6,516,284)

(23,966,510)

Distribution on Class B units

(17,610)

(17,610)

Proceeds from issuance of TGR public warrants

11,500,000

11,500,000

Accretion of redeemable non-controlling interest in Kimbell Tiger Acquisition Corporation

(16,325,799)

(2,351,988)

(11,500,000)

(30,177,787)

Net income

7,348,567

1,058,677

8,407,244

Balance at March 31, 2022

57,290,923

462,220,882

8,253,660

412,683

(149,982,337)

312,651,228

Conversion of Class B units to common units

42,081

722,952

(42,081)

(2,104)

(722,952)

(2,104)

Forfeitures of restricted units

(1,171)

(19,813)

(19,813)

Unit-based compensation

2,949,491

2,949,491

Distributions to unitholders

(26,945,962)

(3,859,442)

(30,805,404)

Distribution on Class B units

(8,211)

(8,211)

Accretion of redeemable non-controlling interest in Kimbell Tiger Acquisition Corporation

(1,519,432)

(217,627)

(1,737,059)

Net income

37,870,074

5,424,092

43,294,166

Balance at June 30, 2022

57,331,833

$

475,269,981

8,211,579

$

410,579

$

(149,358,266)

$

$

326,322,294

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

4

KIMBELL ROYALTY PARTNERS, LP

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

Six Months Ended June 30, 

2023

   

2022

CASH FLOWS FROM OPERATING ACTIVITIES

Net income

$

46,696,569

$

51,701,410

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

Depreciation and depletion expense

37,220,503

22,033,124

Amortization of right-of-use assets

167,658

157,298

Amortization of loan origination costs

1,008,830

901,660

Loss on extinguishment of debt

480,244

Equity income in affiliate

(3,634,733)

Cash distribution from affiliate

3,770,651

Forfeiture of restricted units

(19,813)

Unit-based compensation

6,459,740

5,143,833

(Gain) loss on derivative instruments, net of settlements

(15,100,314)

12,116,997

Changes in operating assets and liabilities:

Oil, natural gas and NGL receivables

1,987,323

(18,448,369)

Accounts receivable and other current assets

427,105

906,119

Accounts payable

159,557

741,972

Other current liabilities

3,431,295

1,859,036

Operating lease liabilities

(170,331)

(159,717)

Consolidated variable interest entities related:

Interest earned on marketable securities in trust account

(3,508,691)

(324,521)

Other assets and liabilities

(687,353)

(289,307)

Net cash provided by operating activities

78,572,135

76,455,640

CASH FLOWS FROM INVESTING ACTIVITIES

Purchases of property and equipment

(72,123)

(75,398)

Purchase of oil and natural gas properties

(44,175,131)

(443,977)

Proceeds from trust of variable interest entity

930,850

Cash distribution from affiliate

3,465,376

Consolidated variable interest entities related:

Cash paid for transaction costs

31,553

Cash received from investments held in trust

243,167,434

Investment in marketable securities

(236,900,000)

Net cash provided by (used in) investing activities

199,882,583

(233,953,999)

CASH FLOWS FROM FINANCING ACTIVITIES

Costs associated with equity offering

(325,508)

Contributions from Class B unitholders

268,461

Redemption of Class B contributions on converted units

(470,000)

Distributions to common unitholders

(53,908,777)

(44,396,188)

Distribution to OpCo unitholders

(12,786,091)

(10,375,726)

Distribution on Class B units

(47,085)

(25,821)

Borrowings on long-term debt

59,084,089

36,200,000

Repayments on long-term debt

(22,500,000)

(37,200,000)

Payment of loan origination costs

(4,793,368)

(435,142)

Restricted units repurchased for tax withholding

(4,851,962)

(3,344,828)

Consolidated variable interest entities related:

Proceeds from initial public offering of Kimbell Tiger Operating Company

227,585,000

Payment of underwriting commissions with equity offering of Kimbell Tiger Operating Company, net of adjustments

(2,661,288)

Redemption of Kimbell Tiger Acquisition Corporation equity units

(243,167,434)

Net cash (used in) provided by financing activities

(282,702,167)

164,550,499

NET (DECREASE) INCREASE IN CASH AND CASH EQUIVALENTS

(4,247,449)

7,052,140

CASH AND CASH EQUIVALENTS, beginning of period

25,026,568

7,052,414

CASH AND CASH EQUIVALENTS, end of period

$

20,779,119

$

14,104,554

Supplemental cash flow information:

Cash paid for interest

$

10,963,296

$

5,032,259

Cash paid for taxes

$

$

2,043,374

Non-cash investing and financing activities:

Units issued in exchange for oil and natural gas properties

$

92,038,856

$

Recognition of tenant improvement asset

$

62,500

$

62,501

Consolidated variable interest entities related:

Reduction of deferred underwriting commission associated with redemption of Kimbell Tiger Acquisition Corporation equity units

$

(8,050,000)

$

Deferred underwriting commissions

$

$

8,050,000

5

KIMBELL ROYALTY PARTNERS, LP

CONSOLIDATED STATEMENTS OF CASH FLOWS — (Continued)

(Unaudited)

Six Months Ended June 30, 

2023

   

2022

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

$

20,779,119

$

13,317,833

Cash held at consolidated variable interest entities

786,721

$

20,779,119

$

14,104,554

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.

On February 8, 2022, the Partnership announced the $230 million initial public offering of its special purpose acquisition company, Kimbell Tiger Acquisition Corporation (NYSE: TGR).

Kimbell Tiger Acquisition Corporation (“TGR”) was formed for the purpose of effecting a merger, capital stock exchange, asset acquisition, stock purchase, reorganization or similar business combination with one or more businesses. Kimbell Tiger Acquisition Sponsor, LLC (“TGR Sponsor”), which was a subsidiary of the Partnership, and was created to assist TGR in sourcing, analyzing and consummating acquisition opportunities for that initial business combination. TGR Sponsor and TGR have been consolidated in the financial statements of the Partnership beginning in the year ended December 31, 2021.  

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 (as defined in Note 4) included as part of the units issued in its initial public offering. Following such redemption, TGR (along with TGR Sponsor) was dissolved in accordance with the terms of its organizational documents. Further details can be found in Note 4—Acquisitions, Joint Venture and Special Purpose Acquisition Company.

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 U.S. 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, 2022 (the “2022 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

7

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.

Russia / Ukraine Conflict

In February 2022, Russia invaded Ukraine and is still engaged in active armed conflict against the country. The conflict 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 the invasion of Ukraine; 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 2022 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 and six months ended June 30, 2023.

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

8

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 represent funds raised by TGR, a consolidated special purpose acquisition company, through the TGR IPO (as defined in Note 4). These funds were held in an actively-traded money market fund, which invested in U.S. Treasury securities. Investments held in trust are classified as trading securities and are 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. The estimated fair values of investments held in the trust account are determined using quoted prices in an active market and therefore are classified in Level 1 of the fair value hierarchy, as described in Note 6— Fair Value Measurements.

Redeemable Non-Controlling Interest

Redeemable non-controlling interests represent the shares of TGR Class A common stock (as defined in Note 4) sold in the TGR IPO that were redeemable for cash by the public TGR shareholders that would have been concurrent with TGR’s initial business combination or in the event of TGR’s failure to complete a business combination or a tender offer. The redeemable non-controlling interests were initially recorded at their original issue price, net of issuance costs and the initial fair value of separately traded warrants. As of June 30, 2023, the shares had been redeemed in full.

New Accounting Pronouncements

In March 2023, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2023-01, “Leases (Topic 842): Common Control Arrangements.” This update requires that (i) entities determine whether a related party arrangement between entities under common control is a lease and (ii) that leasehold improvements have an amortization period consistent with the shorter of the remaining lease term and the useful life of the improvements, which is an approach that is largely consistent with legacy guidance. This update is effective for financial statements issued for fiscal years beginning after December 15, 2023, including interim periods within that fiscal year. 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.

9

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 June 30, 

Six Months Ended June 30, 

2023

    

2022

2023

    

2022

Oil revenue

$

39,809,883

$

34,567,049

$

72,810,169

$

68,340,181

Natural gas revenue

11,539,982

35,876,768

31,188,764

58,894,902

NGL revenue

5,631,749

8,147,652

10,399,440

16,440,289

Total Oil, natural gas and NGL revenues

$

56,981,614

$

78,591,469

$

114,398,373

$

143,675,372

NOTE 4ACQUISITIONS, JOINT VENTURE AND SPECIAL PURPOSE ACQUISITION COMPANY

Acquisitions

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 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. 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.

On December 15, 2022, the Partnership completed the acquisition of certain mineral and royalty assets held by Hatch Royalty LLC (the “Hatch Acquisition”). The aggregate consideration for the Hatch Acquisition consisted of (i) approximately $150.4 million in cash and (ii) the issuance of 7,272,821 OpCo common units and an equal number of Class B units. The Partnership funded the cash payment of the purchase price with borrowings under its secured revolving credit facility. The assets acquired in the Hatch Acquisition are located in the Permian Basin and the Partnership estimates that the assets consisted of approximately 889 net royalty acres on approximately 230,000 gross acres. The Hatch Acquisition was accounted for as an asset acquisition and the allocation of the purchase price was $56.4 million to proved properties and $204.7 million to unevaluated properties.

Joint Venture

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 was 49.3%. During the year ended December 31, 2022, the Joint Venture completed the sale of its royalty, mineral and overriding interests and similar non-cost bearing interests in oil and gas properties for a total purchase price of $15.0 million. Net proceeds distributed to the Partnership were $6.5 million during the year ended December 31, 2022, the majority of which was used to repay debt on the Partnership’s secured revolving credit facility. The Joint Venture was dissolved on November 1, 2022.

Special Purpose Acquisition Company

On July 29, 2021, TGR, the Partnership’s recently dissolved special purpose acquisition company and subsidiary, filed a registration statement on Form S-1 with the SEC. On February 8, 2022, TGR consummated its initial public offering (the “TGR IPO”) of 23,000,000 units (each a “unit” and, collectively, the “units”), including 3,000,000 additional units issued pursuant to the underwriter’s exercise in full of its over-allotment option, at $10.00 per unit, generating proceeds of approximately $230,000,000 and incurring offering costs of approximately $12,650,000, inclusive of $8,050,000 in deferred underwriting commissions. Each unit consisted of one share of Class A common stock, par value $0.0001 (the

10

“TGR Class A common stock”), and one-half of one redeemable warrant. Each whole warrant was exercisable for one share of Class A common stock at a price of $11.50 per share. Certain members of our management and members of the Board of Directors were members of the sponsor of TGR, TGR Sponsor. TGR was formed for the purpose of effecting a merger, capital stock exchange, asset acquisition, stock purchase, reorganization or similar business combination with one or more businesses (the “Business Combination”). Under the terms of TGR’s governing documents, TGR had until May 8, 2023 (15 months from the closing of the TGR IPO) to complete the Business Combination, subject to TGR Sponsor’s option to extend such deadline by three months up to two times.

In connection with the closing of the TGR IPO, TGR completed the sale of 14.1 million private placement warrants (the “private placement warrants”) to TGR Sponsor, which was a subsidiary of the Partnership, for a purchase price of $1.00 per private placement warrant, generating gross proceeds of $14.1 million. Each private placement warrant was exercisable to purchase for $11.50 one share of TGR Class A common stock.

In addition, TGR incurred $12.7 million of fees and expenses, of which $8.1 million were deferred underwriting commissions that became payable to the underwriters solely in the event that TGR completed the Business Combination, which were included in deferred underwriting commissions on the accompanying unaudited interim consolidated balance sheet at December 31, 2022.

In May 2021, prior to TGR’s IPO, TGR Sponsor paid $25,000 in exchange for the issuance of (i) 5,750,100 shares of TGR’s Class B common stock, par value $0.0001 per share (the “TGR Class B common stock”), and (ii) 2,500 shares of TGR Class A common stock. Additionally, in May 2021, TGR paid $25,000 to Kimbell Tiger Operating Company (“TGR Opco”) in exchange for the issuance of 2,500 Class A units of TGR Opco. Also in May 2021, TGR Sponsor received 100 Class A units of TGR Opco in exchange for $1,000 and 5,750,000 Class B units of TGR Opco. The shares of TGR Class B common stock and corresponding number of Class B units of TGR Opco (or the Class A units of TGR Opco into which such Class B units will convert) are collectively referred to as the “Founders Shares.” The Founders Shares would have been exchangeable for shares of TGR Class A common stock upon completion of the Business Combination on a one-for-one basis, subject to certain adjustments. Class A units and Class B units of TGR Opco were substantially similar, other than certain distribution rights, and were entitled to vote together as a single class on all matters submitted for stockholder vote.

In determining the accounting treatment of the Partnership’s equity interest in TGR, management concluded that TGR was a VIE as defined by Accounting Standards Codification Topic 810, “Consolidation.” A VIE is an entity in which equity investors at risk lack the characteristics of a controlling financial interest. VIEs are consolidated by the primary beneficiary, the party who has both the power to direct the activities of a VIE that most significantly impact the entity’s economic performance, as well as the obligation to absorb losses of the entity or the right to receive benefits from the entity that could potentially be significant to the entity. TGR Sponsor was the primary beneficiary of TGR as it had, through its equity interest, the right to receive benefits or the obligation to absorb losses from TGR, as well as the power to direct a majority of the activities that significantly impacted TGR’s economic performance, including identification of a target for its Business Combination. As such, TGR was consolidated into the Partnership’s financial statements through TGR Sponsor.

Proceeds of $236.9 million were deposited in a trust account established for the benefit of TGR’s public unitholders consisting of certain proceeds from the TGR IPO and certain proceeds from the sale of the private placement warrants, net of underwriters’ discounts and commissions and other costs and expenses. The proceeds held in the trust account were not available to be used by the Partnership at any time. A minimum balance of $236.9 million, representing the number of TGR units sold at a redemption value of $10.30 per unit, was required by the underwriting agreement to be maintained in the trust account. The proceeds held in the trust account were only permitted to be invested in U.S. government treasury obligations with a maturity of 185 days or less or in money market funds meeting certain conditions under Rule 2a-7 of the Investment Company Act that invest only in direct U.S. government treasury obligations. In connection with the trust account, the Partnership reported investments held in trust of $240.6 million on the accompanying unaudited interim consolidated balance sheet as of December 31, 2022.

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 included as part of the units issued in its initial public offering. The per-share redemption price for the TGR public shares was $10.57 and the Partnership remeasured and accreted through equity the redeemable non-

11

controlling interest in TGR to its redemption value of $243.0 million and wrote off the deferred underwriting commissions through equity. The public shares of TGR ceased trading as of the close of business on May 8, 2023. As of the close of business on May 9, 2023, the public shares were deemed cancelled and represented only the right to receive the redemption amount. Following such redemption, TGR (along with TGR Sponsor) was dissolved in accordance with the terms of its organizational documents. There were no redemption rights or liquidating distributions with respect to TGR’s warrants, including the Private Placement Warrants held by TGR Sponsor, which expired worthless. TGR Sponsor waived its redemption rights with respect to TGR’s outstanding common stock issued before TGR’s initial public offering. The Class A common stock was redeemed on June 22, 2023 and the Partnership completed the dissolution and deconsolidation of TGR on June 30, 2023. The net non-cash impact of the deconsolidation of TGR was $1.6 million, which is included in the accompanying unaudited interim consolidated balance sheet as of June 30, 2023.

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 June 30, 2023, 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 June 30, 2023, these economic hedges constituted approximately 15% 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 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 current period and are presented on a net basis within revenue in the accompanying unaudited interim 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. On May 17, 2022, the Partnership entered into a partial termination agreement with Citibank to unwind 50% of the interest rate swap. On August 8, 2022, the Partnership entered into a termination agreement with Citibank to unwind the remaining 50% of the interest rate swap. The May 2022 termination resulted in a $3.0 million gain, which is included in other income (expense) in the accompanying unaudited interim consolidated statements of operations for the three and six months ended June 30, 2022. The Partnership used an interest rate swap for the management of interest rate risk exposure, as the interest rate swap effectively converted 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 were recognized as gains or losses in the current period and were presented on a net basis within other income in the accompanying unaudited interim consolidated statements of operations. As of June 30, 2022, the interest rate swap had a total notional amount of $75.0 million and a fair value of $3.3 million.

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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 June 30, 

Six Months Ended June 30, 

2023

2022

2023

2022

Beginning fair value of derivative instruments

$

175,525

$

(45,305,641)

$

(12,324,076)

$

(26,624,646)

Gain (loss) on derivative instruments

1,729,459

(6,195,920)

10,791,835

(34,434,335)

Net cash paid on settlements of derivative instruments

871,254

12,759,918

4,308,479

22,317,338

Ending fair value of derivative instruments

$

2,776,238

$

(38,741,643)

$

2,776,238

$

(38,741,643)

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

June 30, 

December 31, 

Classification

Balance Sheet Location

2023

2022

Assets:

Current assets

Derivative assets

$

1,794,888

$

Long-term assets

Derivative assets

1,580,439

754,786

Liabilities:

Current liabilities

Derivative liabilities

(428,560)

(12,646,720)

Long-term liabilities

Derivative liabilities

(170,529)

(432,142)

$

2,776,238

$

(12,324,076)

As of June 30, 2023, 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

July 2023 - December 2023

140,668

$

62.33

$

61.70

$

63.00

January 2024 - December 2024

228,044

$

74.44

$

69.30

$

82.40

January 2025 - June 2025

171,558

$

65.17

$

64.35

$

66.31

Natural Gas Price Swaps

Notional

Weighted Average

Range (per MMBtu)

Volumes (MMBtu)

Fixed Price (per MMBtu)

Low

High

July 2023 - December 2023

2,043,412

$

3.18

$

3.09

$

3.28

January 2024 - December 2024

3,229,292

$

4.34

$

4.15

$

4.48

January 2025 - June 2025

1,765,168

$

3.93

$

3.53

$

4.37

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 June 30, 2023 and December 31, 2022 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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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 and six months ended June 30, 2023 and 2022.

The estimated fair values of investments held in the trust account are determined using quoted prices in an active market and therefore are classified in Level 1 of the fair value hierarchy. 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

June 30, 2023

Assets

Commodity derivative contracts

$

$

3,375,327

$

$

$

3,375,327

Liabilities

Commodity derivative contracts

$

$

(599,089)

$

$

$

(599,089)

December 31, 2022

Assets

Commodity derivative contracts

$

$

754,786

$

$

$

754,786

Investments held in trust

$

240,621,146

$

$

$

$

240,621,146

Liabilities

Commodity derivative contracts

$

$

(13,078,862)

$

$

$

(13,078,862)

NOTE 7—OIL AND NATURAL GAS PROPERTIES

Oil and natural gas properties consist of the following:

    

June 30, 

December 31, 

2023

2022

Oil and natural gas properties

Proved properties

$

1,476,598,620

$

1,258,290,375

Unevaluated properties

125,601,085

207,695,343

Less: accumulated depreciation, depletion and impairment

(749,745,922)

(712,716,951)

Total oil and natural gas properties

$

852,453,783

$

753,268,767

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 developed producing 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 did not record an impairment on its oil and natural gas properties for the three or six months ended June 30, 2023 or 2022.

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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. 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 June 30, 2023 is 5.88 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 six months ended June 30, 2023.

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 and six months ended June 30, 2023 and 2022. The total operating lease expense recorded for both the three months ended June 30, 2023 and 2022 was $0.1 million and $0.3 million and $0.2 million for the six months ended June 30, 2023 and 2022, 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 June 30, 2023 were as follows:

Total

2023

2024

2025

2026

2027

Thereafter

Operating leases

$

2,956,414

$

243,741

$

488,725

$

497,033

$

507,648

$

511,917

$

707,350

Less: Imputed Interest

 

(554,818)

 

Total

$

2,401,596

 

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 $750,000,000, 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 $10,000,000, and (ii) an extension of the maturity date of the A&R Credit Agreement to June 7, 2027.

The revolving credit facility bears interest at a rate equal to, at the Partnership’s election, either (a) 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 (b) a base rate plus an applicable margin that varies from 1.75% to 2.75% per annum, based on borrowing base utilization.

The 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

15

Lenders between scheduled redeterminations during each calendar year. The first scheduled redetermination will be on or around November 1, 2023.

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 A&R Credit Agreement) above $30.0 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, each beginning with the fiscal quarter ending June 30, 2023.

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.

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.

On July 24, 2023, the Partnership entered into Amendment No. 1 (the “First Amendment”) to the A&R Credit Agreement. The amendment amends 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.

During the six months ended June 30, 2023, the Partnership borrowed an additional $59.1 million under the secured revolving credit facility and repaid approximately $22.5 million of the outstanding borrowings. As of June 30, 2023, the Partnership’s outstanding balance was $269.6 million. The Partnership was in compliance with all covenants included in the secured revolving credit facility as of June 30, 2023.

As of June 30, 2023, 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 and six months ended June 30, 2023, the weighted average interest rate on the Partnership’s outstanding borrowings was 8.76% and 8.52%, respectively.

NOTE 10—UNITHOLDERS’ EQUITY AND PARTNERSHIP DISTRIBUTIONS

The Partnership has issued units representing limited partner interests. As of June 30, 2023, the Partnership had a total of 65,507,635 common units issued and outstanding and 20,853,618 Class B units outstanding.

In November 2022, the Partnership completed an underwritten public offering of 6,900,000 common units for net proceeds of approximately $117.0 million (the “2022 Equity Offering”). The Partnership used the net proceeds from the

16

2022 Equity Offering to purchase OpCo common units. The Operating Company in turn used the net proceeds to repay approximately $116.0 million of the outstanding borrowings under the Partnership’s secured revolving credit facility.

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

Common Units

Balance at December 31, 2022

64,231,833

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

998,162

Restricted units repurchased for tax withholding

(279,662)

Common unit issued for acquisition

557,302

Balance at June 30, 2023

65,507,635

(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 21, 2023.

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 2023

$

0.35

May 3, 2023

May 15, 2023

May 22, 2023

Q2 2023

$

0.39

August 2, 2023

August 14, 2023

August 21, 2023

Q1 2022

$

0.47

April 22, 2022

May 2, 2022

May 9, 2022

Q2 2022

$

0.55

August 3, 2022

August 15, 2022

August 22, 2022

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 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—EARNINGS (LOSS) PER COMMON UNIT

Basic earnings (loss) per common unit is calculated by dividing net income (loss) attributable to common units by the weighted-average number of common units outstanding during the period. Diluted net income (loss) per common unit gives effect, when applicable, to unvested restricted units granted under the Partnership’s A&R LTIP (as defined in Note 12) for its employees, directors and consultants and potential conversion of Class B units. The Partnership uses the “if-converted” method to determine the potential dilutive effect of exchanges of outstanding 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.

17

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

Three Months Ended June 30, 

Six Months Ended June 30, 

2023

2022

2023

2022

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

$

13,467,988

$

37,861,863

$

36,788,624

$

45,192,820

Net adjustment to accretion of redeemable non-controlling interest in Kimbell Tiger Acquisition Corporation and write-off of deferred underwriting commissions

1,572,737

(1,519,432)

1,572,737

(17,845,231)

Net income attributable to common units of Kimbell Royalty Partners, LP after accretion of redeemable non-controlling interest in Kimbell Tiger Acquisition Corporation and write-off of deferred underwriting commissions

15,040,725

36,342,431

38,361,361

27,347,589

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

4,329,043

9,907,945

Diluted net income attributable to common units of Kimbell Royalty Partners, LP after accretion of redeemable non-controlling interest in Kimbell Tiger Acquisition Corporation

19,369,768

36,342,431

48,269,306

27,347,589

Weighted average number of common units outstanding:

Basic

63,274,492

55,424,930

62,910,053

50,710,073

Effect of dilutive securities:

Class B units

18,139,508

8,221,290

16,819,289

12,787,092

Restricted units

1,545,981

1,897,449

1,533,759

1,826,114

Diluted

82,959,981

65,543,669

81,263,101

65,323,279

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

Basic

$

0.24

$

0.66

$

0.61

$

0.54

Diluted

$

0.23

$

0.55

$

0.59

$

0.42

The calculation of diluted net income per share for the three and six months ended June 30, 2023 and 2022 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 12—UNIT-BASED COMPENSATION

On May 18, 2022, the Partnership held a special meeting of unitholders of the Partnership (the “Special Meeting”), at which the Partnership’s unitholders voted to approve the Amended and Restated Kimbell Royalty GP, LLC 2017 Long-Term Incentive Plan (the “A&R LTIP”), which increased the number of common units eligible for issuance under the A&R LTIP by 3,700,000 common units for a total of 8,241,600 common units. The Partnership’s A&R LTIP authorizes grants to its employees, directors and consultants. 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. Compensation expense for consultants is treated in the same manner as that of the employees and directors.

18

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, 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, 2022

1,897,192

$

13.553

 

1.517 years

Awarded

998,162

15.020

Vested

(943,924)

12.602

Unvested at June 30, 2023

1,951,430

$

14.763

 

2.029 years

NOTE 13—INCOME TAXES

The Partnership’s provision for income taxes is based on the estimated annual effective tax rate plus discrete items. The Partnership recorded an income tax expense of $0.9 million and $1.8 million for the three months ended June 30, 2023 and 2022, respectively, and an income tax expense of $2.3 million and $2.1 million for the six months ended June 30, 2023 and 2022, respectively.

NOTE 14—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 and six months ended June 30, 2023, no monthly services fee was paid to BJF Royalties. During the three and six months ended June 30, 2023, the Partnership made payments to K3 Royalties in the amount of $30,000 and $60,000, respectively. Certain consultants who provide services under management services agreements are granted restricted units under the Partnership’s A&R LTIP.

The Partnership received $48,853 and $105,095 in reimbursements from Rivercrest Capital Management, LLC for shared operating expenses for the three and six months ended June 30, 2023, respectively.

Commencing on the date of the TGR IPO, TGR agreed to pay the Partnership a total of $25,000 per month for office space utilities, secretarial support and administrative services provided to members of the management team. During the three and six months ended June 30, 2023, TGR incurred $25,000 and $50,000, respectively, as part of this service agreement. Such fees are eliminated in consolidation. Upon TGR’s liquidation, TGR ceased paying these monthly fees.

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 June 30, 2023.

NOTE 16—SUBSEQUENT EVENTS

The Partnership has evaluated events that occurred subsequent to June 30, 2023 in the preparation of its unaudited interim consolidated financial statements.

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Distributions

On August 2, 2023, the Board of Directors declared a quarterly cash distribution of $0.39 per common unit and OpCo common unit for the quarter ended June 30, 2023. The Partnership intends to pay this distribution on August 21, 2023 to common unitholders and OpCo common unitholders of record as of the close of business on August 14, 2023.

Acquisition

On August 2, 2023, the Partnership announced that it has agreed to acquire mineral and royalty interests held by LongPoint Minerals II, LLC in a cash transaction valued at approximately $455.0 million, subject to purchase price adjustments and other customary closing adjustments. The Partnership intends to fund the purchase price through a private placement of 6.00% Series A Cumulative Convertible Preferred Units to funds managed by affiliates of Apollo Global Management, LLC and borrowings under its revolving credit facility. The final mix of funding will be determined at closing.

Long-Term Debt

On July 28, 2023, the Partnership drew down $47.0 million on the senior secured revolving credit facility to fund the deposit on the LongPoint Acquisition.

20

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, 2022 (the “2022 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” or “OpCo” 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 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;
revisions to our reserve estimates as a result of changes in commodity prices, decline curves and other uncertainties;

21

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;
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 2022 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 June 30, 2023, we owned mineral and royalty interests in approximately 11.6 million gross acres and overriding royalty interests in approximately 4.7 million gross acres, with approximately 52% 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 June 30, 2023, 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 were

22

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 125,000 gross wells, including over 48,000 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 June 30, 2023:

Average Daily

Production

Basin or Producing Region

Gross Acreage

Net Acreage

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

Well Count

Permian Basin

3,176,076

25,245

6,070

48,766

Mid‑Continent

 

5,369,358

44,310

1,897

19,205

Terryville/Cotton Valley/Haynesville

 

1,428,907

7,919

3,692

16,175

Appalachian Basin

741,354

23,203

1,821

3,871

Bakken/Williston Basin

 

1,640,077

6,138

894

5,278

Eagle Ford

 

624,148

6,730

1,797

4,088

DJ Basin/Rockies/Niobrara

 

74,152

1,036

720

12,540

Other

 

3,232,560

36,693

1,254

15,413

Total

 

16,286,632

151,274

18,145

125,336

(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 2022 Form 10-K.

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 June 30, 2023:

Basin or Producing Region(1)

Gross DUCs

Gross Permits

Net DUCs

Net Permits

Permian Basin

462

388

2.27

1.47

Mid‑Continent

 

76

49

0.14

0.10

Terryville/Cotton Valley/Haynesville

 

105

27

0.81

0.49

Appalachian Basin

5

12

0.01

0.03

Bakken/Williston Basin

 

68

175

0.23

0.20

Eagle Ford

 

43

61

0.39

0.47

DJ Basin/Rockies/Niobrara

 

8

22

0.04

0.21

Total

 

767

734

3.89

2.97

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

Kimbell Tiger Acquisition Corporation

In April 2021, we formed Kimbell Tiger Acquisition Corporation (“TGR”) as a special purpose acquisition company, or SPAC, for the purpose of effecting a merger, capital stock exchange, asset acquisition, stock purchase, reorganization or similar business combination with one or more businesses. The sponsor of TGR was Kimbell Tiger Acquisition Sponsor, LLC (the “TGR Sponsor”), which was a wholly owned subsidiary of the Operating Company. The Sponsor owned a combination of equity securities in TGR and TGR’s operating company, Kimbell Tiger Operating Company, LLC (“TGR Opco”), that represented 20% of the total outstanding shares of common stock of TGR.

On February 8, 2022, TGR completed its initial public offering (the “TGR IPO”) of 23,000,000 units, including 3,000,000 units that were issued pursuant to the underwriter’s exercise in full of its over-allotment option. Each unit had an offering price of $10.00 and consisted of one share of Class A common stock of TGR, par value $0.0001 per share (the “Class A common stock”), and one-half of one redeemable warrant of TGR (each such whole warrant, a “Public Warrant”). Each Public Warrant entitled the holder thereof to purchase one share of Class A common stock at a price of $11.50 per share.

23

On February 8, 2022, simultaneously with the closing of the TGR IPO and pursuant to a separate private placement warrants purchase agreement dated February 3, 2022, TGR completed the private sale of 14.1 million private placement warrants (the “Private Placement Warrants”) to the TGR Sponsor at a purchase price of $1.00 per Private Placement Warrant, generating gross proceeds of $14,100,000. Each Private Placement Warrant was exercisable to purchase for $11.50 one share of Class A common stock.

Proceeds of $236.9 million were deposited in a trust account established for the benefit of TGR’s public unitholders consisting of certain proceeds from the TGR IPO and certain proceeds from the sale of the private placement warrants, net of underwriters’ discounts and commissions and other costs and expenses. The proceeds held in the trust account were not available to be used by us at any time. 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 included as part of the units issued in its initial public offering. The per-share redemption price for the TGR public shares was $10.57. The public shares of TGR ceased trading as of the close of business on May 8, 2023. As of the close of business on May 9, 2023, the public shares were deemed cancelled and represented only the right to receive the redemption amount. Following such redemption, TGR (along with TGR Sponsor) was dissolved in accordance with the terms of its organizational documents. There were no redemption rights or liquidating distributions with respect to TGR’s warrants, including the Private Placement Warrants held by TGR Sponsor, which expired worthless. TGR Sponsor waived its redemption rights with respect to TGR’s outstanding common stock issued before TGR’s initial public offering. The non-cash impact of the deconsolidation of TGR was $1.6 million, which is included in the accompanying unaudited interim consolidated balance sheet as of June 30, 2023.

Recent Developments

Acquisition

On May 17, 2023, we 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 unit 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 unit representing limited partner interests in the Partnership (“common units”). We funded the cash payment of the purchase price with borrowings under our secured revolving credit facility. The assets acquired in the MB Minerals Acquisition are located in Howard and Borden Counties, Texas.

On August 2, 2023, we announced that we have agreed to acquire mineral and royalty interests held by LongPoint Minerals II, LLC in a cash transaction valued at approximately $455.0 million, subject to purchase price adjustments and other customary closing adjustments. We intend to fund the purchase price through a private placement of 6.00% Series A Cumulative Convertible Preferred Units to funds managed by an affiliate of Apollo Global Management, LLC and borrowings under our revolving credit facility. The final mix of funding will be determined at closing.

Long-Term Debt

On July 28, 2023, we drew down $47.0 million on our senior secured revolving credit facility to fund the deposit on the LongPoint Acquisition.

24

Quarterly Distributions

On August 2, 2023, the General Partner’s Board of Directors (the “Board of Directors”) declared a quarterly cash distribution of $0.39 per common unit and OpCo common unit for the quarter ended June 30, 2023. We intend to pay the distributions on August 21, 2023 to common unitholders and OpCo common unitholders of record as of the close of business on August 14, 2023.

Business Environment

Russia / Ukraine Conflict

In February 2022, Russia invaded Ukraine and is still engaged in active armed conflict against the country. The conflict 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, we have not experienced a material impact to operations or the consolidated financial statements as a result of the invasion of Ukraine; however, we will continue to monitor for events that could materially impact us.

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 various OPEC announcements and the current conflict between Russia and Ukraine 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 (the “EIA”).

Six Months Ended June 30, 2023

Six Months Ended June 30, 2022

High

    

Low

High

    

Low

Oil ($/Bbl)

$

83.26

$

66.61

$

123.64

$

75.99

Natural gas ($/MMBtu)

$

3.78

$

1.74

$

9.44

$

3.73

On July 24, 2023, the West Texas Intermediate posted price for crude oil was $78.81 per Bbl and the Henry Hub spot market price of natural gas was $2.68 per MMBtu.

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

Three Months Ended June 30, 

Six Months Ended June 30, 

2023

    

2022

2023

    

2022

Oil ($/Bbl)

$

73.54

$

108.83

$

74.73

$

102.01

Natural gas ($/MMBtu)

$

2.16

$

7.50

$

2.40

$

6.08

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 10.5% to 653 active land rigs at June 30, 2023 compared to 730 active land rigs at June 30, 2022. The 653 active land rigs at June 30, 2023 decreased by 11.3% from 736 active land rigs at March 31, 2023. The overall decrease in rig count at June 30, 2023 compared June 30, 2022 is primarily attributable to the volatility and decrease in the average daily prices for oil and natural gas.

25

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

June 30, 

Basin or Producing Region

2023

2022

Permian Basin

50

38

Mid‑Continent

12

14

Terryville/Cotton Valley/Haynesville

17

11

Appalachian Basin

3

Bakken/Williston Basin

4

3

Eagle Ford

5

4

DJ Basin/Rockies/Niobrara

1

1

Other

1

Total

90

74

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 oil, natural gas, and NGL revenues for the following periods:

Three Months Ended June 30, 

Six Months Ended June 30, 

2023

    

2022

2023

    

2022

Revenue

Oil revenue

70

%

44

%

64

%

48

%

Natural gas revenue

20

%

46

%

27

%

41

%

NGL revenue

10

%

10

%

9

%

11

%

100

%

100

%

100

%

100

%

We have entered into oil and natural gas commodity derivative agreements, which extend through June 2025, to establish, in advance, a price for the sale of a portion of the oil and natural gas produced from our mineral and royalty interests.

26

Non-GAAP Financial Measures

Adjusted EBITDA and Cash Available for Distribution on Common Units

Adjusted EBITDA and cash available for distribution on common units 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 on common units 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, non cash unit based compensation, loss on extinguishment of debt, unrealized gains and losses on derivative instruments, cash distribution from affiliate, equity income (loss) in affiliate, gains and losses on sales of assets and operational impacts of VIEs, which include general and administrative expense and interest income. Adjusted EBITDA is not a measure of net income (loss) or net cash provided by operating activities 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 on common units 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 on common units 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 on common units may not be comparable to other similarly titled measures of other companies.

27

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

Three Months Ended June 30, 

Six Months Ended June 30, 

2023

2022

2023

2022

Reconciliation of net income to Adjusted EBITDA and cash available for distribution on common units:

Net income

$

17,797,031

$

43,294,166

$

46,696,569

$

51,701,410

Depreciation and depletion expense

19,656,855

 

11,273,960

37,220,503

22,033,124

Interest expense

6,341,118

 

3,323,290

11,804,522

6,201,145

Cash distribution from affiliate

385,326

Income tax expense

909,057

1,803,441

2,312,040

2,075,240

EBITDA

44,704,061

 

59,694,857

98,033,634

82,396,245

Unit-based compensation

3,289,740

 

2,949,491

6,459,740

5,143,833

Loss on extinguishment of debt

480,244

 

480,244

(Gain) loss on derivative instruments, net of settlements

(2,600,713)

(6,563,998)

(15,100,314)

12,116,997

Cash distribution from affiliate

431,268

473,812

Equity income in affiliate

(3,385,325)

(3,634,733)

Consolidated variable interest entities related:

Interest earned on marketable securities in trust account

(1,069,854)

(223,135)

(3,508,691)

(324,521)

General and administrative expenses

219,473

590,500

927,699

1,329,959

Consolidated Adjusted EBITDA

45,022,951

53,493,658

87,292,312

97,501,592

Adjusted EBITDA attributable to non-controlling interest

(10,871,674)

(6,701,931)

(19,008,901)

(12,233,681)

Adjusted EBITDA attributable to Kimbell Royalty Partners, LP

34,151,277

46,791,727

68,283,411

85,267,911

Adjustments to reconcile Adjusted EBITDA to cash available for distribution

Cash interest expense

4,442,318

2,441,582

8,566,027

4,400,361

Cash income tax (refund) expense

2,043,374

(639,325)

2,043,374

Distributions on Class B units

31,601

8,211

47,085

25,821

Cash available for distribution on common units

$

29,677,358

$

42,298,560

$

60,309,624

$

78,798,355

28

Three Months Ended June 30, 

Six Months Ended June 30, 

2023

2022

2023

2022

Reconciliation of net cash provided by operating activities to Adjusted EBITDA and cash available for distribution on common units:

Net cash provided by operating activities

$

31,518,529

$

40,423,167

$

78,572,135

$

76,455,640

Interest expense

 

6,341,118

 

3,323,290

 

11,804,522

 

6,201,145

Income tax expense

909,057

1,803,441

2,312,040

2,075,240

Amortization of right-of-use assets

(84,501)

(79,273)

(167,658)

 

(157,298)

Amortization of loan origination costs

 

(492,732)

 

(459,261)

 

(1,008,830)

 

(901,660)

Loss on extinguishment of debt

(480,244)

(480,244)

Equity income in affiliate, net

 

 

 

 

249,408

Forfeiture of restricted units

19,813

19,813

Unit-based compensation

 

(3,289,740)

 

(2,949,491)

 

(6,459,740)

 

(5,143,833)

Gain (loss) on derivative instruments, net of settlements

2,600,713

 

6,563,998

 

15,100,314

 

(12,116,997)

Changes in operating assets and liabilities:

Oil, natural gas and NGL receivables

 

9,070,691

 

12,039,342

 

(1,987,323)

 

18,448,369

Accounts receivable and other current assets

 

86,707

 

(175,459)

 

(427,105)

 

(906,119)

Accounts payable

 

(450,078)

 

340,681

 

(159,557)

 

(741,972)

Other current liabilities

 

(3,175,769)

 

(1,395,863)

 

(3,431,295)

 

(1,859,036)

Operating lease liabilities

85,313

80,471

170,331

 

159,717

Consolidated variable interest entities related:

Interest earned on marketable securities in trust account

1,069,854

223,135

3,508,691

 

324,521

Other assets and liabilities

995,143

(63,134)

687,353

 

289,307

EBITDA

44,704,061

59,694,857

98,033,634

82,396,245

Add:

Unit-based compensation

 

3,289,740

 

2,949,491

 

6,459,740

 

5,143,833

Loss on extinguishment of debt

480,244

 

 

480,244

 

(Gain) loss on derivative instruments, net of settlements

 

(2,600,713)

 

(6,563,998)

 

(15,100,314)

 

12,116,997

Cash distribution from affiliate

431,268

473,812

Equity income in affiliate

(3,385,325)

(3,634,733)

Consolidated variable interest entities related:

Interest earned on marketable securities in Trust Account

(1,069,854)

(223,135)

(3,508,691)

(324,521)

General and administrative expenses

219,473

590,500

927,699

1,329,959

Consolidated Adjusted EBITDA

45,022,951

53,493,658

87,292,312

97,501,592

Adjusted EBITDA attributable to non-controlling interest

(10,871,674)

(6,701,931)

(19,008,901)

(12,233,681)

Adjusted EBITDA attributable to Kimbell Royalty Partners, LP

34,151,277

46,791,727

68,283,411

85,267,911

Adjustments to reconcile Adjusted EBITDA to cash available for distribution

Cash interest expense

4,442,318

2,441,582

8,566,027

4,400,361

Cash income tax expense

2,043,374

(639,325)

2,043,374

Distributions on Class B units

31,601

8,211

47,085

25,821

Cash available for distribution on common units

$

29,677,358

$

42,298,560

$

60,309,624

$

78,798,355

29

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 and six months ended June 30, 2023 and 2022 include the acquisition of certain mineral and royalty assets held by Hatch Royalty LLC (the “Hatch Acquisition”) and the MB Minerals 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 significant 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. We did not record an impairment on our oil and natural gas properties for the three and six months ended June 30, 2023 and 2022.

Because we do not intend to book proved undeveloped 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.

30

Results of Operations

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

Three Months Ended June 30, 

Six Months Ended June 30, 

    

2023

2022

2023

2022

Operating Results:

Revenue

Oil, natural gas and NGL revenues

$

56,981,614

$

78,591,469

$

114,398,373

$

143,675,372

Lease bonus and other income

2,041,189

1,213,322

2,478,526

1,867,452

Gain (Loss) on commodity derivative instruments, net

1,729,459

(7,094,127)

10,791,835

(39,077,647)

Total revenues

60,752,262

72,710,664

127,668,734

106,465,177

Costs and expenses

Production and ad valorem taxes

 

5,404,955

 

5,002,794

 

9,682,159

 

9,023,705

Depreciation and depletion expense

 

19,656,855

 

11,273,960

 

37,220,503

 

22,033,124

Marketing and other deductions

 

2,907,459

 

4,063,004

 

5,669,498

 

7,571,070

General and administrative expenses

 

7,925,159

 

7,866,176

 

16,203,426

 

14,455,435

Consolidated variable interest entities related:

General and administrative expense

219,473

590,500

927,699

 

1,329,959

Total costs and expenses

 

36,113,901

 

28,796,434

 

69,703,285

 

54,413,293

Operating income

 

24,638,361

 

43,914,230

 

57,965,449

 

52,051,884

Other income (expense)

Equity income in affiliate

3,385,325

3,634,733

Interest expense

 

(6,341,118)

 

(3,323,290)

 

(11,804,522)

 

(6,201,145)

Loss on extinguishment of debt

(480,244)

 

 

(480,244)

 

Other (expense) income

(180,765)

 

898,207

 

(180,765)

 

3,966,657

Consolidated variable interest entities related:

Interest earned on marketable securities in trust account

1,069,854

223,135

3,508,691

 

324,521

Net income before income taxes

18,706,088

45,097,607

49,008,609

53,776,650

Income tax expense

909,057

1,803,441

2,312,040

2,075,240

Net income

17,797,031

43,294,166

46,696,569

51,701,410

Net income attributable to non-controlling interests in OpCo

(4,297,442)

(5,424,092)

(9,860,860)

(6,482,769)

Distribution on Class B units

(31,601)

(8,211)

(47,085)

(25,821)

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

$

13,467,988

$

37,861,863

$

36,788,624

$

45,192,820

Production Data:

Oil (Bbls)

 

553,588

 

320,195

 

999,601

 

712,556

Natural gas (Mcf)

 

5,203,964

 

5,180,033

 

10,794,157

 

10,015,882

Natural gas liquids (Bbls)

 

230,241

 

176,730

 

432,946

 

381,155

Combined volumes (Boe) (6:1)

 

1,651,156

 

1,360,264

 

3,231,573

 

2,763,025

Comparison of the Three Months Ended June 30, 2023 to the Three Months Ended June 30, 2022

Oil, Natural Gas and NGL Revenues

For the three months ended June 30, 2023, our oil, natural gas and NGL revenues were $57.0 million, a decrease of $21.6 million from $78.6 million for the three months ended June 30, 2022. The decrease in oil, natural gas and NGL revenues was primarily related to the decrease in the average prices we received for oil, natural gas and NGL production, partially offset by an increase in production volumes for the three months ended June 30, 2023 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 1,651,156 Boe or 18,145 Boe/d, for the three months ended June 30, 2023, an increase of 290,892 Boe or 3,197 Boe/d, from 1,360,264 Boe or 14,948 Boe/d, for the three months ended June 30, 2022. The increase in production for the three months ended June 30, 2023 was primarily attributable to production associated with the Hatch Acquisition, and to a lesser extent, production associated with the MB Minerals Acquisition.

31

Our operators received an average of $71.91 per Bbl of oil, $2.22 per Mcf of natural gas and $24.46 per Bbl of NGL for the volumes sold during the three months ended June 30, 2023 compared to $107.96 per Bbl of oil, $6.93 per Mcf of natural gas and $46.10 per Bbl of NGL for the volumes sold during the three months ended June 30, 2022. These average prices received during the three months ended June 30, 2023 decreased 33.4% or $36.05 per Bbl of oil and 68.0% or $4.71 per Mcf of natural gas as compared to the three months ended June 30, 2022. This change is consistent with prices experienced in the market, specifically when compared to the EIA average price decreases of 32.4% or $35.29 per Bbl of oil and 71.2% or $5.34 per Mcf of natural gas for the comparable periods.

Lease Bonus and Other Income

Lease bonus and other income was $2.0 million for the three months ended June 30, 2023 compared to $1.2 million for the three months ended June 30, 2022. The $0.8 million increase in lease bonus and other income was primarily related to a $0.9 million legal settlement received during the three months ended June 30, 2023.

Gain (Loss) on Commodity Derivative Instruments

Gain on commodity derivative instruments for the three months ended June 30, 2023 included $2.6 million of mark-to-market gains and $0.9 million of losses on the settlement of commodity derivative instruments compared to $8.8 million of mark-to-market gains and $15.9 million of losses on the settlement of commodity derivative instruments for the three months ended June 30, 2022. We recorded a mark-to-market gain for the three months ended June 30, 2023 as a result of the maturity of derivative contracts with lower strike pricing. This gain was offset by the realized losses on the settlement of commodity derivative instruments. We recorded a mark-to-market gain for the three months ended June 30, 2022 as a result of the maturity of derivative contracts with lower strike pricing, offset by realized losses on the settlement of commodity derivative instruments.

Production and Ad Valorem Taxes

Production and ad valorem taxes for the three months ended June 30, 2023 were $5.4 million, an increase of $0.4 million from $5.0 million for the three months ended June 30, 2022. The increase in production and ad valorem taxes was primarily attributable to the Hatch Acquisition, and to a lesser extent, the MB Minerals Acquisition, partially offset by the decrease in the average prices we received for oil, natural gas and NGL production.

Depreciation and Depletion Expense

Depreciation and depletion expense for the three months ended June 30, 2023 was $19.7 million, an increase of $8.4 million from $11.3 million for the three months ended June 30, 2022. The increase in depreciation and depletion expense was due to the Hatch Acquisition and the MB Minerals Acquisition, which significantly increased our net capitalized oil and natural gas properties.

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 $11.85 for the three months ended June 30, 2023, an increase of $3.78 per barrel from the $8.07 average depletion rate per barrel for the three months ended June 30, 2022. The increase in the depletion rate was due to the Hatch Acquisition and the MB Minerals Acquisition, which significantly increased our net capitalized oil and natural gas properties.

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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 June 30, 2023 were $2.9 million, a decrease of $1.2 million from $4.1 million for the three months ended June 30, 2022. The decrease in marketing and other deductions was primarily related to the decrease in the average prices we received for oil, natural gas and NGL production for the three months ended June 30, 2023, partially offset by marketing and other deductions associated with the Hatch Acquisition and the MB Minerals Acquisition.

General and Administrative Expenses

General and administrative expenses remained flat at $7.9 million for both the three months ended June 30, 2023  and 2022.

Interest Expense

Interest expense for the three months ended June 30, 2023 was $6.3 million compared to $3.3 million for the three months ended June 30, 2022. The increase in interest expense was primarily due to a 4.01% increase in the weighted average interest rate on the Partnership’s outstanding borrowings for the three months ended June 30, 2023 and also due to an increase in the overall long-term debt balance as a result of borrowings associated with the Hatch Acquisition and the MB Minerals Acquisition.

Income Tax Expense

We recorded an income tax expense of $0.9 million for the three months ended June 30, 2023. The income tax expense recorded during the three months ended June 30, 2023 was due to a change in the estimated income tax expense for the year ended December 31, 2023. We recorded an income tax expense of $1.8 million for the three months ended June 30, 2022. The income tax expense recorded during the three months ended June 30, 2022 was due to the significant increase in commodity prices which generated forecasted taxable net income for the year ended December 31, 2022.

Comparison of the Six Months Ended June 30, 2023 to the Six Months Ended June 30, 2022

Oil, Natural Gas and NGL Revenues

For the six months ended June 30, 2023, our oil, natural gas and NGL revenues were $114.4 million, a decrease of $29.3 million from $143.7 million for the six months ended June 30, 2022. The decrease in oil, natural gas and NGL revenues was primarily related to the decrease in the average prices we received for oil, natural gas and NGL production, partially offset by an increase in production volumes for the six months ended June 30, 2023 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 3,231,573 Boe or 17,783 Boe/d, for the six months ended June 30, 2023, an increase of 468,548 Boe or 3,020 Boe/d, from 2,763,025 Boe or 14,763 Boe/d, for the six months ended June 30, 2022. The increase in production for the six months ended June 30, 2023 was primarily attributable to production associated with the Hatch Acquisition, and to a lesser extent, production associated with the MB Minerals Acquisition.

Our operators received an average of $72.84 per Bbl of oil, $2.89 per Mcf of natural gas and $24.02 per Bbl of NGL for the volumes sold during the six months ended June 30, 2023 compared to $95.91 per Bbl of oil, $5.88 per Mcf of natural gas and $43.13 per Bbl of NGL for the volumes sold during the six months ended June 30, 2022. These average prices received during the six months ended June 30, 2023 decreased 24.1% or $23.07 per Bbl of oil and 50.9% or $2.99 per Mcf of natural gas as compared to the six months ended June 30, 2022. This change is consistent with prices experienced in the market, specifically when compared to the EIA average price decreases of 26.7% or $27.28 per Bbl of oil and 60.5% or $3.68 per Mcf of natural gas for the comparable periods.

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Lease Bonus and Other Income

Lease bonus and other income was $2.5 million for the six months ended June 30, 2023 compared to $1.9 million for the six months ended June 30, 2022. The increase in lease bonus and other income is primarily related to a $0.9 million legal settlement received during the six months ended June 30, 2023.

Gain (Loss) on Commodity Derivative Instruments

Gain on commodity derivative instruments for the six months ended June 30, 2023 included $15.1 million of mark-to-market gains and $4.3 million of losses on the settlement of commodity derivative instruments compared to $13.7 million of mark-to-market losses and $25.3 million of losses on the settlement of commodity derivative instruments for the six months ended June 30, 2022. We recorded a mark-to-market gain for the six months ended June 30, 2023 as a result of the maturity of derivative contracts with lower strike pricing. This gain was offset by the realized losses on the settlement of commodity derivative instruments. We recorded a mark-to-market loss for the six months ended June 30, 2022 as a result of the increase in the strip pricing of oil and natural gas from the year ended December 31, 2021 to the six months ended June 30, 2022.

Production and Ad Valorem Taxes

Production and ad valorem taxes for the six months ended June 30, 2023 were $9.7 million, an increase of $0.7 million from $9.0 million for the six months ended June 30, 2022. The increase in production and ad valorem taxes was primarily attributable to the Hatch Acquisition, and to a lesser extent, the MB Minerals Acquisition, partially offset by the decrease in the average prices we received for oil, natural gas and NGL production.  

Depreciation and Depletion Expense

Depreciation and depletion expense for the six months ended June 30, 2023 was $37.2 million, an increase of $15.2 million from $22.0 million for the six months ended June 30, 2022. The increase in depreciation and depletion expense was due to the Hatch Acquisition and the MB Minerals Acquisition, which significantly increased our net capitalized oil and natural gas properties.

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 $11.46 for the six months ended June 30, 2023, an increase of $3.73 per barrel from the $7.73 average depletion rate per barrel for the six months ended June 30, 2022. The increase in the depletion rate was due to the Hatch Acquisition and the MB Minerals Acquisition, which significantly increased our net capitalized oil and natural gas properties.

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 six months ended June 30, 2023 were $5.7 million, a decrease of $1.9 million from $7.6 million for the six months ended June 30, 2022. The decrease in marketing and other deductions was primarily related to the decrease in the average prices we received for oil, natural gas and NGL production for the six months ended June 30, 2022, partially offset by marketing and other deductions associated with the Hatch Acquisition and the MB Minerals Acquisition.

General and Administrative Expenses

General and administrative expenses for the six months ended June 30, 2023 were $16.2 million, an increase of $1.7 million from $14.5 million for the six months ended June 30, 2022. 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 attributable to a $1.3 million increase in unit-based compensation expense and cash general and administrative expenses resulting from an increase in our costs associated with company growth.

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Interest Expense

Interest expense for the six months ended June 30, 2023 was $11.8 million compared to $6.2 million for the six months ended June 30, 2022. The increase in interest expense was primarily due to a 4.09% increase in the weighted average interest rate on the Partnership’s outstanding borrowings for the six months ended June 30, 2023 and also due to an increase in the overall long-term debt balance as a result of borrowings associated with the Hatch Acquisition and the MB Minerals Acquisition.

Income Tax Expense

We recorded an income tax expense of $2.3 million for the six months ended June 30, 2023. The income tax expense recorded during the six months ended June 30, 2023 was due to a change in the estimated income tax expense for the year ended December 31, 2023. We recorded an income tax expense of $2.1 million for the six months ended June 30, 2022. The income tax expense recorded during the six months ended June 30, 2022 was due to the significant increase in commodity prices which generated forecasted taxable net income for the year ended December 31, 2022.

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 our partnership agreement and in the limited liability company agreement of the Operating Company. 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.

The Board of Directors approved the allocation of 25% of our cash available for distribution on common units for the second quarter of 2023 for the repayment of $11.2 million in outstanding borrowings under our secured revolving credit facility during its determination of “available cash” for the second quarter of 2023. 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 7,272,821 OpCo common units and an equal number of Class B units as partial consideration in connection with the Hatch Acquisition and 5,369,218 OpCo common units and an

35

equal number of Class B units and 557,302 common units as partial consideration in connection with the MB Minerals 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 second quarter 2023 distributions.

Cash Flows

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

Six Months Ended June 30, 

2023

   

2022

Cash Flow Data:

Net cash provided by operating activities

$

78,572,135

$

76,455,640

Net cash provided by (used in) investing activities

 

199,882,583

 

(233,953,999)

Net cash (used in) provided by financing activities

 

(282,702,167)

 

164,550,499

Net (decrease) increase in cash and cash equivalents

$

(4,247,449)

$

7,052,140

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 six months ended June 30, 2023 were $78.6 million, an increase of $2.1 million compared to $76.5 million for the six months ended June 30, 2022.

Investing Activities

Cash flows provided by investing activities for the six months ended June 30, 2023 were $199.9 million compared to $234.0 million of cash flows used in investing activities for the six months ended June 30, 2022. For the six months ended June 30, 2023, cash flows provided by investing activities included $243.2 million of cash received from investment held in trust related to TGR and $0.9 million in cash received from the dissolution of TGR, partially offset by $44.2 million used primarily to fund costs associated with the MB Minerals Acquisition.

For the six months ended June 30, 2022, cash flows used in investing activities include $236.9 million of investments held in marketable securities related to TGR and $0.4 million used to fund costs associated with the acquisition of all of the equity interests in certain subsidiaries owned by Caritas Royalty Fund LLC and certain of its affiliates, partially offset by $3.5 million in cash distributions received in connection to the joint venture with Springbok SKR Capital Company, LLC and Rivercrest Capital Partners, LP.

Financing Activities

Cash flows used in financing activities were $282.7 million for the six months ended June 30, 2023 compared to $164.6 million of cash flows provided by financing activities for the six months June 30, 2022. Cash flows used in financing activities for the six months ended June 30, 2023 consists of $243.2 million of distributions to common unitholders of TGR, $66.7 million of distributions paid to holders common units, OpCo common units and Class B units, $22.5 million used to repay borrowings under our secured revolving credit facility, $4.9 million of restricted units repurchased for tax withholding and a $4.8 million payment of loan origination costs, partially offset by $59.1 million of additional borrowings under our secured revolving credit facility and $0.3 million in Class B contributions.

Cash flows provided by financing activities for the six months ended June 30, 2022 consists of $227.6 million in proceeds from TGR IPO and $36.2 million of additional borrowings under our secured revolving credit facility, partially offset by $54.8 million of distributions paid to holders of common units, OpCo common units and Class B units, $37.2 million used to repay borrowings under our secured revolving credit facility, $3.3 million of restricted units repurchased

36

for tax withholding, $2.7 million used to pay underwriting commissions related to the equity offering of TGR, $0.5 million paid in connection with the redemption of Class B units, $0.3 million paid in connection with fees related to our 2021 equity offering and $0.4 million payment of loan origination costs.

Indebtedness

On June 13, 2023, we entered into an Amended and Restated Credit Agreement (the “A&R Credit Agreement”), which amended and restated our 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 $750,000,000, 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 $10,000,000, and (ii) an extension of the maturity date of the A&R Credit Agreement to June 7, 2027.

On July 24, 2023, we entered into Amendment No. 1 (the “First Amendment”) to the A&R Credit Agreement. The amendment amends 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 us to issue certain preferred equity interests.

As of June 30, 2023, we had outstanding borrowings of $269.6 million under the secured revolving credit facility and $130.4 million of available capacity. As of July 28, 2023, we had outstanding borrowings of $316.6 million under the secured revolving credit facility and $83.4 million of available capacity.

For additional information on our secured revolving credit facility, please read Note 9―Long-Term Debt to the unaudited interim consolidated financial statements included in this Quarterly Report.

Tax Matters

Even though we are organized as a limited partnership under state law, we are treated as a corporation for United States federal income tax purposes. Accordingly, we are subject to United States federal income tax at regular corporate rates on our net taxable income. We estimate that a portion of our quarterly distributions will constitute a non-taxable reduction to the tax basis of unitholders’ common units. The reduced tax basis will increase unitholders’ capital gain (or decrease unitholders’ capital loss) when unitholders sell their common units. We currently believe that the portion that constitutes dividends for U.S. federal income tax purposes will be considered qualified dividends, subject to holding period and certain other conditions, which are subject to a tax rate of 0%, 15% or 20% depending on the income level and tax filing status of a unitholder for 2023. Our estimates regarding treatment of our distributions are based on currently available information only and are subject to change, including with respect to prior quarters.

Distributions in excess of the amount taxable as dividend income will reduce a common unitholder's tax basis in its common units or produce capital gain to the extent they exceed a common unitholder's tax basis. Any reduced tax basis will increase a common unitholder's capital gain when it sells its common units. Our estimates are the result of certain non-cash expenses (principally depletion) substantially offsetting our taxable income and tax “earnings and profits.” Our estimates of the tax treatment of earnings and distributions are based upon assumptions regarding the capital structure and earnings of the Operating Company, our capital structure and the amount of the earnings of the Operating Company allocated to us. Many factors may impact these estimates, including changes in drilling and production activity, commodity prices, future acquisitions or changes in the business, economic, regulatory, legislative, competitive or political environment in which we operate. These estimates are based on current tax law and tax reporting positions that we have adopted and with which the Internal Revenue Service could disagree. These estimates are not fact and should not be relied upon as being necessarily indicative of future results, and no assurances can be made regarding these estimates. You are encouraged to consult with your tax advisor on this matter.

37

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 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 2022 Form 10-K.

Contractual Obligations and Off-Balance Sheet Arrangements

There have been no significant changes to our contractual obligations previously disclosed in our 2022 Form 10-K. As of June 30, 2023, we did not have any off-balance sheet arrangements. See Note 8—Leases to the unaudited interim 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 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 counterparties to the contracts are unrelated third parties.

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 Note 5—Derivatives to the unaudited interim 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 June 30, 2023, we had four 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.

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Interest Rate Risk

We will have exposure to changes in interest rates on our indebtedness. As of June 30,2023, we had total borrowings outstanding under our secured revolving credit facility of $269.6 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 $2.7 million annually, assuming that our indebtedness remained constant throughout the year.

Inflation

Inflation in the United States did not have a material impact on results of operations for the period from January 1, 2022 through June 30, 2023. However, inflation in wages and other costs has the potential to adversely affect our results of operations, cash flows and financial position by increasing our overall cost structure. In addition, the existence of inflation in the economy has the potential to result in higher interest rates, which could result in higher borrowing costs, supply shortages, increased costs of labor and other similar effects.

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 ensure that the information required to be disclosed by us in reports that we file or submit under the Exchange Act is accumulated and communicated to management, including our General Partner’s principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized, and reported within the time periods specified in the rules and forms of the SEC. Based upon that evaluation, our General Partner’s management, including its principal executive officer and principal financial officer concluded that as of June 30, 2023, 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 June 30, 2023 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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 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, included in Part I, Item 2: Management’s Discussion and Analysis of Financial Condition and Results of Operations, you should carefully consider the risks set out under the heading “Risk Factors” in Part I, Item 1A. Risk Factors in our 2022 Form 10-K. These risk factors could materially affect our business, financial condition and results of operations. The unprecedented nature of the current pandemic and the volatility in the worldwide economy and oil and gas industry may make it more difficult to

39

identify all the risks to our business, results of operations and financial condition and the ultimate impact of identified risks. Further, 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 5. Other Information

During the period covered by this report, none of the Partnership’s directors or executive officers has adopted or terminated a Rule 10b5-1 trading arrangement or a non-Rule 10b5-1 trading arrangement (each as defined in Item 408 of Regulation S-K under the Securities Exchange Act of 1934, as amended).

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

Fourth Amended and Restated Agreement of Limited Partnership of Kimbell Royalty Partners, LP, dated as of May 18, 2022 (incorporated by reference to Exhibit 3.1 to Kimbell Royalty Partners, LP’s Current Report on Form 8-K filed May 18, 2022)

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

Second Amended and Restated Limited Liability Company Agreement of Kimbell Royalty Operating, LLC, dated as of May 18, 2022 (incorporated by reference to Exhibit 3.2 to Kimbell Royalty Partners, LP’s Current Report on Form 8-K filed on May 18, 2022)

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)

4.1

Registration Rights Agreement, dated as of May 17, 2023, by and among between Kimbell Royalty Partners, LP and MB Minerals, L.P. (incorporated by reference to Exhibit 4.1 to Kimbell Royalty Partners, LP Current Report on Form 8-K filed on May 18, 2023)

10.1

Amended and Restated Credit Agreement, dated as of June 13, 2023, by and among Kimbell Royalty Partners, LP, each of the guarantors party thereto, the several lenders from time to time parties thereto and Citibank, N.A., as administrative agent (incorporated by reference to Exhibit 10.1 to Kimbell Royalty Partners, LP’s Current Report on Form 8-K filed on June 20, 2023)

10.2

Amendment No. 1 to Amended and Restated Credit Agreement, dated as of July 24, 2023, by and among Kimbell Royalty Partners, LP, each of the guarantors party thereto, the several lenders from time to time parties thereto and Citibank, N.A., as administrative agent (incorporated by reference to Exhibit 10.1 to Kimbell Royalty Partners, LP’s Current Report on Form 8-K filed on July 28, 2023)

10.3

Purchase and Sale Agreement, dated as of April 11, 2023, by and among MB Minerals, L.P., Kimbell Royalty Partners, LP and Kimbell Royalty Operating, LLC (incorporated by reference to Exhibit 10.1 to Kimbell Royalty Partners, LP’s Current Report on Form 8-K filed on April 12, 2023)

10.4

Securities Purchase Agreement, dated as of August 2, 2023, by and between LongPoint Minerals II, LLC and Kimbell Royalty Partners, LP (incorporated by reference to Exhibit 10.1 to Kimbell Royalty Partners, LP’s Current Report on Form 8-K filed on August 2, 2023)

10.5

Preferred Units Purchase Agreement, dated as of August 2, 2023, by and among Kimbell Royalty Partners, LP and the several purchasers party thereto (incorporated by reference to Exhibit 10.2 to Kimbell Royalty Partners, LP’s Current Report on Form 8-K filed on August 2, 2023)

31.1*

Certification of Chief Executive Officer pursuant to Rule 13a-14(a)/15d-14(a) under the Securities Exchange Act of 1934

40

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

41

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: August 2, 2023

By:

/s/ Robert D. Ravnaas

Name:

Robert D. Ravnaas

Title:

Chief Executive Officer and Chairman

Principal Executive Officer

Date: August 2, 2023

    

By:

/s/ R. Davis Ravnaas

Name:

R. Davis Ravnaas

Title:

President and Chief Financial Officer

Principal Financial Officer

42

Exhibit 31.1

CERTIFICATION PURSUANT TO SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, Robert D. Ravnaas, certify that:

1.I have reviewed this quarterly report on Form 10-Q of Kimbell Royalty Partners, LP;  

2.

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

3.

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

4.

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

(a)

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

(b)

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

(c)

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

(d)

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

5.

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

(a)

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

(b)

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

Date: August 2, 2023

/s/ Robert D. Ravnaas

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

(Principal Executive Officer)


Exhibit 31.2

CERTIFICATION PURSUANT TO SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, R. Davis Ravnaas, certify that:

1.

I have reviewed this quarterly report on Form 10-Q of Kimbell Royalty Partners, LP;  

2.

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

3.

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

4.

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

(a)

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

(b)

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

(c)

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

(d)

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

5.

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

(a)

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

(b)

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

Date: August 2, 2023

/s/ R. Davis Ravnaas

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


Exhibit 32.1

CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report of Kimbell Royalty Partners, LP (the “Partnership”) on Form 10-Q for the fiscal quarter ended June 30, 2023, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Robert D. Ravnaas, Chief Executive Officer and Chairman of the Board of Directors of Kimbell Royalty GP, LLC, the general partner of the Partnership, certify, pursuant to 18 U.S.C. §1350, as adopted pursuant to §906 of the Sarbanes-Oxley Act of 2002, that to the best of my knowledge:

(1)The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and
(2)The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Partnership.

Date: August 2, 2023

/s/ Robert D. Ravnaas

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


Exhibit 32.2

CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report of Kimbell Royalty Partners, LP (the “Partnership”) on Form 10-Q for the fiscal quarter ended June 30, 2023, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, R. Davis Ravnaas, President and Chief Financial Officer of Kimbell Royalty GP, LLC, the general partner of  the Partnership, certify, pursuant to 18 U.S.C. §1350, as adopted pursuant to §906 of the Sarbanes-Oxley Act of 2002, that to the best of my knowledge:

(1)The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and
(2)The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Partnership.

Date: August 2, 2023

/s/ R. Davis Ravnaas

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

(Principal Financial Officer)


v3.23.2
Document and Entity Information - shares
6 Months Ended
Jun. 30, 2023
Jul. 28, 2023
Document Information    
Document Type 10-Q  
Document Quarterly Report true  
Document Period End Date Jun. 30, 2023  
Document Transition Report false  
Entity Registrant Name Kimbell Royalty Partners, LP  
Entity File Number 001-38005  
Entity Incorporation, State or Country Code DE  
Entity Tax Identification Number 47-5505475  
Entity Address, Address Line One 777 Taylor Street, Suite 810  
Entity Address, City or Town Fort Worth  
Entity Address, State or Province TX  
Entity Address, Postal Zip Code 76102  
City Area Code 817  
Local Phone Number 945-9700  
Title of 12(b) Security Common Units Representing Limited Partner Interests  
Trading Symbol KRP  
Security Exchange Name NYSE  
Entity Current Reporting Status Yes  
Entity Interactive Data Current Yes  
Entity Filer Category Large Accelerated Filer  
Entity Small Business false  
Entity Emerging Growth Company false  
Entity Shell Company false  
Entity Central Index Key 0001657788  
Current Fiscal Year End Date --12-31  
Document Fiscal Year Focus 2023  
Document Fiscal Period Focus Q2  
Amendment Flag false  
Common Units    
Document Information    
Entity Common Stock, Shares Outstanding   65,507,635
Class B    
Document Information    
Entity Common Stock, Shares Outstanding   20,853,618
v3.23.2
CONSOLIDATED BALANCE SHEETS - USD ($)
Jun. 30, 2023
Dec. 31, 2022
Current assets    
Cash and cash equivalents $ 20,779,119 $ 24,635,718
Oil, natural gas and NGL receivables 45,006,388 46,993,711
Derivative assets 1,794,888  
Accounts receivable and other current assets 3,135,807 3,562,912
Total current assets 70,716,202 75,192,341
Property and equipment, net 771,872 953,781
Oil and natural gas properties    
Oil and natural gas properties, using full cost method of accounting ($125,601,085 and $207,695,343 excluded from depletion at June 30, 2023 and December 31, 2022, respectively) 1,602,199,705 1,465,985,718
Less: accumulated depreciation, depletion and impairment (749,745,922) (712,716,951)
Total oil and natural gas properties, net 852,453,783 753,268,767
Right-of-use assets, net 2,357,665 2,525,323
Derivative assets 1,580,439 754,786
Loan origination costs, net 6,308,398 3,004,104
Investments held in trust   240,600,000
Total assets 934,188,359 1,076,746,299
Current liabilities    
Accounts payable 1,369,894 1,210,337
Other current liabilities 8,340,805 4,909,510
Derivative liabilities 428,560 12,646,720
Total current liabilities 10,139,259 18,766,567
Operating lease liabilities, excluding current portion 2,066,030 2,236,361
Derivative liabilities 170,529 432,142
Long-term debt 269,600,000 233,015,911
Other liabilities 260,417 322,917
Total liabilities 282,236,235 263,336,623
Commitments and contingencies (Note 15)
Mezzanine equity:    
Redeemable non-controlling interest in Kimbell Tiger Acquisition Corporation   236,900,000
Kimbell Royalty Partners, LP unitholders' equity:    
Common units (65,507,635 units and 64,231,833 units issued and outstanding as of June 30, 2023 and December 31, 2022, respectively) 596,177,270 601,841,776
Class B units (20,853,618 and 15,484,400 units issued and outstanding as of June 30, 2023 and December 31, 2022, respectively) 1,042,681 774,220
Total Kimbell Royalty Partners, LP unitholders' equity 597,219,951 602,615,996
Non-controlling interest (deficit) in OpCo 54,732,173 (26,106,320)
Total equity 651,952,124 576,509,676
Total liabilities, mezzanine equity and unitholders' equity $ 934,188,359 1,076,746,299
Consolidated variable interest entities    
Oil and natural gas properties    
Cash   390,850
Investments held in trust   240,621,146
Prepaid expenses   35,201
Current liabilities    
Other current liabilities   512,725
Deferred underwriting commissions   $ 8,050,000
v3.23.2
CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($)
Jun. 30, 2023
Dec. 31, 2022
CONSOLIDATED BALANCE SHEETS    
Oil and natural gas properties excluded from depletion $ 125,601,085 $ 207,695,343
Common units, issued (in units) 65,507,635 64,231,833
Common units, outstanding (in units) 65,507,635 64,231,833
Class B units, issued (in units) 20,853,618 15,484,400
Class B units, outstanding (in units) 20,853,618 15,484,400
v3.23.2
CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($)
3 Months Ended 6 Months Ended
Jun. 30, 2023
Jun. 30, 2022
Jun. 30, 2023
Jun. 30, 2022
Revenues $ 56,981,614 $ 78,591,469 $ 114,398,373 $ 143,675,372
Lease bonus and other income 2,041,189 1,213,322 2,478,526 1,867,452
Gain (Loss) on commodity derivative instruments, net 1,729,459 (7,094,127) 10,791,835 (39,077,647)
Total revenues 60,752,262 72,710,664 127,668,734 106,465,177
Costs and expenses        
Production and ad valorem taxes 5,404,955 5,002,794 9,682,159 9,023,705
Depreciation and depletion expense 19,656,855 11,273,960 37,220,503 22,033,124
Marketing and other deductions 2,907,459 4,063,004 5,669,498 7,571,070
General and administrative expense 7,925,159 7,866,176 16,203,426 14,455,435
Total costs and expenses 36,113,901 28,796,434 69,703,285 54,413,293
Operating income 24,638,361 43,914,230 57,965,449 52,051,884
Other income (expense)        
Equity income in affiliate   3,385,325   3,634,733
Interest expense (6,341,118) (3,323,290) (11,804,522) (6,201,145)
Loss on extinguishment of debt (480,244)   (480,244)  
Other (expense) income (180,765) 898,207 (180,765) 3,966,657
Net income before income taxes 18,706,088 45,097,607 49,008,609 53,776,650
Income tax expense 909,057 1,803,441 2,312,040 2,075,240
Net income 17,797,031 43,294,166 46,696,569 51,701,410
Net income attributable to non-controlling interests in OpCo (4,297,442) (5,424,092) (9,860,860) (6,482,769)
Distribution on Class B units (31,601) (8,211) (47,085) (25,821)
Net income attributable to common units of Kimbell Royalty Partners, LP $ 13,467,988 $ 37,861,863 $ 36,788,624 $ 45,192,820
Net income per unit attributable to common units of Kimbell Royalty Partners, LP        
Net income per unit attributable to common units (basic) (in dollar per share) $ 0.24 $ 0.66 $ 0.61 $ 0.54
Net income per unit attributable to common units (diluted) (in dollar per share) $ 0.23 $ 0.55 $ 0.59 $ 0.42
Weighted average number of common units outstanding        
Weighted average number of common units outstanding Basic (in units) 63,274,492 55,424,930 62,910,053 50,710,073
Weighted average number of common units outstanding Diluted (in units) 82,959,981 65,543,669 81,263,101 65,323,279
Consolidated variable interest entities        
Costs and expenses        
General and administrative expense $ 219,473 $ 590,500 $ 927,699 $ 1,329,959
Other income (expense)        
Interest earned on marketable securities in trust account $ 1,069,854 $ 223,135 $ 3,508,691 $ 324,521
v3.23.2
CONSOLIDATED STATEMENTS OF CHANGES IN UNITHOLDERS' EQUITY - USD ($)
Common Units
Class B Common Units
Non-controlling Interest in Opco
Non-controlling Interest in TGR
Total
Unitholders' capital, beginning balance at Dec. 31, 2021 $ 328,717,841 $ 880,579 $ 19,251,361   $ 348,849,781
Unitholders' capital, beginning balance (in units) at Dec. 31, 2021 47,162,773 17,611,579      
Increase (Decrease) in Unitholders' Capital          
Costs associated with equity offering $ (325,508)       (325,508)
Conversion of Class B units to common units $ 161,424,103 $ (467,896) (161,424,103)   (467,896)
Conversion of Class B units to common units (in units) 9,357,919 (9,357,919)      
Restricted units repurchased for tax withholding $ (3,344,828)       (3,344,828)
Restricted units repurchased for tax withholding (in units) (193,604)        
Unit-based compensation $ 2,194,342       2,194,342
Unit-based compensation (in units) 963,835        
Distributions to unitholders $ (17,450,226)   (6,516,284)   (23,966,510)
Distribution on Class B units (17,610)       (17,610)
Proceeds from issuance of TGR public warrants       $ 11,500,000 11,500,000
Accretion of redeemable non-controlling interest in Kimbell Tiger Acquisition Corporation (16,325,799)   (2,351,988) $ (11,500,000) (30,177,787)
Net income 7,348,567   1,058,677   8,407,244
Unitholders' capital, ending balance at Mar. 31, 2022 $ 462,220,882 $ 412,683 (149,982,337)   312,651,228
Unitholders' capital, ending balance (in units) at Mar. 31, 2022 57,290,923 8,253,660      
Unitholders' capital, beginning balance at Dec. 31, 2021 $ 328,717,841 $ 880,579 19,251,361   348,849,781
Unitholders' capital, beginning balance (in units) at Dec. 31, 2021 47,162,773 17,611,579      
Increase (Decrease) in Unitholders' Capital          
Net income         51,701,410
Unitholders' capital, ending balance at Jun. 30, 2022 $ 475,269,981 $ 410,579 (149,358,266)   326,322,294
Unitholders' capital, ending balance (in units) at Jun. 30, 2022 57,331,833 8,211,579      
Unitholders' capital, beginning balance at Mar. 31, 2022 $ 462,220,882 $ 412,683 (149,982,337)   312,651,228
Unitholders' capital, beginning balance (in units) at Mar. 31, 2022 57,290,923 8,253,660      
Increase (Decrease) in Unitholders' Capital          
Conversion of Class B units to common units $ 722,952 $ (2,104) (722,952)   (2,104)
Conversion of Class B units to common units (in units) 42,081 (42,081)      
Forfeiture of restricted units $ (19,813)       (19,813)
Forfeiture of restricted units (in units) (1,171)        
Unit-based compensation $ 2,949,491       2,949,491
Distributions to unitholders (26,945,962)   (3,859,442)   (30,805,404)
Distribution on Class B units (8,211)       (8,211)
Accretion of redeemable non-controlling interest in Kimbell Tiger Acquisition Corporation (1,519,432)   (217,627)   (1,737,059)
Net income 37,870,074   5,424,092   43,294,166
Unitholders' capital, ending balance at Jun. 30, 2022 $ 475,269,981 $ 410,579 (149,358,266)   326,322,294
Unitholders' capital, ending balance (in units) at Jun. 30, 2022 57,331,833 8,211,579      
Unitholders' capital, beginning balance at Dec. 31, 2022         602,615,996
Unitholders' capital, beginning balance at Dec. 31, 2022 $ 601,841,776 $ 774,220 (26,106,320)   $ 576,509,676
Unitholders' capital, beginning balance (in units) at Dec. 31, 2022 64,231,833 15,484,400     64,231,833
Increase (Decrease) in Unitholders' Capital          
Restricted units repurchased for tax withholding $ (4,851,962)       $ (4,851,962)
Restricted units repurchased for tax withholding (in units) (279,662)        
Unit-based compensation $ 3,170,000       3,170,000
Unit-based compensation (in units) 998,162        
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
Unitholders' capital, ending balance at Mar. 31, 2023 $ 592,304,290 $ 774,220 (27,979,517)   565,098,993
Unitholders' capital, ending balance (in units) at Mar. 31, 2023 64,950,333 15,484,400      
Unitholders' capital, beginning balance at Dec. 31, 2022         602,615,996
Unitholders' capital, beginning balance at Dec. 31, 2022 $ 601,841,776 $ 774,220 (26,106,320)   $ 576,509,676
Unitholders' capital, beginning balance (in units) at Dec. 31, 2022 64,231,833 15,484,400     64,231,833
Increase (Decrease) in Unitholders' Capital          
Net income         $ 46,696,569
Unitholders' capital, ending balance at Jun. 30, 2023         597,219,951
Unitholders' capital, ending balance at Jun. 30, 2023 $ 596,177,270 $ 1,042,681 54,732,173   $ 651,952,124
Unitholders' capital, ending balance (in units) at Jun. 30, 2023 65,507,635 20,853,618     65,507,635
Unitholders' capital, beginning balance at Mar. 31, 2023 $ 592,304,290 $ 774,220 (27,979,517)   $ 565,098,993
Unitholders' capital, beginning balance (in units) at Mar. 31, 2023 64,950,333 15,484,400      
Increase (Decrease) in Unitholders' Capital          
Common units issued for acquisition $ 8,654,900 $ 268,461 83,383,956   92,307,317
Common units issued for acquisition (in units) 557,302 5,369,218      
Unit-based compensation $ 3,289,740       3,289,740
Distributions to unitholders (22,732,617)   (5,349,476)   (28,082,093)
Distribution on Class B units (31,601)       (31,601)
Accretion of redeemable noncontrolling interest in Kimbell Tiger Acquisition Corporation and write-off of deferred underwriting commissions 1,192,969   379,768   1,572,737
Net income 13,499,589   4,297,442   17,797,031
Unitholders' capital, ending balance at Jun. 30, 2023         597,219,951
Unitholders' capital, ending balance at Jun. 30, 2023 $ 596,177,270 $ 1,042,681 $ 54,732,173   $ 651,952,124
Unitholders' capital, ending balance (in units) at Jun. 30, 2023 65,507,635 20,853,618     65,507,635
v3.23.2
CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($)
6 Months Ended
Jun. 30, 2023
Jun. 30, 2022
CASH FLOWS FROM OPERATING ACTIVITIES    
Net income $ 46,696,569 $ 51,701,410
Adjustments to reconcile net income to net cash provided by operating activities:    
Depreciation and depletion expense 37,220,503 22,033,124
Amortization of right-of-use assets 167,658 157,298
Amortization of loan origination costs 1,008,830 901,660
Loss on extinguishment of debt 480,244  
Equity income in affiliate   (3,634,733)
Cash distribution from affiliate   3,770,651
Forfeiture of restricted units   (19,813)
Unit-based compensation 6,459,740 5,143,833
(Gain) loss on derivative instruments, net of settlements (15,100,314) 12,116,997
Changes in operating assets and liabilities:    
Oil, natural gas and NGL receivables 1,987,323 (18,448,369)
Accounts receivable and other current assets 427,105 906,119
Accounts payable 159,557 741,972
Other current liabilities 3,431,295 1,859,036
Operating lease liabilities (170,331) (159,717)
Net cash provided by operating activities 78,572,135 76,455,640
CASH FLOWS FROM INVESTING ACTIVITIES    
Purchases of property and equipment (72,123) (75,398)
Purchase of oil and natural gas properties (44,175,131) (443,977)
Proceeds from trust of variable interest entity 930,850  
Cash distribution from affiliate   3,465,376
Net cash provided by (used in) investing activities 199,882,583 (233,953,999)
CASH FLOWS FROM FINANCING ACTIVITIES    
Costs associated with equity offering   (325,508)
Contributions from Class B unitholders 268,461  
Redemption of Class B contributions on converted units   (470,000)
Distributions to common unitholders (53,908,777) (44,396,188)
Distribution to OpCo unitholders (12,786,091) (10,375,726)
Distribution on Class B units (47,085) (25,821)
Borrowings on long-term debt 59,084,089 36,200,000
Repayments on long-term debt (22,500,000) (37,200,000)
Payment of loan origination costs (4,793,368) (435,142)
Restricted units repurchased for tax withholding (4,851,962) (3,344,828)
Net cash (used in) provided by financing activities (282,702,167) 164,550,499
NET (DECREASE) INCREASE IN CASH AND CASH EQUIVALENTS (4,247,449) 7,052,140
CASH AND CASH EQUIVALENTS, beginning of period 25,026,568 7,052,414
CASH AND CASH EQUIVALENTS, end of period 20,779,119 14,104,554
Supplemental cash flow information:    
Cash paid for interest 10,963,296 5,032,259
Cash paid for taxes   2,043,374
Non-cash investing and financing activities:    
Units issued in exchange for oil and natural gas properties 92,038,856  
Recognition of tenant improvement asset 62,500 62,501
Consolidated variable interest entities    
Changes in operating assets and liabilities:    
Interest earned on marketable securities in trust account (3,508,691) (324,521)
Other assets and liabilities (687,353) (289,307)
CASH FLOWS FROM INVESTING ACTIVITIES    
Cash received from investments held in trust 243,167,434  
Cash paid for transaction costs 31,553  
Investment in marketable securities   (236,900,000)
CASH FLOWS FROM FINANCING ACTIVITIES    
Payment of underwriting commissions with equity offering of Kimbell Tiger Operating Company, net of adjustments   (2,661,288)
Proceeds from initial public offering of Kimbell Tiger Operating Company   227,585,000
Redemption of Kimbell Tiger Acquisition Corporation equity units (243,167,434)  
CASH AND CASH EQUIVALENTS, end of period   786,721
Non-cash investing and financing activities:    
Reduction of deferred underwriting commission associated with redemption of Kimbell Tiger Acquisition Corporation equity units $ (8,050,000)  
Deferred underwriting commissions   $ 8,050,000
v3.23.2
CONSOLIDATED STATEMENTS OF CASH FLOWS (Parenthetical) - USD ($)
Jun. 30, 2023
Jun. 30, 2022
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 $ 20,779,119 $ 14,104,554
Consolidated variable interest entities    
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   786,721
Non-Consolidated Variable Interest Entity Primary Beneficiary    
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 $ 20,779,119 $ 13,317,833
v3.23.2
ORGANIZATION AND BASIS OF PRESENTATION
6 Months Ended
Jun. 30, 2023
ORGANIZATION AND BASIS OF PRESENTATION  
ORGANIZATION AND BASIS OF PRESENTATION

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.

On February 8, 2022, the Partnership announced the $230 million initial public offering of its special purpose acquisition company, Kimbell Tiger Acquisition Corporation (NYSE: TGR).

Kimbell Tiger Acquisition Corporation (“TGR”) was formed for the purpose of effecting a merger, capital stock exchange, asset acquisition, stock purchase, reorganization or similar business combination with one or more businesses. Kimbell Tiger Acquisition Sponsor, LLC (“TGR Sponsor”), which was a subsidiary of the Partnership, and was created to assist TGR in sourcing, analyzing and consummating acquisition opportunities for that initial business combination. TGR Sponsor and TGR have been consolidated in the financial statements of the Partnership beginning in the year ended December 31, 2021.  

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 (as defined in Note 4) included as part of the units issued in its initial public offering. Following such redemption, TGR (along with TGR Sponsor) was dissolved in accordance with the terms of its organizational documents. Further details can be found in Note 4—Acquisitions, Joint Venture and Special Purpose Acquisition Company.

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 U.S. 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, 2022 (the “2022 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.

Russia / Ukraine Conflict

In February 2022, Russia invaded Ukraine and is still engaged in active armed conflict against the country. The conflict 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 the invasion of Ukraine; however, the Partnership will continue to monitor for events that could materially impact them.

v3.23.2
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
6 Months Ended
Jun. 30, 2023
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES  
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

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 2022 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 and six months ended June 30, 2023.

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 represent funds raised by TGR, a consolidated special purpose acquisition company, through the TGR IPO (as defined in Note 4). These funds were held in an actively-traded money market fund, which invested in U.S. Treasury securities. Investments held in trust are classified as trading securities and are 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. The estimated fair values of investments held in the trust account are determined using quoted prices in an active market and therefore are classified in Level 1 of the fair value hierarchy, as described in Note 6— Fair Value Measurements.

Redeemable Non-Controlling Interest

Redeemable non-controlling interests represent the shares of TGR Class A common stock (as defined in Note 4) sold in the TGR IPO that were redeemable for cash by the public TGR shareholders that would have been concurrent with TGR’s initial business combination or in the event of TGR’s failure to complete a business combination or a tender offer. The redeemable non-controlling interests were initially recorded at their original issue price, net of issuance costs and the initial fair value of separately traded warrants. As of June 30, 2023, the shares had been redeemed in full.

New Accounting Pronouncements

In March 2023, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2023-01, “Leases (Topic 842): Common Control Arrangements.” This update requires that (i) entities determine whether a related party arrangement between entities under common control is a lease and (ii) that leasehold improvements have an amortization period consistent with the shorter of the remaining lease term and the useful life of the improvements, which is an approach that is largely consistent with legacy guidance. This update is effective for financial statements issued for fiscal years beginning after December 15, 2023, including interim periods within that fiscal year. 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.

v3.23.2
REVENUE FROM CONTRACTS WITH CUSTOMERS
6 Months Ended
Jun. 30, 2023
REVENUE FROM CONTRACTS WITH CUSTOMERS  
REVENUE FROM CONTRACTS WITH CUSTOMERS

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 June 30, 

Six Months Ended June 30, 

2023

    

2022

2023

    

2022

Oil revenue

$

39,809,883

$

34,567,049

$

72,810,169

$

68,340,181

Natural gas revenue

11,539,982

35,876,768

31,188,764

58,894,902

NGL revenue

5,631,749

8,147,652

10,399,440

16,440,289

Total Oil, natural gas and NGL revenues

$

56,981,614

$

78,591,469

$

114,398,373

$

143,675,372

v3.23.2
ACQUISITIONS, JOINT VENTURE AND SPECIAL PURPOSE ACQUISITION COMPANY
6 Months Ended
Jun. 30, 2023
ACQUISITIONS, JOINT VENTURE AND SPECIAL PURPOSE ACQUISITION COMPANY  
ACQUISITIONS, JOINT VENTURE AND SPECIAL PURPOSE ACQUISITION COMPANY

NOTE 4ACQUISITIONS, JOINT VENTURE AND SPECIAL PURPOSE ACQUISITION COMPANY

Acquisitions

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 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. 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.

On December 15, 2022, the Partnership completed the acquisition of certain mineral and royalty assets held by Hatch Royalty LLC (the “Hatch Acquisition”). The aggregate consideration for the Hatch Acquisition consisted of (i) approximately $150.4 million in cash and (ii) the issuance of 7,272,821 OpCo common units and an equal number of Class B units. The Partnership funded the cash payment of the purchase price with borrowings under its secured revolving credit facility. The assets acquired in the Hatch Acquisition are located in the Permian Basin and the Partnership estimates that the assets consisted of approximately 889 net royalty acres on approximately 230,000 gross acres. The Hatch Acquisition was accounted for as an asset acquisition and the allocation of the purchase price was $56.4 million to proved properties and $204.7 million to unevaluated properties.

Joint Venture

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 was 49.3%. During the year ended December 31, 2022, the Joint Venture completed the sale of its royalty, mineral and overriding interests and similar non-cost bearing interests in oil and gas properties for a total purchase price of $15.0 million. Net proceeds distributed to the Partnership were $6.5 million during the year ended December 31, 2022, the majority of which was used to repay debt on the Partnership’s secured revolving credit facility. The Joint Venture was dissolved on November 1, 2022.

Special Purpose Acquisition Company

On July 29, 2021, TGR, the Partnership’s recently dissolved special purpose acquisition company and subsidiary, filed a registration statement on Form S-1 with the SEC. On February 8, 2022, TGR consummated its initial public offering (the “TGR IPO”) of 23,000,000 units (each a “unit” and, collectively, the “units”), including 3,000,000 additional units issued pursuant to the underwriter’s exercise in full of its over-allotment option, at $10.00 per unit, generating proceeds of approximately $230,000,000 and incurring offering costs of approximately $12,650,000, inclusive of $8,050,000 in deferred underwriting commissions. Each unit consisted of one share of Class A common stock, par value $0.0001 (the

“TGR Class A common stock”), and one-half of one redeemable warrant. Each whole warrant was exercisable for one share of Class A common stock at a price of $11.50 per share. Certain members of our management and members of the Board of Directors were members of the sponsor of TGR, TGR Sponsor. TGR was formed for the purpose of effecting a merger, capital stock exchange, asset acquisition, stock purchase, reorganization or similar business combination with one or more businesses (the “Business Combination”). Under the terms of TGR’s governing documents, TGR had until May 8, 2023 (15 months from the closing of the TGR IPO) to complete the Business Combination, subject to TGR Sponsor’s option to extend such deadline by three months up to two times.

In connection with the closing of the TGR IPO, TGR completed the sale of 14.1 million private placement warrants (the “private placement warrants”) to TGR Sponsor, which was a subsidiary of the Partnership, for a purchase price of $1.00 per private placement warrant, generating gross proceeds of $14.1 million. Each private placement warrant was exercisable to purchase for $11.50 one share of TGR Class A common stock.

In addition, TGR incurred $12.7 million of fees and expenses, of which $8.1 million were deferred underwriting commissions that became payable to the underwriters solely in the event that TGR completed the Business Combination, which were included in deferred underwriting commissions on the accompanying unaudited interim consolidated balance sheet at December 31, 2022.

In May 2021, prior to TGR’s IPO, TGR Sponsor paid $25,000 in exchange for the issuance of (i) 5,750,100 shares of TGR’s Class B common stock, par value $0.0001 per share (the “TGR Class B common stock”), and (ii) 2,500 shares of TGR Class A common stock. Additionally, in May 2021, TGR paid $25,000 to Kimbell Tiger Operating Company (“TGR Opco”) in exchange for the issuance of 2,500 Class A units of TGR Opco. Also in May 2021, TGR Sponsor received 100 Class A units of TGR Opco in exchange for $1,000 and 5,750,000 Class B units of TGR Opco. The shares of TGR Class B common stock and corresponding number of Class B units of TGR Opco (or the Class A units of TGR Opco into which such Class B units will convert) are collectively referred to as the “Founders Shares.” The Founders Shares would have been exchangeable for shares of TGR Class A common stock upon completion of the Business Combination on a one-for-one basis, subject to certain adjustments. Class A units and Class B units of TGR Opco were substantially similar, other than certain distribution rights, and were entitled to vote together as a single class on all matters submitted for stockholder vote.

In determining the accounting treatment of the Partnership’s equity interest in TGR, management concluded that TGR was a VIE as defined by Accounting Standards Codification Topic 810, “Consolidation.” A VIE is an entity in which equity investors at risk lack the characteristics of a controlling financial interest. VIEs are consolidated by the primary beneficiary, the party who has both the power to direct the activities of a VIE that most significantly impact the entity’s economic performance, as well as the obligation to absorb losses of the entity or the right to receive benefits from the entity that could potentially be significant to the entity. TGR Sponsor was the primary beneficiary of TGR as it had, through its equity interest, the right to receive benefits or the obligation to absorb losses from TGR, as well as the power to direct a majority of the activities that significantly impacted TGR’s economic performance, including identification of a target for its Business Combination. As such, TGR was consolidated into the Partnership’s financial statements through TGR Sponsor.

Proceeds of $236.9 million were deposited in a trust account established for the benefit of TGR’s public unitholders consisting of certain proceeds from the TGR IPO and certain proceeds from the sale of the private placement warrants, net of underwriters’ discounts and commissions and other costs and expenses. The proceeds held in the trust account were not available to be used by the Partnership at any time. A minimum balance of $236.9 million, representing the number of TGR units sold at a redemption value of $10.30 per unit, was required by the underwriting agreement to be maintained in the trust account. The proceeds held in the trust account were only permitted to be invested in U.S. government treasury obligations with a maturity of 185 days or less or in money market funds meeting certain conditions under Rule 2a-7 of the Investment Company Act that invest only in direct U.S. government treasury obligations. In connection with the trust account, the Partnership reported investments held in trust of $240.6 million on the accompanying unaudited interim consolidated balance sheet as of December 31, 2022.

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 included as part of the units issued in its initial public offering. The per-share redemption price for the TGR public shares was $10.57 and the Partnership remeasured and accreted through equity the redeemable non-

controlling interest in TGR to its redemption value of $243.0 million and wrote off the deferred underwriting commissions through equity. The public shares of TGR ceased trading as of the close of business on May 8, 2023. As of the close of business on May 9, 2023, the public shares were deemed cancelled and represented only the right to receive the redemption amount. Following such redemption, TGR (along with TGR Sponsor) was dissolved in accordance with the terms of its organizational documents. There were no redemption rights or liquidating distributions with respect to TGR’s warrants, including the Private Placement Warrants held by TGR Sponsor, which expired worthless. TGR Sponsor waived its redemption rights with respect to TGR’s outstanding common stock issued before TGR’s initial public offering. The Class A common stock was redeemed on June 22, 2023 and the Partnership completed the dissolution and deconsolidation of TGR on June 30, 2023. The net non-cash impact of the deconsolidation of TGR was $1.6 million, which is included in the accompanying unaudited interim consolidated balance sheet as of June 30, 2023.

v3.23.2
DERIVATIVES
6 Months Ended
Jun. 30, 2023
DERIVATIVES  
DERIVATIVES

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 June 30, 2023, 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 June 30, 2023, these economic hedges constituted approximately 15% 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 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 current period and are presented on a net basis within revenue in the accompanying unaudited interim 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. On May 17, 2022, the Partnership entered into a partial termination agreement with Citibank to unwind 50% of the interest rate swap. On August 8, 2022, the Partnership entered into a termination agreement with Citibank to unwind the remaining 50% of the interest rate swap. The May 2022 termination resulted in a $3.0 million gain, which is included in other income (expense) in the accompanying unaudited interim consolidated statements of operations for the three and six months ended June 30, 2022. The Partnership used an interest rate swap for the management of interest rate risk exposure, as the interest rate swap effectively converted 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 were recognized as gains or losses in the current period and were presented on a net basis within other income in the accompanying unaudited interim consolidated statements of operations. As of June 30, 2022, the interest rate swap had a total notional amount of $75.0 million and a fair value of $3.3 million.

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 June 30, 

Six Months Ended June 30, 

2023

2022

2023

2022

Beginning fair value of derivative instruments

$

175,525

$

(45,305,641)

$

(12,324,076)

$

(26,624,646)

Gain (loss) on derivative instruments

1,729,459

(6,195,920)

10,791,835

(34,434,335)

Net cash paid on settlements of derivative instruments

871,254

12,759,918

4,308,479

22,317,338

Ending fair value of derivative instruments

$

2,776,238

$

(38,741,643)

$

2,776,238

$

(38,741,643)

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

June 30, 

December 31, 

Classification

Balance Sheet Location

2023

2022

Assets:

Current assets

Derivative assets

$

1,794,888

$

Long-term assets

Derivative assets

1,580,439

754,786

Liabilities:

Current liabilities

Derivative liabilities

(428,560)

(12,646,720)

Long-term liabilities

Derivative liabilities

(170,529)

(432,142)

$

2,776,238

$

(12,324,076)

As of June 30, 2023, 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

July 2023 - December 2023

140,668

$

62.33

$

61.70

$

63.00

January 2024 - December 2024

228,044

$

74.44

$

69.30

$

82.40

January 2025 - June 2025

171,558

$

65.17

$

64.35

$

66.31

Natural Gas Price Swaps

Notional

Weighted Average

Range (per MMBtu)

Volumes (MMBtu)

Fixed Price (per MMBtu)

Low

High

July 2023 - December 2023

2,043,412

$

3.18

$

3.09

$

3.28

January 2024 - December 2024

3,229,292

$

4.34

$

4.15

$

4.48

January 2025 - June 2025

1,765,168

$

3.93

$

3.53

$

4.37

v3.23.2
FAIR VALUE MEASUREMENTS
6 Months Ended
Jun. 30, 2023
FAIR VALUE MEASUREMENTS  
FAIR VALUE MEASUREMENTS

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 June 30, 2023 and December 31, 2022 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).

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 and six months ended June 30, 2023 and 2022.

The estimated fair values of investments held in the trust account are determined using quoted prices in an active market and therefore are classified in Level 1 of the fair value hierarchy. 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

June 30, 2023

Assets

Commodity derivative contracts

$

$

3,375,327

$

$

$

3,375,327

Liabilities

Commodity derivative contracts

$

$

(599,089)

$

$

$

(599,089)

December 31, 2022

Assets

Commodity derivative contracts

$

$

754,786

$

$

$

754,786

Investments held in trust

$

240,621,146

$

$

$

$

240,621,146

Liabilities

Commodity derivative contracts

$

$

(13,078,862)

$

$

$

(13,078,862)

v3.23.2
OIL AND NATURAL GAS PROPERTIES
6 Months Ended
Jun. 30, 2023
OIL AND NATURAL GAS PROPERTIES  
OIL AND NATURAL GAS PROPERTIES

NOTE 7—OIL AND NATURAL GAS PROPERTIES

Oil and natural gas properties consist of the following:

    

June 30, 

December 31, 

2023

2022

Oil and natural gas properties

Proved properties

$

1,476,598,620

$

1,258,290,375

Unevaluated properties

125,601,085

207,695,343

Less: accumulated depreciation, depletion and impairment

(749,745,922)

(712,716,951)

Total oil and natural gas properties

$

852,453,783

$

753,268,767

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 developed producing 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 did not record an impairment on its oil and natural gas properties for the three or six months ended June 30, 2023 or 2022.

v3.23.2
LEASES
6 Months Ended
Jun. 30, 2023
LEASES  
LEASES

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. 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 June 30, 2023 is 5.88 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 six months ended June 30, 2023.

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 and six months ended June 30, 2023 and 2022. The total operating lease expense recorded for both the three months ended June 30, 2023 and 2022 was $0.1 million and $0.3 million and $0.2 million for the six months ended June 30, 2023 and 2022, 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 June 30, 2023 were as follows:

Total

2023

2024

2025

2026

2027

Thereafter

Operating leases

$

2,956,414

$

243,741

$

488,725

$

497,033

$

507,648

$

511,917

$

707,350

Less: Imputed Interest

 

(554,818)

 

Total

$

2,401,596

 

v3.23.2
LONG-TERM DEBT
6 Months Ended
Jun. 30, 2023
LONG-TERM DEBT.  
LONG-TERM DEBT

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 $750,000,000, 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 $10,000,000, and (ii) an extension of the maturity date of the A&R Credit Agreement to June 7, 2027.

The revolving credit facility bears interest at a rate equal to, at the Partnership’s election, either (a) 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 (b) a base rate plus an applicable margin that varies from 1.75% to 2.75% per annum, based on borrowing base utilization.

The 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 first scheduled redetermination will be on or around November 1, 2023.

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 A&R Credit Agreement) above $30.0 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, each beginning with the fiscal quarter ending June 30, 2023.

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.

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.

On July 24, 2023, the Partnership entered into Amendment No. 1 (the “First Amendment”) to the A&R Credit Agreement. The amendment amends 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.

During the six months ended June 30, 2023, the Partnership borrowed an additional $59.1 million under the secured revolving credit facility and repaid approximately $22.5 million of the outstanding borrowings. As of June 30, 2023, the Partnership’s outstanding balance was $269.6 million. The Partnership was in compliance with all covenants included in the secured revolving credit facility as of June 30, 2023.

As of June 30, 2023, 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 and six months ended June 30, 2023, the weighted average interest rate on the Partnership’s outstanding borrowings was 8.76% and 8.52%, respectively.

v3.23.2
UNITHOLDERS' EQUITY AND PARTNERSHIP DISTRIBUTIONS
6 Months Ended
Jun. 30, 2023
UNITHOLDERS' EQUITY AND PARTNERSHIP DISTRIBUTIONS  
UNITHOLDERS' EQUITY AND PARTNERSHIP DISTRIBUTIONS

NOTE 10—UNITHOLDERS’ EQUITY AND PARTNERSHIP DISTRIBUTIONS

The Partnership has issued units representing limited partner interests. As of June 30, 2023, the Partnership had a total of 65,507,635 common units issued and outstanding and 20,853,618 Class B units outstanding.

In November 2022, the Partnership completed an underwritten public offering of 6,900,000 common units for net proceeds of approximately $117.0 million (the “2022 Equity Offering”). The Partnership used the net proceeds from the

2022 Equity Offering to purchase OpCo common units. The Operating Company in turn used the net proceeds to repay approximately $116.0 million of the outstanding borrowings under the Partnership’s secured revolving credit facility.

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

Common Units

Balance at December 31, 2022

64,231,833

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

998,162

Restricted units repurchased for tax withholding

(279,662)

Common unit issued for acquisition

557,302

Balance at June 30, 2023

65,507,635

(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 21, 2023.

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 2023

$

0.35

May 3, 2023

May 15, 2023

May 22, 2023

Q2 2023

$

0.39

August 2, 2023

August 14, 2023

August 21, 2023

Q1 2022

$

0.47

April 22, 2022

May 2, 2022

May 9, 2022

Q2 2022

$

0.55

August 3, 2022

August 15, 2022

August 22, 2022

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 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.

v3.23.2
EARNINGS (LOSS) PER COMMON UNIT
6 Months Ended
Jun. 30, 2023
EARNINGS (LOSS) PER COMMON UNIT  
EARNINGS (LOSS) PER COMMON UNIT

NOTE 11—EARNINGS (LOSS) PER COMMON UNIT

Basic earnings (loss) per common unit is calculated by dividing net income (loss) attributable to common units by the weighted-average number of common units outstanding during the period. Diluted net income (loss) per common unit gives effect, when applicable, to unvested restricted units granted under the Partnership’s A&R LTIP (as defined in Note 12) for its employees, directors and consultants and potential conversion of Class B units. The Partnership uses the “if-converted” method to determine the potential dilutive effect of exchanges of outstanding 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 (loss) per common unit:

Three Months Ended June 30, 

Six Months Ended June 30, 

2023

2022

2023

2022

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

$

13,467,988

$

37,861,863

$

36,788,624

$

45,192,820

Net adjustment to accretion of redeemable non-controlling interest in Kimbell Tiger Acquisition Corporation and write-off of deferred underwriting commissions

1,572,737

(1,519,432)

1,572,737

(17,845,231)

Net income attributable to common units of Kimbell Royalty Partners, LP after accretion of redeemable non-controlling interest in Kimbell Tiger Acquisition Corporation and write-off of deferred underwriting commissions

15,040,725

36,342,431

38,361,361

27,347,589

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

4,329,043

9,907,945

Diluted net income attributable to common units of Kimbell Royalty Partners, LP after accretion of redeemable non-controlling interest in Kimbell Tiger Acquisition Corporation

19,369,768

36,342,431

48,269,306

27,347,589

Weighted average number of common units outstanding:

Basic

63,274,492

55,424,930

62,910,053

50,710,073

Effect of dilutive securities:

Class B units

18,139,508

8,221,290

16,819,289

12,787,092

Restricted units

1,545,981

1,897,449

1,533,759

1,826,114

Diluted

82,959,981

65,543,669

81,263,101

65,323,279

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

Basic

$

0.24

$

0.66

$

0.61

$

0.54

Diluted

$

0.23

$

0.55

$

0.59

$

0.42

The calculation of diluted net income per share for the three and six months ended June 30, 2023 and 2022 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.

v3.23.2
UNIT-BASED COMPENSATION
6 Months Ended
Jun. 30, 2023
UNIT-BASED COMPENSATION  
UNIT-BASED COMPENSATION

NOTE 12—UNIT-BASED COMPENSATION

On May 18, 2022, the Partnership held a special meeting of unitholders of the Partnership (the “Special Meeting”), at which the Partnership’s unitholders voted to approve the Amended and Restated Kimbell Royalty GP, LLC 2017 Long-Term Incentive Plan (the “A&R LTIP”), which increased the number of common units eligible for issuance under the A&R LTIP by 3,700,000 common units for a total of 8,241,600 common units. The Partnership’s A&R LTIP authorizes grants to its employees, directors and consultants. 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. 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 A&R 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, 2022

1,897,192

$

13.553

 

1.517 years

Awarded

998,162

15.020

Vested

(943,924)

12.602

Unvested at June 30, 2023

1,951,430

$

14.763

 

2.029 years

v3.23.2
INCOME TAXES
6 Months Ended
Jun. 30, 2023
INCOME TAXES  
INCOME TAXES

NOTE 13—INCOME TAXES

The Partnership’s provision for income taxes is based on the estimated annual effective tax rate plus discrete items. The Partnership recorded an income tax expense of $0.9 million and $1.8 million for the three months ended June 30, 2023 and 2022, respectively, and an income tax expense of $2.3 million and $2.1 million for the six months ended June 30, 2023 and 2022, respectively.

v3.23.2
RELATED PARTY TRANSACTIONS
6 Months Ended
Jun. 30, 2023
RELATED PARTY TRANSACTIONS  
RELATED PARTY TRANSACTIONS

NOTE 14—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 and six months ended June 30, 2023, no monthly services fee was paid to BJF Royalties. During the three and six months ended June 30, 2023, the Partnership made payments to K3 Royalties in the amount of $30,000 and $60,000, respectively. Certain consultants who provide services under management services agreements are granted restricted units under the Partnership’s A&R LTIP.

The Partnership received $48,853 and $105,095 in reimbursements from Rivercrest Capital Management, LLC for shared operating expenses for the three and six months ended June 30, 2023, respectively.

Commencing on the date of the TGR IPO, TGR agreed to pay the Partnership a total of $25,000 per month for office space utilities, secretarial support and administrative services provided to members of the management team. During the three and six months ended June 30, 2023, TGR incurred $25,000 and $50,000, respectively, as part of this service agreement. Such fees are eliminated in consolidation. Upon TGR’s liquidation, TGR ceased paying these monthly fees.

v3.23.2
COMMITMENTS AND CONTINGENCIES
6 Months Ended
Jun. 30, 2023
COMMITMENTS AND CONTINGENCIES.  
COMMITMENTS AND CONTINGENCIES

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 June 30, 2023.

v3.23.2
SUBSEQUENT EVENTS
6 Months Ended
Jun. 30, 2023
SUBSEQUENT EVENTS  
SUBSEQUENT EVENTS

NOTE 16—SUBSEQUENT EVENTS

The Partnership has evaluated events that occurred subsequent to June 30, 2023 in the preparation of its unaudited interim consolidated financial statements.

Distributions

On August 2, 2023, the Board of Directors declared a quarterly cash distribution of $0.39 per common unit and OpCo common unit for the quarter ended June 30, 2023. The Partnership intends to pay this distribution on August 21, 2023 to common unitholders and OpCo common unitholders of record as of the close of business on August 14, 2023.

Acquisition

On August 2, 2023, the Partnership announced that it has agreed to acquire mineral and royalty interests held by LongPoint Minerals II, LLC in a cash transaction valued at approximately $455.0 million, subject to purchase price adjustments and other customary closing adjustments. The Partnership intends to fund the purchase price through a private placement of 6.00% Series A Cumulative Convertible Preferred Units to funds managed by affiliates of Apollo Global Management, LLC and borrowings under its revolving credit facility. The final mix of funding will be determined at closing.

Long-Term Debt

On July 28, 2023, the Partnership drew down $47.0 million on the senior secured revolving credit facility to fund the deposit on the LongPoint Acquisition.

v3.23.2
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies)
6 Months Ended
Jun. 30, 2023
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES  
Basis of Presentation

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 U.S. 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, 2022 (the “2022 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

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

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.

Consolidation

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 by Consolidated Variable Interest Entities

Investments held in trust represent funds raised by TGR, a consolidated special purpose acquisition company, through the TGR IPO (as defined in Note 4). These funds were held in an actively-traded money market fund, which invested in U.S. Treasury securities. Investments held in trust are classified as trading securities and are 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. The estimated fair values of investments held in the trust account are determined using quoted prices in an active market and therefore are classified in Level 1 of the fair value hierarchy, as described in Note 6— Fair Value Measurements.

Redeemable Non-Controlling Interest

Redeemable Non-Controlling Interest

Redeemable non-controlling interests represent the shares of TGR Class A common stock (as defined in Note 4) sold in the TGR IPO that were redeemable for cash by the public TGR shareholders that would have been concurrent with TGR’s initial business combination or in the event of TGR’s failure to complete a business combination or a tender offer. The redeemable non-controlling interests were initially recorded at their original issue price, net of issuance costs and the initial fair value of separately traded warrants. As of June 30, 2023, the shares had been redeemed in full.

New Accounting Pronouncements

New Accounting Pronouncements

In March 2023, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2023-01, “Leases (Topic 842): Common Control Arrangements.” This update requires that (i) entities determine whether a related party arrangement between entities under common control is a lease and (ii) that leasehold improvements have an amortization period consistent with the shorter of the remaining lease term and the useful life of the improvements, which is an approach that is largely consistent with legacy guidance. This update is effective for financial statements issued for fiscal years beginning after December 15, 2023, including interim periods within that fiscal year. 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.

v3.23.2
REVENUE FROM CONTRACTS WITH CUSTOMERS (Tables)
6 Months Ended
Jun. 30, 2023
REVENUE FROM CONTRACTS WITH CUSTOMERS  
Schedule of disaggregation of revenues

Three Months Ended June 30, 

Six Months Ended June 30, 

2023

    

2022

2023

    

2022

Oil revenue

$

39,809,883

$

34,567,049

$

72,810,169

$

68,340,181

Natural gas revenue

11,539,982

35,876,768

31,188,764

58,894,902

NGL revenue

5,631,749

8,147,652

10,399,440

16,440,289

Total Oil, natural gas and NGL revenues

$

56,981,614

$

78,591,469

$

114,398,373

$

143,675,372

v3.23.2
DERIVATIVES (Tables)
6 Months Ended
Jun. 30, 2023
DERIVATIVES  
Schedule of changes in fair value of derivative instruments

Three Months Ended June 30, 

Six Months Ended June 30, 

2023

2022

2023

2022

Beginning fair value of derivative instruments

$

175,525

$

(45,305,641)

$

(12,324,076)

$

(26,624,646)

Gain (loss) on derivative instruments

1,729,459

(6,195,920)

10,791,835

(34,434,335)

Net cash paid on settlements of derivative instruments

871,254

12,759,918

4,308,479

22,317,338

Ending fair value of derivative instruments

$

2,776,238

$

(38,741,643)

$

2,776,238

$

(38,741,643)

Schedule of derivative contracts

June 30, 

December 31, 

Classification

Balance Sheet Location

2023

2022

Assets:

Current assets

Derivative assets

$

1,794,888

$

Long-term assets

Derivative assets

1,580,439

754,786

Liabilities:

Current liabilities

Derivative liabilities

(428,560)

(12,646,720)

Long-term liabilities

Derivative liabilities

(170,529)

(432,142)

$

2,776,238

$

(12,324,076)

Schedule of commodity derivative contracts

Oil Price Swaps

Notional

Weighted Average

Range (per Bbl)

Volumes (Bbl)

Fixed Price (per Bbl)

Low

High

July 2023 - December 2023

140,668

$

62.33

$

61.70

$

63.00

January 2024 - December 2024

228,044

$

74.44

$

69.30

$

82.40

January 2025 - June 2025

171,558

$

65.17

$

64.35

$

66.31

Natural Gas Price Swaps

Notional

Weighted Average

Range (per MMBtu)

Volumes (MMBtu)

Fixed Price (per MMBtu)

Low

High

July 2023 - December 2023

2,043,412

$

3.18

$

3.09

$

3.28

January 2024 - December 2024

3,229,292

$

4.34

$

4.15

$

4.48

January 2025 - June 2025

1,765,168

$

3.93

$

3.53

$

4.37

v3.23.2
FAIR VALUE MEASUREMENTS (Tables)
6 Months Ended
Jun. 30, 2023
FAIR VALUE MEASUREMENTS  
Schedule of assets and liabilities measured at fair value on a recurring basis

Fair Value Measurements Using

Level 1

Level 2

Level 3

Effect of
Counterparty Netting

Total

June 30, 2023

Assets

Commodity derivative contracts

$

$

3,375,327

$

$

$

3,375,327

Liabilities

Commodity derivative contracts

$

$

(599,089)

$

$

$

(599,089)

December 31, 2022

Assets

Commodity derivative contracts

$

$

754,786

$

$

$

754,786

Investments held in trust

$

240,621,146

$

$

$

$

240,621,146

Liabilities

Commodity derivative contracts

$

$

(13,078,862)

$

$

$

(13,078,862)

v3.23.2
OIL AND NATURAL GAS PROPERTIES (Tables)
6 Months Ended
Jun. 30, 2023
OIL AND NATURAL GAS PROPERTIES  
Schedule of oil and natural gas properties

    

June 30, 

December 31, 

2023

2022

Oil and natural gas properties

Proved properties

$

1,476,598,620

$

1,258,290,375

Unevaluated properties

125,601,085

207,695,343

Less: accumulated depreciation, depletion and impairment

(749,745,922)

(712,716,951)

Total oil and natural gas properties

$

852,453,783

$

753,268,767

v3.23.2
LEASES (Tables)
6 Months Ended
Jun. 30, 2023
LEASES  
Schedule of future minimum lease commitments

Total

2023

2024

2025

2026

2027

Thereafter

Operating leases

$

2,956,414

$

243,741

$

488,725

$

497,033

$

507,648

$

511,917

$

707,350

Less: Imputed Interest

 

(554,818)

 

Total

$

2,401,596

 

v3.23.2
UNITHOLDERS' EQUITY AND PARTNERSHIP DISTRIBUTIONS (Tables)
6 Months Ended
Jun. 30, 2023
Common units  
Schedule of distributions approved by the Board of Directors

Amount per

Date

Unitholder

Payment

Common Unit

Declared

Record Date

Date

Q1 2023

$

0.35

May 3, 2023

May 15, 2023

May 22, 2023

Q2 2023

$

0.39

August 2, 2023

August 14, 2023

August 21, 2023

Q1 2022

$

0.47

April 22, 2022

May 2, 2022

May 9, 2022

Q2 2022

$

0.55

August 3, 2022

August 15, 2022

August 22, 2022

Common Units  
Common units  
Schedule of changes in Partnership's units

Common Units

Balance at December 31, 2022

64,231,833

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

998,162

Restricted units repurchased for tax withholding

(279,662)

Common unit issued for acquisition

557,302

Balance at June 30, 2023

65,507,635

(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 21, 2023.
v3.23.2
EARNINGS (LOSS) PER COMMON UNIT (Tables)
6 Months Ended
Jun. 30, 2023
EARNINGS (LOSS) PER COMMON UNIT  
Schedule of earnings (loss) per unit

Three Months Ended June 30, 

Six Months Ended June 30, 

2023

2022

2023

2022

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

$

13,467,988

$

37,861,863

$

36,788,624

$

45,192,820

Net adjustment to accretion of redeemable non-controlling interest in Kimbell Tiger Acquisition Corporation and write-off of deferred underwriting commissions

1,572,737

(1,519,432)

1,572,737

(17,845,231)

Net income attributable to common units of Kimbell Royalty Partners, LP after accretion of redeemable non-controlling interest in Kimbell Tiger Acquisition Corporation and write-off of deferred underwriting commissions

15,040,725

36,342,431

38,361,361

27,347,589

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

4,329,043

9,907,945

Diluted net income attributable to common units of Kimbell Royalty Partners, LP after accretion of redeemable non-controlling interest in Kimbell Tiger Acquisition Corporation

19,369,768

36,342,431

48,269,306

27,347,589

Weighted average number of common units outstanding:

Basic

63,274,492

55,424,930

62,910,053

50,710,073

Effect of dilutive securities:

Class B units

18,139,508

8,221,290

16,819,289

12,787,092

Restricted units

1,545,981

1,897,449

1,533,759

1,826,114

Diluted

82,959,981

65,543,669

81,263,101

65,323,279

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

Basic

$

0.24

$

0.66

$

0.61

$

0.54

Diluted

$

0.23

$

0.55

$

0.59

$

0.42

v3.23.2
UNIT-BASED COMPENSATION (Tables)
6 Months Ended
Jun. 30, 2023
UNIT-BASED COMPENSATION  
Schedule of unvested restricted stock activity

Weighted

    

Weighted

Average

Average

Grant-Date

Remaining

Fair Value

Contractual

Units

per Unit

Term

Unvested at December 31, 2022

1,897,192

$

13.553

 

1.517 years

Awarded

998,162

15.020

Vested

(943,924)

12.602

Unvested at June 30, 2023

1,951,430

$

14.763

 

2.029 years

v3.23.2
ORGANIZATION AND BASIS OF PRESENTATION (Details)
6 Months Ended
Feb. 08, 2022
USD ($)
Jun. 30, 2023
USD ($)
segment
Mar. 31, 2023
USD ($)
Dec. 31, 2022
USD ($)
Jun. 30, 2022
USD ($)
Mar. 31, 2022
USD ($)
Dec. 31, 2021
USD ($)
Organization              
Assets   $ 934,188,359   $ 1,076,746,299      
Liabilities   282,236,235   263,336,623      
Redeemable Noncontrolling Interest, Equity, Carrying Amount       236,900,000      
Partners' Capital, Including Portion Attributable to Noncontrolling Interest   $ 651,952,124 $ 565,098,993 $ 576,509,676 $ 326,322,294 $ 312,651,228 $ 348,849,781
Segment Reporting              
Number of operating units | segment   1          
Number of reporting units | segment   1          
IPO | Kimbell Tiger Acquisition Corporation              
Organization              
Common units sold to public $ 230,000,000            
v3.23.2
REVENUE FROM CONTRACTS WITH CUSTOMERS (Details) - USD ($)
3 Months Ended 6 Months Ended
Jun. 30, 2023
Jun. 30, 2022
Jun. 30, 2023
Jun. 30, 2022
Revenue from External Customer [Line Items]        
Total revenue $ 56,981,614 $ 78,591,469 $ 114,398,373 $ 143,675,372
Oil revenue        
Revenue from External Customer [Line Items]        
Total revenue 39,809,883 34,567,049 72,810,169 68,340,181
Natural gas revenue        
Revenue from External Customer [Line Items]        
Total revenue 11,539,982 35,876,768 31,188,764 58,894,902
NGL revenue        
Revenue from External Customer [Line Items]        
Total revenue $ 5,631,749 $ 8,147,652 $ 10,399,440 $ 16,440,289
v3.23.2
ACQUISITIONS, JOINT VENTURE AND SPECIAL PURPOSE ACQUISITION COMPANY - Acquisitions (Details)
1 Months Ended 6 Months Ended 12 Months Ended
May 22, 2023
USD ($)
$ / shares
May 17, 2023
USD ($)
shares
Dec. 15, 2022
USD ($)
a
shares
Feb. 08, 2022
USD ($)
$ / shares
shares
Jul. 29, 2021
USD ($)
$ / shares
May 31, 2021
USD ($)
$ / shares
shares
Jun. 30, 2023
USD ($)
$ / shares
Dec. 31, 2022
USD ($)
Jun. 19, 2019
Acquisitions                  
Stock split conversion ratio           1      
Assets Held-in-trust               $ 240,600,000  
Assets             $ 934,188,359 1,076,746,299  
Liabilities             282,236,235 263,336,623  
Purchase and sale agreement | Royalty, mineral and overriding interests                  
Acquisitions                  
Total purchase price               15,000,000.0  
Net proceeds realized               6,500,000  
Kimbell Tiger Acquisition Corporation                  
Acquisitions                  
Common units issued for equity offering (in units) | shares       23,000,000          
Share price (in dollar per share) | $ / shares       $ 10.00          
Warrant share price (in dollar per share) | $ / shares       $ 11.50          
Assets Held-in-trust             $ 236,900,000    
Redemption price per share | $ / shares             $ 10.30    
Redemption price $ 243,000,000.0                
Stock issuance costs         $ 12,650,000     12,700,000  
Deferred underwriting commissions         $ 8,050,000        
Proceeds from Issuance of Common Stock       $ 230,000,000          
Threshold Period to Complete Business Combination After Initial Public Offerings       15 months          
Kimbell Tiger Acquisition Corporation | Other Liabilities                  
Acquisitions                  
Deferred underwriting commissions               $ 8,100,000  
Kimbell Tiger Acquisition Sponsor, LLC                  
Acquisitions                  
Common units issued for equity offering           $ 25,000      
Number of units received during period | shares           100      
Kimbell Tiger Acquisition Sponsor, LLC | Private Placement Warrants                  
Acquisitions                  
Warrant share price (in dollar per share) | $ / shares       $ 1.00          
Class of warrant or right issued | shares       14,100,000          
Gross proceeds from issuance of warrants       $ 14,100,000          
Kimbell Tiger Operating Company | Capital Unit Class A                  
Acquisitions                  
Number of units issued, shares | shares           2,500      
Number of units issued, value           $ 25,000      
Kimbell Tiger Operating Company | Capital Unit Class B                  
Acquisitions                  
Number of units issued, shares | shares           5,750,000      
Number of units issued, value           $ 1,000      
Springbok SKR Capital Company, LLC and Rivercrest Capital Partners, LP.                  
Acquisitions                  
Ownership interest (as a percent)                 49.30%
Kimbell Tiger Acquisition Corporation                  
Acquisitions                  
Redemption of equity in variable interest entity $ 1,600,000                
Underwriters option to purchase additional units | Kimbell Tiger Acquisition Corporation                  
Acquisitions                  
Common units issued for equity offering (in units) | shares       3,000,000          
Class A | Kimbell Tiger Acquisition Corporation                  
Acquisitions                  
Class of Warrant or Right, Number of Securities Called by Each Warrant or Right | shares       1          
Redemption price per share | $ / shares $ 10.57                
Class A | Kimbell Tiger Acquisition Sponsor, LLC                  
Acquisitions                  
Common units issued for equity offering (in units) | shares           2,500      
Class A | Kimbell Tiger Acquisition Sponsor, LLC | Private Placement Warrants                  
Acquisitions                  
Warrant share price (in dollar per share) | $ / shares       $ 11.50          
Class A | Kimbell Tiger Acquisition Corporation                  
Acquisitions                  
Common Stock par value (in dollars per share) | $ / shares         $ 0.0001        
Class B | Kimbell Tiger Acquisition Sponsor, LLC                  
Acquisitions                  
Common units issued for equity offering (in units) | shares           5,750,100      
Common Stock par value (in dollars per share) | $ / shares           $ 0.0001      
MB Minerals, L.P. and certain of its affiliates                  
Acquisition asset allocation                  
Proved properties   $ 60,800,000              
Unevaluated properties   74,900,000              
Hatch Royalties, LLC                  
Acquisitions                  
Purchase price cash, gross     $ 150,400,000            
Gross acres acquired (in acres) | a     230,000            
Net royalty acres acquired (in acres) | a     889            
Acquisition asset allocation                  
Proved properties     $ 56,400,000            
Unevaluated properties     $ 204,700,000            
Hatch Royalties, LLC | OpCo Units                  
Acquisitions                  
Business Acquisition issuance of common units | shares     7,272,821            
MB Minerals, L.P.                  
Acquisitions                  
Purchase price cash, gross   $ 48,800,000              
MB Minerals, L.P. | OpCo Units                  
Acquisitions                  
Business Acquisition issuance of common units | shares   5,369,218              
MB Minerals, L.P. | Class B Common Units                  
Acquisitions                  
Business Acquisition issuance of common units | shares   557,302              
v3.23.2
DERIVATIVES (Details)
3 Months Ended 6 Months Ended
Jun. 30, 2023
USD ($)
$ / bbl
MMBbls
Jun. 30, 2022
USD ($)
Jun. 30, 2023
USD ($)
$ / bbl
MMBbls
Jun. 30, 2022
USD ($)
Dec. 31, 2022
USD ($)
May 17, 2022
Jan. 27, 2021
USD ($)
Derivatives              
Daily oil and natural gas production (as a percent) 15.00%   15.00%        
Change in fair values of derivative instruments              
Beginning fair value of commodity derivative instruments | $ $ 175,525 $ (45,305,641) $ (12,324,076) $ (26,624,646)      
Gain (loss) on derivative instruments | $ 1,729,459 (6,195,920) 10,791,835 (34,434,335)      
Net cash paid on settlements of derivative instruments | $ 871,254 12,759,918 4,308,479 22,317,338      
Ending fair value of commodity derivative instruments | $ 2,776,238 (38,741,643) 2,776,238 (38,741,643)      
Assets:              
Current assets | $ 1,794,888   1,794,888        
Long-term assets | $ 1,580,439   1,580,439   $ 754,786    
Liabilities:              
Current liability | $ (428,560)   (428,560)   (12,646,720)    
Long-term liability | $ (170,529)   (170,529)   (432,142)    
Derivative assets (liabilities) | $ $ 2,776,238 (38,741,643) $ 2,776,238 (38,741,643) $ (12,324,076)    
Interest Rate Swap              
Derivatives              
Derivative, Notional Amount | $   75,000,000.0   75,000,000.0     $ 150,000,000.0
Unwind notional amount (as a percent)           50.00%  
Change in fair values of derivative instruments              
Gain on interest rate swap | $   3,000,000.0   3,000,000.0      
Liabilities:              
Derivative Asset | $   $ 3,300,000   $ 3,300,000      
Oil Price Swaps - July 2023 - December 2023              
Derivatives              
Notional Volumes | MMBbls 140,668   140,668        
Weighted Average Fixed Price 62.33   62.33        
Oil Price Swaps - January 2024 - December 2024              
Derivatives              
Notional Volumes | MMBbls 228,044   228,044        
Weighted Average Fixed Price 74.44   74.44        
Oil Price Swaps - January 2025 - June 2025              
Derivatives              
Notional Volumes | MMBbls 171,558   171,558        
Weighted Average Fixed Price 65.17   65.17        
Natural Gas Price Swaps - July 2023 - December 2023              
Derivatives              
Notional Volumes | MMBbls 2,043,412   2,043,412        
Weighted Average Fixed Price 3.18   3.18        
Natural Gas Price Swaps - January 2024 - December 2024              
Derivatives              
Notional Volumes | MMBbls 3,229,292   3,229,292        
Weighted Average Fixed Price 4.34   4.34        
Natural Gas Price Swaps - January 2025 - June 2025              
Derivatives              
Notional Volumes | MMBbls 1,765,168   1,765,168        
Weighted Average Fixed Price 3.93   3.93        
Minimum | Oil Price Swaps - July 2023 - December 2023              
Derivatives              
Weighted Average Fixed Price 61.70   61.70        
Minimum | Oil Price Swaps - January 2024 - December 2024              
Derivatives              
Weighted Average Fixed Price 69.30   69.30        
Minimum | Oil Price Swaps - January 2025 - June 2025              
Derivatives              
Weighted Average Fixed Price 64.35   64.35        
Minimum | Natural Gas Price Swaps - July 2023 - December 2023              
Derivatives              
Weighted Average Fixed Price 3.09   3.09        
Minimum | Natural Gas Price Swaps - January 2024 - December 2024              
Derivatives              
Weighted Average Fixed Price 4.15   4.15        
Minimum | Natural Gas Price Swaps - January 2025 - June 2025              
Derivatives              
Weighted Average Fixed Price 3.53   3.53        
Maximum | Oil Price Swaps - July 2023 - December 2023              
Derivatives              
Weighted Average Fixed Price 63.00   63.00        
Maximum | Oil Price Swaps - January 2024 - December 2024              
Derivatives              
Weighted Average Fixed Price 82.40   82.40        
Maximum | Oil Price Swaps - January 2025 - June 2025              
Derivatives              
Weighted Average Fixed Price 66.31   66.31        
Maximum | Natural Gas Price Swaps - July 2023 - December 2023              
Derivatives              
Weighted Average Fixed Price 3.28   3.28        
Maximum | Natural Gas Price Swaps - January 2024 - December 2024              
Derivatives              
Weighted Average Fixed Price 4.48   4.48        
Maximum | Natural Gas Price Swaps - January 2025 - June 2025              
Derivatives              
Weighted Average Fixed Price 4.37   4.37        
v3.23.2
FAIR VALUE MEASUREMENTS (Details) - USD ($)
Jun. 30, 2023
Dec. 31, 2022
Jun. 30, 2022
Commodity Derivative contract      
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]      
Derivative contracts assets $ 3,375,327 $ 754,786  
Derivative contracts liabilities (599,089) (13,078,862)  
Commodity Derivative contract | Level 2      
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]      
Derivative contracts assets 3,375,327 754,786  
Derivative contracts liabilities $ (599,089) (13,078,862)  
Interest Rate Swap      
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]      
Derivative contracts assets     $ 3,300,000
Assets Held In Trust      
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]      
Derivative contracts assets   240,621,146  
Assets Held In Trust | Level 1      
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]      
Derivative contracts assets   $ 240,621,146  
v3.23.2
OIL AND NATURAL GAS PROPERTIES (Details) - USD ($)
3 Months Ended 6 Months Ended
Jun. 30, 2023
Jun. 30, 2022
Jun. 30, 2023
Jun. 30, 2022
Dec. 31, 2022
OIL AND NATURAL GAS PROPERTIES          
Proved properties $ 1,476,598,620   $ 1,476,598,620   $ 1,258,290,375
Unevaluated properties 125,601,085   125,601,085   207,695,343
Less: accumulated depreciation, depletion, and impairment (749,745,922)   (749,745,922)   (712,716,951)
Total oil and natural gas properties, net 852,453,783   852,453,783   $ 753,268,767
Impairment of oil and natural gas properties $ 0 $ 0 $ 0 $ 0  
v3.23.2
LEASES (Details) - USD ($)
3 Months Ended 6 Months Ended
Jun. 30, 2023
Jun. 30, 2022
Jun. 30, 2023
Jun. 30, 2022
LEASES        
Operating lease weighted average remaining lease term 5 years 10 months 17 days   5 years 10 months 17 days  
Operating lease weighted average discount rate (as a percent) 6.75%   6.75%  
Operating lease expense $ 100,000 $ 300,000 $ 200,000 $ 200,000
2023 243,741   243,741  
2024 488,725   488,725  
2025 497,033   497,033  
2026 507,648   507,648  
2027 511,917   511,917  
Thereafter 707,350   707,350  
Total operating leases 2,956,414   2,956,414  
Less Imputed Interest (554,818)   (554,818)  
Total $ 2,401,596   $ 2,401,596  
v3.23.2
LONG-TERM DEBT (Details) - USD ($)
3 Months Ended 6 Months Ended
Jun. 13, 2023
Jun. 30, 2023
Jun. 30, 2023
Jun. 30, 2022
Jul. 24, 2023
Jul. 23, 2023
Long-term debt            
Minimum percentage of proved reserves constituting borrowings based properties (as a percent)   75.00% 75.00%      
Amortization of Debt Issuance Costs     $ 1,008,830 $ 901,660    
Debt extinguishment     500,000      
Borrowings of debt     59,084,089 36,200,000    
Repayment of debt     22,500,000 $ 37,200,000    
Revolving credit facility            
Long-term debt            
Revolving credit facility outstanding   $ 269,600,000 $ 269,600,000      
Excess cash determinations         $ 50,000,000.0 $ 30,000,000.0
Interest rate on outstanding borrowings (as a percent)   8.76% 8.52%      
Borrowings of debt     $ 59,100,000      
Revolving credit facility | Prime            
Long-term debt            
Margin (as a percent)     2.25%      
Revolving credit facility | SOFR            
Long-term debt            
Margin (as a percent)     3.25%      
Revolving credit facility | Maximum            
Long-term debt            
Debt to EBITDAX ratio   350.00% 350.00%      
Revolving credit facility | Minimum            
Long-term debt            
Current assets to current liabilities ratio   100.00% 100.00%      
Standby and/or commercial letters of credit            
Long-term debt            
Revolving credit facility maximum borrowings $ 10,000,000          
Senior Secured Reserve Based Revolving Credit Facility            
Long-term debt            
Revolving credit facility maximum borrowings 750,000,000          
Borrowing base 400,000,000.0          
Initial aggregate elected commitments amount 400,000,000.0          
Minimum cash balance required to be applied weekly to prepay loans 30,000,000.0          
Reduced cash balance as permitted by agreement $ 0          
Commitment fees (as a percent) 0.50%          
Senior Secured Reserve Based Revolving Credit Facility | Maximum | SOFR            
Long-term debt            
Margin (as a percent) 3.75%          
Senior Secured Reserve Based Revolving Credit Facility | Maximum | Base Rate            
Long-term debt            
Margin (as a percent) 2.75%          
Senior Secured Reserve Based Revolving Credit Facility | Minimum | SOFR            
Long-term debt            
Margin (as a percent) 2.75%          
Senior Secured Reserve Based Revolving Credit Facility | Minimum | Base Rate            
Long-term debt            
Margin (as a percent) 1.75%          
v3.23.2
UNITHOLDERS' EQUITY AND PARTNERSHIP DISTRIBUTIONS (Details) - USD ($)
1 Months Ended 3 Months Ended 6 Months Ended
Nov. 30, 2022
Jun. 30, 2023
Jun. 30, 2022
Jun. 30, 2023
Jun. 30, 2022
Dec. 31, 2022
Common units            
Units issued (in units)   65,507,635   65,507,635   64,231,833
Units outstanding (in units)   65,507,635   65,507,635   64,231,833
Repayment of debt       $ 22,500,000 $ 37,200,000  
Capital rollforward            
Unitholders' capital, beginning balance (in units)       64,231,833    
Unitholders' capital, ending balance (in units)   65,507,635   65,507,635    
Cash distributions declared and paid (in dollars per unit)   $ 0.39 $ 0.55 $ 0.35 $ 0.47  
Common Units            
Common units            
Units issued (in units)   65,507,635   65,507,635    
Units outstanding (in units)   65,507,635   65,507,635   64,231,833
Capital rollforward            
Unitholders' capital, beginning balance (in units)       64,231,833    
Common units issued under the A&R LTIP (in units)       998,162    
Restricted units repurchased for tax withholding (in units)       (279,662)    
Common unit issued for acquisition (in units)       557,302    
Unitholders' capital, ending balance (in units)   65,507,635   65,507,635    
Class B            
Capital rollforward            
Cash distributions (as a percent)       2.00%    
Class B Common Units            
Common units            
Units outstanding (in units)   20,853,618   20,853,618    
Capital rollforward            
Unitholders' capital, ending balance (in units)   20,853,618   20,853,618    
Additional consideration paid per unit (in dollars per unit)       $ 0.05    
Public Offering            
Common units            
Units issued (in units) 6,900,000          
Proceeds from equity offering $ 117,000,000.0          
Repayment of debt $ 116,000,000.0          
v3.23.2
EARNINGS (LOSS) PER COMMON UNIT (Details) - USD ($)
3 Months Ended 6 Months Ended
Jun. 30, 2023
Jun. 30, 2022
Jun. 30, 2023
Jun. 30, 2022
Earnings per unit        
Net income attributable to common units of Kimbell Royalty Partners, LP $ 13,467,988 $ 37,861,863 $ 36,788,624 $ 45,192,820
Net adjustment to accretion of redeemable non-controlling interest in Kimbell Tiger Acquisition Corporation and write-off of deferred underwriting commissions (1,572,737) 1,519,432 (1,572,737) 17,845,231
Net income attributable to common units of Kimbell Royalty Partners, LP after accretion of redeemable non-controlling interest in Kimbell Tiger Acquisition Corporation and write-off of deferred underwriting commissions 15,040,725 36,342,431 38,361,361 27,347,589
Net income attributable to noncontrolling interest 4,297,442 5,424,092 9,860,860 6,482,769
Diluted net income attributable to common units of Kimbell Royalty Partners, LP after accretion of redeemable non-controlling interest in Kimbell Tiger Acquisition Corporation $ 19,369,768 $ 36,342,431 $ 48,269,306 $ 27,347,589
Weighted average number of common units outstanding Basic (in units) 63,274,492 55,424,930 62,910,053 50,710,073
Weighted average number of common units outstanding Diluted (in units) 82,959,981 65,543,669 81,263,101 65,323,279
Net income per unit attributable to common units (basic) (in dollar per share) $ 0.24 $ 0.66 $ 0.61 $ 0.54
Net income per unit attributable to common units (diluted) (in dollar per share) $ 0.23 $ 0.55 $ 0.59 $ 0.42
Restricted Units        
Earnings per unit        
Weighted average number of common units outstanding (in units) 1,545,981 1,897,449 1,533,759 1,826,114
Class B        
Earnings per unit        
Net income attributable to noncontrolling interest $ 4,329,043   $ 9,907,945  
Weighted average number of common units outstanding (in units) 18,139,508 8,221,290 16,819,289 12,787,092
v3.23.2
UNIT-BASED COMPENSATION (Details) - Long-Term Incentive Plan - $ / shares
6 Months Ended 12 Months Ended
May 18, 2022
Jun. 30, 2023
Dec. 31, 2022
Unit-based compensation      
Additional common units authorized for issuance 3,700,000    
Vesting period   3 years  
Authorized issuance of units 8,241,600    
First Anniversary      
Unit-based compensation      
Vesting percent   33.30%  
Second Anniversary      
Unit-based compensation      
Vesting percent   33.30%  
Third Anniversary      
Unit-based compensation      
Vesting percent   33.30%  
Restricted Units      
Unvested Units      
Unvested at beginning of period (in units)   1,897,192  
Awarded (in units)   998,162  
Vesting (in units)   (943,924)  
Unvested at end of period (in units)   1,951,430 1,897,192
Unvested Weighted Average Grant-Date Fair Value      
Unvested at beginning of period (in dollars per unit)   $ 13.553  
Awarded (in dollars per unit)   15.020  
Vesting (in dollars per unit)   12.602  
Unvested at end of period (in dollars per unit)   $ 14.763 $ 13.553
Weighted Average Remaining Contractual Term      
Unvested contractual term, at end of period   2 years 10 days 1 year 6 months 6 days
v3.23.2
INCOME TAXES - (Details) - USD ($)
3 Months Ended 6 Months Ended
Jun. 30, 2023
Jun. 30, 2022
Jun. 30, 2023
Jun. 30, 2022
INCOME TAXES        
Income tax expense $ 909,057 $ 1,803,441 $ 2,312,040 $ 2,075,240
v3.23.2
RELATED PARTY TRANSACTIONS (Details) - USD ($)
3 Months Ended 6 Months Ended
Feb. 08, 2022
Jun. 30, 2023
Jun. 30, 2022
Jun. 30, 2023
Jun. 30, 2022
Related Party Transactions          
Total revenue   $ 60,752,262 $ 72,710,664 $ 127,668,734 $ 106,465,177
Kimbell Tiger Acquisition Corporation          
Related Party Transactions          
Common units issued for equity offering (in units) 23,000,000        
Related Party          
Related Party Transactions          
Due from related parties   25,000   25,000  
Total revenue   25,000   50,000  
Related Party | BJF Royalties          
Related Party Transactions          
Payments made to related parties   0   0  
Related Party | K3 Royalties          
Related Party Transactions          
Payments made to related parties   30,000   60,000  
Related Party | Rivercrest Capital Management, LLC          
Related Party Transactions          
Related party expense reimbursement received   $ 48,853   $ 105,095  
v3.23.2
SUBSEQUENT EVENTS (Details) - Subsequent Event - USD ($)
$ / shares in Units, $ in Millions
Aug. 02, 2023
Jul. 28, 2023
Common Units    
Subsequent events    
Cash distributions declared (in dollars per unit) $ 0.39  
LongPoint Minerals II, LLC    
Subsequent events    
Cash consideration $ 455.0  
Revolving credit facility    
Subsequent events    
Draw downs   $ 47.0
Operating Company    
Subsequent events    
Cash distributions declared (in dollars per unit) $ 0.39  
Private placement    
Subsequent events    
Dividend percentage 6.00%  
v3.23.2
Insider Trading Arrangements
3 Months Ended
Jun. 30, 2023
Trading Arrangements, by Individual  
Rule 10b5-1 Arrangement Adopted false
Non-Rule 10b5-1 Arrangement Adopted false
Rule 10b5-1 Arrangement Terminated false
Non-Rule 10b5-1 Arrangement Terminated false

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