UNITIL CORP

Current report

v)

Current report

Maine Natural Gas Corporation (Maine Natural), which provides gas service in southern and central Maine, including the greater Portland region, as well as the capital city of Augusta.

Current report

Electric GAAP Gross Margin was $21.3 million in the three months ended March 31, 2026, an increase of $1.7 million compared to the same period in 2025. The increase was driven by higher rates of $2.8 million, partially offset by higher depreciation and amortization expense of $0.4 million and a one-time reduction of FERC transmission revenue of $0.7 million (see Note 7 Regulatory Matters: FERC Transmission Formula Rate Proceedings).

Current report

Electric Adjusted Gross Margin (a non-GAAP financial measure) was $29.6 million in the first quarter of 2026, an increase of $2.1 million compared to the same period in 2025. The increase reflects higher rates of $2.8 million partially offset by a one-time reduction of FERC transmission revenue of $0.7 million (see Note 7 Regulatory Matters: FERC Transmission Formula Rate Proceedings).

Current report

Depreciation and Amortization expense increased $1.6 million in the three months ended March 31, 2026, compared to the same period in 2025. The increase reflects higher levels of utility plant in service, partially offset by lower amortization of other deferred costs. Included in Depreciation and Amortization for the three months ended March 31, 2026 was $0.7 million related to Maine Natural.

Current report

Provision for Income Taxes increased $2.4 million in the three months ended March 31, 2026, compared with the same period in 2025, reflecting higher pre-tax earnings in 2026.

Current report

Electric Adjusted Gross Margin (a non-GAAP financial measure) was $29.6 million for the three months ended March 31, 2026, an increase of $2.1 million, compared with the same period in 2025. The increase reflects higher rates of $2.8 million partially offset by a one-time reduction of FERC transmission revenue of $0.7 million (see Note 7 Regulatory Matters: FERC Transmission Formula Rate Proceedings).

Current report

The Company transported 62.9 million therms in the first three months of 2026 to two electric generation facilities in Maine. As these facilities were charged fixed fees and utilized third-party energy suppliers for natural gas, the therms were not included in the above table.

Current report

Depreciation and Amortization - Depreciation and Amortization expense increased $1.6 million, or 7.4%, in the three months ended March 31, 2026, compared to the same period in 2025. The increase reflects higher levels of utility plant in service, partially offset by lower amortization of other deferred costs. Included in Depreciation and Amortization for the three months ended March 31, 2026 was $0.7 million related to Maine Natural.

Current report

On April 30, 2026, Fitchburg issued $23.0 million of Notes due 2036 at 5.62% and $17.0 million of Notes due 2041 at 5.87%. Fitchburg used the net proceeds to refinance existing debt and for general corporate purposes. Approximately $0.2 million of costs associated with this issuance will be recorded as a reduction of Long-Term Debt on the Consolidated Balance Sheet in the second quarter of 2026.

Current report

The Company has contracts that meet the definition of derivatives (see Note 6 Derivatives). Derivatives are recognized on the balance sheet at fair value as either assets or liabilities. The Company considers the amount of the derivative expected to be settled within the next twelve months as current and the remainder as long-term. Derivative instruments are presented on a gross basis in the consolidated balance sheets. Cash flows related to derivative settlements are classified as operating activities in the consolidated statements of cash flows. Regulatory assets or liabilities are recorded to offset the fair value of derivatives, as contract settlement amounts are tracked and reconciled as a pass-through to customers. Costs associated with the Purchase Power Agreement (PPA) are approved by the MDPU to be passed through to customers through the Company’s Long-Term Renewable Contract Adjustment Clause tariff and accounted for per FASB Accounting Standard Codification 980, Regulated Operations. Unrealized gains or losses resulting from the change in fair value are not recognized in the income statement. Instead, they are deferred and recorded as a regulatory asset for losses or a regulatory liability for gains.

Current report

The Company recognizes an environmental attribute asset at the allocated contract cost upon receipt of the associated certificates in the applicable registry and derecognizes the asset upon retirement, at which time the related cost is recognized in Cost of Electric Sales, which are tracked and reconciled costs as pass-through to customers. Please see Note 6 (Derivatives) for additional information.

Current report

Recently Issued Pronouncements- In November 2024, the FASB issued ASU 2024-03, Income Statement - Reporting Comprehensive Income - Expense Disaggregation Disclosures, and in January 2025, the FASB issued ASU 2025-01, Income Statement - Reporting Comprehensive Income - Expense Disaggregation Disclosures: Clarifying the Effective Date. ASU 2024-03 requires public entities to disclose, in the notes to financial statements, certain costs and expenses, such as purchases of inventory, employee compensation, and costs related to depreciation and amortization. ASU 2024-03, as clarified by ASU 2025-01, is effective for the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 2027, and subsequent interim periods, with early adoption permitted. The Company is currently evaluating the impact of these standards on its Consolidated Financial Statement disclosures.

Current report

In connection with this acquisition, the Company recorded $82.1 million of net utility plant, $8.4 million working capital, $2.7 million goodwill, $1.4 million noncurrent assets and $3.5 million noncurrent regulatory liabilities.

Current report

On April 30, 2026, Fitchburg issued $23.0 million of Notes due 2036 at 5.62% and $17.0 million of Notes due 2041 at 5.87%. Fitchburg used the net proceeds to refinance existing debt and for general corporate purposes. Approximately $0.2 million of costs associated with this issuance will be recorded as a reduction of Long-Term Debt on the Consolidated Balance Sheet in the second quarter of 2026.

Current report

The Performance Restricted Shares issued in January 2023 were fully vested as of December 31, 2025. During the first quarter, an additional 820 shares were awarded due to exceeding certain goals and 931 shares were forfeited due to retirements. The compensation expense associated with the additional shares was less than $0.1 million for the three months ended March 31, 2026.

Current report

NOTE 6: DERIVATIVES

Current report

In 2018, Fitchburg entered into a long-term power purchase agreement (PPA) with H.Q. Energy Services (U.S.) Inc. (HQUS) to procure bundled clean energy and associated environmental attributes pursuant to Section 83D of “An Act to Promote Energy Diversity” (2016). The PPA requires Fitchburg to purchase specified quantities of electric energy over the 20-year contract term and provides for the transfer of associated environmental attributes. (See Note 7 Regulatory Matters: Fitchburg - Massachusetts Request for Proposals.)

Current report

During 2025, based on the status of the NECEC Transmission Line and the Company’s assessment that the contingency related to the commencement of deliveries was substantially resolved as of December 31, 2025, the Company concluded that the PPA met the definition of a derivative. The Company evaluated the PPA under ASC 815 and concluded that (i) the host contract includes environmental attributes that do not meet the definition of a derivative and (ii) the PPA contains an embedded derivative related to the energy component that requires bifurcation.

Current report

The Company has not designated the derivative as a hedging instrument. Additionally, the derivative does not qualify for the normal purchase normal sale scope exception. Accordingly, the Company accounts for the embedded energy derivative at fair value, with subsequent changes in fair value recognized as a regulatory offset. Please see Note 1 (Summary of Significant Accounting Policies - Derivatives) for a discussion of the Company’s regulatory accounting treatment of derivatives.

Current report

The PPA provides a bundled price for energy and environmental attributes. In connection with bifurcation and fair value measurement of the embedded energy derivative, the Company applied an allocation approach to separate the embedded energy derivative from the non-derivative environmental attribute component. The fair value of the embedded energy derivative is estimated using a discounted cash flow model that compares forward market prices to the adjusted fixed price for the energy component of the PPA, multiplied by expected delivery volumes, and discounted using a rate that reflects the relevant counterparty’s credit risk. Observable inputs include on-peak and off-peak forward electricity prices and the Company incorporates an adjustment to estimate the pricing through the term of the PPA. The Company has classified the embedded derivative within Level 3 of the fair value hierarchy due to the use of significant unobservable inputs in estimating the value of the embedded derivative. Please also see Note 1 (Summary of Significant Accounting Policies) for a discussion of the Company’s fair value accounting policy.

Current report

The fair value of the derivative was $20.2 million and $17.7 million as of March 31, 2026 and December 31, 2025, respectively, with $3.9 million and $2.8 million recorded in Prepayments and Other related to the current portion and $16.3 million and $14.9 million in Other Assets related to the noncurrent portion. The Company has recorded corresponding Current and Noncurrent Regulatory Liabilities related to the fair value of the derivative. No derivative assets or liabilities were recognized as of March 31, 2025. The Company does not offset derivative assets and liabilities in the balance sheet.

Current report

The Company entered into a long-term energy procurement arrangement primarily to comply with regulatory clean energy requirements. The Company does not enter into such arrangements for trading or speculative purposes.

Current report

The Company is exposed to credit risk related to possible nonperformance by its counterparty. The Company manages this risk through ongoing credit monitoring and, as applicable, the use of collateral or other credit enhancements.

Current report

Northern Utilities - Base Rates - Maine- On April 1, 2026, Northern Utilities’ Maine Division filed a Notice of Intent to File a General Rate Case with the MPUC. The Company plans to file its case on or about June 1, 2026. The filing is expected to request an increase in annual base revenues of approximately $7.5 million, or about 6.5% of the Company’s 2025 total operating revenues, including its cost of gas supply. The Company expects to request an overall rate of return on rate base of approximately 7.9%, including an approximate return on equity component of 10.6%.

Current report

Unitil Energy - Base Rates- On April 27, 2026, the NHPUC issued a procedural Order in the distribution base rate case filed with the NHPUC on May 1, 2025 by Unitil Energy. The Order approves the settlement agreement filed on February 24, 2026 between the Company, the NH DOE and the Community Power Coalition of New Hampshire in its entirety.

Current report

In addition to authorizing an increase to permanent distribution rates of approximately $13.0 million effective May 1, 2026, the settlement agreement included: (1) a proposed multi-year rate plan, including two annual Step Adjustments to rates on September 1, 2026 and September 1, 2027, to recover total prudent investments completed and placed into service in 2025 and 2026 respectively, subject to a cap 2.50 percent of the Company’s prior year total revenue; (2) a continuation of its revenue decoupling mechanism; (3) an update to the previously approved suite of proposed time of use rates including rates for electric vehicles; (4) resiliency programs to further the Company’s commitment to reliability; (5) an Arrearage Management Program for financial hardship customers; and (6) other rate design and tariff changes. This distribution base rate case reflects the Company’s operating costs and investments in utility plant for a test year ended December 31, 2024 as adjusted for known and measurable changes. The Order provides for an overall cost of capital of 9.32% including a 9.45% return on equity. The increase in permanent rates will be reconciled back to July 1, 2025, the effective date of temporary rates previously approved in this docket, which will begin to be recovered effective August 1, 2026. Unitil Energy will record a net increase to pretax income of $1.7 million in the second quarter of 2026 reflecting the difference between the temporary and permanent rates.

Current report

Massachusetts Inquiry into Gas and Electric Delivery Charge and Bill Redesign - On December 15, 2025, the MDPU opened an investigation to conduct a comprehensive review of gas and electric delivery rates and charges with the aims of containing customer costs, reducing utility bill volatility, and increasing utility bill transparency and accessibility. As directed, on February 13, 2026, each Distribution Company submitted a report including certain requested information regarding delivery related reconciling mechanisms and costs. Written comments from the Distribution Companies and other interested stakeholders responding to a list of questions regarding delivery related reconciling charges were filed on April 14, 2026. Public comments were filed on April 30, 2026. Reply comments are due on May 14, 2026.

Current report

Massachusetts Solar Massachusetts Renewable Target Program (SMART) 3.0 - On November 21, 2025, the EDCs jointly filed a new tariff (the SMART 3.0 Tariff) with the MDPU to implement the SMART 3.0 Program regulations 225 C.M.R. 28.00, which were filed with the Secretary of State on September 12, 2025 (SMART Regulations). The SMART Program, which was first implemented in 2017, establishes a voluntary statewide solar incentive program under the direction of the Massachusetts Department of Energy Resources (DOER). In 2020, the DOER revised its SMART Program regulations, 225 C.M.R. 20.00 -- an update commonly referred to as SMART 2.0. The SMART Program relies on the EDCs to issue incentive payments and alternative on-bill credits to participating customers. Accordingly, the EDCs are seeking approval of revised SMART Tariffs. SMART 3.0 replaces the structure of the initial SMART Program, a declining block incentive program, with a program that contains capacity targets and incentive rates adjusted annually by the DOER. SMART 3.0 Program incentives will be paid over a 20-year term and will vary based on a project’s category and capacity. On January 9, 2026, the EDCs supplemented their filing to provide updated program costs estimates reflecting SMART 3.0 applications received in program year 2025 and assuming full enrollment of all available capacity in program year 2026. Because program year 2025 application levels were significantly lower than the maximum capacity quantities across the EDCs, this resulted in a decrease in estimated maximum statewide costs from $6.7 billion to $4.5 billion over 20 years. Fitchburg’s estimated maximum cost is $191 million over 20 years. The cost projections are illustrative and intended to give the MDPU a sense of scale of the potential long-term costs of the SMART 3.0 Program. The EDCs are not seeking approval of specific costs at this time. The EDCs recover SMART Program costs from all distribution customers through the SMART factor, which is set forth in its current SMART tariff and is updated annually. This matter remains pending.

Current report

In its D.P.U. 20-80-B Order, the MDPU directed each LDC to work with the relevant EDC to study the feasibility of piloting a targeted electrification project in its service territory, and to propose at least one demonstration project for decommissioning an area of its system through targeted electrification. On March 16, 2026, Fitchburg filed its proposed Targeted Electrification Pilot Project and Targeted Electrification Pilot Provision in compliance with the Order. The Company proposed implementing its pilot on Maryland Avenue in Fitchburg, MA on a segment of main serving eight customers. The identified segment is scheduled for replacement in 2029. This matter remains pending.

Current report

Fitchburg - Electric Vehicle (EV) Proceedings -On December 31, 2025, Fitchburg submitted to the MDPU a petition for approval of a right-of-way and pole-mounted electric vehicle supply equipment (EVSE) proposal as required by the 2024 Climate Act (Chapter 239, Section 134 of the Acts of 2024). The Company proposes to leverage the program modifications approved on October 17, 2025 to continue to promote public EVSE through its currently approved EV program, which will extend through 2027. This matter remains pending.

Current report

Unitil Corporation – Merger of Aquarion Water Companies - On May 6, 2025, Unitil announced that it has entered into a definitive agreement to acquire Aquarion Water Company of Massachusetts Inc., Aquarion Water Company of New Hampshire, Inc., and Abenaki Water Co., Inc. (the Aquarion Companies) from the Aquarion Water Authority (AWA), a quasi-public corporation chartered by the Connecticut General Assembly in 2024 to acquire Aquarion and to operate as a water authority. Unitil’s acquisition of the Aquarion Companies is contingent upon the initial sale of Aquarion by Eversource Energy (Eversource) to the AWA (Initial Transaction), which will then simultaneously convey the Aquarion Companies to Unitil. On November 19, 2025, the Connecticut Public Utilities Regulatory Authority (PURA) denied approval of the Initial Transaction. On December 2, 2025, the joint applicants in the Connecticut proceeding filed a judicial appeal of PURA’s decision denying the Initial Transaction. On January 15, 2026, a decision was issued that remanded the case back to PURA for further deliberation. On March 6, 2026, PURA issued a Proposed Final Decision approving the application for a change of control over Aquarion Company. A Final Decision approving the application was issued on March 25, 2026. The Initial Transaction is still pending.

Current report

The EDCs issued the first RFP for offshore wind energy generation pursuant to Section 83C in June 2017. In July 2018, the EDCs filed two long-term PPAs with Vineyard Wind, each for 400 MW for approval by the MDPU. In April 2019, the MDPU approved the offshore wind PPAs, including similar requirements for the EDCs to sell the energy procured and credit or charge net costs to customers including EDC remuneration of 2.75%. Vineyard Wind achieved commercial operation for both Facilities on April 24, 2026, at less than 100 percent of project capacity. The developer will continue construction to complete Facility 1 and Facility 2 to the full 800MW.

Current report

The EDCs issued additional RFPs pursuant to Section 83C to procure additional offshore wind energy generation in May 2019 and in May 2021. These two procurements led to four additional PPAs for a total of 2400 MW that were approved by MDPU but were later terminated in September 2023.

Current report

Pursuant to Section 82 of Chapter 179 of the Acts of 2022 (An Act driving clean energy and offshore wind), the DOER is authorized to coordinate with other New England states issuing competitive solicitations for long-term clean energy generation, including nuclear power generation, associated environmental attributes, transmission or capacity for the benefit of residents of the Commonwealth and the region. If the DOER, in consultation with the EDCs and the office of the Attorney General, determines not later than December 31, 2027, that a project would satisfy the benefits listed in Section 82, the DOER may direct the EDCs to enter into cost-effective long-term contracts. The DOER is currently exploring procurements issued by Maine and Connecticut. In September 2025, Connecticut issued an Expedited Zero Carbon RFP and following selections made by Connecticut, the DOER selected two projects for Massachusetts. Negotiations between the EDCs and the project developers are underway.

Current report

The NETOs were directed to file refund reports by April 18, 2026. On April 2, 2026, the NETOs filed a motion to extend the refund deadline and requested an expedited comment period. The motion was granted on April 14, 2026 and set a refund date of May 20, 2027. Refund reports are due June 4, 2027. Also filed on April 2, 2026 was a motion for stay of refund obligations. FERC decisions on this matter is pending. On April 30, 2026, the NETOs submitted a 205 filing at FERC requesting an ROE of 11.39% based on recalculating March 19, 2026 Order results with current data. The Company does not believe these proceedings will have a material effect on its financial condition or results of operations.

Previous report

On October 31, 2025, Unitil Corporation acquired Maine Natural Gas Company, a natural gas distribution utility. Maine Natural Gas Company was incorporated under the laws of the State of Maine in 1998.

Previous report

Electric GAAP Gross Margin was $25.1 million in the three months ended September 30, 2025, an increase of $2.8 million compared to the same period in 2024. Electric GAAP Gross Margin was $62.7 million in the nine months ended September 30, 2025, an increase of $2.5 million compared to the same period in 2024. The three month period increase was driven by higher rates and customer growth of $3.4 million, partially offset by higher depreciation and amortization expense of $0.6 million. The nine month period increase was driven by higher rates and customer growth of $4.7 million, partially offset by higher depreciation and amortization expense of $2.2 million.

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The Company’s Net Income (Loss) was ($0.3) million, or ($0.02) in Earnings Per Share (EPS), for the third quarter of 2025, a decrease of $0.3 million in Net Income, or $0.02 in EPS, compared to the third quarter of 2024. The Company's Adjusted Net Income (a non-GAAP financial measure) for the third quarter of 2025, which excluded transaction-related costs in connection with the acquisitions of Bangor, Maine Natural and the Aquarion Companies, was $0.4 million, which was unchanged from the third quarter of 2024, or $0.03 in EPS, an increase of $0.01 in EPS, compared to the third quarter of 2024.

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Electric Adjusted Gross Margin (a non-GAAP financial measure) was $33.1 million and $86.4 million in the three and nine months ended September 30, 2025, respectively, increases of $3.4 million and $4.7 million, respectively, compared to the same periods in 2024. This increase reflects higher rates and customer growth.

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Depreciation and Amortization expense increased $3.1 million and $10.5 million in the three and nine months ended September 30, 2025, respectively, compared to the same periods in 2024. The increase in the three month period reflects higher depreciation rates from recent base rate cases, additional depreciation associated with higher levels of utility plant in service and higher amortization of other deferred costs. The increase in the nine month period reflects higher depreciation rates from recent base rate cases, additional depreciation associated with higher levels of utility plant in service and higher amortization of recoverable storm costs and other deferred costs. Included in Depreciation and Amortization for the three months and nine months ended September 30, 2025 is $0.7 million and $2.0 million, respectively, related to Bangor.

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Income Tax Expense (Benefit) is unchanged for the three months ended September 30, 2025, compared to the same period in 2024. Income Tax Expense (Benefit) increased $0.2 million in the nine months ended September 30, 2025, compared with the same period in 2024.

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Electric Adjusted Gross Margin (a non-GAAP financial measure) was $33.1 million and $86.4 million for the three and nine months ended September 30, 2025, respectively, increases of $3.4 million and $4.7 million, respectively, compared with the same periods in 2024. These increases reflect higher rates and customer growth.

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Depreciation and Amortization - Depreciation and Amortization expense increased $3.1 million, or 16.2%, and $10.5 million, or 19.0%, in the three and nine months ended September 30, 2025, respectively, compared to the same periods in 2024. The increase in the three month period reflects higher depreciation rates from recent base rate cases, additional depreciation associated with higher levels of utility plant in service and higher amortization of other deferred costs. The increase in the nine month period reflects higher depreciation rates from recent base rate cases, additional depreciation associated with higher levels of utility plant in service and higher amortization of recoverable storm costs and other deferred costs. Included in Depreciation and Amortization for the three months and nine months ended September 30, 2025 is $0.7 million and $2.0 million, respectively, related to Bangor.

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On August 21, 2024, Unitil issued $20.0 million of Notes due 2034 at 5.99%; Fitchburg issued $12.5 million of Notes due 2034 at 5.54% and $12.5 million of Notes due 2044 at 5.99%; Unitil Energy issued $40.0 million of Bonds due 2054 at 5.69%; Northern Utilities issued $25.0 million of Notes due 2034 at 5.54% and $15.0 million of Notes due 2039 at 5.74%; and Granite State issued $10.0 million of Notes due 2034 at 5.74%. The Company used the net proceeds from these offerings to refinance existing debt and for general corporate purposes. Approximately $1.0 million of costs associated with this issuance were recorded as a reduction of Long-Term Debt for presentation purposes on the Consolidated Balance Sheet in the third quarter of 2024.

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On October 31, 2025, Unitil Corporation acquired Maine Natural Gas Company, a natural gas distribution utility.

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Fitchburg has entered into power purchase agreements for which contingencies exist (see Note 6, Regulatory Matters—Fitchburg— Massachusetts Request for Proposal (RFPs)). Until these contingencies are satisfied, these contracts will not qualify for derivative accounting. The Company believes that the power purchase obligations under these long-term contracts will have a material effect on the contractual obligations of Fitchburg.

Previous report

In November 2023, the FASB issued ASU 2023-07, Segment Reporting – Improvements to Reportable Segment Disclosures (ASU 2023-07). The amendments in ASU 2023-07 are intended to improve reportable segment disclosure requirements, primarily through enhanced disclosures about significant segment expenses. The amendments in ASU 2023-07 are effective for fiscal years beginning after December 15, 2023 and interim periods within fiscal years beginning after December 15, 2024. The Company adopted this new guidance for the year-ended December 31, 2024 and it did not have a material effect on the Company’s Consolidated Financial Statements (see Note 3, Segment Information).

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Acquisition of Maine Natural Gas Company -On March 31, 2025, Unitil entered into a Stock Purchase Agreement (the Purchase Agreement) between the Company and Avangrid Enterprises, Inc. (the Seller). Pursuant to, and subject to the terms and conditions of, the Purchase Agreement, the Company agreed to acquire all of the issued and outstanding shares of capital stock of Maine Natural from the Seller for $86.0 million in cash, subject to certain adjustments as provided in the Purchase Agreement. The MPUC issued an order on September 12, 2025 approving the merger of Maine Natural into Unitil. The transaction closed on October 31, 2025.

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On August 21, 2024, Unitil issued $20.0 million of Notes due 2034 at 5.99%; Fitchburg issued $12.5 million of Notes due 2034 at 5.54% and $12.5 million of Notes due 2044 at 5.99%; Unitil Energy issued $40.0 million of Bonds due 2054 at 5.69%; Northern Utilities issued $25.0 million of Notes due 2034 at 5.54% and $15.0 million of Notes due 2039 at 5.74%; and Granite State issued $10.0 million of Notes due 2034 at 5.74%. The Company used the net proceeds from these offerings to refinance existing debt and for general corporate purposes. Approximately $1.0 million of costs associated with this issuance were recorded as a reduction of Long-Term Debt for presentation purposes on the Consolidated Balance Sheet in the third quarter of 2024.

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Northern Utilities - Base Rates - Maine- On September 20, 2023, the MPUC issued an order approving a Stipulation filed on August 31, 2023, between Northern Utilities and the Office of the Public Advocate which resolved all matters in the base rate filing made by Northern Utilities with the MPUC on May 1, 2023. The order approves an increase in distribution revenues of $7.6 million effective October 1, 2023. The order reflects a return on equity of 9.35%, an equity ratio of 52.01%, and a weighted average cost of capital of 7.22%.

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Northern Utilities - Targeted Infrastructure Replacement Adjustment (TIRA) - Maine- The settlement in Northern Utilities’ Maine division’s 2013 rate case authorized the Company to implement a TIRA rate mechanism to adjust base distribution rates annually to recover the revenue requirements associated with targeted investments in gas distribution system infrastructure replacement and upgrade projects, including the Company’s Cast Iron Replacement Program (CIRP). In its Final Order issued on February 28, 2018 for Northern Utilities’ 2017 base rate case, the MPUC approved an extension of the TIRA mechanism for an additional eight-year period, which will allow for annual rate adjustments through the end of the CIRP program. The Company’s most recent request under the TIRA mechanism, to increase annual base rates by $2.1 million for 2024 eligible facilities, was filed with the MPUC on February 28, 2025 for rates effective May 1, 2025. On April 29, 2025, the MPUC issued an order approving the filing, for rates effective May 1, 2025. During 2024, Northern Utilities performed its fourteenth and final year of construction on the 14-year combined CIRP, (Unprotected Steel and Farm Tap project ordered by the MPUC in Docket Nos. 2008-00151 and 2013-00133). As the

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Cast Iron Replacement Program and related unprotected steel and Farm Tap programs now have been completed and all leak-prone pipe has been removed, this is Northern’s final TIRA rate adjustment.

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Northern Utilities - Base Rates - New Hampshire- On July 20, 2022, the NHPUC issued an Order in the distribution base rate case filed with the NHPUC on August 2, 2021 by Northern Utilities. The Order approved a comprehensive Settlement Agreement between the Company, the New Hampshire Department of Energy (DOE), and the Office of the Consumer Advocate (OCA). As provided in the Settlement Agreement, in addition to authorizing an increase to permanent distribution rates of $6.1 million, effective August 1, 2022, the Order (1) approved a revenue decoupling mechanism and (2) allowed for a step adjustment effective September 1, 2022 covering the additional revenue requirement resulting from changes in Net Plant in Service associated with non-growth investments for the period January 1, 2021, through December 31, 2021. This distribution base rate case reflected the Company’s operating costs and investments in utility plant for a test year ended December 31, 2020 as adjusted for known and measurable changes. The Order provided for a return on equity of 9.3% and a capital structure reflecting 52% equity and 48% long-term debt. The increase in permanent rates was reconciled back to October 1, 2021, the effective date of temporary rates previously approved in this docket. On June 8, 2022, the Company filed for its step increase of approximately $1.6 million of annual revenue, for rates effective as of September 1, 2022, to recover eligible 2021 capital investments. On August 31, 2022, the NHPUC approved the Company’s filing.

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Fitchburg - Base Rates - Gas - On August 17, 2023, Fitchburg filed a petition with the MDPU seeking approval for a $10.9 million increase to base distribution rates, with new rates anticipated to be effective July 1, 2024. Fitchburg proposed to transfer $4.2 million in revenue requirements recovered through its Gas System Enhancement Program to base distribution rates. Net of these transfers, the proposed overall increase to distribution revenues was $6.7 million. As part of this filing, Fitchburg requested approval for a PBR plan for up to a five-year term and continuation of its revenue decoupling mechanism. On June 28, 2024, the MDPU issued an Order providing for a $10.1 million increase to base rates, effective July 1, 2024. This includes a transfer of $4.9 million in costs from certain reconciling mechanisms to base distribution rates. In addition to authorizing an increase to base rates, the Order approved a PBR plan for up to a five-year term. The order approves continuation of the Company’s revenue decoupling mechanism but changes the structure from a revenue per customer benchmark to a total revenue cap. The Order provided for a return on equity of 9.4% and a capital structure reflecting 52% equity and 48% long-term debt. On July 5, 2024, the Company filed its compliance tariff filing and made further revisions as directed by the MDPU on July 15, 2024. On July 16, 2024, the MDPU approved its revised compliance filing.

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Unitil Energy - Proposal to Construct Utility - Scale Solar Facility - On October 31, 2022, Unitil Energy submitted a petition to the NHPUC for review of Unitil Energy’s proposal to construct, own, and operate a 4.99 MW utility-scale photovoltaic generating facility, which was subsequently revised to a 4.88 MW facility. On May 1, 2023, the NHPUC issued an Order approving the Company's petition.

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The facility became fully commissioned in May 2025. Unitil Energy has included a cost recovery proposal associated with the solar facility as part of its pending base rate proceeding filing.

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Unitil Energy - Major Storm Cost Reserve Recovery -On February 28, 2025, Unitil Energy filed a request with the NHPUC to increase its Storm Recovery Adjustment Factor (SRAF) effective August 1, 2025. The Company proposed to reduce its Major Storm Cost Reserve deferral balance by transferring its April 2024 Nor’easter costs of approximately $1.8 million into the SRAF and recover the cost over the next three years. On June 27, 2025, the New Hampshire DOE filed a statement in support of the Company’s request. On August 29, 2025, the NHPUC issued an order approving the Company’s request.

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Fitchburg - Grid Modernization - On July 1, 2021, Fitchburg submitted its Grid Modernization Plan (GMP) to the MDPU. The GMP includes a five-year strategic plan, including a plan for the full deployment of advanced metering functionality, and a four-year short-term investment plan, which focuses on foundational investments to facilitate the interconnection and integration of distributed energy resources, optimizing system performance through command and control and self-healing measures, and optimizing system demand by facilitating consumer price-responsiveness. On October 7, 2022, the MDPU issued a “Track 1” Order approving a budget cap of $9.3 million through 2025 for previously deployed or preauthorized grid modernization investments. On November 30, 2022, the MDPU issued its “Track 2” Order addressing new technologies and Advanced Metering Infrastructure (AMI) proposals. The MDPU preauthorizes a four-year $1.5 million budget for Fitchburg’s additional grid-facing investments. Any spending over the total budget cap is not eligible for targeted cost recovery through its Grid Modernization Factor (GMF), and instead, may be recovered by the Company in a base distribution rate proceeding subsequent to a prudency finding by the MDPU in a GMF filing or term review Order. The MDPU also preauthorized the Company’s AMI meter replacement investments, with a budget of $11.2 million through 2025. Additionally, the MDPU provided preliminary approval for the Company’s customer engagement and experience and data sharing platform investments, with a combined budget of $2.3 million through 2025. The Company may recover eligible costs incurred for preauthorized grid-facing investments and customer-facing investments that will be made during the 2022-2025 GMP term through the GMFs, subject to certain modifications to the Company’s GMF tariff and a final prudence review. The MDPU conducted a hearing on September 26, 2023 on the Company’s then-pending GMF filings and Grid Modernization Term Report. This matter remains pending.

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On April 24, 2023, Fitchburg submitted its 2022 Grid Modernization Plan Annual Report to the MDPU. Among other things, the Company explained a modification to its implementation of the AMI plan that the MDPU preauthorized in D.P.U. 21-82. Due to a discontinuation of the meter technology upon which the Company’s initial AMI plan relied, the Company reported that it will need to replace its meters with a new meter technology and to implement a new communications system. On May 31, 2023, the MDPU issued an Order indicating its intent to explore the impact of the discontinuation and determine the appropriate next steps outside the GMF proceeding. On April 15, 2024, the Company submitted its annual Grid Modernization Filing seeking recovery of costs related to grid modernization investments placed into service in 2023. In connection with this filing, the Company submitted a request for preauthorization of the metering, communications systems, and head end system investments that will be implemented in connection with the Company’s advanced metering infrastructure replacement project. On March 28, 2025, the MDPU issued an Order approving, among other things, the Company’s request for preauthorization. Fitchburg submitted its 2024 Grid Modernization Plan Annual Report on July 1, 2025. This matter remains pending.

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In its Track 2 Order, the MDPU directed the Company and other EDCs to convene a statewide AMI stakeholder working group (AMI Working Group) to address the following issues: (1) customer and third-party access to customer usage data; (2) customer education and engagement; (3) billing of time varying rates (TVR) offered by competitive suppliers; and (4) AMI deployment strategies that may expedite the ability for competitive suppliers to offer TVR products. Additionally, the MDPU directed the EDCs to file quarterly status reports, including a final report that sets forth issues on which a consensus had been reached and those issues that remain to be resolved. On August 1, 2024, the EDCs filed a final report identifying where stakeholders were able and unable to reach consensus.

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Fitchburg - Investigation into the role of gas LDCs to achieve Commonwealth 2050 climate goals- The MDPU has opened an investigation to examine the role of Massachusetts gas local distribution companies (LDCs) in helping the Commonwealth achieve its 2050 climate goal of net-zero greenhouse gas (GHG) emissions. In its Order opening the inquiry, the MDPU stated it is required to consider new policies and structures as the Commonwealth reduces reliance on fossil fuels, including natural gas, which may require LDCs to make significant changes to their planning processes and business models. The LDCs, including Fitchburg, engaged an independent consultant to conduct a study and prepare a report (Consultant Report), including a detailed study of each LDC, that analyzes the feasibility of all identified pathways to help the Commonwealth achieve its net-zero GHG goal. The study includes an examination of the potential pathways identified in the 2050 Decarbonization Roadmap developed by the Massachusetts Executive Office of Energy and Environmental Affairs, in consultation with the Massachusetts Department of Environmental Protection and the Massachusetts Department of Energy Resources (DOER).

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The MDPU has indicated its intent to investigate how innovative approaches to cost recovery through base distribution rates can further the purpose of G.L. c. 164, § 92B, optimally balance the MDPU’s priorities, and promote efficiency. The MDPU stated that such a proceeding will likely require a lengthy inquiry to identify, analyze, and resolve many complex ratemaking issues. To help inform the subsequent proceeding(s), the MDPU requested comments from interested parties on items and issues that should be considered, including: (1) information and data on innovative approaches to cost recovery, in particular, to facilitate accelerated electrification and/or grid modernization efforts identified at the federal level and/or successfully implemented or being considered in other states; and (2) discussion and proposals on performance metrics and incentives applicable to longer-term cost recovery considerations. On October 1, 2025, the Company and the other EDCs, at the MDPU’s direction, submitted comments on potential future approaches to cost recovery for Electric Sector Modernization Plan investments and expenses.

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Fitchburg - Electric Vehicle (EV) Proceeding -On December 30, 2022, the MDPU issued an order approving Fitchburg’s five-year EV program with a $1.0 million budget consisting of: (1) public infrastructure offering ($0.5 million); (2) Electric Vehicle Supply Equipment incentives for residential segment ($0.3 million); and (3) marketing and outreach ($0.2 million). The Company may shift spending between program segments and between years over the five-year term of its program, subject to a 15% cap. Any spending above the approved EV program budget or above the 15% cap for each program segment is not eligible for targeted cost recovery through the GMF and, instead, may be recovered in a base distribution rate proceeding subsequent to a prudency finding by the MDPU. The MDPU’s Order directs the Companies to submit annual reports that document their performance and these reports are due on or before May 15th of each year. The MDPU accepted the Company’s Demand Charge Alternative proposal and directed implementation within six months. The Demand Charge Alternative is offered for a ten-year period beginning July 1, 2023 with tiered rates to separately-metered EV general delivery service customers. The MDPU also accepted the Company’s proposed residential EV TOU rate, effective April 1, 2023.

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In June 2023, the MDPU convened an EV stakeholder process to finalize EV program performance metrics. On April 3, 2023, the electric companies filed comments on the MDPU’s proposed metrics. On December 15, 2023, the MDPU approved EV performance metrics. Following that approval, the MDPU required the electric companies to develop a joint state-wide program evaluation plan for MDPU approval and stakeholder input. On May 15, 2024, Fitchburg submitted its first annual report on the performance of its EV Program, and along with the other Massachusetts EDCs, a proposed statewide program evaluation plan for MDPU approval and stakeholder input. On September 30, 2024, the MDPU stamp approved the Joint Statewide Electric Vehicle Program Evaluation Plan. In addition, on October 1, 2024 the MDPU approved Fitchburg’s request for a supplemental budget increase to engage a consultant to assist with the Joint Statewide Electric Vehicle Program Evaluation Plan. On December 20, 2024, the Company submitted a request for approval to modify certain aspects of the public, residential, and income eligible offers of its EV program. Fitchburg does not anticipate any rate changes resulting from this filing, which is currently pending before the MDPU.

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Fitchburg - Storm Cost Deferral Petition -On November 2, 2023, Fitchburg filed a request with the MDPU to increase its Storm Reserve Adjustment Factor effective January 1, 2024. The increase would allow the Company to recover approximately $4.8 million of costs of repairing damage to its electrical system plus $1.4 million of projected carrying costs resulting from the January and March 2023 winter storms over a five-year period. On December 19, 2023, the MDPU allowed the associated rate increase to become effective on January 1, 2024, subject to further investigation and reconciliation. This matter remains pending before the MDPU.

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Fitchburg - Approval of Gas Supply Agreement with Constellation LNG- On February 16, 2024, Fitchburg filed a petition with the MDPU for approval of a six year agreement with Constellation LNG for the purchase of natural gas in the liquid or vapor form for the period June 1, 2024 through May 31, 2030 heating seasons. This request is for the approval of two contracts, the first for up to 3,400 Dth per day of natural gas peaking supply to the Company. This first contract will be broken out for 3,000 Dth per Day in the form of LNG for use at the Company’s Westminster LNG facility and 400 Dth per Day will be in the form of natural gas supply delivered to the city-gate connecting the Company’s system to the Tennessee Gas Pipeline. The second contract will provide up to 3,000 Dth per day of LNG trucking from the Everett Marine Terminal to the Company’s Westminster LNG facility.

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This Agreement ensures that the Everett Marine Terminal (EMT), which plays a critical role in both the Company’s and the New England energy market’s efficient and reliable operation, will continue to be available for the next six winter seasons. A six year agreement was also requested by Boston Gas Company, Eversource Gas Company, and NSTAR Gas Company. Fitchburg and the other LDCs received an Order on May 17, 2024 approving the agreements.

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Unitil Corporation – Merger of Bangor Natural Gas, Inc. - On July 15, 2024, Unitil, Northern Utilities, Hearthstone Holdings, Inc. d/b/a Hope Companies, Inc. (HUI), PHC Utilities, Inc. (PHC), and Bangor Natural Gas Company filed a Joint Petition requesting that the MPUC approve the merger of Bangor into Unitil pursuant to a July 8, 2024 Stock Purchase Agreement among PHC, HUI and Unitil. Furthermore, Unitil requested that the MPUC issue an order excusing Bangor and Unitil from certain regulatory conditions and obligations imposed upon Bangor or its affiliates in conjunction with prior reorganizations of Bangor. Unitil filed a Stipulation supporting the proposed merger, signed by all parties to the docket, on December 4, 2024. Among other provisions, Unitil and Bangor agreed that Bangor would not file a general rate case prior to January 1, 2027. The MPUC issued an Order approving the Stipulation on December 18, 2024. In a separate Order issued January 14, 2025, the MPUC approved the proposed long-term debt facility. Unitil completed the acquisition of Bangor on January 31, 2025.

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Unitil Corporation – Merger of Maine Natural Gas Company - On May 9, 2025, Unitil, Northern Utilities, Bangor, Avangrid Enterprises, Inc. and Maine Natural filed a Joint Petition requesting that the MPUC approve the merger of Maine Natural into Unitil pursuant to a Stock Purchase Agreement among Avangrid and Unitil. A procedural schedule has been established which includes discovery, technical conferences, testimonies and briefs. To comply with the statutory timeframe of 180 days, deliberations are scheduled to be held no later than early November 2025. The MPUC issued an Order approving the Stipulation on September 12, 2025. In a separate Order issued September 16, 2025, the MPUC approved the proposed long-term debt facility. Unitil completed the acquisition of Maine Natural on October 31, 2025.

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On May 23, 2025, pursuant to 35-A M.R.S. § 708, Northern Utilities filed a request that the MPUC grant an exemption from approval of the reorganization that will be triggered by the anticipated acquisition by Unitil of the three water utilities in Massachusetts and New Hampshire. The MPUC has previously granted Maine public utilities exemptions from regulatory approval of reorganizations under circumstances similar to those presented in this case involving the acquisition of companies outside of Maine by a utility’s holding company parent that will have no direct financial or operational impact on the Maine utility. Based on MPUC precedent in similar reorganizations, Northern Utilities requested an exemption from Section 708 approval of Unitil’s acquisition of the Aquarion MA-NH Companies. In the alternative, if the MPUC declines to grant the requested exemption, then Northern Utilities requested that the MPUC approve the reorganization pursuant to Section 708. This matter remains pending.

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Northern Utilities / Granite State - Firm Capacity Contract - Northern Utilities relies on the transportation of gas supply over its affiliate Granite State pipeline to serve its customers in the Maine and New Hampshire service areas. Granite State facilitates critical upstream interconnections with interstate pipelines and third party suppliers essential to Northern Utilities’ service to its customers. Northern Utilities reserves firm capacity through a contract with Granite State, which is renewed annually. Pursuant to statutory requirements in Maine and orders of the MPUC, Northern Utilities submits an annual informational report requesting approval of a one-year extension of its 12-month contract for firm pipeline capacity reservation, with an evergreen provision and three-month termination notification requirement. On March 31, 2025, Northern Utilities submitted an annual informational report requesting approval on a one-year extension for the period of November 1, 2025 through October 31, 2026. The Company received an order approving the one-year extension of its request on June 3, 2025.

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Northern Utilities / Portland Natural Gas Transmission System (PNGTS) and TransCanada Pipelines Limited (TCPL) transportation from Empress, Alberta to Granite State Gas Transmission, Inc. (GSGT)- On October 5, 2023, Northern Utilities filed with the NHPUC and the MPUC a request to approve agreements for the ability for Northern Utilities to increase supply portfolio capacity by 12,500 Dth per day in New Hampshire and Maine. This incremental capacity to Northern Utilities’ supply portfolio took effect April 1, 2024 for a thirty-year term. Northern Utilities was able to acquire this incremental supply of TCPL capacity through an open season process. On January 26, 2024 and January 30, 2024, the Company received orders from the NHPUC and MPUC, respectively, approving Northern Utilities’ proposal for Empress Agreements with PNGTS and TransCanada Pipelines. Conservation Law Foundation filed a motion for reconsideration of the MPUC’s decision on February 15, 2024. The Company objected to the motion, and on March 26, 2025, the Hearing Examiners issued a Recommended Order on Reconsideration from the MPUC on this CLF motion. The Recommended Order, if adopted, would affirm the MPUC’s previous decision to approve the Company’s entry into these Agreements. The MPUC issued an Order reaffirming and clarifying its initial Order approving the Empress Agreements, and specifically affirmed its conclusion that entering into the Empress Capacity Agreements is prudent, in the public interest, and not inconsistent with the state’s climate policy.

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Section 83C of “An Act Relative to Green Communities,” St. 2008, c. 169, as amended by St. 2016, c. 188, § 12 (Section 83C) requires the EDCs to jointly and competitively solicit proposals for offshore wind energy generation not later than June 30, 2017. The EDCs issued an initial RFP pursuant to Section 83C in June 2017. On July 23, 2018, the EDCs, filed two long-term contracts with Vineyard Wind, each for 400 MW of offshore wind energy generation, for approval by the MDPU. On April 12, 2019, the MDPU approved the offshore wind energy generation PPAs, including the EDCs’ proposal to sell the energy procured under the contract into the ISO-NE wholesale market and to credit or charge the difference between the contract costs and the ISO-NE market revenue to customers. The EDCs issued a second RFP pursuant to Section 83C to procure an additional 800 MW of offshore wind energy generation in May 2019. The EDCs filed for approval of two PPAs with Mayflower Wind Energy LLC (now known as SouthCoast Wind), each for 400 MW of offshore wind energy generation, on February 10, 2020. On November 5, 2020, the MDPU approved the PPAs. In both cases, the MDPU approved the EDCs’ request for remuneration equal to 2.75% of the contract payments, as well as the EDCs’ proposal to recover costs associated with the contracts. In April 2023, SouthCoast Wind engaged with the EDCs to explore options to mitigate impacts of global resource constraints and pricing challenges associated with the PPAs from this procurement. They cited an inability to finance the project within the terms set out in the PPA. The EDCs negotiated a termination agreement with SouthCoast Wind which was filed with the MDPU for approval on August 28, 2023 and which received approval on September 30, 2023.

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In accordance with “An Act to Advance Clean Energy” (2018) the DOER recommended that the EDCs solicit up to 1,600 MW in additional offshore wind in 2022 and 2024. On May 7, 2021, the EDCs issued a third RFP for up to an additional 1,600 MW of offshore wind generation. On May 25, 2022, the EDCs sought approval of PPAs with Commonwealth Wind for 1,200 MW and with SouthCoast Wind for 400 MW. On December 16, 2022, Commonwealth Wind filed a motion requesting that the MDPU dismiss proceedings related to the approval of its contract, arguing that, due to various economic conditions, its contracts with the EDCs would no longer facilitate the financing of offshore wind energy generation. On December 30, 2022, the MDPU denied Commonwealth Wind’s motion and approved the PPAs. The MDPU also approved the EDCs’ request for remuneration equal to 2.25%as reasonable and in the public interest. On January 19, 2023, Commonwealth Wind filed a Petition for Appeal with the Massachusetts Supreme Judicial Court (SJC) seeking to set aside and vacate the MDPU’s Order approving the PPAs. In April 2023, SouthCoast Wind engaged with the EDCs to explore options to mitigate global resource constraints and pricing challenges associated with their PPAs from this procurement. SouthCoast Wind noted challenges around an inability to finance the projects under the current terms. The EDCs negotiated termination agreements with Commonwealth Wind and SouthCoast Wind and submitted the agreementsto the MDPU for approval on July 13, 2023 and August 28, 2023, respectively. The MDPU approved both termination agreements on September 30, 2023.

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Unitil Energy/Northern Utilities - 2024-2026 Triennial Energy Efficiency Plan - New Hampshire- On November 30, 2023, the NHPUC approved the changes to New Hampshire’s ratepayer-funded energy efficiency program offerings for the 2024–2026 period requested by New Hampshire’s electric and gas utilities. On July 1, 2024, the New Hampshire electric and gas utilities filed an interim update with the NHPUC, seeking approval to update the energy efficiency program models with benefit assumptions from the recently issued report of Avoided Energy Supply Components in New England: 2024 Report.

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Company believes excluding Depreciation and Amortization, which are period costs and not related to volumetric sales, is a meaningful measure to inform investors of the Company’s profitability from electric and gas sales in the period.

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Level 1 as they are actively traded and no valuation adjustments have been applied. Changes in the fair value of these investments are recorded in Other Expense, Net.

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Acquisition of Maine Natural Gas Corporation - On October 31, 2025, the Company acquired all issued and outstanding shares of Maine Natural for $91.1 million. Through this acquisition, the Company expanded its service territory to include approximately 6,300 customers in the Portland area of central Maine, as well as the capital city of Augusta.

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Goodwill represents the amount by which the purchase price exceeds the estimated fair value of the net assets acquired. The goodwill related to Maine Natural is partially tax-deductible. The tax-deductible portion of goodwill is $1.9 million and will be amortized over 15 years.

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Service’s and Unitil Realty’s costs are allocated to the Electric and Gas segments based on cost allocation factors. Unitil Water does not have any activity.

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On October 31, 2025, the Company entered into a senior unsecured delayed-draw term loan facility with The Bank of Nova Scotia. The proceeds of the $86.0 million facility were used to fund the acquisition of Maine Natural on October 31, 2025. Thefacility provides that the Company has an option for determining whether interest on loans under the facility will bear interest based on a Base

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On December 29, 2023, the LDCs filed a Joint Motion for Clarification. The Joint Motion requested clarification of three issues: (1) the MDPU’s directive concerning the NPAs analysis; (2) the timetable for establishing ‘incentives and disincentives’ for progress toward compliance with Climate Act mandates as part of a PBR framework and achievement of approved Climate Compliance Plans; and (3) the methodology for emissions reduction accounting for Climate Compliance Plans, with particular attention to Scope 1 and

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ASU 2023-09 as of December 31, 2025 on a prospective basis. The following table presents the Company’s provisions for Income Taxes and the provisions calculated at the statutory federal tax rate for the three months ended March 31, 2026:

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The Company estimates the ARAM flow back period for protected and unprotected excess ADIT to be between fifteen and twenty years over the remaining life of the related utility plant. As of March 31, 2026, the Company flowed back $14.5 million to customers in its Massachusetts, Maine, New Hampshire and federal jurisdictions.

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On September 29, 2022, the Company entered into a Third Amended and Restated Credit Agreement with a syndicate of lenders (collectively, the "Credit Facility”), which amended and restated in its entirety the prior credit facility. On January 29, 2025, the Company entered into an amendment to the Credit Facility, which (among other things) increased the borrowing limit under the Credit

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Facility from $200 million to $275 million and extended the term of the Credit Facility from September 29, 2027 until September 29, 2028. Unitil may borrow under the Credit Facility until September 29, 2028, subject to two one-year extensions under certain circumstances.

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In December 2024, the Massachusetts Legislature approved “An Act promoting a clean energy grid, advancing equity, and protecting ratepayers” which, among other provisions, extends the period for long-term renewable contracts up to 30 years and directs the EDCs to “jointly and competitively solicit proposals for energy storage systems and enter into cost-effective long-term contracts equal to, in the aggregate, approximately 5,000 megawatts of energy storage systems not later than July 31, 2030.” The first solicitation will be for the environmental attributes associated with approximately 1,500 megawatts of mid-duration storage. The RFP for the first roundwas released on July 31, 2025 and bids were due on September 10, 2025. The DOER and MA EDCs are evaluating the bids. Selection of projects is scheduled to occur on December 9, 2025.

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In connection with Unitil’s acquisition of Bangor, the Company entered into a Transition Services Agreement dated January 31, 2025 between Bangor and Hope Utilities, Inc. (Hope Utilities). Pursuant to the Transition Services Agreement, Hope Utilities will provide Bangor with certain services at cost, for up to 12 months, in order to continue the operation and maintenance of Bangor substantially consistent with past practices until Unitil has completed the successful transition.

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On September 29, 2022, the Company entered into a Third Amended and Restated Credit Agreement with a syndicate of lenders (collectively, the "Credit Facility”), which amended and restated in its entirety the prior credit facility. On January 29, 2025, the Company entered into an amendment to the Credit Facility, which (among other things) increased the borrowing limit under the Credit Facility from $200 million to $275 million and extended the term of the Credit Facility from September 29, 2027 until September 29, 2028. Unitil may borrow under the Credit Facility until September 29, 2028, subject to two one-year extensions under certain circumstances.

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In its Order, the MDPU found that allowing the Company to recover pension and PBOP expense through its Pension/PBOP Adjustment mechanism is no longer warranted. Instead, the MDPU concluded that these expenses should be recovered in base distribution rates, the mechanism should be discontinued, and any unrecovered expenses existing as of the effective date of new rates will be recovered over two years. On July 18, 2024, the Company filed a Motion for Reconsideration and Recalculation requesting that the MDPU reconsider its decision to require the Company to absorb $1.4 million in negative excess ADIT because the effect of the Order was to inappropriately claw back amounts that were previously approved by the MDPU for recovery from customers. On November 26, 2024, the MDPU issued an Order on the Company’s motion holding, in part, that Pension/PBOP expenses shall be recovered in base distribution rates. On December 9, 2024, the Company filed an appeal with Massachusetts Supreme Judicial Court on the grounds that the MDPU’s Order unlawfully deniesthe Company’s recovery of approximately $1.4 million of negative, excess ADIT. The amount of $1.4 million is disaggregated between the Company’s Gas Division ($0.6 million) and the Electric Division ($0.8 million). This appeal is pending. The ruling on November 26, 2024 approved certain other recalculations, resulting in an additional increase to gas base rates of $0.1 million effective December 1, 2024.

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assetsof $5.6 million and $1.0 million of federal tax credit carryforward. As of December 31, 2024, the Company has $1.7 million of federal NOLC and $0.6 million of federal tax credits to offset current taxes payable. In addition, at December 31, 2024, the Company had $1.6 million of cumulative state tax credit carryforwards to offset future income taxes payable. If unused, the Company’s state tax credit carryforwards will begin to expire in 2027.