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

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

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

On July 27, 2026, TXNM filed its compliance filing with the NMPRC detailing the unwinding of the May 2025 Stock Purchase Agreement by cancelling the 8,000,000 shares of TXNM common stock sold as of July 2, 2026, drawing on the $400.0 million TXNM 2026 Delayed-Draw Term Loan, and repaying (on September 4, 2026) the aggregate $400.0 million received in the May 2025 Stock Purchase Agreement (Note 9). On August 10, 2026, TXNM filed a notice of amended compliance report reflecting that all $13.3 million in dividends previously paid in relation to the 8,000,000 shares of TXNM

common stock sold under the May 2025 Stock Purchase Agreement had been returned. TXNM expressed intent to issue shares of TXNM common stock to repay the $400.0 million TXNM 2026 Delayed-Draw Term Loan through either publicly registered offerings or private placement transactions. On July 31, 2026, TXNM filed a petition with the NMPRC for a declaratory order that the proposed equity transactions do not require prior NMPRC approval and requested that the NMPRC expedite approval of the petition. On August 27, 2026, the NMPRC granted TXNM’s petition for a declaratory order concluding that TXNM does not require prior authorization from the NMPRC to issue shares of TXNM common stock to repay the $400.0 million TXNM 2026 Delayed-Draw Term Loan, subject to certain restrictions. See Note 9. On September 28, and October 28, 2026, PNM filed documents with the NMPRC demonstrating compliance with the declaratory order granted on August 27, 2026.

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

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

In June 2024, PNM filed an application with the NMPRC for a general increase in retail electric rates. The proposed base rate changes would be implemented in two phases, with the first phase effective July 1, 2025 and the second phase effective January 1, 2026. In November 2024, PNM filed an unopposed comprehensive stipulation with the NMPRC that was approved on May 15, 2025, with the base rate changes becoming effective July 1, 2025 and April 1, 2026. Key components agreed upon by the signatories may be found in Note 17 of the Notes to Consolidated Financial Statements in the 2025 Annual Reports on Form 10-K. This matter is now concluded.

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

Under the renewable rider, if PNM’s earned rate of return on jurisdictional equity in a calendar year, adjusted for items not representative of normal operations, exceeds the NMPRC-approved rate by 0.5%, PNM is required to refund the excess to customers during May through December of the following year. PNM did not exceed such limitation in 2025. On May 28, 2026, PNM filed its application, requesting to collect $53.0 million for 2027 costs beginning on January 1, 2027. On September 14, 2026, the hearing examiner issued a RD recommending approval of PNM’s application.

On April 15, 2026, PNM filed its application with the NMPRC for energy efficiency and load management programs to be offered in 2027, 2028, and 2029 (the “2027 Plan”) in compliance with the EUEA. The 2027 Plan proposed to continue ten existing energy efficiency programs with modifications and total annual budgets of $45.6 million in 2027, $47.6 million in 2028, and $48.8 million in 2029. The application also sought approval of an annual base incentive of 7.1% of the portfolio budget and a sliding scale that provides additional incentive for additional energy saved as a percentage of program cost, up to the maximum allowed by the energy efficiency rule which for PNM is 10.54%. On October 14, 2026, the hearing examiner issued a RD recommending approval of the 2027 Plan as filed however, the RD also recommends that PNM be required, in its next energy efficiency and load management filing, to provide more granular information concerning its demand response programs. PNM cannot predict the outcome of this matter.

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

On December 30, 2024, PNM issued its 2029-2032 RFP for at least 900 MW of new energy resources to come online between 2029 and 2032, with at least 500 MW needed by 2030. The RFP is consistent with the needs identified in PNM’s 2023 IRP, which identified a range of 900 to 2,900 MW of new capacity needed by 2032, depending on the type of resources selected. The 2029-2032 RFP is anticipated to identify potential replacement resources for PNM’s current natural gas generation capacity as well as PNM’s ownership interest in Four Corners. On January 2, 2026, PNM filed a Notice of Material Event for the 2023 IRP to inform the NMPRC of its intent to issue a supplemental RFP for gas-fired resources in response to new customer requirements that have accelerated and increased energy demands beyond previously forecasted resources. On February 4, 2026, the IM appointed to the 2029-2032 RFP concluded that PNM appropriately evaluated the bids, made

reasonable portfolio selection decisions, and overall, the RFP process was conducted in a fair, transparent manner that was in compliance with regulatory requirements. On March 6, 2026, PNM filed its draft supplemental RFP for the additional resources anticipated. On April 4, 2026, the IM issued a design report on PNM’s draft supplemental RFP which contained targeted modifications to improve transparency, expand participation, and strengthen competitive neutrality within the class of eligible firm resources. PNM filed responses to the IM design report and issued a supplemental RFP on May 1, 2026.

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

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

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

In October 2022, in compliance with New Mexico Grid Modernization Statute, PNM filed its Grid Modernization Plan with the NMPRC. The projects included in the application improve customers’ ability to customize their use of energy and ensure that customers, including low-income customers, are a top priority and will receive benefits consistent with the Grid Modernization Statute. PNM’s proposal to modernize its electricity grid through infrastructure and technology improvements also increases the efficiency, reliability, resilience, and security of PNM’s electric system. PNM’s application included grid modernization investments of approximately $344 million for the 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 Grid Modernization Plan. On October 17, 2024, the NMPRC issued a final order largely approving PNM’s application with minor modifications.

On June 20, 2025, PNM filed its first annual Grid Modernization Plan review to provide updates on year one implementation progress and outline planned activities for year two, in alignment with regulatory expectations. Additionally, PNM has updated key portions of the forecasted strategy including increasing investments from approximately $344 million to $367 million in the first six years, while decreasing projected operations and maintenance costs by approximately 18%. On February 26, 2026, the NMPRC approved PNM’s first annual Grid Modernization Review and the updated year two revenue requirement. This matter is now concluded.

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

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

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

On June 1, 2026, PNM filed its 2027-2029 TEP with the NMPRC, requesting approval of a $32.9 million total three-year budget and continuation of the current TEP Rider. Approximately 40% of the budget, $13.2 million, will be dedicated to low-income customers and underserved communities. On September 25, 2026, NMPRC staff recommended approval of PNM’s requested 2027-2029 TEP with a slight modification reducing the total budget to $30.0 million. PNM cannot predict the outcome of this matter.

On August 6, 2025, PNM filed an application with the NMPRC for approval of a CCN to construct, own, and operate 30 MWs of energy storage. The application consists of 6 MW batteries to be constructed at five existing PNM-owned solar facilities located in Otero County, San Miguel County, Luna County and two sites in Valencia County. PNM estimates that the BESS Project will cost $78.7 million and will assist in serving our summer peak season when operational. PNM expects to seek recovery of these costs in a future rate case. On March 10, 2026, the hearing examiner issued an RD recommending approval of the CCN that was approved in a final order issued by the NMPRC on April 10, 2026. This matter is now concluded.

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

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

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

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

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

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

On March 12, 2025, TNMP filed a refund claim with the Texas Comptroller’s office for overpaid sales and use taxes primarily related to asset purchases. The $34.6 million refund claim covers periods from January 2022 to October 2024, and amounts received, net of consultant fees, are expected to be applied to 2025 TNMP capital projects. On September 22, 2025, TNMP received the requested refund net of $7.5 million in consultant fees; $24.7 million was applied to 2025 TNMP capital projects; $2.1 million to offset related interest expense; and $0.3 million for other related expenses. On October 15, 2025, TNMP filed another refund claim for $5.1 million for overpaid sales and use taxes primarily related to asset purchases covering the period from November 2024 through February 2025. On June 25, 2026, the Texas Comptroller’s Office issued an adjustment report indicating that the refund claim had been approved and interest would be accruing at a daily rate until paid. TNMP received the requested refund net of $1.1 million in consultant fees and applied $3.8 million to capital projects with the remaining $0.2 million to offset related interest expense.

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

PUCT rules permit interim rate adjustments twice per year to reflect changes in investments in distribution. Additionally, a DCRF may be filed during a pending rate case proceeding as long as that DCRF request is not filed until the 185th day after the rate case proceeding was initiated. DCRF updates are expected to be filled annually in a single UTM filing going forward. The following sets forth TNMP’s recently approved interim distribution rate increases:

In June 2025, Texas House Bill 5247 (“HB 5247”) was signed into law. HB 5247, which took effect immediately, added Section 36.216 to the Public Regulatory Act (“PURA 36.216”), authorizing certain electric utilities with total capital expenditures that exceeded 300 percent of annual depreciation in a calendar year, to elect, in the following calendar year, to file a single, annual proceeding to adjust nonfuel rates on a system-wide basis to reflect changes in transmission and distribution rates previously authorized under certain other interim rate mechanisms such as DCRF and TCOS. Management has evaluated the application of HB 5247 and PURA 36.216 and determined that TNMP qualifies as the type of electric utility that would be eligible for the election. Upon completion of its general rate proceeding (the TNMP Base Rate Review) discussed above, TNMP made its first comprehensive filing (UTM filing) under Section 36.216 with a view towards recovering costs associated with eligible transmission and distribution investments that were placed into service after December 31, 2024, and that are not currently reflected in rates. TNMP’s requested DCRF and TCOS revenue requirement increases in the current UTM filing include $20.5 million and $13.9 million of regulatory assets through June 30, 2026. Eligible costs for capital investments expected to be included in the next annual UTM will continue to be recorded as a regulatory asset, offset in alternative revenue.

TNMP recovers the costs of its energy efficiency programs through an energy efficiency cost recovery factor (“EECRF”), which includes projected program costs, under and over collected costs from prior years, rate case expenses, and performance bonuses (if programs exceed mandated savings goals). On May 30, 2025, TNMP filed its request to adjust the EECRF to reflect changes in costs for 2026. On November 14, 2025, the total amount requested of $8.1 million, which includes a performance bonus of $2.5 million, based on TNMP’s energy efficiency achievements in 2024, was approved and took effect March 1, 2026. On May 29, 2026, TNMP filed its request to adjust the EECRF to reflect changes in costs for 2027. The total amount requested was $9.5 million, which includes a performance bonus of $1.2 million based on TNMP’s energy efficiency achievements in 2025. The case is pending review by the PUCT.

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,

On December 11, 2024, TNMP filed an unopposed settlement with the PUCT. The settlement includes $565.8 million of capital investments over 2025 through 2027, reflecting 94% of TNMP’s proposed plan investments. The settlement also encompasses $128.2 million of operations and maintenance expenses associated with several programs, including vegetation management and wildfire mitigation. On March 26, 2025, TNMP received the final order from the PUCT which included modifications reflecting capital investments of $545.8 million and $86.1 million of operating and maintenance costs. TNMP’s requested DCRF revenue requirement increase in the current UTM filing includes $28.7 million of SRP deferred operating and maintenance costs incurred through June 30, 2026.