# Kimbell Royalty Partners, LP: Form 10-Q for the period ended Sep 30, 2023

- Company: [Kimbell Royalty Partners, LP](/companies/krp.md) (CIK 1657788)
- Form: 10-Q
- Filed: 2023-11-02
- Accepted by EDGAR: Nov 2, 2023, 20:05 ET
- Period: 2023-09-30
- Accession: 0001558370-23-017410
- Inline XBRL: yes
- Main document: https://www.sec.gov/Archives/edgar/data/1657788/000155837023017410/krp-20230930x10q.htm
- All documents and exhibits: https://www.sec.gov/Archives/edgar/data/1657788/000155837023017410/

## Figures reported in this filing

Standardized XBRL line items for the period ended 2023-09-30.

| Line item | Period | Value | XBRL concept |
| --- | --- | ---: | --- |
| Revenue | 3 months, 2023-07-01 to 2023-09-30 | $69.2m | us-gaap:RevenueFromContractWithCustomerExcludingAssessedTax |
| Revenue | 9 months, 2023-01-01 to 2023-09-30 | $183.6m | us-gaap:RevenueFromContractWithCustomerExcludingAssessedTax |
| Selling, general and administrative | 3 months, 2023-07-01 to 2023-09-30 | $10.4m | us-gaap:SellingGeneralAndAdministrativeExpense |
| Selling, general and administrative | 9 months, 2023-01-01 to 2023-09-30 | $26.6m | us-gaap:SellingGeneralAndAdministrativeExpense |
| Operating income | 3 months, 2023-07-01 to 2023-09-30 | $25.3m | us-gaap:OperatingIncomeLoss |
| Operating income | 9 months, 2023-01-01 to 2023-09-30 | $83.3m | us-gaap:OperatingIncomeLoss |
| Interest expense | 3 months, 2023-07-01 to 2023-09-30 | $6.7m | us-gaap:InterestExpense |
| Interest expense | 9 months, 2023-01-01 to 2023-09-30 | $18.5m | us-gaap:InterestExpense |
| Income tax | 3 months, 2023-07-01 to 2023-09-30 | $128.4k | us-gaap:IncomeTaxExpenseBenefit |
| Income tax | 9 months, 2023-01-01 to 2023-09-30 | $2.4m | us-gaap:IncomeTaxExpenseBenefit |
| Net income | 3 months, 2023-07-01 to 2023-09-30 | $18.5m | us-gaap:ProfitLoss |
| Net income | 9 months, 2023-01-01 to 2023-09-30 | $65.2m | us-gaap:ProfitLoss |
| Operating cash flow | 9 months, 2023-01-01 to 2023-09-30 | $115.0m | us-gaap:NetCashProvidedByUsedInOperatingActivities |
| Cash and equivalents | at 2023-09-30 | $39.5m | us-gaap:CashAndCashEquivalentsAtCarryingValue |
| Current assets | at 2023-09-30 | $105.2m | us-gaap:AssetsCurrent |
| Total assets | at 2023-09-30 | $1.39bn | us-gaap:Assets |
| Current liabilities | at 2023-09-30 | $15.1m | us-gaap:LiabilitiesCurrent |
| Total liabilities | at 2023-09-30 | $329.3m | us-gaap:Liabilities |

## Management's discussion and analysis

As filed, 74,646 characters.

*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 and the conflict in the Middle East;
- revisions to our reserve estimates as a result of changes in commodity prices, decline curves and other uncertainties;
- impact of impairment expense on our financial statements;
- competition in the oil and natural gas industry generally and the mineral and royalty industry in particular;
- the ability of the operators of our properties to obtain capital or financing needed for development and exploration operations;
- title defects in the properties in which we acquire an interest;
- the availability or cost of rigs, completion crews, equipment, raw materials, supplies, oilfield services or personnel to the operators of our properties;
- restrictions on or the availability of the use of water in the business of the operators of our properties;
- the availability of transportation facilities;
- the ability of the operators of our properties to comply with applicable governmental laws and regulations and to obtain permits and governmental approvals;
- federal and state legislative and regulatory initiatives relating to the environment, hydraulic fracturing, tax laws and other matters affecting the oil and gas industry, including the Biden administration’s proposals and recent executive orders focused on addressing climate change;
- future operating results;
- exploration and development drilling prospects, inventories, projects and programs;
- operating hazards faced by the operators of our properties;
- the ability of the operators of our properties to keep pace with technological advancements;
- uncertainties regarding United States federal income tax law, including the treatment of our future earnings and distributions; and
- our ability to maintain effective internal controls over financial reporting and disclosure controls and procedures.

These factors are discussed in further detail in the 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 September 30, 2023, we owned mineral and royalty interests in approximately 12.2 million gross acres and overriding royalty interests in approximately 4.7 million gross acres, with approximately 55% 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 September 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 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 127,000 gross wells, including over 49,000 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 September 30, 2023:

| ​ ​ ​ Basin or Producing Region | ​ ​ ​ ​ | ​ ​ ​ Gross Acreage | ​ ​ ​ ​ | ​ ​ ​ Net Acreage | ​ ​ ​ ​ | ​ Average Daily Production (Boe/d)(6:1)(1) | ​ ​ ​ ​ | ​ ​ ​ Well Count |
| --- | --- | ---: | --- | ---: | --- | ---: | --- | ---: |
| Permian Basin | ​ | 3,336,728 | ​ | 26,930 | ​ | 7,493 | ​ | 49,735 |
| Mid‑Continent |  | 5,868,927 | ​ | 48,833 | ​ | 1,887 | ​ | 20,752 |
| Terryville/Cotton Valley/Haynesville |  | 1,428,907 | ​ | 7,919 | ​ | 3,850 | ​ | 16,175 |
| Appalachian Basin | ​ | 741,354 | ​ | 23,203 | ​ | 1,744 | ​ | 3,871 |
| Bakken/Williston Basin |  | 1,640,077 | ​ | 6,138 | ​ | 927 | ​ | 5,278 |
| Eagle Ford |  | 624,148 | ​ | 6,730 | ​ | 1,884 | ​ | 4,088 |
| DJ Basin/Rockies/Niobrara |  | 74,152 | ​ | 1,036 | ​ | 775 | ​ | 12,540 |
| Other |  | 3,232,561 | ​ | 36,692 | ​ | 1,217 | ​ | 15,413 |
| Total |  | 16,946,854 | ​ | 157,481 | ​ | 19,777 | ​ | 127,852 |

(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 September 30, 2023:

| ​ Basin or Producing Region(1) | ​ ​ | ​ Gross DUCs | ​ ​ | ​ Gross Permits | ​ ​ | ​ Net DUCs | ​ ​ | ​ Net Permits |
| --- | --- | ---: | --- | ---: | --- | ---: | --- | ---: |
| Permian Basin | ​ | 551 | ​ | 469 | ​ | 3.06 | ​ | 2.38 |
| Mid‑Continent |  | 177 | ​ | 66 | ​ | 0.96 | ​ | 0.32 |
| Terryville/Cotton Valley/Haynesville |  | 83 | ​ | 24 | ​ | 0.86 | ​ | 0.34 |
| Appalachian Basin | ​ | 5 | ​ | 9 | ​ | 0.01 | ​ | 0.02 |
| Bakken/Williston Basin |  | 64 | ​ | 155 | ​ | 0.17 | ​ | 0.14 |
| Eagle Ford |  | 26 | ​ | 63 | ​ | 0.33 | ​ | 0.56 |
| DJ Basin/Rockies/Niobrara |  | 3 | ​ | 19 | ​ | 0.01 | ​ | 0.18 |
| Total |  | 909 | ​ | 805 | ​ | 5.40 | ​ | 3.94 |

(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.

On February 8, 2022, TGR completed its initial public offering. 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 September 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 units of the Operating Company (“OpCo common units”) and an equal number of Class B units representing limited partnership interests in the Partnership (“Class B Units”) and (b) 557,302 common 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 September 13, 2023, we completed the acquisition of all of the issued and outstanding membership interests of Cherry Creek Minerals LLC pursuant to a securities purchase agreement with LongPoint Minerals II, LLC (the “LongPoint Acquisition”) in a cash transaction valued at approximately $455.0 million. We funded the cash transaction with borrowings under our secured revolving credit facility and net proceeds from the Preferred Unit Transaction (as defined in Note 10—Preferred Units).

#### Series A Preferred Units

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

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

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

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

The Series A preferred units are redeemable at the option of the Series A Purchasers after seven years. The Series A preferred units may be redeemed by us at any time or in the event of a change of control. The Series A preferred units may be redeemed for a cash amount per Series A preferred unit equal to the product of (a) the number of outstanding Series A preferred units multiplied by (b) the greatest of (i) an amount (together with all prior distributions made in respect of such Series A preferred unit) necessary to achieve the Minimum IRR (as defined below), (ii) an amount (together with all prior distributions made in respect of such Series A preferred unit) necessary to achieve a return on investment equal to 1.2 times with respect to such Series A preferred unit and (iii) the Series A issue price plus accrued and unpaid distributions.

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

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

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

#### Equity Offering

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

#### Quarterly Distributions

On November 2, 2023, the General Partner’s Board of Directors (the “Board of Directors”) declared a quarterly cash distribution of $0.51 per common unit and OpCo common unit for the quarter ended September 30, 2023. We intend to pay the distributions on November 20, 2023 to common unitholders and OpCo common unitholders of record as of the close of business on November 13, 2023.

We will pay a pro-rated quarterly cash distribution on the Series A preferred units of approximately $1.0 million for the quarter ended September 30, 2023. We intend to pay the distribution subsequent to November 13, 2023 and prior to the distribution on the common units and OpCo common units.

### Business Environment

### Russia / Ukraine Conflict and Conflict in the Middle East

In February 2022, Russia invaded Ukraine and is still engaged in active armed conflict against the country. In October 2023, armed active conflict began in the Middle East and is still active These conflicts and the sanctions imposed in response have led to regional instability and caused dramatic fluctuations in global financial markets and have increased the level of global economic and political uncertainty, including uncertainty about world-wide oil supply and demand, which in turn has increased volatility in commodity prices. To date, we have not experienced a material impact to operations or the consolidated financial statements as a result of these conflicts; 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”).

| ​ ​ ​ | ​ ​ ​ | ​ ​ Nine Months Ended September 30, 2023 High | ​ | ​ ​ Low | ​ ​ ​ | ​ ​ Nine Months Ended September 30, 2022 High | ​ | ​ ​ Low |
| --- | --- | ---: | --- | ---: | --- | ---: | --- | ---: |
| Oil ($/Bbl) | ​ | $93.67 | ​ | $66.61 | ​ | $123.64 | ​ | $75.99 |
| Natural gas ($/MMBtu) | ​ | $3.78 | ​ | $1.74 | ​ | $9.85 | ​ | $3.73 |

On October 23, 2023, the West Texas Intermediate posted price for crude oil was $85.49 per Bbl and the Henry Hub spot market price of natural gas was $2.65 per MMBtu.

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

| ​ ​ ​ | ​ ​ ​ | ​ ​ Three Months Ended September 30, 2023 | ​ | ​ ​ 2022 | ​ ​ ​ | ​ ​ Nine Months Ended September 30, 2023 | ​ | ​ ​ 2022 | ​ ​ ​ |
| --- | --- | ---: | --- | ---: | --- | ---: | --- | ---: | --- |
| Oil ($/Bbl) | ​ | $82.25 | ​ | $93.06 | ​ | $77.27 | ​ | $98.96 | ​ |
| Natural gas ($/MMBtu) | ​ | $2.59 | ​ | $8.03 | ​ | $2.46 | ​ | $6.74 | ​ |

### 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 19.5% to 600 active land rigs at September 30, 2023 compared to 745 active land rigs at September 30, 2022. The 600 active land rigs at September 30, 2023 decreased by 8.1% from 653 active land rigs at June 30, 2023. The overall decrease in rig count at September 30, 2023 compared September 30, 2022 is primarily attributable to the volatility and decrease in the average daily prices for oil and natural gas.

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

| ​ ​ Basin or Producing Region | ​ ​ ​ | ​ September 30, 2023 | ​ ​ | ​ 2022 |
| --- | --- | ---: | --- | ---: |
| Permian Basin | ​ | 56 | ​ | 39 |
| Mid‑Continent | ​ | 18 | ​ | 9 |
| Terryville/Cotton Valley/Haynesville | ​ | 16 | ​ | 18 |
| Appalachian Basin | ​ | 1 | ​ | 1 |
| Bakken/Williston Basin | ​ | 5 | ​ | 4 |
| Eagle Ford | ​ | 2 | ​ | 6 |
| DJ Basin/Rockies/Niobrara | ​ | 1 | ​ | 1 |
| Other | ​ | — | ​ | 1 |
| Total | ​ | 99 | ​ | 79 |

### 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:

| ​ ​ ​ Revenue | ​ ​ ​ ​ | ​ ​ Three Months Ended September 30, 2023 ​ ​ | ​ ​ | ​ ​ 2022 ​ ​ | ​ ​ ​ ​ | ​ ​ Nine Months Ended September 30, 2023 ​ ​ | ​ ​ | ​ ​ 2022 ​ ​ |
| --- | --- | ---: | --- | ---: | --- | ---: | --- | ---: |
| Oil revenue | ​ | 73% | ​ | 43% | ​ | 67% | ​ | 46% |
| Natural gas revenue | ​ | 18% | ​ | 48% | ​ | 24% | ​ | 43% |
| NGL revenue | ​ | 9% | ​ | 9% | ​ | 9% | ​ | 11% |
| ​ | ​ | 100% | ​ | 100% | ​ | 100% | ​ | 100% |

We have entered into oil and natural gas commodity derivative agreements, which extend through September 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.

### 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.

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).

| ​ ​ ​ Reconciliation of net income to Adjusted EBITDA and cash available for distribution on common units: | ​ ​ ​ ​ | ​ ​ Three Months Ended September 30, 2023 ​ ​ | ​ ​ ​ | ​ ​ 2022 ​ ​ | ​ ​ ​ ​ | ​ ​ Nine Months Ended September 30, 2023 ​ ​ | ​ ​ ​ | ​ ​ 2022 ​ ​ |
| --- | --- | --- | --- | --- | --- | --- | --- | --- |
| Net income | ​ | $18,481,038 | ​ | $43,845,114 | ​ | $65,177,607 | ​ | $95,546,524 |
| Depreciation and depletion expense | ​ | ​ 23,060,163 | ​ | 11,326,791 | ​ | ​ 60,280,666 | ​ | ​ 33,359,915 |
| Interest expense | ​ | ​ 6,680,661 | ​ | 3,667,534 | ​ | ​ 18,485,183 | ​ | ​ 9,868,679 |
| Cash distribution from affiliate | ​ | ​ — | ​ | ​ — | ​ | ​ — | ​ | ​ 385,326 |
| Income tax expense (benefit) | ​ | ​ 128,359 | ​ | ​ (224,883) | ​ | ​ 2,440,399 | ​ | ​ 1,850,357 |
| EBITDA | ​ | ​ 48,350,221 | ​ | 58,614,556 | ​ | ​ 146,383,855 | ​ | ​ 141,010,801 |
| Unit-based compensation | ​ | ​ 3,325,891 | ​ | 2,981,903 | ​ | ​ 9,785,631 | ​ | ​ 8,125,736 |
| Loss on extinguishment of debt | ​ | ​ — | ​ | — | ​ | ​ 480,244 | ​ | ​ — |
| Loss (gain) on derivative instruments, net of settlements | ​ | ​ 4,097,565 | ​ | ​ (13,388,100) | ​ | ​ (11,002,749) | ​ | ​ (1,271,103) |
| Cash distribution from affiliate | ​ | ​ — | ​ | ​ — | ​ | ​ — | ​ | ​ 473,812 |
| Equity income in affiliate | ​ | ​ — | ​ | ​ (23,727) | ​ | ​ — | ​ | ​ (3,658,460) |
| Consolidated variable interest entities related: | ​ | ​ ​ | ​ | ​ ​ | ​ | ​ ​ | ​ | ​ ​ |
| Interest earned on marketable securities in trust account | ​ | ​ — | ​ | ​ (1,188,256) | ​ | ​ (3,508,691) | ​ | ​ (1,512,777) |
| General and administrative expense | ​ | ​ — | ​ | ​ 527,634 | ​ | ​ 927,699 | ​ | ​ 1,857,593 |
| Consolidated Adjusted EBITDA | ​ | ​ 55,773,677 | ​ | ​ 47,524,010 | ​ | ​ 143,065,989 | ​ | ​ 145,025,602 |
| Adjusted EBITDA attributable to non-controlling interest | ​ | ​ (12,278,201) | ​ | ​ (5,954,026) | ​ | ​ (31,287,102) | ​ | ​ (18,187,707) |
| Adjusted EBITDA attributable to Kimbell Royalty Partners, LP | ​ | ​ 43,495,476 | ​ | ​ 41,569,984 | ​ | ​ 111,778,887 | ​ | ​ 126,837,895 |
| Adjustments to reconcile Adjusted EBITDA to cash available for distribution | ​ | ​ ​ | ​ | ​ ​ | ​ | ​ ​ | ​ | ​ ​ |
| Cash interest expense | ​ | ​ 4,645,744 | ​ | ​ 2,624,190 | ​ | ​ 13,211,771 | ​ | ​ 7,024,551 |
| Cash distributions on Series A preferred units | ​ | ​ 749,945 | ​ | ​ — | ​ | ​ 749,945 | ​ | ​ — |
| Cash income tax expense (refund) | ​ | ​ — | ​ | ​ 1,024,000 | ​ | ​ (639,325) | ​ | ​ 3,067,374 |
| Distributions on Class B units | ​ | ​ 20,854 | ​ | ​ 8,211 | ​ | ​ 67,939 | ​ | ​ 34,032 |
| Cash available for distribution on common units | ​ | $38,078,933 | ​ | $37,913,583 | ​ | $98,388,557 | ​ | $116,711,938 |

| ​ ​ ​ Reconciliation of net cash provided by operating activities to Adjusted EBITDA and cash available for distribution on common units: | ​ ​ ​ ​ | ​ ​ Three Months Ended September 30, 2023 ​ ​ | ​ ​ ​ | ​ ​ 2022 ​ ​ | ​ ​ ​ ​ | ​ ​ Nine Months Ended September 30, 2023 ​ ​ | ​ ​ ​ | ​ ​ 2022 ​ ​ |
| --- | --- | --- | --- | --- | --- | --- | --- | --- |
| Net cash provided by operating activities | ​ | $36,386,578 | ​ | $51,550,250 | ​ | $114,958,713 | ​ | $128,005,890 |
| Interest expense | ​ | 6,680,661 | ​ | 3,667,534 | ​ | 18,485,183 | ​ | 9,868,679 |
| Income tax expense (benefit) | ​ | ​ 128,359 | ​ | ​ (224,883) | ​ | ​ 2,440,399 | ​ | ​ 1,850,357 |
| Amortization of right-of-use assets | ​ | ​ (83,517) | ​ | ​ (80,541) | ​ | ​ (251,175) | ​ | (237,839) |
| Amortization of loan origination costs | ​ | (405,244) | ​ | (480,057) | ​ | (1,414,074) | ​ | (1,381,717) |
| Loss on extinguishment of debt | ​ | ​ — | ​ | ​ — | ​ | ​ (480,244) | ​ | ​ — |
| Equity income in affiliate, net | ​ | — | ​ | 23,727 | ​ | — | ​ | 273,135 |
| Forfeiture of restricted units | ​ | ​ — | ​ | ​ — | ​ | ​ — | ​ | ​ 19,813 |
| Unit-based compensation | ​ | (3,325,891) | ​ | (2,981,903) | ​ | (9,785,631) | ​ | (8,125,736) |
| (Loss) gain on derivative instruments, net of settlements | ​ | ​ (4,097,565) | ​ | 13,388,100 | ​ | 11,002,749 | ​ | 1,271,103 |
| Changes in operating assets and liabilities: | ​ | ​ ​ | ​ | ​ ​ | ​ | ​ ​ | ​ | ​ ​ |
| Oil, natural gas and NGL receivables | ​ | 16,313,898 | ​ | (7,208,042) | ​ | 14,326,575 | ​ | 11,240,327 |
| Accounts receivable and other current assets | ​ | (280,154) | ​ | 450,477 | ​ | (707,259) | ​ | (455,642) |
| Accounts payable | ​ | (854,707) | ​ | 678,811 | ​ | (1,014,264) | ​ | (63,161) |
| Other current liabilities | ​ | (2,200,296) | ​ | (1,240,468) | ​ | (5,631,591) | ​ | (3,099,504) |
| Operating lease liabilities | ​ | ​ 88,099 | ​ | ​ 81,597 | ​ | ​ 258,430 | ​ | 241,314 |
| Consolidated variable interest entities related: | ​ | ​ ​ | ​ | ​ ​ | ​ | ​ ​ | ​ | ​ ​ |
| Interest earned on marketable securities in trust account | ​ | ​ — | ​ | ​ 1,188,256 | ​ | ​ 3,508,691 | ​ | 1,512,777 |
| Other assets and liabilities | ​ | ​ — | ​ | ​ (198,302) | ​ | ​ 687,353 | ​ | 91,005 |
| EBITDA | ​ | ​ 48,350,221 | ​ | ​ 58,614,556 | ​ | ​ 146,383,855 | ​ | ​ 141,010,801 |
| Add: | ​ | ​ ​ | ​ | ​ ​ | ​ | ​ ​ | ​ | ​ ​ |
| Unit-based compensation | ​ | 3,325,891 | ​ | 2,981,903 | ​ | 9,785,631 | ​ | 8,125,736 |
| Loss on extinguishment of debt | ​ | ​ — | ​ | — | ​ | 480,244 | ​ | — |
| Loss (gain) on derivative instruments, net of settlements | ​ | 4,097,565 | ​ | (13,388,100) | ​ | (11,002,749) | ​ | (1,271,103) |
| Cash distribution from affiliate | ​ | ​ — | ​ | ​ — | ​ | ​ — | ​ | ​ 473,812 |
| Equity income in affiliate | ​ | ​ — | ​ | ​ (23,727) | ​ | ​ — | ​ | ​ (3,658,460) |
| Consolidated variable interest entities related: | ​ | ​ ​ | ​ | ​ ​ | ​ | ​ ​ | ​ | ​ ​ |
| Interest earned on marketable securities in Trust Account | ​ | ​ — | ​ | ​ (1,188,256) | ​ | ​ (3,508,691) | ​ | ​ (1,512,777) |
| General and administrative expense | ​ | ​ — | ​ | ​ 527,634 | ​ | ​ 927,699 | ​ | ​ 1,857,593 |
| Consolidated Adjusted EBITDA | ​ | ​ 55,773,677 | ​ | ​ 47,524,010 | ​ | ​ 143,065,989 | ​ | ​ 145,025,602 |
| Adjusted EBITDA attributable to non-controlling interest | ​ | ​ (12,278,201) | ​ | ​ (5,954,026) | ​ | ​ (31,287,102) | ​ | ​ (18,187,707) |
| Adjusted EBITDA attributable to Kimbell Royalty Partners, LP | ​ | ​ 43,495,476 | ​ | ​ 41,569,984 | ​ | ​ 111,778,887 | ​ | ​ 126,837,895 |
| Adjustments to reconcile Adjusted EBITDA to cash available for distribution | ​ | ​ ​ | ​ | ​ ​ | ​ | ​ ​ | ​ | ​ ​ |
| Cash interest expense | ​ | ​ 4,645,744 | ​ | ​ 2,624,190 | ​ | ​ 13,211,771 | ​ | ​ 7,024,551 |
| Cash distributions on Series A preferred units | ​ | ​ 749,945 | ​ | ​ — | ​ | ​ 749,945 | ​ | ​ — |
| Cash income tax expense (refund) | ​ | ​ — | ​ | ​ 1,024,000 | ​ | ​ (639,325) | ​ | ​ 3,067,374 |
| Distributions on Class B units | ​ | ​ 20,854 | ​ | ​ 8,211 | ​ | ​ 67,939 | ​ | ​ 34,032 |
| Cash available for distribution on common units | ​ | $38,078,933 | ​ | $37,913,583 | ​ | $98,388,557 | ​ | $116,711,938 |

### 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 nine months ended September 30, 2023 and 2022 include the acquisition of certain mineral and royalty assets held by Hatch Royalty LLC (the “Hatch Acquisition”), the MB Minerals Acquisition and the LongPoint 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 standards 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 nine months ended September 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.

### Results of Operations

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

| ​ ​ ​ Operating Results: Revenue | ​ ​ ​ ​ | ​ ​ Three Months Ended September 30, 2023 ​ ​ ​ ​ | ​ ​ ​ ​ | ​ ​ 2022 ​ ​ ​ ​ | ​ ​ ​ ​ ​ | ​ ​ Nine Months Ended September 30, 2023 ​ ​ ​ ​ | ​ ​ ​ ​ | ​ ​ 2022 ​ ​ ​ ​ |
| --- | --- | --- | --- | --- | --- | --- | --- | ---: |
| Oil, natural gas and NGL revenues | ​ | $69,237,603 | ​ | $73,867,992 | ​ | $183,635,976 | ​ | $217,543,364 |
| Lease bonus and other income | ​ | ​ 2,543,240 | ​ | ​ 171,702 | ​ | ​ 5,021,766 | ​ | ​ 2,039,154 |
| (Loss) gain on commodity derivative instruments, net | ​ | ​ (4,576,570) | ​ | ​ (1,116,722) | ​ | ​ 6,215,265 | ​ | ​ (40,194,369) |
| Total revenues | ​ | ​ 67,204,273 | ​ | ​ 72,922,972 | ​ | ​ 194,873,007 | ​ | ​ 179,388,149 |
| Costs and expenses | ​ | ​ ​ | ​ | ​ ​ | ​ | ​ ​ | ​ | ​ ​ |
| Production and ad valorem taxes | ​ | 4,986,878 | ​ | 4,518,580 | ​ | 14,669,037 | ​ | 13,542,285 |
| Depreciation and depletion expense | ​ | 23,060,163 | ​ | 11,326,791 | ​ | 60,280,666 | ​ | 33,359,915 |
| Marketing and other deductions | ​ | 3,508,500 | ​ | 3,068,244 | ​ | 9,177,998 | ​ | 10,639,314 |
| General and administrative expenses | ​ | 10,358,674 | ​ | 7,482,814 | ​ | 26,562,100 | ​ | 21,938,249 |
| Consolidated variable interest entities related: | ​ | ​ ​ | ​ | ​ ​ | ​ | ​ ​ | ​ | ​ ​ |
| General and administrative expense | ​ | ​ — | ​ | ​ 527,634 | ​ | ​ 927,699 | ​ | 1,857,593 |
| Total costs and expenses | ​ | 41,914,215 | ​ | 26,924,063 | ​ | 111,617,500 | ​ | 81,337,356 |
| Operating income | ​ | 25,290,058 | ​ | 45,998,909 | ​ | 83,255,507 | ​ | 98,050,793 |
| Other income (expense) | ​ | ​ ​ | ​ | ​ ​ | ​ | ​ ​ | ​ | ​ ​ |
| Equity income in affiliate | ​ | ​ — | ​ | ​ 23,727 | ​ | ​ — | ​ | ​ 3,658,460 |
| Interest expense | ​ | (6,680,661) | ​ | (3,667,534) | ​ | (18,485,183) | ​ | (9,868,679) |
| Loss on extinguishment of debt | ​ | ​ — | ​ | — | ​ | (480,244) | ​ | — |
| Other income (expense) | ​ | ​ — | ​ | 76,873 | ​ | (180,765) | ​ | 4,043,530 |
| Consolidated variable interest entities related: | ​ | ​ ​ | ​ | ​ ​ | ​ | ​ ​ | ​ | ​ ​ |
| Interest earned on marketable securities in trust account | ​ | ​ — | ​ | ​ 1,188,256 | ​ | ​ 3,508,691 | ​ | 1,512,777 |
| Net income before income taxes | ​ | ​ 18,609,397 | ​ | ​ 43,620,231 | ​ | ​ 67,618,006 | ​ | ​ 97,396,881 |
| Income tax expense (benefit) | ​ | ​ 128,359 | ​ | ​ (224,883) | ​ | ​ 2,440,399 | ​ | ​ 1,850,357 |
| Net income | ​ | ​ 18,481,038 | ​ | ​ 43,845,114 | ​ | ​ 65,177,607 | ​ | ​ 95,546,524 |
| Distribution and accretion on Series A preferred units | ​ | ​ (1,040,572) | ​ | ​ — | ​ | ​ (1,040,572) | ​ | ​ — |
| Net income attributable to non-controlling interests in OpCo | ​ | ​ (3,839,401) | ​ | ​ (5,493,117) | ​ | ​ (13,700,261) | ​ | ​ (11,975,886) |
| Distribution on Class B units | ​ | ​ (20,854) | ​ | ​ (8,211) | ​ | ​ (67,939) | ​ | ​ (34,032) |
| Net income attributable to common units of Kimbell Royalty Partners, LP | ​ | $13,580,211 | ​ | $38,343,786 | ​ | $50,368,835 | ​ | $83,536,606 |
| **Production Data:** | ​ | ​ ​ | ​ | ​ ​ | ​ | ​ ​ | ​ | ​ ​ |
| Oil (Bbls) | ​ | 622,831 | ​ | 345,867 | ​ | 1,622,432 | ​ | 1,058,423 |
| Natural gas (Mcf) | ​ | 5,589,952 | ​ | 5,130,753 | ​ | 16,384,109 | ​ | 15,146,635 |
| Natural gas liquids (Bbls) | ​ | 264,967 | ​ | 177,651 | ​ | 697,913 | ​ | 558,806 |
| Combined volumes (Boe) (6:1) | ​ | 1,819,457 | ​ | 1,378,644 | ​ | 5,051,030 | ​ | 4,141,668 |

### Comparison of the Three Months Ended September 30, 2023 to the Three Months Ended September 30, 2022

### Oil, Natural Gas and NGL Revenues

For the three months ended September 30, 2023, our oil, natural gas and NGL revenues were $69.2 million, a decrease of $4.7 million from $73.9 million for the three months ended September 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 September 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 1,819,457 Boe or 19,777 Boe/d, for the three months ended September 30, 2023, an increase of 440,813 Boe or 4,792 Boe/d, from 1,378,644 Boe or 14,985 Boe/d, for the three months ended September 30, 2022. The increase in production for the three months ended September 30, 2023 was primarily attributable to production associated with the Hatch Acquisition and the MB Minerals Acquisition, and to a lesser extent, production associated with the LongPoint Acquisition.

Our operators received an average of $81.53 per Bbl of oil, $2.21 per Mcf of natural gas and $23.10 per Bbl of NGL for the volumes sold during the three months ended September 30, 2023 compared to $92.65 per Bbl of oil, $6.92 per Mcf of natural gas and $35.50 per Bbl of NGL for the volumes sold during the three months ended September 30, 2022. These average prices received during the three months ended September 30, 2023 decreased 12.0% or $11.12 per Bbl of oil and 68.1% or $4.71 per Mcf of natural gas as compared to the three months ended September 30, 2022. This change is consistent with prices experienced in the market, specifically when compared to the EIA average price decreases of 11.6% or $10.81 per Bbl of oil and 67.7% or $5.44 per Mcf of natural gas for the comparable periods.

### Lease Bonus and Other Income

Lease bonus and other income was $2.5 million for the three months ended September 30, 2023 compared to $0.2 million for the three months ended September 30, 2022. The $2.3 million increase in lease bonus and other income was primarily related to a legal settlement received during the three months ended September 30, 2023.

### Loss on Commodity Derivative Instruments

Loss on commodity derivative instruments for the three months ended September 30, 2023 included $4.1 million of mark-to-market losses and $0.5 million of losses on the settlement of commodity derivative instruments compared to $16.7 million of mark-to-market gains and $17.8 million of losses on the settlement of commodity derivative instruments for the three months ended September 30, 2022. We recorded a mark-to-market loss for the three months ended September 30, 2023 as a result of the increase in strip pricing from the three months ended June 30, 2023. We recorded a mark-to-market gain for the three months ended September 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 September 30, 2023 were $5.0 million, an increase of $0.5 million from $4.5 million for the three months ended September 30, 2022. The increase in production and ad valorem taxes was primarily attributable to the Hatch Acquisition and the MB Minerals Acquisition, and to a lesser extent, and the LongPoint 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 September 30, 2023 was $23.1 million, an increase of $11.8 million from $11.3 million for the three months ended September 30, 2022. The increase in depreciation and depletion expense was due to the Hatch Acquisition, the MB Minerals Acquisition and the LongPoint 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 $12.62 for the three months ended September 30, 2023, an increase of $4.56 per barrel from the $8.06 average depletion rate per barrel for the three months ended September 30, 2022. The increase in the depletion rate was due to the Hatch Acquisition, the MB Minerals Acquisition and the LongPoint 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 three months ended September 30, 2023 were $3.5 million, a decrease of $0.4 million from $3.1 million for the three months ended September 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 September 30, 2023, partially offset by marketing and other deductions associated with the Hatch Acquisition, the MB Minerals Acquisition and the LongPoint Acquisition.

### General and Administrative Expenses

General and administrative expenses for the three months ended September 30, 2023 were $10.4 million an increase of $2.9 million from $7.5 million for the three months ended September 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 $0.3 million increase in unit-based compensation expense, expenses related to a one-time cash bonus paid to employees 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 ended September 30, 2023 was $6.7 million compared to $3.7 million for the three months ended September 30, 2022. The increase in interest expense was primarily due to a 3.1% increase in the weighted average interest rate on the Partnership’s outstanding borrowings for the three months ended September 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, the MB Minerals Acquisition and the LongPoint Acquisition.

### Income Tax Expense

We recorded an income tax expense of $0.1 million for the three months ended September 30, 2023. The income tax expense recorded during the three months ended September 30, 2023 was due to a change in the estimated income tax expense for the year ended December 31, 2023. We recorded a benefit from income taxes of $0.2 million for the three months ended September 30, 2022. The benefit from income taxes recorded during the three months ended September 30, 2022 was due to a change in the estimated income tax expense for the year ended December 31, 2022.

### Comparison of the Nine Months Ended September 30, 2023 to the Nine Months Ended September 30, 2022

### Oil, Natural Gas and NGL Revenues

For the nine months ended September 30, 2023, our oil, natural gas and NGL revenues were $183.6 million, a decrease of $33.9 million from $217.5 million for the nine months ended September 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 nine months ended September 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 5,051,030 Boe or 18,523 Boe/d, for the nine months ended September 30, 2023, an increase of 909,362 Boe or 3,654 Boe/d, from 4,141,668 Boe or 14,869 Boe/d, for the nine months ended September 30, 2022. The increase in production for the nine months ended September 30, 2023 was primarily attributable to production associated with the Hatch Acquisition and the MB Minerals Acquisition, and to a lesser extent, production associated with the LongPoint Acquisition.

Our operators received an average of $76.17 per Bbl of oil, $2.66 per Mcf of natural gas and $23.67 per Bbl of NGL for the volumes sold during the nine months ended September 30, 2023 compared to $94.84 per Bbl of oil, $6.23 per Mcf of natural gas and $40.71 per Bbl of NGL for the volumes sold during the nine months ended September 30, 2022. These average prices received during the nine months ended September 30, 2023 decreased 19.7% or $18.67 per Bbl of oil and 57.3% or 3.57 per Mcf of natural gas as compared to the nine months ended September 30, 2022. This change is consistent with prices experienced in the market, specifically when compared to the EIA average price decreases of 21.9% or $21.69 per Bbl of oil and 63.5% or $4.28 per Mcf of natural gas for the comparable periods.

### Lease Bonus and Other Income

Lease bonus and other income was $5.0 million for the nine months ended September 30, 2023 compared to $2.0 million for the nine months ended September 30, 2022. The increase in lease bonus and other income is primarily related to legal settlements received during the nine months ended September 30, 2023.

### Gain (Loss) on Commodity Derivative Instruments

Gain on commodity derivative instruments for the nine months ended September 30, 2023 included $11.0 million of mark-to-market gains and $4.8 million of losses on the settlement of commodity derivative instruments compared to $3.0 million of mark-to-market losses and $43.2 million of losses on the settlement of commodity derivative instruments for the nine months ended September 30, 2022. We recorded a mark-to-market gain for the nine months ended September 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 nine months ended September 30, 2022 as a result of the increase in the strip pricing of oil and natural gas from December 31, 2021.

### Production and Ad Valorem Taxes

Production and ad valorem taxes for the nine months ended September 30, 2023 were $14.7 million, an increase of $1.2 million from $13.5 million for the nine months ended September 30, 2022. The increase in production and ad valorem taxes was primarily attributable to the Hatch Acquisition and the MB Minerals Acquisition, and to a lesser extent, the LongPoint Acquisition. The increase was 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 nine months ended September 30, 2023 was $60.3 million, an increase of $26.9 million from $33.4 million for the nine months ended September 30, 2022. The increase in depreciation and depletion expense was due to the Hatch Acquisition, the MB Minerals Acquisition and the LongPoint 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 $11.88 for the nine months ended September 30, 2023, an increase of $4.04 per barrel from the $7.84 average depletion rate per barrel for the nine months ended September 30, 2022. The increase in the depletion rate was due to the Hatch Acquisition, the MB Minerals Acquisition and the LongPoint 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 nine months ended September 30, 2023 were $9.2 million, a decrease of $1.4 million from $10.6 million for the nine months ended September 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 nine months ended September 30, 2023, partially offset by marketing and other deductions associated with the Hatch Acquisition and the MB Minerals Acquisition, and to a lesser extent, the LongPoint Acquisition.

### General and Administrative Expenses

General and administrative expenses for the nine months ended September 30, 2023 were $26.6 million, an increase of $4.7 million from $21.9 million for the nine months ended September 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 $1.7 million increase in unit-based compensation expense, expenses related to a one-time cash bonus paid to employees and cash general and administrative expenses resulting from an increase in our costs associated with company growth.

### Interest Expense

Interest expense for the nine months ended September 30, 2023 was $18.5 million compared to $9.9 million for the nine months ended September 30, 2022. The increase in interest expense was primarily due to a 3.8% increase in the weighted average interest rate on the Partnership’s outstanding borrowings for the nine months ended September 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, the MB Minerals Acquisition and The LongPoint.

### Income Tax Expense

We recorded an income tax expense of $2.4 million for the nine months ended September 30, 2023. The income tax expense recorded during the nine months ended September 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 $1.9 million for the nine months ended September 30, 2022. The income tax expense recorded during the nine months ended September 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. On June 13, 2023, we entered into the A&R Credit Agreement (as defined below). On July 24, 2023, we entered into the First Amendment (as defined below) to the A&R Credit Agreement that, 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. 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 third quarter of 2023 for the repayment of $16.2 million in outstanding borrowings under our secured revolving credit facility during its determination of “available cash” for the third 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, 5,369,218 OpCo common units and an equal number of Class B units and 557,302 common units as partial consideration in connection with the MB Minerals Acquisition and we completed the LongPoint Acquisition partially with net proceeds from the Preferred Unit Transaction. 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 third quarter 2023 distributions.

### Cash Flows

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

| ​ ​ ​ Cash Flow Data: | ​ ​ ​ ​ | ​ ​ Nine Months Ended September 30, 2023 ​ ​ | ​ ​ | ​ ​ 2022 ​ ​ |
| --- | --- | ---: | --- | ---: |
| Net cash provided by operating activities | ​ | $114,958,713 | ​ | $128,005,890 |
| Net cash used in investing activities | ​ | (246,113,134) | ​ | (233,997,215) |
| Net cash provided by financing activities | ​ | 145,656,712 | ​ | 116,045,612 |
| Net increase in cash and cash equivalents | ​ | $14,502,291 | ​ | $10,054,287 |

#### 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 nine months ended September 30, 2023 were $115.0 million, a decrease of $13.0 million compared to $128.0 million for the nine months ended September 30, 2022.

#### Investing Activities

Cash flows used in investing activities for the nine months ended September 30, 2023 were $246.1 million compared to $234.0 million for the nine months ended September 30, 2022. For the nine months ended September 30, 2023, cash flows used in investing activities included $490.1 million used to fund costs associated with the MB Minerals Acquisition and the LongPoint Acquisition and $0.1 million used to fund the purchase of equipment, partially offset by $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.

For the nine months ended September 30, 2022, cash flows used in investing activities include $236.9 million of investments held in marketable securities related to TGR, $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 and $0.1 million used to fund the purchase of equipment, 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 provided by financing activities were $145.7 million for the nine months ended September 30, 2023 compared to $116.0 million for the nine months September 30, 2022. Cash flows used in financing activities for the nine months ended September 30, 2023 consists of $314.0 million in net proceeds from the issuance of Series A preferred units, $201.1 million of additional borrowings under our secured revolving credit facility, $110.7 million in proceeds from the 2023 Equity Offering, and $0.3 million in Class B contributions, partially offset by $243.2 million of distributions to common unitholders of TGR, $123.7 million used to repay borrowings under our secured revolving credit facility, $103.7 million of distributions paid to holders of common units, OpCo common units and Class B units, $4.9 million of restricted units repurchased for tax withholding and a $4.9 million payment of loan origination costs.

Cash flows provided by financing activities for the nine months ended September 30, 2022 consists of $227.6 million in proceeds from the initial public offering of TGR and $43.2 million of additional borrowings under our secured revolving credit facility, partially offset by $91.1 million of distributions paid to holders of common units, OpCo common units and Class B units, $56.4 million used to repay borrowings under out secured revolving credit facility, $3.3 million of restricted units repurchased 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 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). 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.

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.

As of September 30, 2023, we had outstanding borrowings of $310.4 million under the secured revolving credit facility and $89.6 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.

### 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 September 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.

## Market risk

As filed, 4,170 characters.

### 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 September 30, 2023, we had five counterparties to our derivative contracts, four of which are also lenders under our secured revolving credit facility.

As an owner of mineral and royalty interests, we have no control over the volumes or method of sale of oil, natural gas and NGLs produced and sold from the underlying properties. It is believed that the loss of any single purchaser would not have a material adverse effect on our results of operations.

### Interest Rate Risk

We will have exposure to changes in interest rates on our indebtedness. As of September 30,2023, we had total borrowings outstanding under our secured revolving credit facility of $310.4 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 $3.1 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 September 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.

## Controls and procedures

As filed, 2,124 characters.

### 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 September 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 September 30, 2023 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

## Risk factors

As filed, 5,062 characters.

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 and the risk factors listed below, 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 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.

***Our Series A preferred units have rights, preferences and privileges that are not held by, and are preferential to the rights of, holders of our common units.***

On September 13, 2023, we issued 325,000 preferred units representing limited partner interests in the Partnership. The Series A preferred units rank senior to our common units with respect to distribution rights and rights upon liquidation. These preferences could adversely affect the market price for our common units or could make it more difficult for us to sell our common units in the future.

Until the conversion of the Series A preferred units into common units or their redemption, holders of the Series A preferred units are entitled to receive cumulative quarterly distributions equal to 6.0% per annum plus accrued and unpaid distributions. We have the right, in any four non-consecutive quarters, to elect not to pay such quarterly distribution in cash and instead have the unpaid distribution amount added to the liquidation preference at the rate of 10.0% per annum. If we make such an election in consecutive quarters or if we fail to pay in full, in cash and when due, any distribution owed to the Series A preferred units or otherwise materially breach our obligations to the holders of the Series A preferred units, the distribution rate will increase to 20.0% per annum until the accumulated distributions are paid in full in cash, or any such material breach is cured, as applicable. Each holder of Series A preferred units has the right to share in any special distributions by us of cash, securities or other property pro rata with the common units on an as-converted basis, subject to customary adjustments. We cannot declare or make any distributions, redemptions, or repurchases on any junior securities, including any of our common units, prior to paying the quarterly distribution payable to the Series A preferred units, including any previously accrued and unpaid distributions. Our obligation to pay distributions on our Series A preferred units could impact our liquidity and reduce the amount of cash flow available for working capital, capital expenditures, growth opportunities, acquisitions and other general partnership purposes. Our obligations to the holders of the Series A preferred units could also limit our ability to obtain additional financing or increase our borrowing costs, which could have an adverse effect on our financial condition.

***The terms of our Series A preferred units contain covenants that may limit our business flexibility.***

The terms of our Series A preferred units contain covenants preventing us from taking certain actions without the approval of the holders of 662/3% of the outstanding Series A preferred units, voting separately as a class. The need to obtain the approval of holders of the Series A preferred units before taking these actions could impede our ability to take certain actions that management or our board of directors may consider to be in the best interests of our common unitholders.

The affirmative vote of 662/3% of the outstanding Series A preferred units, voting separately as a class, will be necessary to amend our partnership agreement in any manner that is materially adverse to any of the rights, preferences and privileges of the Series A preferred units. The affirmative vote of 662/3% of the outstanding Series A preferred units voting separately as a class, will be necessary to, among other things, (i) issue, authorize or create any additional Series A preferred units or any class or series of partnership interests (or any obligation or security convertible into, exchangeable for or evidencing the right to purchase any class or series of partnership interests) that, with respect to distributions on such partnership interests or distributions in respect of such partnership interests upon our liquidation, dissolution and winding up, ranks equal to or senior to the Series A preferred units or (ii) under certain circumstances, incur certain indebtedness for borrowed money.

Filed Nov 2, 2023.
Source: SEC EDGAR, the filing index for accession 0001558370-23-017410. Last ingested by Listed: Oct 24, 2026, 15:15 ET. No prices; not investment advice.