PNM RESOURCES INC

(1)Significant Accounting Policies and Responsibility for Financial Statements

Financial Statement Preparation

In the opinion of management, the accompanying unaudited interim Condensed Consolidated Financial Statements reflect all normal and recurring accruals and adjustments that are necessary to present fairly the consolidated financial position at March 31, 2024 and December 31, 2023, and the consolidated results of operations, comprehensive income, and cash flows for the three months ended March 31, 2024 and 2023. The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results could ultimately differ from those estimated. Weather causes the Company’s results of operations to be seasonal in nature and the results of operations presented in the accompanying Condensed Consolidated Financial Statements are not necessarily representative of operations for an entire year.

The Notes to Condensed Consolidated Financial Statements include disclosures for PNMR, PNM, and TNMP. This report uses the term “Company” when discussing matters of common applicability to PNMR, PNM, and TNMP. Discussions regarding only PNMR, PNM, or TNMP are so indicated. Certain amounts in the 2023 Condensed Consolidated Financial Statements and Notes thereto have been reclassified to conform to the 2024 financial statement presentation.

These Condensed Consolidated Financial Statements are unaudited. Certain information and note disclosures normally included in the annual audited Consolidated Financial Statements have been condensed or omitted, as permitted under the applicable rules and regulations. Readers of these financial statements should refer to PNMR’s, PNM’s, and TNMP’s audited Consolidated Financial Statements and Notes thereto that are included in their respective 2023 Annual Reports on Form 10-K.

GAAP defines subsequent events as events or transactions that occur after the balance sheet date but before financial statements are issued or are available to be issued. Based on their nature, magnitude, and timing, certain subsequent events may be required to be reflected at the balance sheet date and/or required to be disclosed in the financial statements. The Company has evaluated subsequent events accordingly.

Principles of Consolidation

The Condensed Consolidated Financial Statements of each of PNMR, PNM, and TNMP include their accounts and those of subsidiaries in which that entity owns a majority voting interest. PNM also consolidates Valencia and ETBC I. See Note 6. PNM owns undivided interests in several jointly-owned power plants and records its pro-rata share of the assets, liabilities, and expenses for those plants. The agreements for the jointly-owned plants provide that if an owner were to default on its payment obligations, the non-defaulting owners would be responsible for their proportionate share of the obligations of the defaulting owner. In exchange, the non-defaulting owners would be entitled to their proportionate share of the generating capacity of the defaulting owner. There have beenno such payment defaults under any of the agreements for the jointly-owned plants.

PNMR Services Company expenses, which represent costs that are primarily driven by corporate level activities, are charged to the business segments. These services are billed at cost and are reflected as general and administrative expenses in the business segments. Other significant intercompany transactions between PNMR, PNM, and TNMP include interest and income tax sharing payments, as well as equity transactions, and interconnection billings. See Note 15. All intercompany transactions and balances have been eliminated.

Dividends on Common Stock

Dividends on PNMR’s common stock are declared by the Board. The timing of the declaration of dividends is dependent on the timing of meetings and other actions of the Board. The Board declared dividends on common stock of $0.3875 per share in February 2024 and $0.3675 per share in February 2023, which are reflected as Dividends Declared per Common Share on the PNMR Condensed Consolidated Statement of Earnings.

PNMR did not make any cash equity contributions to PNM or TNMP in the three months ended March 31, 2024 and 2023. On April 30, 2024 PNMR made a $55.0 million cash equity contribution to PNM. PNM and TNMP didnot declare or pay any cash dividends on their common stock to PNMR in the three months ended March 31, 2024 and 2023.

New Accounting Pronouncements

Information concerning recently issued accounting pronouncements that have not yet been adopted by the Company is presented below. The Company does not expect difficulty in adopting these standards by their required effective dates.

Accounting Standards Update 2023-07 - Segment Reporting (Topic 280): Improvements to Reportable Segment Disclosures

In November 2023, the FASB issued ASU 2023-07 enhancing disclosures about significant segment expenses. Disclosure requirements of this update include disclosure, on an annual and interim basis, of significant segment expenses that are regularly provided to the Chief Operating Decision Maker (“CODM”) and included within each reported measure of segment profit or loss (collectively referred to as the “significant expense principle”); an amount forother segment itemsby reportable segment and a description of its composition; the title and position of the CODM and an explanation of how the CODM uses the reported measures in assessing segment performance and deciding how to allocate resources; and that a single reportable segment provides all the disclosures required by the amendments in this ASU and all existing segment disclosures in Topic 280. The amendment also clarifies that in addition to the measure most consistent with the measurement principles under GAAP, reporting of additional measures of a segment’s profit or loss used by the CODM in assessing segment performance and determining allocation of resources is allowed. ASU 2023-07 is effective for the Company beginning January 1, 2024 and interim periods beginning January 1, 2025 with early adoption being permitted. ASU 2023-07 is to be applied retrospectively to all prior periods presented in the financial statements.

Accounting Standards Update 2023-09 - Income Taxes (Topic 740): Improvements to Income Tax Disclosures

In December 2023, the FASB issued ASU 2023-09 enhancing the transparency and decision usefulness of income tax disclosures. Disclosure requirements of this update include (on an annual basis) the disclosure of specific categories in the rate reconciliation and the inclusion of additional information for reconciling items that meet a quantitative threshold (if the effect of the reconciling item is equal to or greater than 5 percent of the amount computed by multiplying pre-tax income by the applicable statutory rate). The amendment also requires the disclosure (on an annual basis) of information about income taxes paid (net of refunds) including, the disaggregation by federal, state, and foreign taxes as well as by individual jurisdiction. Additional requirements include the disclosure of income (loss) from continuing operations before income tax expense (benefit) disaggregated between foreign and domestic as well as income tax expense (benefit) from continuing operations disaggregated by federal, state, and foreign. ASU 2023-09 is effective for the Company beginning January 1, 2025 with early adoption being permitted. ASU 2023-09 is to be applied on a prospective basis with retrospective application permitted.

(2)Segment Information

The following segment presentation is based on the methodology that management uses for making operating decisions and assessing performance of its various business activities. A reconciliation of the segment presentation to the GAAP financial statements is provided.

PNM

PNM includes the retail electric utility operations of PNM that are subject to traditional rate regulation by the NMPRC. PNM provides integrated electricity services that include the generation, transmission, and distribution of electricity for retail electric customers in New Mexico. PNM also includes the generation and sale of electricity into the wholesale market, which includes the asset optimization of PNM’s jurisdictional capacity, as well as providing transmission services to third parties. FERC has jurisdiction over wholesale power and transmission rates. In 2023, ETBC I, a special purpose entity that is wholly-owned by PNM, was formed for the limited purpose of purchasing, owning, and administering energy transition property, issuing Securitized Bonds, and performing related activities. See Note 6.

TNMP

TNMP is an electric utility providing services in Texas under the TECA. TNMP’s operations are subject to traditional rate regulation by the PUCT. TNMP provides transmission and distribution services at regulated rates to various REPs that, in turn, provide retail electric service to consumers within TNMP’s service area. TNMP also provides transmission services at regulated rates to other utilities that interconnect with TNMP’s facilities.

Corporate and Other

The Corporate and Other segment includes PNMR holding company activities, primarily related to corporate level debt and PNMR Services Company. The activities of PNMR Development and the equity method investment in NMRD are also included in Corporate and Other, until the close of the sale on February 27, 2024 (Note 16). Eliminations of intercompany transactions are reflected in the Corporate and Other segment.

The following tables present summarized financial information for PNMR by segment. PNM and TNMP each operate in onlyone segment. Therefore, tabular segment information is not presented for PNM and TNMP.

PNMR SEGMENT INFORMATION

The Company defines utility margin as electric operating revenues less cost of energy. Cost of energy consists primarily of fuel and purchase power costs for PNM and costs charged by third-party transmission providers for TNMP. The Company believes that utility margin provides a more meaningful basis for evaluating operations than electric operating revenues since substantially all such costs are offset in revenues as fuel and purchase power costs are passed through to customers under PNM’s FPPAC and third-party transmission costs are passed on to consumers through TNMP’s transmission cost recovery factor. Utility margin is not a financial measure required to be presented and is considered a non-GAAP measure. PNM and TNMP do not intend for utility margin to represent any financial measure as defined by GAAP however, the calculation of utility margin, as presented, most closely compares to gross margin as defined by GAAP. Reconciliations between utility margin and gross margin are presented below.

1 Corporate and Other depreciation and amortization represents corporate level activities that are billed at cost and reflected as general and administrative expenses at PNM and TNMP and therefore are not a component of gross margin or utility margin. See Note 1.

(3)Accumulated Other Comprehensive Income (Loss)

Information regarding accumulated other comprehensive income (loss) for the three months ended March 31, 2024 and 2023 is as follows:

The Condensed Consolidated Statements of Earnings include pre-tax amounts reclassified from AOCI related to Unrealized Gains on Available-for-Sale Debt Securities in gains (losses) on investment securities, related to Pension Liability Adjustment in other (deductions), and related to Fair Value Adjustment for Cash Flow Hedges in interest charges. The income tax impacts of all amounts reclassified from AOCI are included in income taxes in the Condensed Consolidated Statements of Earnings.

(4)Earnings Per Share

Dual presentation of basic and diluted earnings per share is presented in the Condensed Consolidated Statements of Earnings of PNMR. Diluted earnings per share was computed using the treasury stock method for both restricted stock and the 2023 Forward Sale Agreements. Information regarding the computation of earnings per share is as follows:

(5)Electric Operating Revenues

PNMR is an investor-owned holding company withtwo regulated utilities providing electricity and electric services in New Mexico and Texas. PNMR’s electric utilities are PNM and TNMP. Additional information concerning electric operating revenue is contained in Note 4 of the Notes to Consolidated Financial Statements in the 2023 Annual Reports on Form 10-K.

Accounts Receivable and Allowance for Credit Losses

Accounts receivable consists primarily of trade receivables from customers. In the normal course of business, credit is extended to customers on a short-term basis. The Company estimates the allowance for credit losses on trade receivables based on historical experience and estimated default rates. Accounts receivable balances are reviewed monthly, adjustments to the allowance for credit losses are made as necessary and amounts that are deemed uncollectible are written off. In addition to the allowance for credit losses on trade receivables, the Company has evaluated other receivables for potential credit related losses. These balances include potential exposures for other non-retail utility services. In the three months ended March 31, 2024 and 2023, there wereno estimated credit losses related to these transactions.

Contract Balances

Performance obligations related to contracts with customers are typically satisfied when the energy is delivered and the customer or end-user utilizes the energy. Accounts receivable from customers represent amounts billed, including amounts under ARPs. For PNM, accounts receivable reflected on the Condensed Consolidated Balance Sheets, net of allowance for credit losses, includes $75.4 million at March 31, 2024 and $93.6 million at December 31, 2023 resulting from contracts with customers. All of TNMP’s accounts receivable results from contracts with customers.

Contract assets are an entity’s right to consideration in exchange for goods or services that the entity has transferred to a customer when that right is conditioned on something other than the passage of time (for example, the entity’s future performance). Upon the completion of the Western Spirit Line, PNM entered into a Transmission Service Agreement (“TSA”) with Pattern Wind under an incremental tariff rate approved by FERC. The terms of the agreement provide for a financing component that benefits the customer. As such, the revenue that PNM recognizes will be in excess of the consideration received at the beginning of the service term resulting in a contract asset. The balance of the contract asset is $24.6 million at March 31, 2024 and $22.1 million at December 31, 2023. This contract asset is presented in Other deferred charges on the Condensed Consolidated Balance Sheets.

Contract liabilities arise when consideration is received in advance from a customer before satisfying the performance obligations. Therefore, revenue is deferred and not recognized until the obligation is satisfied. Other utilities pay PNM and TNMP in advance for the joint-use of their utility poles. These revenues are recognized over the period of time specified in the joint-use contract, typically for one calendar year. Deferred revenues on these arrangements are recorded as contract liabilities. PNMR’s, PNM’s, and TNMP’s contract liabilities and related revenues are not material for any of the periods presented. The Company has no other arrangements with remaining performance obligations to which a portion of the transaction price would be required to be allocated.

Disaggregation of Revenues

A disaggregation of revenues from contracts with customers by the type of customer is presented in the table below.

(1)Includes sales for resale activity resulting from PNM’s participation in the EIM.

(6)Variable Interest Entities

How an enterprise evaluates and accounts for its involvement with variable interest entities, focuses primarily on whether the enterprise has the power to direct the activities that most significantly impact the economic performance of a VIE. This evaluation requires continual reassessment of the primary beneficiary of a VIE. Additional information concerning PNM’s VIEs is contained in Note 10 of the Notes to Consolidated Financial Statements in the 2023 Annual Reports on Form 10-K.

Valencia

PNM has a PPA to purchase all of the electric capacity and energy from Valencia, a 155 MW natural gas-fired power plant near Belen, New Mexico, through May 2028. A third party built, owns, and operates the facility while PNM is the sole purchaser of the electricity generated. PNM is obligated to pay fixed operation and maintenance and capacity charges in addition to variable operation and maintenance charges under this PPA. For the three months ended March 31, 2024 and 2023, PNM paid $5.1 million and $5.0 million for fixed charges and $0.1 million and $1.6 million for variable charges. PNM does not have any other financial obligations related to Valencia. The assets of Valencia can only be used to satisfy its obligations and creditors of Valencia do not have any recourse against PNM’s assets. During the term of the PPA, PNM has the option, under certain conditions, to purchase and own up to 50% of the plant or the VIE. The PPA specifies that the purchase price would be the greater of 50% of book value reduced by related indebtedness or 50% of fair market value.

PNM sources fuel for the plant, controls when the facility operates through its dispatch, and receives the entire output of the plant, which factors directly and significantly impact the economic performance of Valencia. Therefore, PNM has concluded that the third-party entity that owns Valencia is a VIE and that PNM is the primary beneficiary of the entity since PNM has the power to direct the activities that most significantly impact the economic performance of Valencia and will absorb the majority of the variability in the cash flows of the plant. As the primary beneficiary, PNM consolidates Valencia in its financial statements. Accordingly, the assets, liabilities, operating expenses, and cash flows of Valencia are included in the Condensed Consolidated Financial Statements of PNM although PNM has no legal ownership interest or voting control of the VIE. The assets and liabilities of Valencia are set forth below and are not shown separately on the Condensed Consolidated Balance Sheets. The owner’s equity and net income of Valencia are considered attributable to non-controlling interest.

Summarized financial information for Valencia is as follows:

Westmoreland San Juan Mining, LLC

As discussed in the subheading Coal Supply in Note 11, PNM purchased coal for SJGS under the SJGS CSA. PNM and Westmoreland also entered into agreements under which CCR disposal and mine reclamation services for SJGS would be provided. In 2019, Westmoreland emerged from Chapter 11 bankruptcy as a privately held company owned and operated by a group of its former creditors. Under the reorganization, the assets of SJCC were sold to Westmoreland San Juan Mining, LLC (“WSJ LLC”), a subsidiary of Westmoreland Mining Holdings, LLC. As successor entity to SJCC, WSJ LLC assumed all rights and obligations of SJCC including obligations to PNM under the SJGS CSA and to PNMR under letter of credit support agreements. In conjunction with the retirement of SJGS, the SJGS CSA expired under its terms on September 30, 2022.

PNMR issued $30.3 million in letters of credit to facilitate the issuance of reclamation bonds required in order for SJCC to mine coal to be supplied to SJGS. As discussed above, WSJ LLC assumed the rights and obligations of SJCC, including obligations to PNMR for the letters of credit. The letters of credit support results in PNMR having a variable interest in WSJ LLC since PNMR is subject to possible loss in the event performance by PNMR is required under the letters of credit support. PNMR 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. Additionally, much of the mine reclamation activities have been and will continue to be performed after the SJGS CSA expired on September 30, 2022. 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. PNMR’s analysis of its arrangements with WSJ LLC concluded that WSJ LLC had the ability to direct its mining operations and reclamation services, which are the factors that most significantly impact the economic performance of WSJ LLC. Other than PNM being able to ensure that coal was supplied in adequate quantities and of sufficient quality to provide the fuel necessary to operate SJGS in a normal manner and monitoring of reclamation activities, the mining operations and reclamation services were solely under the control of WSJ LLC, including developing mining and reclamation plans, hiring of personnel, and incurring operating and maintenance expenses. Neither PNMR nor PNM had any ability to direct or influence the mining operation or reclamation activities. PNM’s involvement through the SJGS CSA and 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 had been able to mine or performs reclamation services more efficiently than anticipated, its economic performance would improve. Conversely, if WSJ LLC had not been able to mine or does not perform reclamation services as efficiently as anticipated, its economic performance would be negatively impacted. Accordingly, PNMR believes WSJ LLC is the primary beneficiary and, therefore, WSJ LLC is not consolidated by either PNMR or PNM. The amounts outstanding under the letters of credit support continue to be PNMR’s maximum exposure to loss from the VIE at March 31, 2024.

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 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 Securitized Bonds are paid in full and all allowed financing costs have been recovered. The 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 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 2023 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

Overview

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. 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 has entered into agreements for the purchase and sale of power from third parties. On April 23, 2024, PNM entered into agreements to purchase a total of 150 MW from July 1, 2024 through July 30, 2024 and 100 MW from August 1, 2024 through August 30, 2024. The agreements will be accounted for as derivative agreements and will be considered economic hedges under the NMPRC approved hedging plan covered by its FPPAC during the second quarter of 2024.

Agreements for the purchase of 85 MW from June through September 2023 as well as agreements for the sale of 50 MW from September 1, 2024 through September 30, 2024 and 50 MW from October 1, 2024 though December 31, 2024 were not considered derivatives because there was either no notional amount due to their unit-contingent nature or qualified for a normal purchase, normal sale scope exception.

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. TNMP does not enter into energy related derivative contracts.

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 three months ended March 31, 2024 and the year ended December 31, 2023, 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 results of operations on the Condensed Consolidated Statements of Earnings and are classified between 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

PNM’s commodity derivative instruments that are recorded at fair value, all of which are accounted for as economic hedges and considered Level 2 fair value measurements, are presented in the following line items on the Condensed Consolidated Balance Sheets:

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

As discussed above, PNM has NMPRC-approved guidelines for hedging arrangements to manage fuel and purchased power costs related to customers covered by its FPPAC. The table above includes $0.8 million of current assets andzero of current liabilities related to these arrangements at March 31, 2024 and $0.8 million of current assets andzero of current liabilities at December 31, 2023 with changes in fair value recorded as regulatory assets and regulatory liabilities.

At March 31, 2024 and December 31, 2023, PNM hadno amounts recognized for the legal right to reclaim cash collateral. However, amounts posted as cash collateral under margin arrangements were $0.3 million at March 31, 2024 and $0.2 million at December 31, 2023. These amounts are included in other current assets on the Condensed Consolidated Balance Sheets. At March 31, 2024 and December 31, 2023, obligations to return cash collateral were $0.2 million, which is included in other current liabilities on the Condensed Consolidated Balance Sheets.

The changes in the fair value of commodity derivative instruments that are considered economic hedges had no impact on PNM’s net earnings during the three months ended March 31, 2024 and 2023. Commodity derivatives had no impact on OCI for any of the periods presented. Commodity contract volume positions are presented in MMBTU for gas related contracts and in MWh for power related contracts. The table below presents PNM’s net buy (sell) volume positions:

In connection with managing its commodity risks, PNM enters into master agreements with certain counterparties. If PNM is in a net liability position under an agreement, some agreements provide that the counterparties can request collateral if PNM’s credit rating is downgraded; other agreements provide that the counterparty may request collateral to provide it with “adequate assurance” that PNM will perform; and others have no provision for collateral.

PNM has contingent requirements to provide collateral under certain commodity contracts having an objectively determinable collateral provision, that are in net liability positions, and that are not fully collateralized with cash. Contractual liability represents those commodity derivative contracts recorded at fair value on the balance sheet, determined on an individual contract basis without offsetting amounts for individual contracts that are in an asset position and could be offset under master netting agreements with the same counterparty. Cash collateral posted under these contracts does not reflect letters of credit under the Company’s revolving credit facilities that may have been issued as collateral. Net exposure is the net contractual liability for all contracts, including those designated as normal purchase and normal sale, offset by existing collateral and by any offsets available under master netting agreements, including both assets and liability positions. At March 31, 2024 and December 31, 2023, PNM had zero contractual liability, zero posted cash collateral, and no such contracts in a net liability position.

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 March 31, 2024 and December 31, 2023, the fair value of investment securities included $371.0 million and $361.0 million for the NDT, $11.7 million and $12.3 million for the SJGS decommissioning trust, and $65.5 million and $71.1 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 March 31, 2024 and December 31, 2023, PNM had no available-for-sale debt securities for which carrying value exceeds fair value and there are no impairments considered to be “other than temporary” that are included in AOCI and not 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 $13.4 million and $2.0 million for the three months ended March 31, 2024 and 2023.

At March 31, 2024, 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 which 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 net asset value. 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, which are measured at NAV at the end of each reporting period. Audited financial statements are received for each fund and reviewed by the Company annually. Fair value for these collective investment trusts 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

PNMR has various stock-based compensation programs, which provide restricted stock awards, that are performance based and time based, under the Performance Equity Plan (“PEP”). Although certain PNM and TNMP employees are eligible to participate in the PNMR plans, PNM and TNMP do not have separate employee stock-based compensation plans. Performance stock awards awarded under the PEP are awarded for athree-year, overlapping performance period. Performance stock awards with performance periods ending before 2024 or after 2025 are subject to achieving both performance and market targets. Performance stock awards with performance periods ending from 2024 through 2025 do not include 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 2023 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 March 31, 2024, PNMR had unrecognized expense related to stock awards of $8.4 million, which is expected to be recognized over an average of 2.2 years.

The grant date fair value for restricted stock and stock awards with internal PNMR performance targets is determined based on the market price of PNMR 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 three months ended March 31, 2024:

Included, as granted and released, in the table above are 80,492 previously awarded shares that were earned for the 2021 - 2023 performance measurement period and ratified by the Board in February 2024 (based upon achieving targets at above “target”, below “maximum” levels). Excluded from the table above are 138,978,133,960, and 186,951 shares for thethree-year performance periods ending in 2024, 2025 and 2026 that will be awarded if all performance and market criteria are achieved at maximum levels and all executives remain eligible.

On December 4, 2023, the Company entered into a retention agreements with its Chairman and Chief Executive Officer and its Senior Vice President and General Counsel under which they would be awarded a total of 26,766 and 8,922 respectively of restricted stock rights if they remained employed through the award’s vesting date which is the earliest of 24 months from the grant date, the closing of the Merger, orsix months following the termination of the Merger. As of December 31, 2023, upon the notice from Avangrid regarding the termination of the Merger Agreement, these awards will vest on June 30, 2024.

On December 4, 2023, the Company entered into a retention agreement with its President and Chief Operating Officer under which he would receive a retention bonus of $1.0 million to be paid in increments beginning in December 2023 and continuing each December until 2025. On April 8, 2024, pursuant to the retention agreement, the Board elected to convert the unvested portion of the retention bonus into restricted stock rights equal to $0.8 million of the fair value of one share of Company stock as of the first trading day after expiration of the current black-out period.

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

(9)Financing

The Company’s financing strategy includes both short-term and long-term borrowings. The Company utilizes short-term revolving credit facilities, as well as cash flows from operations, to provide funds for both construction and operating expenditures. Depending on market and other conditions, the Company will periodically sell long-term debt or enter into term loan arrangements and use the proceeds to reduce borrowings under the revolving credit facilities or refinance other debt. Each of the Company’s revolving credit facilities, term loans, and other debt agreements contains a single financial covenant that requires the maintenance of a debt-to-capitalization ratio. For the PNMR 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 2023 Annual Reports on Form 10-K.

On May 16, 2023, PNM filed a shelf registration statement that provides for the issuance of up to $650.0 million of SUNs that expires in May 2026.

On March 2, 2022, PNMR filed a shelf registration that provides for the issuance of various types of debt and equity securities. The PNMR shelf registration statement expires in March 2025.

Financing Activities

On March 28, 2024, TNMP entered into an agreement (the “TNMP 2024 Bond Purchase Agreement”) with institutional investors for the sale of $285.0 million aggregate principal amount offour series of TNMP first mortgage bonds (the “TNMP 2024 Bonds”) offered in private placement transactions. TNMP issued the first two series on March 28, 2024, consisting of $32.0 million at a 5.26% interest rate, due March 28, 2029, and $85.0 million at a 5.55% interest rate, due March 28, 2036. The third and fourth series of $40.0 million and $128.0 million will be issued on or before July 1, 2024, at a 5.65% and 5.79% interest rate, respectively. The issuance of the third and fourth series is subject to the satisfaction of customary conditions, including continuing compliance with the representations, warranties and covenants of the TNMP 2024 Bond Purchase Agreement. The proceeds were and will be used to repay existing debt, including the $80.0 million of FMBs that are due in July 2024 and borrowings under the TNMP Revolving Credit Facility, for funding of capital expenditures, and for other corporate purposes. The TNMP 2024 Bonds are subject to continuing compliance with the representations, warranties and covenants set forth in the supplemental indentures governing the TNMP 2024 Bonds. The terms of the supplemental indentures governing the TNMP 2024 Bonds include the customary covenants discussed above. In the event of certain changes of control of PNMR or TNMP, TNMP will be required to offer to prepay the TNMP 2024 Bonds at par. TNMP has the right to redeem any or all of the TNMP 2024 Bonds prior to their maturity, subject to payment of a customary make-whole premium.

On April 28, 2023, PNM entered into an agreement (the “PNM 2023 Note Purchase Agreement”) with institutional investors for the sale and issuance of $200.0 million aggregate principal amount oftwo series of SUNs (the “PNM 2023 SUNs”) offered in private placement transactions. The PNM 2023 SUNs were issued on April 28, 2023. PNM issued $150.0 million of the PNM 2023 SUNs at 5.51%, due April 28, 2035, and another $50.0 million at 5.92%, due April 28, 2053. Proceeds from the PNM 2023 SUNs were used to repay borrowings under the PNM Revolving Credit Facility and the PNM New Mexico Credit Facility, for funding of capital expenditures, and for general corporate purposes. The PNM 2023 Note Purchase Agreement includes the customary covenants discussed above. In the event of a change of control of PNM, PNM will be required to offer to prepay the PNM 2023 SUNs at par. PNM has the right to redeem any or all of the PNM 2023 SUNs prior to their maturities, subject to payment of a customary make-whole premium.

On April 28, 2023, TNMP entered into an agreement (the “TNMP 2023 Bond Purchase Agreement”) with institutional investors for the sale of $185.0 million aggregate principal amount oftwo series of TNMP first mortgage bonds (the “TNMP 2023 Bonds”) offered in private placement transactions. TNMP issued the first series of $130.0 million on April 28, 2023, at a 5.01% interest rate, due April 28, 2033. The second series of $55.0 million was issued on July 28, 2023, at a 5.47% interest rate, due July 28, 2053. 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 2023 Bonds are subject to continuing compliance with the representations, warranties and covenants set forth in the supplemental indentures governing the TNMP 2023 Bonds. The terms of the supplemental indentures governing the TNMP 2023 Bonds include the customary covenants discussed above. In the event of certain changes of control of PNMR or TNMP, TNMP will be required to offer to prepay the TNMP 2023 Bonds at par. TNMP has the right to redeem any or all of the TNMP 2023 Bonds prior to their maturity, subject to payment of a customary make-whole premium.

On November 10, 2022, PNMR entered into a distribution agreement with BofA Securities, Inc., MUFG Securities Americas Inc. and Wells Fargo Securities, LLC, as sales agents and Bank of America, N.A., MUFG Securities EMEA plc and Wells Fargo Bank, N.A., as forward purchasers, pursuant to which the Company may sell, from time to time, up to an aggregate sales price of $200.0 million of its common stock, no par value, through the sales agents (the “PNMR 2022 ATM Program”). Sales of the shares made pursuant to the distribution agreement may be made in “at the market offerings” as defined in Rule 415 of the Securities Act. PNMR did not initially receive any proceeds upon the execution of this agreement.

Throughout 2023, PNMR entered into forward sale agreements listed below, for the sale of shares of PNMR common stock. On December 15, 2023, PNMR physically settled the forward purchases under the PNMR 2022 ATM Program and used the proceeds to repay borrowings under the PNMR Revolving Credit Facility and for other corporate purposes. Gross cash proceeds shown below were reduced by $1.0 million in issuance costs resulting in net cash proceeds of $198.2 million.

At March 31, 2024, variable interest rates were 6.38% on the PNMR 2021 Delayed-Draw Term Loan that matures in May 2025 and 6.78% on the PNMR 2023 Term Loan that matures in June 2026.

Hedging Arrangements

PNMR has entered into hedging agreements that establish a fixed rate for the indicated amount of variable rate debt, above which a customary spread is applied, which is subject to change if there is a change in PNMR’s credit rating. As of March 31, 2024, PNMR’s hedging agreements are as follows:

These hedge agreements are accounted for as cash flow hedges. The fair value of these hedges was a gain of $7.8 million and a loss of less than $0.1 million at March 31, 2024. The fair value gain of $7.6 million is included in Other current assets, $0.2 million is included in Other deferred charges, and less than $0.1 million for the loss is included in Other deferred credits on the Condensed Consolidated Balance Sheets. The fair value was determined using Level 2 inputs under GAAP, including using forward SOFR curves under the mid-market convention to discount cash flows over the remaining term of the agreements.

Short-term Debt and Liquidity

As of March 31, 2024, the PNMR 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. On April 1, 2024, PNMR and PNM amended their respective revolving credit facilities, extending their maturity March 30, 2029, withtwo one-year extension options that, if exercised, would extend the maturity to through March 30, 2031, subject to approval by a majority of the lenders. PNM also has the $40.0 million PNM New Mexico Credit Facility with a maturity of May 20, 2026. As of March 31, 2024, the TNMP Revolving Credit Facility had a capacity of $100.0 million and was secured by $100.0 million aggregate principal amount of TNMP first mortgage bonds. On April 1, 2024, TNMP entered into a new $200.0 million Revolving Credit Facility that replaced the $100.0 million Revolving Credit Facility. The new $200.0 million Revolving Credit Facility is secured by $200.0 million aggregate principal amount of TNMP first mortgage bonds and has a maturity of March 30, 2029, withtwo one-year extension options that, if exercised, would extend the maturity to March 30, 2031, subject to approval by a majority of the lenders. Variable interest rates under the PNMR, PNM, and TNMP revolving credit facilities are based on SOFR.

Short-term debt outstanding consists of:

In addition to the above borrowings, PNMR, PNM, and TNMP had letters of credit outstanding of $3.1 million, zero, andzero at March 31, 2024 that reduce the available capacity under their respective revolving credit facilities. PNMR also had $30.3 million of letters of credit outstanding under the WFB LOC Facility. The above table excludes intercompany debt. As of March 31, 2024, PNM and TNMP had $2.3 million andzero in intercompany borrowings from PNMR. As of December 31, 2023, neither PNM nor TNMP had any intercompany borrowings from PNMR. PNMR Development had $2.3 million and $0.1 million in short-term borrowings outstanding from PNMR at December 31, 2023 and March 31, 2024. PNMR hadno intercompany borrowings from PNMR Development at December 31, 2023 or March 31, 2024.

PNM has $198.0 million of PCRBs that must be remarketed by June 1, 2024 as well as $2.5 million and $3.4 million in scheduled payments due for the ETBC I Securitized Bonds in August 2024 and February 2025. TNMP has $80.0 million of FMBs that are due in July 2024, which will be repaid with the $128.0 million proceeds from the TNMP 2024 Bonds that will be issued on or before July 1, 2024. 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 2023 Annual Reports on Form 10-K.

(10)Pension and Other Postretirement Benefit Plans

PNMR 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”). PNMR 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 2023 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 months ended March 31, 2024 and 2023 and doesnot anticipate making any contributions to the pension plan in 2024 through 2028 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 months ended March 31, 2024 and 2023, however, a portion of the disbursements attributable to the OPEB trust is paid by PNM and are therefore considered to be contributions to the OPEB plan. Payments by PNM on behalf of the PNM OPEB plan were less than $0.1 million for the three months ended March 31, 2024 and $0.8 million for the three months ended March 31, 2023. These payments are expected to total $0.2 million in 2024 and $10.1 million for 2025-2028. Disbursements under the executive retirement program, which are funded by PNM and considered to be contributions to the plan, were $0.3 million in the three months ended March 31, 2024 and $0.1 million in the three months ended March 31, 2023 and are expected to total $1.2 million during 2024 and $4.4 million for 2025-2028.

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 months ended March 31, 2024 and 2023 and doesnot anticipate making any contributions to the pension plan in 2024 through 2027 based on current law, funding requirements, and estimates of portfolio performance. In 2028, TNMP does anticipate making a contribution of $0.2 million 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 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 months ended March 31, 2024 and 2023 and doesnot expect to make contributions to the OPEB trust during the period 2024-2028. Disbursements under the executive retirement program, which are funded by TNMP and considered to be contributions to the plan, were less than $0.1 million in the three months ended March 31, 2024 and 2023 and are expected to total $0.1 million during 2024 and $0.2 million in 2025-2028.

(11)Commitments and Contingencies

Overview

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 2023 Annual Reports on Form 10-K.

Commitments and Contingencies Related to the Environment

Nuclear Spent Fuel and Waste Disposal

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

PNM estimates that it will incur approximately $55.6 million (in 2023 dollars) for its share of the costs related to the on-site interim storage of spent nuclear fuel at PVNGS for the remaining term of the operating licenses. PNM accrues these costs as a component of fuel expense as the nuclear fuel is consumed. At March 31, 2024 and December 31, 2023, PNM had a liability for interim storage costs of $11.7 million and $11.0 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 Energy Transition Act

In 2019, the Governor signed into New Mexico state law Senate Bill 489, known as the Energy Transition Act (“ETA”). The ETA became effective as of June 14, 2019 and 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 ETA requires utilities operating in New Mexico to have renewable portfolios equal to 40% by 2025, 50% by 2030, 80% by 2040, and 100% zero-carbon energy by 2045. The ETA also allows 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. The ETA also directs the New Mexico Environmental Improvement Board to adopt standards of performance that limit CO 2 emissions to no more than 1,100 lbs. per MWh beginning January 1, 2023 for new or 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, which are designed to be highly rated bonds that can be issued 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. See additional discussion in Note 12 of PNM’s Four Corners Abandonment Application.

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 BART 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.

In 2017, EPA published revisions to the regional haze rule in the Federal Register that delayed the due date for the next cycle of SIPs from 2019 to 2021 and altered the planning process that states must employ in determining whether to impose “reasonable progress” emission reduction measures. EPA’s new rule was challenged by numerous parties, but the litigation was held in abeyance after EPA granted various petitions for reconsideration.

In 2018, EPA released a new guidance document on tracking visibility progress for the second planning period. EPA is allowing states discretion to develop SIPs that may differ from EPA’s guidance as long as they are consistent with the CAA and other applicable regulations. In 2019, EPA finalized the draft guidance that was previously released as a companion to the regional haze rule revisions, and EPA clarified that guidance in a memorandum issued in 2021. SIPs for the second planning period were due in July 2021, which deadline NMED was unable to meet. NMED is currently preparing its SIP for the second compliance period and has notified PNM that it will not be required to submit a regional haze four-factor analysis for SJGS since PNM retired its share of SJGS in 2022. On August 30, 2022, EPA published in the Federal Register an official “Finding of Failure to Submit” for states, including New Mexico, that have not yet submitted a round 2 regional haze SIP. This action by EPA starts a 2-year clock for it to issue a Federal Implementation Plan (FIP). NMED’s current timeline indicates the proposed SIP will be submitted to EPA by Summer 2024.

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.

Multiple states, utilities, and trade groups challenged both the Carbon Pollution Standards for new sources and the Clean Power Plan for existing sources in separate cases. Challengers successfully petitioned the US Supreme Court for a stay of the Clean Power Plan. However, before the DC Circuit could issue an opinion regarding either the Carbon Pollution Standards or the Clean Power Plan, the Trump Administration asked that the case be held in abeyance while the rules were reevaluated, which was granted.

In 2019, EPA repealed the Clean Power Plan, promulgated the ACE Rule, and revised the implementing regulations for all emission guidelines. EPA set the BSER for existing coal-fired power plants as heat rate efficiency improvements based on a range of “candidate technologies” that can be applied inside the fence line of an individual facility. The DC Circuit issued an order that granted motions by various petitioners, including industry groups and EPA, to dismiss the cases challenging the Clean Power Plan as moot due to EPA’s issuance of the ACE Rule.

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. While the DC Circuit rejected the ACE Rule, it did not reinstate the Clean Power Plan. Rather, the DC Circuit granted an EPA motion asking the court to withhold issuance of the mandate with respect to the repeal of the Clean Power Plan until EPA responds to the court’s remand in a new rulemaking action.

Numerous parties sought review by the US Supreme Court, and on June 30, 2022, the Court held that the “generation shifting” approach in the Clean Power Plan exceeded the powers granted to EPA by Congress, though the Court did not address the related issue of whether Section 111 of the CAA only authorizes EPA to require measures that can be implemented entirely within the fence line at an individual source. 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.

On May 23, 2023, EPA published in the Federal Register proposed regulatory actions under CAA sections 111(b) and (d) to replace the Clean Power Plan and the ACE Rule. The proposed regulations cover: (1) New natural gas-based EGUs under section 111(b); (2) Existing large and frequently operated natural gas-based EGUs under section 111(d); and (3) Existing coal-based EGUs under section 111(d). Standards of performance for existing coal EGUs will be based on two technologies depending on retirement date: CCS or co-firing gas in lieu of coal. For gas-based EGUs, the standards will be based on CCS or the use of green hydrogen in lieu of natural gas. States will be required to develop SIPs to EPA that provide for the establishment, implementation and enforcement of these standards as they apply to existing sources. States may take into account remaining useful life and other factors when establishing the standards. EPA is proposing that existing coal units must start complying with their gas co-firing or CCS based standards of performance on January 1, 2030, unless they commit to retirement before 2032 (or retirement by 2035 if they also commit to a 20% annual operating limit). Existing combustion turbine units must start complying with their hydrogen or CCS based standards of performance on January 1, 2032, or January 1, 2035, depending on their subcategory, which is based on the control technology selected. The package also includes a proposed repeal of the ACE Rule and revisions to the standard for modified and reconstructed units, along with a notice of public rulemaking seeking data and information about setting standards for existing smaller natural gas-based generators. Comments on the rule were due to EPA by August 8, 2023. PNM filed company-specific comments and continues to review the proposed rule and its potential impacts on the company’s fossil generation resources. On April 25, 2024, EPA signed a final rule promulgating emission guidelines under Section 111 of the CAA requiring states to develop standards of performance for greenhouse gas emissions from new gas-fired combustion turbines and existing fossil-fuel-fired electric steam generating units. The standards for existing coal- or gas-fired steam generating units must be based on the use of CCS, natural gas co-firing, or early retirement, and 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). We are currently determining what impact, if any, the final rule will have on our business, results of operation, and financial condition.

In late February 2024, EPA indicated that the CAA 111 rule will not contain provisions for existing natural gas units and will issue a new proposal for existing gas in the future after conducting additional stakeholder outreach. On March 26, 2024, EPA announced it was opening a non-regulatory docket and issued framing questions to gather input about ways to design a stronger, more durable approach to GHG regulation of existing gas combustion turbines. The docket will be open for public comment from March 26, 2024 to May 28, 2024 and the agency will hold a May 17 policy forum to bring stakeholders together to share ideas with EPA and others. The agency has indicated that it plans to promulgate a final rule by Summer 2024.

On January 27, 2021, President Biden signed an extensive Executive Order aimed at addressing climate change concerns domestically and internationally. The order is intended to build on the initial climate-related actions the Biden Administration took on January 20, 2021. It addresses 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 will sit on the National Security Council. On April 22, 2021, at the Earth Day Summit, as part of the U.S.’s re-entry into the Paris Agreement, President Biden unveiled the goal to cut U.S. emissions by 50% - 52% from 2005 levels by 2030, nearly double the GHG emissions reduction target set by the Obama Administration. The 2030 goal joins President Biden’s other climate goals which include a carbon pollution-free power sector by 2035 and a net-zero emissions economy by no later than 2050.

PNM’s review of the GHG emission reductions standards that may occur as a result of legislation or regulation under the Biden Administration and in response to the court’s ruling on the ACE Rule is ongoing. PNM cannot predict the impact these standards may have on its operations or a range of the potential costs of compliance, if any.

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 will retain 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.

On March 26, 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. 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. EPA finalized its decision to retain the ozone NAAQS in a notice published on December 31, 2020 making it immediately effective. In response to lawsuits brought by states and environmental groups, on October 29, 2021, EPA filed a motion in the DC Circuit indicating it will reconsider the 2020 ozone NAAQS. On August 21, 2023, EPA announced an entirely new review of the ozone standard that will incorporate the work to date on the reconsideration, likely indicating a delay in the schedule for a decision on whether the standard should be revised. On January 3, 2024, EPA filed in the DC Circuit an unopposed motion for voluntary remand, without vacatur, of EPA’s final rule retaining the current ozone NAAQS. The filing was made in the consolidated cases challenging the 2020 ozone NAAQS rule.

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. The rule became effective May 8, 2018.

NMED has responsibility for bringing the small area in Doña Ana County designated as marginal/non-attainment for ozone into compliance and will look at all sources of NOx and volatile organic compounds. NMED has submitted the required elements for the Sunland Park Ozone Non-attainment Area SIP. This includes a transportation conformity demonstration, a 2017 baseline emissions inventory and emissions statement, and an amendment to the state’s Non-attainment Permitting rules at 20.2.79 New Mexico Administrative Code to conform to EPA’s SIP Requirements Rule for 2015 Q3 NAAQS (i.e., “implementation rule”).

The SIP elements had staggered deadlines and were done in three submissions: (1) the transportation conformity demonstration was completed by the El Paso Metropolitan Planning Organization on behalf of New Mexico in 2019, which is responsible for transportation planning in that area, and the submission received concurrence from EPA and the Federal Highway Administration; (2) the emissions inventory and statement SIP was submitted to EPA in September 2020; and (3) the Non-attainment New Source Review SIP was submitted to EPA on August 10, 2021. On October 15, 2021, EPA proposed to approve New Mexico’s SIP to meet the emissions inventory and statement requirements of the CAA for the Sunland Park Ozone Non-Attainment Area.

PNM does not believe there will be material impacts to its facilities because of NMED’s 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. With respect to EPA’s reconsideration of the 2020 decision to retain the 2015 ozone standards, EPA is statutorily obligated to complete its review of the ozone standards by December 2025. 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 federal implementation plan 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. Nevertheless, when EPA failed to approve the SIP or issue a FIP within two years of the finding of failure to submit, multiple parties filed a deadline suit against EPA, resulting in a consent decree requiring EPA to issue a FIP or approve a SIP for New Mexico by a deadline of no later than June 1, 2024, which was later extended to August 30, 2024. 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 EPA had not proposed a FIP for the state because the most up to date modeling available at 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, Tennessee) and expanding the Good Neighbor Federal Implementation Plan (FIP) to apply to these states. In denying the NMED-submitted SIP, the EPA concluded that the SIP was incomplete and did not contain the necessary provisions to prohibit emission from sources within the state from interfering with maintenance of the 2015 ozone NAAQS in downwind areas, specifically a maintenance-only receptor in the El Paso area. The FIP aspect of the proposed rule would require fossil fuel-fired power plants in these five states to participate in an allowance-based ozone season NOX emissions trading program beginning in 2025. Comments on the proposed rule are due May 16, 2024. PNM is reviewing the impact of this proposal and will be submitting company-specific comments by the due date. EPA is targeting summer of 2024 for a final rule.

Of importance in considering the possibility of a Good Neighbor plan FIP for New Mexico, are the many court challenges to EPA’s earlier rulemaking imposing a FIP on 23 states. On February 21, 2024, the US Supreme Court heard oral arguments on an Emergency Stay Application. Court issuances of state-by-state stays and remands may impact the viability of a multi-state trading program.

PM Standard – On January 30, 2020, EPA published, in the Federal Register, a notice announcing the availability of a final Policy Assessment for the Review of the NAAQS for Particulate Matter (the “PA”). The 2020 final PA was prepared as part of the review of the primary and secondary PM NAAQS. In the 2020 final PA, EPA recommended lowering the primary annual PM 2.5 standard to between 8 µg/m3 and 10 µg/m3. However, on April 30, 2020, EPA published a proposed rule to retain the current standards for PM due to uncertainties in the data relied upon in the 2020 final PA and EPA published a notice of that final action on December 18, 2020, making it immediately effective. On January 14, 2021, several states and New York City filed a petition for review in the DC Circuit, challenging EPA’s final rule retaining the current primary and secondary PM NAAQS and a similar lawsuit was filed by the Center for Biological Diversity in the DC Circuit. On June 10, 2021, EPA announced that it will reconsider the previous administration’s December 2020 decision to retain the current primary and secondary PM NAAQS and on October 8, 2021, EPA announced the release of a new draft PA stating that available scientific evidence and technical information indicate that the current standards may not be adequate to protect public health and welfare, as required by the CAA. On June 1, 2022, EPA issued a new final PA that likewise indicates current standards may not be adequate and that available scientific evidence could support lowering the standards.

On January 27, 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 particulate matter standard, the daily coarse particulate matter 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. The rule is effective May 6, 2024. States will have until March 2032 to attain compliance with the new standard. During the multi-year implementation process, the NMED will designate attainment/nonattainment areas by March 6, 2026, and submit a State Implementation Plan to EPA by September 6, 2027. This implementation process also applies to the Albuquerque-Bernalillo County Environmental Health Department who may combine efforts with NMED. Bernalillo County does not currently meet the 9 ug/m3 standard which may impact future air permitting activities at Rio Bravo and Reeves Generating Stations if the county is designated as nonattainment. Beginning May 6, 2024, the new standard will be used when conducting required modeling for permit applications and revisions. Although the lower standard is expected to result in new nonattainment areas throughout the country and could prompt additional PM control requirements, PNM cannot predict the impacts of the outcome of future rulemaking.

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 determination. Compliance deadlines under the rule are tied to permit renewal and will be subject to a schedule of compliance established by the permitting authority.

In 2018, several environmental groups sued EPA Region IX in the U.S. Court of Appeals for the Ninth Circuit Court 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, as EPA determined that the facility has 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 several requirements under the Clean Water Act and did not contain required provisions concerning certain revised ELG, existing-source regulations governing cooling-water intake structures, and effluent limits for surface seepage and subsurface discharges from coal-ash disposal facilities. EPA withdrew the Four Corners NPDES permit in order to examine issues raised by the environmental groups. Withdrawal of the permit moots the appeal pending before the EAB. EAB thereafter dismissed the environmental groups’ appeal. EPA issued an updated NPDES permit in 2019. The permit was once again appealed to the EAB and was stayed before the effective date. Oral argument was heard on September 3, 2020. The EAB issued an order denying the petition for review on September 30, 2020. The denial was based on the EAB’s determination that the petitioners had failed to demonstrate that review of the permit was warranted on any of the grounds presented in the petition. 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 and will expire on November 30, 2025. 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 remains in effect pending 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 associated case 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 issued on November 9, 2020. The modification applies to permit elements related to effluent discharge. PNM cannot predict whether the analysis under the settlement agreement will result in 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 needs 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 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 these 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 rule requires compliance with new limits as soon as possible on or after October 13, 2021, but no later than December 31, 2025.

On August 3, 2021, EPA published notice that it will undertake a supplemental rulemaking to revise the ELG after completing its review of the rules reconsidered in 2020. As part of this process, EPA will determine whether more stringent limitations and standards are appropriate. On March 29, 2023, EPA published the proposed ELG Rule in the Federal Register. The proposed rule includes stricter limitations on bottom ash transport water, flue gas desulfurization, and coal combustion residual leachate. Also included are flexibilities for coal-powered facilities that will soon decommission or repower. With this proposed rule EPA has extended the date of decommissioning or repowering from December 31, 2028, to December 31, 2032. Comments on the proposed rule were due May 30, 2023.

On April 24, 2024, EPA signed a final rule to revise ELGs under the Clean Water Act for the Steam Electric Power Generating Point Source Category. This final supplemental rule updates the technology-based ELGs applicable to flue gas desulfurization wastewater, bottom ash transport water, and legacy wastewater at existing sources, and combustion residual leachate at new and existing sources.

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 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 in 2023. PNM is unable to predict the outcome of these matters or a range of the potential costs of compliance.

Santa Fe Generating Station

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

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

PNM submitted work plans to NMED in January 2021 for review and approval. In December 2021, NMED approved both work plans and work activities were completed by the end of 2022 and a report was submitted to the NMED in the first quarter of 2023.

Groundwater sampling for the abatement plan’s first semiannual work commenced at the beginning of March 2023 and was completed in April 2023. The associated report was completed and submitted to the NMED in July 2023. In addition, the work plan for the 2023 CAF work was completed and submitted to the NMED in July 2023. NMED approved the work plan in December 2023 and PNM is working to schedule the associated activities.

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 the NMED determines remediation is not required, whichever is earlier. 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 are currently disposed of in the surface mine pits adjacent to the plant. SJGS does not operate any 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 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 final coal ash rule, which became effective in 2015, 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 contains a number of provisions related to the CCR rules. Among other things, the WIIN Act allows, but does not require, states to develop and submit CCR permit programs for EPA approval, provides flexibility for states to incorporate EPA’s final rule for CCRs or develop other criteria that are at least as protective as EPA’s final rule, and requires 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 will implement the permit program in states that choose not to implement a program, subject to Congressional funding. Until permit programs are in effect, EPA has authority to directly enforce the CCR rule. 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 April 17, 2015, CCR rule. The final Phase One, Part One rule includes two types of revisions. The first revision 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. This deadline 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 revisions, which are commonly referred to as the “Phase Two” revisions. Phase Two proposed revisions to reporting and accessibility to public information, the “CCR piles” and “beneficial use” definitions and the requirements for management of CCR piles. EPA has reopened and extended the Phase Two comment period several times. EPA has not yet finalized provisions in Phase Two related to beneficial use of CCR and CCR piles. This activity is on EPA’s long-term agenda, which means EPA has no plans to address these issues in the next 12 months.

Since promulgating its Phase Two proposal, EPA has finalized two other rules addressing various CCR rule provisions. In 2019, EPA promulgated its proposed Holistic Approach to Closure Part A (“Part A”), which proposed a new deadline of August 31, 2020, for companies to initiate closure of unlined CCR impoundments. In accordance with the DC Circuit Court of Appeals’ vacatur of portions of the CCR Rule, Part A also proposed changing the classification of compacted soil-lined or clay-lined surface impoundments from “lined” to “unlined”. In addition, Part A delineated a process for owners/operators to submit requests for alternative closure deadlines based on lack of alternate disposal capacity. EPA issued the final Part A, which became effective on September 28, 2020. This rule finalized the classification of soil-lined and clay-lined surface impoundments as unlined, thus, triggering closure or retrofit requirements for those impoundments. The final Part A also gave operators of unlined impoundments until April 11, 2021 to cease receipt of waste at these units and initiate closure.

In 2020, EPA issued the proposed Holistic Approach to Closure Part B (“Part B”), which delineated the process for owners/operators to submit alternate liner demonstrations for clay-lined surface impoundments that could otherwise meet applicable requirements. Part B also proposed regulations addressing beneficial use for closure of surface impoundments. EPA issued the final Part B rule, which became effective on December 14, 2020. This rule did not include beneficial use of CCR for closure, which EPA explains will be addressed in subsequent rulemaking actions. On May 18, 2023, EPA published a proposed rule on the regulatory requirements for inactive surface impoundments at inactive facilities 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. EPA intends to issue other rulemakings and finalizing parts of previously proposed rules, including a final rule in October 2024 on remaining Part B issues regarding closure options and annual reporting.

On April 24, 2024, EPA Administrator Regan signed a final rule that extends federal CCR regulatory requirements to (1) inactive CCR surface impoundments at inactive utilities and (2) CCR management units (“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 is managed directly on the land. 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. EPA also codified the controversial definitions of infiltration and liquids that are being litigated in the DC Circuit.

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. According to the Fall 2023 Regulatory Agenda the final rule is expected in March 2026. EPA is coordinating 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.

The CCR rule does not cover mine placement of coal ash. OSM is expected to publish a proposed rule covering mine placement in the future and will likely be influenced by EPA’s rule and the determination by EPA that CCRs are non-hazardous. 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. Based upon the requirements of the final Part A CCR rule, PNM conducted a CCR assessment at SJGS and made minor modifications at the plant to ensure that there are no facilities that would be considered impoundments or landfills under the rule. PNM would seek recovery from its retail customers of all CCR costs for jurisdictional assets that are ultimately incurred.

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

Other Commitments and Contingencies

Coal Supply

Four Corners

APS purchases all of Four Corners’ coal requirements from NTEC, an entity owned by the Navajo Nation, under the Four Corners CSA that expires in 2031. The coal comes from reserves located within the Navajo Nation. The contract provides for pricing adjustments over its term based on economic indices and certain minimum payments that may be required if no deliveries of coal are taken. PNM’s share of the coal costs is being recovered through the FPPAC. See additional discussion of the Four Corners CSA in Note 17 of the Notes to Consolidated Financial Statements in the 2023 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. A mine reclamation costs study was completed in 2024 and PNM remeasured its liability, which resulted in an increase in overall reclamation costs of $20.9 million, due primarily to higher inflationary factors. As a result, PNM recorded an increase of $17.0 million in the liability at March 31, 2024 related to the underground mine in regulatory assets on the Condensed Consolidated Balance Sheets. In addition, PNM recorded an increase of $4.0 million in the liability and a decrease of $0.5 million in Deferred Regulatory assets at March 31, 2024 related to the surface mine as a regulatory disallowance of $4.5 million on the Condensed Consolidated Statements of

Earnings, due to the fact that the NMPRC has capped the amount that can be collected from retail customers for final reclamation of the surface mines at $100.0 million. 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, PNMR entered into the WFB LOC Facility under which letters of credit aggregating $30.3 million have been issued.

A coal mine reclamation study for the mine that serves Four Corners was issued in 2019. The study reflected operation of the mine through 2031, the term of the Four Corners CSA.

Based on the most recent estimates, PNM’s remaining payments as of March 31, 2024 for mine reclamation, in future dollars, are estimated to be $51.4 million for the surface mines at both SJGS and Four Corners and $59.7 million for the underground mine at SJGS. At March 31, 2024 and December 31, 2023, liabilities, in current dollars, of $44.5 million and $50.0 million for surface mine reclamation and $47.9 million and $26.2 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 funded $2.7 million in 2023. The recently completed and approved mine reclamation cost study resulted in an update to the trust’s funding curves. Based on PNM’s reclamation trust fund balance at March 31, 2024, and current funding curves, PNM anticipates contributing $20.7 million in 2024, $3.9 million in 2025, and $4.0 million in 2026. Additional contributions may be necessary in future years in order to meet the year end funding targets.

Under the Four Corners CSA, PNM is required to fund its share of estimated final reclamation costs in annual installments into an irrevocable escrow account solely dedicated to the final reclamation cost of the surface mine at Four Corners. PNM contributed $0.2 million in 2023 and $2.4 million in 2022. PNM anticipates providing additional funding of $3.1 million in 2024, $1.3 million in 2025, and $1.5 million in 2026.

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 or the range of possible impacts.

SJGS Decommissioning

On November 9, 2021, the San Juan County Commission approved the Coal-Fired Electricity Generating Facility Demolition and Remediation Ordinance (“Ordinance 121”), requiring the full demolition of SJGS upon its complete and permanent closure. Ordinance 121 required the SJGS owners to submit a proposed demolition and remediation plan no later than three months after SJGS was retired. The SJGS owners submitted the decommissioning and remediation plan on December 28, 2022. In connection with restructuring of the SJGS ownership on December 31, 2017, PNM and the other SJGS owners entered into the San Juan Decommissioning and Trust Funds Agreement, which requires PNM to fund its ownership share of final decommissioning costs into an irrevocable trust. Under the agreement, PNM made an initial funding of $14.7 million in December 2022. The amount and timing of additional trust funding is subject to revised decommissioning cost studies and agreement among the SJGS owners. 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. For information regarding the impact of Ordinance 121 on PNM’s SJGS decommissioning ARO see Note 15 of the Notes to Consolidated Financial Statements in the 2023 Annual Reports on Form 10-K.

PNM records its share of the SJGS decommissioning obligation as an ARO on its Condensed Consolidated Balance Sheets. Studies on the decommissioning costs of SJGS are performed periodically and revisions to the ARO liability are recorded. In the third quarter of 2022, a new decommissioning cost study was completed, which required PNM to remeasure its

SJGS decommissioning ARO. The new study resulted in an estimated decrease to PNM’s share of the decommissioning obligation of $21.1 million, which was recorded in September 2022. Additional information concerning the Company’s SJGS decommissioning ARO is contained in Note 15 of the Notes to Consolidated Financial Statements in the 2023 Annual Reports on Form 10-K.

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 CPI. The most recent adjustment took effect on October 5, 2023. As of that date, in accordance with this act, the PVNGS participants are insured against public liability exposure for a nuclear incident up to $16.3 billion per occurrence. PVNGS maintains the maximum available nuclear liability insurance in the amount of $500 million, which is provided by American Nuclear Insurers. The remaining $15.8 billion is provided through a mandatory industry-wide retrospective assessment program. If losses at any nuclear power plant covered by the program exceed the accumulated funds, PNM could be assessed retrospective premium adjustments. After the expiration of the PVNGS Unit 1 and Unit 2 leases in January 2023 and January 2024, PNM’s maximum potential retrospective premium assessment per incident for all three units is $36.3 million, with a maximum annual payment limitation of $5.4 million, to be adjusted periodically for inflation.

The PVNGS participants maintain insurance for damage to, and decontamination of, property at PVNGS in the aggregate amount of $2.8 billion, a substantial portion of which must first be applied to stabilization and decontamination. These coverages are provided by Nuclear Electric Insurance Limited (“NEIL”). The primary policy offered by NEIL contains a sublimit of $2.25 billion for non-nuclear property damage. If NEIL’s losses in any policy year exceed accumulated funds, PNM is subject to retrospective premium adjustments of $4.9 million. The insurance coverages discussed in this and the previous paragraph are subject to certain policy conditions, sublimits, and exclusions.

(12)Regulatory and Rate Matters

The Company is involved in various regulatory matters, some of which contain contingencies that are subject to the same uncertainties as those described in Note 11. Additional information concerning regulatory and rate matters is contained in Note 17 of the Notes to Consolidated Financial Statements in the 2023 Annual Reports on Form 10-K.

PNM

New Mexico General Rate Case

2024 Rate Change

On December 5, 2022, PNM filed an application with the NMPRC for a general increase in retail electric rates including recovery on total rate base of $2.7 billion based on a calendar year 2024 FTY, an increase of $63.8 million in retail non-fuel revenues, and an ROE 10.25%. The application also proposed ratemaking treatment of PVNGS Leased Interest and testimony supporting the prudence of PNM’s decisions to renew thefive leases and repurchase 64.1 MW of PVNGS Unit 2 capacity.

On January 3, 2024, the NMPRC issued a final order authorizing PNM to implement an increase in non-fuel base rates of $15.3 million, effective for service beginning January 15, 2024. Major components of the difference compared to PNM’s application include:

•A ROE of 9.26%.

•A capital structure of 49.61% equity,50.10% debt, and 0.29% preferred stock.

•Finding of imprudence regarding PNM’s decision to remain in Four Corners and a remedy for the imprudence resulting in a disallowance of $81.0 million to PNM’s total Four Corners net book value.

•Approval of $51.3 million of PNM’s requested $96.3 million regulatory asset for PVNGS undepreciated investments, but disallowance of a return on the remaining $45.0 million or any CWIP associated with it.

•Requiring that the $38.4 million regulatory liability associated with leased capacity at PVNGS after the Unit 1 lease expired on January 15, 2023, be returned to ratepayers overtwo years through a separate rate rider.

•The approval of new depreciation rates, reflecting shorter useful lives, of PNM’s gas plants with service lives and depreciable lives extending beyond January 1, 2045, which would include PNM’s La Luz and Luna generating stations.

•The approval of PNM’s TOD pilot program, with a requirement to make annual compliance filings and to adjust certain rate schedules.

For additional details related to the initial application, see Note 17 of the Notes to Consolidated Financial Statements in the 2023 Annual Reports on Form 10-K.

In the year ended December 31, 2023, PNM evaluated the outcome of the NMPRC final order in the 2024 Rate Change and recorded a regulatory disallowance of $55.5 million on the Consolidated Statement of Earnings and a corresponding reduction to Utility Plant, after accounting for previous impairments, to reflect the remedy adopted in the Final Order for Four Corners. In addition, PNM recorded a reduction to electric operating revenues of $38.4 million with a corresponding current regulatory liability of $19.2 million and a deferred regulatory liability of $19.2 million for the PVNGS rate refunds that will be returned to customers over atwo-year period. PNM also recorded a regulatory disallowance of $8.2 million on the Consolidated Statement of Earnings and a corresponding reduction to Utility Plant for the disallowance of CWIP from PVNGS.

In March 2024, notice of appeals were separately filed with the NM Supreme Court by NEE and PNM, and a joint notice of appeal was filed by the NM Department of Justice, Bernalillo County, and ABCWUA. Statements of issues from appellants are due June 5, 2024.

2025 Rate Change

As previously indicated, PNM anticipates filing a general rate case during 2024 with rates requested to be implemented during 2025. On March 18, 2024, PNM filed a motion for variance with the NMPRC, requesting a 16-day variance which would allow for the filing of its next general rate case to be on or before June 14, 2024. The proposed rate case will include a FTY beginning on July 1, 2025 and a base period ending December 31, 2023. On April 18, 2024, the motion for variance was granted.

Renewable Energy Portfolio Standard

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

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

•158 MW of PNM-owned solar-PV facilities

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

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

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

•Solar distributed generation, aggregating 289.3 MW at March 31, 2024, owned by customers or third parties from whom PNM purchases any net excess output and RECs

The NMPRC has authorized PNM to recover certain renewable procurement costs through a rate rider billed on a per KWh basis. In its 2024 renewable energy procurement plan, which became effective on January 1, 2024, PNM proposed to collect $59.0 million for the year. PNM recorded revenues from the rider of $15.3 million and $18.6 million in the three months ended March 31, 2024 and 2023.

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 2023.

Energy Efficiency and Load Management

Program Costs and Incentives/Disincentives

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

On April 17, 2023, PNM filed an application for energy efficiency and load management programs to be offered in 2024, 2025, and 2026 (the “2024 Plan”). The 2024 Plan proposed to continueten existing energy efficiency programs with modification and a total annual budget of $34.5 million in 2024, $35.4 million in 2025, and $36.5 million in 2026. The application also sought approval of an annual base incentive of 7.1% of the portfolio budget and a sliding scale that provides additional incentive for additional energy saved as a percentage of program cost, up to the maximum allowed by the energy efficiency rule which for PNM is 8.82%. On January 26, 2024, the hearing examiners in the case issued a RD. The RD largely approved PNM’s 2024 Plan but with modifications that include the pursuit of demand response resources, additional analysis in future filings, adjustments to certain energy efficiency programs, and modification of the incentive sliding scale cap to reflect a new maximum. On March 7, 2024, the NMPRC approved the RD in its entirety.

2020 Decoupling Petition

As discussed above, the legislature amended the EUEA to, among other things, include a decoupling mechanism for disincentives. On May 28, 2020, PNM filed a petition for approval of a rate adjustment mechanism that would decouple the rates of its residential and small power rate classes. Decoupling is a rate design principle that severs the link between the recovery of fixed costs of the utility through volumetric charges. On July 13, 2020, NEE, ABCWUA, the City of Albuquerque, and Bernalillo County filed motions to dismiss the petition on the grounds that approving PNM’s proposed rate adjustment mechanism outside of a general rate case would result in retroactive ratemaking and piecemeal ratemaking. The motions to dismiss also alleged that PNM’s proposed rate adjustment mechanism is inconsistent with the EUEA. On October 2, 2020, PNM requested an order to vacate the public hearing, scheduled to begin October 13, 2020, and staying the proceeding until the NMPRC decides whether to entertain a petition to issue a declaratory order resolving the issues raised in the motions to dismiss. On October 7, 2020, the hearing examiner approved PNM’s request to stay the proceeding and vacate the public hearing and required PNM to file a petition for declaratory order by October 30, 2020. On October 30, 2020, PNM filed a petition for declaratory order asking the NMPRC to issue an order finding that full revenue decoupling is authorized by the EUEA. On November 4, 2020, ABCWUA and Bernalillo County jointly filed a competing petition asking the NMPRC to issue a declaratory order on the EUEA’s requirements related to disincentives. On March 17, 2021, the NMPRC issued an order granting the petitions for declaratory order, commencing a declaratory order proceeding to address the petitions and appointing a hearing examiner to preside over the declaratory order proceeding.

On January 14, 2022, the hearing examiner issued a RD recommending the NMPRC find that the EUEA does not mandate the NMPRC to authorize or approve a full decoupling mechanism, defining full decoupling as limited to energy efficiency and load management measures and programs. The RD also states that a utility may request approval of a rate adjustment mechanism to remove regulatory disincentives to energy efficiency and load management measures and programs through a stand-alone petition, as part of the utility’s triennial energy efficiency application or a general rate case and that PNM is not otherwise precluded from petitioning for a rate adjustment mechanism prior to its next general rate case. Finally, the RD stated that the EUEA does not permit the NMPRC to reduce a utility’s ROE based on approval of a disincentive removal mechanism founded on removing regulatory disincentives to energy efficiency and load management measures and programs. The RD does not specifically prohibit a downward adjustment to a utility’s capital structure, based on approval of a disincentive removal mechanism. On April 27, 2022, the NMPRC issued an order adopting the RD in its entirety. On May 24, 2022, PNM filed a notice of appeal with the NM Supreme Court. The NM Supreme Court held oral arguments on November 13, 2023. PNM cannot predict the outcome of this matter.

Integrated Resource Plans

NMPRC rules require that investor-owned utilities file an IRP every three years. The IRP is required to cover a 20-year planning period and contain an action plan covering the first three years of that period. On September 14, 2022, the NMPRC adopted revisions to the IRP Rule. The new rule revamps and modernizes the planning process to accommodate increased stakeholder involvement. The IRP Rule 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 request for proposals (“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. On October 14, 2022, PNM and other investor-owned utilities filed motions for rehearing with the NMPRC. On October 26, 2022, the NMPRC issued an order partially granting and partially denying certain aspects of PNM’s and the other investor-owned utilities’ motions for rehearing. On November 2, 2022, the NMPRC adopted an amended IRP Rule. On December 2, 2022, PNM filed an appeal with the NM Supreme Court. Two other investor-owned utilities also separately filed appeals at the NM Supreme Court. On January 3, 2023, PNM and the two other investor-owned utilities filed statements of issues with the NM Supreme Court. Among other things, the investor-owned utilities question whether the IRP Rule exceeds the NMPRC authority by imposing unauthorized requirements on utilities and extending NMPRC jurisdiction through over-broad interpretation of the statutes and state that the IRP Rule is contrary to law in its provisions for NMPRC regulation of a utility’s resource procurement decision-making. On June 5, 2023, PNM and the other two investor-owned utilities filed their Joint Brief in Chief and request for oral arguments at the NM Supreme Court. On November 22, 2023, the NM Supreme Court scheduled oral arguments for May 13, 2024. PNM cannot predict the outcome of this matter.

2023 IRP

On December 15, 2023, PNM filed its 2023 IRP with a continued focus on a carbon-free energy system by 2040. The plan highlights the need for the significant sustained addition of resources over the next two decades, replacing retiring or expiring capacity, meeting concurrent load growth, while reducing the carbon intensity of PNM’s portfolio. On April 4, 2024, the NMPRC accepted PNM’s 2023 IRP. On May 2, 2024, the NMPRC issued an order appointing an independent monitor who will report the results of PNM’s 2023 IRP.

Four Corners Abandonment Application

In 2020, PNM entered into the Four Corners Purchase and Sale Agreement with NTEC, pursuant to which PNM agreed to sell its 13% ownership interest (other than certain transmission assets) in Four Corners to NTEC, contingent upon NMPRC approval. In connection with the sale, PNM would make payments of $75.0 million to NTEC for relief from its obligations under the coal supply agreement for Four Corners after December 31, 2024. PNM made an initial payment to NTEC of $15.0 million in November 2020, subject to refund with interest upon termination of the Four Corners Purchase and Sale Agreement prior to closing. Under the terms of the Four Corners Purchase and Sale Agreement, upon receipt of the NMPRC approval, PNM was expected to make a final payment of $60.0 million.

On January 8, 2021, PNM filed the Four Corners Abandonment Application, which sought NMPRC approval to exit PNM’s share of Four Corners as of December 31, 2024, and issuance of approximately $300 million of Securitized Bonds as provided by the ETA. On December 15, 2021, the NMPRC issued a final order denying approval of the Four Corners Abandonment Application and the corresponding request for issuance of securitized financing. On December 22, 2021, PNM filed a Notice of Appeal with the NM Supreme Court of the NMPRC decision to deny the application and on July 6, 2023, the NM Supreme Court affirmed the NMPRC decision concluding that the NMPRC reasonably and lawfully denied PNM’s application for abandonment. On April 23, 2024, PNM filed an interim notice informing the NMPRC that PNM’s updated analysis indicates it is in the interest of customers for PNM to remain as a participant in Four Corners until the expiration of the current coal supply agreement in 2031. PNM continues to work with the other Four Corners owners to update the necessary project agreements to reflect this continued participation.

Summer Peak Resource Adequacy

Beginning in 2021 PNM began providing notices of delays, as received from developers, and status updates to the NMPRC for the approved SJGS replacement resource projects as well as delays in replacement resources for the PVNGS leased capacity that expired in January 2023 and January 2024. While PNM continues to experience new system peaks, PNM’s generation resources performed sufficiently with no challenges to resource adequacy during the 2023 summer peak season. While some of the replacement resources have come online, other replacement resources have experienced additional developer delays and PNM has entered into additional firm energy market purchases necessary to meet customer load during the 2024 summer season. See Note 7.

2026 Resource Application

On October 25, 2023, PNM filed an application with the NMPRC seeking approval of resources to be available for the 2026 summer peak. The application includes approval of a 100 MW solar PPA andthree battery storage agreements of 100 MW,100 MW, and 50 MW. In addition, PNM is seeking approval of a CCN for a 60 MW battery storage system to be owned by PNM. The resources are necessary for PNM to safely and reliably meet its projected system load. A hearing was held on March 20 and 21, 2024. PNM is unable to predict the outcome of this matter.

Grid Modernization Application

On October 3, 2022, in compliance with New Mexico Grid Modernization Statute, PNM filed its Grid Modernization Application with the NMPRC. The projects included in the Grid Modernization Application improve customers’ ability to customize their use of energy and ensure that customers, including low-income customers, are a top priority and will benefit consistent with the Grid Modernization Statute. PNM’s proposal to modernize its electricity grid through infrastructure and technology improvements also increases the efficiency, reliability, resilience, and security of PNM’s electric system. PNM’s application seeks approval of grid modernization investments of approximately $344 million for the firstsix years of a broader 11-year strategy. The proposed Grid Modernization Rider would recover capital costs, operating expenses, and taxes associated with the investments included in the Grid Modernization Application. PNM also requested authorization to create related regulatory assets and liabilities, permitting PNM to record costs incurred for the development and implementation of PNM’s plan between the requested approval of the application on July 1, 2023, and the implementation of the Grid Modernization Rider by September 1, 2023; undepreciated investments associated with legacy meters being replaced with AMI meters; and over- or under-collection of costs through the Grid Modernization Rider. In addition, PNM requested approval of the proposed format of an Opt-Out Consent Form and methodology to determine PNM’s proposed cost-based opt-out fees, which includes a one-time fee and a monthly fee. Following a hearing and subsequent briefs, on May 31, 2023, the NMPRC issued an order requiring the hearing examiner to direct PNM to file a cost benefit analysis as a supplement to the application. On November 22, 2023, PNM filed the required cost benefit analysis supporting PNM’s proposed Grid Modernization plan. A hearing began on April 23, 2024. PNM is unable to predict the outcome of this matter.

The Community Solar Act

In 2021, the Community Solar Act established a program that allows for the development of community solar facilities and provides customers of a qualifying utility with the option of subscribing to community solar facilities, and in exchange would receive a bill credit from their utility, while the utility received energy from the community solar facility. The NMPRC is charged with administering the Community Solar Act program, establishing a total maximum capacity of 200 MW community solar (applicable until November 2024) facilities and allocating proportionally to the New Mexico electric investor-owned utilities and participating cooperatives. On March 30, 2022, the NMPRC issued an order that adopted a rule on the administration of the Community Solar Act program. The rule required utilities to file proposed community solar tariffs with the NMPRC within 60 days from the publication of the rule. A number of motions for rehearing and requests for clarification were filed between April 7 and May 2, 2022. On May 18, 2022, the NMPRC issued an order partially granting motions for rehearing, reconsideration and clarification and staying implementation pending further rulemaking. On June 16, 2022, PNM requested clarification related to the existing interconnection queue, which would not delay implementation of the Community Solar Act program. On July 12, 2022, the NMPRC provided notice of publication of its final rule in the New Mexico Register, starting the 60-day clock for utilities to file their proposed community solar tariffs, forms, and other relevant agreements. On September 14, 2022, PNM filed Community Solar tariffs. On October 12, 2022, the NMPRC issued an order to suspend PNM’s and two other investor-owned utilities tariffs and required the utilities to file information NMPRC Staff has identified as necessary for a complete evaluation of the tariffs but did not appoint a hearing examiner or schedule a public hearing. Another investor-owned utility has filed an appeal with the NM Supreme Court seeking review of the NMPRC’s decisions, to which

PNM has intervened. The NM Supreme Court held oral arguments on March 11, 2024 and issued an order upholding the Community Solar Rule and affirming without further delay the implementation of the Community Solar Act program.

On November 16, 2022, PNM filed its Community Solar tariff which establishes the Community Solar bill credit to be applied to an eligible retail customer of PNM who is a subscriber to a community solar facility. On December 23, 2022, PNM filed an updated Community Solar tariff under protest and filed a motion for clarification, suspension, and timely hearing on PNM’s Community Solar tariff. On January 18, 2023, the NMPRC suspended PNM’s Community Solar tariff. On March 1, 2023, the NMPRC issued an Order Opening a New Docket for Two-Phase Proceedings. The first phase addressed issues concerning the proposed subscriber organization agreements and the proposed customer data forms. The second phase will address all issues concerning proposed tariffs, agreements and forms that are not addressed in the first phase. On May 31, 2023, the utilities filed a Consolidated Reply Brief to the NMPRC and the Joint Intervenors-Appellee filed Answer Briefs in the NM Supreme Court proceeding. On September 21, 2023, the NMPRC issued an order approving an uncontested stipulation on the first phase and on October 30, 2023, PNM’s advice notice conforming to the stipulation became effective. A hearing for the second phase was held from January 17 through January 19, 2024. PNM cannot predict the outcome of the pending matters.

Transportation and Electrification Program (TEP)

On June 1, 2023, PNM filed its 2024-2026 TEP with the NMPRC, requesting approval of a $37.1 million total three-year budget and continuation of the current TEP Rider. Approximately 22% of the budget, $8.0 million, will be dedicated to low-income customers. A hearing was held on December 13, 2023. On February 2, 2024, the hearing examiners in the case issued a RD largely approving PNM’s 2024 Plan but with modifications to certain TEP programs. On February 23, 2024, the NMPRC approved the RD with additional modifications that reduced the three-year budget by $4.0 million, for a total revised budget of $32.9 million.

TNMP

Transmission Cost of Service Rates

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

Periodic Distribution Rate Adjustment

PUCT rules permit interim rate adjustments to reflect changes in investments in distribution assets. Historically, distribution utilities have been restricted to a single, annual periodic rate adjustment through a DCRF submitted between April 1 and April 8 of each year as long as the electric utility was not earning more than its authorized rate of return using weather-normalized data. However, the recent passage of Senate Bill 1015 now permits DCRF proceedings to be filed twice per year with a 60-day administrative deadline that can be extended for 15 days on good cause. Additionally, a DCRF may be filed during a pending rate case proceeding as long as that DCRF request is not filed until the 185th day after the rate case proceeding was initiated. The following sets forth TNMP’s recent interim distribution rate increases:

On April 1, 2024, TNMP filed its 2024 DCRF that requested an increase in TNMP annual distribution revenue requirement of $15.9 million based on an increase in rate base of $207.4 million. The case is pending review by the PUCT.

Energy Efficiency

TNMP recovers the costs of its energy efficiency programs through an energy efficiency cost recovery factor (“EECRF”), which includes projected program costs, under and over collected costs from prior years, rate case expenses, and performance bonuses (if programs exceed mandated savings goals). TNMP’s 2022 EECRF filing requested recovery of $7.3 million, including a performance bonus of $1.9 million, and became effective March 1, 2023. On May 26, 2023, TNMP filed its request to adjust the EECRF to reflect changes in costs for 2024. On September 28, 2023, the PUCT approved a unanimous stipulation, authorizing recovery of $6.6 million, including a performance bonus of $1.2 million based on TNMP’s energy efficiency achievements in the 2022 plan year.

(13)Lease Commitments

The Company leases office buildings, vehicles, battery 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 2023 Annual Reports on Form 10-K.

PVNGS

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

On April 5, 2021, PNM and SRP entered into an Asset Purchase and Sale Agreement, pursuant to which PNM agreed to sell to SRP certain PNM-owned assets and nuclear fuel necessary to the ongoing operation and maintenance of leased capacity in PVNGS Unit 1 and Unit 2. In January 2023, the Unit 1 leases expired, and PNM closed on the associated sale to SRP, receiving payments of $33.7 million, of which $28.4 million was recorded as a reduction to Net utility plant on the Condensed Consolidated Balance Sheets and is presented as cash flows from investing activities on the Condensed Consolidated Statement of Cash Flows. In addition, $5.3 million was recorded as a reduction to materials, supplies, and fuel stock on the Condensed Consolidated Balance Sheets and is presented as cash flows from operating activities on the Condensed Consolidated Statement of Cash Flows. In January 2024, the Unit 2 leases expired, and PNM closed on the associated sale to SRP, receiving payments of $3.4 million, of which $2.8 million was recorded as a reduction to Net utility plant on the Condensed Consolidated Balance Sheets and is presented as cash flows from investing activities on the Condensed Consolidated Statement of Cash Flows. In addition, $0.6 million was recorded as a reduction to Materials, supplies and fuel stock on the Condensed Consolidated Balance Sheets and is presented as cash flows from operating activities on the Condensed Consolidated Statement of Cash Flows.

Land Easements and Rights-of-Ways

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 2023 payment for the amount due under the Navajo Nation right-of-way lease was $8.3 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 March 31, 2024 and December 31, 2023, the unamortized balance of these rights-of-ways was $71.3 million and $56.2 million. PNM recognized amortization expense associated with these agreements of $1.1 million and $0.9 million in the three months ended March 31, 2024 and 2023.

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 March 31, 2024, residual value guarantees on fleet vehicle and equipment leases are $0.8 million, $1.0 million, and $1.8 million for PNM, TNMP, and PNMR Consolidated.

Battery Storage Agreements

The Company has entered into various battery storage agreements for 20-year terms and have fixed payments over the life of the agreements. The Company accounts for these agreements as operating leases and records the initial lease liabilities with corresponding right-of-use assets. In addition, the Company has elected to separate lease components from non-lease components for battery storage agreements and accordingly, does not include non-lease components in the measurement of the lease liability or right-of-use asset. The non-lease components, currently not included in the measurement of the lease liability or the corresponding right-of-use asset, comprise of 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 as of March 31, 2024 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 three months ended March 31, 2024 and 2023.

Future expected lease payments are shown below:

The above table includes $11.9 million, $12.0 million, and $23.8 million for PNM, TNMP, and PNMR at March 31, 2024 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 March 31, 2024, the Company has various lease arrangements that have been executed but have not yet commenced, which are primarily related to battery storage agreements. The Company currently expects lease commencement dates in 2024, with lease terms expiring in 2045, and will recognize lease assets and liabilities upon lease commencement. The expected total fixed consideration to be paid for these arrangements, which includes non-lease payments, is approximately $1.1 billion over the 20-year terms of the agreements.

(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 and excess tax benefits or deficiencies related to stock awards. At March 31, 2024, PNMR, PNM, and TNMP estimated their effective income tax rates for the year ended December 31, 2024 would be 14.64%,13.09%, and 20.72%. 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 three months ended March 31, 2024, income tax expense calculated by applying the expected annual effective income tax rate to earnings before income taxes was further increased by excess tax benefits related to stock awards of $0.2 million for PNMR, of which $0.1 million was allocated to PNM and $0.1 million 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 “Tax Act”), 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 PNM 2024 Rate Change, the remaining balance of $62.7 million of unprotected excess deferred income taxes is being returned over afive-year period. The approved settlement in the TNMP 2018 Rate Case includes a reduction in customer rates to reflect the impacts of the Tax Act beginning on January 1, 2019. PNMR, PNM, and TNMP will amortize federal excess deferred income taxes of $23.3 million, $20.7 million, and $2.6 million in 2024. See additional discussion of the impacts of the Tax Act in Note 18 of the Notes to Consolidated Financial Statements in the 2023 Annual Reports on Form 10-K.

(15)Related Party Transactions

PNMR, PNM, TNMP, and NMRD are considered related parties, as is PNMR Services Company, a wholly-owned subsidiary of PNMR that provides corporate services to PNMR and its subsidiaries in accordance with shared services agreements. These services are billed at cost on a monthly basis to the business units. In addition, PNM purchases renewable energy from certain NMRD-owned facilities at a fixed price per MWh of energy produced. On February 27, 2024, PNMR Development and AEP Onsite Partners sold their respective interests in NMRD and the table below reflects transactions with NMRD prior to the sale. See Note 16 for additional discussion of NMRD. The table below summarizes the nature and amount of related party transactions of PNMR, PNM, TNMP, and NMRD:

(16)Equity Method Investment

As discussed in Note 21 of the Company’s 2023 Annual Reports on Form 10-K, PNMR Development and AEP OnSite Partners created NMRD in September 2017 to pursue the acquisition, development, and ownership of renewable energy generation projects, primarily in the state of New Mexico. On February 27, 2024, PNMR Development and AEP Onsite Partners sold their respective interests in NMRD. PNMR Development received net proceeds of $117.0 million and recognized an after-tax gain of $4.4 million, which includes the recognition of deferred investment tax credits of $15.7 million.

In the three months ended March 31, 2024 and 2023, PNMR Development and AEP OnSite Partners each made cash contributions to NMRD of $12.6 million and $11.5 million for its construction activities.

Until the sale closing on February 27, 2024, PNMR presented its share of net earnings from NMRD in Other income on the Condensed Consolidated Statements of Earnings. Summarized financial information for NMRD through the closing date of the sale is as follows: