0001559432--12-312023Q2false
(a) Changes in Operating Assets and Liabilities
Accounts receivable$21,834 $(24,461)
Other current assets903 (2,081)
Aid-in-construction— 238 
Current liabilities(10,059)20,879 
Other operating liabilities(668)(170)
$12,010 $(5,595)
0.0394
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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(Mark One)
xQUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended June 30, 2023
OR
oTRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from ______ to ______
Commission file number 001-04321
TXO Partners, L.P.
(Exact name of registrant as specified in its charter)
Delaware32-0368858
(State or other jurisdiction of
incorporation or organization)
(I.R.S. Employer
Identification No.)
400 West 7th Street, Fort Worth, Texas
76102
(Address of Principal Executive Offices)(Zip Code)
(817) 334-7800
(Registrant's telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act:
Title of each classTrading Symbol(s)Name of each exchange on which registered
Common UnitsTXONew York Stock Exchange
Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports); and (2) has been subject to such filing requirements for the past 90 days. Yes x No o
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes x No o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):
Large accelerated fileroAccelerated filero
Non-accelerated filerxSmaller reporting companyo
Emerging growth companyx
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. o
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes o No x
The registrant had outstanding 30,750,000 common units as of August 8, 2023.


TABLE OF CONTENTS
i

Part I - Financial Information
Item 1. Financial Statements
TXO PARTNERS, L.P.
Consolidated Balance Sheets
(in thousands)
June 30,
2023
December 31,
2022
(Unaudited)
ASSETS
Current Assets:
Cash and cash equivalents$4,440 $9,204 
Accounts receivable, net30,419 52,304 
Derivative fair value4,800 1,242 
Other10,374 11,277 
Total Current Assets50,033 74,027 
Property and Equipment, at cost – successful efforts method:
Proved properties1,507,319 1,481,233 
Unproved properties18,466 18,406 
Other83,432 82,210 
Total Property and Equipment1,609,217 1,581,849 
Accumulated depreciation, depletion and amortization(767,924)(745,444)
Net Property and Equipment841,293 836,405 
Other Assets:
Note receivable from related party7,131 7,131 
Derivative fair value 290 
Other2,434 6,779 
Total Other Assets9,565 14,200 
TOTAL ASSETS$900,891 $924,632 
LIABILITIES AND PARTNERS’ CAPITAL
Current Liabilities:
Accounts payable$9,793 $14,686 
Accrued liabilities26,546 34,128 
Derivative fair value13,412 95,371 
Asset retirement obligation, current portion2,500 2,500 
Other current liabilities779 779 
Total Current Liabilities53,030 147,464 
Long-term Debt21,100 120,100 
Other Liabilities:
Asset retirement obligation129,070 123,958 
Derivative fair value9,199 10,401 
Other liabilities462 1,172 
Total Other Liabilities138,731 135,531 
Commitments and Contingencies
Partners’ Capital:
Partners’ capital688,030 521,537 
TOTAL LIABILITIES AND PARTNERS’ CAPITAL$900,891 $924,632 
See accompanying notes to the Consolidated Financial Statements
1

TXO PARTNERS, L.P.
Consolidated Statements of Operations (Unaudited)
(in thousands)
Three Months Ended June 30,Six months ended June 30,
2023202220232022
REVENUES
Oil and condensate$47,691 $44,138 $97,312 $41,608 
Natural gas liquids7,033 12,852 16,156 15,973 
Gas5,748 35,887 105,403 25,758 
Total Revenues60,472 92,877 218,871 83,339 
EXPENSES
Production39,357 36,155 74,681 61,181 
Exploration16 113 83 200 
Taxes, transportation and other15,088 24,532 43,991 48,019 
Depreciation, depletion and amortization11,543 9,937 22,481 19,717 
Accretion of discount in asset retirement obligation2,159 1,493 4,277 2,970 
General and administrative1,084 92 3,306 488 
Total Expenses69,247 72,322 148,819 132,575 
OPERATING INCOME (LOSS)(8,775)20,555 70,052 (49,236)
OTHER INCOME (EXPENSE)
Other income6,720 5,556 13,034 11,428 
Interest income127 17 234 23 
Interest expense(618)(1,650)(2,057)(3,320)
Total Other Income6,229 3,923 11,211 8,131 
NET INCOME (LOSS)$(2,546)$24,478 $81,263 $(41,105)
NET INCOME (LOSS) PER COMMON UNIT
Basic$(0.08)$0.98$2.73$(1.64)
Diluted$(0.08)$0.98$2.68$(1.64)
WEIGHTED AVERAGE COMMON UNITS OUTSTANDING
Basic30,750 25,000 29,772 25,000 
Diluted30,750 25,000 30,313 25,000 
See accompanying notes to the Consolidated Financial Statements
2

TXO PARTNERS, L.P.
Consolidated Statements of Cash Flows (Unaudited)
(in thousands)
Six months ended June 30, 2023
20232022
OPERATING ACTIVITIES
Net income (loss) $81,263 $(41,105)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization22,481 19,717 
Accretion of discount in asset retirement obligation4,277 2,970 
Derivative fair value (gain) loss(8,235)134,328 
Net cash paid to counterparties(78,194)(42,167)
Non-cash incentive compensation1,591  
Other non-cash items360 340 
Changes in operating assets and liabilities (a)
12,010 (5,595)
Cash Provided by Operating Activities35,553 68,488 
INVESTING ACTIVITIES
Proved property acquisitions(6,105)(3,754)
Development costs(21,196)(2,201)
Unproved property acquisitions(60)(49)
Other property and asset additions(1,222)(1,895)
Cash Used by Investing Activities(28,583)(7,899)
FINANCING ACTIVITIES
Proceeds from long-term debt48,000 751,000 
Payments on long-term debt(147,000)(804,000)
Net proceeds from initial public offering106,277  
Capitalized offering costs (544)
Debt issuance costs(110)(91)
Distributions(18,901)(6,480)
Cash Used by Financing Activities(11,734)(60,115)
(DECREASE) INCREASE IN CASH AND CASH EQUIVALENTS(4,764)474 
Cash and Cash Equivalents, beginning of period9,204 7,547 
Cash and Cash Equivalents, end of period$4,440 $8,021 
(a) Changes in Operating Assets and Liabilities
Accounts receivable$21,834 $(24,461)
Other current assets903 (2,081)
Aid-in-construction 238 
Current liabilities(10,059)20,879 
Other operating liabilities(668)(170)
$12,010 $(5,595)
See accompanying notes to the Consolidated Financial Statements
3

TXO PARTNERS, L.P.
Consolidated Statements of Members’ Equity (Unaudited)
(in thousands)

Series 3
Preferred
Series 5
Preferred
CommonTotal
Balances, March 31, 2023$ $ $708,525 $708,525 
Net loss— — (2,546)(2,546)
Expensing of unit awards— — 952 952 
Distributions to unitholders— — (18,901)(18,901)
Balances, June 30, 2023$ $ $688,030 $688,030 

Series 3
Preferred
Series 5
Preferred
CommonTotal
Balances, March 31, 2022$34,295 $206,074 $235,407 $475,776 
Net income— — 24,478 24,478 
Increase in partners’ equity from in-kind distributions— — 857 857 
In-kind distributions— — (857)(857)
Distributions— — (6,480)(6,480)
Balances, June 30, 2022$34,295 $206,074 $253,405 $493,774 

Series 3
Preferred
Series 5
Preferred
CommonTotal
Balances, December 31, 2022$ $206,074 $315,463 $521,537 
Net income— — 81,263 81,263 
Net proceeds from initial public offering— — 102,540 102,540 
Expensing of unit awards— — 1,591 1,591 
Distributions to unitholders— — (18,901)(18,901)
Conversion of Series 5 preferred to Common equity— $(206,074)$206,074 $ 
Balances, June 30, 2023$ $ $688,030 $688,030 

Series 3
Preferred
Series 5
Preferred
CommonTotal
Balances, December 31, 2021$34,295 $206,074 $300,990 $541,359 
Net loss— — (41,105)(41,105)
Increase in partners’ equity from in-kind distributions— — 857 857 
In-kind distributions— — (857)(857)
Distributions to unitholders— — (6,480)(6,480)
Balances, June 30, 2022$34,295 $206,074 $253,405 $493,774 




See accompanying notes to the Consolidated Financial Statements
4

TXO PARTNERS, L.P.
Notes to Consolidated Financial Statements
1.Organization and Summary of Significant Accounting Policies
TXO Partners, L.P. (TXO Partners or the Partnership) is an independent oil and gas company that was formed as a Delaware limited partnership in January 2012 (with an effective inception of operations at January 18, 2012). The operations of TXO Partners are governed by the provisions of the partnership agreement, as amended, executed by the general partner, TXO Partners GP, LLC (the General Partner) and the limited partners. The General Partner is the manager and operator of TXO Partners. The General Partner is managed by the board of directors and executive officers of our General Partner. The members of the board of directors of our General Partner are appointed by MorningStar Oil & Gas, LLC (“MSOG”), as the sole member of our General Partner. TXO Partners will remain in existence unless and until dissolved in accordance with the terms of the partnership agreement.
TXO Partners’ assets include its investment in an unincorporated joint venture, Cross Timbers Energy, LLC (“Cross Timbers Energy”). TXO Partners owns 50% of Cross Timbers Energy, and TXO Partners is the manager of Cross Timbers Energy. Cross Timbers Energy is governed by a Member Management Committee (MMC) and is comprised of six representatives, three from each group, with each group having one voting member. All matters that come before the MMC require the unanimous consent of the voting members. On the last day of each calendar quarter, Cross Timbers Energy distributes all excess cash to the members based on their ownership percentage of 50% each, except for earnings from the note receivable which is owned 5% by TXO Partners. Cross Timbers Energy’s properties are located primarily in the San Juan Basin of New Mexico and Colorado and the Permian Basin of West Texas and New Mexico.
TXO Partners also has a wholly-owned subsidiary, MorningStar Operating LLC which owns oil and gas assets primarily in the San Juan Basin of New Mexico and Colorado and the Permian Basin of West Texas and New Mexico.
Reorganization and Public Listing of Common Units

In January, 2023, we completed a series of reorganization transactions in conjunction with publicly listing our common units on the New York Stock Exchange. These included the following transactions (the ‘Reorganization Transactions’):

We effectuated a one-for-25.33 reverse unit split;
We caused the exchange of all outstanding Series 5 preferred units for 10,644,484 common units, resulting in our capital structure to consist of a single class of common units;
All limited partner holders party to our amended and restated agreement of limited partnership contributed all of the outstanding equity interests in us to a new parent company, MorningStar Partners II, L.P., a Delaware limited partnership (“MSP II”) in exchange for equity interests in MSP II; and
We amended our governing documents to, among other things, (i) change our name from “MorningStar Partners, L.P.” to “TXO Energy Partners, L.P.” and (ii) reflect the General Partner as our new non-economic general partner.

As a result of these transactions, the capital structure has been reflected as if the new number of units had been in place for all periods presented.

In May 2023, we amended our Certificate of Formation to change our name to “TXO Partners, L.P.” and the General Partner amended its Certificate of Formation to change its name to “TXO Partners GP, LLC.”

2.Basis of Presentation and Significant Accounting Policies
The 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, 2022 included in our Annual Report on Form 10-K for the year ended December 31, 2022. The consolidated balance sheet as of June 30, 2023 and the consolidated statements of operations, members’ equity 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
5

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, 2022.
3.Related Party Transactions
We earned management fees from Cross Timbers Energy of $1.4 million for the three months ended June 30, 2023 and $1.5 million for the three months ended June 30, 2022 We earned management fees from Cross Timbers Energy of $2.8 million for the six months ended June 30, 2023 and $3.0 million for the six months ended June 30, 2022.
4.Debt
(in thousands)June 30,
2023
December 31,
2022
Credit Facility, 8.7% at June 30, 2023 and 7.8% at December 31, 2022
$14,000 $113,000 
September 2016 Loan, 8.4% at June 30, 2023 and 7.4% at December 31, 2022
$7,100 $7,100 
Total Long-term Debt$21,100 $120,100 
November 2021 Credit Facility
On November 1, 2021, we entered into a four-year, $165 million senior secured credit facility (the “Credit Facility”) with certain commercial banks, as the lenders, and JPMorgan Chase Bank, N.A., as the administrative agent. The Credit Facility has a maturity date of November 1, 2025. On June 28, 2023, we entered into an amendment to the Credit Facility (the “Second Amendment”) to make certain changes as described below. We use the Credit Facility for general corporate purposes. In connection with entering into the Credit Facility, we incurred financing fees and expenses of approximately $3.0 million as of June 30, 2023 and $2.8 million as of December 31, 2022 before accumulated amortization of $1.2 million as of June 30, 2023 and $0.8 million as of December 31, 2022. 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, and scheduled borrowing base redeterminations occur semi-annually, in March and September. Interim redeterminations, may occur between scheduled redeterminations at the lenders sole discretion or upon our request. 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 Cross Timbers Energy, (ii) all our deposit accounts, securities accounts, and commodities accounts, (iii) any receivables owed to us by Cross Timbers Energy 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 current assets and 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 each calculated quarterly. 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. Effective with the Second Amendment, our hedge requirements are based on availability under the Credit Facility and the Leverage Ratio. If the Leverage Ratio is greater than 0.75 to 1.00, we are required to hedge at least 50% of reasonably anticipated projected production of proved developed producing reserves for the 24 months following the end of the most recent quarter. If the Leverage ratio is less than 0.75 to 1.00 and availability under the Credit Facility is greater than 20% of the then current borrowing base, the minimum required hedge volume would be
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35% for the 12 months following the end of the most recent quarter. If the Leverage ratio is less than 0.5 to 1.0 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 as amended by the Second Amendment, we were in compliance with all of our debt covenants as of June 30, 2023. From September 30, 2022 through the spring redetermination, we received waivers to reduce the hedging requirement from 30 months to 15 months and from 50% to 45% of the reasonably anticipated projected production. As a result, we were in compliance with all of our debt covenants as of December 31, 2022. 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 (either one, three or six months) 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 0.50% 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.

We utilized the proceeds from our initial public offering and cash on hand to pay down our credit facility.
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 5). The loan matures on January 31, 2026, 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) London Interbank Offered Rate (“LIBOR”) plus three and one-quarter of one percent (3.25%) per annum, adjusted monthly or (b) the highest rate permitted by applicable law. Though the note is unsecured, we are required to stay in compliance with terms of the Credit Facility.
5.Note Receivable from Related Party
As of June 30, 2023 and December 31, 2022, we, through our 5% ownership interest in investment assets at Cross Timbers Energy, had a note receivable totaling $7.1 million outstanding with a highly-rated, offshore subsidiary of Exxon Mobil Corporation. Under the terms of the agreement, there is no stated maturity date and Cross Timbers Energy may demand repayment of all or any portion of the outstanding balance on two business days’ notice. Interest is earned based on the one-month SOFR rate and is paid monthly. Interest income totaled $0.2 million in the first six months of 2023 and less than $0.1 million in the first six months of 2022.
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.
6.Asset Retirement Obligation
Our asset retirement obligation primarily represents the estimated present value of the amount we will incur to plug, abandon and remediate our proved producing properties at the end of their productive lives, in accordance with applicable state and federal laws. We determine our asset retirement obligation by calculating the present value of estimated cash
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flows related to the liability. The following is a summary of changes in TXO Partners’ asset retirement obligation activity for the six months ended June 30, 2023:
(in thousands)
Asset retirement obligation, January 1$126,458 
Liability incurred upon acquiring and drilling wells1,151 
Liability settled upon plugging and abandoning wells(316)
Accretion of discount expense4,277 
Asset retirement obligation, June 30131,570 
Less current portion(2,500)
Asset retirement obligation, long term$129,070 
7.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.
8.Fair Value
We 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 9).
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 June 30, 2023 and December 31, 2022. The following are estimated fair values and carrying values of our other financial instruments at each of these dates:
Asset (Liability)
June 30, 2023December 31, 2022
(in thousands)Carrying
Amount
Fair
Value
Carrying
Amount
Fair
Value
Note receivable from related party$7,131 $7,131 $7,131 $7,131 
Long-term debt$(21,100)$(21,100)$(120,100)$(120,100)
Derivative asset$4,800 $4,800 $1,532 $1,532 
Derivative liability$(22,611)$(22,611)$(105,772)$(105,772)
The fair value of our note receivable from related party approximates the carrying amount because the interest rate is based on current market interest rates and can be called upon two business days’ notice (Note 5). 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 4).
The fair value of our note receivable from related party (Note 5), derivative asset/(liability) (Note 9) and our long-term debt (Note 4) is measured using Level 2 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 net 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 net derivative asset (liability).
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The following table summarizes our fair value measurements and the level within the fair value hierarchy in which the fair value measurements fall.
Fair Value Measurements
June 30, 2023December 31, 2022
(in thousands)Significant
Other
Observable
Inputs
(Level 2)
Significant
Unobservable
Inputs
(Level 3)
Significant
Other
Observable
Inputs
(Level 2)
Significant
Unobservable
Inputs
(Level 3)
Note receivable from related party$7,131 $ $7,131 $ 
Long-term debt$(21,100)$ $(120,100)$ 
Derivative asset$4,800 $ $1,532 $ 
Derivative liability$(22,611)$ $(105,772)$ 
Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis
Certain assets and liabilities are measured at fair value on a nonrecurring basis. These assets and liabilities are not measured at fair value on an ongoing basis, but are subject to fair value adjustments whenever events or circumstances indicate that the carrying value of those assets may not be recoverable and are based upon Level 3 inputs. These assets and liabilities can include assets and liabilities acquired in a business combination, proved and unproved natural gas properties, asset retirement obligations and other long-lived assets that are written down to fair value when they are impaired. Such fair value estimates require assumptions and judgments regarding the existence of liabilities, the amount and timing of cash outflows required to settle the liability, what constitutes adequate restoration, inflation factors, credit adjusted discount rates, and consideration of changes in legal, regulatory, environmental and political environments.
We periodically review our long-lived assets to be held and used, including proved oil and natural gas properties, whenever events or circumstances indicate that the carrying value of those assets may not be recoverable. We review our oil and natural gas properties by asset group. The estimated future net cash flows are based upon the underlying reserves and anticipated future pricing. An impairment loss is recognized if the sum of the expected undiscounted future net cash flows is less than the carrying amount of the assets. If the estimated undiscounted future net cash flows are less than the carrying amount of a particular asset, the Partnership recognizes an impairment loss for the amount by which the carrying amount of the asset exceeds the estimated fair value of such assets. The fair value of the proved properties is measured based on the income approach, which incorporates a number of assumptions involving expectations of future product prices, which the Partnership bases on the forward-price curves, estimates of oil and gas reserves, estimates of future expected operating and capital costs and a risk adjusted discount rate of 10%. These inputs are categorized as Level 3 in the fair value hierarchy.
Commodity Price Hedging Instruments
We periodically enter into futures contracts, energy swaps, swaptions, collars and basis swaps to hedge our exposure to price fluctuations on crude oil, natural gas and natural gas liquids sales. When actual commodity prices exceed the fixed price provided by these contracts we pay this excess to the counterparty, and when the commodity prices are below the contractually provided fixed price, we receive this difference from the counterparty. See Note 9.
The fair value of our derivatives contracts consists of the following:
Asset DerivativesLiability Derivatives
(in thousands)June 30,
2023
December 31,
2022
June 30,
2023
December 31,
2022
Derivatives not designated as hedging instruments:
Crude oil futures and differential swaps$442 $968 $(3,173)$(13,594)
Natural gas liquids futures$282 $ $(183)$(524)
Natural gas futures, collars and basis swaps$4,076 $564 $(19,255)$(91,654)
Total$4,800 $1,532 $(22,611)$(105,772)
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Derivative fair value (gain) loss, included as part of the related revenue line on the consolidated income statements, comprises the following realized and unrealized components:
Three Months Ended June 30,Six Months Ended
June 30,
(in thousands)2023202220232022
Net cash (received from) paid to counterparties$(2,244)$27,003 $78,194 $42,167 
Non-cash change in derivative fair value$9,065 $808 $(86,429)$92,161 
Derivative fair value (gain) loss$6,821 $27,811 $(8,235)$134,328 
Concentrations of Credit Risk
Our receivables are from a diverse group of companies including major energy companies, pipeline companies, local distribution companies, marketing companies and end-users in various industries. Letters of credit or other appropriate security are obtained as considered necessary to limit risk of loss from the other companies. Including the bank that issued the letter of credit, we currently have greater concentrations of credit with several investment-grade (BBB- or better) rated companies.
9.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 enter futures contracts, energy swaps, swaptions and basis swaps to hedge our exposure to price fluctuations on crude oil, natural gas liquids and natural gas sales. When actual commodity prices exceed the fixed price provided by these contracts we pay this excess to the counterparty, and when the commodity prices are below the contractually provided fixed price, we receive this difference from the counterparty. We also enter costless price collars, which set a ceiling and floor price to hedge our exposure to price fluctuations on natural gas sales. When actual commodity prices exceed the ceiling price provided by these contracts we pay this excess to the counterparty, and when the commodity prices are below the floor price, we receive this difference from the counterparty. If the actual commodity price falls in between the ceiling and floor price, there is no cash settlement.
Crude Oil
We have entered into crude oil futures contracts and swap agreements that effectively fix prices for the production and periods shown below. Prices to be realized for hedged production may be less than these fixed prices because of location, quality and other adjustments. See Note 8.
Production PeriodBbls per DayWeighted Average
NYMEX
Price per Bbl
July 2023—December 20232,500$68.87 
January 2024—June 20242,000$63.27 
The price we receive for our oil production is generally different than the NYMEX price because of adjustments for delivery location (“basis”), relative quality and other factors. We have entered sell basis swap agreements that effectively fix the basis adjustment for the West Texas Midland delivery location for the production and periods shown below.
Production PeriodBbls per DayWeighted Average
Sell Basis
Price per Bbl (a)
July 2023—December 20235,000$1.21 
_________________________________
(a)Increases to NYMEX oil price for delivery location
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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 PeriodBbls per DayWeighted Average
Roll
Price per Bbl (a)
July 2023—December 20233,000$0.89 
_________________________________
(a)Increases to NYMEX oil price for roll component
Net settlements on oil futures and sell basis swap contracts decreased oil revenues by $0.7 million in the three months ended June 30, 2023 and $12.9 million in the three months ended June 30, 2022. Net settlements on oil futures and sell basis swap contracts decreased oil revenues by $2.1 million in the six months ended June 30, 2023 and $20.7 million in the six months ended June 30, 2022. An unrealized gain increased oil revenues by $3.7 million in the three months ended June 30, 2023 and $0.1 million in three months ended June 30, 2022. An unrealized gain increased oil revenues by $9.9 million in the six months ended June 30, 2023 and an unrealized loss decreased oil revenues by $43.1 million in six months ended June 30, 2022.
Natural Gas Liquids
We have entered into natural gas liquids futures contracts and swap agreements for ethane that effectively fix prices for the production and periods shown below. Prices to be realized for hedged production may be less than these fixed prices because of location, quality and other adjustments. See Note 8.
Production PeriodGallons per DayWeighted Average
NGL OPIS
Price per Gallon
Ethane
July 2023—December 202363,000$0.27 
January 2024—June 202463,000$0.23 
Net settlements on NGL futures contracts increased NGL revenues by $0.3 million in the three months ended June 30, 2023 and decreased NGL revenues by $2.2 million in the three months ended June 30, 2022. Net settlements on NGL futures contracts increased NGL revenues by $0.4 million in the six months ended June 30, 2023 and decreased NGL revenues by $3.4 million in the six months ended June 30, 2022. An unrealized loss decreased NGL revenues by $0.6 million in the three months ended June 30, 2023 and an unrealized gain increased NGL revenues by $1.1 million in the three months ended June 30, 2022. An unrealized gain increased NGL revenues by $0.6 million in the six months ended June 30, 2023 and an unrealized loss decreased NGL revenues by $6.1 million in the six months ended June 30, 2022.
Natural Gas
We have entered into natural gas futures contracts and swap agreements that effectively fix prices for the production and periods shown below. Prices to be realized for hedged production may be less than these fixed prices because of location, quality and other adjustments. See Note 8.
Production PeriodMMBtu per DayWeighted Average
NYMEX
Price per MMBtu
July 2023—December 202335,000$3.51 
January 2024—June 202430,000$3.26 
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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 PeriodMMBtu per DayFloorCeiling
January 2024—June 20245,000$3.75 $7.25 
The price we receive for our gas production is generally less than the NYMEX price because of adjustments for delivery location (“basis”), relative quality and other factors. We have entered sell basis swap agreements that effectively fix the basis adjustment for the San Juan Basin delivery location for the production and periods shown below.
Production PeriodMMBtu per DayWeighted Average
Sell Basis
Price per MMBtu(a)
July 2023—December 202350,000$0.18 
January 2024—December 2024
20,000$0.25 
_________________________________
(a)Reductions to NYMEX gas price for delivery location
Net settlements on gas futures and sell basis swap contracts increased gas revenues by $2.7 million in the three months ended June 30, 2023 and decreased gas revenues by $11.9 million in the three months ended June 30, 2022. Net settlements on gas futures and sell basis swap contracts decreased gas revenues by $76.5 million in the six months ended June 30, 2023 and $18.1 million in the six months ended June 30, 2022. An unrealized loss to record the fair value of derivative contracts decreased gas revenues by $12.1 million in the three months ended June 30, 2023 and $1.9 million in the three months ended June 30, 2022. An unrealized gain to record the fair value of derivative contracts increased gas revenues by $75.9 million in the six months ended June 30, 2023 and an unrealized loss decreased gas revenues by $42.9 million in the six months ended June 30, 2022.


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10. Earnings per Unit

The following represents basic and diluted earnings (loss) per Common Unit upon the Reorganization (See Note 1) and corresponding issuance of 5.8 million Common Units for the three and six months ended June 30, 2023 and 2022:

(in thousands, except per unit data)Net income (loss)UnitsIncome (loss) per Unit
Three Months Ended June 30, 2023
Basic$(2,546)30,750 $(0.08)
Effect of dilutive securities  
Diluted$(2,546)30,750 $(0.08)
Three Months Ended June 30, 2022
Basic$24,478 25,000 $0.98
Effect of dilutive securities  
Diluted$24,478 25,000 $0.98
Six Months Ended June 30, 2023
Basic$81,263 29,772 $2.73
Effect of dilutive securities 541 
Diluted$81,263 30,313 $2.68
Six Months Ended June 30, 2022
Basic$(41,105)25,000 $(1.64)
Effect of dilutive securities  
Diluted$(41,105)25,000 $(1.64)

All restricted units, totaling 538 thousand units, were excluded from the calculation of earnings per share for the three months ended June 30, 2023, because the units are anti-dilutive.

11. Partners’ Capital
On August 8, 2023, the board of directors of our general partner declared a cash distribution of $0.48 per common unit for the quarter ended June 30, 2023. The distribution will be paid on August 25, 2023, to unitholders of record on August 18, 2023.
On May 9, 2023, the board of directors of our general partner declared a cash distribution of $0.50 per common unit for the quarter ended March 31, 2023. The distribution was paid on May 30, 2023, to unitholders of record on May 22, 2023.

12. 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.
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As discussed in Note 9, 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 June 30, 2023
Oil and
condensate
Natural gas
liquids
Natural gasTotal
Revenues
(in thousands)
Revenue from customers$44,783 $7,322 $15,188 $67,293 
Unrealized gain (loss) on derivatives3,658 (600)(12,123)(9,065)
Realized gain (loss) on derivatives(750)311 2,683 2,244 
Total revenues$47,691 $7,033 $5,748 $60,472 
Three Months Ended June 30, 2022
Oil and
condensate
Natural gas
liquids
Natural gasTotal
Revenues
(in thousands)
Revenue from customers$57,003 $13,936 $49,749 $120,688 
Unrealized gain (loss) on derivatives68 1,068 (1,944)(808)
Realized gain (loss) on derivatives(12,933)(2,152)(11,918)(27,003)
Total Revenues$44,138 $12,852 $35,887 $92,877 
Six Months Ended June 30, 2023
Oil and
condensate
Natural gas
liquids
Natural gasTotal
Revenues
(in thousands)
Revenue from customers$89,482 $15,137 $106,017 $210,636 
Unrealized gain (loss) on derivatives9,896 622 75,911 86,429 
Realized gain (loss) on derivatives$(2,066)$397 $(76,525)$(78,194)
Total revenues$97,312 $16,156 $105,403 $218,871 
Six Months Ended June 30, 2022
Oil and
condensate
Natural gas
liquids
Natural gasTotal
Revenues
(in thousands)
Revenue from customers$105,410 $25,484 $86,773 $217,667 
Unrealized gain (loss) on derivatives(43,132)(6,127)(42,902)(92,161)
Realized gain (loss) on derivatives(20,670)(3,384)(18,113)(42,167)
Total revenues$41,608 $15,973 $25,758 $83,339 
Natural Gas and NGL Sales
Under our natural gas processing contracts, we deliver natural gas to a midstream processing entity at the wellhead or at the inlet of a facility. The midstream provider gathers and processes the product and both the residue gas and the resulting natural gas liquids are sold at the tailgate of the plant. The Partnership’s natural gas production is primarily sold under market-sensitive contracts that are typically priced at a differential to the published natural gas index price for the producing area due to the natural gas quality and the proximity to the market. We evaluated these arrangements and determined that control of the products transfers at the tailgate of the plant, meaning that the Partnership is the principal and the third-party purchaser is its customer. As such, we present the gas and NGL sales on a gross basis and the related gathering and processing costs as a component of taxes, transportation, and other on the statement of operations.
Oil and Condensate Sales
Oil production is sold at the wellhead 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
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the customer. This treatment after the adoption of ASC 606 is consistent with the treatment under ASC 605 and has no impact on revenues or expenses on the statement of operations.
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.
13. Employee Benefit Plans

In connection with the initial public offering, the board approved grants of 545,000 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.

The following summarizes the status of nonvested phantom units as of June 30, 2023:

(in thousands, except per unit amounts)Weighted Average Grant Date Fair ValueNumber of Units
Nonvested at January 1, 2023$  
    Grants$20.00 545,000 
    Forfeitures$20.00 (10,000)
Nonvested at June 30, 2023$20.00 535,000 

We recognized compensation expense related to these grants of $1.6 million for the six months ended June 30, 2023 and none for the six months ended June 30, 2022. As of June 30, 2023, we had total deferred compensation expense of $9.1 million. For these non-vested unit awards, we estimate that compensation expense for service periods after June 30, 2023 will be $1.9 million in 2023, $3.5 million in 2024, $3.5 million in 2025 and $0.3 million in 2026. The weighted average remaining vesting period is 2.5 years.
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14.Accrued Liabilities
Accrued liabilities consist of the following at June 30, 2023 and December 31, 2022:
June 30,
2023
December 31,
2022
Accrued production expenses$15,442 $19,846 
Accrued capital expenditures$4,237 $6,654 
Accrued severance taxes$2,676 $4,946 
Accrued ad valorem taxes$2,400 $2,420 
Other accrued liabilities$1,791 $262 
Total accrued liabilities$26,546 $34,128 
15.Supplemental Cash Flow Information
Interest payments totaled $1.7 million for the six months ended June 30, 2023 and $3.4 million for the six months ended June 30, 2022. Income tax payments were $1.1 million during the six months ended June 30, 2023 and $0.5 million during the six months ended June 30, 2022.
16.Subsequent Events
We have evaluated subsequent events through the date the financial statements were available to be issued. See Note 11.
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Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations
The following discussion and analysis should be read in conjunction with our unaudited consolidated financial statements and notes thereto presented in Item 1 of this Quarterly Report. Additionally, the following discussion and analysis should be read in conjunction with our audited consolidated financial statements and notes thereto and the related “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” included in our Annual Report on Form 10-K for the year ended December 31, 2022.

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

Cautionary Statement Regarding Forward-Looking Statements

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

We caution you that these forward-looking statements are subject to all of the risks and uncertainties, most of which are difficult to predict and many of which are beyond our control, incident to the exploration for and development and production of oil, natural gas and 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;

the impact of COVID-19, and governmental measures related thereto, on global demand for oil and natural gas and on the operations of our business;
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 and the San Juan 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;
17


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;

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

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

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

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

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

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

Except as otherwise required by applicable law, we disclaim any duty to update any forward-looking statements, all of which are expressly qualified by the statements in this section, to reflect events or circumstances after the date of this Quarterly Report on Form 10-Q.
Overview
We are an independent oil and natural gas company focused on the acquisition, development, optimization and exploitation of conventional oil, natural gas and natural gas liquid reserves in North America. Our properties are predominately located in the Permian Basin of New Mexico and Texas and the San Juan Basin of New Mexico and Colorado.
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Initial Public Offering
On January 31, 2023, we completed our initial public offering in which we issued and sold 5,000,000 common units at a public offering price of $20.00 per unit. In addition, on February 6, 2023, we sold an additional 750,000 common units pursuant to the underwriters’ option to purchase additional units to cover over-allotments. We received net proceeds of approximately $102 million, after deducting underwriting discounts and commissions and offering expenses borne by us. We utilized the proceeds from our initial public offering and cash on hand to pay down our credit facility.
Market Outlook
The oil and natural gas industry is cyclical and commodity prices are highly volatile. For example, during the period from January 1, 2022 through June 30, 2023, NYMEX prices for crude oil and natural gas reached a high of $123.70 per Bbl and $9.68 per MMBtu, respectively, and a low of $66.74 per Bbl and $1.99 per MMBtu, respectively. Oil prices steadily increased significantly in the first half of 2022 due to increased demand, domestic supply reductions, OPEC control measures and market disruptions resulting from the Russia-Ukraine war and sanctions on Russia. Since the Russia-Ukraine conflict first commenced, WTI crude oil prices have been volatile reaching a high of $123.70 per Bbl in March 2022 before declining to $75.75 per Bbl as of July 18, 2023. Natural gas prices reached a high of $9.68 per MMbtu in August, 2022 before declining to $2.63 per MMbtu as of July 18, 2023.
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.
Although inflation in the United States had been relatively low for many years, there was a significant increase in inflation beginning in the second half of 2021, which has continued into 2023, due to a substantial increase in the money supply, a stimulative fiscal policy, a significant rebound in consumer demand as COVID-19 restrictions were relaxed, the Russia-Ukraine war and worldwide supply chain disruptions resulting from the economic contraction caused by COVID-19 and lockdowns followed by a rapid recovery. Inflation, as measured on an annual basis, rose from 7.0% in December 2021 to a high of 9.1% in June 2022 and fell to 3.0% in June 2023. Global, industry-wide supply chain disruptions have resulted in widespread shortages of labor, materials and services. Such shortages have resulted in our facing significant cost increases for labor, materials and services. Principally, commodity costs for steel and chemicals required for drilling, higher transportation and fuel costs and annual wage increases have increased our operating costs for the three and six months ended June 30, 2023 compared to the same periods in 2022. We also may face shortages of these commodities and labor, which may prevent us from executing on our development plan. We do not expect these shortages and 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 inflation remains elevated, we may experience further cost increases in our operations, including costs for drill rigs, workover rigs, tubulars and other well equipment, as well as increased labor costs. 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 continue to evaluate actions to mitigate supply chain and 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 may 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;
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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.

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Reconciliation of Adjusted EBITDAX and Cash Available for Distribution to GAAP Financial Measures
Three Months Ended June 30,Six Months Ended June 30,
2023202220232022
(in thousands)
Net income (loss)$(2,546)$24,478 $81,263 $(41,105)
Interest expense618 1,650 2,057 3,320 
Interest income(127)(17)(234)(23)
Depreciation, depletion and amortization11,543 9,937 22,481 19,717 
Accretion of discount in asset retirement obligation2,159 1,493 4,277 2,970 
Exploration expense16 113 83 200 
Unrealized (gain)/loss on derivatives9,065 808 (86,429)92,161 
Non-cash incentive compensation952 — 1,591 — 
Adjusted EBITDAX$21,680 $38,462 $25,089 $77,240 
Cash Interest expense(438)(1,478)(1,697)(2,980)
Cash Interest income127 17 234 23 
Exploration expense(16)(113)(83)(200)
Development costs(9,918)(1,505)(21,196)(2,201)
Cash Available for Distribution$11,435 $35,383 $2,347 $71,882 
Net cash provided by operating activities$18,404 $39,823 $35,553 $68,488 
Changes in operating assets and liabilities2,949 (2,935)(12,010)5,595 
Development costs(9,918)(1,505)(21,196)(2,201)
Cash Available for Distribution$11,435 $35,383 $2,347 $71,882 

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Results of Operations

Three Months Ended June 30, 2023 Compared to the Three Months Ended June 30, 2022
Three Months Ended June 30,
20232022
(in thousands)
REVENUES
Oil and condensate$47,691 $44,138 
Natural gas liquids7,033 12,852 
Gas5,748 35,887 
Total Revenues60,472 92,877 
EXPENSES
Production39,357 36,155 
Exploration16 113 
Taxes, transportation and other15,088 24,532 
Depreciation, depletion and amortization11,543 9,937 
Accretion of discount in asset retirement obligation2,159 1,493 
General and administrative1,084 92 
Total Expenses69,247 72,322 
OPERATING INCOME (LOSS)(8,775)20,555 
OTHER INCOME (EXPENSE)
Other income6,720 5,556 
Interest income127 17 
Interest expense(618)(1,650)
Total Other Income6,229 3,923 
NET INCOME (LOSS)$(2,546)$24,478 












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The following table provides a summary of our sales volumes, average prices (both including and excluding the effects of derivatives) and operating expenses on a per Boe basis for the periods indicated:
Three Months Ended June 30,
20232022
Sales:
Oil and condensate sales (MBbls)
620524
Natural gas liquids sales (MBbls)
352345
Natural gas sales (MMcf)
6,9527,602
Total (MBoe)
2,1312,136
Total (MBoe/d)
2323
Average sales prices:
Oil and condensate excluding the effects of derivatives (per Bbl)
$72.28 $108.73 
Oil and condensate (per Bbl) (1)
$76.97 $84.19 
Natural gas liquids excluding the effects of derivatives (per Bbl)
$20.81 $40.39 
Natural gas liquids (per Bbl) (2)
$19.98 $37.25 
Natural gas excluding the effects of derivatives (per Mcf)
$2.18 $6.54 
Natural gas (per Mcf) (3)
$0.83 $4.72 
Expense per Boe:
Production
$18.47 $16.93 
Taxes, transportation and other
$7.08 $11.49 
Depreciation, depletion and amortization
$5.42 $4.65 
General and administrative expenses
$0.51 $0.04 
_________________________________
(1)Oil and condensate prices include both realized losses and unrealized gains and losses from derivatives. Unrealized gains were $3.7 million for the three months ended June 30, 2023 and $0.1 million for the three months ended June 30, 2022. Realized losses were $0.7 million for the three months ended June 30, 2023 and $12.9 million for the three months ended June 30, 2022
(2)Natural gas liquids prices include both realized and unrealized gains and losses from derivatives. Unrealized losses were $0.6 million for the three months ended June 30, 2023 and unrealized gains were $1.1 million for the three months ended June 30, 2022. Realized gains were $0.3 million for the three months ended June 30, 2023 and realized losses were $2.2 million for the three months ended June 30, 2022.
(3)Natural gas prices include both realized losses and unrealized gains and losses from derivatives. Unrealized losses were $12.1 million for the three months ended June 30, 2023 and $1.9 million for the three months ended June 30, 2022. Realized gains were $2.7 million for the three months ended June 30, 2023 and realized losses were $18.1 million for the three months ended June 30, 2022.
Revenues
Revenues decreased $32.4 million, or 35%, from $92.9 million for the three months ended June 30, 2022 to $60.5 million for the three months ended June 30, 2023. The decrease was primarily attributable to a decrease in the average selling price, excluding the effects of derivatives, on oil of 34% resulting in a decrease in revenue of $19.1 million, on NGLs of 48% resulting in a decrease in revenue of $6.8 million and on natural gas of 67% resulting in a decrease in revenue of $33.1 million. These decreases were partially offset by net gains on our hedging activity of $21.0 million, of which $8.3 million were unrealized losses and $29.2 million were realized gains. Additionally, revenue increased $5.6 million in spite of a decrease in production of 6 MBoe primarily as a result of the acquisition of additional interest in the Permian Basin being offset by natural declines in San Juan Basin.
Production expenses
Production expenses increased $3.2 million, or 9%, from $36.2 million for the three months ended June 30, 2022 to $39.4 for the three months ended June 30, 2023. The increase is primarily due to increased maintenance and energy costs.
On a per unit basis, production expenses increased from $16.93 per Boe sold for the three months ended June 30, 2022 to $18.47 per Boe sold for the three months ended June 30, 2023. The increase is primarily related to increased maintenance and energy costs.
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Taxes, transportation, and other
Taxes, transportation, and other decreased $9.4 million, or 38%, from $24.5 million for the three months ended June 30, 2022 to $15.1 million for the three months ended June 30, 2023. The decrease is primarily attributable to the decrease in oil, NGLs and natural gas prices and natural gas production partially offset by increased oil and NGLs production.
On a per unit basis, taxes, transportation, and other decreased from $11.49 per Boe sold for the three months ended June 30, 2022 to $7.08 per Boe sold for the three months ended June 30, 2023. The decrease is primarily related to the lower oil, NGLs and natural gas prices.
Depreciation, depletion, and amortization
Depreciation, depletion, and amortization increased $1.6 million, or 16%, from $9.9 million for the three months ended June 30, 2022 to $11.5 million for the three months ended June 30, 2023. The increase is primarily attributable to the increased production associated with the acquisition of additional interest in the Permian Basin in the third quarter of 2022 of $1.5 million.
On a per unit basis, depreciation, depletion, and amortization increased from $4.65 per Boe sold for the three months ended June 30, 2022 to $5.42 per Boe sold for the three months ended June 30, 2023. The increase is primarily related to changes in production mix.
General and administrative
General and administrative (“G&A”) expenses increased $1.0 million, or 1,078%, from $0.1 million for the three months ended June 30, 2022 to $1.1 million for the three months ended June 30, 2023. The increase is primarily attributable to higher personnel costs of $0.8 million due in part to amortization of unit awards and additional expenses related to the initial public offering in January 2023.
On a per unit basis, G&A expense increased from $0.04 per Boe sold for the three months ended June 30, 2022 to $0.51 per Boe sold for the three months ended June 30, 2023. The increase is primarily related to increased costs and decreased production.
Other income
Other income increased $1.2 million, or 21%, from $5.6 million for the three months ended June 30, 2022 to $6.7 million for the three months ended June 30, 2023. The increase is primarily attributable to higher CO2 and plant income of $1.0 million related to the acquisition of additional interest in the Permian Basin and a $0.2 million increase in marketing income. The CO2 and plant income is ancillary to the operations of the gas processing plant in the Permian Basin in New Mexico and CO2 assets in Colorado we acquired from Chevron in November 2021, which we refer to as the Vacuum properties.
Interest expense
Interest expense decreased $1.0 million, or 63%, from $1.7 million for the three months ended June 30, 2022 to $0.6 million for the three months ended June 30, 2023. The decrease is primarily attributable to the decreased borrowings due in part to the January 2023 initial public offering partially offset by a higher interest rate.




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Six Months Ended June 30, 2023 Compared to the Six Months Ended June 30, 2022
Six months ended June 30,
20232022
(in thousands)
REVENUES
Oil and condensate$97,312 $41,608 
Natural gas liquids16,156 15,973 
Gas105,403 25,758 
Total Revenues218,871 83,339 
EXPENSES
Production74,681 61,181 
Exploration83 200 
Taxes, transportation and other43,991 48,019 
Depreciation, depletion and amortization22,481 19,717 
Accretion of discount in asset retirement obligation4,277 2,970 
General and administrative3,306 488 
Total Expenses148,819 132,575 
OPERATING INCOME (LOSS)70,052 (49,236)
OTHER INCOME (EXPENSE)
Other income13,034 11,428 
Interest income234 23 
Interest expense(2,057)(3,320)
Total Other Income11,211 8,131 
NET INCOME (LOSS)$81,263 $(41,105)













25

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:
Six months ended June 30,
20232022
Sales:
Oil and condensate sales (MBbls)
1,2231,041
Natural gas liquids sales (MBbls)
620647
Natural gas sales (MMcf)
13,85515,153
Total (MBoe)
4,1524,213
Total (MBoe/d)
2323
Average sales prices:
Oil and condensate excluding the effects of derivatives (per Bbl)
$73.16 $101.23 
Oil and condensate (per Bbl) (1)
$79.56 $39.96 
Natural gas liquids excluding the effects of derivatives (per Bbl)
$24.39 $39.42 
Natural gas liquids (per Bbl) (2)
$26.04 $24.71 
Natural gas excluding the effects of derivatives (per Mcf)
$7.65 $5.73 
Natural gas (per Mcf) (3)
$7.61 $1.70 
Expense per Boe:
Production
$17.99 $14.52 
Taxes, transportation and other
$10.59 $11.40 
Depreciation, depletion and amortization
$5.41 $4.68 
General and administrative expenses
$0.80 $0.12 
_________________________________
(1)Oil and condensate prices include both realized losses and unrealized gains and losses from derivatives. Unrealized gains were $9.9 million for the six months ended June 30, 2023 and the unrealized losses were $43.1 million for the six months ended June 30, 2022. Realized losses were $2.1 million for the six months ended June 30, 2023 and $20.7 million for the six months ended June 30, 2022.
(2)Natural gas liquids prices include both realized and unrealized gains and losses from derivatives. Unrealized gains were $0.6 million for the six months ended June 30, 2023 and unrealized losses were $6.1 million for the six months ended June 30, 2022. Realized gains were $0.4 million for the six months ended June 30, 2023 and realized losses were $3.4 million for the six months ended June 30, 2022.
(3)Natural gas prices include both realized losses and unrealized gains and losses from derivatives. Unrealized gains were $75.9 million for the six months ended June 30, 2023 and unrealized losses were $42.9 million for the six months ended June 30, 2022. Realized losses were $76.5 million for the six months ended June 30, 2023 and $18.1 million for the six months ended June 30, 2022.
Revenues
Revenues increased $135.5 million, or 163%, from $83.3 million for the six months ended June 30, 2022 to $218.9 million for the six months ended June 30, 2023. The increase was primarily attributable to net gains on our hedging activity of $142.6 million, of which $178.6 million were unrealized gains and $36.0 million were realized losses. Also, a 34% increase in the average selling price, excluding the effects of derivatives, of natural gas resulted in an increase in revenue of $29.2 million. These high natural gas prices were related to selling to West Coast markets that had higher prices than the rest of the country due to colder weather and transportation constraints in California. Finally, revenue increased $2.7 million in spite of a decrease in production of 60 MBoe primarily as a result of the acquisition of additional interest in the Permian Basin being offset by natural declines in San Juan Basin. These increases were partially offset by a decrease in the average selling price, excluding the effects of derivatives, on oil of 28% resulting in a decrease in revenue of $29.2 million and on NGLs of 38% resulting in a decrease in revenue of $9.7 million.
Production expenses
Production expenses increased $13.5 million, or 22%, from $61.2 million for the six months ended June 30, 2022 to $74.7 million for the six months ended June 30, 2023. Of this increase, $6.1 million is attributable to the acquisition of additional interest in the Permian Basin. The remainder of the increase is primarily due to increased maintenance and energy costs.
On a per unit basis, production expenses increased from $14.52 per Boe sold for the six months ended June 30, 2022 to $17.99 per Boe sold for the six months ended June 30, 2023. The increase is primarily related to the increased costs per
26

Boe from the acquisition of additional interest in the Permian Basin due to the acquired properties having a higher percentage of oil production, which is more expensive on a Boe basis than natural gas production. Additionally, increased maintenance and energy costs contributed to the increase per Boe.
Taxes, transportation, and other
Taxes, transportation, and other decreased $4.0 million, or 8%, from $48.0 million for the six months ended June 30, 2022 to $44.0 million for the six months ended June 30, 2023. The decrease is primarily attributable to the decrease in oil and NGLs prices partially offset by increased natural gas prices.
On a per unit basis, taxes, transportation, and other decreased from $11.40 per Boe sold for the six months ended June 30, 2022 to $10.59 per Boe sold for the six months ended June 30, 2023. The decrease is primarily related to the lower oil and NGLs prices and change in production mix partially offset by higher natural gas prices.
Depreciation, depletion, and amortization
Depreciation, depletion, and amortization increased $2.8 million, or 14%, from $19.7 million for the six months ended June 30, 2022 to $22.5 million for the six months ended June 30, 2023. The increase is primarily attributable to the increased production associated with the acquisition of additional interest in the Permian Basin third quarter of 2022 of $2.7 million.
On a per unit basis, depreciation, depletion, and amortization increased from $4.68 per Boe sold for the six months ended June 30, 2022 to $5.41 per Boe sold for the six months ended June 30, 2023. The increase is primarily related to changes in production mix.
General and administrative
General and administrative (“G&A”) expenses increased $2.8 million, or 577%, from $0.5 million for the six months ended June 30, 2022 to $3.3 million for the six months ended June 30, 2023. The increase is primarily attributable to higher personnel costs of $2.2 million due in part to amortization of unit awards and additional expenses related to the initial public offering in January 2023.
On a per unit basis, G&A expense increased from $0.12 per Boe sold for the six months ended June 30, 2022 to $0.80 per Boe sold for the six months ended June 30, 2023. The increase is primarily related to increased costs and decreased production.
Other income
Other income increased $1.6 million, or 14%, from $11.4 million for the six months ended June 30, 2022 to $13.0 million for the six months ended June 30, 2023. The increase is primarily attributable to higher CO2 and plant income of $2.2 million related to the acquisition of additional interest in the Permian Basin partially offset by $0.6 million decrease in marketing income. The CO2 and plant income is ancillary to the operations of the gas processing plant in the Permian Basin in New Mexico and CO2 assets in Colorado we acquired from Chevron in November 2021, which we refer to as the Vacuum properties.
Interest expense
Interest expense decreased $1.3 million, or 38%, from $3.3 million for the six months ended June 30, 2022 to $2.1 million for the six months ended June 30, 2023. The decrease is primarily attributable to the decreased borrowings due in part to the January 2023 initial public offering partially offset by a higher 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 $113.0 million at December 31, 2022 and $14.0 million at June 30, 2023, and the remaining availability under our Credit Facility was $52.0 million at December 31,
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2022 and $151.0 million at June 30, 2023. Additionally, we had positive net working capital (including cash and excluding the effects of derivative instruments) of $20.7 million at December 31, 2022 and $5.6 million at June 30, 2023.
Our net credit facility debt as of June 30, 2023 was $9.6 million (less cash of $4.4 million) and was incurred primarily to cover our acquisition and capital expenditures for other property of $7.3 million as well as the change in the capital accrual during the six months ended June 30, 2023 of $2.4 million. We expect to repay the debt incurred by us to complete such acquisition and capital expenditures in order to meet our long-term goal of remaining substantially debt free.
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 second quarter distribution of $0.48 per unit with respect to cash available for distribution for the three months ended June 30, 2023, was declared on August 8, 2023 and will be paid on August 25, 2023 to unitholders of record on August 18, 2023.

The first quarter distribution of $0.50 per unit with respect to cash available for distribution for the three months ended March 31, 2023, was declared on May 9, 2023 and paid May 30, 2023 to unitholders of record on May 22, 2023. In accordance with the terms of our partnership agreement, we prorated the amount of the distribution payable for the period from January 31, 2023 (the closing of our initial public offering) through March 31, 2023, based on the actual length of that period.
Our acquisition and development expenditures consist of acquisitions of proved, unproved and other property and development expenditures. Our capital expenditures including acquisitions were $28.6 million for the six months ended June 30, 2023 and $7.9 million for the six months ended June 30, 2022.

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 $18.8 million for drilling, completion and recompletion activities and facilities costs in the six months ended June 30, 2023 and we have budgeted approximately $30.0 million for such costs in 2023.
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 2023 capital development programs from cash flow from operations and net proceeds from the initial public offering.
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.
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Cash flows
The following table summarizes our cash flows for the periods indicated (in thousands):
Six months ended
June 30,
20232022
Net cash provided by operating activities
$35,553 $68,488 
Net cash used by investing activities
(28,583)(7,899)
Net cash used by financing activities
(11,734)(60,115)

Six Months Ended June 30, 2023 Compared to Six Months Ended June 30, 2022
Net cash provided by operating activities
Net cash provided by operating activities decreased $32.9 million for the six months ended June 30, 2023 compared to the six months ended June 30, 2022 due to a decline in operating results, excluding the effects of derivatives, primarily due to lower oil and NGL realizations and increased costs partially offset by improved natural gas realizations.
Net cash used by investing activities
Net cash used by investing activities increased $20.7 million for the six months ended June 30, 2023 compared to the six months ended June 30, 2022 due to an increase in development costs of $19.0 million and increased proved property acquisitions of $2.4 million partially offset by decreased other asset additions of $0.7 million.
Net cash used by financing activities
Six months ended
June 30,
20232022
(in thousands)
Proceeds from long-term debt$48,000 $751,000 
Payments on long-term debt(147,000)(804,000)
Net proceeds from initial public offering106,277 — 
Capitalized offering costs— (544)
Debt issuance costs(110)(91)
Distributions(18,901)(6,480)
Net cash used in financing activities
$(11,734)$(60,115)
Net cash used in financing activities decreased $48.4 million for the six months ended June 30, 2023 compared to the six months ended June 30, 2022 primarily due to proceeds from the initial public offering of $106.3 million partially offset by an increase in net repayments under our credit facility of $46.0 million and increased distributions to unitholders of $12.4 million.
Revolving credit agreement
On November 1, 2021, we entered into a four-year, $165 million senior secured credit facility with certain commercial banks, as the lenders, and JPMorgan Chase Bank, N.A., as the administrative agent. The facility has a maturity date of November 1, 2025 and as of November 3, 2022, the last date of redetermination, our borrowing base was $165 million.
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
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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 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 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 8.3% in the six months ended June 30, 2023.
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. The total EBITDAX calculation includes 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..
We utilized the proceeds from our initial public offering and cash on hand to pay down our credit facility, so that we had $14 million of debt outstanding and $151 million available under our Credit Facility as of June 30, 2023.
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 June 30, 2023, the current liability related to such contracts was $13.4 million and the non-current liability was $9.2 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 9 in the financial statements included elsewhere in this Quarterly Report.
Asset Retirement Obligation
At June 30, 2023, we had asset retirement obligations of $131.6 million inclusive of a current portion of $2.5 million. For further information on asset retirement obligations, see Note 6 in the financial statements included elsewhere in this Quarterly Report.

Critical Accounting Policies

There has been no change in our critical accounting policies from those disclosed in our Annual Report on Form 10-K filed with the SEC on March 31, 2023.
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.
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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 June 30, 2023, the fair market value of our oil, NGL and natural gas derivative contracts was a net liability of $17.8 million. Based upon our open commodity derivative positions at June 30, 2023, a hypothetical 10% change in the NYMEX WTI and Henry Hub prices, OPIS prices and basis prices would change our net oil, NGL and natural gas derivative liability by approximately $11.9 million.
(in thousands)Fair Value at
June 30,
2023
Hypothetical
Price Increase
or Decrease
of
10%
Derivative asset (liability) – Crude Oil
$(2,731)$5,904 
Derivative asset (liability) – Natural Gas Liquids
$99 $565 
Derivative asset (liability) – Natural Gas
$(15,179)$5,447 
Net derivative liability
$(17,811)$11,916 
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, 2022 and December 31, 2021, we had two and three customers, respectively, that each accounted for more than 10% of total revenues. We do not believe the loss of any single purchaser would materially impact our operating results because oil, NGLs and natural gas are fungible products with well-established markets and numerous purchasers.
At June 30, 2023, 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 June 30, 2023, we had $14.0 million of variable rate debt outstanding. Based on this and expected borrowing levels in 2023, a change in interest rates would be de minimis. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Revolving credit agreement.”
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Item 4. Controls and Procedures

As required by Rule 13a 15(b) under the Securities Exchange Act of 1934 (the “Exchange Act”), we have evaluated, under the supervision and with the participation of management, including our principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a 15(e) and 15d 15(e) under the Exchange Act) as of the end of the period covered by this Quarterly Report.

Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we file or submit under the Exchange Act is accumulated and communicated to management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC. Based upon that evaluation, our principal executive officer and principal financial officer concluded that our disclosure controls and procedures were effective as of June 30, 2023.


Changes in Internal Control over Financial Reporting

There were no changes in our internal control over financial reporting that occurred during the quarter ended June 30, 2023 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
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Part II - Other Information
Item 1. Legal Proceedings
We are party to lawsuits arising in the ordinary course of our business. We cannot predict the outcome of any such lawsuits with certainty, but management believes it is remote that pending or threatened legal matters will have a material adverse impact on our financial condition. Due to the nature of our business, we are, from time to time, involved in other routine litigation or subject to disputes or claims related to our business activities, including workers’ compensation claims and employment-related disputes. In the opinion of our management, none of these other pending litigation matters, disputes or claims against us, if decided adversely, will have a material adverse effect on our financial condition, cash flows or results of operations.
Item 1A. Risk Factors
There have been no material changes in the risk factors disclosed under Part I, Item 1A of our Annual Report on Form 10-K for the year ended December 31, 2022.
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
None.
Item 3. Defaults Upon Senior Securities
None.
Item 4. Mine Safety Disclosures
None.
Item 5. Other Information

During the quarter ended June 30, 2023, there were no adoptions, modifications, or terminations by directors or officers of Rule 10b5-1 trading arrangements or non-Rule 10b5-1 trading arrangements, each as defined in Item 408 of Regulation S-K.


33

Item 6. Exhibits
Exhibit
Number
Description
3.1
3.2
3.3
3.4
3.5
3.6
10.1*
31.1*
31.2*
32.1*
32.2*
101.INSInline 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.SCHInline XBRL Taxonomy Extension Schema Document.
101.CALInline XBRL Taxonomy Extension Calculation Linkbase Document.
101.DEFInline XBRL Taxonomy Extension Definition Linkbase Document.
101.LABInline XBRL Taxonomy Extension Label Linkbase Document.
101.PREInline XBRL Taxonomy Extension Presentation Linkbase Document.
104.0Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101)
_________________________________
*    Filed herewith

34

SIGNATURES
Pursuant to the requirements of the Securities Act of 1933, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
TXO Partners, L.P.
By:TXO Partners GP, LLC, its general partner
By:/s/ Brent W. Clum
Name: Brent W. Clum
Title: President of Business Operations, Chief Financial Officer and Duly Authorized Officer

35
Execution Version

AMENDMENT NO. 2 TO CREDIT AGREEMENT

This AMENDMENT NO. 2 TO CREDIT AGREEMENT (this “Amendment”) dated as of June 28, 2023, is among TXO PARTNERS, L.P. (f/k/a TXO Energy Partners, L.P. and MorningStar Partners, L.P.), a Delaware limited partnership, each of the Guarantors party hereto, each of the Lenders party hereto, and JPMORGAN CHASE BANK, N.A., as Administrative Agent.
Recitals
A.    WHEREAS, TXO Partners, L.P. (f/k/a TXO Energy Partners, L.P. and MorningStar Partners, L.P.), a Delaware limited partnership (the “Borrower”), each of the lenders from time to time party thereto (each, a “Lender” and, collectively, the “Lenders”) and JPMorgan Chase Bank, N.A., as administrative agent for the Lenders (in such capacity, the “Administrative Agent”), are parties to that certain Credit Agreement dated as of November 1, 2021, as amended, supplemented or otherwise modified prior to the date hereof (the “Existing Credit Agreement”, and as the same may be further amended, restated, amended and restated, supplemented or otherwise modified from time to time, including, without limitation, pursuant to this Amendment, the “Credit Agreement”), pursuant to which the Lenders have made certain credit available to and on behalf of the Borrower.
B.    WHEREAS, the Borrower, the Administrative Agent, the Guarantors party hereto and the Lenders have agreed to make certain amendments and modifications to the Existing Credit Agreement, in each case as set forth herein.
C.    NOW, THEREFORE, in consideration of the premises and the mutual covenants herein contained, for good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the parties hereto agree as follows:
Section 1.Defined Terms. Each capitalized term which is defined in the Credit Agreement, but which is not defined in this Amendment, shall have the meaning ascribed such term in the Credit Agreement.
Section 2.Amendments to the Credit Agreement.
1.1The Existing Credit Agreement is hereby amended in its entirety as set forth in Exhibit A hereto (it being agreed, for the avoidance of doubt, that, subject to Section 2.2 below, nothing in this Amendment amends or modifies the Exhibits or Schedules to the Existing Credit Agreement).
1.2Schedule I to the Existing Credit Agreement is hereby amended by replacing the addresses for notice included thereon with the addresses set forth on Schedule I attached hereto.
1.3Pursuant to Section 6.11 of the Credit Agreement, the Administrative Agent hereby consents to the change of the Borrower’s name from “TXO Energy Partners, L.P.” to “TXO Partners, L.P.”, and the Lenders party hereto hereby waive any noncompliance with such Section 6.11 or any Default or Event of Default arising therefrom in connection with such name change.




        

Section 3.Conditions Precedent. This Amendment shall become effective on the date (such date, the “Amendment No. 2 Effective Date”) when each of the following conditions is satisfied (or waived in accordance with Section 9.01 of the Credit Agreement):
1.1The Administrative Agent shall have received from the Borrower, each Guarantor, and the Majority Lenders counterparts of this Amendment signed on behalf of such persons.
1.2At the time of and immediately after giving effect to this Amendment, (a) the representations and warranties contained in Article IV of the Credit Agreement and the representations and warranties contained in the Security Instruments and each of the other Loan Documents shall be true and correct in all material respects (except to the extent such representation or warranty is already subject to a materiality qualifier, in which case such representation or warranty is true and correct in all respects) and (b) no Default or Event of Default shall have occurred and be continuing.
1.3The Administrative Agent shall have received a certificate dated as of the Amendment No. 2 Effective Date from a Responsible Officer of the general partner of the Borrower certifying that the conditions contained in Section 3.2 have been satisfied.
1.4The Administrative Agent shall have received all fees due and payable on or prior to the Amendment No. 2 Effective Date and, to the extent the Borrower has received an invoice therefor no later than one (1) Business Day prior to the Amendment No. 2 Effective Date, reimbursement or payment of all out-of-pocket expenses required to be reimbursed or paid by the Borrower hereunder, including all reasonable and documented fees, expenses and disbursements of counsel for the Administrative Agent.
Each party hereto hereby authorizes and directs the Administrative Agent to declare this Amendment to be effective when it has received documents confirming or certifying, to the reasonable satisfaction of the Administrative Agent, compliance with the conditions set forth in this Section 3. Such declaration shall be final, conclusive and binding upon all parties to the Credit Agreement for all purposes.
Section 4.Miscellaneous.
1.1Confirmation. The provisions of the Credit Agreement, as amended by this Amendment, shall remain in full force and effect following the Amendment No. 2 Effective Date.
1.2Ratification and Affirmation; Representations and Warranties. The Borrower and each Guarantor hereby (a) acknowledges and agrees to the terms of this Amendment and the Credit Agreement, (b) represents and warrants to the Administrative Agent and the Lenders that, after giving effect to this Amendment, (i) the representations and warranties of the Borrower and the Guarantors set forth in the Credit Agreement, this Amendment and in the other Loan Documents are true and correct in all material respects on and as of the date hereof, except to the extent any such representations and warranties (A) are expressly limited to an earlier date, in which case, on and as of the date hereof, such representations and warranties continue to be true and correct in all material respects as of such specified earlier date or (B) are already qualified by materiality, Material Adverse Effect or a similar qualification, in which case, such representations and warranties are true and correct in all respects and (ii) no Borrowing Base Deficiency, Default or Event of Default has occurred and is continuing as of the date hereof and (c) ratifies and affirms the covenants, guarantees, pledges, grants of Liens and agreements or other commitments applicable to such Loan Party contained in each Loan Document to which it is a party. The amendment of the Credit Agreement pursuant to this Amendment and all other
    -2-


        

Loan Documents amended and/or executed and delivered in connection herewith is not intended to, and shall not, constitute a novation of the Credit Agreement or any of the other Loan Documents as in effect immediately prior to the Amendment No. 2 Effective Date.
1.3Counterparts.
(a)This Amendment may be executed in counterparts (and by different parties hereto on different counterparts), each of which shall constitute an original, but all of which when taken together shall constitute a single contract.
(b)Delivery of an executed counterpart of a signature page of this Amendment, and/or any document, amendment, approval, consent, information, notice, certificate, request, statement, disclosure or authorization related to this Amendment and/or the transactions contemplated hereby and/or thereby (each an “Ancillary Document”) that is an electronic sound, symbol, or process attached to, or associated with, a contract or other record and adopted by a Person with the intent to sign, authenticate or accept such contract or record (an “Electronic Signature”) transmitted by telecopy, emailed pdf or any other electronic means that reproduces an image of an actual executed signature page shall be effective as delivery of a manually executed counterpart of this Amendment or such Ancillary Document, as applicable. The words “execution,” “signed,” “signature,” “delivery,” and words of like import in or relating to this Amendment and/or any Ancillary Document shall be deemed to include Electronic Signatures, deliveries or the keeping of records in any electronic form (including deliveries by telecopy, emailed pdf or any other electronic means that reproduces an image of an actual executed signature page), each of which shall be of the same legal effect, validity or enforceability as a manually executed signature, physical delivery thereof or the use of a paper-based recordkeeping system, as the case may be.
1.4Integration. This Amendment, the Credit Agreement, the Senior Secured Credit Facility Fee Letter, the other Loan Documents and any separate letter agreements with respect to fees payable to the Administrative Agent constitute the entire contract among the parties relating to the subject matter hereof and thereof and supersede any and all previous agreements and understandings, oral or written, relating to the subject matter hereof and thereof. THIS AMENDMENT, THE CREDIT AGREEMENT AND THE OTHER LOAN DOCUMENTS REPRESENT THE FINAL AGREEMENT WITH RESPECT TO THE SUBJECT MATTER CONTAINED HEREIN AND THEREIN AMONG THE PARTIES HERETO AND THERETO AND MAY NOT BE CONTRADICTED BY EVIDENCE OF PRIOR, CONTEMPORANEOUS OR SUBSEQUENT ORAL AGREEMENTS OF THE PARTIES. THERE ARE NO UNWRITTEN ORAL AGREEMENTS BETWEEN THE PARTIES.
1.5GOVERNING LAW. THIS AMENDMENT SHALL BE GOVERNED BY, AND CONSTRUED IN ACCORDANCE WITH, THE LAW OF THE STATE OF NEW YORK.
1.6Jurisdiction; Consent to Service of Process; Waiver of Jury Trial. The express terms of Sections 9.15 and 9.16 of the Credit Agreement are hereby incorporated by reference, mutatis mutandis.
1.7Payment of Expenses. Pursuant to Section 9.04 of the Credit Agreement, the Borrower agrees to pay all reasonable and documented out-of-pocket expenses incurred by the
    -3-


        

Administrative Agent and its Affiliates in connection with the preparation, negotiation, execution, delivery and administration of this Amendment and the other Loan Documents.
1.8Severability. Any provision of this Amendment held to be invalid, illegal or unenforceable in any jurisdiction shall, as to such jurisdiction, be ineffective to the extent of such invalidity, illegality or unenforceability without affecting the validity, legality and enforceability of the remaining provisions hereof or thereof; and the invalidity of a particular provision in a particular jurisdiction shall not invalidate such provision in any other jurisdiction.
1.9Successors and Assigns. The provisions of this Amendment shall be binding upon and inure to the benefit of the parties hereto and their respective successors and assigns permitted by the Credit Agreement.
1.10Loan Documents. This Amendment is a Loan Document.
1.11No Waiver. The execution, delivery and effectiveness of this Amendment shall not operate as a waiver, other than as expressly set forth herein, of any right, power or remedy of the Administrative Agent or any Lender under the Credit Agreement or any Loan Document, or constitute a waiver or amendment of any provision of the Credit Agreement or any Loan Document, other than as expressly set forth herein. Section 9.03 of the Credit Agreement remains in full force and effect and is hereby ratified and confirmed by the Borrower and each Guarantor.
[Signature Pages Follow]
    -4-



IN WITNESS WHEREOF, the parties hereto have caused this Amendment to be duly executed effective as of the Amendment No. 2 Effective Date.
BORROWER:TXO PARTNERS, L.P.
By: TXO Partners GP, LLC, its general partner
By:     s/ Brent W. Clum    
Name:    Brent W. Clum
Title:    President of Business Operations and Chief     Financial Officer
GUARANTORS: