SEC Form 10-Q filed by TXO Partners L.P.

5/1/25 4:14:33 PM ET

$TXO

Oil & Gas Production

Energy

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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)


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

For the quarterly period ended March 31, 2025


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

For the transition period from ______ to ______

Commission file number 001-04321

TXO Partners, L.P.

(Exact name of registrant as specified in its charter)


Delaware			32-0368858
(State or other jurisdiction of incorporation or organization)			(I.R.S. Employer Identification No.)

400 West 7th Street, Fort Worth, Texas			76102
(Address of Principal Executive Offices)			(Zip Code)

(817) 334-7800

(Registrant's telephone number, including area code)

Securities registered pursuant to Section 12(b) of the Act:


Title of each class	Trading Symbol(s)	Name of each exchange on which registered
Common Units	TXO	New York Stock Exchange

Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports); and (2) has been subject to such filing requirements for the past 90 days. Yes x No o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes x No o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):


Large accelerated filer	o	Accelerated filer	x
Non-accelerated filer	o	Smaller reporting company	o
		Emerging growth company	x

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes o No x

The registrant had outstanding 41,367,625 common units as of May 1, 2025.

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TABLE OF CONTENTS


			Page
Part I - Financial Information
Item 1. Financial Statements			1
Consolidated Balance Sheets			1
Consolidated Statements of Operations			2
Consolidated Statements of Cash Flows			3
Consolidated Statements of Partners’ Capital			4
Notes to Financial Statements			5
Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations			17
Item 3. Quantitative and Qualitative Disclosures About Market Risk			28
Item 4. Controls and Procedures			29

Part II - Other Information
Item 1. Legal Proceedings			31
Item 1A. Risk Factors			31
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds			31
Item 3. Defaults Upon Senior Securities			31
Item 4. Mine Safety Disclosures			31
Item 5. Other Information			31
Item 6. Exhibits			32
Signatures			33

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Part I - Financial Information

Item 1. Financial Statements


TXO PARTNERS, L.P. Consolidated Balance Sheets

(in thousands)


	March 31, 2025		December 31, 2024
	(Unaudited)
ASSETS
Current Assets:
Cash and cash equivalents	$	10,842	$	7,305
Accounts receivable, net	38,485		39,689
Derivative fair value	18,849		6,412
Other	13,404		11,041
Total Current Assets	81,580		64,447
Property and Equipment, at cost – successful efforts method:
Proved properties	1,918,025		1,912,624
Unproved properties	18,759		18,706
Other	85,608		85,425
Total Property and Equipment	2,022,392		2,016,755
Accumulated depreciation, depletion and amortization	(1,086,727)		(1,065,364)
Net Property and Equipment	935,665		951,391
Other Assets:
Note receivable from related party	7,131		7,131
Derivative fair value	2,289		2,065
Other	6,640		5,807
Total Other Assets	16,060		15,003
TOTAL ASSETS	$	1,033,305	$	1,030,841
LIABILITIES AND PARTNERS’ CAPITAL
Current Liabilities:
Accounts payable	$	19,782	$	18,217
Accrued liabilities	31,743		38,927
Derivative fair value	25,632		5,846
Asset retirement obligation, current portion	3,000		2,000
Other current liabilities	1,795		1,347
Total Current Liabilities	81,952		66,337

Long-term Debt	162,100		157,100
Other Liabilities:
Asset retirement obligation	190,393		188,904
Derivative fair value	8,489		8,022
Other liabilities	1,638		1,062
Total Other Liabilities	200,520		197,988
Commitments and Contingencies
Partners’ Capital:
Partners’ capital	588,733		609,416
TOTAL LIABILITIES AND PARTNERS’ CAPITAL	$	1,033,305	$	1,030,841

See accompanying notes to the Consolidated Financial Statements

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TXO PARTNERS, L.P. Consolidated Statements of Operations (Unaudited)

(in thousands)


	Three months ended March 31,
	2025		2024
REVENUES
Oil and condensate	$	64,995	$	38,034
Natural gas liquids	8,562		6,502
Natural gas	10,768		22,903
Total Revenues	84,325		67,439
EXPENSES
Production	42,271		33,083
Exploration	73		123
Taxes, transportation and other	17,881		15,573
Depreciation, depletion and amortization	21,429		10,517
Accretion of discount in asset retirement obligation	3,813		2,784
General and administrative	2,441		2,654
Total Expenses	87,908		64,734
OPERATING (LOSS) INCOME	(3,583)		2,705
OTHER INCOME (EXPENSE)
Other income	9,517		8,413
Interest income	103		125
Interest expense	(3,621)		(976)
Total Other Income	5,999		7,562
NET INCOME	$	2,416	$	10,267

NET INCOME PER COMMON UNIT
Basic	$0.06		$0.33
Diluted	$0.06		$0.33

WEIGHTED AVERAGE COMMON UNITS OUTSTANDING
Basic	41,083		30,800
Diluted	41,814		31,425

See accompanying notes to the Consolidated Financial Statements

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TXO PARTNERS, L.P. Consolidated Statements of Cash Flows (Unaudited)

(in thousands)


	Three months ended March 31,
	2025		2024
OPERATING ACTIVITIES
Net income	$	2,416	$	10,267
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization	21,429		10,517
Accretion of discount in asset retirement obligation	3,813		2,784
Derivative fair value (gain) loss	9,487		1,054
Net cash paid to derivative counterparties	(1,896)		(396)
Non-cash incentive compensation	2,131		1,141
Other non-cash items	258		241
Changes in operating assets and liabilities (a)	(7,028)		(411)
Cash Provided by Operating Activities	30,610		25,197
INVESTING ACTIVITIES
Proved property acquisition final settlement	1,755		—
Development costs	(8,291)		(2,835)
Unproved property acquisitions	(53)		(37)
Other property and asset additions	(254)		(143)
Cash Used by Investing Activities	(6,843)		(3,015)
FINANCING ACTIVITIES
Proceeds from long-term debt	36,000		10,000
Payments on long-term debt	(31,000)		(12,000)
Proceeds from sale of units to cover withholding taxes	1,215		187
Withholding taxes paid on vesting of restricted units	(1,151)		(851)
Debt issuance costs	—		(2)
Distributions	(25,294)		(19,451)
Cash Used by Financing Activities	(20,230)		(22,117)
INCREASE IN CASH AND CASH EQUIVALENTS	3,537		65
Cash and Cash Equivalents, beginning of period	7,305		4,505
Cash and Cash Equivalents, end of period	$	10,842	$	4,570

(a) Changes in Operating Assets and Liabilities
Accounts receivable	$	1,195	$	2,100
Other current assets	(1,914)		(1,071)
Current liabilities	(4,475)		(1,087)
Other operating liabilities	(1,834)		(353)
	$	(7,028)	$	(411)

See accompanying notes to the Consolidated Financial Statements

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TXO PARTNERS, L.P. Consolidated Statements of Partners’ Capital (Unaudited)

(in thousands)


	Common Units
	Units	$
Balances, December 31, 2024	40,913	$	609,416
Net income	—	2,416
Proceeds from sale of units to cover withholding taxes	—	1,215
Withholding taxes paid on vesting of restricted units	—	(1,151)
Expensing of unit awards	254	2,131
Distributions to unitholders	—	(25,294)
Balances, March 31, 2025	41,167	$	588,733


	Common Units
	Units		$
Balances, December 31, 2023	30,750		$	473,798
Net income	—		10,267
Proceeds from sale of units to cover withholding taxes	—		827
Withholding taxes paid on vesting of restricted units	—		(851)
Expensing of unit awards	188		1,141
Distributions to unitholders	—		(19,451)
Balances, March 31, 2024	$	30,938	$	465,731

See accompanying notes to the Consolidated Financial Statements

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TXO PARTNERS, L.P.

Notes to Consolidated Financial Statements (Unaudited)

1.Organization and Summary of Significant Accounting Policies

TXO Partners, L.P. (TXO Partners or the Partnership) is an independent oil and gas company that was formed as a Delaware limited partnership in January 2012 (with an effective inception of operations at January 18, 2012). The operations of TXO Partners are governed by the provisions of the partnership agreement, as amended, executed by the general partner, TXO Partners GP, LLC (the General Partner) and the limited partners. The General Partner is the manager and operator of TXO Partners. The General Partner is managed by the board of directors and executive officers of our General Partner. The members of the board of directors of our General Partner are appointed by MorningStar Oil & Gas, LLC (“MSOG”), as the sole member of our General Partner. TXO Partners will remain in existence unless and until dissolved in accordance with the terms of the partnership agreement.

TXO Partners’ assets include its investment in an unincorporated joint venture, Cross Timbers Energy, LLC (“Cross Timbers Energy”). TXO Partners owns 50% of Cross Timbers Energy, and TXO Partners is the manager of Cross Timbers Energy. Cross Timbers Energy is governed by a Member Management Committee (MMC) and is comprised of six representatives, three from each group, with each group having one voting member. All matters that come before the MMC require the unanimous consent of the voting members. On the last day of each calendar quarter, Cross Timbers Energy distributes all excess cash to the members based on their ownership percentage of 50% each, except for earnings from the note receivable which is owned 5% by TXO Partners. Cross Timbers Energy’s properties are located primarily in the San Juan Basin of New Mexico and Colorado and the Permian Basin of West Texas and New Mexico.

TXO Partners also has a wholly-owned subsidiary, MorningStar Operating LLC which owns oil and gas assets primarily in the San Juan Basin of New Mexico and Colorado, the Permian Basin of West Texas and New Mexico and the Williston Basin of Montana and North Dakota.

2.Basis of Presentation and Significant Accounting Policies

The condensed consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“US GAAP”) and on the same basis as our audited financial statements as of December 31, 2024 included in our Annual Report on Form 10-K for the year ended December 31, 2024. The consolidated balance sheet as of March 31, 2025 and the consolidated statements of operations and cash flows for the periods presented herein are not audited but reflect all adjustments that are of a normal recurring nature and are necessary for a fair statement of results for the periods shown. Certain information and note disclosures normally included in annual financial statements have been omitted pursuant to the rules and regulations of the U.S. Securities and Exchange Commission (“SEC”). Because the consolidated interim financial statements do not include all of the information and notes required by US GAAP for a complete set of financial statements, they should be read in conjunction with the audited consolidated financial statements referred to above. The results and trends in these interim financial statements may not be indicative of results for the full year.

Significant Accounting Policies

For a complete description of TXO Partners’ significant accounting policies, see our annual audited consolidated financial statements included in our Annual Report on Form 10-K for the year ended December 31, 2024.

3.Acquisitions

In August 2024, we completed the acquisition of producing properties from Eagle Mountain Energy Partners and VR 4-ELM, LP, located in the Elm Coulee field in Montana and the Russian Creek field in North Dakota, which are part of the Greater Williston Basin, for cash consideration of $243.5 million and 2.5 million common units of TXO valued at $50.0 million (the “EMEP Acquisition”). Our purchase price allocation included $314.1 million to proved properties, $0.6 million to other properties, $0.3 million to other current assets, $1.0 million to other assets, $5.7 million to other current liabilities and $16.8 million to asset retirement obligation. The cash portion of the acquisition was funded by a combination of cash on hand from the public offering and borrowings under our Credit Facility (Note 5).

Additionally, in August 2024, we completed the acquisition of producing properties from Kaiser-Francis Oil Company in the Russian Creek field in North Dakota for cash consideration of $17.0 million (the “KFOC Acquisition”), subject to customary purchase price adjustments. Our preliminary purchase price allocation included $19.1 million to

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proved properties, $0.5 million to current liabilities and $1.6 million to asset retirement obligation. The acquisition was funded by cash on hand from the public offering.

In the statements of operations for the three months ended March 31, 2025, we recorded $28.8 million of revenues and net income of $9.0 million from these acquisitions.

Pro forma financial information (Unaudited)

The following unaudited pro forma financial information represents a summary of the condensed consolidated results of operations for the three months ended March 31, 2024, assuming the EMEP Acquisition and KFOC Acquisition had been completed as of January 1, 2024. The pro forma financial information is provided for illustrative purposes only and does not purport to represent what the actual consolidated results of operations would have been. Future results may vary significantly from the results reflected because of various factors.


(in thousands)	Three Months Ended March 31, 2024

Total revenue	$	83,153
Net income	$	7,773

4.Related Party Transactions

We earned management fees from Cross Timbers Energy of $1.2 million for the three months ended March 31, 2025 and $1.1 million for the three months ended March 31, 2024.

5.Debt


(in thousands)	March 31, 2025		December 31, 2024
Credit Facility, 8.0% at March 31, 2025 and 8.3% at December 31, 2024	$	155,000	$	150,000
September 2016 Loan, 7.7% at March 31, 2025 and 8.0% at December 31, 2024	$	7,100	$	7,100
Total Long-term Debt	$	162,100	$	157,100

November 2021 Credit Facility

On August 30, 2024, we entered into Amendment No. 4 and Borrowing Base Agreement (“Amendment No. 4”) on our senior secured credit facility (the “Credit Facility”) with certain commercial banks, as the lenders, and JPMorgan Chase Bank, N.A., as the administrative agent. We use the Credit Facility for general corporate purposes. Amendment No. 4 extended the maturity date of the Credit Facility to August 30, 2028, increased the borrowing base from $165 million to $275 million and joined certain new Lenders to the Credit Facility. In connection with the Credit Facility, we incurred financing fees and expenses, which are included in other assets on the balance sheets, of approximately $6.2 million as of March 31, 2025 and December 31, 2024 before accumulated amortization of $2.7 million as of March 31, 2025 and $2.5 million as of December 31, 2024. These costs are being amortized over the life of the credit facility. Such amortized expenses are recorded as interest expense on the statements of operations.

Redetermination of the borrowing base under the credit facility, is based primarily on reserve reports that reflect commodity prices at such time, occurs semi-annually, in March and September, as well as upon requested interim redeterminations, by the lenders at their sole discretion. We also have the right to request additional borrowing base redeterminations each year at our discretion. Significant declines in commodity prices may result in a decrease in the borrowing base. These borrowing base declines can be offset by any commodity price hedges we enter. Our obligations under the credit facility are secured by substantially all assets of the Partnership, including, without limitation, (i) our interest in the joint venture, (ii) all our deposit accounts, securities accounts, and commodities accounts, (iii) any receivables owed to us by the joint venture and (iv) any oil and gas properties owned directly by TXO Partners or its wholly-owned subsidiaries. We are required to maintain (i) a current ratio greater than 1.0 to 1.0 and current assets shall include availability under the Credit Facility, but shall exclude the fair value of derivative instruments, and current liabilities shall exclude the fair value of derivative instruments and any advances under the Credit Facility and (ii) a ratio of total indebtedness-to-EBITDAX of not greater than 3.0 to 1.0. For purposes of the total net debt-to-EBITDAX ratio

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(“Leverage Ratio”), total net debt includes total debt for borrowed money (including capital leases and purchase money debt), minus unrestricted cash and cash equivalents on hand at such time (not exceeding $15.0 million in the aggregate), minus the unpaid balance of the FAM Loan. EBITDAX means sum of (i) net income plus interest expense; income taxes paid; depreciation, depletion and amortization; exploration expenses, including workover expenses; non-cash charges including unrealized losses on derivative instruments; and, any extraordinary or non-recurring charges, minus (ii) any extraordinary or non-recurring income and any non-cash income including unrealized gains on derivative instruments. Effective with the Second Amendment, our hedge requirements are based on availability under the Credit Facility and the Leverage Ratio. If the Leverage Ratio is greater than 0.75 to 1.00, we are required to hedge at least 50% of reasonably anticipated projected production of proved developed producing reserves for the 24 months following the end of the most recent quarter. If the Leverage Ratio is less than 0.75 to 1.00 and availability under the Credit Facility is greater than 20% of the then current borrowing base, the minimum required hedge volume would be 35% for the 12 months following the end of the most recent quarter. If the Leverage Ratio is less than 0.50 to 1.00 and availability under the Credit Facility is greater than 66.7% of the then current borrowing base, there would be no minimum required hedge volume. Our Credit Facility prohibits us from hedging more than 90% of our reasonably projected production for any fiscal year. We expect to complete our spring redetermination in May 2025. Under the terms of the Credit Facility as amended by the Fourth Amendment, we were in compliance with all of our debt covenants as of March 31, 2025 and December 31, 2024. Additionally, we believe we have adequate liquidity to continue as a going concern for at least the next twelve months from the date of this report.

At our election, interest on borrowings under the credit facility is determined by reference to either the secured overnight financing rate (“SOFR”) plus an applicable margin between 3.00% and 4.00% per annum (depending on the then-current level of borrowings under the Credit Facility) or the alternate base rate (“ABR”) plus an applicable margin between 2.00% and 3.00% per annum (depending on the then-current level of borrowings under the Credit Facility). Interest is generally payable quarterly for loans bearing interest based on the ABR and at the end of the applicable interest period for loans bearing interest at SOFR. We are required to pay a commitment fee to the lenders under the Credit Facility, which accrues at a rate per annum of 0.5% on the average daily unused amount of the lesser of: (i) the maximum commitment amount of the lenders and (ii) the then-effective borrowing base.

September 2016 Loan

On September 30, 2016, TXO Partners entered into an unsecured loan agreement with Cross Timbers Energy (the “FAM Loan”). The proceeds for the loan were taken from the cash held by the offshore subsidiary of Exxon Mobil Corporation and the loan was assigned to the offshore subsidiary (Note 6). The loan matures on November 29, 2028, but is automatically extended should the maturity date of the Credit Facility be extended. In all instances, this loan will mature ninety-one days after the maturity of the Credit Facility. Interest on the loan is the lesser of (a) SOFR plus three and one-quarter of one percent (3.25%) per annum, adjusted monthly or (b) the highest rate permitted by applicable law. Though the note is unsecured, we are required to stay in compliance with terms of the Credit Facility.

6.Note Receivable from Related Party

As of March 31, 2025 and December 31, 2024, we, through our 5% ownership interest in investment assets at Cross Timbers Energy, had a note receivable totaling $7.1 million outstanding with a highly-rated, offshore subsidiary of Exxon Mobil Corporation. Under the terms of the agreement, there is no stated maturity date and Cross Timbers Energy may demand repayment of all or any portion of the outstanding balance on two business days’ notice. Interest is earned based on the one-month SOFR rate and is paid monthly. Interest income totaled $0.1 million in the first three months of 2025 and $0.1 million in the first three months of 2024.

The note receivable is treated as a non-current asset, since Cross Timbers Energy does not have any intention of demanding repayment of all or any portion of the outstanding balance at this time. Repayment would require the approval of the Cross Timbers Energy MMC.

7.Asset Retirement Obligation

Our asset retirement obligation primarily represents the estimated present value of the amount we will incur to plug, abandon and remediate our proved producing properties at the end of their productive lives, in accordance with applicable state and federal laws. We determine our asset retirement obligation by calculating the present value of estimated cash

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flows related to the liability. The following is a summary of changes in TXO Partners’ asset retirement obligation activity for the three months ended March 31, 2025:


	(in thousands)
Asset retirement obligation, January 1	$	190,904
Liability settled upon plugging and abandoning wells	(1,324)
Accretion of discount expense	3,813
Asset retirement obligation, March 31	193,393
Less current portion	(3,000)
Asset retirement obligation, long term	$	190,393

8.Commitments and Contingencies

From time to time, the Partnership is subject to various claims and legal actions arising in the ordinary course of business. In the opinion of management, the ultimate disposition of these matters will not have a material adverse effect on the Partnership.

To date, our expenditures to comply with environmental and occupational health and safety laws and regulations have not been significant and are not expected to be significant in the future. However, new regulations, enforcement policies, claims for damages or other events could result in significant future costs.

9.Fair Value

We periodically use commodity-based and financial derivative contracts to manage exposures to commodity price. We do not hold or issue derivative financial instruments for speculative or trading purposes. We periodically enter into futures contracts, costless collars, energy swaps, swaptions and basis swaps to hedge our exposure to price fluctuations on crude oil, natural gas liquids and natural gas sales (Note 10).

Fair Value of Financial Instruments

Because of their short-term maturity, the fair value of cash and cash equivalents, accounts receivable and accounts payable approximates their carrying values at March 31, 2025 and December 31, 2024. The following are estimated fair values and carrying values of our other financial instruments at each of these dates:


	Asset (Liability)
	March 31, 2025				December 31, 2024
(in thousands)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Note receivable from related party	$	7,131	$	7,131	$	7,131	$	7,131
Long-term debt	$	(162,100)	$	(162,100)	$	(157,100)	$	(157,100)
Derivative asset	$	21,138	$	21,138	$	8,477	$	8,477
Derivative liability	$	(34,121)	$	(34,121)	$	(13,868)	$	(13,868)

The fair value of our note receivable from related party approximates the carrying amount because the interest rate is based on current market interest rates and can be called upon two business days’ notice (Note 6). The fair value of our long-term debt approximates the carrying amount because the interest rate is reset periodically at then current market rates (Note 5).

The fair value of our note receivable from related party (Note 6), derivative asset/(liability) (Note 10) and our long-term debt (Note 5) is measured using Level II inputs, and are determined by either market prices on an active market for similar assets or other market-corroborated prices. Counterparty credit risk is considered when determining the fair value of our note receivable and derivative asset (liability). Since our counterparty is highly rated, the fair value of our note receivable from related party does not require an adjustment to account for the risk of nonperformance by the counterparty, however, an adjustment for counterparty credit risk has been applied to the derivative asset (liability).

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The following table summarizes our fair value measurements and the level within the fair value hierarchy in which the fair value measurements fall.


	Fair Value Measurements
	March 31, 2025				December 31, 2024
(in thousands)	Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Note receivable from related party	$	7,131	$	—	$	7,131	$	—
Long-term debt	$	(162,100)	$	—	$	(157,100)	$	—
Derivative asset	$	21,138	$	—	$	8,477	$	—
Derivative liability	$	(34,121)	$	—	$	(13,868)	$	—

Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis

Certain assets and liabilities are measured at fair value on a nonrecurring basis. These assets and liabilities are not measured at fair value on an ongoing basis, but are subject to fair value adjustments whenever events or circumstances indicate that the carrying value of those assets may not be recoverable and are based upon Level 3 inputs. These assets and liabilities can include assets and liabilities acquired in a business combination, proved and unproved natural gas properties, asset retirement obligations and other long-lived assets that are written down to fair value when they are impaired. Such fair value estimates require assumptions and judgments regarding the existence of liabilities, the amount and timing of cash outflows required to settle the liability, what constitutes adequate restoration, inflation factors, credit adjusted discount rates, and consideration of changes in legal, regulatory, environmental and political environments.

We periodically review our long-lived assets to be held and used, including proved oil and natural gas properties, whenever events or circumstances indicate that the carrying value of those assets may not be recoverable. We review our oil and natural gas properties by asset group. The estimated future net cash flows are based upon the underlying reserves and anticipated future pricing. An impairment loss is recognized if the sum of the expected undiscounted future net cash flows is less than the carrying amount of the assets. If the estimated undiscounted future net cash flows are less than the carrying amount of a particular asset, the Partnership recognizes an impairment loss for the amount by which the carrying amount of the asset exceeds the estimated fair value of such assets. The fair value of the proved properties is measured based on the income approach, which incorporates a number of assumptions involving expectations of future product prices, which the Partnership bases on the forward-price curves, estimates of oil and gas reserves, estimates of future expected operating and capital costs and a risk adjusted discount rate of 10%. These inputs are categorized as Level 3 in the fair value hierarchy.

Commodity Price Hedging Instruments

We periodically enter into futures contracts, energy swaps, swaptions, collars and basis swaps to hedge our exposure to price fluctuations on crude oil, natural gas and natural gas liquids sales. When actual commodity prices exceed the fixed price provided by these contracts we pay this excess to the counterparty, and when the commodity prices are below the contractually provided fixed price, we receive this difference from the counterparty. See Note 10.

The fair value of our derivatives contracts consists of the following:


	Asset Derivatives				Liability Derivatives
(in thousands)	March 31, 2025		December 31, 2024		March 31, 2025		December 31, 2024
Derivatives not designated as hedging instruments:
Crude oil futures and differential swaps	$	5,773	$	2,730	$	(24)	$	(52)
Natural gas liquids futures	$	—	$	—	$	(13)	$	—
Natural gas futures, collars and basis swaps	$	15,365	$	5,747	$	(34,084)	$	(13,816)
Total	$	21,138	$	8,477	$	(34,121)	$	(13,868)

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Derivative fair value (gain) loss, included as part of the related revenue line on the consolidated income statements, comprises the following realized and unrealized components:


	Three Months Ended March 31,
(in thousands)	2025		2024
Net cash paid to counterparties	$	1,896	$	396
Non-cash change in derivative fair value	$	7,591	$	658
Derivative fair value (gain) loss	$	9,487	$	1,054

Concentrations of Credit Risk

Our receivables are from a diverse group of companies including major energy companies, pipeline companies, marketing companies, local distribution companies and end-users in various industries. Letters of credit or other appropriate security are obtained as considered necessary to limit risk of loss from the other companies. Including the bank that issued the letter of credit, we currently have greater concentrations of credit with several investment-grade (BBB- or better) rated companies.

10.Commodity Sales Commitments

Our policy is to consider hedging a portion of our production at commodity prices the general partner deems attractive. While there is a risk we may not be able to realize the benefit of rising prices, the general partner may enter into hedging agreements because of the benefits of predictable, stable cash flows.

We periodically enter futures contracts, energy swaps, swaptions and basis swaps to hedge our exposure to price fluctuations on crude oil, natural gas liquids and natural gas sales. When actual commodity prices exceed the fixed price provided by these contracts we pay this excess to the counterparty, and when the commodity prices are below the contractually provided fixed price, we receive this difference from the counterparty. We also enter costless price collars, which set a ceiling and floor price to hedge our exposure to price fluctuations on natural gas sales. When actual commodity prices exceed the ceiling price provided by these contracts we pay this excess to the counterparty, and when the commodity prices are below the floor price, we receive this difference from the counterparty. If the actual commodity price falls in between the ceiling and floor price, there is no cash settlement.

Crude Oil

We have entered into crude oil futures contracts and swap agreements that effectively fix prices for the production and periods shown below. Prices to be realized for hedged production may be less than these fixed prices because of location, quality and other adjustments. See Note 9.


Production Period	Bbls per Day	Weighted Average NYMEX Price per Bbl
April 2025—December 2025	6,000	$	67.39
January 2026—June 2026	3,000	$	70.57
July 2026—September 2026	2,000	$	70.49
October 2026—December 2026	375	$	64.16

Net settlements on oil futures and sell basis swap contracts increased oil revenues by $0.1 million in the first three months of 2025 and decreased oil revenues by $2.5 million in the first three months of 2024. An unrealized gain increased

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oil revenues by $3.1 million in the first three months of 2025 and an unrealized loss decreased oil revenues by $0.3 million in the first three months of 2024.

Natural Gas Liquids

We have entered into natural gas liquids futures contracts and swap agreements for ethane that effectively fix prices for the production and periods shown below. Prices to be realized for hedged production may be less than these fixed prices because of location, quality and other adjustments. See Note 9.


Production Period	Gallons per Day	Weighted Average NGL OPIS Price per Gallon
Ethane
January 2027— March 2027	14,700	$	0.29

Net settlements on NGL futures contracts had no impact on NGL revenues in the first three months of 2025 and increased NGL revenues by $0.2 million in the first three months of 2024. An unrealized loss decreased NGL revenues by $0.0 million in the first three months of 2025 and $0.2 million in the first three months of 2024.

Natural Gas

We have entered into natural gas futures contracts and swap agreements that effectively fix prices for the production and periods shown below. Prices to be realized for hedged production may be less than these fixed prices because of location, quality and other adjustments. See Note 9.


Production Period	MMBtu per Day	Weighted Average NYMEX Price per MMBtu
April 2025—March 2026	50,000	$	3.21
April 2026—September 2026	35,000	$	3.25
October 2026—December 2026	42,500	$	3.90
January 2027—March 2027	42,500	$	4.36

The price we receive for our gas production is generally less than the NYMEX price because of adjustments for delivery location (“basis”), relative quality and other factors. We have entered sell basis swap agreements that effectively fix the basis adjustment for the San Juan Basin delivery location for the production and periods shown below.


Production Period	MMBtu per Day	Weighted Average Sell Basis Price per MMBtu(a)
April 2025—December 2025	50,000	$	(0.01)

_________________________________

(a)Reductions to NYMEX gas price for delivery location

Net settlements on gas futures and sell basis swap contracts decreased gas revenues by $2.0 million in the first three months of 2025 and increased gas revenues by $1.9 million in the first three months of 2024. An unrealized loss to record the fair value of derivative contracts decreased gas revenues by $10.6 million in the first three months of 2025 and $0.2 million in the first three months of 2024.

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11. Earnings per Unit

The following represents basic and diluted earnings per Common Unit for the three months ended March 31, 2025 and 2024:


	(in thousands, except per unit data)	Net income		Units	Income per Unit
2025
	Basic	$	2,416	41,083	$0.06
	Dilutive effect of phantom units	—		731
	Diluted	$	2,416	41,814	$0.06

2024
	Basic	$	10,267	30,800	$0.33
	Dilutive effect of phantom units	—		625
	Diluted	$	10,267	31,425	$0.33

12.Partners’ Capital

On May 1, 2025, the board of directors of our general partner declared a cash distribution of $0.61 per common unit for the quarter ended March 31, 2025. The distribution will be paid on May 23, 2025, to unitholders of record on May 16, 2025.

Our fourth quarter distribution of $0.61 per unit with respect to cash available for distribution for the three months ended December 31, 2024, was paid on March 21, 2025.

13.Revenue from Contracts with Customers

The Partnership recognizes sales of oil, natural gas, and NGLs when it satisfies a performance obligation by transferring control of the product to a customer, in an amount that reflects the consideration to which the Partnership expects to be entitled in exchange for the product.

As discussed in Note 10, the Partnership recognizes the impact of derivative gains and losses as a component of revenue. See table below for the reconciliation of revenue from contracts with customers and derivative gains and losses.


	For the Three Months Ended March 31, 2025
	Oil and condensate		Natural gas liquids		Natural gas		Total Revenues

	(in thousands)
Revenue from customers	$	61,838	$	8,575	$	23,399	$	93,812
Unrealized gain (loss) on derivatives	3,071		(13)		(10,649)		(7,591)
Realized gain (loss) on derivatives	86		—		(1,982)		(1,896)
Total revenues	$	64,995	$	8,562	$	10,768	$	84,325


	For the Three Months Ended March 31, 2024
	Oil and condensate		Natural gas liquids		Natural gas		Total Revenues

	(in thousands)
Revenue from customers	$	40,804	$	6,470	$	21,219	$	68,493
Unrealized gain (loss) on derivatives	(277)		(204)		(177)		(658)
Realized gain (loss) on derivatives	(2,493)		236		1,861		(396)
Total Revenues	$	38,034	$	6,502	$	22,903	$	67,439

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Natural Gas and NGL Sales

Under our natural gas processing contracts, we deliver natural gas to a midstream processing entity at the wellhead or at the inlet of a facility. The midstream provider gathers and processes the product and both the residue gas and the resulting natural gas liquids are sold at the tailgate of the plant. The Partnership’s natural gas production is primarily sold under market-sensitive contracts that are typically priced at a differential to the published natural gas index price for the producing area due to the natural gas quality and the proximity to the market. We evaluated these arrangements and determined that control of the products transfers at the tailgate of the plant, meaning that the Partnership is the principal and the third-party purchaser is its customer. As such, we present the gas and NGL sales on a gross basis and the related gathering and processing costs as a component of taxes, transportation, and other on the statement of operations.

Oil and Condensate Sales

Oil production is typically sold at the wellhead or at the outlet of a gathering system under market-sensitive contracts at an index price, net of pricing differentials. The Partnership recognizes revenue when control transfers to the purchaser at the wellhead at the net price received from the customer.

Production imbalances

The Partnership uses the sales method to account for production imbalances. If the Partnership’s sales volumes for a well exceed the Partnership’s proportionate share of production from the well, a liability is recognized to the extent that the Partnership’s share of estimated remaining recoverable reserves from the well is insufficient to satisfy the imbalance. No receivables are recorded for those wells on which the Partnership has taken less than its proportionate share of production.

Contract Balances

Under the Partnership’s product sales contracts, its customers are invoiced once the Partnership’s performance obligations have been satisfied, at which point payment is unconditional. Accordingly, the Partnership’s product sales contracts do not give rise to contract assets or contract liabilities.

Performance Obligations

The majority of the Partnership’s sales are short-term in nature with a contract term of one year or less. For those contracts, the Partnership has utilized the practical expedient in ASC 606-10-50-14 exempting the Partnership from disclosures of the transaction price allocated to remaining performance obligations if the performance obligation is part of a contract that has an original duration of one year or less.

For the Partnership’s product sales that have a contract term greater than one year, the Partnership has utilized the practical expedient in ASC 606-10-50-14(a), which states the Partnership is not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Under these contracts, each unit of product generally represents a separate performance obligation; therefore, future volumes are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligation is not required.

14. Employee Benefit Plans

In January 2025, the compensation committee approved grants of 301,180 time-vesting phantom units with distribution equivalent rights to the non-employee directors, officers and certain key employees. These phantom units will vest ratably over a three-year period for the officers and key employees and will fully vest on the one-year anniversary of the grant for the non-employee directors. The phantom units will be settled in common units and distribution equivalents will be paid to holders of outstanding phantom units, including unvested phantom units.

Additionally, in January 2025, the compensation committee approved target grants of 249,380 performance-vesting phantom units to the officers and certain key employees. These performance-based phantom units will be earned based on the Company’s performance during the 2025 calendar year according to certain performance objectives and will vest in one-half increments on January 31, 2027 and January 31, 2028. Prior to determination of the achievement of the performance objectives, distribution equivalent rights will be paid according to the target number of phantom units grants; following determination of the number of earned phantom units based on achievement of the performance objectives,

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distribution equivalent rights will be paid according to the number of earned phantom units. The phantom units will be settled in common units and distribution equivalents will be paid to holders of outstanding phantom units, including unvested phantom units.

In conjunction with the announcement that Brent W. Clum and Gary D. Simpson were named Co-Chief Executive Officers of the General Partner, effective April 1, 2025, on March 31, 2025, the compensation committee of the Board granted the following awards, effective April 1, 2025, to each of Mr. Clum and Mr. Simpson: (i) 100,000 phantom units which vest on April 1, 2025 and (ii) 100,000 phantom units, along with distribution equivalent rights, which vest on April 1, 2026.

In January 2024, the compensation committee approved target grants of 159,475 performance-vesting phantom units to the officers and certain key employees. Based on the results of the Company’s performance during 2024 according to certain performance objectives, 215,977 performance-vesting phantom units were earned and will vest in one-half increments on January 31, 2026 and January 31, 2027. The phantom units will be settled in common units and distribution equivalents will be paid to holders of outstanding phantom units, including unvested phantom units.

We recognized compensation expense related to these and prior grants of $2.1 million for the three months ended March 31, 2025 and $1.1 million for the three months ended March 31, 2024. As of March 31, 2025, we had total deferred compensation expense of $17.1 million. For these non-vested unit awards, we estimate that compensation expense for service periods after March 31, 2025 will be $7.2 million in 2025, $6.1 million in 2026, $3.5 million in 2027 and $0.3 million in 2028. The weighted average remaining vesting period is 1.9 years.

15.Accrued Liabilities

Accrued liabilities consist of the following at March 31, 2025 and December 31, 2024:


	March 31, 2025		December 31, 2024
Accrued production expenses	$	21,629	$	22,818
Accrued capital expenditures	$	3,983	$	5,401
Accrued ad valorem taxes	$	2,513	$	3,056
Accrued severance taxes	$	1,986	$	2,567
Accrued bonuses	$	1,329	$	4,841
Other accrued liabilities	$	303	$	244
Total accrued liabilities	$	31,743	$	38,927

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16.Segment Reporting

We have one reportable segment, our exploration and production of oil, natural gas and natural gas liquids segment (“E&P segment”). Our E&P segment derives revenues from customers by selling oil, natural gas and natural gas liquids under contracts of various terms and durations (See Note 13). The operating segments within the reportable segment have been aggregated based on the similarity of their economic and other characteristics, including product type and services. All of our assets are located in the United States, and all revenues are attributable to United States customers.

The Partnership's Chief Operating Decision Maker ("CODM") is a group of executives, including the Co-Chief Executive Officers. The CODM assesses performance for the E&P segment and decides how to allocate resources based on cash provided by operations which is also reported on the statement of cash flows as consolidated cash provided by operations. The measure of segment assets is reported on the balance sheet as total consolidated assets.

The CODM uses net income to evaluate income generated from segment assets in deciding whether to reinvest profits into the E&P segment or to pay distributions.

Selected financial information related to our one reportable segment is included below:


(in thousands)	Three months ended March 31,
	2025		2024
REVENUES
Oil and condensate	$	64,995	$	38,034
Natural gas liquids	8,562		6,502
Gas	10,768		22,903
Total Revenues	84,325		67,439
EXPENSES
Production	42,271		33,083
Exploration	73		123
Taxes, transportation and other	17,881		15,573
Depreciation, depletion, and amortization	21,429		10,517
Accretion of discount in asset retirement obligation	3,813		2,784
General and administrative	2,441		2,654
Total Expenses	87,908		64,734
OPERATING (LOSS) INCOME	(3,583)		2,705
OTHER INCOME
Other income	9,517		8,413
SEGMENT INCOME FROM OPERATIONS	$	5,934	$	11,118

Reconciliation:
Interest income	103		125
Interest expense	(3,621)		(976)
Other Expense	(3,518)		(851)
NET INCOME	$	2,416	$	10,267

CASH PROVIDED BY OPERATING ACTIVITIES	$	30,610	$	25,197

17.Supplemental Cash Flow Information

Interest payments totaled $3.2 million for the three months ended March 31, 2025 and $0.8 million for the three months ended March 31, 2024. State income tax payments on behalf of our unitholders were $0.2 million during the three months ended March 31, 2025 and $1.5 million during the three months ended March 31, 2024.

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18.Subsequent Events

We have evaluated subsequent events through the date the financial statements were available to be issued. See Notes 10 and 14.

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

The following discussion and analysis should be read in conjunction with our unaudited consolidated financial statements and notes thereto presented in Item 1 of this Quarterly Report. Additionally, the following discussion and analysis should be read in conjunction with our audited consolidated financial statements and notes thereto and the related “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” included in our Annual Report on Form 10-K for the year ended December 31, 2024.

Unless otherwise stated or the context indicates otherwise, references in this Quarterly Report to “our general partner” refers to TXO Partners GP, LLC, a Delaware limited liability company, and the terms “partnership,” the “Company,” “we,” “our,” “us” or similar terms refer to TXO Partners, L.P., a Delaware limited partnership (“TXO Partners”) and its subsidiaries. Unless otherwise indicated, throughout this discussion the term “MBoe” refers to thousands of barrels of oil equivalent quantities produced for the indicated period, with natural gas and NGL quantities converted to Bbl on an energy equivalent ratio of six Mcf to one barrel of oil.

Cautionary Statement Regarding Forward-Looking Statements

Some of the information in this Quarterly Report on Form 10-Q may contain “forward-looking statements.” All statements, other than statements of historical fact included in this Quarterly Report on Form 10-Q, regarding our strategy, future operations, financial position, estimated revenues and losses, projected costs, prospects, plans and objectives of management are forward-looking statements. When used in this Quarterly Report on Form 10-Q, words such as “may,” “assume,” “forecast,” “could,” “should,” “will,” “plan,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “project,” “budget” and similar expressions are used to identify forward-looking statements, although not all forward-looking statements contain such identifying words. These forward-looking statements are based on management’s current belief, based on currently available information, as to the outcome and timing of future events at the time such statement was made. When considering forward-looking statements, you should keep in mind the risk factors and other cautionary statements described under the heading “Risk Factors” included in this Quarterly Report on Form 10-Q.

We caution you that these forward-looking statements are subject to all of the risks and uncertainties, most of which are difficult to predict and many of which are beyond our control, incident to the exploration for and development and production of oil, natural gas and natural gas liquids (“NGL”). We disclose important factors that could cause our actual results to differ materially from our expectations as discussed under “Risk Factors” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and elsewhere in this Quarterly Report on Form 10-Q. Factors that could cause our actual results to differ materially from the results contemplated by such forward-looking statement include:

•commodity price volatility;

•the impact of epidemics, outbreaks or other public health events, and the related effects on financial markets, worldwide economic activity and our operations;

•uncertainties about our estimated oil, natural gas and NGL reserves, including the impact of commodity price declines on the economic producibility of such reserves, and in projecting future rates of production;

•the concentration of our operations in the Permian Basin, the San Juan Basin and the Williston Basin;

•difficult and adverse conditions in the domestic and global capital and credit markets;

•lack of transportation and storage capacity as a result of oversupply, government regulations or other factors;

•lack of availability of drilling and production equipment and services;

•potential financial losses or earnings reductions resulting from our commodity price risk management program or any inability to manage our commodity risks;

•failure to realize expected value creation from property acquisitions and trades;

•access to capital and the timing of development expenditures;

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•environmental, weather, drilling and other operating risks;

•regulatory changes, including potential shut-ins or production curtailments mandated by the Railroad Commission of Texas;

•competition in the oil and natural gas industry;

•loss of production and leasehold rights due to mechanical failure or depletion of wells and our inability to re-establish their production;

•our ability to service our indebtedness;

•cost inflation;

•political and economic conditions and events in foreign oil and natural gas producing countries, including embargoes, the Israel-Hamas war, attacks in the Red Sea and other continued hostilities in the Middle East and other sustained military campaigns, the armed conflict in Ukraine and associated economic sanctions on Russia, conditions in South America, Central America, China and Russia, and acts of terrorism or sabotage;

•evolving cybersecurity risks such as those involving unauthorized access, denial-of-service attacks, malicious software, data privacy breaches by employees, insider or other with authorized access, cyber or phishing-attacks, ransomware, social engineering, physical breaches or other actions; and

•risks related to our ability to expand our business, including through the recruitment and retention of qualified personnel.

Reserve engineering is a process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact way. The accuracy of any reserve estimate depends on the quality of available data, the interpretation of such data and price and cost assumptions made by reservoir engineers. In addition, the results of drilling, testing and production activities may justify revisions of estimates that were made previously. If significant, such revisions would change the schedule of any further production and development drilling. Accordingly, our reserve and PV-10 estimates may differ significantly from the quantities of oil, natural gas and NGLs that are ultimately recovered.

Should one or more of the risks or uncertainties described in this Quarterly Report on Form 10-Q occur, or should underlying assumptions prove to be incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements.

All forward-looking statements, expressed or implied, included in this Quarterly Report on Form 10-Q are expressly qualified in their entirety by this cautionary statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that we or persons acting on our behalf may issue.

Except as otherwise required by applicable law, we disclaim any duty to update any forward-looking statements, all of which are expressly qualified by the statements in this section, to reflect events or circumstances after the date of this Quarterly Report on Form 10-Q.

Overview

We are an independent oil and natural gas company focused on the acquisition, development, optimization and exploitation of conventional oil, natural gas and natural gas liquid reserves in North America. Our properties are predominately located in the Permian Basin of New Mexico and Texas, the San Juan Basin of New Mexico and Colorado and the Williston Basin of Montana and North Dakota.

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Recent Developments

Leadership Changes

On March 19, 2025, Bob R. Simpson resigned from his position as Chief Executive Officer of our General Partner, effective April 1, 2025. He has continued to serve as Chairman of our board of directors. In connection with Bob R. Simpson’s resignation, on March 19, 2025, the board of directors appointed Brent W. Clum and Gary D. Simpson to serve as Co-Chief Executive Officers, also effective April 1, 2025. Prior to their new appointments, Brent W. Clum served as the President of Business Operations, Chief Financial Officer and a Director of our General Partner, while Gary D. Simpson served as our General Partner’s President of Production and Development. Both have continued to serve in their previous roles alongside their new appointments.

New Appointments to the Board of Directors

On March 19, 2025, Gary D. Simpson was appointed to serve as a member of the board of directors, effective April 1, 2025.

On March 31, 2025, Lawrence S. Massaro was appointed to serve as a member of the board of directors, effective April 1, 2025. In addition, Mr. Massaro was appointed to the Audit Committee of the board of directors, also effective April 1, 2025.

Market Outlook

The oil and natural gas industry is cyclical and commodity prices are highly volatile. For example, during the period from January 1, 2024 through March 31, 2025, NYMEX prices for crude oil and natural gas reached a high of $86.91 per Bbl and $4.49 per MMBtu, respectively, and a low of $65.75 per Bbl and $1.58 per MMBtu, respectively. Oil prices increased in the first half of 2024 due to hostilities in the Middle East and higher global consumption. However, increased supply led to lower prices in the second half of 2024 and into 2025. These declines accelerated in April due to the tariff announcement and the increased expectation for a global recession. WTI crude oil prices have been volatile reaching a high of $86.91 per Bbl in April 2024 before declining to $61.50 per Bbl as of April 11, 2025. Natural gas prices reached a high of $4.49 per MMbtu in March 2025 before declining to $3.53 per MMbtu as of April 11, 2025.

We expect the crude oil and natural gas markets will continue to be volatile in the future. Our revenue, profitability and future growth are highly dependent on the prices we receive for our oil and natural gas production. Please see “Risk Factors--Risks Related to the Natural Gas, NGL and Oil Industry and Our Business--Commodity prices are volatile--A sustained decline in commodity prices may adversely affect our business, financial condition or results of operations and our ability to meet our capital expenditure obligations and financial commitments.”

With our anticipated cash flows from our long-lived property base, we intend to provide dynamic allocation of funds to prudently meet our goals. These goals include the highest projected economic returns on our capital budget, acquisition opportunities that fulfill our strategy, and cash distributions for the life of our legacy assets. From time to time, we may choose to prioritize the repayment of debt incurred in acquisitions to support the longer-term financial stewardship of our business. At other times, given fluctuations in industry costs and commodity prices, we may modify our capital budget or cash balances to shift funds towards cash distributions. We will use all of these tools to support our underlying strategy as a “production and distribution” enterprise.

Concerns over global economic conditions, energy costs, supply chain disruptions, increased demand, labor shortages associated with a fully employed U.S. labor force, geopolitical issues, inflation, the availability and cost of credit and the United States financial markets and other factors have contributed to increased economic uncertainty and diminished expectations for the global economy. Rising inflation has been pervasive for the last several years, increasing the cost of salaries, wages, supplies, material, freight, and energy. While we have seen inflation moderate, inflation continues to run higher than the Federal Reserve target, resulting in higher costs. We continue to undertake actions and implement plans to address these pressures and protect the requisite access to commodities and services, however, these mitigation efforts may not succeed or be insufficient. Nevertheless, we expect for the foreseeable future to experience inflationary pressure on our cost structure. Principally, commodity costs for steel and chemicals required for drilling, higher transportation and fuel costs and wage increases have increased our operating costs. We do not expect these cost increases to reverse in the short term. Typically, as prices for oil and natural gas increase, so do associated costs.

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Conversely, in a period of declining prices, associated cost declines are likely to lag and may not adjust downward in proportion to prices. We cannot predict the future inflation rate but to the extent these higher costs do not begin to reverse or start to increase again, we may experience a higher cost environment going forward. If we are unable to recover higher costs through higher commodity prices, our current revenue stream, estimates of future reserves, borrowing base calculations, impairment assessments of oil and natural gas properties, and values of properties in purchase and sale transactions would all be significantly impacted.

We are taking actions to mitigate inflationary pressures. We are working closely with other suppliers and contractors to ensure availability of supplies on site, especially fuel, steel and chemical supplies which are critical to many of our operations. However, these mitigation efforts may not succeed or be insufficient.

How We Evaluate Our Operations

We use a variety of financial and operational metrics to assess the performance of our operations, including:

•production volumes;

•realized prices on the sale of oil, NGLs and natural gas;

•production expenses;

•acquisition and development expenditures;

•Adjusted EBITDAX; and

•Cash Available for Distribution.

Non-GAAP Financial Measures

Adjusted EBITDAX

We include in this Quarterly Report the non-GAAP financial measure Adjusted EBITDAX and provide our calculation of Adjusted EBITDAX and a reconciliation of Adjusted EBITDAX to net income (loss), our most directly comparable financial measures calculated and presented in accordance with GAAP. We define Adjusted EBITDAX as net income (loss) before (1) interest income, (2) interest expense, (3) depreciation, depletion and amortization, (4) impairment expenses, (5) accretion of discount on asset retirement obligations, (6) exploration expenses, (7) unrealized (gains) losses on commodity derivative contracts, (8) non-cash incentive compensation, (9) non-cash (gain) loss on forgiveness of debt and (10) certain other non-cash expenses.

Adjusted EBITDAX is used as a supplemental financial measure by our management and by external users of our financial statements, such as industry analysts, investors, lenders, rating agencies and others, to more effectively evaluate our operating performance and our results of operation from period to period and against our peers without regard to financing methods, capital structure or historical cost basis. We exclude the items listed above from net income (loss) in arriving at Adjusted EBITDAX 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. Adjusted EBITDAX is not a measurement of our financial performance under GAAP and should not be considered as an alternative to, or more meaningful than, net income (loss) as determined in accordance with GAAP or as indicators of our operating performance. Certain items excluded from Adjusted EBITDAX are significant components in understanding and assessing a company’s financial performance, such as a company’s cost of capital and tax burden, as well as the historic costs of depreciable assets, none of which are reflected in Adjusted EBITDAX. Our presentation of Adjusted EBITDAX should not be construed as an inference that our results will be unaffected by unusual or non-recurring items. Our computations of Adjusted EBITDAX may not be identical to other similarly titled measures of other companies.

Cash Available for Distribution

Cash available for distribution is not a measure of net income or net cash flow provided by or used in operating activities as determined by GAAP. Cash available for distribution is a supplemental non-GAAP financial measure used by our management and by external users of our financial statements, such as investors, lenders and others (including industry

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analysts and rating agencies who will be using such measure), to assess our ability to internally fund our exploration and development activities, pay distributions, and to service or incur additional debt. We define cash available for distribution as Adjusted EBITDAX less net cash interest expense, exploration expense, non-recurring (gain) / loss and development costs. Development costs include all of our capital expenditures made for oil and gas properties, other than acquisitions. Cash available for distribution will not reflect changes in working capital balances. Cash available for distribution is not a measurement of our financial performance or liquidity under GAAP and should not be considered as an alternative to, or more meaningful than, net income (loss) or net cash provided by or used in operating activities as determined in accordance with GAAP or as indicators of our financial performance and liquidity. The GAAP measures most directly comparable to cash available for distribution are net income and net cash provided by operating activities. Cash available for distribution should not be considered as an alternative to, or more meaningful than, net income or net cash provided by operating activities.

You should not infer from our presentation of Adjusted EBITDAX that its results will be unaffected by unusual or non-recurring items. You should not consider Adjusted EBITDAX or cash available for distribution in isolation or as a substitute for analysis of our results as reported under GAAP. Additionally, because Adjusted EBITDAX and cash available for distribution may be defined differently by other companies in our industry, our definition of Adjusted EBITDAX and cash available for distribution may not be comparable to similarly titled measures of other companies, thereby diminishing their utility.

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Reconciliation of Adjusted EBITDAX and Cash Available for Distribution to GAAP Financial Measures


	Three Months Ended March 31,
	2025		2024

	(in thousands)

Net income	$	2,416	$	10,267
Interest expense	3,621		976
Interest income	(103)		(125)
Depreciation, depletion and amortization	21,429		10,517
Accretion of discount in asset retirement obligation	3,813		2,784
Exploration expense	73		123
Non-cash derivative loss	7,591		658
Non-cash incentive compensation	2,131		1,141
Non-recurring (gain)/loss	$	5	$	45
Adjusted EBITDAX	$	40,976	$	26,386
Cash Interest expense	(3,368)		(780)
Cash Interest income	103		125
Exploration expense	(73)		(123)
Development costs	(8,291)		(2,835)
Cash Available for Distribution	$	29,347	$	22,773

Net cash provided by operating activities	$	30,610	$	25,197
Changes in operating assets and liabilities	7,028		411
Development costs	(8,291)		(2,835)
Cash Available for Distribution	$	29,347	$	22,773

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Results of Operations

Three Months Ended March 31, 2025 Compared to the Three Months Ended March 31, 2024


	Three months ended March 31,
	2025		2024

	(in thousands)
REVENUES
Oil and condensate	$	64,995	$	38,034
Natural gas liquids	8,562		6,502
Natural gas	10,768		22,903
Total Revenues	84,325		67,439
EXPENSES
Production	42,271		33,083
Exploration	73		123
Taxes, transportation and other	17,881		15,573
Depreciation, depletion and amortization	21,429		10,517
Accretion of discount in asset retirement obligation	3,813		2,784
General and administrative	2,441		2,654
Total Expenses	87,908		64,734
OPERATING (LOSS) INCOME	(3,583)		2,705
OTHER INCOME (EXPENSE)
Other income	9,517		8,413
Interest income	103		125
Interest expense	(3,621)		(976)
Total Other Income	5,999		7,562
NET INCOME	$	2,416	$	10,267

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The following table provides a summary of our sales volumes, average prices (both including and excluding the effects of derivatives) and operating expenses on a per Boe basis for the periods indicated:


	Three months ended March 31,
	2025		2024
Sales:
Oil and condensate sales (MBbls)	902		541
Natural gas liquids sales (MBbls)	295		283
Natural gas sales (MMcf)	6,791		7,334
Total (MBoe)	2,329		2,046
Total (MBoe/d)	26		22
Average sales prices:
Oil and condensate excluding the effects of derivatives (per Bbl)	$	68.58	$	75.42
Oil and condensate (per Bbl) (1)	$	72.08	$	70.30
Natural gas liquids excluding the effects of derivatives (per Bbl)	$	29.04	$	22.83
Natural gas liquids (per Bbl) (2)	$	29.00	$	22.94
Natural gas excluding the effects of derivatives (per Mcf)	$	3.45	$	2.89
Natural gas (per Mcf) (3)	$	1.59	$	3.12
Expense per Boe:
Production	$	18.15	$	16.17
Taxes, transportation and other	$	7.68	$	7.61
Depreciation, depletion and amortization	$	9.20	$	5.14
General and administrative expenses	$	1.05	$	1.30

_________________________________

(1)Oil and condensate prices include both realized losses and unrealized gains and losses from derivatives. The unrealized gains were $3.1 million for the three months ended March 31, 2025 and the unrealized losses were $0.3 million for the three months ended March 31, 2024. The realized gains were $0.1 million for the three months ended March 31, 2025 and the realized losses were $2.5 million for the three months ended March 31, 2024.

(2)Natural gas liquids prices include both realized and unrealized gains and losses from derivatives. The unrealized losses were $0.0 million for the three months ended March 31, 2025 and $0.2 million for the three months ended March 31, 2024. There were no realized gains for the three months ended March 31, 2025 and $0.2 million for the three months ended March 31, 2024.

(3)Natural gas prices include both realized losses and unrealized gains and losses from derivatives. The unrealized losses were $10.6 million for the three months ended March 31, 2025 and $0.2 million for the three months ended March 31, 2024. The realized losses were $2.0 million for the three months ended March 31, 2025 and the realized gains were $1.9 million for the three months ended March 31, 2024.

Revenues

Revenues increased $16.9 million, or 25%, from $67.4 million for the three months ended March 31, 2024 to $84.3 million for the three months ended March 31, 2025. The increase was primarily attributable to a 282 MBoe increase in production which resulted in a $23.2 million increase in revenue primarily as a result of the acquisition of producing assets in the Williston Basin being offset by natural declines in San Juan Basin and Permian Basin. Additionally, a 19% increase in the average selling price of natural gas, excluding the effects of derivatives, resulting in an increase in revenue of $4.1 million and an increase in the average selling price on NGLs of 27%, excluding the effects of derivatives, resulting in an increase in revenue of $1.8 million. These increases were partially offset by net losses on our hedging activity of $8.4 million, of which $6.9 million were unrealized losses and $1.5 million were realized losses, as well as a decrease in the average selling price, excluding the effects of derivatives, on oil of 9% resulting in a decrease in revenue of $3.7 million.

Production expenses

Production expenses increased $9.2 million, or 28%, from $33.1 million for the three months ended March 31, 2024 to $42.3 million for the three months ended March 31, 2025. Of this increase, $8.5 million is attributable to production from the Williston Basin acquisitions. The remaining increase is primarily related to increased labor, maintenance and energy costs.

On a per unit basis, production expenses increased from $16.17 per Boe sold for the three months ended March 31, 2024 to $18.15 per Boe sold for the three months ended March 31, 2025. The increase is primarily related to the increased

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costs per Boe from our historical properties as decreased production and increased labor, maintenance and energy in these properties resulted in higher costs per Boe.

Taxes, transportation, and other

Taxes, transportation, and other increased $2.3 million, or 15%, from $15.6 million for the three months ended March 31, 2024 to $17.9 million for the three months ended March 31, 2025. The increase is primarily attributable to the increase in natural gas and NGLs prices and increase in oil and NGLs production partially offset by decreased oil prices and natural gas production.

On a per unit basis, taxes, transportation, and other increased from $7.61 per Boe sold for the three months ended March 31, 2024 to $7.68 per Boe sold for the three months ended March 31, 2025. The increase is primarily related to the higher natural gas and NGLs prices and change in production mix.

Depreciation, depletion, and amortization

Depreciation, depletion, and amortization increased $10.9 million, or 104%, from $10.5 million for the three months ended March 31, 2024 to $21.4 million for the three months ended March 31, 2025. The increase is primarily attributable to the increased production associated with the Williston Basin acquisitions of $10.0 million which has a higher rate than the historical properties, and a higher rate on our historical properties partially offset by decreased production.

On a per unit basis, depreciation, depletion, and amortization increased from $5.14 per Boe sold for the three months ended March 31, 2024 to $9.20 per Boe sold for the three months ended March 31, 2025. The increase is primarily related to the production associated with the Williston Basin acquisitions which has a higher rate than the historical properties.

General and administrative

General and administrative (“G&A”) expenses decreased $0.2 million, or (8)%, from $2.7 million for the three months ended March 31, 2024 to $2.4 million for the three months ended March 31, 2025. The decrease is primarily attributable to lower personnel costs of $0.8 million partially offset by higher professional costs related to being public.

On a per unit basis, G&A expense decreased from $1.30 per Boe sold for the three months ended March 31, 2024 to $1.05 per Boe sold for the three months ended March 31, 2025. The decrease is related to increased production and lower costs.

Other income

Other income increased $1.1 million, or 13%, from $8.4 million for the three months ended March 31, 2024 to $9.5 million for the three months ended March 31, 2025. The increase is primarily attributable to a $2.4 million increase in bonus receipts on term assignments partially offset by lower CO2 and plant income of $1.1 million and a $0.3 million decrease in marketing income. The CO2 and plant income is ancillary to the operations of the gas processing plant in the Permian Basin in New Mexico and CO2 assets in Colorado.

Interest expense

Interest expense increased $2.6 million, or 271%, from $1.0 million for the three months ended March 31, 2024 to $3.6 million for the three months ended March 31, 2025. The increase is primarily attributable to the increased borrowings partially offset by a lower interest rate.

Liquidity and Capital Resources

Our primary sources of liquidity and capital will be cash flows generated by operating activities and borrowings under our Credit Facility. Outstanding borrowings under our Credit Facility were $155.0 million at March 31, 2025 and $150.0 million at December 31, 2024, and the remaining availability under our Credit Facility was $120.0 million at March 31, 2025 and $125.0 million at December 31, 2024. Additionally, we had positive net working capital (including cash and excluding the effects of derivative instruments) of $6.4 million at March 31, 2025 and negative net working capital of $2.5 million at December 31, 2024.

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Our partnership agreement requires that we distribute all of our available cash (as defined in the partnership agreement) to our unitholders. Our quarterly cash distributions may vary from quarter to quarter as a direct result of variations in the performance of our business, including those caused by fluctuations in the prices of oil and natural gas. Such variations may be significant and quarterly distributions paid to our unitholders may be zero. The first quarter distribution of $0.61 per unit with respect to cash available for distribution for the three months ended March 31, 2025, was declared on May 1, 2025 and will be paid May 23, 2025 to unitholders of record on May 16, 2025.

Our acquisition and development expenditures consist of acquisitions of unproved and other property and development expenditures partially offset by final settlement on previous acquisition of proved property. Our capital expenditures including acquisitions were $6.8 million for the three months ended March 31, 2025 and $3.0 million for the three months ended March 31, 2024.

In order to mitigate volatility in oil and natural gas prices, we have entered into commodity derivative contracts. See “Quantitative and Qualitative Disclosures About Market Risk—Commodity Price Risk.”

We incurred costs of approximately $6.9 million for drilling, completion and recompletion activities and facilities costs in the three months ended March 31, 2025 and we have budgeted approximately $30.0 - $50.0 million for such costs in 2025.

The amount and timing of these capital expenditures is substantially within our control and subject to management’s discretion. We retain the flexibility to defer a portion of these planned capital expenditures depending on a variety of factors, including, but not limited to the prevailing and anticipated prices for oil, NGLs and natural gas, the availability of necessary equipment, infrastructure and capital, seasonal conditions and drilling and acquisition costs. Any postponement or elimination of our development program could result in a reduction of proved reserve volumes, production and cash flow, including distributions to unitholders.

Based on current commodity prices and our drilling success rate to date, we expect to be able to fund our distributions, meet our debt obligations and fund our 2025 capital development programs from cash flow from operations and borrowings under our Credit Facility.

If cash flow from operations does not meet our expectations, we may reduce our expected level of capital expenditures and/or distributions to unitholders. Alternatively, we may fund these expenditures using borrowings under our Credit Facility, issuances of debt and equity securities or from other sources, such as asset sales. We cannot assure you that necessary capital will be available on acceptable terms or at all. Our ability to raise funds through the incurrence of additional indebtedness could be limited by covenants in our debt arrangements. If we are unable to obtain funds when needed or on acceptable terms, we may not be able to complete acquisitions that may be favorable to us, finance the capital expenditures necessary to maintain our production or proved reserves, or make distributions to unitholders.

Cash flows

The following table summarizes our cash flows for the periods indicated (in thousands):


	Three months ended March 31,
	2025		2024
Net cash provided by operating activities	$	30,610	$	25,197
Net cash used by investing activities	(6,843)		(3,015)
Net cash used by financing activities	(20,230)		(22,117)

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Three Months Ended March 31, 2025 Compared to Three Months Ended March 31, 2024

Net cash provided by operating activities

Net cash provided by operating activities increased $5.4 million for the three months ended March 31, 2025 compared to the three months ended March 31, 2024 due improved operating results, excluding the effects of derivatives, primarily due to improved revenues.

Net cash used by investing activities

Net cash used by investing activities increased $3.8 million for the three months ended March 31, 2025 compared to the three months ended March 31, 2024 due to an increase in development costs of $5.5 million and other asset additions of $0.1 million partially offset by final settlement of previous property acquisition of $1.8 million

Net cash used by financing activities


	Three months ended March 31,
	2025		2024
	(in thousands)
Proceeds from long-term debt	$	36,000	$	10,000
Payments on long-term debt	(31,000)		(12,000)
Proceeds from sale of units to cover withholding taxes	1,215		187
Withholding taxes paid on vesting of restricted units	(1,151)		(851)
Debt issuance costs	—		(2)
Distributions	(25,294)		(19,451)
Net cash used in financing activities	$	(20,230)	$	(22,117)

Net cash used in financing activities decreased $1.9 million for the three months ended March 31, 2025 compared to the three months ended March 31, 2024 due to the increase in net borrowings under our credit facility of $7.0 million and an increase in net proceeds from sale of units to cover withholding tax payments on vesting of restricted units of $0.7 million partially offset by increased distributions of $5.8 million.

Revolving credit agreement

Our Credit Facility contains certain customary representations, warranties and covenants, including but not limited to, limitations on incurring debt and liens, limitations on merging or consolidating with another company, limitations on making certain restricted payments, limitations on investments, limitations on paying distributions on, redeeming, or repurchasing common units, limitations on entering into transactions with affiliates, and limitations on asset sales. The Credit Facility also contains customary events of default, including non-payment, breach of covenants, materially incorrect representations, cross-default, bankruptcy and change of control. If an event of default occurs and is continuing, the lenders may declare all amounts outstanding under the Credit Facility to be immediately due and payable.

We are required to maintain (i) a current ratio (the ratio of current assets to current liabilities) greater than 1.0 to 1.0, which for purposes of this definition includes availability under the Credit Facility but excludes the fair value of derivative instruments, and (ii) a ratio of total net debt-to-EBITDAX of not greater than 3.0 to 1.0. For purposes of the total net debt-

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to-EBITDAX ratio, total net debt is total debt for borrowed money (including capital leases and purchase money debt) minus unrestricted cash and cash equivalents on hand at such time (not exceeding $15.0 million in the aggregate), minus the unpaid balance of the FAM Loan. EBITDAX means the sum of (i) net income plus interest expense; income taxes paid; depreciation, depletion and amortization; exploration expenses, including workover expenses; non-cash charges including unrealized losses on derivative instruments; and, any extraordinary or non-recurring charges, minus (ii) any extraordinary or non-recurring income and any non-cash income including unrealized gains on derivative instruments. Under the terms of the Credit Facility, we were in compliance with all of our debt covenants as of March 31, 2025. Additionally, we believe we have adequate liquidity to continue as a going concern for at least the next twelve months from the date of this report.

We had $155.0 million debt outstanding and $120.0 million available under our Credit Facility as of March 31, 2025.

Contractual obligations and commitments

We have not guaranteed the debt or obligations of any other party, nor do we have any other arrangements or relationships with other entities that could potentially result in consolidated debt or losses.

Derivative contracts

We have entered into derivative instruments to hedge our exposure to commodity price fluctuations. If market prices are higher than the contract prices when the cash settlement amount is calculated, we are required to pay the contract counterparties. As of March 31, 2025, the current liability related to such contracts was $25.6 million and the long-term liability related to such contracts was $8.5 million. Such payments will generally be funded by higher prices received from the sale of oil, NGLs and natural gas. For further information on derivative contracts, see Note 10 in the financial statements included elsewhere in this Quarterly Report.

Asset Retirement Obligation

At March 31, 2025, we had asset retirement obligations of $193.4 million inclusive of a current portion of $3.0 million. For further information on asset retirement obligations, see Note 7 in the financial statements included elsewhere in this Quarterly Report.

Critical Accounting Policies

There has been no change in our critical accounting policies from those disclosed in our Annual Report on Form 10-K filed with the SEC on March 4, 2025.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

We are exposed to market risk, including the effects of adverse changes in commodity prices and interest rates as described below. The primary objective of the following information is to provide quantitative and qualitative information about our potential exposure to market risks. The term “market risk” refers to the risk of loss arising from adverse changes in commodity prices and interest rates. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. All of our market risk sensitive instruments were entered into for purposes other than speculative trading. Also, gains and losses on these instruments are generally offset by losses and gains on the offsetting expenses.

Commodity price risk

Our major market risk exposure is in the pricing that we receive for our oil, NGL and natural gas production. Pricing for oil, NGLs, and natural gas has been volatile and unpredictable for several years, and this volatility is expected to continue in the future. The prices we receive for our oil, NGL, and natural gas production depend on many factors outside of our control, such as the strength of the global economy and global supply and demand for the commodities we produce.

To reduce the impact of fluctuations in oil, NGL and natural gas prices on our revenues, we periodically enter into commodity derivative contracts with respect to certain of our oil, NGL and natural gas production through various transactions that limit the risks of fluctuations of future prices. We plan to continue our practice of entering into such

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transactions to reduce the impact of commodity price volatility on our cash flow from operations. Future transactions may include price swaps whereby we will receive a fixed price for our production and pay a variable market price to the contract counterparty. Additionally, we may enter into collars, whereby we receive the excess, if any, of the fixed floor over the floating rate or pay the excess, if any, of the floating rate over the fixed ceiling. These hedging activities are intended to limit our exposure to product price volatility and to maintain stable cash flows.

As of March 31, 2025, the fair market value of our oil, NGL and natural gas derivative contracts was a net liability of $13.0 million. Based upon our open commodity derivative positions at March 31, 2025, a hypothetical 10% change in the NYMEX WTI and Henry Hub prices, OPIS prices and basis prices would change our net oil, NGL and natural gas derivative liability by approximately $25.6 million.


(in thousands)	Fair Value at March 31, 2025		Hypothetical Price Increase or Decrease of 10% Price Change
Derivative asset (liability) – Crude Oil	$	5,749	$	12,593
Derivative asset (liability) – Natural Gas Liquids	$	(13)	$	40
Derivative asset (liability) – Natural Gas	$	(18,719)	$	12,984
Net cash used in financing activities	$	(12,983)	$	25,617

The hypothetical change in fair value could be a gain or loss depending on whether prices increase or decrease.

Counterparty and customer credit risk

Our cash and cash equivalents are exposed to concentrations of credit risk. We manage and control this risk by investing these funds in major financial institutions. We often have balances in excess of the federally insured limits.

We sell oil, NGL and natural gas production to various types of customers. Credit is extended based on an evaluation of the customer’s financial condition and historical payment record. The future availability of a ready market for our production depends on numerous factors outside of our control, none of which can be predicted with certainty. For the years ended December 31, 2024 and December 31, 2023, we had two and two customers, respectively, that each accounted for more than 10% of total revenues. We do not believe the loss of any single purchaser would materially impact our operating results because oil, NGLs and natural gas are fungible products with well-established markets and numerous purchasers.

At March 31, 2025, we had commodity derivative contracts with counterparties. We are currently not required to provide collateral or other security to counterparties to support derivative instruments; however, to minimize the credit risk in derivative instruments, it is our policy to enter into derivative contracts only with counterparties that are creditworthy financial institutions deemed by management as competent and competitive market makers. Additionally, we use master netting arrangements to minimize credit risk exposure. The creditworthiness of our counterparties is subject to periodic review.

Interest rate risk

At March 31, 2025, we had $155.0 million of variable rate debt outstanding. Assuming no change in the amount outstanding, the impact on interest expense of a 1% increase or decrease in the average interest rate would be approximately $1.6 million per year. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Revolving credit agreement.”

Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

Under the supervision and with the participation of our management, including our Principal Executive Officers and Principal Financial Officer, we conducted an evaluation of the effectiveness of the design and operation of our disclosure controls and procedures, as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act as of March 31, 2025. Based on this evaluation, our Principal Executive Officers and Principal Financial Officer concluded that as of March 31, 2025, our disclosure controls and procedures were effective to provide reasonable assurance that information required to be

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disclosed in the reports we file and submit under the Exchange Act is recorded, processed, summarized, and reported as and when required, and that such information is accumulated and communicated to our management, including our Principal Executive Officers and Principal Financial Officer, to allow timely decisions regarding its required disclosure. Based on the evaluation of our disclosure controls and procedures as of March 31, 2025, our Principal Executive Officers and Principal Financial Officer have concluded that, as of such date, our disclosure controls and procedures were effective at the reasonable assurance level.

Changes in Internal Control over Financial Reporting

There were no changes in our internal control over financial reporting that occurred during the quarter ended March 31, 2025 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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Part II - Other Information

Item 1. Legal Proceedings

We are party to lawsuits arising in the ordinary course of our business. We cannot predict the outcome of any such lawsuits with certainty, but management believes it is remote that pending or threatened legal matters will have a material adverse impact on our financial condition. Due to the nature of our business, we are, from time to time, involved in other routine litigation or subject to disputes or claims related to our business activities, including workers’ compensation claims and employment-related disputes. In the opinion of our management, none of these other pending litigation matters, disputes or claims against us, if decided adversely, will have a material adverse effect on our financial condition, cash flows or results of operations.

Item 1A. Risk Factors

There have been no material changes in the risk factors disclosed under Part I, Item 1A of our Annual Report on Form 10-K for the year ended December 31, 2024.

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

None.

Item 3. Defaults Upon Senior Securities

None.

Item 4. Mine Safety Disclosures

None.

Item 5. Other Information

During the fiscal quarter ended March 31, 2025, there were no adoptions, modifications or terminations by directors or officers of Rule 10b5-1 trading arrangements or non-Rule 10b5-1 trading arrangements, each as defined in Item 408 of Regulation S-K.

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Item 6. Exhibits


Exhibit Number			Description

3.1			Amended and Restated Certificate of Limited Partnership of TXO Partners, L.P. (incorporated by reference to Exhibit 3.1 to Quarterly Report on Form 10-Q filed on May 9, 2023)

3.2			Amended and Restated Certificate of Formation of TXO Partners, GP, LLC (incorporated by reference to Exhibit 3.2 to Quarterly Report on Form 10-Q filed on May 9, 2023)

3.3			Seventh Amended and Restated Agreement of Limited Partnership of TXO Partners, L.P. (incorporated by reference to Exhibit 3.2 to Current Report on Form 8-K filed on January 31, 2023)

3.4			Amendment No. 1 to the Seventh Amended and Restated Agreement of Limited Partnership of TXO Partners, L.P. (incorporated by reference to Exhibit 3.3 to Quarterly Report on Form 10-Q filed on May 9, 2023)

3.5			Amended and Restated Limited Liability Company Agreement of TXO Partners GP, LLC (incorporated by reference to Exhibit 3.4 to Annual Report on Form 10-K filed on March 31, 2023)

3.6			Amendment No. 1 to the Amended and Restated Limited Liability Company Agreement of TXO Partners GP, LLC (incorporated by reference to Exhibit 3.4 to Quarterly Report on Form 10-Q filed on May 9, 2023)

31.1*			Certification of C o -Chief Executive Officer pursuant to Exchange Act Rule 13a-14(a) and Rule 15d-14(a)

31.2*			Certification of Co-C hief Exec utive Officer and Chief Financial Officer pursuant to Exchange Act Rule 13a-14(a) and Rule 15d-14(a)

32.1*			Certification of C o-C hief Executive Officer pursuant to 18 U.S.C. Section 1350

32.2*			Certification of Co-Chief Executive Offic e r and Chief Financial Officer pursuant to 18 U.S.C. Section 1350

101.INS			Inline XBRL Instance Document. (the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document).

101.SCH			Inline XBRL Taxonomy Extension Schema Document.

101.CAL			Inline XBRL Taxonomy Extension Calculation Linkbase Document.

101.DEF			Inline XBRL Taxonomy Extension Definition Linkbase Document.

101.LAB			Inline XBRL Taxonomy Extension Label Linkbase Document.

101.PRE			Inline XBRL Taxonomy Extension Presentation Linkbase Document.

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

_________________________________

* Filed herewith

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SIGNATURES

Pursuant to the requirements of the Securities Act of 1933, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.


			TXO Partners, L.P.

			By:			TXO Partners GP, LLC, its general partner

			By:			/s/ Brent W. Clum
						Name: Brent W. Clum Title: Co-Chief Executive Officer, Chief Financial Officer and Duly Authorized Officer

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Date	Price Target	Rating	Analyst
4/23/2025	$20.00	Buy	Stifel
2/21/2023	$35.00	Overweight	CapitalOne
2/21/2023	$34.00	Strong Buy	Raymond James
2/21/2023	$31.00	Buy	Stifel

SEC Form 10-Q filed by TXO Partners L.P.

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