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Regulatory and Rate Matters

6 Months Ended

Jun. 30, 2025

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

PNM

New Mexico General Rate Case

2025 Rate Request

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

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

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

•Drivers of revenue deficiency:

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

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

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

◦ROE of 10.45%

◦Proposed capital structure of 52.5% equity

◦An increased cost of borrowing

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

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

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

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

•ROE of 9.45%

•Capital structure of 51.0% equity

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

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

•Costs associated with ESAs shall be recovered through base rates

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

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

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

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

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

2024 Rate Change

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

In March 2024, notice of appeals were separately filed with the NM Supreme Court by NEE and PNM, and a joint notice of appeal was filed by the NM Department of Justice, Bernalillo County, and Albuquerque Bernalillo County Water Utility Authority (“ABCWUA”). NEE’s appeal was subsequently consolidated with the joint notice of appeal. In the statements of issues submitted in the parties’ appellate dockets, PNM took issue with the NMPRC’s ruling on capital structure; other appellants primarily challenged the NMPRC rulings related to Four Corners and Palo Verde cost recovery. On June 20, 2025, PNM filed an uncontested motion to dismiss its appeal. PNM cannot predict the outcome of this matter.

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 320.5 MW at June 30, 2025, owned by customers or third parties from whom PNM purchases any net excess output and RECs

The NMPRC has authorized PNM to recover certain renewable procurement costs through a rate rider billed on a per KWh basis. In its 2025 renewable energy procurement plan, which became effective on January 1, 2025, PNM proposed to collect $58.7 million for the year. PNM recorded revenues from the rider of $14.6 million and $31.6 million in the three and six months ended June 30, 2025 and $15.3 million and $30.6 million in the three and six months ended June 30, 2024.

Under the renewable rider, if PNM’s earned rate of return on jurisdictional equity in a calendar year, adjusted for items not representative of normal operations, exceeds the NMPRC-approved rate by 0.5%, PNM is required to refund the excess to customers during May through December of the following year. PNM did not exceed such limitation in 2024. On May 30, 2025, PNM filed its application for its 2026 renewable energy procurement plan, requesting to collect $54.3 million for the year.

Energy Efficiency and Load Management

Program Costs and Incentives/Disincentives

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

In 2023, PNM filed an application for energy efficiency and load management programs to be offered in 2024, 2025, and 2026 (the “2024 Plan”). The 2024 Plan proposed to continue ten 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.

Integrated Resource Plans

NMPRC rules require that investor-owned utilities file an IRP every three years and is required to cover a 20-year planning period and contain an action plan covering the first three years of that period. The IRP establishes a collaborative facilitated process for a utility and stakeholders to agree on a statement of need for potential new or additional resources, as well as an action plan to guide procurement or development of resources to meet the stated need. A most-cost-effective portfolio of resources shall be derived from the statement of need analysis. The statement of need and action plan must be accepted before the utility begins the resource solicitation process pursuant to the IRP Rule. Following acceptance of the statement of need and action plan, a utility will provide the NMPRC and intervenors drafts of the RFP and a timeline for issuing, receiving, evaluating, and ranking bids. The NMPRC will then appoint an Independent Monitor (“IM”) to oversee the RFP process, which allows for parties and the IM to comment on the RFP consistency with the IRP, after which the utility issues the RFP. Within 120 days of receiving bids the utility shall provide the IM with results including pricing and non-price

evaluation criteria, ranking of bids, chosen portfolio and alternatives that also meet the needs; the IM then rules on the fairness of the RFP execution. Acceptance of the statement of need and action plan will not constitute a finding of prudency or pre-approval of costs associated with the additional resources. Following the RFP and IM processes, the utility may apply for approvals, and any costs incurred to implement the action plan will be considered in a general rate case and/or resource acquisition proceeding.

2023 IRP

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

On December 30, 2024, PNM issued its 2029-2032 RFP for at least 900 MW of new energy resources to come online between 2029 and 2032, with at least 500 MW needed by 2030. The RFP is consistent with the needs identified in PNM’s 2023 IRP, which identified a range of 900 to 2,900 MW of new capacity needed by 2032, depending on the type of resources selected. The 2029-2032 RFP is anticipated to identify potential replacement resources for PNM’s current natural gas generation capacity as well as PNM’s ownership interest in Four Corners.

2028 Resource Application

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

•Two 150 MW ESAs

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

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

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

Grid Modernization Plan

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

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

Transportation and Electrification Program (TEP)

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

Meta Platforms Inc. Data Center - Phase IV

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

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

•three 20-year solar PPAs totaling 290 MW

•three 20-year ESAs totaling 268 MW of storage

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

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

On July 3, 2025 a procedural order was issued, with a hearing scheduled for October 27, 2025. PNM is unable to predict the outcome of this matter.

TNMP

On June 20, 2025, Texas House Bill 5247 (“HB 5247”) was signed into law by Governor Gregg Abbott. HB 5247, which took effect immediately, added Section 36.216 to the Public Regulatory Act (“PURA 36.216”), authorizing certain electric utilities with total capital expenditures that exceeded 300 percent of annual depreciation in a calendar year, to elect, in the following calendar year, to file a single, annual proceeding to adjust nonfuel rates on a system-wide basis to reflect changes in transmission and distribution rates previously authorized under certain other interim rate mechanisms. A utility seeking to make this election under PURA 36.216 is required to file a notice with the PUCT informing them of its intent and provide supporting documentation of the applicable capital expenditures at least 60 days before filing the single, annual proceeding and correspondingly must notify the PUCT if the utility determines that it no longer qualifies for continued use of the election. Management has evaluated the application of HB 5247 and PURA 36.216 and determined that TNMP qualifies as the type of electric utility that would be eligible for the election. Currently, TNMP expects to make its first comprehensive filing under Section 36.216 in 2026 with a view towards recovering costs associated with eligible transmission and distribution investments that were placed into service after December 31, 2024 and that are not currently reflected in rates. In the interim, TNMP plans to immediately begin to recognize a regulatory asset for depreciation associated with eligible capital investments placed into service after December 31, 2024. At June 30, 2025 the regulatory asset associated with these costs totals $0.6 million.

Sales and Use Tax Refund

On March 12, 2025, TNMP filed a refund claim with the Texas Comptroller’s office for overpaid sales and use taxes primarily related to asset purchases. The $33.6 million refund request covers periods from January 2022 to October 2024. Although the Company is unable to predict the outcome of the refund claim, the bulk of any refund amounts received, net of consultant fees, are expected to be applied to 2025 TNMP capital projects.

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:


Effective Date	Approved Increase in Rate Base		Annual Increase in Revenue
	(In millions)


















September 6, 2023	$	21.4	$	4.2
March 15, 2024	97.4		13.1
September 20, 2024	20.6		3.9
March 25, 2025	83.5		11.5

On July 24. 2025, TNMP filed an application to further update its transmission rates to reflect an increase in total rate base of $87.4 million, which would increase revenues by $12.3 million annually. The application is pending before the PUCT.

Periodic Distribution Rate Adjustment

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


Effective Date	Approved Increase in Rate Base		Annual Increase in Revenue
	(In millions)
















September 1, 2023	$	157.0	$	14.5
July 28, 2024	205.9		15.6
November 17, 2024	43.7		7.7
June 29, 2025	176.6		25.0

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

Energy Efficiency

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

Hurricane Beryl

On July 8, 2024, Hurricane Beryl made landfall in the Texas Gulf Coast leaving approximately 116,000 customers in the TNMP service area without power. As of June 30, 2025, TNMP incurred $53.8 million of costs, of which $33.4 million has been recorded in Utility Plant and $20.4 million has been recorded as a Regulatory Asset on the Condensed Consolidated Balance Sheets. TNMP will seek collection of such costs in a future regulatory proceeding.

System Resiliency Plan (“SRP”)

In 2023, the Texas Legislature enacted House Bill No, 2555 (“HB 2555”), permitting an electric utility to seek approval of, and cost recovery for, a system resiliency plan. On August 28, 2024, TNMP filed its first SRP with the PUCT designed to benefit customers through enhanced resiliency of its distribution system, as intended under HB 2555. The SRP includes approximately $600 million of capital investments and approximately $151 million of other related costs over three

years and was developed using a comprehensive and data-driven approach which evaluated various types of resiliency events posing material risk to the safe and reliable operation of TNMP's distribution system. TNMP's service territory includes non-contiguous areas across different regions of Texas, ranging from small communities and rural areas to communities around large metropolitan areas, each with unique risks. Investments in the SRP are prioritized based on customer benefit, physical protection of infrastructure, foundational investments in operational and cybersecurity technologies, and wildfire risk reduction and are focused on lower-performing areas in the context of reliability. Eight different resiliency measures are outlined in the SRP with associated programs and infrastructure impacts to improve the system's ability to prevent, withstand, mitigate and/or more promptly recover from resiliency events: distribution system resiliency, distribution system protection modernization, vegetation management, wildfire mitigation, flood mitigation, enhanced operations system technology, cybersecurity, and physical security resiliency. Recovery of investments and costs are permissible primarily through semi-annual DCRF filings, with deferral of depreciation and other certain expenses until recovery begins.

On December 11, 2024, TNMP filed an unopposed settlement with the PUCT. The settlement includes $565.8 million of capital investments over 2025 through 2027, reflecting 94% of TNMP’s proposed plan investments. The settlement also encompasses $128.2 million of operations and maintenance expenses associated with several programs, including vegetation management and wildfire mitigation. On March 26, 2025, TNMP received the final order from the PUCT which included modifications reflecting capital investments of $545.8 million and $86.1 million of operating and maintenance costs.