10-Q

Part I - Financial Information

Item 1. Financial Statements

TXO PARTNERS, L.P.

Consolidated Balance Sheets

(in thousands)


	March 31, 2026			December 31, 2025
	(Unaudited)
ASSETS
Current Assets:
Cash and cash equivalents	$	7,886		$	9,374
Accounts receivable, net		58,448			52,391
Derivative fair value		6,221			18,276
Other		17,672			15,293
Total Current Assets		90,227			95,334
Property and Equipment, at cost – successful efforts method:
Proved properties		2,340,193			2,336,977
Unproved properties		18,998			18,863
Other		89,202			89,065
Total Property and Equipment		2,448,393			2,444,905
Accumulated depreciation, depletion and amortization		(1,232,891	)		(1,204,261	)
Net Property and Equipment		1,215,502			1,240,644
Other Assets:
Note receivable from related party		7,168			7,131
Derivative fair value		1,401			5,576
Other		7,489			6,218
Total Other Assets		16,058			18,925
TOTAL ASSETS	$	1,321,787		$	1,354,903
LIABILITIES AND PARTNERS’ CAPITAL
Current Liabilities:
Accounts payable	$	38,991		$	27,979
Deferred payment		70,000			70,000
Accrued liabilities		37,766			45,776
Derivative fair value		56,017			5,057
Asset retirement obligation, current portion		3,500			3,500
Other current liabilities		3,726			1,605
Total Current Liabilities		210,000			153,917
Long-term Debt		277,100			291,100
Other Liabilities:
Asset retirement obligation		221,476			217,585
Derivative fair value		8,481			35
Other liabilities		262			534
Total Other Liabilities		230,219			218,154
Commitments and Contingencies
Partners’ Capital:
Partners’ capital		604,468			691,732
TOTAL LIABILITIES AND PARTNERS’ CAPITAL	$	1,321,787		$	1,354,903

See accompanying notes to the Consolidated Financial Statements

TXO PARTNERS, L.P.

Consolidated Statements of Operations (Unaudited)

(in thousands)


	Three Months Ended March 31,
	2026			2025
REVENUES
Oil and condensate	$	(2,746	)	$	64,995
Natural gas liquids		9,335			8,562
Natural gas		21,687			10,768
Total Revenues		28,276			84,325
EXPENSES
Production		47,737			42,271
Exploration		108			73
Taxes, transportation and other		19,762			17,881
Depreciation, depletion and amortization		28,838			21,429
Accretion of discount in asset retirement obligation		4,568			3,813
General and administrative		4,814			2,441
Total Expenses		105,827			87,908
OPERATING LOSS		(77,551	)		(3,583	)
OTHER INCOME (EXPENSE)
Other income		8,856			9,517
Interest income		99			103
Interest expense		(5,740	)		(3,621	)
Total Other Income		3,215			5,999
NET (LOSS) INCOME	$	(74,336	)	$	2,416

NET (LOSS) INCOME PER COMMON UNIT
Basic	$	(1.35	)	$	0.06
Diluted	$	(1.35	)	$	0.06

WEIGHTED AVERAGE COMMON UNITS OUTSTANDING
Basic		55,090			41,083
Diluted		55,090			41,814

See accompanying notes to the Consolidated Financial Statements

TXO PARTNERS, L.P.

Consolidated Statements of Cash Flows (Unaudited)

(in thousands)


	Three Months Ended March 31,
	2026			2025
OPERATING ACTIVITIES
Net (loss) income	$	(74,336	)	$	2,416
Adjustments to reconcile net (loss) income to net cash provided by operating activities, net of effects of assets acquired and liabilities assumed:
Depreciation, depletion and amortization		28,838			21,429
Accretion of discount in asset retirement obligation		4,568			3,813
Derivative fair value (gain) loss		91,280			9,487
Net cash received from (paid to) derivative counterparties		(15,644	)		(1,896	)
Non-cash incentive compensation		3,574			2,131
Other non-cash items		381			258
Changes in operating assets and liabilities (a)		(5,253	)		(7,028	)
Cash Provided by Operating Activities		33,408			30,610
INVESTING ACTIVITIES
Proceeds from sale of property and equipment		6,270			-
Proved property acquisitions		(695	)		1,755
Development costs		(9,427	)		(8,291	)
Unproved property acquisitions		(135	)		(53	)
Other property and asset additions		(394	)		(254	)
Cash Used by Investing Activities		(4,381	)		(6,843	)
FINANCING ACTIVITIES
Proceeds from long-term debt		23,000			36,000
Payments on long-term debt		(37,000	)		(31,000	)
Proceeds from sale of units to cover withholding taxes		1,508			1,215
Withholding taxes paid on vesting of restricted units		(1,446	)		(1,151	)
Debt issuance costs		(13	)		-
Distributions		(16,564	)		(25,294	)
Cash Used by Financing Activities		(30,515	)		(20,230	)
(DECREASE) INCREASE IN CASH AND CASH EQUIVALENTS		(1,488	)		3,537
Cash and Cash Equivalents, beginning of period		9,374			7,305
Cash and Cash Equivalents, end of period	$	7,886		$	10,842

(a) Changes in Operating Assets and Liabilities
Accounts receivable	$	(6,147	)	$	1,195
Other current assets		(257	)		(1,914	)
Current liabilities		3,733			(4,475	)
Other operating liabilities		(2,582	)		(1,834	)
	$	(5,253	)	$	(7,028	)

See accompanying notes to the Consolidated Financial Statements

TXO PARTNERS, L.P.

Consolidated Statements of Partners’ Capital (Unaudited)

(in thousands)


	Units		$
Balances, December 31, 2025		54,784	$	691,732
Net loss		—		(74,336	)
Proceeds from sale of units to cover withholding taxes		—		1,508
Withholding taxes paid on vesting of restricted units		—	$	(1,446	)
Expensing of unit awards		458	$	3,574
Distributions to unitholders		—	$	(16,564	)
Balances, March 31, 2026		55,242	$	604,468


	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

See accompanying notes to the Consolidated Financial Statements

TXO PARTNERS, L.P.

Notes to Consolidated Financial Statements (Unaudited)

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. Cross Timbers Energy entered into purchase and sale agreements with multiple private buyers to sell its oil and gas properties (Note 3).

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.

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, 2025 included in our Annual Report on Form 10-K for the year ended December 31, 2025. The consolidated balance sheet as of March 31, 2026 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, 2025.

Acquisitions and Dispositions

In March 2026, the Partnership announced that Cross Timbers Energy executed three purchase and sale agreements with multiple private buyers to sell oil and gas properties for gross aggregate consideration of approximately $200 million (each a "Cross Timbers Transaction" and collectively, the “Cross Timbers Transactions”), including a purchase and sale agreement with CTOC Energy, LLC (“CTOC”) for approximately $123.5 million in aggregate gross consideration.

Also, in March 2026, we received $6.2 million of deposits, net to TXO Partners, related to the Cross Timbers Transactions.

On April 1, 2026, the first Cross Timbers Transaction closed resulting in net proceeds to TXO Partners of approximately $8.2 million, subject to customary purchase price adjustments.

On April 30, 2026, the second Cross Timbers Transaction closed resulting in net proceeds to TXO Partners of approximately $30.8 million, subject to customary purchase price adjustments.

Subject to customary closing conditions, the third Cross Timbers Transaction is expected to close by the end of the second quarter of 2026. There can be no assurance that all conditions to closing the third Cross Timbers Transaction will be satisfied.

The Partnership expects to receive approximately $100 million in net proceeds from the Cross Timbers Transactions, subject to customary purchase price adjustments. The Partnership intends to use a portion of the net proceeds to pay the $70.0 million deferred payment for its 2025 purchase of assets from White Rock Energy, LLC, due on July 31, 2026.

The carrying value of the Cross Timbers Energy oil and gas assets and liabilities includes net property and equipment of $158.7 million and asset retirement obligation of $68.6 million, net to TXO Partners’ interest, as of March 31, 2026. The net income related to these properties, net to TXO Partners, was $0.4 million for the three months ended March 31, 2026 and $3.5 million for the three months ended March 31, 2025.

Subsequent to the closing of the Cross Timbers Transactions, we expect to begin the process of winding down Cross Timbers Energy.

In July 2025, we completed the acquisition of certain oil and gas assets from White Rock Energy, LLC, which are located in the Elm Coulee field in Montana and North Dakota for cash consideration of $331.6 million (the “WRE Acquisition”), including a deferred payment of $70.0 million which is due on July 31, 2026. Our purchase price allocation included $343.0 million to proved properties, $3.0 million to other properties, $1.7 million to other current assets, $6.9 million to other current liabilities and $9.2 million to asset retirement obligation. The WRE Acquisition was funded by a combination of cash on hand from the Offering (Note 12) and borrowings under our Credit Facility (Note 5).

In the statements of operations, we recorded $26.4 million of revenues and net income of $10.9 million for the three months ended March 31, 2026 from the WRE Acquisition.

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, 2025, assuming the WRE Acquisition had been completed as of January 1, 2025. 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, 2025
Total revenue	$	132,077
Net income	$	15,420

Related Party Transactions

We earned management fees from Cross Timbers Energy of $1.4 million for the three months ended March 31, 2026 and $1.2 million for the three months ended March 31, 2025.

Debt


(in thousands)	March 31, 2026		December 31, 2025
Credit Facility, 7.4 % at March 31, 2026 and 7.6% at December 31, 2025	$	270,000	$	284,000
September 2016 Loan, 7.0% at March 31, 2026 and 7.4% at December 31, 2025	$	7,100	$	7,100
Total Long-term Debt	$	277,100	$	291,100

November 2021 Credit Facility

On July 31, 2025, we entered into Amendment No. 5 and Borrowing Base Agreement (“Amendment No. 5”) 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. 5 increased the borrowing base from $275 million to $410 million, extended the maturity date to August 30, 2029 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 $8.6 million as of March 31, 2026 and $8.6 million as of December 31, 2025 before accumulated amortization of $4.0 million as of March 31, 2026 and $3.6 million as of December 31, 2025. We incurred $2.4 million of financing fees and expenses

in conjunction with Amendment No. 5. 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 (“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. 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. Under the terms of the Credit Facility, we were in compliance with all of our debt covenants as of March 31, 2026 and December 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.

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, 2029, 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 the terms of the Credit Facility.

Note Receivable from Related Party

We, through our 5% ownership interest in investment assets at Cross Timbers Energy, had a note receivable totaling $7.2 million as of March 31, 2026 and $7.1 million as of December 31, 2025 with a highly-rated, offshore subsidiary of Exxon Mobil Corporation. Under the terms of the agreement, the maturity date is February 10, 2046, but Cross Timbers Energy may demand repayment of all or any portion of the outstanding balance on five business days’ notice. Interest is earned based on the quarterly SOFR rate plus 4.3% and is paid quarterly. Interest income totaled $0.1 million in the first three months of 2026 and $0.1 million in the first three months of 2025.

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.

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 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, 2026:


	(in thousands)
Asset retirement obligation, January 1		221,085
Liability settled upon plugging and abandoning wells		(677	)
Accretion of discount expense		4,568
Asset retirement obligation, March 31		224,976
Less current portion		(3,500	)
Asset retirement obligation, long term	$	221,476

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.

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, 2026 and December 31, 2025. The following are estimated fair values and carrying values of our other financial instruments at each of these dates:


	Asset (Liability)
	March 31, 2026						December 31, 2025
(in thousands)	Carrying Amount			Fair Value			Carrying Amount			Fair Value
Note receivable from related party	$	7,168		$	7,168		$	7,131		$	7,131
Long-term debt	$	(277,100	)	$	(277,100	)	$	(291,100	)	$	(291,100	)
Derivative asset	$	7,622		$	7,622		$	23,852		$	23,852
Derivative liability	$	(64,498	)	$	(64,498	)	$	(5,092	)	$	(5,092	)

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 five 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).

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, 2026			December 31, 2025
(in thousands)	Significant Other Observable Inputs (Level 2)			Significant Other Observable Inputs (Level 2)
Note receivable from related party	$	7,168		$	7,131
Long-term debt	$	(277,100	)	$	(291,100	)
Derivative asset	$	7,622		$	23,852
Derivative liability	$	(64,498	)	$	(5,092	)

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 oil and 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, 2026		December 31, 2025		March 31, 2026			December 31, 2025
Derivatives not designated as hedging instruments:
Crude oil futures and differential swaps	$	—	$	21,771	$	(62,399	)	$	—
Natural gas liquids futures	$	42	$	19	$	—		$	—
Natural gas futures, collars and basis swaps	$	7,580	$	2,062	$	(2,099	)	$	(5,092	)
Total	$	7,622	$	23,852	$	(64,498	)	$	(5,092	)

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


	Three Months Ended March 31,
(in thousands)	2026		2025
Net cash paid to counterparties	$	15,644	$	1,896
Non-cash change in derivative fair value	$	75,636	$	7,591
Derivative fair value (gain) loss	$	91,280	$	9,487

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. 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 commodity prices. 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.


Production Period	Bbls per Day		Weighted Average NYMEX Price per Bbl
April 2026—June 2026		10,000	$	62.89
July 2026—September 2026		10,000	$	61.44
October 2026—December 2026		10,000	$	59.29
January 2027—June 2027		3,000	$	60.56
July 2027—December 2027		3,000	$	63.43
January 2028—March 2028		3,000	$	63.07

The price we receive for our oil production is generally different than the NYMEX price because of changes in the roll component of the NYMEX price due to the timing of when the monthly NYMEX price is set. We have entered sell basis swap agreements that effectively fix the roll component of the NYMEX price for the production and periods shown below.


Production Period	Bbls per Day		Weighted Average Roll Price per Bbl (a)
April 2026—December 2026		4,000	$	1.80

_________________________________

Increases to NYMEX oil price for roll component

Net settlements on oil futures and sell basis swap contracts decreased oil revenues by $8.4 million in the three months ended March 31, 2026 and increased oil revenues by $0.1 million in the three months ended March 31, 2025. An unrealized loss decreased

oil revenues by $84.2 million in the three months ended March 31, 2026 and an unrealized gain increased oil revenues by $3.1 million in the three months ended March 31, 2025.

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.


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 three months ended March 31, 2026 and no impact on NGL revenues in the three months ended March 31, 2025. An unrealized gain increased NGL revenues by $23.0 thousand in the three months ended March 31, 2026 and an unrealized loss decreased NGL revenues by $13.0 thousand in the three months ended March 31, 2025.

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.


Production Period	MMBtu per Day		Weighted Average NYMEX Price per MMBtu
April 2026—September 2026		50,000	$	3.49
October 2026—December 2026		50,000	$	3.93
January 2027—March 2027		42,500	$	4.36
April 2027—December 2027		32,500	$	3.76
January 2028—March 2028		20,000	$	4.18

We have also entered into gas collars that set a ceiling and floor price for the production and periods shown below.


			Weighted Average NYMEX Price per MMBtu
Production Period	MMBtu per Day		Floor		Ceiling
January 2028— March 2028		10,000	$	3.50	$	5.40

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 into 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 2026—March 2028		30,000	$	(0.89	)

____________________________

(a)

Reductions to NYMEX gas price for delivery location

Net settlements on gas futures and sell basis swap contracts decreased gas revenues by $7.3 million in the three months ended March 31, 2026 and $2.0 million in the three months ended March 31, 2025. An unrealized gain to record the fair value of derivative contracts increased gas revenues by $8.5 million in the three months ended March 31, 2026 and an unrealized loss decreased gas revenues by $10.6 million in the three months ended March 31, 2025.

11.

Earnings per Unit

The following represents basic and diluted earnings per common unit for the three months ended March 31, 2026 and 2025:


(in thousands, except per unit data)	Net (loss) income			Units		(Loss) Income per Unit
2026
Basic	$	(74,336	)		55,090	$	(1.35	)
Dilutive effect of phantom units		—			—
Diluted	$	(74,336	)		55,090	$	(1.35	)

2025
Basic	$	2,416			41,083	$	0.06
Dilutive effect of phantom units		—			731
Diluted	$	2,416			41,814	$	0.06

All restricted units, totaling 1.3 million, were excluded from the calculation of earnings per common unit for the three months ended March 31, 2026, because the units are anti-dilutive. No units were excluded for the three months ended March 31, 2025.

12.

Partners’ Capital

On May 15, 2025, we completed an underwritten public offering for the sale of 11,666,667 common units at a price of $15.00 per common unit resulting in proceeds of approximately $165.6 million net of underwriting discounts, commissions and other costs. On May 19, 2025, we completed the sale of an additional 1,750,000 common units at a price of $15.00 per common unit pursuant to the underwriter’s exercise in full of its option to purchase additional common units in the Offering, resulting in additional net proceeds of approximately $23.9 million, after deducting underwriting discounts, commissions and other costs. We used the net proceeds from the Offering to fund a portion of the cash consideration for the WRE Acquisition (Note 3).

On May 4, 2026, the board of directors of our general partner declared a cash distribution of $0.36 per common unit for the quarter ended March 31, 2026. The distribution will be paid on May 22, 2026, to unitholders of record on May 15, 2026.

Our fourth quarter distribution of $0.30 per unit with respect to cash available for distribution for the three months ended December 31, 2025, was paid on March 17, 2026.

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.


	Three Months Ended March 31, 2026
	Oil and condensate			Natural gas liquids		Natural gas			Total Revenues
	(in thousands)
Revenue from customers	$	89,777		$	9,312	$	20,467		$	119,556
Unrealized gain (loss) on derivatives		(84,170	)		23		8,511			(75,636	)
Realized gain (loss) on derivatives		(8,353	)		—		(7,290	)		(15,644	)
Total revenues	$	(2,746	)	$	9,335	$	21,687		$	28,276


	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

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 expenses 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 2026, the Compensation Committee of the Board (the "Compensation Committee") approved grants of 632,353 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 2026, the Compensation Committee approved grants of 510,552 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 2026 calendar year according to certain performance objectives and will vest in one-half increments on January 31, 2028 and January 31, 2029. Prior to determination of the achievement of the performance objectives, distribution equivalent rights will be paid according to the target number of phantom unit grants; following determination of the number of earned phantom units based on achievement of the performance objectives, 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.

Additionally, in January 2025, the Compensation Committee approved grants of 249,380 performance-vesting phantom units to the officers and certain key employees. Based on the results of the Company’s performance during 2025 according to certain performance objectives, 243,142 performance-vesting phantom units were earned and will vest in one-half increments on January 31, 2027 and January 31, 2028. 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 $3.6 million for the three months ended March 31, 2026 and $2.1 million for the three months ended March 31, 2025. As of March 31, 2026, we had total deferred compensation expense of $20.7 million. For these non-vested unit awards, we estimate that compensation expense for service periods after March 31, 2026 will be $8.0 million in 2026, $7.7 million in 2027, $4.6 million in 2028 and $0.4 million in 2029. The weighted average remaining vesting period is 1.8 years.

15.

Accrued Liabilities

Accrued liabilities consist of the following at March 31, 2026 and December 31, 2025:


	March 31, 2026		December 31, 2025
Accrued production expenses	$	25,828	$	27,409
Accrued capital expenditures	$	4,094	$	4,826
Accrued bonuses	$	1,439	$	6,100
Accrued ad valorem taxes	$	2,494	$	3,978
Accrued severance taxes	$	3,733	$	2,944
Other accrued liabilities	$	178	$	519
Total accrued liabilities	$	37,766	$	45,776

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,
	2026			2025
REVENUES
Oil and condensate	$	(2,746	)	$	64,995
Natural gas liquids		9,335			8,562
Gas		21,687			10,768
Total Revenues		28,276			84,325
EXPENSES
Production		47,737			42,271
Exploration		108			73
Taxes, transportation and other		19,762			17,881
Depreciation, depletion, and amortization		28,838			21,429
Accretion of discount in asset retirement obligation		4,568			3,813
General and administrative		4,814			2,441
Total Expenses		105,827			87,908
OPERATING LOSS		(77,551	)		(3,583	)
OTHER INCOME
Other income		8,856			9,517
SEGMENT (LOSS) INCOME FROM OPERATIONS	$	(68,695	)	$	5,934

Reconciliation:
Interest income		99			103
Interest expense		(5,740	)		(3,621	)
Other Expense		(5,641	)		(3,518	)
NET (LOSS) INCOME	$	(74,336	)	$	2,416

CASH PROVIDED BY OPERATING ACTIVITIES	$	33,408		$	30,610

17.

Supplemental Cash Flow Information

Interest payments totaled $5.7 million for the three months ended March 31, 2026 and $3.2 million for the three months ended March 31, 2025. State income tax payments were insignificant for the three months ended March 31, 2026 and $0.2 million during the three months ended March 31, 2025.

18.

Subsequent Events

We have evaluated subsequent events through the date the financial statements were available to be issued. See Note 3.

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 on Form 10-Q (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, 2025.

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 (the "Partnership" or“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;

•

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;

•

changes to U.S. and foreign governmental regulation, taxation and tariffs;

•

our ability to integrate the acquired assets and realize the anticipated benefits of the WRE Acquisition, including, among other things, operating efficiencies, revenue synergies and other cost savings;

•

political and economic conditions and events in foreign oil and natural gas producing countries, including embargoes, the recent military conflict involving Iran, 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 and unconventional 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.

Recent Developments

Cross Timbers Energy, LLC Disposition

In March 2026, we announced that Cross Timbers Energy executed three purchase and sale agreements with multiple private buyers to sell oil and gas properties for gross aggregate consideration of approximately $200 million, including a purchase and sale agreement with CTOC for approximately $123.5 million in gross aggregate consideration.

Also, in March 2026, we received approximately $6.2 million of deposits, net to TXO Partners, related to the Cross Timbers Transactions.

On April 1, 2026, the first Cross Timbers Transaction closed resulting in net proceeds of approximately $8.2 million, subject to customary purchase price adjustments. The preliminary allocation of the proceeds included $8.3 million to proved properties and $0.1 million to other current liabilities.

On April 30, 2026, the second Cross Timbers Transaction closed resulting in net proceeds of approximately $30.8 million, subject to customary purchase price adjustments, of which all was allocated to proved properties.

We expect to receive approximately $100.0 million in net proceeds from the Cross Timbers Transactions, subject to customary purchase price adjustments. We intend to use a portion of the net proceeds to pay the $70.0 million deferred payment for our 2025 purchase of assets from White Rock Energy, LLC, due on July 31, 2026.

Market Outlook

The oil and natural gas industry is cyclical and commodity prices are highly volatile. For example, during the period from January 1, 2025 through March 31, 2026, NYMEX prices for crude oil and natural gas reached a high of $102.88 per Bbl and $7.46 per MMBtu, respectively, and a low of $55.27 per Bbl and $2.70 per MMBtu, respectively. Oil prices increased in the first quarter of 2026 due to hostilities in the Middle East which led to unexpected production cuts and supply constraints. These increases began to moderate in April 2026 due to the cease fire announcement, however, oil prices remain volatile.

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, war, geopolitical issues, inflation, tariffs, 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. 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 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.

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


	Three Months Ended March 31,
	2026			2025
	(in thousands)
Net (loss) income	$	(74,336	)	$	2,416
Interest expense		5,740			3,621
Interest income		(99	)		(103	)
Depreciation, depletion and amortization		28,838			21,429
Accretion of discount in asset retirement obligation		4,568			3,813
Exploration expense		108			73
Unrealized (gains) losses on commodity derivative contracts		75,636			7,591
Non-cash incentive compensation		3,574			2,131
Non-recurring (gain)/loss		43			5
Adjusted EBITDAX	$	44,072		$	40,976
Cash Interest expense		(5,402	)		(3,368	)
Cash Interest income		99			103
Exploration expense		(108	)		(73	)
Development costs		(9,427	)		(8,291	)
Cash Available for Distribution	$	29,234		$	29,347

Net cash provided by operating activities	$	33,408		$	30,610
Changes in operating assets and liabilities		5,253			7,028
Development costs		(9,427	)		(8,291	)
Cash Available for Distribution	$	29,234		$	29,347

Results of Operations

Three Months Ended March 31, 2026 Compared to the Three Months Ended March 31, 2025


	Three months ended March 31,
	2026			2025
REVENUES
Oil and condensate	$	(2,746	)	$	64,995
Natural gas liquids		9,335			8,562
Natural gas		21,687			10,768
Total Revenues		28,276			84,325
EXPENSES
Production		47,737			42,271
Exploration		108			73
Taxes, transportation and other		19,762			17,881
Depreciation, depletion and amortization		28,838			21,429
Accretion of discount in asset retirement obligation		4,568			3,813
General and administrative		4,814			2,441
Total Expenses		105,827			87,908
OPERATING LOSS		(77,551	)		(3,583	)
OTHER INCOME (EXPENSE)
Other income		8,856			9,517
Interest income		99			103
Interest expense		(5,740	)		(3,621	)
Total Other Income		3,215			5,999
NET (LOSS) INCOME	$	(74,336	)	$	2,416

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,
	2026			2025
Sales:
Oil and condensate sales (MBbls)		1,310			902
Natural gas liquids sales (MBbls)		425			295
Natural gas sales (MMcf)		7,027			6,791
Total (MBoe)		2,906			2,329
Total (MBoe/d)		32			26
Average sales prices:
Oil and condensate excluding the effects of derivatives (per Bbl)	$	68.54		$	68.58
Oil and condensate (per Bbl) (1)	$	(2.10	)	$	72.08
Natural gas liquids excluding the effects of derivatives (per Bbl)	$	21.91		$	29.04
Natural gas liquids (per Bbl) (2)	$	21.96		$	29.00
Natural gas excluding the effects of derivatives (per Mcf)	$	2.91		$	3.45
Natural gas (per Mcf) (3)	$	3.09		$	1.59
Expense per Boe:
Production	$	16.43		$	18.15
Taxes, transportation and other	$	6.80		$	7.68
Depreciation, depletion and amortization	$	9.92		$	9.20
General and administrative expenses	$	1.66		$	1.05

(1)

Oil and condensate prices include both realized and unrealized gains and losses from derivatives. Unrealized losses were $84.2 million for the three months ended March 31, 2026 and unrealized gains were $3.1 million for the three months ended March 31, 2025. Realized losses were $8.4 million for the three months ended March 31, 2026 and realized gains were $0.1 million for the three months ended March 31, 2025.

(2)

Natural gas liquids prices include unrealized gains and losses from derivatives. Unrealized gains were $23.0 thousand for the three months ended March 31, 2026 and unrealized losses were $13.0 thousand for the three months ended March 31, 2025. There were no realized gains or losses for either the three months ended March 31, 2026 or the three months ended March 31, 2025.

(3)

Natural gas prices include both realized gains and unrealized gains and losses from derivatives. Unrealized gains were $8.5 million for the three months ended March 31, 2026 and unrealized losses were $10.6 million for the three months ended March 31, 2025. Realized losses were $7.3 million for the three months ended March 31, 2026 and $2.0 million for the three months ended March 31, 2025.

Revenues

Revenues decreased $56.0 million, or 66%, from $84.3 million for the three months ended March 31, 2025 to $28.3 million for the three months ended March 31, 2026. The decrease was primarily attributable to net losses on our hedging activity of $91.3 million for the three months ended March 31, 2026, compared to net hedging losses of $9.5 million for the three months ended March 31, 2025, resulting in a year-over-year increase in hedging losses of $81.8 million, of which $68.0 million were unrealized losses and $13.7 million were realized losses. Additionally, a 15% decrease in the average selling price of natural gas, excluding the effects of derivatives, resulted in a decrease in revenue of $3.6 million and a 25% decrease in the average selling price of NGLs, excluding the effects of derivatives, resulted in a decrease in revenue of $2.1 million. These decreases were partially offset by increases in production of 577 MBoe which resulted in increased revenue of $31.5 million primarily as a result of the acquisition of producing assets in the Williston Basin (the "Williston Acquisition") being offset by natural declines in the historical properties.

Production expenses

Production expenses increased $5.5 million, or 13%, from $42.3 million for the three months ended March 31, 2025 to $47.7 million for the three months ended March 31, 2026. This increase is primarily due to increased costs of $3.3 million related to the Williston Acquisition and increased maintenance and electricity costs on our historical properties.

On a per unit basis, production expenses decreased from $18.15 per Boe sold for the three months ended March 31, 2025 to $16.43 per Boe sold for the three months ended March 31, 2026. The decrease is primarily related to an increase in production of 577 MBoe partially offset by increased costs attributable to production from the Williston Acquisition.

Taxes, transportation, and other

Taxes, transportation, and other increased $1.9 million, or 11%, from $17.9 million for the three months ended March 31, 2025 to $19.8 million for the three months ended March 31, 2026. The increase is primarily attributable to the increase in production partially offset by decreased oil, gas and NGL prices excluding the effects of derivatives.

On a per unit basis, taxes, transportation, and other decreased from $7.68 per Boe sold for the three months ended March 31, 2025 to $6.80 per Boe sold for the three months ended March 31, 2026. The decrease is primarily related to increased production partially offset by increased costs.

Depreciation, depletion, and amortization

Depreciation, depletion, and amortization (“DD&A”) increased $7.4 million, or 35%, from $21.4 million for the three months ended March 31, 2025 to $28.8 million for the three months ended March 31, 2026. The increase is primarily attributable to the DD&A from increased production associated with the Williston Acquisition which has a higher rate than the historical properties partially offset by decreased production on our historical properties.

On a per unit basis, depreciation, depletion, and amortization increased from $9.20 per Boe sold for the three months ended March 31, 2025 to $9.92 per Boe sold for the three months ended March 31, 2026. The increase is primarily related to the production associated with the Williston Acquisition, which has a higher rate than the historical properties.

General and administrative

General and administrative (“G&A”) expenses increased $2.4 million, or 97%, from $2.4 million for the three months ended March 31, 2025 to $4.8 million for the three months ended March 31, 2026. The increase is primarily attributable to higher personnel costs of $1.7 million, principally due to amortization of unit-based compensation.

On a per unit basis, G&A expense increased from $1.05 per Boe sold for the three months ended March 31, 2025 to $1.66 per Boe sold for the three months ended March 31, 2026. The increase is primarily related to increased costs partially offset by increased production.

Other income

Other income decreased $0.7 million, or 7%, from $9.5 million for the three months ended March 31, 2025 to $8.9 million for the three months ended March 31, 2026. The decrease is primarily attributable to lower CO2 and plant income of $1.7 million and the absence of bonus payments from term leases of $1.2 million partially offset by increased marketing income of $1.5 million. 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 $2.1 million, or 59%, from $3.6 million for the three months ended March 31, 2025 to $5.7 million for the three months ended March 31, 2026. The increase is primarily attributable to increased borrowings partially offset by a lower average 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 $270.0 million at March 31, 2026 and $284.0 million at December 31, 2025, and the remaining availability under our Credit Facility was $140.0 million at March 31, 2026 and $126.0 million at December 31, 2025. Additionally, we had negative net working capital (including cash and excluding the effects of derivative instruments) of $70.0 million at March 31, 2026 and negative net working capital of $71.8 million at December 31, 2025. The negative working capital of $70.0 million at March 31, 2026 and $71.8 million at December 31, 2025 is primarily related to the $70.0 million deferred payment on the Williston Acquisition that is due July 31, 2026.

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. Our first quarter distribution of $0.36 per unit with respect to cash available for distribution for the three months ended March 31, 2026, was declared on May 4, 2026 and will be paid on May 22, 2026 to unitholders of record on May 15, 2026.

Our acquisition and development expenditures consist of acquisitions of proved, unproved and other property and development expenditures. Our capital expenditures including acquisitions and net of sales were $4.4 million for the three months ended March 31, 2026 and $6.8 million for the three months ended March 31, 2025 Included in the three months ended March 31, 2026, is $6.2 million related to TXO Partners' share of deposits related to the Cross Timbers Transactions.

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 $8.7 million for drilling, completion and recompletion activities and facilities costs in the three months ended March 31, 2026 and we have budgeted approximately $70.0 million for such costs in 2026.

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 2026 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,
	2026			2025
Net cash provided by operating activities	$	33,408		$	30,610
Net cash used by investing activities		(4,381	)		(6,843	)
Net cash used by financing activities		(30,515	)		(20,230	)

Three Months Ended March 31, 2026 Compared to Three Months Ended March 31, 2025

Net cash provided by operating activities

Net cash provided by operating activities increased $2.8 million for the three months ended March 31, 2026 compared to the three months ended March 31, 2025 due to increased production and improved operating results, excluding the effects of derivatives partially offset by higher expenses and lower oil, gas and NGL prices.

Net cash used by investing activities

Net cash used by investing activities decreased $2.5 million for the three months ended March 31, 2026 compared to the three months ended March 31, 2025 due to proceeds from sale of property and equipment of $6.3 million partially offset by an increase in proved property acquisitions of $2.5 million and development costs of $1.1 million.

Net cash used by financing activities


	Three Months Ended March 31,
	2026			2025
	(in thousands)
Proceeds from long-term debt	$	23,000		$	36,000
Payments on long-term debt		(37,000	)		(31,000	)
Proceeds from sale of units to cover withholding taxes		1,508			1,215
Withholding taxes paid on vesting of restricted units		(1,446	)		(1,151	)
Debt issuance costs		(13	)		—
Distributions		(16,564	)		(25,294	)
Net cash used by financing activities	$	(30,515	)	$	(20,230	)

Net cash used by financing activities increased $10.3 million for the three months ended March 31, 2026 compared to the three months ended March 31, 2025 primarily due to increased net repayments under our Credit Facility of $19.0 million partially offset by decreased distributions to unitholders of $8.7 million.

Revolving credit agreement

On July 31, 2025, we entered into Amendment No. 5 to our 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. 5 increased the borrowing base from $275 million to $410 million, extended the maturity date to August 30, 2029 and joined certain new Lenders to the Credit Facility.

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.

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). The weighted average interest rate on Credit Facility borrowings was 7.4% in the three months ended March 31, 2026.

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-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, 2026. 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 $270.0 million debt outstanding and $140.0 million available under our Credit Facility as of March 31, 2026.

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, 2026, the current liability related to such contracts was $56.0 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, 2026, we had asset retirement obligations of $225.0 million inclusive of a current portion of $3.5 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 February 26, 2026.

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 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, 2026, the fair market value of our oil, NGL and natural gas derivative contracts was a net liability of $56.9 million. Based upon our open commodity derivative positions at March 31, 2026, a hypothetical 10% change in the NYMEX WTI, Henry Hub prices, OPIS prices and basis prices would change our net oil, NGL and natural gas derivative liability by approximately $40.6 million.


(in thousands)	Fair Value at March 31, 2026			Hypothetical Price Increase or Decrease of 10% Price Change
Derivative asset (liability) – Crude Oil	$	(62,399	)	$	32,014
Derivative asset (liability) – Natural Gas Liquids	$	42		$	34
Derivative asset (liability) – Natural Gas	$	5,481		$	8,525
Net derivative liability	$	(56,876	)	$	40,573

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, 2025, we had three customers and December 31, 2024, we had two customers 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, 2026, 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, 2026, we had $270.0 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 $2.7 million per year. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Revolving credit agreement.”


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)


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


Large accelerated filer	☐	Accelerated filer	☒
Non-accelerated filer	☐	Smaller reporting company	☐
		Emerging growth company	☒


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)

10.1*#	TXO Partners GP, LLC Executive Severance Plan

10.2	Purchase and Sale Agreement with CTOC, dated as of March 10, 2026 (incorporated by reference to Exhibit 2.1 to Current Report on Form 8-K filed on March 10, 2026)

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

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

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

32.2*	Certification of Co-Chief Executive Officer 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 with Embedded Linkbase Documents

104	Cover Page Interactive Data File (embedded within the Inline XBRL document)


	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


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


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


		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		16
Item 3. Quantitative and Qualitative Disclosures About Market Risk		25
Item 4. Controls and Procedures		27
Part II - Other Information
Item 1. Legal Proceedings		28
Item 1A. Risk Factors		28
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds		28
Item 3. Defaults Upon Senior Securities		28
Item 4. Mine Safety Disclosures		28
Item 5. Other Information		28
Item 6. Exhibits		29
Signatures		30