PUBLIC SERVICE CO OF NEW MEXICO

Westmoreland San Juan Mining, LLC

As discussed in the subheading Coal Supply in Note 11, PNM and Westmoreland San Juan Mining, LLC (“WSJ LLC”), a subsidiary of Westmoreland Mining Holdings, LLC have agreements under which mine reclamation services for SJGS will be provided.

TXNM issued $30.3 million in letters of credit to facilitate the issuance of reclamation bonds. The letters of credit support results in TXNM having a variable interest in WSJ LLC since TXNM is subject to possible loss in the event performance by TXNM is required under the letters of credit support. TXNM considers the possibility of loss under the letters of credit support to be remote since the purpose of posting the bonds is to provide assurance that WSJ LLC performs the required reclamation of the mine site in accordance with applicable regulations and the reclamation services agreement provides WSJ LLC the ability to recover the cost of reclamation. As discussed in Note 11, each of the SJGS participants has established and actively fund trusts to meet future reclamation obligations.

WSJ LLC is considered a VIE. TXNM’s analysis of its arrangements with WSJ LLC concluded that WSJ LLC has the ability to direct its reclamation services, which are the factors that most significantly impact the economic performance of WSJ LLC. Other than PNM being able to monitor the reclamation activities, the reclamation services were solely under the control of WSJ LLC, including developing reclamation plans, hiring personnel, and incurring operating and maintenance expenses.

Neither TXNM nor PNM has any ability to direct or influence the reclamation activities. PNM’s involvement through the reclamation services agreement is a protective right rather than a participating right, and WSJ LLC still has the power to direct the activities that most significantly impact the economic performance of WSJ LLC. If WSJ LLC performs reclamation services more efficiently than anticipated, its economic performance will improve. Conversely, if WSJ LLC does not perform reclamation services as efficiently as anticipated, its economic performance will be negatively impacted. Accordingly, TXNM believes WSJ LLC is the primary beneficiary and, therefore, WSJ LLC is not consolidated by either TXNM or PNM. The amounts outstanding under the letters of credit support continue to be TXNM’s maximum exposure to loss from the VIE at September 30, 2025.

ETBC I

ETBC I is a wholly-owned, special purpose subsidiary of PNM that was formed in August 2023 for the limited purpose of purchasing, owning, and administering energy transition property, issuing securitized bonds, and performing related activities authorized by the NMPRC. On November 15, 2023, ETBC I issued the ETBC I Securitized Bonds and used the proceeds to purchase energy transition property from PNM. The energy transition property purchased includes the right to impose, bill, collect, and adjust a non-bypassable energy transition charge from all PNM retail customers until the ETBC I Securitized Bonds are paid in full and all allowed financing costs have been recovered. The ETBC I Securitized Bonds are secured by the energy transition property, and cash collections from the Energy Transition Charges are the sole source of funds to satisfy the debt obligation. The bondholders have no recourse to PNM.

PNM acts as the servicer of the energy transition property on behalf of ETBC I and is responsible for metering, calculating, billing, and collecting the Energy Transition Charges. On behalf of ETBC I, PNM is required to remit all collections of the Energy Transition Charges to the trustee for the ETBC I Securitized Bonds. PNM has the power to direct the activities that most significantly impact the economic performance of ETBC I and will absorb the majority of the variability in the cash flows of the entity. As the primary beneficiary, PNM consolidates ETBC I in its financial statements. Accordingly, the assets, liabilities, operating expenses, and cash flows of ETBC I are included in the Consolidated Financial Statements of PNM.

The following tables summarize the impact of ETBC I on PNM’s Financial Statements:

(7)Fair Value of Derivative and Other Financial Instruments

Additional information concerning energy related derivative contracts and other financial instruments is contained in Note 9 of the Notes to Consolidated Financial Statements in the 2024 Annual Reports on Form 10-K.

Fair value is defined as the price that would be received for an asset or paid to transfer a liability (an exit price) in the principal or most advantageous market for the asset or liability in an orderly transaction between market participants on the measurement date. Fair value is based on current market quotes as available and is supplemented by modeling techniques and assumptions made by the Company to the extent quoted market prices or volatilities are not available. External pricing input availability varies based on commodity location, market liquidity, and term of the agreement. Valuations of derivative assets and liabilities take into account nonperformance risk, including the effect of counterparties’ and the Company’s credit risk. The Company regularly assesses the validity and availability of pricing data for its derivative transactions. Although the Company uses its best judgment in estimating the fair value of these instruments, there are inherent limitations in any estimation technique.

Energy Related Derivative Contracts

The primary objective for the use of commodity derivative instruments, including energy contracts, options, swaps, and futures, is to manage price risk associated with forecasted purchases of energy and fuel used to generate electricity, as well as managing anticipated generation capacity in excess of forecasted demand from existing customers. PNM’s energy related derivative contracts manage commodity risk. TNMP does not enter into energy related derivative contracts.

PNM enters into agreements for the purchase and sale of power from third parties. As PNM is required to meet the demand and energy needs of its customers, PNM may be exposed to market risk for the needs of its customers not covered under the FPPAC.

PNM’s operations are managed primarily through a net asset-backed strategy, whereby PNM’s aggregate net open forward contract position is covered by its forecasted excess generation capabilities or market purchases. PNM could be exposed to market risk if its generation capabilities were to be disrupted or if its load requirements were to be greater than anticipated. If all or a portion of load requirements were required to be covered as a result of such unexpected situations, commitments would have to be met through market purchases.

Commodity Risk

Marketing and procurement of energy often involve market risks associated with managing energy commodities and establishing positions in the energy markets, primarily on a short-term basis. PNM routinely enters into various derivative instruments such as forward contracts, option agreements, and price basis swap agreements to economically hedge price and volume risk on power commitments and fuel requirements and to minimize the effect of market fluctuations. PNM monitors the market risk of its commodity contracts in accordance with approved risk and credit policies.

Accounting for Derivatives

Under derivative accounting and related rules for energy contracts, PNM accounts for its various instruments for the purchase and sale of energy, which meet the definition of a derivative, based on PNM’s intent. During the nine months ended September 30, 2025 and the year ended December 31, 2024, PNM was not hedging its exposure to the variability in future cash flows from commodity derivatives through designated cash flow hedges. The derivative contracts recorded at fair value that do not qualify or are not designated for cash flow hedge accounting are classified as economic hedges. Economic hedges are defined as derivative instruments, including long-term power agreements, used to economically hedge generation assets, purchased power and fuel costs, and customer load requirements. Changes in the fair value of economic hedges are reflected in Operating income on the Condensed Consolidated Statements of Earnings and are presented in Electric Operating Revenues and Cost of energy according to the intent of the hedge. PNM also uses such instruments under an NMPRC-approved hedging plan to manage fuel and purchased power costs related to customers covered by its FPPAC. Changes in the fair value of instruments covered by its FPPAC are recorded as Regulatory assets and Regulatory liabilities on the Condensed Consolidated Balance Sheets. The cash impacts of settled derivatives are recorded as operating activities or financing activities on the Condensed Consolidated Statement of Cash Flows consistent with the classification of the hedged transaction. PNM has no trading transactions.

Commodity Derivatives

In November 2024, February 2025, and April 2025, PNM entered into agreements to purchase a total of 250 MW from July 1, 2025 through August 31, 2025 in order to ensure that customer demand during the 2025 summer peak load period was met. In 2024, PNM had existing agreements to purchase a total of 150 MW from July 1, 2024 through July 31, 2024 and 100 MW from August 1, 2024 through August 30, 2024. All of these agreements are related to customers covered by the FPPAC and are reflected in the commodity derivative table for each of the periods presented below. PNM’s commodity derivative instruments that are recorded at fair value, all of which are accounted for as economic hedges and considered Level 2 fair value measurements, are presented in the following line items on the Condensed Consolidated Balance Sheets:

Certain of PNM’s commodity derivative instruments in the above table are subject to master netting agreements whereby assets and liabilities could be offset in the settlement process. PNM does not offset fair value and cash collateral for derivative instruments under master netting arrangements and the above table reflects the gross amounts of fair value assets and liabilities for commodity derivatives.

At September 30, 2025 and December 31, 2024, PNM had no commodity derivative instruments, considered economic hedges, that did not pertain to the NMPRC-approved hedging plan discussed above. Changes in fair value had no impact on PNM’s net earnings during the nine months ended September 30, 2025 and 2024. Commodity contract volume positions are presented in MMBTU for gas related contracts and in MWh for power related contracts. The table below presents PNM’s net buy (sell) volume positions:

PNM has contingent requirements to provide collateral under commodity contracts having an objectively determinable collateral provision that are in net liability positions and are not fully collateralized with cash. In connection with managing its commodity risks, PNM enters into master agreements with certain counterparties. If PNM is in a net liability position under an agreement, some agreements provide that the counterparties can request collateral if PNM’s credit rating is downgraded; other agreements provide that the counterparty may request collateral to provide it with “adequate assurance” that PNM will perform; and others have no provision for collateral.

Contractual liability represents those commodity derivative contracts recorded at fair value on the balance sheet, determined on an individual contract basis without offsetting amounts for individual contracts that are in an asset position and could be offset under master netting agreements with the same counterparty. Cash collateral posted under these contracts does not reflect letters of credit under the Company’s revolving credit facilities that may have been issued as collateral. Net exposure is the net contractual liability for all contracts, including those designated as normal purchase and normal sale, offset by existing collateral and by any offsets available under master netting agreements, including both assets and liability positions. At September 30, 2025 and December 31, 2024, PNM hadzero and $5.7 million of contractual liability, zero posted cash collateral, andzero and $5.7 million in a net liability position.

At September 30, 2025 and December 31, 2024, PNM hadno amounts recognized for the legal right to reclaim cash collateral. However, amounts posted as cash collateral under margin arrangements were zero at September 30, 2025 and $0.1 million at December 31, 2024. These amounts are included in other current assets on the Condensed Consolidated Balance Sheets. At both September 30, 2025 and December 31, 2024, there wereno obligations to return cash collateral.

Non-Derivative Financial Instruments

The carrying amounts reflected on the Condensed Consolidated Balance Sheets approximate fair value for cash, receivables, and payables due to the short period of maturity. Investment securities are carried at fair value. Investment securities consist of PNM assets held in the NDT for its share of decommissioning costs of PVNGS, a trust for PNM’s share of decommissioning costs at SJGS, and trusts for PNM’s share of final reclamation costs related to the coal mines serving SJGS and Four Corners. See Note 11. At September 30, 2025 and December 31, 2024, the fair value of investment securities included $420.8 million and $384.6 million for the NDT, $2.3 million and $8.2 million for the SJGS decommissioning trust, and $70.8 million and $82.7 million for the coal mine reclamation trusts.

PNM records a realized loss as an impairment for any available-for-sale debt security that has a fair value that is less than its carrying value. At September 30, 2025 and December 31, 2024, PNM had no available-for-sale debt securities for which carrying value exceeded fair value, where the impairments were considered to be “other than temporary” and included in AOCI rather than recognized in earnings. All gains and losses resulting from sales and changes in the fair value of equity securities are recognized immediately in earnings. Gains and losses recognized on the Condensed Consolidated Statements of Earnings related to investment securities in the NDT, SJGS decommissioning, and coal mine reclamation trusts are presented in the following table:

The proceeds and gross realized gains and losses on the disposition of securities held in the NDT, SJGS decommissioning trust, and coal mine reclamation trusts are shown in the following table. Realized gains and losses are determined by specific identification of costs of securities sold. Gross realized losses shown below exclude the (increase)/decrease in realized impairment losses ofzero for the three and nine months ended September 30, 2025 and $2.0 million and $17.0 million for the three and nine months ended September 30, 2024.

At September 30, 2025, the available-for-sale debt securities held by PNM, had the following final maturities:

Fair Value Disclosures

The Company determines the fair values of its derivative and other financial instruments based on the hierarchy that requires an entity to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. There are three levels of inputs that may be used to measure fair value. Level 1 inputs are quoted prices (unadjusted) in active markets for identical assets or liabilities that the reporting entity has the ability to access at the measurement date. Level 2 inputs are inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly. Level 3 inputs are unobservable inputs for the asset or liability.

For investment securities, Level 2 fair values are provided by fund managers utilizing a pricing service. For Level 2 fair values, the pricing provider predominantly uses the market approach using bid side market values based upon a hierarchy of information for specific securities or securities with similar characteristics. Fair values of Level 2 investments in mutual funds are equal to NAV. For commodity derivatives, Level 2 fair values are determined based on market observable inputs, which are validated using multiple broker quotes, including forward price, volatility, and interest rate curves to establish expectations of future prices. Credit valuation adjustments are made for estimated credit losses based on the overall exposure to each counterparty. For the Company’s long-term debt, Level 2 fair values are provided by an external pricing service. The pricing service primarily utilizes quoted prices for similar debt in active markets when determining fair value. Management of the Company independently verifies the information provided by pricing services. Uncategorized investments include common/collective investment trusts and real estate funds which are measured at NAV at the end of each reporting period. Financial statements are received for each fund and reviewed by the Company quarterly with audited financial statements received and reviewed on an annual basis. Fair value for these funds is measured using a practical expedient provided under GAAP that allows the NAV per share to be used as fair value for investments in certain entities that do not have readily determinable fair values and are considered to be investment companies. Investments valued using this practical expedient are not required to be presented within the GAAP fair value hierarchy.

Items recorded at fair value by PNM on the Condensed Consolidated Balance Sheets are presented below by level of the fair value hierarchy along with gross unrealized gains on investments in available-for-sale debt securities:

The carrying amounts and fair values of long-term debt, all of which are considered Level 2 fair value measurements and are not recorded at fair value on the Condensed Consolidated Balance Sheets, are presented below:

The carrying amount and fair value of the Company’s other investments presented on the Condensed Consolidated Balance Sheets are not material and not shown in the above table.

(8)Stock-Based Compensation

TXNM has various stock-based compensation programs, which provide restricted stock awards, that are performance-based and time-based, under the PEP. Although certain PNM and TNMP employees are eligible to participate in the TXNM plans, PNM and TNMP do not have separate employee stock-based compensation plans. Performance stock awards granted under the PEP are awarded for athree-year, overlapping performance period. Performance stock awards with performance periods ending in 2024 and 2025 do not include market targets. Performance stock awards with performance periods ending after 2025 are subject to achieving both performance and market targets. Other awards of restricted stock are only subject to time-based vesting requirements. Additional information concerning stock-based compensation under the PEP is contained in Note 12 of the Notes to Consolidated Financial Statements in the 2024 Annual Reports on Form 10-K.

Restricted stock under the PEP refers to awards of stock subject to vesting, performance, or market conditions rather than to shares with contractual post-vesting restrictions. Generally, the awards vest ratably over three years from the grant date of the award. However, awards with performance or market conditions vest upon satisfaction of those conditions. In addition, plan provisions provide that upon retirement, participants become 100% vested in certain stock awards. The vesting period for awards of restricted stock to non-employee members of the Board isone-year.

The stock-based compensation expense related to restricted stock awards without performance or market conditions to participants that are retirement eligible on the grant date is recognized immediately at the grant date and is not amortized. Compensation expense for other such awards is amortized over the shorter of the requisite vesting period or the period until the participant becomes retirement eligible. Compensation expense for performance-based shares is recognized ratably over the performance period as required service is provided and is adjusted periodically to reflect the level of achievement expected to be attained. Compensation expense related to market-based shares is recognized ratably over the measurement period, regardless of the actual level of achievement, provided the employees meet their service requirements. At September 30, 2025, TXNM had unrecognized expense related to stock awards of $7.7 million, which is expected to be recognized over an average of 1.8 years.

The grant date fair value for restricted stock and stock awards with internal TXNM performance targets is determined based on the market price of TXNM common stock on the date of the agreements reduced by the present value of future dividends that will not be received prior to vesting. The grant date fair value is applied to the total number of shares that are anticipated to vest, although the number of performance shares that ultimately vest cannot be determined until after the performance periods end. The grant date fair value of stock awards with market targets were determined using Monte Carlo simulation models, which provide grant date fair values that include an expectation of the number of shares to vest at the end of the measurement period.

The following table summarizes the weighted-average assumptions used to determine the awards grant date fair value:

The following table summarizes activity in restricted stock awards, including performance-based and market-based shares for the nine months ended September 30, 2025:

Included, as granted and released, in the table above are 50,923 previously awarded performance-based shares that were earned for the 2022 - 2024 performance measurement period and ratified by the Board in February 2025 (based upon achieving targets at above “threshold,” below “target” levels). Also included, as granted and released, are 341 of other restricted stock awards for participants who retired and immediately vested. Excluded from the table above are 155,388,242,177, and 205,478 shares for thethree-year performance periods ending in 2025, 2026, and 2027 that will be awarded if all performance and market criteria are achieved at maximum levels and all executives remain eligible.

On December 4, 2023, the Company entered into a retention agreement with its President and Chief Operating Officer under which he would receive a retention bonus of $1.0 million to be paid in increments beginning in December 2023 and continuing each December until 2025. On April 8, 2024, pursuant to the retention agreement, the Board elected to convert the unvested portion of the retention bonus of $0.8 million into restricted stock rights whereby each share of restricted stock is equal toone share of Company common stock as of the first trading day after expiration of the then current black-out period. On May 3, 2024, subsequent to the expiration of the black-out period,19,851 restricted stock rights were awarded that will vest in accordance with the original terms of the retention agreement.

On September 16, 2024, in connection with a one-time sign-on equity grant, the Company’s newly appointed General Counsel, Senior Vice President Regulatory and Public Policy, and Corporate Secretary was awarded 9,300 shares of restricted stock, of which 50% vested immediately and the remaining 50% vested on September 16, 2025.

The following table provides additional information concerning restricted stock activity, including performance-based and market-based shares:

(9)Financing

The Company’s financing strategy includes both short-term and long-term borrowings. The Company utilizes short-term revolving credit facilities, as well as cash flows from operations, to provide funds for both construction and operating expenditures. Depending on market and other conditions, the Company will periodically sell long-term debt, enter into term loan arrangements, or equity arrangements and use the proceeds to reduce borrowings under the revolving credit facilities or refinance other debt. Each of the Company’s revolving credit facilities, term loans, and other debt agreements contains a single financial covenant that requires the maintenance of a debt-to-capitalization ratio. For the TXNM agreements, this ratio must be maintained at less than or equal to 70%, and for the PNM and TNMP agreements, this ratio must be maintained at less than or equal to 65%. The Company’s revolving credit facilities, term loans, and other debt agreements generally also contain customary covenants, events of default, cross-default provisions, and change-of-control provisions. PNM must obtain NMPRC approval for any financing transaction having a maturity of more than 18 months. In addition, PNM files its annual informational financing filing and short-term financing plan with the NMPRC. Additional information concerning financing activities is contained in Note 7 of the Notes to Consolidated Financial Statements in the 2024 Annual Reports on Form 10-K.

On February 28, 2025, TXNM filed a shelf registration that provides for the issuance of various types of debt and equity securities. The TXNM shelf registration statement expires in February 2028.

Financing Activities

On August 29, 2025, TXNM paid the remaining balance due under its TXNM 2023 Term Loan in accordance with its terms, which terminated the agreement.

On August 15, 2025, TXNM entered into a distribution agreement (the “Distribution Agreement”) with BofA Securities, Inc., MUFG Securities Americas Inc., RBC Capital Markets, LLC and Scotia Capital (USA) Inc., as sales agents and Bank of America, N.A., MUFG Securities EMEA plc, Royal Bank of Canada and The Bank of Nova Scotia, as forward purchasers, pursuant to which the Company may sell, from time to time, up to an aggregate sales price of $200.0 million of its common stock, no par value, through the sales agents (the “TXNM 2025 ATM Program”). Sales of the shares made pursuant to the Distribution Agreement, if any, may be made in “at the market offerings” as defined in Rule 415 of the Securities Act. TXNM did not initially receive any proceeds upon the execution of this agreement.

Beginning on August 15, 2025, TXNM sold, through the sales agents listed above, an aggregate of 3,542,377 shares of TXNM common stock as set forth in the table below and used the proceeds to repay borrowings under the TXNM Revolving Credit Facility and for other corporate purposes. Gross cash proceeds shown below were reduced by $2.0 million in issuance costs resulting in net cash proceeds of $198.0 million.

On July 31, 2025, PNM entered into an agreement (the “PNM July 2025 Note Purchase Agreement”) with institutional investors for the sale and issuance of $350.0 million aggregate principal amount oftwo series of SUNs (the “PNM July 2025 SUNs”) offered in private placement transactions. The PNM July 2025 SUNs were issued on July 31, 2025. PNM issued $200.0 million of the PNM July 2025 SUNs at 5.47%, due July 31, 2031, and another $150.0 million at 6.03%, due July 31, 2036. PNM used the proceeds from the PNM July 2025 SUNs to repay the PNM $250.0 million SUNs and for general corporate purposes. The PNM July 2025 Note Purchase Agreement includes the customary covenants discussed above. In the event of a change of control, PNM will be required to offer to prepay the PNM July 2025 SUNs at par. Although there are customary change of control provisions in the PNM debt agreements, the change of control provisions in the agreements, including the PNM July 2025 Note Purchase Agreement, will not be triggered by the closing of the Merger. PNM has the right to redeem any or all of the PNM July 2025 SUNs prior to their maturities, subject to payment of a customary make-whole premium.

On July 21, 2025, TNMP entered into an agreement (the “TNMP July 2025 Bond Purchase Agreement”) with institutional investors for the sale of $1,084.3 million aggregate principal amount ofsix series of TNMP first mortgage bonds (the “TNMP July 2025 FMBs”) offered in private placement transactions. TNMP issued the bonds on July 21, 2025 with the following terms:

The proceeds were used to repay borrowings under the TNMP Merger Backstop Term Loan (defined below). The TNMP July 2025 FMBs are subject to continuing compliance with the representations, warranties, and covenants set forth in the governing supplemental indentures. In the event of certain changes of control of TNMP, TNMP will be required to offer to prepay the TNMP July 2025 FMBs at par. Although there are customary change of control provisions in the TNMP July 2025 FMBs, the change of control provisions will not be triggered by the closing of the Merger. TNMP has the right to redeem any or all of the TNMP July 2025 FMBs prior to their maturity, subject to payment of a customary make-whole premium.

At June 30, 2025, TXNM had a series of treasury lock agreements, with terms ranging from 5 years to 30 years, aggregating a total notional amount of $730.0 million to reduce interest rate exposure on the TNMP July 2025 FMBs that were issued in July 2025. The treasury lock agreements had an average fixed rate of 4.18% and TXNM designated them as cash flow hedges, measured at fair value, which was recorded as a loss of $2.5 million in Other current liabilities at June 30, 2025. Fair values, provided by an external pricing service, were determined using Level 2 inputs of quoted prices for similar agreements in active markets. On July 1, 2025, TXNM terminated all of the treasury lock agreements, realizing a pre-tax net loss of $1.6 million recorded in Accumulated other comprehensive income. The loss will be amortized through interest expense over a range of 5 to 30 years, in accordance with the terms of the TNMP July 2025 FMBs issued July 21, 2025.

On June 24, 2025, TXNM entered into an agreement (the “June 2025 Stock Purchase Agreement”) whereby TXNM sold, in a private placement transaction, and the purchasers named therein agreed to purchase 3,615,003 shares of TXNM common stock for a purchase price of $55.325 per share (for an aggregate amount of approximately $200 million). The closing of the issuance occurred on June 27, 2025. TXNM used the proceeds to repay an equal amount under the TXNM 2023 Term Loan. TXNM granted the purchasers customary registration rights with respect to the shares, pursuant to which TXNM was required to register such shares for resale with the SEC no later than five business days after TXNM filed its Quarterly Report on Form 10-Q for the quarterly period ending June 30, 2025. On August 8, 2025, TXNM registered the shares for resale.

The documents governing an aggregate $1,505.0 million of TNMP’s outstanding FMBs ("TNMP FMBs") obligated TNMP to offer (“the Offer”), within 30 business days following the signing of the Merger Agreement, to prepay the outstanding TNMP FMBs at 100% of the principal amount, plus accrued and unpaid interest thereon, but without any make-whole amount or other premium. On June 14, 2025, the Offer expired and $1,084.3 million in aggregate principal amount of the bonds were validly tendered. TNMP accepted for purchase all validly tendered bonds. On June 24, 2025, holders whose bonds were validly tendered and accepted for purchase received 100% of the aggregate principal amount of bonds prepaid plus accrued and unpaid interest using funds drawn under the TNMP Merger Backstop Term Loan, discussed below. The documents governing the TNMP FMBs currently require TNMP to make another offer, within 30 business days of closing of the Merger, to prepay the remaining outstanding TNMP FMBs, totaling $420.7 million, at par. TNMP will make such offer to prepay the TNMP FMBs in accordance with the terms of the TNMP FMBs; however, holders of the TNMP FMBs are not required to tender their TNMP FMBs and may accept or reject such offer to prepay.

The information in this Form 10-Q is for informational purposes only and is neither an offer to purchase, nor a solicitation of an offer to sell, subscribe for or buy any securities in any jurisdiction pursuant to the proposed transactions or otherwise, nor shall there be any sale, issuance or transfer of securities in any jurisdiction in contravention of applicable law. Similar to the offer to prepay made after signing the Merger Agreement, the post-Merger closing offer to prepay the TNMP FMBs will be made only pursuant to an offer to prepay, which will set forth the terms and conditions of the offer to prepay.

On May 27, 2025, TXNM physically settled all shares under the TXNM 2024 ATM Program by issuing 1,104,641 shares to the forward purchasers, aggregating net proceeds of $49.6 million, including $0.5 million for equity issuance costs. TXNM used the proceeds from the settled shares to repay borrowings under the TXNM Revolving Credit Facility. Following this settlement, no additional shares of TXNM’s common stock remain subject to future settlement under the TXNM 2024 ATM Program.

On May 18, 2025, the execution of the Merger Agreement constituted a “Change of Control” under certain TXNM and TNMP debt agreements. Under each of the specified debt agreements, a “Change of Control” constitutes an “Event of Default,” pursuant to which the lender parties thereto had the right to accelerate the indebtedness under the debt agreements. The definition of Change of Control under the PNM debt agreements and PNM note purchase agreements are not triggered by the execution of the Merger Agreement.

On May 23, 2025, TXNM and TNMP entered into amendments in connection with the TXNM Revolving Credit Facility, TXNM 2023 Term Loan, WFB LOC Facility, and TNMP Revolving Credit Facility with the lender parties thereto (the “Lender Consents”) to (i) amend the definition of "Change of Control" in such agreements such that the entry into the Merger Agreement would not constitute a Change of Control and (ii) waive the Event of Default arising from entry into the Merger Agreement. The amended Change of Control definition under the TXNM and TNMP debt agreements will, however, be triggered again upon the closing of the Merger. Prior to the closing of the Merger, the Company intends to coordinate with the lenders to either (a) seek to amend the definition of Change of Control permitting the Merger; or (b) to refinance or enter into new debt agreements that would permit the Merger. The Change of Control provisions in the PNM debt agreements are not triggered by the close of the Merger.

To ensure sufficient liquidity pending the Lender Consents, on May 18, 2025, TXNM entered into a $910.0 million,364-day revolving credit facility (the “TXNM Merger Backstop Revolving Facility") between TXNM, the lenders party thereto, and Wells Fargo Bank, National Association, as administrative agent. The TXNM Merger Backstop Revolving Facility was available to provide liquidity in the event the Company was unable to obtain the Lender Consents. On May 19, 2025, TXNM borrowed approximately $4.0 million under the TXNM Merger Backstop Revolving Facility and subsequently repaid the entire balance by May 21, 2025. The TXNM Merger Backstop Revolving Facility expired according to its terms as TXNM did not make any additional borrowings thereunder by the commitment termination date of May 23, 2025, and the Company was able to obtain the Lender Consents.

On May 18, 2025, concurrent with the execution of the TXNM Merger Backstop Revolving Facility, TNMP entered into a $1,505.0 million,364-day delayed-draw term loan (the “TNMP Merger Backstop Term Loan”) between TNMP, the lenders party thereto, and Wells Fargo Bank, National Association, as administrative agent. The TNMP Merger Backstop Term Loan was available to provide liquidity to repurchase TNMP’s FMBs that were tendered for prepayment pursuant to the Offer. On July 21, 2025, TNMP issued the TNMP July 2025 FMBs and used the proceeds to repay the outstanding principal balance under the TNMP Merger Backstop Term Loan on July 22, 2025, terminating that agreement.

On May 18, 2025, concurrent with the execution of the Merger Agreement, TXNM entered into an agreement (the “May 2025 Stock Purchase Agreement”) whereby TXNM sold, in a private placement transaction,8,000,000 shares of TXNM common stock for a purchase price of $50.00 per share (aggregating $400.0 million). The consummation of the May 2025 Stock Purchase Agreement occurred on June 2, 2025. TXNM used the proceeds to make a cash equity contribution of $160.0 million to TNMP, to repay borrowings under the TXNM Revolving Credit Facility, and for general corporate purposes.

On May 16, 2025, TXNM paid the remaining balance due under its TXNM 2021 Delayed Draw Term Loan in accordance with its terms.

On April 23, 2025, PNM entered into an agreement (the “PNM April 2025 Note Purchase Agreement”) with institutional investors for the sale and issuance of $300.0 million aggregate principal amount oftwo series of SUNs (the “PNM April 2025 SUNs”) offered in private placement transactions. The PNM April 2025 SUNs were issued on April 23, 2025. PNM issued $125.0 million of the PNM April 2025 SUNs at 5.75%, due June 1, 2032, and another $175.0 million at 6.13%, due June 1, 2037. PNM used proceeds from the PNM April 2025 SUNs for the repayment of existing indebtedness, funding of capital expenditures, and general corporate purposes. The PNM April 2025 Note Purchase Agreement includes the customary covenants discussed above. In the event of a change of control, PNM will be required to offer to prepay the PNM April 2025 SUNs at par. Although there are customary change of control provisions in the PNM debt agreements, the change of control provisions in the agreements, including the PNM April 2025 Note Purchase Agreement, are not triggered by the closing of the Merger. PNM has the right to redeem any or all of the PNM April 2025 SUNs prior to their maturities, subject to payment of a customary make-whole premium.

On February 14, 2025, TNMP entered into an agreement (the “TNMP February 2025 Bond Purchase Agreement”) with institutional investors for the sale and issuance of $140.0 million aggregate principal amount of first mortgage bonds (the “TNMP February 2025 Bonds”) offered in private placement transactions. TNMP issued all $140.0 million of the TNMP February 2025 Bonds on February 14, 2025 at a 5.19% interest rate, due April 1, 2031. The proceeds were used to repay borrowings under the TNMP Revolving Credit Facility, for funding of capital expenditures, and for other corporate purposes. The TNMP February 2025 Bonds are subject to continuing compliance with the representations, warranties, and covenants set forth in the supplemental indentures governing the TNMP February 2025 Bonds. The terms of the supplemental indentures governing the TNMP February 2025 Bonds include the customary covenants discussed above. In the event of a change of control, TNMP will be required to offer to prepay the TNMP February 2025 Bonds at par. The definition of change of control in the supplemental indentures governing the TNMP February 2025 Bonds were triggered by the execution of the Merger Agreement and the TNMP February 2025 Bonds were included in the Offer, with $40.0 million validly tendered by the bondholders and accepted for purchase by TNMP. The change of control for the remaining $100.0 million of TNMP February 2025 Bonds will again be triggered by the close of the Merger. TNMP has the right to redeem any or all of the TNMP February 2025 Bonds prior to their maturity, subject to payment of a customary make-whole premium.

On January 21, 2025, PNM entered into a $195.0 million term loan agreement (the “PNM 2025 Term Loan”), among PNM, the lenders party thereto and Canadian Imperial Bank of Commerce, New York Branch, as administrative agent. PNM used the proceeds of the PNM 2025 Term Loan to repay borrowings under the PNM Revolving Credit Facility and the PNM New Mexico Credit Facility, and for general corporate purposes. The PNM 2025 Term Loan bears interest at a variable rate, which was 5.14% at September 30, 2025, and must be repaid on or before July 21, 2026.

On May 6, 2024, TXNM entered into a distribution agreement with BofA Securities, Inc., Citigroup Global Markets, Inc., MUFG Securities Americas Inc., RBC Capital Markets, LLC, Scotia Capital (USA) Inc., and Wells Fargo Securities, LLC, as sales agents and Bank of America, N.A., Citibank, N.A., MUFG Securities EMEA plc, Royal Bank of Canada, The Bank of Nova Scotia, and Wells Fargo Bank, N.A., as forward purchasers, pursuant to which the Company may sell, from time to time, up to an aggregate sales amount of $100.0 million of its common stock, no par value, through the sales agents (the “TXNM 2024 ATM Program”). On August 5, 2024, subsequent to approval by shareholders to increase TXNM’s authorized shares, the Company amended the distribution agreement increasing the aggregate sales amount from $100.0 million to $300.0 million of its common stock, no par value, that may be sold under the TXNM 2024 ATM Program. The Company did not initially receive any proceeds from the execution of the distribution agreement.

During the second quarter of 2024, TXNM entered into a forward sale agreement with a forward purchaser for the sale of 262,025 shares of common stock under the TXNM 2024 ATM Program (the “Q2 2024 Forward Sale Agreement”) with an initial forward sale price of $37.77 per share. During the third quarter of 2024, TXNM entered into forward sale agreements with forward purchasers for the sale of 2,196,926 shares of common stock under the TXNM 2024 ATM Program (the “Q3 2024 Forward Sale Agreements”, and together with the Q2 2024 Forward Sale Agreement, the “2024 Forward Sale Agreements”). The Q3 2024 Forward Sale Agreements had a weighted average initial forward sale price of $40.58 per share. TXNM physically settled these shares on December 30, 2024.

On May 10, 2024, PNM entered into a $200.0 million term loan agreement (the “PNM 2024 Term Loan”), among PNM, the lenders party thereto and U.S. Bank National Association, as administrative agent. PNM used the proceeds of the PNM 2024 Term Loan to repay borrowings under the PNM Revolving Credit Facility, the PNM New Mexico Credit Facility, and for general corporate purposes. The PNM 2024 Term Loan bears interest at a variable rate, which was 5.16% at September 30, 2025, and must be repaid on or before November 10, 2025.

On June 10, 2024, TXNM issued $500.0 million aggregate principal amount of junior subordinated convertible notes due 2054 (the “Convertible Notes”) in a private offering to qualified institutional buyers pursuant to Rule 144A under the Securities Act. The Convertible Notes are unsecured obligations of the Company and rank junior and subordinate in right of payment to the prior payment in full of the Company’s existing and future senior indebtedness. The Convertible Notes bear interest at a rate of 5.75% per year, payable semi-annually in arrears on June 1 and December 1, and mature on June 1, 2054, unless earlier converted, redeemed, or repurchased in accordance with their terms. On June 21, 2024, TXNM issued an additional $50.0 million aggregate principal amount of the Convertible Notes, pursuant to an overallotment option granted by TXNM to the initial purchasers of the $500.0 million Convertible Notes. Proceeds from the Convertible Notes were used to prepay $449.0 million of borrowings under the TXNM 2021 Delayed Draw Term Loan and $90.0 million of borrowings under the TXNM 2023 Term Loan, without penalty, and for other corporate purposes.

At December 31, 2023, PNM had outstanding $37.0 million of 3.00% PCRBs and $125.0 million of 1.15% PCRBs issued by the City of Farmington, New Mexico with a mandatory remarketing date of June 1, 2024 and final maturities of June 2040 and $36.0 million of 3.00% PCRBs issued by Maricopa County, Arizona with a mandatory remarketing date of June 1, 2024 and a final maturity of January 2038. On June 3, 2024, PNM remarketed these PCRBs aggregating $198.0 million to new investors at 3.875% with a mandatory tender date of June 1, 2029.

On March 28, 2024, TNMP entered into the TNMP 2024 Bond Purchase Agreement with institutional investors for the sale of $285.0 million aggregate principal amount offour series of the TNMP 2024 Bonds offered in private placement transactions. TNMP issued the firsttwo series on March 28, 2024, consisting of $32.0 million at a 5.26% interest rate, due March 28, 2029, and $85.0 million at a 5.55% interest rate, due March 28, 2036. The third and fourth series were issued on July 1, 2024, consisting of $40.0 million at a 5.65% interest rate, due July 1, 2039, and $128.0 million at a 5.79% interest rate, due July 1, 2054. The proceeds were used to repay existing debt, including the $80.0 million of 4.03% TNMP FMBs that were due July 2024 and borrowings under the TNMP Revolving Credit Facility, for funding of capital expenditures, and for other corporate purposes. The TNMP 2024 Bonds are subject to continuing compliance with the representations, warranties, and covenants set forth in the supplemental indentures governing the TNMP 2024 Bonds. The terms of the supplemental indentures governing the TNMP 2024 Bonds include the customary covenants discussed above. In the event of certain changes of control of TXNM or TNMP, TNMP will be required to offer to prepay the TNMP 2024 Bonds at par. The definition of change of control in the supplemental indentures governing the TNMP 2024 Bonds were triggered by the execution of the Merger Agreement and the TNMP 2024 Bonds were included in the Offer, with $125.0 million validly tendered by the bondholders and accepted for purchase by TNMP. The change of control for the remaining $160.0 million of TNMP 2024 Bonds will again be triggered by the close of the Merger. TNMP has the right to redeem any or all of the TNMP 2024 Bonds prior to their maturity, subject to payment of a customary make-whole premium.

At September 30, 2025, variable interest rates were 5.16% on the PNM 2024 Term Loan that matures in November 2025 and 5.14% on the PNM 2025 Term Loan that matures in July 2026.

Short-term Debt and Liquidity

As of September 30, 2025, the TXNM Revolving Credit Facility had a financing capacity of $300.0 million and the PNM Revolving Credit Facility had a financing capacity of $400.0 million. Each of these facilities matures on March 30, 2029 and containstwo one-year extension options that, if exercised, would extend the maturity to March 2031, subject to approval by a majority of the lenders. PNM also has the $40.0 million PNM New Mexico Credit Facility. On July 25, 2025, PNM amended its PNM New Mexico Credit Facility to, among other things, extend the maturity from May 20, 2026 to May 31, 2030. As of September 30, 2025, the TNMP Revolving Credit Facility has a capacity of $200.0 million and is secured by $200.0 million aggregate principal amount of TNMP first mortgage bonds and has a maturity of March 30, 2029, withtwo one-year extension options that, if exercised, would extend the maturity to March 2031, subject to approval by a majority of the lenders. Variable interest rates under the TXNM, PNM, and TNMP revolving credit facilities are based on SOFR. Short-term debt outstanding consists of:

In addition to the above borrowings, TXNM, PNM, and TNMP had letters of credit outstanding of $3.1 million, zero, andzero at September 30, 2025 that reduce the available capacity under their respective revolving credit facilities. TXNM also had $30.3 million of letters of credit outstanding under the WFB LOC Facility. The above table excludes intercompany debt. As of September 30, 2025 and December 31, 2024, neither PNMnor TNMP had any intercompany borrowings from TXNM. TXNM had $1.7 million and $1.5 million in short-term borrowings from PNMR Development at September 30, 2025 and December 31, 2024.

PNM has $3.6 million and $3.7 million in scheduled principal payments due for the ETBC I Securitized Bonds in February and August 2026. PNM also has $200.0 million under the PNM 2024 Term Loan due in November 2025, $195.0 million under the PNM 2025 Term Loan due in July 2026, and $100.3 million of 0.875% PCRBs with a mandatory tender date of October 1, 2026. The Company’s debt arrangements have various maturities and expiration dates. Additional information on debt maturities is contained in Note 7 of the Notes to Consolidated Financial Statements in the 2024 Annual Reports on Form 10-K.

(10)Pension and Other Postretirement Benefit Plans

TXNM and its subsidiaries maintain qualified defined benefit pension plans, postretirement benefit plans providing medical and dental benefits, and executive retirement programs (collectively, the “PNM Plans” and “TNMP Plans”). TXNM maintains the legal obligation for the benefits owed to participants under these plans. The periodic costs or income of the PNM Plans and TNMP Plans are included in regulated rates to the extent attributable to regulated operations. The Company presents the service cost component of its net periodic benefit costs in administrative and general expenses and the non-service costs components in other income (deductions), net of amounts capitalized or deferred to regulatory assets and liabilities, on the Condensed Consolidated Statements of Earnings. PNM and TNMP receive a regulated return on the amounts funded for pension and OPEB plans in excess of accumulated periodic cost or income to the extent included in retail rates (a “prepaid pension asset”).

Additional information concerning pension and OPEB plans is contained in Note 11 of the Notes to Consolidated Financial Statements in the 2024 Annual Reports on Form 10-K. Annual net periodic benefit cost for the plans is actuarially determined using the methods and assumptions set forth in that note and is recognized ratably throughout the year. Differences between TNMP’s annual net periodic costs (income) and amounts included in its regulated rates are deferred to regulatory assets or liabilities, for recovery or refund in future rate proceedings.

PNM Plans

The following table presents the components of the PNM Plans’ net periodic benefit cost:

PNM didnot make any contributions to its pension plan trust in the three and nine months ended September 30, 2025 and 2024 and doesnot anticipate making any contributions to the pension plan in the remaining months of 2025 through 2028. PNM does expect to make a cash contribution of $7.9 million in 2029 based on current law, funding requirements, and estimates of portfolio performance. Funding assumptions were developed using a discount rate of 5.31% in 2025 declining to a rate of approximately 5.03% in 2027 and later years. Actual amounts to be funded in the future will be dependent on the actuarial assumptions at that time, including the appropriate discount rate. PNM may make additional contributions at its discretion. PNM didnot make any cash contributions to the OPEB trust in the three and nine months ended September 30, 2025 and 2024, however, a portion of the disbursements attributable to the OPEB trust is paid by PNM and are therefore considered to be contributions to the OPEB plan. Payments by PNM on behalf of the PNM OPEB plan were less than $0.1 million and $0.2 million for the three and nine months ended September 30, 2025 andzero and less than $0.1 million for the three and nine months ended September 30, 2024. These payments are expected to total $2.0 million in 2025 and $11.1 million for 2026-2029. Disbursements under the executive retirement program, which are funded by PNM and considered to be contributions to the plan, were $0.4 million and $0.9 million in the three and nine months ended September 30, 2025 and $0.4 million and $0.9 million in the three and nine months ended September 30, 2024 and are expected to total $1.2 million during 2025 and $4.2 million for 2026-2029.

TNMP Plans

The following table presents the components of the TNMP Plans’ net periodic benefit cost:

TNMP didnot make any contributions to its pension plan trust in the three and nine months ended September 30, 2025 and 2024 and doesnot anticipate making any contributions to the pension plan in 2025 through 2029 based on current law, funding requirements, and estimates of portfolio performance. Funding assumptions were developed using a discount rate of 5.32% in 2025 declining to a rate of approximately 5.05% in 2027 and later years. Actual amounts to be funded in the future will depend on the actuarial assumptions at that time, including the appropriate discount rate. TNMP may make additional contributions at its discretion. TNMP didnot make any contributions to the OPEB trust in the three and nine months ended September 30, 2025 and 2024 and doesnot expect to make contributions to the OPEB trust during the period 2025-2029.

(11)Commitments and Contingencies

Merger-Related Litigation

Counsel for TXNM has received a number of demand letters from certain law firms on behalf of individuals who are purported TXNM shareholders, accompanied by draft complaints naming TXNM and its directors as defendants and alleging that TXNM’s preliminary proxy statement with respect to the Merger omitted or misrepresented certain material information. Such draft complaints include a request for injunctive relief with respect to the TXNM shareholder vote to approve, and the closing of, the Merger, as well as other remedies, including counsel fees. TXNM believes that the allegations set forth in the demand letters and draft complaints are without merit and, if such complaints are actually filed, will defend such actions vigorously.

There are various claims and lawsuits pending against the Company. In addition, the Company is subject to federal, state, and local environmental laws and regulations and periodically participates in the investigation and remediation of various sites. In addition, the Company periodically enters into financial commitments in connection with its business operations. Also, the Company is involved in various legal and regulatory proceedings in the normal course of its business. See Note 12. It is not possible at this time for the Company to determine fully the effect of all litigation and other legal and regulatory proceedings on its financial position, results of operations, or cash flows.

With respect to some of the items listed below, the Company has determined that a loss is not probable or that, to the extent probable, cannot be reasonably estimated. In some cases, the Company is not able to predict with any degree of certainty the range of possible loss that could be incurred. The Company assesses legal and regulatory matters based on current information and makes judgments concerning their potential outcome, giving due consideration to the nature of the claim, the amount and nature of any damages sought, and the probability of success. Such judgments are made with the understanding that the outcome of any litigation, investigation, or other legal proceeding is inherently uncertain. The Company records liabilities for matters where it is probable a loss has been incurred, and the amount of loss is reasonably estimatable. The actual outcomes of the items listed below could ultimately differ from the judgments made and the differences could be material. The Company cannot make any assurances that the amount of reserves or potential insurance coverage will be sufficient to cover the cash obligations that might be incurred as a result of litigation or regulatory proceedings. Except as otherwise disclosed, the Company does not expect that any known lawsuits, environmental costs, or commitments will have a material effect on its financial condition, results of operations, or cash flows.

Additional information concerning commitments and contingencies is contained in Note 16 of the Notes to Consolidated Financial Statements in the 2024 Annual Reports on Form 10-K.

Commitments and Contingencies Related to the Environment

Nuclear Spent Fuel and Waste Disposal

Nuclear power plant operators are required to enter into spent fuel disposal contracts with the DOE that require the DOE to accept and dispose of all spent nuclear fuel and other high-level radioactive wastes generated by domestic power reactors. Although the Nuclear Waste Policy Act required the DOE to develop a permanent repository for the storage and disposal of spent nuclear fuel by 1998, the DOE announced that it would not be able to open the repository by 1998 and sought to excuse its performance of these requirements. In November 1997, the DC Circuit issued a decision preventing the DOE from excusing its own delay but refused to order the DOE to begin accepting spent nuclear fuel. Based on this decision and the DOE’s delay, a number of utilities, including APS (on behalf of itself and the other PVNGS owners, including PNM), filed damages actions against the DOE in the Court of Federal Claims. The lawsuits filed by APS alleged that damages were incurred due to DOE’s continuing failure to remove spent nuclear fuel and high-level waste from PVNGS. APS and the DOE entered into a settlement agreement, subsequently extended, that established a process for the payment of claims for costs incurred through December 31, 2025. Under the settlement agreement, APS must submit claims annually for payment of allowable costs. PNM records estimated claims on a quarterly basis. The benefit from the claims is passed through to customers under the FPPAC.

PNM estimates that it will incur approximately $55.6 million (in 2023 dollars) for its share of the costs related to the on-site interim storage of spent nuclear fuel at PVNGS for the remaining term of the operating licenses. PNM accrues these costs as a component of fuel expense as the nuclear fuel is consumed. At September 30, 2025 and December 31, 2024, PNM had a liability for interim storage costs of $15.3 million and $13.4 million, which is included in other deferred credits.

PVNGS has sufficient capacity at its on-site Independent Spent Fuel Storage Installation (“ISFSI”) to store all of the nuclear fuel that will be irradiated during the initial operating license period, which ends in December 2027. Additionally, PVNGS has sufficient capacity at its on-site ISFSI to store a portion of the fuel that will be irradiated during the period of extended operation, which ends in November 2047. If uncertainties regarding the U.S. Government’s obligation to accept and store spent fuel are not favorably resolved, APS will evaluate alternative storage solutions that may obviate the need to expand the ISFSI to accommodate all of the fuel that will be irradiated during the period of extended operation.

The New Mexico Energy Transition Act

The New Mexico Energy Transition Act (“ETA”) sets a statewide standard that requires investor-owned electric utilities to have specified percentages of their electric-generating portfolios be from renewable and zero-carbon generating resources. The passage of the ETA amended the REA to require utilities operating in New Mexico to have renewable portfolios equal to 40% by 2025, 50% by 2030, 80% by 2040, and 100% zero-carbon energy by 2045. The amendments also allow for the recovery of undepreciated investments and decommissioning costs related to qualifying EGUs that the NMPRC has required be removed from retail jurisdictional rates, provided replacement resources to be included in retail rates have lower or zero-carbon emissions. The ETA requires the NMPRC to review and approve utilities’ annual renewable portfolio plans to ensure compliance with the RPS. Also pursuant to the ETA, the NM Environmental Improvement Board adopted standards of performance that limit CO 2 emissions to no more than 1,100 lbs. per MWh beginning January 1, 2023 for new and existing coal-fired EGUs with original installed capacities exceeding 300 MW.

The ETA provides for a transition from fossil-fuel generation resources to renewable and other carbon-free resources through certain provisions relating to the abandonment of coal-fired generating facilities. These provisions include the use of energy transition bonds to finance certain costs of abandoning coal-fired facilities that are retired prior to January 1, 2023 for facilities operated by a “qualifying utility,” or prior to January 1, 2032 for facilities that are not operated by a qualifying utility. The amount of energy transition bonds that can be issued to recover abandonment costs is limited to the lesser of $375.0 million or 150% of the undepreciated investment of the facility as of the abandonment date. Proceeds provided by energy transition bonds must be used only for purposes related to providing utility service to customers and to pay energy transition costs (as defined by the ETA). These costs may include plant decommissioning and coal mine reclamation costs provided those costs have not previously been recovered from customers or disallowed by the NMPRC or by a court order. Proceeds from energy transition bonds may also be used to fund severances for employees of the retired facility and related coal mine and to promote economic development, education and job training in areas impacted by the retirement of the coal-fired facilities. Energy transition bonds must be issued under a NMPRC-approved financing order, are secured by “energy transition property,” are non-recourse to the issuing utility, and are repaid by a non-bypassable charge paid by all customers of the issuing utility. These customer charges are subject to an adjustment mechanism designed to provide for timely and complete payment of principal and interest due under the energy transition bonds.

The ETA also provides that utilities must obtain NMPRC approval of competitively procured replacement resources that shall be evaluated based on their cost, economic development opportunity, ability to provide jobs with comparable pay and benefits to those lost upon retirement of the facility, and that do not exceed emissions thresholds specified in the ETA. In determining whether to approve replacement resources, the NMPRC must give preference to resources with the least environmental impacts, those with higher ratios of capital costs to fuel costs, and those located in the school district of the abandoned facility. The ETA also provides for the procurement of energy storage facilities and gives utilities discretion to maintain, control, and operate these systems to ensure reliable and efficient service.

The ETA has had and will have a significant impact on PNM’s future generation portfolio, including PNM’s retirement of SJGS in 2022. PNM cannot predict the full impact of the ETA with respect to Four Corners or the outcome of its future generating resource abandonment and replacement resource filings with the NMPRC.

The Clean Air Act

Regional Haze

Pursuant to the CAA, states are required to establish goals for improving visibility in national parks and wilderness areas (also known as Class I areas) and to develop long-term strategies for reducing emissions of air pollutants that cause visibility impairment in their own states and for preventing degradation in other states. States must establish a series of interim goals to ensure continued progress by adopting a new SIP every ten years. In the first SIP planning period, states were required to conduct best available retrofit technology determinations for certain covered facilities, including utility boilers, built between 1962 and 1977 that have the potential to emit more than 250 tons per year of visibility impairing pollution. For all future SIP planning periods, states must evaluate whether additional emissions reduction measures may be needed to continue making reasonable progress toward natural visibility conditions.

SIPs for the second planning period were due in July 2021, which deadline NMED was unable to meet. NMED is currently preparing its SIP for the second compliance period and has notified PNM that it will not be required to submit a regional haze four-factor analysis for SJGS since PNM retired its share of SJGS in 2022. On August 30, 2022, EPA published in the Federal Register an official “Finding of Failure to Submit” for states, including New Mexico, that have not yet submitted a round 2 regional haze SIP. This action by EPA started a two-year clock for it to issue a FIP, which deadline has now passed. NMED petitioned the NM Environmental Improvement Board to adopt a proposed SIP and submitted a final revised plan to the NM Environmental Improvement Board on March 3, 2025. PNM submitted comments on the proposed SIP in response to a request for comments by NMED. The NM Environmental Improvement Board held a public hearing from April 28 to April 30, 2025 and is expected to deliberate and deliver a final rule during its regular meeting on November 21, 2025.

On March 12, 2025, as part of EPA’s list of 31 deregulatory actions, EPA announced it would restructure the Regional Haze Program. On October 2, 2025, EPA published an advanced notice of proposed rulemaking to solicit information from the public to help develop regulatory changes on the implementation and structure of the Regional Haze Rule (“RHR”). The advanced notice itself does not impose any requirements but requests input on how EPA can revise the RHR to streamline regulatory requirements impacting states’ visibility improvement obligations. Comments are due December 1, 2025.

Carbon Dioxide Emissions

In 2015, EPA established standards to limit CO 2 emissions from power plants, including (1) Carbon Pollution Standards for new, modified, and reconstructed power plants; and (2) the Clean Power Plan for existing power plants. Challengers successfully petitioned the U.S. Supreme Court for a stay of the Clean Power Plan. In 2019, EPA repealed the Clean Power Plan, promulgated the ACE Rule, and revised the implementing regulations for all emission guidelines. The ACE Rule was also challenged, and on January 19, 2021, the DC Circuit issued an opinion in American Lung Association and American Public Health Association v. EPA, et al., vacating the ACE Rule.

Numerous parties sought review by the U.S. Supreme Court, and on June 30, 2022, the U.S. Supreme Court held that the “generation shifting” approach in the Clean Power Plan exceeded the powers granted to EPA by Congress. Of broader significance in administrative law, the Court’s opinion expressly invoked the “major question” doctrine, which requires rules involving issues of “vast economic or political significance” to be supported by clear statutory authorization. In cases where there is no clear statement of authority, courts need not defer to the agency’s statutory interpretation on “major questions.” The decision sets legal precedent for future rulemakings by EPA and other federal regulatory agencies whereby the agencies’ authority may be limited based upon similar reasoning.

The litigation over the Carbon Pollution Standards remains held in abeyance but could be reactivated by the parties upon a determination by the court that reconsideration of the rule has concluded.

In 2024, EPA adopted regulatory actions under CAA Sections 111(b) and (d) to replace the Clean Power Plan and the ACE Rule. The final rules include revised new source performance standards under Section 111(b) for all new natural gas-fired combustion turbines and emission guidelines under Section 111(d) requiring states to develop standards of performance for GHG emissions from existing fossil-fuel-fired electric steam generating units. In the final rules, EPA determined that the standards for existing coal- or gas-fired steam generating units must be based on the use of either CCS (long-term), natural gas co-firing (medium-term), or exempt from the rule via early retirement. The standards for new combustion turbines must be based on CCS (base load), efficient simple cycle design (intermediate load), or lower-emitting fuels (low load). Over a dozen states, several industry groups and some power companies and labor unions filed challenges to the rule at the DC Circuit, which heard oral arguments on December 6, 2024. However, President Trump issued several executive orders on January 20, 2025, directing his Administration to review all agency actions and suspend, revise, or rescind those identified as imposing an undue burden on domestic energy resources. On March 12, 2025, as part of EPA’s reconsideration of 31 environmental regulations, EPA announced the agency will reconsider the previous Administration’s regulations on GHG standards and guidelines for power plants. On June 17, 2025, EPA published a proposed rule in the Federal Register with two alternatives to repeal or revise the GHG emission standards for EGUs. EPA primarily proposes to find that GHG emissions from fossil fuel-fired power plants “do not contribute significantly to dangerous air pollution” under the meaning of CAA Section 111, which would preclude EPA from regulating GHG emissions from those plants. As a result, EPA is proposing to repeal all GHG standards for the power sector promulgated under CAA Section 111 in both 2015 and 2024. EPA also proposed, in the alternative, to find that CCS is not adequately demonstrated and that neither CCS nor gas co-firing are the best system of emission reduction for GHG emissions from power plants, which findings also support repeal of those specific requirements from the rules adopted in 2024. Comments were due by September 15, 2025 and EPA has indicated it intends to finalize the proposed rule by the end of 2025.

Because the CAA 111 rule does not contain provisions for existing natural gas units, on March 26, 2024, EPA announced it was opening a non-regulatory docket and issued framing questions to gather input about ways to design a stronger, more durable approach to GHG regulation of existing gas combustion turbines. The docket was open for public comment from March 26, 2024 to May 28, 2024 and the agency held a policy forum to bring stakeholders together to share ideas with EPA and others. Under the Trump Administration, EPA is unlikely to propose a rule based on this non-regulatory docket.

In 2021, President Biden signed an extensive executive order aimed at addressing climate change concerns domestically and internationally. The order was intended to build on the initial climate-related actions the Biden Administration took on January 20, 2021. It addressed a wide range of issues, including establishing climate change concerns as an essential element of U.S. foreign and security policy, identifying a process to determine the U.S. INDC under the Paris Agreement, and establishing a Special Presidential Envoy for Climate that would sit on the National Security Council. On April 22, 2021, at the Earth Day Summit, as part of the U.S.’s re-entry into the Paris Agreement, President Biden unveiled the goal to cut U.S. emissions by 50% - 52% from 2005 levels by 2030, nearly double the GHG emissions reduction target set by the Obama Administration. The 2030 goal joined President Biden’s other climate goals which included a carbon pollution-free power sector by 2035 and a net-zero emissions economy by no later than 2050. In an executive order issued on January 20, 2025, President Trump ordered his Administration to withdraw the U.S. from the Paris Agreement and from any agreement, pact, accord, or similar commitment made under the United Nations Framework Convention on Climate Change.

On August 1, 2025, EPA published a proposal to rescind the Agency’s 2009 final rule commonly known as the Endangerment Finding. In the Endangerment Finding, EPA found that current and projected atmospheric concentrations of the well-mixed combination of six GHGs threaten public health and welfare, and that the combined emissions of these GHGs from new motor vehicles and engines contribute to the GHG pollution that threatens public health and welfare. This provided the basis for EPA’s subsequent GHG regulations applicable to stationary sources. Comments were due September 15, 2025.

PNM’s review of the GHG emission reductions standards that have or may occur as a result of legislation or regulation is ongoing. We are currently determining what impact, if any, the final rules will have on our business, results of operations, and financial condition.

National Ambient Air Quality Standards (“NAAQS”)

The CAA requires EPA to set NAAQS for pollutants reasonably anticipated to endanger public health or welfare. EPA has set NAAQS for certain pollutants, including NOx, SO 2, ozone, and particulate matter.

NOx Standard –In 2018, EPA published the final rule to retain the current primary health-based NOx standards of which NO 2 is the constituent of greatest concern and is the indicator for the primary NAAQS. EPA concluded that the current 1-hour and annual primary NO 2 standards are requisite to protect public health with an adequate margin of safety. The rule became effective on May 18, 2018. The State of New Mexico has attained the current NOx NAAQS standards.

SO 2 Standard – In 2019, EPA announced its final decision to retain, without changes, the primary health-based NAAQS for SO 2. Specifically, EPA retained the current 1-hour standard for SO 2, which is 75 parts per billion, based on the 3-year average of the 99th percentile of daily maximum 1-hour SO 2 concentrations. In 2021, EPA published in the Federal Register the initial air quality designations for all remaining areas not yet designated under the 2010 SO 2 Primary NAAQS. All areas of New Mexico have been designated attainment/unclassifiable through four rounds of designations by EPA.

Ozone Standard – In 2015, EPA finalized the new ozone NAAQS and lowered both the primary and secondary 8-hour standard from 75 to 70 parts per billion. With ozone standards becoming more stringent, fossil-fueled generation units will come under increasing pressure to reduce emissions of NOx and volatile organic compounds since these are the pollutants that form ground-level ozone. During 2017 and 2018, EPA released rules establishing area designations for ozone. In those rules, San Juan County, New Mexico, where Four Corners is located, is designated as attainment/unclassifiable and only a small area in Doña Ana County, New Mexico is designated as marginal non-attainment. Although Afton Generating Station is located in Doña Ana County, it is not located within the small area designated as non-attainment for the 2015 ozone standard.

PNM does not believe there will be material impacts to its facilities because of the non-attainment designation of the small area within Doña Ana County. Until EPA approves attainment designations for the Navajo Nation and releases a proposal to implement the revised ozone NAAQS, PNM is unable to predict what impact the adoption of these standards may have on Four Corners. On July 13, 2020, EPA proposed to retain the existing ozone NAAQS based on a review of the full body of currently available scientific evidence and exposure/risk information, but on August 21, 2023, EPA announced an entirely new review of the ozone standard. PNM cannot predict the outcome of this matter.

In 2019, EPA issued findings that several states, including New Mexico, had failed to submit interstate transport SIPs for the 2015 8-hour ozone NAAQS, triggering an obligation for EPA to issue a FIP within two years. In response, NMED submitted a Good Neighbor SIP on July 27, 2021 that demonstrates that there are no significant contributions from New Mexico to downwind problems in meeting the federal ozone standard. On March 15, 2023, EPA Administrator Regan signed a final action imposing a FIP on multiple states but did not include a FIP for New Mexico because the most updated modeling available at the time of the proposal confirmed the state did not contribute to downwind ozone nonattainment or maintenance areas. However, the updated modeling EPA used in the final rule indicated that New Mexico may be significantly contributing to one or more non-attainment or maintenance areas. In light of that modeling result, on February 16, 2024, the EPA published a proposed rule partially disapproving the SIPs for New Mexico and four other states (Arizona, Iowa, Kansas, and Tennessee) and expanding the Good Neighbor FIP to apply to these states. The FIP aspect of the proposed rule would have required fossil fuel-fired power plants in these five states to participate in an allowance-based ozone season NOx emissions trading program beginning in 2025, but the outgoing Biden Administration did not finalize the rule. On March 10, 2025, in the DC Circuit, the EPA filed a motion for voluntary remand of its ozone interstate transport FIP for the 2015 ozone NAAQS to reconsider the rule and had anticipated completing a new rulemaking by Fall 2026. The FIP is listed for reconsideration under the EPA’s March 2025 list of deregulatory actions.

PM Standard – In 2023, EPA published, in the Federal Register, a proposal to lower the annual fine PM standard to between 9-10 µg/m3 but retain the rest of its PM standards, including the current daily fine PM standard, the daily coarse PM standard, and the secondary PM standards. The final rule was published on March 6, 2024, lowering the primary annual PM 2.5 NAAQS to 9 ug/m3, and became effective May 6, 2024. States will have until March 2032 to attain compliance with the new standard. During the multi-year implementation process, EPA will designate attainment/nonattainment areas by March 6, 2026, and states will submit a SIP to EPA by September 6, 2027. This implementation process also applies to the Albuquerque-Bernalillo County Environmental Health Department who may combine efforts with NMED. However, even before any designations are made, the new standard is effective for conducting required modeling for permit applications and revisions. The lower standard is expected to result in new nonattainment areas throughout the country and could prompt additional PM control requirements, but PNM cannot predict the impacts of the outcome of future rulemaking. The March 2024 final rule is listed for reconsideration under EPA’s March 2025 list of deregulatory actions. EPA had anticipated a proposed rule in July 2025 with a final rule in January 2026.

Cooling Water Intake Structures

In 2014, EPA issued a rule establishing national standards for certain cooling water intake structures at existing power plants and other facilities under the Clean Water Act to protect fish and other aquatic organisms by minimizing impingement mortality (the capture of aquatic wildlife on intake structures or against screens) and entrainment mortality (the capture of fish or shellfish in water flow entering and passing through intake structures).

To minimize impingement mortality, the rule provides operators of facilities, such as Four Corners, seven options for meeting Best Technology Available (“BTA”) standards for reducing impingement. The permitting authority must establish the BTA for entrainment on a site-specific basis, taking into consideration an array of factors, including endangered species and social costs and benefits. Affected sources must submit source water baseline characterization data to the permitting authority to assist in the BTA determination. Compliance deadlines under the rule are tied to permit renewals, including any subject to a schedule of compliance established by the permitting authority in the permit itself.

In 2018, several environmental groups sued EPA Region IX in the U.S. Court of Appeals for the Ninth Circuit over EPA’s failure to timely reissue the Four Corners NPDES permit. The petitioners asked the court to issue awrit of mandamus compelling EPA Region IX to take final action on the pending NPDES permit by a reasonable date. EPA subsequently reissued the NPDES permit. The permit did not contain conditions related to the cooling water intake structure rule, because EPA determined that the facility had achieved BTA for both impingement and entrainment by operating a closed-cycle recirculation system. Several environmental groups filed a petition for review with EPA’s Environmental Appeals Board (“EAB”) concerning the reissued permit. The environmental groups alleged that the permit was reissued in contravention of the Clean Water Act and did not contain limits or conditions required by EPA’s ELG applicable to Four Corners or EPA’s cooling water intake structures rule, among others. EPA withdrew the Four Corners NPDES permit in order to examine the issues raised by the environmental groups and then issued an updated NPDES permit in 2019. The permit was once again appealed to the EAB and was stayed before the effective date, but the EAB issued an order denying the petition for review on September 30, 2020. Thereafter, the Regional Administrator of the EPA signed a notice of final permit decision, and the NPDES permit was issued on November 9, 2020. The permit became effective December 1, 2020. On January 22, 2021, the environmental groups filed a petition for review of the EAB’s decision with the U.S. Court of Appeals for the Ninth Circuit. The September 2019 permit remained in effect pending the outcome of this appeal. On March 21, 2022, EPA provided notice in the Federal Register of a proposed settlement agreement with the environmental groups. The parties subsequently executed the settlement agreement as of May 2, 2022. Under the settlement, the lawsuit was administratively closed through September 6, 2023, during which time a third-party consultant spent 12 months sampling discharges from Four Corners and EPA spent three months completing an analysis. On December 1, 2023, EPA issued a modification, effective December 31, 2023, to the NPDES permit that had been issued on November 9, 2020. The modification applies to permit elements related to effluent discharge. PNM cannot predict whether the analysis required to be performed by EPA under the settlement agreement will result in further changes to the NPDES permit but does not anticipate that it will have a material impact on PNM’s financial position, results of operations, or cash flows.

Effluent Limitation Guidelines

In 2013, EPA published proposed revised wastewater ELG establishing technology-based wastewater discharge limitations for fossil fuel-fired electric power plants. EPA signed the final Steam Electric ELG rule in 2015. The final rule, which became effective on January 4, 2016, phased in the new, more stringent requirements in the form of effluent limits for arsenic, mercury, selenium, and nitrogen for wastewater discharged from wet scrubber systems and zero discharge of pollutants in ash transport water that must be incorporated into plants’ NPDES permits. The 2015 rule required each plant to comply between 2018 and 2023 depending on when it needed a new or revised NPDES permit.

The Steam Electric ELG rule was challenged in the U.S. Court of Appeals for the Fifth Circuit by numerous parties. In 2017, EPA signed a notice indicating its intent to reconsider portions of the rule, and the Fifth Circuit issued an order severing the issues under reconsideration and holding the case in abeyance as to those issues. However, the court allowed challenges to other portions of the rule to proceed. In 2019, the Fifth Circuit granted those challenges and issued an opinion vacating several portions of the rule, specifically those related to legacy wastewater and leachate, for which the court deemed the standards selected by EPA to be arbitrary and capricious.

In 2017, EPA published a final rule for postponement of certain compliance dates. The rule postponed the earliest date on which compliance with the ELG for regulated waste streams would be required from November 1, 2018 until November 1, 2020. In 2019, EPA published a proposed rule revising the original ELG while maintaining the compliance dates. In 2020, EPA published in the Federal Register the final Steam Electric ELG and Standards for the Steam Electric Power Generating Point Source Category, revising the final 2015 guidelines for both flue gas desulfurization wastewater and bottom ash transport water. The 2020 rule required compliance with new limits as soon as possible on or after October 13, 2021, but no later than December 31, 2025.

In 2021, EPA published notice that it would undertake a supplemental rulemaking to revise the ELG after completing its review of the rules reconsidered in 2020. As part of this process, EPA committed to determine whether more stringent limitations and standards would be appropriate. On March 29, 2023, EPA published the proposed ELG Rule in the Federal Register. The proposed rule included stricter limitations for wastewater discharges for coal-fired facilities, but allowed for flexibilities for those coal-powered facilities that would decommission or repower by December 31, 2028, to December 31, 2032.

On May 9, 2024, EPA published a final rule to further revise the ELG. This final supplemental rule updated the technology-based limitations applicable to flue gas desulfurization wastewater, bottom ash transport water, and legacy wastewater at existing sources, as well as combustion residual leachate at new and existing sources. The 2024 rule was challenged in the U.S. Court of Appeals for the Eighth Circuit, but the court denied motions for a stay, so the rule remains in effect. On March 12, 2025, EPA announced it would reconsider the ELGs for the steam electric power generating industry. On October 2, 2025, EPA published proposed and direct final rules for extension of deadlines and other provisions. Comments are due November 3, 2025.

Reeves Station discharges cooling tower blowdown to a publicly owned treatment plant and no longer holds an NPDES permit; therefore, it is expected that no ELG requirements will be imposed.

See “Cooling Water Intake Structures” above for additional discussion of Four Corners’ current NPDES permit. Four Corners may be required to change equipment and operating practices affecting boilers and ash handling systems, as well as change its waste disposal techniques during the next NPDES permit renewal. PNM is unable to predict the outcome of these matters or a range of the potential costs of compliance.

Santa Fe Generating Station

PNM and NMED are parties to agreements under which PNM has installed a remediation system to treat water from a City of Santa Fe municipal supply well and an extraction well to address gasoline contamination in the groundwater at the site of PNM’s former Santa Fe Generating Station and service center. A 2008 NMED site inspection report states that neither the source nor extent of contamination at the site has been determined and that the source may not be the former Santa Fe Generating Station. During 2013 and 2014, PNM and NMED collected additional samples that showed elevated concentrations of nitrate and volatile organic compounds in some of the monitoring wells at the site. In addition, one monitoring well contained free-phase hydrocarbon products. PNM collected a sample of the product for “fingerprint” analysis. The results of this analysis indicated the product was a mixture of older and newer fuels. The presence of newer fuels in the sample suggests the hydrocarbon product likely originated from off-site sources. In 2015, PNM and NMED entered into a memorandum of understanding to address changing groundwater conditions at the site under which PNM agreed to continue hydrocarbon investigation under the supervision of NMED. Qualified costs are eligible for payment through the New Mexico Corrective Action Fund (“CAF”), which is administered by the NMED Petroleum Storage Tank Bureau. In 2019, PNM received notice from NMED that an abatement plan for the site is required to address concentrations of previously identified compounds, unrelated to those discussed above, found in the groundwater. NMED approved PNM’s abatement plan proposal, which covers field work and reporting.

Field work related to the investigation under both the CAF and abatement plan requirements was completed and activities and findings associated with the field work were presented intwo separate reports and released to stakeholders in early 2020. Subsequent field work was completed in July 2020 andtwo reports were released supporting PNM’s contention that off-site sources have impacted, and are continuing to impact, the local groundwater in the vicinity of the former Santa Fe Generating Station.

In 2021, NMED approved both the field work plans required for site characterization and associated work activities which were completed by the end of 2022 and a report was submitted to NMED in 2023. Groundwater sampling for the abatement plan’s first semiannual work was completed in 2023, and the associated report was completed and submitted to

NMED. In addition, the work plan for the 2023 CAF work was completed and submitted to NMED in July 2023. NMED approved this work plan in December 2023. The activities from the work plan include the installation ofthree monitoring wells which were completed in December 2024. A report summarizing the well installation is under preparation. Site wide sampling was completed in March 2025, with reports provided to NMED.

The City of Santa Fe has stopped operating its well at the site, which is needed for PNM’s groundwater remediation system to operate. As a result, PNM has stopped performing remediation activities at the site. However, PNM’s monitoring and other abatement activities at the site are ongoing and will continue until the groundwater meets applicable federal and state standards or until NMED determines that remediation is not required, whichever is earlier. PNM is also in communications with the City of Santa Fe to determine when operations at the site might resume. PNM is not able to assess the duration of this project or estimate the impact on its obligations if PNM is required to resume groundwater remediation activities at the site. PNM is unable to predict the outcome of these matters.

Coal Combustion Residuals Waste Disposal

CCRs consisting of fly ash, bottom ash, and gypsum generated from coal combustion and emission control equipment at SJGS have been disposed of in the surface mine pits adjacent to the plant. SJGS does not operate any onsite CCR impoundments or landfills. The NMMMD currently regulates mine reclamation activities at the San Juan mine, including placement of CCRs in the surface mine pits, with federal oversight by the OSM. APS disposes of CCRs in onsite ponds and dry storage areas at Four Corners. Ash management at Four Corners is regulated by EPA and the New Mexico State Engineer’s Office.

EPA’s 2015 coal ash rule included a non-hazardous waste determination for coal ash and sets minimum criteria for existing and new CCR landfills and surface impoundments. In 2016, the Water Infrastructure Improvements for the Nation Act (the “WIIN Act”) was signed into law to address critical water infrastructure needs in the U.S. and contained a number of provisions related to CCRs. Among other things, the WIIN Act allowed, but did not require, states to develop and submit CCR permit programs for EPA approval, provided flexibility for states to incorporate EPA’s 2015 rule for CCRs or develop other criteria that are at least as protective as EPA’s rule, and required EPA to approve state permit programs within 180 days of submission by the state. Because states are not required to implement their own CCR permit programs, EPA was required to develop a federal permit program in states that chose not to implement a program, subject to congressional funding. Until state or federal permit programs are in effect, the 2015 rule continues to be self-implementing in nature, subject to enforcement by EPA or citizen groups. For facilities located within the boundaries of Native American reservations, such as the Navajo Nation where Four Corners is located, EPA is required to develop a federal permit program regardless of appropriated funds.

In 2018, EPA published a rule that constitutes “Phase One, Part One” of its ongoing reconsideration and revision of the 2015 CCR rule. The final Phase One, Part One rule extended the deadline to allow EGUs with unlined impoundments or that fail to meet the uppermost aquifer requirement to continue to receive coal ash until October 31, 2020, which was again extended by subsequent amendments. The rule also authorized a “Participating State Director” or EPA to approve suspension of groundwater monitoring requirements and to issue certifications related to the location restrictions, design criteria, groundwater monitoring, remedy selection and implementation. The rule also modified groundwater protection standards for certain constituents, which include cobalt, molybdenum, lithium, and lead without a maximum contamination level.

In 2019, EPA published a second round of proposed revisions, which are commonly referred to as the “Phase Two” revisions, to address reporting and accessibility to public information, “CCR piles” and “beneficial use” definitions, and the requirements for management of CCR piles. EPA reopened and extended the Phase Two comment period several times. To date, EPA has not yet finalized provisions in Phase Two related to beneficial use of CCR and CCR piles.

Since its Phase Two proposal, EPA has finalized three other rules addressing various CCR rule provisions. In 2020, EPA promulgated its proposed Holistic Approach to Closure Part A (“Part A”), which proposed a new deadline of August 31, 2020, for companies to initiate closure of unlined CCR impoundments. In accordance with the DC Circuit’s vacatur of portions of the 2015 CCR Rule, Part A also changed the classification of compacted soil-lined or clay-lined surface impoundments from “lined” to “unlined”, triggering closure or retrofit requirements for those impoundments. In addition, Part A delineated a process for owners/operators to submit requests for alternative closure deadlines based on lack of alternate disposal capacity and gave operators of unlined impoundments until April 11, 2021 to cease receipt of waste at these units and initiate closure.

EPA also issued the Holistic Approach to Closure Part B (“Part B”) in 2020, which delineated the process for owners/operators to submit alternate liner demonstrations for clay-lined surface impoundments that could otherwise meet applicable requirements. This rule did not include beneficial use of CCR for closure, which EPA explained would be addressed in subsequent rulemaking actions. On May 18, 2023, EPA published a proposed rule on the regulatory requirements for inactive surface impoundments at inactive facilities and a new category of regulated unit called a CCR management unit (“CCRMU”), including groundwater monitoring, corrective action, closure, and post-closure care requirements for all CCR management units (regardless of how or when that CCR was placed), and several technical corrections to the existing regulations. Comments on the proposed rule were due July 17, 2023.

On May 8, 2024, EPA published a final rule that extended federal CCR regulatory requirements to (1) inactive CCR surface impoundments at inactive utilities and (2) CCRMU (Legacy Rule), including CCR impoundments and landfills that closed prior to the effective date of the 2015 CCR rule, inactive CCR landfills, and other areas where CCR was managed directly on the land. The rule became effective on November 8, 2024. EPA included deferral options for smaller CCRMU containing between one and 1,000 tons of CCR, CCRMU located beneath critical infrastructure or large buildings or structures vital to the continuation of current site activities, and CCRMU that closed prior to the effective date of the new rule (subject to certain eligibility conditions). EPA also codified the controversial definitions of infiltration and liquids that were litigated in the DC Circuit. Six petitions for review of the Legacy Rule were filed and were consolidated into one case by the DC Circuit. The Utility Solid Waste Activities Group, of which TXNM is a member, is a petitioner jointly with the National Rural Electric Cooperative Association, and American Public Power Association. The U.S. Supreme Court denied a requested stay of the rule by East Kentucky Power Cooperative. The DC Circuit has agreed to hold the case in abeyance until December 15, 2025. On July 22, 2025, EPA published a final rule and companion proposal revising the compliance deadlines for CCRMU requirements under the Legacy Rule. In September 2025, EPA withdrew the final rule due to adverse comments but anticipates a proposed rule in January 2026 with a final rule expected in October 2026.

As of the effective date of the rule, one CCRMU was identified at SJGS. SJGS is required, at a minimum, to conduct a two-part evaluation of historic and current CCRMUs with reporting due dates of February 9, 2026, and February 8, 2027 (or not later than February 8, 2027 for both under EPA’s most recent regulatory actions), with each report posted to a company website by the due date.

At this time, PNM is still evaluating the financial impacts of this final regulation for Four Corners. Initial CCRMU site surveys and final site investigation reports expected to be finalized by February 2027. Based on the information available to the Company at this time, PNM cannot reasonably estimate the fair value of the entire CCRMU ARO. PNM cannot predict the outcome of the CCRMU site evaluations and investigations, or how these outcomes might affect the associated costs, which might have a material impact on PNM’s operations, financial position, or cash flows.

In 2020, EPA published a proposed rule establishing a federal permitting program for the handling of CCR within the boundaries of Native American reservations and in states without their own federally authorized state programs. Permits for units within the boundaries of Native American reservations would be due 18 months after the effective date of the rule. EPA anticipates a final rule in December 2026. EPA has coordinated with the affected permits for the three facilities with CCR disposal units located on Native American lands. PNM cannot predict the outcome of EPA’s rulemaking activity or the outcome of any related litigation, and whether or how such a ruling would affect operations at Four Corners.

EPA’s CCR rule does not cover mine placement of coal ash. In the preamble to its 2015 rule, EPA explained that the OSM and, as necessary, EPA would address the management of CCR in mine fills in a separate regulatory action, recognizing OSM’s expertise in this area. EPA’s decision to defer to OSM was based on a recommendation from the National Academy of Sciences (“NAS”), which was commissioned by Congress in 2006 to investigate the health, safety and environmental risks associated with the use of CCR for mine reclamation. The NRC report recommended that enforceable federal standards be established for the disposal of CCR in mine fills to ensure that states have specific authority and that states implement adequate safeguards. In 2007, OSM published an advance notice of proposed rulemaking on the placement of CCR at mine sites. In that notice, OSM explained its intent to develop the proposed regulations based on its existing authority under the Surface Mining Control and Reclamation Act. Since 2007, however, OSM has not taken any further action to advance this rulemaking. PNM cannot predict the outcome of OSM’s proposed rulemaking regarding CCR regulation, including mine placement of CCRs, or whether OSM’s actions will have a material impact on PNM’s operations, financial position, or cash flows.

As noted above, SJGS does not operate any onsite CCR impoundments or landfills that are regulated under the 2015 CCR rule, and as of November 8, 2024, identified only one CCRMU that would be regulated under the Legacy Rule. The CCR has since been removed from that unit and PNM will conduct the requisite site investigation reports. PNM would seek recovery from its retail customers of all CCR costs for jurisdictional assets that are ultimately incurred.

Utilities that own or operate CCR disposal units, such as those at Four Corners, as indicated above, were required to collect sufficient groundwater sampling data to initiate a detection monitoring program. Four Corners completed the analysis for its CCR disposal units, which identified several units that needed corrective action or needed to cease operations and initiate closure by April 11, 2021. Work is ongoing. Four Corners continues to gather additional groundwater data and perform remedial evaluations and activities. At this time, PNM does not anticipate its share of the cost to complete these corrective actions to close the CCR disposal units, or to gather and perform remedial evaluations on groundwater at Four Corners, will have a significant impact on its operations, financial position, or cash flows.

Other Commitments and Contingencies

Coal Supply

Four Corners

APS purchases all of Four Corners’ coal requirements from NTEC, an entity owned by the Navajo Nation, under the Four Corners CSA that expires in 2031. The coal comes from reserves located within the Navajo Nation. The contract provides for pricing adjustments over its term based on economic indices and certain minimum payments that may be required if no deliveries of coal are taken. PNM’s share of the coal costs is being recovered through the FPPAC. See additional discussion of the Four Corners CSA in Note 17 of the Notes to Consolidated Financial Statements in the 2024 Annual Reports on Form 10-K.

Coal Mine Reclamation

As indicated under Coal Combustion Residuals Waste Disposal above, SJGS disposed of CCRs in the surface mine pits adjacent to the plant and Four Corners disposes of CCRs in ponds and dry storage areas.

PNM and the other SJGS owners are obligated to compensate WSJ LLC for all reclamation costs associated with the supply of coal from the San Juan mine. PNM and Westmoreland have entered into an agreement under which mine reclamation services for SJGS would be provided.

A mine reclamation cost study was completed in the first quarter of 2024 and PNM remeasured its liability, which resulted in an increase in overall reclamation costs of $20.9 million, due primarily to higher inflationary factors. As a result, PNM recorded the increase in the liability related to the underground mine of $17.0 million as a regulatory asset on the Condensed Consolidated Balance Sheets. Due to the NMPRC cap on the amount that can be collected from retail customers for final reclamation of the surface mines at $100.0 million, PNM was required to record $4.0 million of the increase related to the surface mine liability plus an additional $0.5 million, related to other costs, as a regulatory disallowance on the Condensed Consolidated Statements of Earnings in the three months ended March 31, 2024. In the third quarter of 2024, PNM and Westmoreland amended the mine reclamation services agreement to update the base rates for the costs of reclamation activities, which resulted in an increase in overall reclamation costs of $12.1 million. As a result, PNM recorded an additional increase in the liability related to the underground mine of $6.0 million as regulatory assets on the Condensed Consolidated Balance Sheets and the increase of $6.1 million related to the surface mine as a regulatory disallowance on the Condensed Consolidated Statements of Earnings for the three months ended September 30, 2024.

In the third quarter of 2025, PNM and Westmoreland amended the mine reclamation services agreement to update the capital recovery charges due in each year from 2025 through 2028, which resulted in an increase in overall reclamation costs. As a result on September 30, 2025, PNM recorded increases in the liabilities related to the underground mine of $0.2 million and the surface mine of $0.2 million. PNM recorded the increase in the liability related to the underground mine as a regulatory asset on the Condensed Consolidated Balance Sheets. PNM recorded the increase related to the surface mine liability as a regulatory disallowance on the Condensed Consolidated Statements of Earnings for the three and nine months ended September 30, 2025.

PNM’s estimate of the costs necessary to reclaim the mine that serves SJGS is subject to many assumptions, including the timing of reclamation, generally accepted practices at the time reclamation activities occur, and current inflation and discount rates. PNM cannot predict the ultimate cost to reclaim the mine that serves SJGS and would seek to recover all costs related to reclaiming the underground mine from its customers but could be exposed to additional loss related to surface mine reclamation. In connection with certain mining permits relating to the operation of the San Juan mine, Westmoreland was required to post reclamation bonds of $118.7 million with the NMMMD. In order to facilitate the posting of reclamation bonds by sureties on behalf of Westmoreland, TXNM entered into the WFB LOC Facility under which letters of credit aggregating $30.3 million have been issued.

A coal mine reclamation study for the surface mine that serves Four Corners was completed in December 2024. The study reflected operation of the mine through 2031, the term of the Four Corners CSA. PNM remeasured its liability, which resulted in a decrease in overall reclamation costs of $1.6 million, due primarily to lower overhead costs, contractor management costs, and taxes and royalties. Due to the NMPRC cap on the amount that can be collected from retail customers for final reclamation of the surface mines at $100.0 million, PNM recorded the decrease related to the surface mine liability as a regulatory disallowance on the Consolidated Statements of Earnings for the year ended December 31, 2024. In 2025, APS provided an update to the cumulative MMBTU consumption for Four Corners for the purpose of allocating final mine reclamation costs. Based on the consumption outlook, PNM’s forecasted share of final reclamation costs was reduced from 9.755% to 9.096%. As a result on September 30, 2025, PNM recorded a decrease in the liability related to the surface mine of $0.9 million on the Condensed Consolidated Balance Sheets. This decrease is also recorded as a $0.9 million reduction in regulatory disallowance on the Condensed Consolidated Statements of Earnings for the three and nine months ended September 30, 2025.

Based on the most recent estimates, PNM’s remaining payments as of September 30, 2025 for mine reclamation, in future dollars, are estimated to be $34.6 million for the surface mines at both SJGS and Four Corners and $63.7 million for the underground mine at SJGS. At September 30, 2025 and December 31, 2024, liabilities, in current dollars, of $24.1 million and $38.3 million for surface mine reclamation and $55.0 million and $52.9 million for underground mine reclamation were recorded in other deferred credits.

The SJGS owners are parties to a reclamation trust funds agreement to provide financial assurance for post-term coal mine reclamation obligations. The trust funds agreement requires each owner to enter into an individual trust agreement with a financial institution as trustee, create an irrevocable reclamation trust, and meet year-end funding targets set by funding curves that are approved by the SJGS ownership. PNM began using its mine reclamation trust to pay for final mine reclamation costs in April 2023. Because the trust agreement requires meeting specific funding targets at year end, it may be necessary for PNM to make additional contributions to meet those targets. PNM contributed $27.3 million in 2024. Based on PNM’s reclamation trust fund balance at September 30, 2025, current forecasts, and current funding curve targets, PNM anticipates contributing $6.5 million in 2025 and doesnot anticipate making any contributions in 2026 or 2027.

Under the Four Corners CSA, PNM is required to fund its share of estimated final reclamation costs in annual installments into an irrevocable escrow account solely dedicated to the final reclamation cost of the surface mine at Four Corners. PNM contributed $3.2 million in 2024 and anticipates contributing $0.5 million per year for 2025, 2026 and 2027.

PNM recovers from retail customers reclamation costs associated with the underground mine. However, the NMPRC capped the amount collected from retail customers for final reclamation of the surface mines at $100.0 million for both SJGS and Four Corners. If future estimates increase the liability for surface mine reclamation, the excess would be expensed at that time. The impacts of changes in New Mexico state law as a result of the enactment of the ETA and regulatory determinations made by the NMPRC may also affect PNM’s financial position, results of operations, and cash flows. PNM is currently unable to determine the outcome of these matters.

SJGS Decommissioning

On November 9, 2021, the San Juan County Commission approved the Coal-Fired Electricity Generating Facility Demolition and Remediation Ordinance (“Ordinance 121”), requiring the full demolition of SJGS upon its complete and permanent closure. Ordinance 121 required the SJGS owners to submit a proposed demolition and remediation plan no later than three months after SJGS was retired. The SJGS owners submitted the decommissioning and remediation plan on December 28, 2022. In connection with restructuring of the SJGS ownership on December 31, 2017, PNM and the other SJGS owners entered into the San Juan Decommissioning and Trust Funds Agreement, which requires PNM to fund its ownership share of final decommissioning costs into an irrevocable trust. Under the agreement, PNM made an initial funding of $14.7 million in December 2022 and made an additional contribution of $7.0 million in 2024. The amount and timing of additional trust funding is subject to revised decommissioning cost studies and agreement among the SJGS owners. PNM began using its decommissioning trust to pay for demolition and decommissioning costs in October 2023. PNM has posted a surety bond in the amount of $46.0 million in connection with certain environmental decommissioning obligations and must maintain the bond or other financial assurance until those obligations are satisfied. The surety bond only represents a liability if the SJGS owners fail to deliver on its contractual liability.

PNM records its share of the SJGS decommissioning obligation as an ARO on its Condensed Consolidated Balance Sheets. Studies on the decommissioning costs of SJGS are performed periodically and revisions to the ARO liability are recorded. In the third quarter of 2022, a new decommissioning cost study was completed, which required PNM to remeasure its SJGS decommissioning ARO. The new study resulted in an estimated decrease to PNM’s share of the decommissioning obligation of $21.1 million, which was recorded in September 2022.

On July 29, 2025 PNM received a letter from the NMED indicating that the NMED designated PNM as a responsible party and requiring a Stage 1 Abatement Plan (“S1AP”) proposal for SJGS for groundwater and soil contamination associated with former operations at SJGS. NMED has approved PNM’s request to delay the submission of the S1AP to November 26, 2025. PNM is currently working with experienced consultants to design and conduct site investigations and groundwater modeling to develop the S1AP. PNM is currently unable to determine the outcome of this matter.

PVNGS Liability and Insurance Matters

Public liability for incidents at nuclear power plants is governed by the Price-Anderson Nuclear Industries Indemnity Act, which limits the liability of nuclear reactor owners to the amount of insurance available from both commercial sources and an industry-wide retrospective payment plan. The insurance limit is subject to an adjustment every five years based upon the aggregate percentage change in the Consumer Price Index. The most recent adjustment took effect on January 1, 2024. As of that date, in accordance with this act, the PVNGS participants are insured against public liability exposure for a nuclear incident up to $16.3 billion per occurrence. PVNGS maintains the maximum available nuclear liability insurance in the amount of $500 million, which is provided by American Nuclear Insurers. The remaining $15.8 billion is provided through a mandatory industry-wide retrospective assessment program. If losses at any nuclear power plant covered by the program exceed the accumulated funds, PNM could be assessed retrospective premium adjustments. The maximum retrospective premium per reactor under the program for each nuclear liability incident is $165.9 million, subject to a maximum annual premium of $24.7 million per incident. Based on PNM’s ownership interest in thethree units, PNM’s maximum retrospective premium per incident for allthree units is $36.3 million, with a maximum annual payment limitation of $5.4 million, to be adjusted periodically for inflation.

The PVNGS participants maintain insurance for damage to, and decontamination of, property at PVNGS in the aggregate amount of $2.8 billion, a substantial portion of which must first be applied to stabilization and decontamination. These coverages are provided by Nuclear Electric Insurance Limited (“NEIL”). The primary policy offered by NEIL contains a sublimit of $2.25 billion for non-nuclear property damage. If NEIL’s losses in any policy year exceed accumulated funds, PNM is subject to retrospective premium adjustments of $5.3 million. The insurance coverages discussed in this and the previous paragraph are subject to certain policy conditions, sublimits, and exclusions.

(12)Regulatory and Rate Matters

The Company is involved in various regulatory matters, some of which contain contingencies that are subject to the same uncertainties as those described in Note 11. Additional information concerning regulatory and rate matters is contained in Note 17 of the Notes to Consolidated Financial Statements in the 2024 Annual Reports on Form 10-K.

TXNM

Merger Proceedings

On August 25, 2025, TXNM filed applications for approval of its proposed Merger with Blackstone Infrastructure (Note 17) with the NMPRC, PUCT, and FERC. In addition to strong governance and oversight provisions, the applications include the following benefits for PNM and TNMP’s customers:

Application to the NMPRC

•$105.0 million in retail rate credits to be paid over four years

•$10.0 million in additional contributions to the PNM Good Neighbor Fund to be paid over 10 years

•$35.0 million in economic development funding to be paid over 10 years

•$25.0 million commitment to innovative technologies to support New Mexico’s transition to carbon-free energy

•PNM’s continued strong community involvement and charitable giving

The NMPRC does not have a statutory timeframe for consideration of the application.

Application to the PUCT

•Rate credits of $35.0 million to be paid over four years

•$10.0 million in economic development funding to be paid over 10 years

•$5.0 million in additional community support over 10 years to enhance charitable giving

The PUCT has a 180-day statutory timeframe for consideration of the application.

Application to the FERC

The application demonstrates that the Merger is consistent with the public interest because it will not have an adverse effect on competition, rates, and regulation and will not result in any inappropriate cross-subsidization. The FERC also has a 180-day statutory timeframe for consideration of the application.

PNM

New Mexico General Rate Case

2025 Rate Request

On June 14, 2024, PNM filed an application with the NMPRC for a general increase in retail electric rates. The proposed base rate changes would be implemented in two phases, with the first phase effective July 1, 2025 and the second phase effective January 1, 2026. Key aspects of PNM’s request include:

•Recovery on total rate base of $3.0 billion, based on a FTY with the 12 months ending June 30, 2026

•An increase of $174.3 million in retail revenues, comprised of a $92.2 million increase in base rates and a $82.1 million increase in revenues collected under PNM’s FPPAC

•Drivers of revenue deficiency:

◦Needed investments across distribution, transmission, and generation facilities to ensure safe, reliable delivery of electricity

◦Increased operations and maintenance expenses to meet operational needs, including wildfire risk mitigation

◦Costs associated with ESAs, previously approved by the NMPRC, necessary to serve our customers

◦ROE of 10.45%

◦Proposed capital structure of 52.5% equity

◦An increased cost of borrowing

◦Adjustments to Four Corners depreciation rates to recover remaining plant investments through July 2031, the expected abandonment date of the facility

•Proposed ratemaking treatment of ESAs to be recovered through PNM’s FPPAC which began July 1, 2025

On November 26, 2024, PNM filed an unopposed comprehensive stipulation with the NMPRC. Key components agreed upon by the signatories are as follows:

•Overall revenue requirement increase of $105.0 million with the first phase effective July 1, 2025 and the second phase effective April 1, 2026

•ROE of 9.45%

•Capital structure of 51.0% equity

•Maintain currently approved depreciation rates for Four Corners as established in PNM’s 2024 Rate Change and PNM’s NM 2015 Rate Case

•Modification of PNM’s current amortization period through December 31, 2028 on the unprotected Excess Deferred Federal Income Taxes (“EDFIT”) regulatory liability to reflect amortization of remaining unprotected EDFIT through December 31, 2027

•Costs associated with ESAs shall be recovered through base rates

◦PNM will establish a regulatory asset or regulatory liability for the difference in actual ESA costs compared to the forecasted $82.1 million included in base rates in the test period and thereafter until new rates are effective from PNM’s next general rate case filing. The regulatory asset or regulatory liability will be subject to NMPRC approval in PNM’s next rate case

•PNM will establish a regulatory liability associated with investment tax credits for the Sandia energy storage system as proposed in its application

•PNM will establish a regulatory liability equal to the return on legacy meters currently included in rates, as the legacy meters are retired during PNM’s deployment of its approved Grid Modernization Plan

•PNM will make a one-time shareholder contribution of $1.5 million to the Good Neighbor Fund

A hearing was held on February 17 and 18, 2025. On April 8, 2025, the hearing examiners issued a certification of stipulation recommending approval of the unopposed stipulation and on May 15, 2025, the NMPRC issued a final order adopting the unopposed stipulation. This matter is now concluded.

2024 Rate Change

In December 2022, PNM filed an application with the NMPRC for a general increase in retail electric rates. On January 3, 2024, the NMPRC issued a final order authorizing PNM to implement an increase in non-fuel base rates of $15.3 million, effective for service beginning January 15, 2024. The final order included an ROE of 9.26% and a capital structure of 49.61% equity,50.10% debt, and 0.29% preferred stock. As a result of the final order, PNM recorded a regulatory disallowance of $55.5 million and a corresponding reduction to Utility Plant in the year ended December 31, 2023, after accounting for previous impairments, to reflect the remedy adopted in the Final Order for Four Corners. In addition, PNM had recorded a reduction to electric operating revenues of $38.4 million with a corresponding increase to current regulatory liability of $19.2 million and deferred regulatory liability of $19.2 million for the PVNGS rate refunds that are being returned to customers over atwo-year period ending March 2026. PNM had also recorded a regulatory disallowance of $8.2 million and a corresponding reduction to Utility Plant for the disallowance of construction work in progress (“CWIP”) from PVNGS.

In March 2024, notice of appeals were separately filed with the NM Supreme Court by NEE and PNM, and a joint notice of appeal was filed by the NM Department of Justice, Bernalillo County, and Albuquerque Bernalillo County Water Utility Authority (“ABCWUA”). NEE’s appeal was subsequently consolidated with the joint notice of appeal. In the statements of issues submitted in the parties’ appellate dockets, PNM took issue with the NMPRC’s ruling on capital structure; other appellants primarily challenged the NMPRC rulings related to Four Corners and Palo Verde cost recovery. On June 20, 2025, PNM filed an uncontested motion to dismiss its appeal. The NM Supreme Court granted PNM’s uncontested motion to dismiss its appeal, and on September 25, 2025, issued a ruling rejecting the consolidated appeal and upholding the NMPRC’s final order. This matter is now concluded.

Renewable Energy Portfolio Standard

As discussed in Note 11, the ETA amends the REA including removal of diversity requirements and certain customer caps and exemptions relating to the application of the RPS under the REA. The REA provides for streamlined proceedings for approval of utilities’ renewable energy procurement plans, assures that utilities recover costs incurred consistent with approved procurement plans, and requires the NMPRC to establish a Reasonable Cost Threshold (“RCT”) for the procurement of renewable resources to prevent excessive costs being added to rates. The ETA sets a RCT of $60 per MWh, adjusted for inflation, using an average annual levelized resource cost basis. PNM makes renewable procurements consistent with the NMPRC approved plans and recovers certain renewable procurement costs from customers through the renewable energy rider billed on a KWh basis.

Included in PNM’s approved procurement plans are the following renewable energy resources:

•158 MW of PNM-owned solar-PV facilities

•A PPA through 2044 for the output of New Mexico Wind, having a current aggregate capacity of 200 MW, and a PPA through 2035 for the output of Red Mesa Wind, having an aggregate capacity of 102 MW

•A PPA through 2040 for 140 MW of output from La Joya Wind II

•A PPA through 2042 for the output of the Lightning Dock Geothermal facility with a capacity of 11 MW

•Solar distributed generation, aggregating 327.9 MW at September 30, 2025, owned by customers or third parties from whom PNM purchases any net excess output and RECs

The NMPRC has authorized PNM to recover certain renewable procurement costs through a rate rider billed on a per KWh basis. In its 2025 renewable energy procurement plan, which became effective on January 1, 2025, PNM proposed to collect $58.7 million for the year. PNM recorded revenues from the rider of $10.9 million and $42.5 million in the three and nine months ended September 30, 2025 and $11.1 million and $41.7 million in the three and nine months ended September 30, 2024.

Under the renewable rider, if PNM’s earned rate of return on jurisdictional equity in a calendar year, adjusted for items not representative of normal operations, exceeds the NMPRC-approved rate by 0.5%, PNM is required to refund the excess to customers during May through December of the following year. PNM did not exceed such limitation in 2024. On May 30, 2025, PNM filed its application for its 2026 renewable energy procurement plan, requesting to collect $54.3 million for the year. On September 25, 2025, the Hearing Examiners issued an RD recommending approval of PNM’s application with no significant modifications and on October 30, 2025, the NMPRC issued a Final Order approving the application as filed.

Energy Efficiency and Load Management

Program Costs and Incentives/Disincentives

The EUEA requires public utilities to achieve specified levels of energy savings and to obtain NMPRC approval to implement energy efficiency and load management programs. The EUEA requires the NMPRC to remove utility disincentives to implementing energy efficiency and load management programs and to provide incentives for such programs. The NMPRC has adopted a rule to implement this act. PNM’s costs to implement approved programs and incentives are recovered through a rate rider. During the 2019 New Mexico legislative session, the EUEA was amended to, among other things, include a decoupling mechanism for disincentives, preclude a reduction to a utility’s ROE based on approval of disincentive or incentive mechanisms, establish energy savings targets for the period 2021 through 2025, and require that annual program funding be 3% to 5% of an electric utility’s annual customer bills excluding gross receipt taxes, franchise and right-of-way access fees, provided that a customer’s annual cost does not exceed seventy-five thousand dollars.

In 2023, PNM filed an application for energy efficiency and load management programs to be offered in 2024, 2025, and 2026 (the “2024 Plan”). The 2024 Plan proposed to continueten existing energy efficiency programs with modification and a total annual budget of $34.5 million in 2024, $35.4 million in 2025, and $36.5 million in 2026. The application also sought approval of an annual base incentive of 7.1% of the portfolio budget and a sliding scale that provides additional incentive for additional energy saved as a percentage of program cost, up to the maximum allowed by the energy efficiency rule which for PNM is 8.82%. On January 26, 2024, the hearing examiners in the case issued a RD. The RD largely approved the 2024 Plan but with modifications that include the pursuit of demand response resources, additional analysis in future filings, adjustments to certain energy efficiency programs, and modification of the incentive sliding scale cap to reflect a new maximum. On March 7, 2024, the NMPRC approved the RD in its entirety.

Integrated Resource Plans

NMPRC rules require that investor-owned utilities file an IRP every three years and is required to cover a 20-year planning period and contain an action plan covering the first three years of that period. The IRP establishes a collaborative facilitated process for a utility and stakeholders to agree on a statement of need for potential new or additional resources, as well as an action plan to guide procurement or development of resources to meet the stated need. A most-cost-effective portfolio of resources shall be derived from the statement of need analysis. The statement of need and action plan must be accepted before the utility begins the resource solicitation process pursuant to the IRP Rule. Following acceptance of the statement of need and action plan, a utility will provide the NMPRC and intervenors drafts of the RFP and a timeline for issuing, receiving, evaluating, and ranking bids. The NMPRC will then appoint an Independent Monitor (“IM”) to oversee the RFP process, which allows for parties and the IM to comment on the RFP consistency with the IRP, after which the utility issues the RFP. Within 120 days of receiving bids the utility shall provide the IM with results including pricing and non-price evaluation criteria, ranking of bids, chosen portfolio and alternatives that also meet the needs; the IM then rules on the fairness of the RFP execution. Acceptance of the statement of need and action plan will not constitute a finding of prudency or pre-approval of costs associated with the additional resources. Following the RFP and IM processes, the utility may apply for approvals, and any costs incurred to implement the action plan will be considered in a general rate case and/or resource acquisition proceeding.

2023 IRP

On December 15, 2023, PNM filed its 2023 IRP with a continued focus on a carbon-free energy system by 2040. The plan highlights the need for the significant sustained addition of resources over the next two decades, replacing retiring or expiring capacity, meeting concurrent load growth, while reducing the carbon intensity of PNM’s portfolio. On April 4, 2024, the NMPRC accepted PNM’s 2023 IRP.

On December 30, 2024, PNM issued its 2029-2032 RFP for at least 900 MW of new energy resources to come online between 2029 and 2032, with at least 500 MW needed by 2030. The RFP is consistent with the needs identified in PNM’s 2023 IRP, which identified a range of 900 to 2,900 MW of new capacity needed by 2032, depending on the type of resources selected. The 2029-2032 RFP is anticipated to identify potential replacement resources for PNM’s current natural gas generation capacity as well as PNM’s ownership interest in Four Corners. PNM has been granted an extension from the required September 2025 deadline to a January 9, 2026 deadline to file and present PNM’s evaluation of RFP bids, with the IM expected to issue a final report by February 9, 2026.

2028 Resource Application

On November 22, 2024, PNM filed an application with the NMPRC seeking approval of ESAs, a PPA, and a CCN for system resources in 2028 to be available to meet summer 2028 customer needs. PNM’s request includes:

•Two 150 MW ESAs

•A 167 MW PPA for the Valencia power plant through 2039

•A CCN for a 100 MW solar facility and a 30 MW battery to be PNM-owned and located in San Juan County. The request provides the opportunity to increase the 30 MW battery by an additional 20 MW

On March 12, 2025, PNM and intervening parties filed an unopposed comprehensive stipulation with the NMPRC. The stipulation supports approval of PNM’s application, including the proposed option to increase the 30 MW battery by an additional 20 MW. On May 6, 2025, the hearing examiners issued a certification of stipulation recommending approval of the unopposed stipulation and on June 26, 2025, the NMPRC approved the unopposed stipulation. This matter is now concluded.

Grid Modernization Plan

In October 2022, in compliance with New Mexico Grid Modernization Statute, PNM filed its Grid Modernization Plan with the NMPRC. The projects included in the application improve customers’ ability to customize their use of energy and ensure that customers, including low-income customers, are a top priority and will benefit consistent with the Grid Modernization Statute. PNM’s proposal to modernize its electricity grid through infrastructure and technology improvements also increases the efficiency, reliability, resilience, and security of PNM’s electric system. PNM’s application included grid modernization investments of approximately $344 million for the firstsix years of a broader 11-year strategy. The approved rate rider will recover capital costs, operating expenses, and taxes associated with the investments included in the plan. On October 17, 2024, the NMPRC issued a final order which largely approved PNM’s application with minor modifications.

On June 20, 2025, PNM filed its first annual Grid Modernization Plan review to provide updates on year one implementation progress and outline planned activities for year two, in alignment with regulatory expectations. Additionally, PNM has updated key portions of the forecasted strategy including increasing investments from approximately $344 million to $367 million in the firstsix years, while decreasing projected operations and maintenance costs by approximately 18%.

Transportation and Electrification Program (TEP)

On June 1, 2023, PNM filed its 2024-2026 TEP with the NMPRC, requesting approval of a $37.1 million total three-year budget and continuation of the current TEP Rider. Approximately 22% of the budget, $8.0 million, will be dedicated to low-income customers. On February 2, 2024, the hearing examiners in the case issued a RD largely approving PNM’s 2024-2026 TEP but with certain modifications. On February 23, 2024, the NMPRC approved the RD with modifications that reduced thethree-year budget by $4.0 million, for a total revised budget of $32.9 million. The TEP rider became effective on April 26, 2024.

EDAM

As previously disclosed, PNM participates in the EIM, a real-time wholesale energy trading market operated by the CAISO, that enables participating electric utilities to buy and sell energy. EDAM is a voluntary day-ahead regional market that expands on CAISO’s EIM market, which PNM plans on joining in the fall of 2027. On August 22, 2025, PNM filed an application with the NMPRC requesting approval to create a regulatory asset for the costs associated with joining the EDAM, which was approved in an accounting order issued on October 16, 2025. PNM expects to seek recovery of these costs in a future rate case.

Meta Platforms Inc. Data Center - Phase IV

PNM has a special service contract to provide service to Meta for a data center in PNM’s service area. Meta’s service requirements include the acquisition by PNM of a sufficient amount of new renewable energy resources and RECs to match the energy and capacity requirements of the data center. The cost of renewable energy procured is passed through to Meta under a rate rider. A special service rate is applied to Meta’s energy consumption in those hours of the month when their consumption exceeds the energy production from the renewable resources.

On June 13, 2025, PNM filed an application with the NMPRC for an amended special service contract, PPAs, ESAs, special service rate, and an amended rate rider to service a new phase of the data center, the Greater Kudo, LLC Data Center. This amended special service contract requests:

•three 20-year solar PPAs totaling 290 MW

•three 20-year ESAs totaling 268 MW of storage

•a third revised and restated special service contract with Greater Kudo, LLC Data Center; and

•updates to the special service rate - Renewable Energy Resources, the Green Energy Rider, and the Production Cost Allocation Rider.

On July 3, 2025 a procedural order was issued and on October 21, 2025, a prehearing conference was held where all parties agreed that a public hearing was unnecessary and that the evidence on record was sufficient to support a RD. The NMPRC is expected to rule on the application during a future open meeting where public comment is permitted. PNM is unable to predict the outcome of this matter.

BESS Project

On August 6, 2025, PNM filed an application with the NMPRC for approval of a CCN to construct, own, and operate 30 MWs of energy storage. The application consists of 6 MW batteries to be constructed atfive existing PNM-owned solar facilities located in Otero County, San Miguel County, Luna County andtwo sites in Valencia County. PNM estimates that the BESS Project will cost $78.7 million and will assist in serving our summer peak season when operational.

TNMP

HB 5247

On June 20, 2025, Texas House Bill 5247 (“HB 5247”) was signed into law by Governor Gregg Abbott. HB 5247, which took effect immediately, added Section 36.216 to the Public Regulatory Act (“PURA 36.216”), authorizing certain electric utilities with total capital expenditures that exceeded 300 percent of annual depreciation in a calendar year, to elect, in the following calendar year, to file a single, annual proceeding to adjust nonfuel rates on a system-wide basis to reflect changes in transmission and distribution rates previously authorized under certain other interim rate mechanisms. A utility seeking to make this election under PURA 36.216 is required to file a notice with the PUCT informing them of its intent and provide supporting documentation of the applicable capital expenditures at least 60 days before filing the single, annual proceeding and correspondingly must notify the PUCT if the utility determines that it no longer qualifies for continued use of the election. Management has evaluated the application of HB 5247 and PURA 36.216 and determined that TNMP qualifies as the type of electric utility that would be eligible for the election. Currently, TNMP expects to make its first comprehensive filing under Section 36.216 in 2026 with a view towards recovering costs associated with eligible transmission and distribution investments that were placed into service after December 31, 2024 and that are not currently reflected in rates. In the interim, TNMP plans to immediately begin to recognize a regulatory asset for costs associated with its eligible transmission and distribution capital investments, including depreciation expense and carrying costs. At September 30, 2025 the regulatory asset associated with these costs totaled $2.2 million.

Sales and Use Tax Refund

On March 12, 2025, TNMP filed a refund claim with the Texas Comptroller’s office for overpaid sales and use taxes primarily related to asset purchases. The $34.6 million refund claim covers periods from January 2022 to October 2024 and amounts received, net of consultant fees, are expected to be applied to 2025 TNMP capital projects. On September 22, 2025, TNMP received the requested refund net of $7.5 million in consultant fees; $24.7 million was applied to 2025 TNMP capital projects; $2.1 million to offset related interest expense; and $0.3 million for other related expenses.

Transmission Cost of Service Rates

TNMP can update its TCOS rates twice per year to reflect changes in its invested capital although updates are not allowed while a general rate case is in process. Updated rates reflect the addition and retirement of transmission facilities, including appropriate depreciation, federal income tax and other associated taxes, and the approved rate of return on such facilities.

The following sets forth TNMP’s recent interim transmission cost rate increases:

Periodic Distribution Rate Adjustment

PUCT rules permit interim rate adjustments twice per year to reflect changes in investments in distribution assets. Additionally, a DCRF may be filed during a pending rate case proceeding as long as that DCRF request is not filed until the 185th day after the rate case proceeding was initiated. The following sets forth TNMP’s recent interim distribution rate increases:

On July 31, 2025, TNMP filed its second 2025 DCRF that requested an increase in TNMP annual distribution revenues of $5.4 million based on an increase in rate base of $27.9 million. The case is pending review by the PUCT.

Energy Efficiency

TNMP recovers the costs of its energy efficiency programs through an energy efficiency cost recovery factor (“EECRF”), which includes projected program costs, under and over collected costs from prior years, rate case expenses, and performance bonuses (if programs exceed mandated savings goals). On May 31, 2024, TNMP filed its request to adjust the EECRF to reflect changes in costs for 2025. On October 24, 2024, the PUCT approved the total amount requested, authorizing recovery of $7.0 million, which includes a performance bonus of $1.3 million based on TNMP’s energy efficiency achievements in the 2023 plan year and became effective March 1, 2025. On May 30, 2025, TNMP filed its request to adjust the EECRF to reflect changes in costs for 2026. The total amount requested was $8.1 million, which includes a performance bonus of $2.5 million based on TNMP’s energy efficiency achievements in 2024. The case is pending review by the PUCT.

Hurricane Beryl

On July 8, 2024, Hurricane Beryl made landfall in the Texas Gulf Coast leaving approximately 116,000 customers in the TNMP service area without power. As of September 30, 2025, TNMP incurred $54.0 million of costs, of which $33.5 million has been recorded in Utility Plant and $20.5 million has been recorded as a Regulatory Asset on the Condensed Consolidated Balance Sheets. TNMP will seek collection of such costs in a future regulatory proceeding.

System Resiliency Plan (“SRP”)

In 2023, the Texas Legislature enacted House Bill No, 2555 (“HB 2555”), permitting an electric utility to seek approval of, and cost recovery for, a system resiliency plan. On August 28, 2024, TNMP filed its first SRP with the PUCT designed to benefit customers through enhanced resiliency of its distribution system, as intended under HB 2555. The SRP includes approximately $600 million of capital investments and approximately $151 million of other related costs over three years and was developed using a comprehensive and data-driven approach which evaluated various types of resiliency events posing material risk to the safe and reliable operation of TNMP's distribution system. TNMP's service territory includes non-contiguous areas across different regions of Texas, ranging from small communities and rural areas to communities around large metropolitan areas, each with unique risks. Investments in the SRP are prioritized based on customer benefit, physical protection of infrastructure, foundational investments in operational and cybersecurity technologies, and wildfire risk reduction and are focused on lower-performing areas in the context of reliability. Eight different resiliency measures are outlined in the SRP with associated programs and infrastructure impacts to improve the system's ability to prevent, withstand, mitigate and/or more promptly recover from resiliency events: distribution system resiliency, distribution system protection modernization, vegetation management, wildfire mitigation, flood mitigation, enhanced operations system technology, cybersecurity, and physical security resiliency. Recovery of investments and costs are permissible primarily through semi-annual DCRF filings, with deferral of depreciation and other certain expenses until recovery begins.

On December 11, 2024, TNMP filed an unopposed settlement with the PUCT. The settlement includes $565.8 million of capital investments over 2025 through 2027, reflecting 94% of TNMP’s proposed plan investments. The settlement also encompasses $128.2 million of operations and maintenance expenses associated with several programs, including vegetation management and wildfire mitigation. On March 26, 2025, TNMP received the final order from the PUCT which included modifications reflecting capital investments of $545.8 million and $86.1 million of operating and maintenance costs. As of September 30, 2025, TNMP incurred $3.3 million of operating and maintenance costs, all of which have been recorded as a Regulatory Asset on the Condensed Consolidated Balance Sheets. TNMP will seek collection of such costs in a future regulatory proceeding.

(13)Lease Commitments

The Company leases office buildings, vehicles, energy storage facilities, and other equipment. In addition, certain rights-of-way agreements are classified as leases. All of the Company’s leases with terms in excess of one year are recorded on the balance sheet by recording a present value lease liability and a corresponding right-of-use asset. Operating lease expense is recognized within operating expenses according to the use of the asset on a straight-line basis. Financing lease costs, which are comprised primarily of fleet and office equipment leases commencing after January 1, 2019, are recognized by amortizing the right-of-use asset on a straight-line basis and by recording interest expense on the lease liability. Financing lease right-of-use assets amortization is reflected in depreciation and amortization and interest on financing lease liabilities is reflected as interest charges on the Company’s Condensed Consolidated Statements of Earnings. See additional discussion of the Company’s leasing activities in Note 8 of the Notes to Consolidated Financial Statements in the 2024 Annual Reports on Form 10-K.

PVNGS

In 1985 and 1986, PNM entered into leases for its interest in PVNGS Unit 1 and 2. The leases initially were scheduled to expire in January 2015 forfour Unit 1 leases and January 2016 forfour Unit 2 leases. Following procedures set forth in the PVNGS leases, PNM notified four of the lessors under the Unit 1 leases andone lessor under the Unit 2 lease that it would elect to renew those leases on the expiration date of the original leases. Thefour Unit 1 leases expired in January 2023 and theone Unit 2 lease expired in January 2024. PNM has no further lease payments related to PVNGS Unit 1 or 2.

On April 5, 2021, PNM and Salt River Project entered into an Asset Purchase and Sale Agreement, pursuant to which PNM agreed to sell to Salt River Project certain PNM-owned assets and nuclear fuel necessary to the ongoing operation and maintenance of leased capacity in PVNGS Unit 1 and Unit 2. In January 2023, the Unit 1 leases expired, and PNM closed on the associated sale to Salt River Project. In January 2024, the Unit 2 leases expired, and PNM closed on the associated sale to Salt River Project, receiving payments totaling $3.4 million, of which $2.8 million was recorded as a reduction to Net utility plant on the Condensed Consolidated Balance Sheets and was presented as cash flows from investing activities on the Condensed Consolidated Statement of Cash Flows. In addition, $0.6 million was recorded as a reduction to Materials, supplies and fuel stock on the Condensed Consolidated Balance Sheets and was presented as cash flows from operating activities on the Condensed Consolidated Statement of Cash Flows.

Land Easements and Rights-of-Way

Many of PNM’s electric transmission and distribution facilities are located on lands that require the grant of rights-of-way from governmental entities, Native American tribes, or private parties. PNM has completed several renewals of rights-of-way, the largest of which is a renewal with the Navajo Nation. PNM is obligated to pay the Navajo Nation annual payments of $6.0 million, subject to adjustment each year based on the Consumer Price Index, through 2029. PNM’s April 2025 payment for the amount due under the Navajo Nation right-of-way lease was $8.8 million, which included amounts due under the Consumer Price Index adjustment. Changes in the Consumer Price Index subsequent to January 1, 2019 are considered variable lease payments.

PNM has other prepaid rights-of-way agreements that are not accounted for as leases or recognized as a component of plant in service. PNM reflects the unamortized balance of these prepayments in other deferred charges on the Condensed Consolidated Balance Sheets and recognizes amortization expense associated with these agreements in the Condensed Consolidated Statement of Earnings over their term. As of September 30, 2025 and December 31, 2024, the unamortized balance of these rights-of-ways was $69.7 million and $67.1 million. PNM recognized amortization expense associated with these agreements of $1.1 million and $3.3 million in the three and nine months ended September 30, 2025 and $1.1 million and $3.2 million in the three and nine months ended September 30, 2024.

Fleet Vehicles and Equipment

Fleet vehicle and equipment leases commencing on or after January 1, 2019 are classified as financing leases. Fleet vehicle and equipment leases existing as of December 31, 2018 are classified as operating leases. The Company’s fleet vehicle and equipment lease agreements include non-lease components for insignificant administrative and other costs that are billed over the life of the agreement. At September 30, 2025, residual value guarantees on fleet vehicle and equipment leases are $0.7 million, $0.6 million, and $1.3 million for PNM, TNMP, and TXNM Consolidated.

Energy Storage Agreements

The Company has ESAs with fixed payments over the life of the agreements, that are accounted for as operating leases, for which the Company records the initial lease liabilities and corresponding right-of-use assets. The Company also has ESAs with monthly payments that vary, depending on the available capacity of the energy storage facility, that are also accounted for as operating leases. However, due to the variable nature of the consideration, these agreements do not require a lease liability or a right-of-use asset to be recorded upon inception. Expenses for this type of lease are reflected in variable lease expense in the tables below. In addition, the Company has elected to separate lease components from non-lease components for ESAs and accordingly, does not include non-lease components in the measurement of the lease liability or right-of-use asset. The non-lease components, which are not included in the measurement of the lease liability or the corresponding right-of-use asset, comprise 25.5% of the value of the agreements.

Information related to the Company’s operating leases recorded on the Condensed Consolidated Balance Sheets is presented below:

As discussed above, the Company classifies its fleet vehicle and equipment leases and its office equipment leases commencing on or after January 1, 2019 as financing leases.

Information related to the Company’s financing leases recorded on the Condensed Consolidated Balance Sheets is presented below:

Information concerning the weighted average remaining lease terms and the weighted average discount rates used to determine the Company’s lease liabilities is presented below:

Information for the components of lease expense is as follows:

Supplemental cash flow information related to the Company’s leases is as follows:

Capitalized lease costs are reflected as investing activities on the Company’s Condensed Consolidated Statements of Cash Flows for the nine months ended September 30, 2025 and 2024. Future expected lease payments are shown below:

The above table includes $15.2 million, $14.7 million, and $30.2 million for PNM, TNMP, and TXNM at September 30, 2025 for expected future payments on fleet vehicle and equipment leases that could be avoided if the leased assets were returned and the lessor is able to recover estimated market value for the equipment from third parties.

At September 30, 2025, the Company has an ESA that has been executed with a lease component that has not yet commenced. The lease component begins in 2029, expires in 2044, and will be recognized as a lease asset and liability upon the commencement. The expected total fixed consideration to be paid for this arrangement, which includes non-lease payments, is approximately $94.3 million over the 20-year term of the agreement.

(14)Income Taxes

The Company makes an estimate of its anticipated effective tax rate for the year as of the end of each quarterly period within its fiscal year. In interim periods, income tax expense is calculated by applying the anticipated annual effective tax rate to year-to-date earnings before income taxes. Certain unusual or infrequently occurring items are excluded from the estimated annual rate calculation. Such items include regulatory disallowances, Merger-related costs, and excess tax benefits or deficiencies related to stock awards. At September 30, 2025, TXNM, PNM, and TNMP estimated their effective income tax rates for the year ended December 31, 2025 would be 13.04%,9.59%, and 20.43%. The primary difference between the statutory income tax rates and the effective tax rates is the effect of the reduction in income tax expense resulting from the amortization of excess deferred federal income taxes.

During the nine months ended September 30, 2025, income tax expense was calculated by applying the expected annual effective income tax rate to earnings before income taxes was decreased by $4.7 million for the tax effects of Merger related costs, of which $0.2 million was allocated to PNM and $0.2 million was allocated to TNMP. Excess tax benefits related to stock awards decreased tax expense by $0.4 million for TXNM, with $0.3 million allocated to PNM and $0.1 million allocated to TNMP. Tax expense was increased by $0.2 million for the tax effects of regulatory disallowances at TXNM and PNM.

Beginning February 2018, PNM’s NM 2016 Rate Case reflected the reduction in the federal corporate income tax rate resulting from enactment of legislation commonly known as the Tax Cuts and Jobs Act (the “TCJA”), including amortization of excess deferred federal income taxes. In accordance with the order in that case, PNM is returning the protected portion of excess deferred federal income taxes to customers over the average remaining life of plant in service as of December 31, 2017, and had been returning the unprotected portion of excess deferred federal income taxes to customers over a period of approximately twenty-three years. Pursuant to the final order in the 2024 Rate Change, the remaining balance of $62.7 million of unprotected excess deferred income taxes is being returned over afour-year period. The approved settlement in the TNMP 2018 Rate Case includes a reduction in customer rates to reflect the impacts of the TCJA beginning on January 1, 2019. TXNM, PNM, and TNMP will amortize federal excess deferred income taxes of $25.6 million, $22.9 million, and $2.7 million in 2025. See additional discussion of the impacts of the TCJA in Note 18 of the Notes to Consolidated Financial Statements in the 2024 Annual Reports on Form 10-K.

On July 4, 2025, changes in U.S. federal income tax laws were enacted through the OBBBA. The OBBBA generally extends and makes permanent the changes from the TCJA, including maintaining the 21% corporate tax rate, interest deductibility for regulated electric utilities, and state and local tax deductibility. The OBBBA also accelerates the phase-out of certain Inflation Reduction Act of 2022 energy tax credits and restricts the availability of credits for “foreign entities of concern.” As a result, TXNM anticipates potentially higher costs associated with any future renewable energy development but does not expect other aspects of the OBBBA to have a material impact on its financial statements.

(15)Related Party Transactions

TXNM, PNM, TNMP, and NMRD are considered related parties, as is PNMR Services Company, a wholly-owned subsidiary of TXNM that provides corporate services to TXNM and its subsidiaries in accordance with shared services agreements. These services are billed at cost on a monthly basis to the business units. In addition, prior to the sale of NMRD, PNM purchased renewable energy from certain NMRD-owned facilities at a fixed price per MWh of energy produced. On February 27, 2024, PNMR Development and AEP OnSite Partners sold their respective interests in NMRD and the table below reflects transactions with NMRD prior to the sale. The table below summarizes the nature and amount of related party transactions of TXNM, PNM, TNMP, and NMRD:

(16)Goodwill

The excess purchase price over the fair value of the assets acquired and the liabilities assumed by TXNM for its 2005 acquisition of TNP Enterprises, Inc. and Subsidiaries (“TNP”) was recorded as goodwill and was pushed down to the businesses acquired. In 2007, the TNMP assets that were included in its New Mexico operations, including goodwill, were transferred to PNM. TXNM’s reporting units that currently have goodwill are PNM and TNMP. The Company evaluates its goodwill for impairment annually at the reporting unit level or more frequently if circumstances indicate that the goodwill may be impaired. Application of the impairment test requires judgment, including the identification of reporting units, assignment of assets and liabilities to reporting units, and determination of the fair value of each reporting unit.

In certain circumstances an entity may perform a qualitative analysis to conclude that the goodwill of a reporting unit is not impaired. Under a qualitative assessment an entity considers macroeconomic conditions, industry and market considerations, cost factors, overall financial performance, other relevant entity-specific events affecting a reporting unit, as well as whether a sustained decrease (both absolute and relative to its peers) in share price has occurred. An entity considers the extent to which each of the adverse events and circumstances identified could affect the comparison of a reporting unit’s fair value with its carrying amount. An entity places more weight on the events and circumstances that most affect a reporting unit’s fair value or the carrying amount of its net assets. An entity also considers positive and mitigating events and circumstances that may affect its determination of whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount. An entity evaluates, on the basis of the weight of evidence, the significance of all identified events and circumstances in the context of determining whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount. A quantitative analysis is not required if, after assessing events and circumstances, an entity determines that it is not more likely than not that the fair value of a reporting unit is less than its carrying amount.

In other circumstances, an entity may perform a quantitative analysis to reach the conclusion regarding impairment with respect to a reporting unit. An entity may choose to perform a quantitative analysis without performing a qualitative analysis and may perform a qualitative analysis for certain reporting units, but a quantitative analysis for others. The first step of the quantitative impairment test requires an entity to compare the fair value of the reporting unit with its carrying value, including goodwill. If, as a result of this analysis, the entity concludes there is an indication of impairment in a reporting unit having goodwill, the entity is required to perform the second step of the impairment analysis, determining the amount of goodwill impairment to be recorded. The amount is calculated by comparing the implied fair value of the goodwill to its carrying amount. This exercise would require the entity to allocate the fair value determined in step one to the individual assets and liabilities of the reporting unit. Any remaining fair value would be the implied fair value of goodwill on the testing date. To the extent the recorded amount of goodwill of a reporting unit exceeds the implied fair value determined in step two, an impairment loss would be reflected in results of operations.

TXNM periodically updates its quantitative analysis for both PNM and TNMP. The use of a quantitative approach in a given period is not necessarily an indication that a potential impairment has been identified under a qualitative approach. When TXNM performs a quantitative analysis for PNM or TNMP, a discounted cash flow methodology is primarily used to estimate the fair value of the reporting unit. This analysis requires significant judgments, including estimations of future cash flows, which is dependent on internal forecasts, estimations of long-term growth rates for the business, and determination of appropriate weighted average cost of capital for the reporting unit. Changes in these estimates and assumptions could materially affect the determination of fair value and the conclusion of impairment. When TXNM performs a qualitative or quantitative analysis for PNM or TNMP, TXNM considers market and macroeconomic factors including changes in growth rates, changes in the WACC, and changes in discount rates. TXNM also evaluates its stock price relative to historical performance, industry peers, and to major market indices, including an evaluation of TXNM’s market capitalization relative to the carrying value of its reporting units.

For its annual evaluations performed as of April 1, 2025, TXNM performed a qualitative analysis for both the PNM and TNMP reporting units. In addition to the typical considerations discussed above, the qualitative analysis considered changes in the Company’s expectations of future financial performance since the April 1, 2024 quantitative analysis performed for PNM, as well as the April 1, 2020 quantitative analysis and the previous qualitative analyses through April 1, 2024 performed for TNMP. This analysis considered Company-specific events such as the Merger, potential impacts of legal and regulatory matters discussed in Note 11 and Note 12, including the outcomes in the 2025 Rate Request, PNM’s Grid Modernization Plan, and TNMP’s System Resiliency Plan. Based on an evaluation of these and other factors, the Company determined it was not more likely than not that the April 1, 2025 carrying values of PNM and TNMP exceeded their fair value.

For its annual evaluations performed as of April 1, 2024, TXNM performed a quantitative analysis for the PNM reporting unit and a qualitative analysis for the TNMP reporting unit. The quantitative analysis, discussed above, indicated that the fair value of the PNM reporting unit, which has goodwill of $51.6 million, exceeded its carrying value by approximately 54%. The qualitative analysis, in addition to the typical considerations discussed above, considered changes in the Company’s expectations of future financial performance since the April 1, 2020 quantitative analysis and the previous qualitative analyses through April 1, 2023 performed for TNMP. The April 1, 2020 quantitative evaluations indicated the fair value of the TNMP reporting unit, which has goodwill of $226.7 million, exceeded its carrying value by approximately 38%. This analysis considered events specific to TNMP such as the potential impacts of legal and regulatory matters discussed in Note 11 and Note 12. Based on an evaluation of these and other factors, the Company determined it was not more likely than not that the April 1, 2024 carrying values of PNM and TNMP exceeded their fair value. Since the April 1, 2024 annual evaluation, there have been no events, including the Merger, or indications that the fair values of the reporting units with recorded goodwill have decreased below their carrying values.

(17)Merger

On May 18, 2025, TXNM, Parent, and Merger Sub, entered into the Merger Agreement, pursuant to which Merger Sub will merge with and into TXNM, with TXNM surviving the Merger as a direct wholly-owned subsidiary of Parent. Parent and Merger Sub are affiliates of Blackstone Infrastructure.

Pursuant to the Merger Agreement, each issued and outstanding share of the common stock of TXNM (other than (i) the issued shares of TXNM common stock that are owned by TXNM, Parent, Merger Sub, or any other wholly-owned subsidiaries of Parent or TXNM, in each case, not held on behalf of third parties, which will be automatically cancelled at the Effective Time and (ii) shares of TXNM common stock outstanding immediately prior to the Effective Time and held by a holder who has not voted in favor of, or consented in writing to, the Merger who is entitled to, and who has demanded, payment for fair value of such shares in accordance with applicable New Mexico law) will, at the Effective Time, be converted into the right to receive $61.25 in cash, without interest.

The proposed Merger has been unanimously approved by the Board. Consummation of the Merger is subject to the satisfaction or waiver of certain customary conditions, including, without limitation, the approval by at least a majority of the holders of outstanding shares of TXNM common stock entitled to vote thereon, the absence of any material adverse effect on TXNM, no legal prohibition on the consummation of the Merger (a “Legal Restraint”), and the receipt of certain required regulatory approvals (including PUCT, NMPRC, FERC, NRC and under the Hart-Scott-Rodino Antitrust Improvements Act of 1976). The Merger Agreement does not contain any financing condition. On August 25, 2025 TXNM filed applications for regulatory approvals to the NMPRC, PUCT, and FERC (Note 12). On August 28, 2025, TXNM held a special meeting of shareholders whereby a majority of the holders of outstanding shares of TXNM common stock as of the close of business on July 17, 2025, voted to approve the Merger. The Merger is currently expected to close in the second half of 2026.

The Merger Agreement may be terminated by each of TXNM and Parent under certain circumstances, including if the Merger is not consummated by the 15-month anniversary of the execution of the Merger Agreement (as extended, the “End Date”), so long as failure of the Merger to consummate on or before the End Date was not due to the breach of the Merger Agreement by such party, subject to an automatic extension of the End Date until December 31, 2026 and an additional three-month extension by mutual agreement of the parties, in each case if all of the conditions to the closing, other than the conditions related to obtaining regulatory approvals or the absence of a Legal Restraint, have been satisfied or waived. The Merger Agreement also provides for other customary termination rights for both Parent (including if the Board changes its recommendation in respect of the Merger) and TXNM. The Merger Agreement further provides that, upon termination of the Merger Agreement under certain specified circumstances (including if Parent terminates the Merger Agreement due to a change in recommendation of the Board or if TXNM terminates the Merger Agreement to accept a Superior Proposal), TXNM will be required to pay Parent a termination fee of $210.0 million plus costs and expenses (“TXNM Termination Fee”). In addition, the Merger Agreement provides that (i) if the Merger Agreement is terminated by either party as a result of a Legal Restraint (solely in connection with required regulatory approvals), (ii) if the Merger Agreement is terminated by either party as a result of the Merger not being consummated by the End Date, (iii) the Merger Agreement is terminated by TXNM as a result of a terminable breach by Parent, (iv) Parent fails to effect the closing when all closing conditions have been satisfied and it is otherwise obligated to do so under the Merger Agreement or (v) TXNM terminates the June 2025 Purchase Agreement (as defined below) as a result of Purchaser (as defined below) failing to timely consummate the Stock Purchase Closing (as defined below), then, in any such case, upon termination of the Merger Agreement, Parent will be required to pay TXNM a termination fee of $350.0 million plus costs and expenses as the sole and exclusive remedy (the “Parent Termination Fee”).

Parent and Merger Sub have obtained equity and debt financing commitments for the transactions contemplated by the Merger Agreement. Pursuant to an equity commitment letter dated May 18, 2025 (the “Equity Commitment Letter”), Blackstone Infrastructure committed to provide Parent, at the consummation of the Merger, with an equity contribution in the amount set forth therein. In addition, pursuant to debt commitment letters (“Debt Commitment Letters”) delivered to Merger Sub, Royal Bank of Canada, MUFG Bank, Ltd., BNP Paribas, Sumitomo Mitsui Banking Corporation and Canadian Imperial Bank of Commerce have agreed to provide debt financing to Merger Sub following the Closing on the terms and subject to the conditions set forth therein. The equity financing, when funded in accordance with the Equity Commitment Letter together with the debt financing when funded in accordance with the Debt Commitment Letters, will provide an amount that is sufficient to fund the payment of (i) the aggregate per share merger consideration, (ii) the repayment of certain TXNM debt to be satisfied at Closing and (iii) all related fees, costs and expenses. Additionally, following Closing, Parent and TXNM will have sufficient funds to repay, prepay or discharge certain other debt obligations of TXNM. In addition, Blackstone Infrastructure has entered into a limited guarantee with TXNM (the “Limited Guarantee”), pursuant to which Blackstone Infrastructure has guaranteed the obligations of Parent and Merger Sub to pay the Parent Termination Fee and certain costs and expenses reimbursement obligations of TXNM under the Merger Agreement. The Limited Guarantee is capped at $375.0 million.

Upon consummation of the Merger, the outstanding shares of TXNM common stock will be delisted from the New York Stock Exchange (“NYSE”) and deregistered under the Exchange Act.