KIMBELL ROYALTY PARTNERS, LP 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 endedDecember 31, 2022 (the "2022 Form 10-K"). Unless the context otherwise requires, references to "Kimbell Royalty Partners, LP ," the "Partnership," "we" or "us" refer toKimbell Royalty Partners, LP and its subsidiaries. References to the "Operating Company" or "OpCo" refer toKimbell Royalty Operating, LLC . References to the "General Partner" refer toKimbell Royalty GP, LLC . References to the "Sponsors" refer to affiliates of the Partnership's founders,Ben J. Fortson ,Robert D. Ravnaas ,Brett G. Taylor andMitch 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
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
? revisions to our reserve estimates as a result of changes in commodity prices,
decline curves and other uncertainties;
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? impact of impairment expense on our financial statements;
? competition in the oil and natural gas industry generally and the mineral and
royalty industry in particular;
? the ability of the operators of our properties to obtain capital or financing
needed for development and exploration operations;
? title defects in the properties in which we acquire an interest;
? the availability or cost of rigs, completion crews, equipment, raw materials,
supplies, oilfield services or personnel;
? 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
treatment of our future earnings and distributions;
? our ability to maintain effective internal controls over financial reporting
and disclosure controls and procedures;
the ability of Kimbell Tiger Acquisition Corporation ("TGR") to select an
? appropriate target business or businesses, enter into a binding agreement with
a target and complete its initial business combination, as well as its ability
to obtain necessary financing to complete its initial business combination; and
? the overall performance and success of any target business or businesses
selected by TGR for its initial business combination.
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 aDelaware limited partnership formed in 2015 to own and acquire mineral and royalty interests in oil and natural gas properties throughoutthe United States . We have elected to be taxed as a corporation forUnited 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. 21
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As ofMarch 31, 2023 , we owned mineral and royalty interests in approximately 11.5 million gross acres and overriding royalty interests in approximately 4.7 million gross acres, with approximately 52% of our aggregate acres located in thePermian Basin and Mid-Continent. We refer to these non-cost-bearing interests collectively as our "mineral and royalty interests." As ofMarch 31, 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 held by production. Our mineral and royalty interests are located in 28 states and in every major onshore basin across the continentalUnited States and include ownership in over 124,000 gross wells, including over 48,000 wells in thePermian Basin .
The following table summarizes our ownership in
Average Daily
Production
Basin or Producing Region Gross Acreage Net Acreage (Boe/d)(6:1)(1) Well Count
Permian Basin 3,130,391 24,448 4,434 48,407
MidContinent 5,369,358 44,310 1,715 19,205
Terryville/Cotton
Valley/Haynesville 1,428,907 7,919 4,555 16,175
Appalachian Basin 741,354 23,203 1,729 3,871
Bakken/Williston Basin 1,640,077 6,138 930 5,278
Eagle Ford 624,148 6,730 1,780 4,088
DJ Basin/Rockies/Niobrara 74,152 1,036 777 12,540
Other 3,232,560 36,693 1,295 15,413
Total 16,240,947 150,477 17,215 124,977
"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 (1) 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
Basin or Producing Region(1) Gross DUCs Gross Permits Net DUCs Net Permits Permian Basin 416 369 1.63 1.30 MidContinent 82 55 0.13 0.15
Terryville/Cotton Valley/Haynesville 102 39 1.04
0.50
Appalachian Basin 7 12 0.01 0.02
Bakken/Williston Basin 73 183 0.22 0.27
Eagle Ford 61 70 0.48 0.74
DJ Basin/Rockies/Niobrara 8 22 0.04 0.21
Total 749 750 3.55 3.19
The above table represents DUCs and permitted locations only, and there is no (1) guarantee that the DUCs or permitted locations will be developed into
producing wells in the future.
Kimbell Tiger Acquisition Corporation
InApril 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 isKimbell Tiger Acquisition Sponsor, LLC (the "TGR Sponsor"), which is a wholly owned subsidiary of theOperating Company . The Sponsor owns a combination of equity securities in TGR and TGR's operating company,Kimbell Tiger Operating Company, LLC ("TGR Opco"), that represent 20% of the total outstanding shares of common stock of TGR. TGR intends to focus its search for a target business in the energy and natural resources industry inNorth America . OnFebruary 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 22
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an offering price of$10.00 and consists 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 entitles the holder thereof to purchase one share of Class A Common Stock at a price of$11.50 per share. OnFebruary 8, 2022 , simultaneously with the closing of the TGR IPO and pursuant to a separate private placement warrants purchase agreement datedFebruary 3, 2022 , TGR completed the private sale of 14,100,000 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 is exercisable to purchase for$11.50 one share of Class A Common Stock. Of the net proceeds of TGR's IPO and the sale of the Private Placement Warrants,$236,900,000 , including$8,050,000 of deferred underwriting discounts and commissions, has been deposited into aU.S. based trust account atJ.P. Morgan Chase Bank, N.A ., withContinental Stock Transfer & Trust Company acting as trustee.
Under the terms of TGR's governing documents, TGR has until
OnMay 3, 2023 , TGR announced that it will redeem all of its outstanding shares of Class A Common Stock included as part of the units issued in its initial public offering and the 2,500 shares of Class A common stock forming part of the sponsor shares, effective as of the close of business onMay 22, 2023 , as TGR will not consummate an initial business combination on or prior toMay 8, 2023 . Based on the amount held in trust as ofMarch 31, 2023 , the per-share redemption price for the TGR public shares is expected to be approximately$10.56 . The public shares of TGR will cease trading as of the close of business onMay 8, 2023 . As of the close of business onMay 9, 2023 , the public shares will be deemed cancelled and will represent only the right to receive the redemption amount. There will be no redemption rights or liquidating distributions with respect to TGR's warrants, including the Private Placement Warrants held by TGR Sponsor, which will expire worthless. TGR Sponsor has 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 future deconsolidation of TGR will be reflected in the Partnership's financial statements for the period endingJune 30, 2023 and is not expected to impact the Company's cash flow available for distribution or its liquidity.
Recent Developments
Acquisition
OnApril 11, 2023 , we entered into a purchase and sale agreement withMB Minerals, L.P. and certain of its affiliates (the "MB Minerals Acquisition") to acquire certain mineral and royalty assets located inHoward andBorden Counties,Texas . The aggregate consideration at closing will comprise of (i) approximately$48.8 million in cash and (ii) the issuance of (a) 5,369,218 common unit of theOperating Company ("OpCo common units") and an equal number of Class B units representing limited partnership interests in the Partnership ("ClassB Units ") and (b) 557,302 common unit representing limited partner interests in the Partnership ("common units"). Completion of the MB Minerals Acquisition is subject to the satisfaction or waiver of certain customary closing conditions as set forth in the purchase and sale agreement. The MB Minerals Acquisition is expected to close in the second quarter of 2023, with an effective date ofApril 1, 2023 . 23 Table of Contents Quarterly Distributions OnMay 3, 2023 , the Board of Directors declared a quarterly cash distribution of$0.35 per common unit and$0.346516 per OpCo common unit for the quarter endedMarch 31, 2023 . We intend to pay the distributions onMay 22, 2023 to common unitholders and OpCo common unitholders of record as of the close of business onMay 15, 2023 . As to us,$0.003484 excluded from the OpCo common unit distribution corresponds to a tax refund received by us in the first quarter of 2023. Under the limited liability company agreement of theOperating Company , we do not reimburse theOperating Company for federal income received by us.
Business Environment
InFebruary 2022 ,Russia invadedUkraine and is still engaged in active armed conflict against the country. The conflict and the sanctions imposed in response have led to regional instability and caused dramatic fluctuations in global financial markets and have increased the level of global economic and political uncertainty, including uncertainty about world-wide oil supply and demand, which in turn has increased volatility in commodity prices. To date, we have not experienced a material impact to operations or the consolidated financial statements as a result of the invasion ofUkraine ; however, we will continue to monitor for events that could materially impact us.
Commodity Prices and Demand
Oil and natural gas prices have been historically volatile and may continue to be volatile in the future. As noted above, the supply and demand imbalance resulting from variousOPEC announcements and the current conflict betweenRussia andUkraine have created increased volatility in oil and natural gas prices. The table below demonstrates such volatility for the periods presented as reported by theUnited States Energy Information Administration (the "EIA"). Three Months Ended March 31, 2023 Three Months Ended March 31, 2022 High Low High Low Oil ($/Bbl) $ 81.62 $ 66.61$ 123.64 $ 75.99 Natural gas ($/MMBtu) $ 3.78 $ 1.93$ 6.70 $ 3.73 OnApril 17, 2023 , the West Texas Intermediate posted price for crude oil was$80.93 per Bbl and the Henry Hub spot market price of natural gas was$2.21 per MMBtu. The following table, as reported by the EIA, sets forth the average daily prices for oil and natural gas. Three Months Ended March 31, 2023 2022 Oil ($/Bbl) $ 75.93 $ 95.18 Natural gas ($/MMBtu) $ 2.64 $ 4.67 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 increased by 12.0% to 736 active land rigs atMarch 31, 2023 compared to 657 active land rigs atMarch 31, 2022 . The 736 active land rigs atMarch 31, 2023 decreased slightly from 762 active land rigs atDecember 31, 2023 . The overall increase in rig count atMarch 31, 2023 comparedMarch 31, 2022 is primarily attributable to an uptake in the oil and natural gas market as a result of steadied oil and natural gas prices and overall supply shortages. 24 Table of Contents The following table summarizes the number of active rigs operating on our acreage byUnited States basins and producing regions for the periods indicated: March 31, Basin or Producing Region 2023 2022 Permian Basin 45 32 MidContinent 16 14 Terryville/Cotton Valley/Haynesville 21 13 Appalachian Basin - 2 Bakken/Williston Basin 9 5 Eagle Ford 3 6 Other - 1 Total 94 73 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 March 31,
2023 2022
Revenue
Oil sales 58 % 52 %
Natural gas sales 34 % 35 %
NGL sales 8 % 13 %
100 % 100 %
We have entered into oil and natural gas commodity derivative agreements, which
extend through March 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.
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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, 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 inthe 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. 26 Table of Contents 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
2023 2022
Reconciliation of net income to Adjusted EBITDA and cash available for distribution on common units: Net income$ 28,899,538 $
8,407,244
Depreciation and depletion expense 17,563,648
10,759,164
Interest expense 5,463,404
2,877,855
Cash distribution from affiliate -
385,326
Income tax expense 1,402,983 271,799
EBITDA 53,329,573 22,701,388
Unit-based compensation 3,170,000 2,194,342
(Gain) loss on derivative instruments, net of
settlements (12,499,601) 18,680,995
Cash distribution from affiliate -
42,544
Equity income in affiliate -
(249,408)
Consolidated variable interest entities related: Interest earned on marketable securities in trust account (2,438,837)
(101,386)
General and administrative expenses 708,226
660,671
Consolidated Adjusted EBITDA 42,269,361
43,929,146
Adjusted EBITDA attributable to non-controlling interest (8,137,227)
(5,531,750)
Adjusted EBITDA attributable toKimbell Royalty Partners, LP 34,132,134
38,397,396
Adjustments to reconcile Adjusted EBITDA to cash available for distribution Cash interest expense 4,123,709
1,958,779
Cash income tax refund (639,325)
-
Distributions on Class B units 15,484
17,610
Cash available for distribution on common units$ 30,632,266 $ 36,421,007 27 Table of Contents Three Months Ended March 31, 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$ 47,053,606 $ 36,032,473 Interest expense 5,463,404 2,877,855 Income tax expense 1,402,983 271,799
Amortization of right-of-use assets (83,157)
(78,025)
Amortization of loan origination costs (516,098)
(442,399)
Equity income in affiliate, net -
249,408
Unit-based compensation (3,170,000)
(2,194,342)
Gain (loss) on derivative instruments, net of settlements 12,499,601
(18,680,995)
Changes in operating assets and liabilities: Oil, natural gas and NGL receivables (11,058,014)
6,409,027
Accounts receivable and other current assets (513,812)
(730,660) Accounts payable 290,521 (1,082,653) Other current liabilities (255,526) (463,173) Operating lease liabilities 85,018 79,246 Consolidated variable interest entities related: Interest earned on marketable securities in trust account 2,438,837
101,386
Other assets and liabilities (307,790)
352,441 EBITDA 53,329,573 22,701,388 Add: Unit-based compensation 3,170,000 2,194,342 (Gain) loss on derivative instruments, net of settlements (12,499,601)
18,680,995
Cash distribution from affiliate -
42,544
Equity income in affiliate -
(249,408)
Consolidated variable interest entities related: Interest earned on marketable securities in Trust Account (2,438,837)
(101,386)
General and administrative expenses 708,226
660,671
Consolidated Adjusted EBITDA 42,269,361
43,929,146
Adjusted EBITDA attributable to non-controlling interest (8,137,227)
(5,531,750)
Adjusted EBITDA attributable toKimbell Royalty Partners, LP 34,132,134
38,397,396
Adjustments to reconcile Adjusted EBITDA to cash available for distribution Cash interest expense 4,123,709
1,958,779
Cash income tax expense (639,325)
-
Distributions on Class B units 15,484
17,610
Cash available for distribution on common units$ 30,632,266 $
36,421,007
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
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our results for the three months ended
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
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 monthsMarch 31, 2023 and 2022.
Because we continue to 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.
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Results of Operations
The table below summarizes our revenue and expenses and production data for the periods indicated (unaudited).
Three Months Ended March 31,
2023 2022
Operating Results:
RevenueOil, natural gas and NGL revenues$ 57,416,759 $
65,083,903
Lease bonus and other income 437,337
654,130
Gain (Loss) on commodity derivative instruments, net 9,062,376 (31,983,520) Total revenues 66,916,472 33,754,513 Costs and expenses
Production and ad valorem taxes 4,277,204
4,020,911
Depreciation and depletion expense 17,563,648
10,759,164
Marketing and other deductions 2,762,039
3,508,066
General and administrative expenses 8,278,267
6,589,259
Consolidated variable interest entities related: General and administrative expense 708,226
739,459
Total costs and expenses 33,589,384 25,616,859
Operating income 33,327,088 8,137,654
Other income (expense)
Equity income in affiliate - 249,408
Interest expense (5,463,404) (2,877,855)
Other income - 3,068,450
Consolidated variable interest entities
related:
Interest earned on marketable securities in
trust account 2,438,837 101,386
Net income before income taxes 30,302,521
8,679,043 Income tax expense 1,402,983 271,799 Net income 28,899,538 8,407,244 Net income attributable to non-controlling interests in OpCo (5,563,418)
(1,058,677)
Distribution on Class B units (15,484)
(17,610)
Net income attributable to common units of Kimbell Royalty Partners, LP$ 23,320,636 $ 7,330,957 Production Data: Oil (Bbls) 446,013 392,361 Natural gas (Mcf) 5,590,193 4,835,849 Natural gas liquids (Bbls) 202,705 204,425 Combined volumes (Boe) (6:1) 1,580,417 1,402,761
Comparison of the Three Months Ended
Oil, Natural Gas and NGL Revenues
For the three months endedMarch 31, 2023 , our oil, natural gas and NGL revenues were$57.4 million , a decrease of$7.7 million from$65.1 million for the three months endedMarch 31, 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 endedMarch 31, 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 1,580,417 Boe or 17,215 Boe/d, for the three months endedMarch 31, 2023 , an increase of 177,656 Boe or 2,733 Boe/d, from 1,402,761 Boe or 14,482 Boe/d, for the three months endedMarch 31, 2022 . The increase in production for the three months endedMarch 31, 2023 fromMarch 31, 2022 was primarily attributable to production associated with the Hatch Acquisition. Our operators received an average of$73.99 per Bbl of oil,$3.51 per Mcf of natural gas and$23.52 per Bbl of NGL for the volumes sold during the three months endedMarch 31, 2023 compared to$86.08 per Bbl of oil,$4.76 per Mcf of natural gas and$40.57 per Bbl of NGL for the volumes sold during the three months endedMarch 31, 2022 . These 30
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average prices received during the three months endedMarch 31, 2023 decreased 14.0% or$12.09 per Bbl of oil and 26.3% or$1.25 per Mcf of natural gas as compared to the three months endedMarch 31, 2022 . This change is consistent with prices experienced in the market, specifically when compared to the EIA average price decreases of 20.2% or$19.25 per Bbl of oil and 43.5% or$2.03 per Mcf of natural gas for the comparable periods.
Lease Bonus and Other Income
Lease bonus and other income was$0.4 million for the three months endedMarch 31, 2023 compared to$0.7 million for the three months endedMarch 31, 2022 . The decrease in lease bonus and other income is primarily related to a decrease in operators' leasing activity on our acreage as a result of the decrease in oil and natural gas prices.
Gain (Loss) on Commodity Derivative Instruments
Gain on commodity derivative instruments for the three months endedMarch 31, 2023 included$12.5 million of mark-to-market gains and$3.4 million of losses on the settlement of commodity derivative instruments compared to$22.5 million of mark-to-market losses and$9.5 million of losses on the settlement of commodity derivative instruments for the three months endedMarch 31, 2022 . We recorded a mark-to-market gain for the three months endedMarch 31, 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 three months endedMarch 31, 2022 as a result of the increase in the strip pricing of oil and natural gas from the three months endedDecember 31, 2021 to the three months endedMarch 31, 2022 .
Production and Ad Valorem Taxes
Production and ad valorem taxes for the three months endedMarch 31, 2023 were$4.3 million , an increase of$0.3 million from$4.0 million for the three months endedMarch 31, 2022 . The increase in production and ad valorem taxes was primarily attributable to the Hatch 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 endedMarch 31, 2023 was$17.6 million , an increase of$6.8 million from$10.8 million for the three months endedMarch 31, 2022 . The increase in depreciation and depletion expense was due to the Hatch 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$11.05 for the three months endedMarch 31, 2023 , an increase of$3.64 per barrel from the$7.41 average depletion rate per barrel for the three months endedMarch 31, 2022 . The increase in the depletion rate was due to the Hatch Acquisition that was closed inDecember 2022 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 three months endedMarch 31, 2023 were$2.8 million , a decrease of$0.7 million from$3.5 million for the three months endedMarch 31, 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 endedMarch 31, 2022 , partially offset by marketing and other deductions associated with the Hatch Acquisition.
General and Administrative Expenses
General and administrative expenses for the three months endedMarch 31, 2023 were$9.0 million , an increase of$1.7 million from$7.3 million for the three months endedMarch 31, 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$1.0 31 Table of Contents
million increase in unit-based compensation expense and cash general and administrative expenses resulting from an increase in our costs associated with company growth.
Interest Expense Interest expense for the three months endedMarch 31, 2023 was$5.5 million compared to$2.9 million for the three months endedMarch 31, 2022 . The increase in interest expense was primarily due to a 4.2% increase in the weighted average interest rate on the Partnership's outstanding borrowings for the three months endedMarch 31, 2023 . Income Tax Expense We recorded an income tax expense of$1.4 million for the three months endedMarch 31, 2023 . The income tax expense recorded during the three months endedMarch 31, 2023 was due to a change in the estimated income tax expense for the year endedDecember 31, 2023 . We recorded an income tax expense of$0.3 million for the three months endedMarch 31, 2022 . The income tax expense recorded during the three months ended was due to the significant increase in commodity prices which generated forecasted taxable net income for the year endedDecember 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 theOperating 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 theOperating Company . We expect that theOperating 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 theOperating 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 first quarter of 2023 for the repayment of$9.4 million in outstanding borrowings under our secured revolving credit facility during its determination of "available cash" for the first 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 32
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Class B units as partial consideration in connection with the Hatch Acquisition. The Board of Directors may choose to reserve a portion of cash generated from operations to finance such acquisitions as well. We do not currently intend to (i) maintain excess distribution coverage for the purpose of maintaining stability or growth in our quarterly distribution, (ii) otherwise reserve cash for distributions or (iii) incur debt to pay quarterly distributions, although the Board of Directors may do so if they believe it is warranted. See "Recent Developments-Quarterly Distributions" above for discussion of our first quarter 2023 distributions. Cash Flows
The table below presents our cash flows for the periods indicated.
Three Months Ended March 31,
2023 2022
Cash Flow Data:
Net cash provided by operating activities $ 47,053,606 $ 36,032,473
Net cash used in investing activities (321,642) (237,311,341)
Net cash (used in) provided by financing activities (52,580,221)
207,768,223
Net (decrease) increase in cash and cash equivalents$ (5,848,257) $ 6,489,355 Operating Activities
Our operating cash flow is impacted by many variables, the most significant of which are changes in oil, natural gas and NGL production volumes due to acquisitions or other external factors and changes in prices for oil, natural gas and NGLs. Prices for these commodities are determined primarily by prevailing market conditions. Regional and worldwide economic activity, weather and other substantially variable factors influence market conditions for these products. These factors are beyond our control and are difficult to predict. Cash flows provided by operating activities for the three months endedMarch 31, 2023 were$47.1 million , an increase of$11.1 million compared to$36.0 million for the three months endedMarch 31, 2022 .
Investing Activities
Cash flows used in investing activities for the three months endedMarch 31, 2023 were$0.3 million compared to$237.3 million for the three months endedMarch 31, 2023 . For the three months endedMarch 31, 2023 , cash flows used in investing activities include$0.3 million used to fund costs associated with the Hatch Acquisition. For the three months endedMarch 31, 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 byCaritas Royalty Fund LLC and certain of its affiliates.
Financing Activities
Cash flows used in financing activities were$52.6 million for the three months endedMarch 31, 2023 compared to$207.8 million of cash flows provided by financing activities for the three monthsMarch 31, 2022 . Cash flows used in financing activities for the three months endedMarch 31, 2023 consists of$38.6 million of distributions paid to holders common units, OpCo common units and Class B units,$13.1 million used to repay borrowings under out secured revolving credit facility and$4.9 million of restricted units repurchased for tax withholding, partially offset by$4.0 million of additional borrowings under our secured revolving credit facility. Cash flows provided by financing activities for the three months endedMarch 31, 2022 consists of$227.6 million in proceeds from TGR IPO and$19.1 million of additional borrowings under our secured revolving credit facility, partially offset by$24.0 million of distributions paid to holders of common units, OpCo common units and Class B units,$9.7 million used to repay borrowings under out secured revolving credit facility,$3.3 million of restricted units repurchased for tax withholding,$0.9 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 paid in connection with fees related to our 2021 equity offering and$0.2 million payment of loan origination costs. 33 Table of Contents Indebtedness OnDecember 15, 2022 , we entered into Amendment No. 4 (the "Fourth Credit Agreement Amendment") to our existing Credit Agreement, dated as ofJanuary 11, 2017 (as amended by that certain Amendment No. 1 to Credit Agreement, dated as ofJuly 12, 2018 , and that certain Amendment No. 2 to Credit Agreement, dated as ofDecember 8, 2020 , and that certain Amendment No. 3 to Credit Agreement, dated as ofJune 7, 2022 , and as otherwise amended or modified prior to such date, the "Credit Agreement" and the Credit Agreement, as amended by the Fourth Credit Agreement Amendment, the "Amended Credit Agreement"), with certain subsidiaries of the Partnership, as guarantors, the lenders party thereto and Citibank as administrative agent. The Fourth Credit Agreement Amendment amended the Credit Agreement to, among other things, (i) increase the aggregate elected commitments under the Amended Credit Agreement's senior secured revolving credit facility (the "Credit Facility") and (ii) the borrowing base under the Credit Facility, in each case, from$300.0 million to$350.0 million . The Amended Credit Agreement contains various affirmative, negative and financial maintenance covenants. These covenants limit our ability to, among other things, incur or guarantee additional debt, make distributions on, or redeem or repurchase, common units and OpCo common units, make certain investments and acquisitions, incur certain liens or permit them to exist, enter into certain types of transactions with affiliates, merge or consolidate with another company and transfer, sell or otherwise dispose of assets. The Amended Credit Agreement also contains covenants requiring us to maintain the following financial ratios or to reduce our indebtedness if we are unable to comply with such ratios: (i) a Debt to EBITDAX Ratio (as defined in the secured revolving credit facility) of not more than 3.5 to 1.0; and (ii) a ratio of current assets to current liabilities of not less than 1.0 to 1.0. The Amended Credit Agreement also contains customary events of default, including non-payment, breach of covenants, materially incorrect representations, cross default, bankruptcy and change of control. As ofMarch 31, 2023 , we had outstanding borrowings of$223.9 million under the secured revolving credit facility and$126.1 million of available capacity. The secured revolving credit facility matures onJune 7, 2024 . For additional information on our secured revolving credit facility, please read Note 8-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 forUnited States federal income tax purposes. Accordingly, we are subject toUnited 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 forU.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 theOperating Company , our capital structure and the amount of the earnings of theOperating 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. 34
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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
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