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 has $19.3 million in letters of credit outstanding 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, 2026.

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 2025 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, 2026, and the year ended December 31, 2025, 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

During 2025, PNM hadthree agreements to purchase a total of 250 MW for the period of July 1, 2025, through August 31, 2025, in order to ensure that customer demand during the 2025 summer peak load period was met. All of these agreements were related to customers covered by the FPPAC. There were no active commodity derivative agreements as of September 30, 2026, or December 31, 2025.

At September 30, 2026 and December 31, 2025, PNM also had no commodity derivative instruments, considered economic hedges, that did not pertain to the NMPRC-approved hedging plan discussed above.

At September 30, 2026 and December 31, 2025, PNM hadno amounts recognized for the legal right to reclaim cash collateral, no amounts posted as cash collateral under margin arrangements, and 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, 2026 and December 31, 2025, the fair value of investment securities included $437.4 million and $426.4 million for the NDT, $2.0 million and $6.0 million for the SJGS decommissioning trust, and $60.8 million and $73.2 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, 2026 and December 31, 2025, 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 of less than $0.1 million for the three and nine months ended September 30, 2026, andzero for both the three and nine months ended September 30, 2025.

At September 30, 2026, 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 ended or ending in 2028 do not include market targets. Performance stock awards with performance periods ending in 2026 and 2027 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 2025 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, 2026, TXNM had unrecognized expense related to stock awards of $7.8 million, which is expected to be recognized over an average of 1.75 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, 2026:

Included, as granted and released, in the table above are 7,015 of restricted stock awards for participants who retired and immediately vested. Excluded from the table above are 241,046,191,661, and 199,362 shares for thethree-year performance periods ending in 2026, 2027, and 2028 that will be awarded if all performance and market criteria are achieved at maximum levels and all executives remain eligible.

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 and the issuance of equity securities. 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 enter into equity arrangements and use the proceeds to reduce borrowings under the revolving credit facilities and commercial paper or refinance other debt. Each of the Company’s revolving credit facilities, term loans, and other debt agreements contain 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 2025 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.

At December 31, 2025, PNM had a shelf registration statement, which was set to expire in May 2026, with capacity for the issuance of up to $650.0 million of SUNs. On February 20, 2026, PNM filed a post-effective amendment to the registration statement to deregister any and all securities that remained unsold, effectively terminating all offerings of the securities pursuant to the registration statement.

Financing Activities

At December 31, 2025, PNM had $100.3 million outstanding under the PNM 2021 Fixed Rate PCRBs that were subject to mandatory tender on October 1, 2026. On October 1, 2026, PNM successfully remarketed the PNM 2021 Fixed Rate PCRBs to new investors (the “PNM 2026 PCRBs”). The PNM 2026 PCRBs bear interest at 4.125% and are subject to mandatory tender on October 1, 2030.

On August 31, 2026, TXNM entered into an underwriting agreement (the “Underwriting Agreement”) with Wells Fargo Securities, LLC (the “Underwriter”), to issue and sell to the Underwriter 7,079,646 shares of TXNM common stock, no par value (the “2026 Shares”), in connection with an underwritten public offering at a purchase price of $55.935 per share. The 2026 Shares were issued on September 2, 2026 and TXNM received net proceeds of approximately $396 million and used the proceeds to repay an equal amount towards the borrowings outstanding under the TXNM 2026 Delayed-Draw Term Loan (defined below).

On August 19, 2026, PNM entered into an agreement (the “PNM August 2026 Note Purchase Agreement”) with institutional investors for the sale and issuance of $200.0 million aggregate principal amount ofthree series of SUNs (the “PNM August 2026 SUNs”) offered in private placement transactions. PNM issued $115.0 million at 5.44%, due August 31, 2029, $50.0 million at 5.82%, due August 31, 2034, and $35.0 million at 6.12%, due August 31, 2038. PNM used the proceeds from the PNM August 2026 SUNs to repay existing indebtedness, to fund capital expenditures, and for other corporate purposes. The PNM August 2026 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 August 2026 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 August 2026 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 August 2026 SUNs prior to their maturities, subject to payment of a customary make-whole premium.

On August 19, 2026, TNMP entered into an agreement (the “TNMP August 2026 Bond Purchase Agreement”) with institutional investors for the sale and issuance of $150.0 million aggregate principal amount of first mortgage bonds (the “TNMP August 2026 Bonds”) offered in private placement transactions. TNMP issued $75.0 million of the TNMP August 2026 Bonds at 5.23%, due September 1, 2031 and $75.0 million of the TNMP August 2026 Bonds at 5.46%, due September 1, 2033. TNMP used the proceeds to repay existing indebtedness, to fund capital expenditures, and for other corporate purposes. The TNMP August 2026 Bonds are subject to continuing compliance with the representations, warranties, and covenants set forth in the supplemental indenture governing the TNMP August 2026 Bonds. The terms of the supplemental indenture governing the TNMP August 2026 Bonds include the customary covenants discussed above. The definition of change of control in the supplemental indenture governing the TNMP August 2026 Bonds will not be triggered by the close of the Merger. TNMP has the right to redeem any or all of the TNMP August 2026 Bonds prior to their maturity, subject to payment of a customary make-whole premium.

On July 21, 2026, PNM entered into a $195.0 million term loan agreement (the “PNM 2026 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 2026 Term Loan to repay borrowings under the PNM 2025 Term Loan (defined below) which matured on July 21, 2026. Borrowings under the PNM 2026 Term Loan bear interest at a variable rate which was 4.80% at September 30, 2026 and must be repaid on or before January 21, 2028.

On July 17, 2026, TXNM entered into a $400.0 million delayed-draw term loan agreement (the “TXNM 2026 Delayed-Draw Term Loan”), among TXNM and Wells Fargo Bank, National Association, as administrative agent. Draws on the TXNM 2026 Delayed-Draw Term Loan bear interest at a variable rate, and mature on January 17, 2029. On July 22, 2026, TXNM drew the full amount available under the TXNM 2026 Delayed-Draw Term Loan and used such amount to fully repay the $400.0 million previously received under the May 2025 Stock Purchase Agreement (defined below). See Note 12. On September 4, 2026, with proceeds received from the sale of the 2026 Shares, and notes issued under the TXNM Commercial Paper Program, TXNM repaid the TXNM 2026 Delayed-Draw Term Loan.

On May 1, 2026, TXNM, PNM, and TNMP each established commercial paper programs (respectively, the “TXNM Commercial Paper Program”, the “PNM Commercial Paper Program”, the “TNMP Commercial Paper Program”, and collectively the “Commercial Paper Programs”) pursuant to which they may issue from time to time short-term, unsecured commercial paper notes (respectively, the “TXNM Commercial Paper Notes”, the “PNM Commercial Paper Notes”, the “TNMP Commercial Paper Notes”, and collectively the “Notes”) under the exemption from registration contained in Section 4(a)(2) of the Securities Act of 1933, as amended (the “Securities Act”). Amounts available under the Commercial Paper Programs may be borrowed, repaid and re-borrowed from time to time, with the aggregate face or principal amount of the Notes outstanding under the Commercial Paper Programs at any time not to exceed $300.0 million for TXNM, $400.0 million for PNM, and $300.0 million for TNMP. The Notes will have maturities of up to 364 days from the date of issue and net proceeds will be used for general corporate purposes. Each of TXNM, PNM and TNMP have agreed to maintain, at all times, unused available borrowing capacity under their respective revolving credit agreements (except for the PNM New Mexico Credit Agreement) in an amount at least equal to the amount of Notes outstanding at any time. See Short-term debt below for balances outstanding as of September 30, 2026.

On March 3, 2026, TXNM entered into a distribution agreement (the “March Distribution Agreement”) with BofA Securities, Inc., MUFG Securities Americas Inc., and Scotia Capital (USA) Inc., as sales agents and Bank of America, N.A., MUFG Securities EMEA plc, 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 $125.0 million of its common stock, no par value, through the sales agents (the “TXNM 2026 ATM Program”). Sales of the shares made pursuant to the March 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 March 3, 2026, TXNM sold, through the sales agents listed above, an aggregate of 2,123,544 shares of TXNM common stock as set forth in the table below and used the proceeds to make cash equity contributions to PNM and for other corporate purposes. Gross cash proceeds shown below were reduced by $1.3 million in issuance costs resulting in net cash proceeds of $123.7 million.

At December 31, 2025, TXNM had $550.0 million aggregate principal amount of Convertible Notes outstanding. 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. Additional details related to the Convertible Notes may be found in Note 7 of the Notes to Consolidated Financial Statements in the 2025 Annual Reports on Form 10-K.

On January 2, 2026, TXNM notified holders of the Convertible Notes that the Convertible Notes were convertible, at the option of the holders, over a period beginning on January 1, 2026, and ending at the close of business on March 31, 2026, (the “First Quarter 2026 Conversion Period”). The Convertible Notes were convertible at a conversion rate of 22.5248 shares of common stock per $1,000 principal amount of Convertible Notes, which was equivalent to a conversion price of approximately $44.40 per share of common stock. On March 26, 2026, the conversion rate was increased to 22.5382 shares of common stock per $1,000 principal amount of Convertible Notes, which is equivalent to a conversion price of approximately $44.37 per share of common stock.

On March 31, 2026, it was determined that the Convertible Notes would once again become convertible. On March 31, 2026, TXNM notified holders of the Convertible Notes that the Convertible Notes were convertible, at the option of the holders, over a period beginning on April 1, 2026, and ending at the close of business on June 30, 2026, (the “Second Quarter 2026 Conversion Period”). On April 27, 2026, the conversion rate for the Convertible Notes was increased to 22.5517 shares of common stock per $1,000 principal amount of Convertible Notes, which is equivalent to a conversion price of approximately $44.34 per share of common stock.

With respect to the First Quarter 2026 Conversion Period and the Second Quarter 2026 Conversion Period, the Convertible Notes became convertible at the option of the holders because the last reported sale price of TXNM’s common stock, for at least 20 trading days during the period of 30 consecutive trading days ending on, and including, the last trading day of the preceding calendar quarter, was greater than or equal to 130% of the conversion price in effect on each applicable trading day during such 30 consecutive trading day period.

During the First and Second Quarter Conversion Periods, holders of approximately $0.2 million of Convertible Notes elected to convert their notes. For each $1,000 principal amount of Convertible Notes converted, the holders receive $1,000 principal amount of non-convertible 5.75% junior subordinated notes, due 2054 and shares of TXNM common stock with respect to the conversion value based on the trading price over a 60-trading day observation period. As of September 30, 2026, $549.8 million Convertible Notes remain outstanding.

On September 30, 2026, it was determined that the Convertible Notes would once again become convertible. On September 30, 2026, TXNM notified holders of the Convertible Notes that the Convertible Notes were convertible, at the option of the holders, over a period beginning on October 1, 2026, and ending at the close of business on December 31, 2026, (the “Fourth Quarter 2026 Conversion Period”). The Convertible Notes are convertible at a conversion rate of 22.5654 shares of common stock per $1,000 principal amount of Convertible Notes, which was equivalent to a conversion price of approximately $44.32 per share of common stock.

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 “August 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 August 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 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 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 were 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 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 registered the shares for resale with the SEC on August 8, 2025.

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 all 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. On November 6, 2025, TNMP entered into an agreement and supplemental indenture to amend the documents governing $417.7 million of TNMP FMBs. The supplemental indenture amends the requirement for TNMP to provide certain financial reports and amends the definition of change of control under certain supplemental indentures such that TNMP will no longer be required to make an offer to prepay the aggregate $417.7 million TNMP FMBs upon closing of the Merger.

The documents governing an aggregate $3.0 million of TNMP FMBs still require TNMP to make another offer, within 30 business days of closing of the Merger, to prepay the remaining outstanding TNMP FMBs, totaling $3.0 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” constituted 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 were 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. On December 19, 2025, TXNM and TNMP entered into another amendment which provided, among other administrative updates, that the closing of the Merger shall not be deemed to be a change of control under the terms of the TXNM Revolver and TNMP Revolver which would otherwise result in an event of default thereunder. 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. Borrowings under the TNMP Merger Backstop Term Loan were short-term in nature and bore interest at a variable rate. 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 July 2, 2026, the NMPRC ruled that the May 2025 Stock Purchase Agreement is void and of no effect. See Note 12.

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. 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 an offer to prepay, with $40.0 million validly tendered by the bondholders and accepted for purchase by TNMP in July 2025. The definition of change of control for the remaining $100.0 million of TNMP February 2025 Bonds was successfully amended and will not 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 was repaid on July 21, 2026, with the proceeds from the PNM 2026 Term Loan.

Short-term Debt and Liquidity

As of September 30, 2026, 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 29, 2030, and containsone one-year extension option that, if exercised, would extend the maturity to March 2031, subject to approval by a majority of the lenders. On December 19, 2025, when the first extension option was exercised, one lender in each of the revolving credit facilities failed to agree to the extension. As a result, effective March 30, 2029, the TXNM Revolving Credit Facility capacity will adjust to $265.4 million, and the PNM Revolving Credit Facility capacity will adjust to $354.1 million. PNM also has the $40.0 million PNM New Mexico Credit Facility with a maturity of May 31, 2030. As of September 30, 2026, the TNMP Revolving Credit Facility has a capacity of $300.0 million and is secured by $300.0 million aggregate principal amount of TNMP first mortgage bonds and has a maturity of March 29, 2030, withone one-year extension option that, if exercised, would extend the maturity to March 2031, subject to approval by a majority of the lenders. On December 19, 2025, when the first extension option was exercised, one lender failed to agree to the extension and as a result, effective March 30, 2029, the TNMP Revolving Credit Facility capacity will adjust to $277.0 million. As discussed above, Notes issued under the Commercial Paper Programs, effectively reduce the available capacity on each of the revolving credit facilities, except the PNM New Mexico Credit Facility. Variable interest rates under the TXNM, PNM, and TNMP revolving credit facilities and Notes issued under the Commercial Paper Programs 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 $2.7 million, zero, andzero at September 30, 2026, that reduce the available capacity under their respective revolving credit facilities. TXNM also had $19.3 million of letters of credit outstanding under the WFB LOC Facility and $0.9 million of letters of credit issued by other banks. The above table excludes intercompany debt. As of September 30, 2026 and December 31, 2025, neither PNMnor TNMP had any intercompany borrowings from TXNM.

PNM has $3.8 million and $3.9 million in scheduled principal payments due for the ETBC I Securitized Bonds in February and August 2027. PNM also has $120.0 million outstanding under the PNM November 2025 Term Loan due in May 2027. 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 2025 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 2025 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, 2026 and 2025 and doesnot anticipate making any contributions to the pension plan in the remaining months of 2026 through 2030 based on current law, funding requirements, and estimates of portfolio performance. Funding assumptions were developed using a discount rate of 5.5%. 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, 2026 and 2025, 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 $0.9 million and $2.3 million for the three and nine months ended September 30, 2026, and less than $0.1 million and $0.2 million for the three and nine months ended September 30, 2025. These payments are expected to total $3.2 million in 2026 and $11.2 million for 2027-2030. Disbursements under the executive retirement program, which are funded by PNM and considered to be contributions to the plan, were $0.3 million and $0.9 million in the three and nine months ended September 30, 2026, and $0.4 million and $0.9 million in the three and nine months ended September 30, 2025, and are expected to total $1.1 million during 2026 and $3.8 million for 2027-2030.

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, 2026 and 2025 and doesnot anticipate making any contributions to the pension plan in the remaining months of 2026 through 2030 based on current law, funding requirements, and estimates of portfolio performance. Funding assumptions were developed using a discount rate of 5.5% in 2026. 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, 2026 and 2025 and doesnot expect to make any contributions to the OPEB trust during the period 2026-2030.

(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. In August 2025, reported shareholders filed complaints in New York state court alleging disclosure violations and seeking injunctive relief. TXNM believes that the allegations set forth in the demand letters, draft complaints, and complaints are without merit and will defend against 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 2025 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. APS is currently in the process of extending the settlement to cover costs paid through December 31, 2028. 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, 2026 and December 31, 2025, PNM had a liability for interim storage costs of $16.9 million and $15.5 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 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.

Clean Transportation Fuel Program (“CTFP”)

In April 2026, New Mexico became the fourth state to adopt a clean fuel standard by launching the CTFP administered by NMED. The primary goal of the CTFP is to reduce overall climate pollution from transportation fuel used in New Mexico by establishing annual statewide CI standards for transportation fuel, allocating credits and calculating deficits for importers, producers or dispensers of transportation fuel in New Mexico based on whether their fuel is below or above the CI standards. The CTFP also creates a marketplace where CI standards may be met by generating credits from importing or producing low-carbon fuel, using banked credits, or acquiring credits. PNM has opted into the CTFP as a low-carbon fuel producer to participate in this marketplace by generating credits and selling credits. PNM expects the first batch of credits to be produced from residential EV charging to be available towards the end of 2026 and sold in the marketplace within the first half of 2027. PNM will use the proceeds from the sale of the credits to further support transportation electrification through the current TEP rider.

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. During NMED’s preparation of the SIP for the second compliance period, PNM was notified that a regional haze four-factor analysis for SJGS was not required since PNM retired its share of SJGS in 2022. NMED petitioned the NM Environmental Improvement Board to adopt a proposed SIP and submitted a final revised plan to the NM Environmental Improvement Board in March 2025. PNM submitted comments on the proposed SIP in response to a request for comments by NMED. No PNM generating stations were identified as reasonable progress units under the adopted SIP indicating that no additional emissions reductions measures may be necessary at this time. On March 11, 2026, the NMED submitted a SIP revision for the second planning period requesting approval by EPA.

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 were due December 1, 2025. On December 31, 2025, EPA extended the deadline for the third planning period SIPs to July 31, 2031. In February 2026, EPA updated its guidance to ensure that the SIPs account for grid reliability and strategies to prevent premature plant closures.

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 included revised new source performance standards under CAA Section 111(b) for all new natural gas-fired combustion turbines and emission guidelines under CAA 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.

On January 20, 2025, President Trump issued several executive orders 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 it 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 proposed 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 proposed 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.

On September 14, 2026, EPA published a notice of its decision to finalize the alternative proposal to partially repeal the 2024 standards, including the CCS-based standards and all of the standards for existing steam generating units. That final rule is expected to be effective on November 16, 2026, and it has been challenged by numerous parties in the DC Circuit. At the same time EPA issued the notice of a final partial repeal of the 2024 standards, EPA also issued a supplemental proposal on the subject of whether EPA may regulate GHG emissions from the power sector under CAA Section 111 at all, similar to the primary proposal issued in 2025 but under a different legal theory focused on whether the emissions constitute “air pollution” anticipated to “endanger human health and welfare.” Comments on that supplemental proposal are due on November 2, 2026. If finalized as proposed, the supplemental proposal would result in the repeal of all of the remaining GHG standards from EPA’s 2015 and 2024 rulemakings, including the efficiency standards for natural gas-fired combustion turbines and the partial CCS requirements for new steam generating units.

In 2021, then President Biden signed an extensive executive order aimed at addressing 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, then President Biden unveiled the goal to cut U.S. emissions by 50% - 52% from 2005 levels by 2030. The 2030 emissions goal supported 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 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. On February 12, 2026, the rule was finalized as proposed, repealing all GHG emission standards for certain vehicles and engines promulgated on the basis of the Endangerment Finding. While the Endangerment Finding did not directly impose any requirements on EGUs, EPA cited the Endangerment Finding as a basis for its authority to regulate GHG emissions from EGUs under CAA Section 111, and EPA has identified that reliance on the Endangerment Finding as a basis for its supplemental proposal to find that CAA Section 111 does not authorize EPA to regulate GHG emissions from the power sector.

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. In addition, EPA has now reconsidered the policies underlying its Good Neighbor rule, and, on January 30, 2026, EPA issued a proposed rule to approve New Mexico’s SIP submission because it will not contribute significantly to nonattainment or interfere with maintenance of the 2015 8-hour ozone NAAQS in any other state. If finalized, the EPA will withdraw the prior proposed partial SIP disapproval.

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 for any areas designated as nonattainment. 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 PM standard was challenged in the D.C. Circuit, and, following the change in administration, EPA filed a motion for voluntary vacatur of the rule, but the court denied that motion and upheld the new standard on June 26, 2026. The Northern District of California has ordered EPA to promulgate final designations for all areas of the country no later than February 6, 2027.

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 were due November 3, 2025. On November 28, 2025, EPA withdrew the direct final rule due to adverse comments and on December 31, 2025, published a final rule revising various deadlines and other provisions in the 2024 rule. On March 9, 2026, EPA sent a proposed rule to Office of Management and Budget reconsidering the technology-based effluent limitations and standards promulgated in 2024. On May 18, 2026, EPA published its proposed rule revising ELGs for unmanaged combustion residual leachate. Comments were due June 17, 2026. The final rule is expected to be published in March 2027.

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 ongoing field work monitoring and reporting.

Additional monitoring well installations along with periodic groundwater sampling and reporting under NMED-approved CAF and abatement plan requirements have continued and support 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.

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 set forth a new deadline of April 11, 2021, 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.

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 establishing 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, 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 (“Legacy Rule”). The Legacy 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 agreed to hold the case in abeyance pending the outcome of EPA’s reconsideration of the Legacy Rule, with status reports due on March 16, 2026, and at 90-day intervals thereafter. 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 direct final rule due to adverse comments but subsequently issued a final extension rule on February 6, 2026, delaying the deadline to complete the “Facility Evaluation Report Part 1” until February 9, 2027, and extending all subsequent deadlines, as well. The final extension rule was published in the Federal

Register on February 10, 2026. On April 13, 2026, EPA published proposed Legacy Rule/CCRMU Amendments that, among other things, would rescind all the requirements related to CCRMU and authorize site-specific tailoring of certain rule requirements through federal permits or approved state permits. The comment period for that proposal ended June 29, 2026. PNM submitted comments through EEI, relating to the definitions of CCRMU but not related to the federal permit program for CCR as there are no CCR units at SJGS.

As of the effective date of the Legacy 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, 2027, and February 8, 2028 (based on the new final extension rule), 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 are expected to be finalized by February 9, 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 has not yet finalized the federal permitting program rule. On May 8, 2026, EPA published a notice reopening the comment period on the proposed federal CCR permit program. Comments were due July 29, 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. Separately, on July 13, 2026, EPA issued an advance notice of proposed rulemaking to solicit comments on a potential federal general permit option for CCR facilities. The comment period ended on October 13, 2026.

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 did 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 potentially 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. 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 2025 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.

Under the terms of the SJGS CSA, 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.

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, as of September 30, 2025, there was an increase in the liabilities related to both 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 and the increase related to the surface mine liability was recognized 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 $19.3 million are outstanding as of September 30, 2026.

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, PNM recorded a decrease in the liability related to the surface mine of $0.9 million as a 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, 2026, for mine reclamation, in future dollars, are estimated to be $17.5 million for the surface mines at both SJGS and Four Corners and $63.1 million for the underground mine at SJGS. At September 30, 2026 and December 31, 2025, liabilities, in current dollars, of $9.3 million and $20.8 million for surface mine reclamation and $56.9 million and $55.2 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 $7.0 million in 2025. Based on PNM’s reclamation trust fund balance at September 30, 2026, current forecasts, and current funding curve targets, PNM anticipates contributing $3.4 million in 2026 and anticipates making contributions of $0.4 million in 2027 and $4.7 million in 2028.

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 didnot make any contributions in 2025 and anticipates contributing $0.5 million per year for 2026, 2027 and 2028.

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

In 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. PNM and the other SJGS 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 is required to make funding contributions of which the amount and timing are 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.

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. On November 26, 2025, PNM submitted the S1AP to NMED that was approved on February 9, 2026. The S1AP estimates site investigation and monitoring to be completed by the first quarter of 2027. PNM is currently conducting site investigations, groundwater sampling, and monitoring detailed in the S1AP.

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 $16.4 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 $15.9 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 $12.1 million, with a maximum annual payment limitation of $1.8 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”). If NEIL’s losses in any policy year exceed accumulated funds, PNM is subject to retrospective premium adjustments of $5.0 million. The insurance coverage 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 2025 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

On September 15, 2026, TXNM and Blackstone Infrastructure filed a motion with the NMPRC seeking authorization to file a revised version of the Merger application. The motion included a draft of the revised application detailing the following benefits to customers:

•$220.0 million in retail rate credits to be paid over 10 years

•$15.0 million in additional contributions to the PNM Good Neighbor Fund to be paid over 10 years

•$40.0 million in financial contributions to help train and build New Mexico’s workforce and fund economic development projects in local communities

•$25.0 million dedicated to support New Mexico’s transition to carbon-free energy by amplifying PNM’s investments in innovative VPP technology

On October 16, 2026, the NMPRC granted TXNM’s motion to file and accepted the revised version of the Merger application. The NMPRC does not have a statutory timeframe for consideration of the revised application. On October 27, 2026, the hearing examiners published a revised procedural schedule with evidentiary hearings scheduled for January 19 through February 1, 2027.

Show cause

On February 6, 2026, a motion and brief for order was filed, directing the applicants to show cause and for other relief in the pending application with the NMPRC. The motion alleges that the purchase of $400.0 million of TXNM common stock violated Section 62-6-12 of the Public Utility Act because PNM did not receive prior approval of the purchase from the NMPRC. On March 11, 2026, the NMPRC hearing examiners issued an order granting the February 2, 2026, motion to direct the applicants to show cause regarding the $400.0 million purchase of TXNM common stock. The order initiated a formal investigation to determine whether the stock acquisition violated Section 62-6-12 of the Public Utility Act and any legal and practical consequences of such violation.

On June 8, 2026, the hearing examiners issued a RD concluding that the purchase of $400.0 million of TXNM common stock violated Section 62-6-12 of the Public Utility Act because it occurred without prior NMPRC approval. Applicants were required to submit a detailed compliance plan within 45 days of receiving a Final Order to show how the transaction will be unwound ensuring ratepayers are fully protected from all impacts. On July 2, 2026, the NMPRC issued a Final Order largely adopting the RD and imposing a $100,000 penalty on TXNM for the violation.

On July 27, 2026, TXNM filed its compliance filing with the NMPRC detailing the unwinding of the May 2025 Stock Purchase Agreement by cancelling the 8,000,000 shares of TXNM common stock sold as of July 2, 2026, drawing on the $400.0 million TXNM 2026 Delayed-Draw Term Loan, and repaying (on September 4, 2026) the aggregate $400.0 million received in the May 2025 Stock Purchase Agreement (Note 9). On August 10, 2026, TXNM filed a notice of amended compliance report reflecting that all $13.3 million in dividends previously paid in relation to the 8,000,000 shares of TXNM common stock sold under the May 2025 Stock Purchase Agreement had been returned. TXNM expressed intent to issue shares of TXNM common stock to repay the $400.0 million TXNM 2026 Delayed-Draw Term Loan through either publicly registered offerings or private placement transactions. On July 31, 2026, TXNM filed a petition with the NMPRC for a declaratory order that the proposed equity transactions do not require prior NMPRC approval and requested that the NMPRC expedite approval of the petition. On August 27, 2026, the NMPRC granted TXNM’s petition for a declaratory order concluding that TXNM does not require prior authorization from the NMPRC to issue shares of TXNM common stock to repay the $400.0 million TXNM 2026 Delayed-Draw Term Loan, subject to certain restrictions. See Note 9. On September 28, and October 28, 2026, PNM filed documents with the NMPRC demonstrating compliance with the declaratory order granted on August 27, 2026.

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

On December 11, 2025, TXNM and Blackstone Infrastructure reached a unanimous settlement with parties in its Merger proceeding filed with the PUCT. Terms of the settlement include additional financial oversight, corporate governance and regulatory protections that favor local communities and the current workforce. Additionally, the settlement removed the $10.0 million in economic development and the $5.0 million in charitable giving and increased the rate credits from $35.0 million to $45.5 million to be paid over four years. The settlement was approved by the PUCT on February 6, 2026.

Application to the FERC

In October 2025, a protest was filed arguing that the proposed Merger posed significant risk of unlawful cross-subsidization, especially benefitting Blackstone Infrastructure’s data centers and energy affiliates, and could harm competition, rates, and regulatory oversight. On February 20, 2026, FERC approved the proposed Merger concluding that there is no adverse effect on competition, no adverse rate impacts, and no regulatory gap. FERC rejected claims related to data centers, private equity ownership, and speculative cross-subsidization relying on existing state ring-fencing protections in New Mexico and Texas. On March 23, 2026, a request for rehearing was filed concerning FERC’s February 20, 2026, approval of the proposed Merger. The request is based on the recent developments in the application before the NMPRC and the show cause order, discussed above. The request argues that this procedural uncertainty may justify FERC’s reconsideration. On April 23, 2026, FERC issued a notice of denial of rehearing by operation of law and providing further consideration. On July 17, 2026, a motion was filed seeking to notify FERC of the NMPRC’s July 2, 2026, Final Order in the show cause proceeding and asking FERC to consider that order in connection with the pending rehearing request. On August 28, 2026, FERC issued an order rejecting the arguments of the rehearing request and affirming the approval of the proposed Merger issued in February 2026. This matter is now concluded.

PNM

New Mexico General Rate Case

2025 Rate Request

In June 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. In November 2024, PNM filed an unopposed comprehensive stipulation with the NMPRC that was approved on May 15, 2025, with the base rate changes becoming effective July 1, 2025 and April 1, 2026. Key components agreed upon by the signatories may be found in Note 17 of the Notes to Consolidated Financial Statements in the 2025 Annual Reports on Form 10-K. 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. The following sets forth PNM’s revenue recorded under the renewable energy rider:

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 2025. On May 28, 2026, PNM filed its application, requesting to collect $53.0 million for 2027 costs beginning on January 1, 2027. On September 14, 2026, the hearing examiner issued a RD recommending approval of PNM’s application.

Energy Efficiency and Load Management

On April 15, 2026, PNM filed its application with the NMPRC for energy efficiency and load management programs to be offered in 2027, 2028, and 2029 (the “2027 Plan”) in compliance with the EUEA. The 2027 Plan proposed to continueten existing energy efficiency programs with modifications and total annual budgets of $45.6 million in 2027, $47.6 million in 2028, and $48.8 million in 2029. 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 10.54%. On October 14, 2026, the hearing examiner issued a RD recommending approval of the 2027 Plan as filed however, the RD also recommends that PNM be required, in its next energy efficiency and load management filing, to provide more granular information concerning its demand response programs. PNM cannot predict the outcome of this matter.

Integrated Resource Plans

NMPRC rules require that investor-owned utilities file an IRP every three years that covers a 20-year planning period and contains 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. See Note 17 of the Notes to Consolidated Financial Statements in the 2025 Annual Reports on Form 10-K for details related to the filing.

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. On January 2, 2026, PNM filed a Notice of Material Event for the 2023 IRP to inform the NMPRC of its intent to issue a supplemental RFP for gas-fired resources in response to new customer requirements that have accelerated and increased energy demands beyond previously forecasted resources. On February 4, 2026, the IM appointed to the 2029-2032 RFP concluded that PNM appropriately evaluated the bids, made reasonable portfolio selection decisions, and overall, the RFP process was conducted in a fair, transparent manner that was in compliance with regulatory requirements. On March 6, 2026, PNM filed its draft supplemental RFP for the additional resources anticipated. On April 4, 2026, the IM issued a design report on PNM’s draft supplemental RFP which contained targeted modifications to improve transparency, expand participation, and strengthen competitive neutrality within the class of eligible firm resources. PNM filed responses to the IM design report and issued a supplemental RFP on May 1, 2026.

On May 29, 2026, PNM filed its 2029-2032 Resource Portfolio Application with the NMPRC. The application seeks approval of a balanced portfolio that includes:

•800 MW of wind PPAs

•240 MW of solar PPAs

•610 MW of battery storage ESAs

•40 MW of dispatchable natural gas generation (expansion of PNM-owned capacity)

•Abandonment and exit of PNM’s interest in Four Corners in 2031

The application also includes a request for an accounting order under SB 170 (discussed below) for certain resources associated with future economic development and gives notice that PNM intends to extend operations of the existing Reeves Generating Station through the end of 2044 to provide additional resource assurance. The proposed portfolio addresses projected resource shortfalls beginning in 2029, driven by load growth and the need to replace capacity as PNM exits Four Corners. As a result, PNM has requested that the NMPRC adhere to the six-month review timeline for PPAs and ESA and to expedite the review of the natural gas project.

On July 31, 2026, a motion was filed by intervenors in the application requesting that the NMPRC bifurcate PNM’s 2029-2032 Resource Portfolio Application into two phases. The motion argues that combining the renewable PPAs and ESAs with the more controversial requests risks delaying the approval of the renewable resources and jeopardizes the tax credits. On August 13, 2026, PNM filed its response requesting that the motion be denied, emphasizing that the bifurcation would separate interdependent resources and approvals, undermine portfolio level reliability and resource adequacy analysis, complicate review of accounting order requests, and create a risk of inconsistent findings. PNM also contends that bifurcation may duplicate litigation and potentially prejudice review of certain utility-owned resources without providing any corresponding efficiency benefits. On August 19, 2026, the hearing examiner partially granted the motion to bifurcate PNM’s 2029-2032 Resource Portfolio Application. The proceeding will remain under a single docket but will move forward in two phases. Phase I includes all requested PPAs, ESAs, and related accounting order treatment decisions that will continue on the existing procedural schedules. Phase II includes the La Luz CCN request, issues related to the continued operation of Reeves Generating Station through 2044, the abandonment of Four Corners, and any other requests not specifically assigned to Phase I. A Phase I public hearing was held on October 7-9, 2026 and the Phase II hearing has been scheduled for April 5-9, 2027.

On September 8, 2026, PNM notified all the bidders participating in the supplemental RFP that due to the hearing examiner’s bifurcation of the 2029-2032 Resource Portfolio Application, PNM will place the evaluation of the proposals received on hold until further notice in order to assess the reasonableness of PNM’s assumptions regarding the future structure of the generation portfolio. PNM cannot predict the outcome of this matter.

2026 IRP

On September 1, 2026, PNM filed its 2026 IRP with the NMPRC covering the 2026-2045 planning period. The 2026 IRP outlines PNM’s long-term strategy to maintain reliability and affordability while meeting New Mexico’s clean energy requirements, addressing significant projected load growth, transmission needs, and changing market conditions.

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 receive benefits 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 Grid Modernization Plan. On October 17, 2024, the NMPRC issued a final order largely approving 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%. On February 26, 2026, the NMPRC approved PNM’s first annual Grid Modernization Review and the updated year two revenue requirement. This matter is now concluded.

On March 2, 2026, PNM filed its first annual Grid Modernization Plan reconciliation filing to reconcile the year one actual revenue requirement to the approved revenue requirement. On March 16, 2026, PNM filed the advice notice for the rider to collect the year one revenue requirement of $7.7 million with an effective date of April 15, 2026. The advice notice became effective on April 15, 2026, by operation of law.

In February 2025, the NMPRC issued a NOPR proposing a rule within the Grid Modernization Statute requiring electric utilities to file a grid plan every three years to establish transparency in distribution planning and assessment of the current and future grid system for areas of potential expansions, upgrades, and grid enhancing technologies that would improve system reliability, resiliency, and wildfire prevention. On January 30, 2026, the NMPRC issued an order directing PNM to file a one-time distribution system plan by October 1, 2026, that will act as a pilot for future formal planning and will undergo full NMPRC review under the existing Grid Modernization Statute. In a clarification order issued on March 13, 2026, the NMPRC gave PNM the discretion to treat the upcoming filing, due October 1, 2026, as an informational filing for acceptance or as a request for review and approval by the NMPRC. On October 1, 2026, PNM filed its 2026 Distribution System Plan (the “2026 DSP”) with the NMPRC for review and acceptance in compliance with the January order. The 2026 DSP establishes a forward looking framework for maintaining a safe, reliable, resilient, and affordable system while responding to load growth, electrification, distributed energy resources, and grid modernization. It identifies emerging system needs and investments to support detailed engineering studies, project prioritization, and budgeting.

On April 10, 2026, PNM filed its second annual Grid Modernization Plan review to provide updates on implementation progress, costs, and revenue requirements for years two through six. In the filing, PNM requested approval of updated year three costs and revenue requirement estimates, including the presumption of reasonableness, authorization of capital treatment of software as a service costs for years two through six, and issuance of a final order no later than October 15, 2026. On May 1, 2026, a procedural order was issued, and an evidentiary hearing was held on August 11, 2026. PNM cannot predict the outcome of this matter.

Transportation and Electrification Program (TEP)

On June 1, 2026, PNM filed its 2027-2029 TEP with the NMPRC, requesting approval of a $32.9 million total three-year budget and continuation of the current TEP Rider. Approximately 40% of the budget, $13.2 million, will be dedicated to low-income customers and underserved communities. On September 25, 2026, NMPRC staff recommended approval of PNM’s requested 2027-2029 TEP with a slight modification reducing the total budget to $30.0 million. PNM cannot 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. PNM expects to seek recovery of these costs in a future rate case. On March 10, 2026, the hearing examiner issued an RD recommending approval of the CCN that was approved in a final order issued by the NMPRC on April 10, 2026. This matter is now concluded.

SB 170 Projects

The enactment of Senate Bill 170 (“SB 170”) allows a utility to defer costs of economic development projects that serve sites certified by the New Mexico Economic Development Department (“NMEDD”). On December 29, 2025, PNM filed an application with the NMPRC for approval oftwo economic development projects including the Westpointe and Mesa Del Sol Substations and the issuance of an accounting order to defer the costs of the projects as regulatory assets. The projects are estimated to cost $165.5 million and are expected to be reviewed in a future rate proceeding. On March 13, 2026, the NMPRC voted to approve PNM’s application for the economic development projects and issued an accounting order, concluding this matter. The projects remain subject to NMPRC review for necessity and prudence in a future rate proceeding.

Mid-State CCN

On October 30, 2026, PNM filed an application with the NMPRC for approval of a CCN for a new 345 kV transmission line, existing station expansions, determination for a new right-of-way, and reconstruction of portions of an existing 115 kV line at an estimated cost of $595.0 million. PNM intends to seek a prudency review for cost recovery and ratemaking treatment in a future general rate proceeding. This project aims to strengthen PNM's east to west transmission system and supports resources identified in PNM's 2029-2032 Resource Portfolio Application filed on May 29, 2026. PNM cannot predict the outcome of this matter.

Rio Puerco-Pajarito-Prosperity CCN

On December 30, 2025, PNM filed an application with the NMPRC for approval of a CCN and a determination for a new right-of-way. The CCN encompasses a new 345 kV transmission line, existing station expansions, and a new substation. This project aims to enhance reliability and resilience in the Albuquerque area, facilitate the integration of renewable energy, and support economic development. On February 13, 2026, the NMPRC dismissed the application without prejudice and on February 25, 2026, PNM filed a new application for approval of the CCN providing additional clarity and more information on the project. The estimated cost of the project is approximately $247 million and is expected to be reviewed in a future rate proceeding. On March 12, 2026, the hearing examiner issued a procedural order setting a public hearing for August 26, 2026. On July 24, 2026, the hearing examiner issued a RD approving PNM’s request for determination of a new right-of-way for the Rio Puerco-Pajarito-Prosperity 345kV transmission line project that was approved by the NMPRC on August 14, 2026. The approval is limited to the right-of-way determination and does not address project need, routing, costs, ratemaking treatment, or the requested CCN. On August 19, 2026, the hearing examiner issued an order vacating the public hearing. On October 6, 2026, the hearing examiner issued a RD recommending approval of PNM’s CCN. PNM cannot predict the outcome of this matter.

TNMP

Single Unified Tracker Mechanism (“UTM”)

On September 1, 2026, TNMP filed an application with the PUCT seeking approval to file a single UTM under PURA 36.216 for qualified electric utilities who operate solely inside ERCOT, who were responsible for constructing transmission as a part of the reliability plan for the Permian Basin, and who made total capital expenditures that exceeded 300% of annual depreciation in a calendar year. TNMP’s Base Rate Review (below) was based on a July 1, 2024, through June 30, 2025, test year. This UTM application consolidates and includes updates to TNMP’s DCRF, interim TCOS, and the transmission cost recovery factor for the period from July 1, 2025, through June 30, 2026. As a part of the Stipulation in TNMP’s Base Rate Review, baseline values were reset to agreed upon values to be used for future DCRF and TCOS filings. From those agreed upon baseline values, the UTM application requests the following total incremental increase in the total DCRF and TCOS revenue requirement (including deferred operating and maintenance costs related to SRP and the UTM regulatory asset):

TNMP’s rider for the recovery of third party transmission costs through the use of a transmission cost recovery factor has also been included in the application, replacing the expected request for update that would have occurred later in 2026. The UTM is pending with the PUCT.

TNMP Base Rate Review

On November 14, 2025, TNMP filed a general rate proceeding with the PUCT (the “TNMP Base Rate Review”) requesting recovery of $2.8 billion of rate base as of June 30, 2025, a requested ROE of 10.4%, and a 47.54% equity ratio. The TNMP Base Rate Review also includes increases in operations and maintenance expenses that are not recovered through semi-annual TCOS and DCRF filings, excludes increases in interest expense resulting from refinancing of debt associated with the proposed Merger, and requests recovery of $20.5 million associated with Hurricane Beryl restoration costs over afive-year period as well as recovery of other regulatory assets. On March 6, 2026, TNMP, on behalf of all parties to the proceeding, filed a motion to abate the procedural schedule on the merits of continuing their efforts to reach a full resolution and settlement. On March 9, 2026, the hearing was cancelled. On May 29, 2026, TNMP and all parties to the proceeding reached a settlement and filed an unopposed stipulation (the “Stipulation”) with the PUCT. The Stipulation agreed to TNMP’s recovery of $2.8 billion of rate base, a ROE of 9.65% and a 45% equity ratio. Final rates in the Stipulation are effective 45 days from the PUCT’s Final Order and TNMP will establish a surcharge to recover interim rates after the PUCT’s Final Order in the proceeding. On July 30, 2026, the PUCT issued its Final Order approving the Stipulation.

Large Load Interconnection Rulemaking

In July 2025, PUCT Staff opened a rulemaking project to implement large load interconnection standards required by Texas legislation. The legislation directs the PUCT to establish standards for interconnecting large load customers in the ERCOT region in a manner that supports business development, minimizes the risk of stranded infrastructure costs, and maintains system reliability. TNMP participated in a workshop on this initiative in January 2026. On February 6, 2026, the PUCT adopted Rule 25.370, which requires the power demands of large load customers of 75 MW or more, to be incorporated into ERCOT’s Regional Transmission Plan and resource adequacy assessments. The rule establishes thresholds and criteria for identifying large load customers and requires them to demonstrate verifiable progress toward site control, financing, and towards state and local regulatory approvals. Large load customers must also provide attestations to transmission and distribution service providers confirming the status and timeline of their project load ramp schedules. Since the rule’s effectiveness and the establishment of “batch zero” by ERCOT, TNMP has experienced an increase in transmission interconnection requests. As of September 30, 2026, TNMP has batch zero deposits of $51.8 million in Other current liabilities and $52.7 million in Other deferred credits on its Condensed Consolidated Balance Sheet.

Sales and Use Tax Refunds

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. On October 15, 2025, TNMP filed another refund claim for $5.1 million for overpaid sales and use taxes primarily related to asset purchases covering the period from November 2024 through February 2025. On June 25, 2026, the Texas Comptroller’s Office issued an adjustment report indicating that the refund claim had been approved and interest would be accruing at a daily rate until paid. TNMP received the requested refund net of $1.1 million in consultant fees and applied $3.8 million to capital projects with the remaining $0.2 million to offset related interest expense.

Transmission Cost of Service Rates

TNMP can update its TCOS rates twice per year to reflect changes in investments in transmission 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. TCOS updates are expected to be filed annually in a single UTM filing going forward. The following sets forth TNMP’s recently approved 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. 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. DCRF updates are expected to be filled annually in a single UTM filing going forward. The following sets forth TNMP’s recently approved interim distribution rate increases:

HB 5247

In June 2025, Texas House Bill 5247 (“HB 5247”) was signed into law. 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 such as DCRF and TCOS. 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. Upon completion of its general rate proceeding (the TNMP Base Rate Review) discussed above, TNMP made its first comprehensive filing (UTM filing) under Section 36.216 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. TNMP’s requested DCRF and TCOS revenue requirement increases in the current UTM filing include $20.5 million and $13.9 million of regulatory assets through June 30, 2026. Eligible costs for capital investments expected to be included in the next annual UTM will continue to be recorded as a regulatory asset, offset in alternative revenue.

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 30, 2025, TNMP filed its request to adjust the EECRF to reflect changes in costs for 2026. On November 14, 2025, the total amount requested of $8.1 million, which includes a performance bonus of $2.5 million, based on TNMP’s energy efficiency achievements in 2024, was approved and took effect March 1, 2026. On May 29, 2026, TNMP filed its request to adjust the EECRF to reflect changes in costs for 2027. The total amount requested was $9.5 million, which includes a performance bonus of $1.2 million based on TNMP’s energy efficiency achievements in 2025. The case is pending review by the PUCT.

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 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. TNMP’s requested DCRF revenue requirement increase in the current UTM filing includes $28.7 million of SRP deferred operating and maintenance costs incurred through June 30, 2026.

(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 2025 Annual Reports on Form 10-K.

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 2026 payment for the amount due under the Navajo Nation right-of-way lease was $9.1 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, 2026 and December 31, 2025, the unamortized balance of these rights-of-ways was $82.1 million and $69.2 million. PNM recognized amortization expense associated with these agreements of $1.3 million and $3.6 million in the three and nine months ended September 30, 2026, and $1.1 million and $3.3 million in the three and nine months ended September 30, 2025.

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, 2026, residual value guarantees on fleet vehicle, and equipment leases are $0.5 million, $0.4 million, and $0.9 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. During the first quarter of 2026, one existing fixed payment ESA was amended to variable payments based on available capacity, resulting in a $57.2 million retirement of unamortized right-of-use assets and associated lease liabilities. 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, 2026 and 2025.

Future expected lease payments are shown below:

The above table includes $15.4 million, $21.3 million, and $36.9 million for PNM, TNMP, and TXNM at September 30, 2026, 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, 2026, 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, 2026, TXNM, PNM, and TNMP estimated their effective income tax rates for the year ended December 31, 2026, would be 14.69%,12.28%, and 20.22%. 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, 2026, income tax expense calculated by applying the expected annual effective income tax rate to earnings before income taxes was further decreased by excess tax benefits related to stock awards of $0.4 million for TXNM, of which $0.3 million was allocated to PNM and $0.1 million was allocated to TNMPand by tax benefits on Merger-related costs of $2.0 million for TXNM, of which $0.7 million was allocated to PNM and animmaterial amount was allocated to TNMP.

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 $26.2 million, $23.5 million, and $2.7 million in 2026. See additional discussion of the impacts of the TCJA in Note 18 of the Notes to Consolidated Financial Statements in the 2025 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 extended and made 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 accelerated 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, and TNMP 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. The table below summarizes the nature and amount of related party transactions of TXNM, PNM, and TNMP:

(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 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 weighted average cost of capital, 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, 2026 and 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, 2026, carrying values of PNM and TNMP exceeded their fair value.

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, and it was approved by a majority of the holders of outstanding shares of TXNM common stock, as of the applicable record date, at the special meeting held on August 28, 2025. On January 13, 2026, the waiting period under the HSR Act in connection with the Merger expired and on January 23, 2026, the FCC consented to the two transfers of control applications submitted by Parent and TXNM, including amendments to the applications to include additional FCC licenses that TXNM had obtained since the original application was filed. TXNM will continue to amend the transfer of control application filed with the FCC, or file a new application, for any new FCC licenses either acquired by TXNM, or its subsidiaries, from third parties or through spectrum assignment filed with the FCC. Consummation of the Merger is subject to the satisfaction or waiver of certain customary conditions, including the absence of any material adverse effect on TXNM, the absence of legal prohibition on the consummation of the Merger (a “Legal Restraint”), and absence of any agreement between Parent or TXNM and the FCC or Antitrust Division of the U.S. Department of Justice prohibiting the Merger, and the receipt of certain required regulatory approvals (including NMPRC). 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 February 6, 2026, the PUCT approved a unanimous settlement agreement filed by parties to the merger proceeding filed in December and on February 20, 2026, the FERC approved the proposed Merger. On April 24, 2026, TXNM filed its application for regulatory approval of the proposed Merger with the NRC that was approved on August 18, 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 and TXNM. The Merger Agreement further provides that, upon termination of the Merger Agreement under certain specified circumstances, TXNM will be required to pay Parent a termination fee of $210.0 million plus certain costs and expenses. 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 breach of any representation or warranty or failure to perform by Parent, or Merger Sub that is not curable or timely cured or (iv) Parent fails to effect the closing when all closing conditions (other than those that by their nature are to be satisfied at closing) have been satisfied or waived and it is otherwise obligated to do so under the Merger Agreement and it further fails to consummate the closing withintwo business days after receiving notice from TXNM, 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 (subject to the terms of the Waiver defined and described below) plus certain costs and expenses (the “Parent Termination Fee”).

On July 17, 2026, TXNM, Parent and Merger Sub entered into a Waiver (the “Waiver”) pursuant to Section 8.6 of the Merger Agreement. Pursuant to the Waiver, each of Parent and TXNM irrevocably waived its right to terminate the Merger Agreement and abandon the Merger pursuant to Section 8.1(c) of the Merger Agreement (relating to the failure of the Merger to occur by the End Date (as defined in the Merger Agreement)) prior to May 31, 2027 (such period, the “Waiver Period”). Each party further waived any right or claim to interpret the terms of the Merger Agreement, including references to the End Date, in a manner inconsistent with the Waiver Period. In addition, TXNM irrevocably waived $175.0 million of the $350.0 million Parent Termination Fee, such that the Parent Termination Fee, if and when payable, would be reduced to $175 million. This reduction does not affect certain cost and expense reimbursement or indemnification obligations of the parties under specified provisions of the Merger Agreement relating to access to information, debt financing cooperation, effect of termination, and expenses.

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, New York Branch 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 (i) payment of the aggregate per share merger consideration, (ii) repayment, prepayment or discharge of certain obligations of the Company and its subsidiaries that would become due (after giving effect to the Merger) and are intended to be repaid at Closing and (iii) payment of all fees and expenses expected to be incurred at Closing in connection therewith. 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 executed and delivered a limited guarantee in favor of 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 other fees and expenses 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 and deregistered under the Exchange Act.