| Regulatory Assets and Liabilities | Regulatory Assets and Liabilities Pursuant to the requirements concerning accounting for regulated operations, our utilities capitalize, as regulatory assets, incurred and accrued costs that are probable of recovery in future electric and natural gas rates. We base our assessment of whether recovery is probable on the existence of regulatory orders that allow for recovery of certain costs over a specific period, or allow for reconciliation or deferral of certain costs. When costs are not treated in a specific regulatory order, we use regulatory precedent to determine if recovery is probable. Our operating utilities also record, as regulatory liabilities, obligations to refund previously collected revenue or to spend revenue collected from customers on future costs. The primary items that are not included in rate base or accruing carrying costs are regulatory assets for qualified pension and other postretirement benefits, which reflect unrecognized actuarial gains and losses; debt premium; environmental remediation costs, which are primarily the offset of accrued liabilities for future spending; unfunded future income taxes, which are the offset to the unfunded future deferred income tax liability recorded; asset retirement obligations; hedge losses; and contracts for differences. As of September 30, 2024, the total net amount of these items is approximately $1,147 million. CMP Distribution Rate Case On August 11, 2022, CMP filed a three-year rate plan, with adjustments to the distribution revenue requirement in each year. On June 6, 2023, the MPUC approved a Stipulation resolving all issues in the case providing for a 9.35% ROE, 50% equity ratio, and 50% earnings sharing for annual earnings in excess of 100 basis points of CMP’s allowed ROE. The Stipulation also provides for a two-year forward looking rate plan with increases to occur in four equal levelized amounts every six months beginning on July 1, 2023. An increase occurred on January 1, 2024 and July 1, 2024. The last increase will occur on January 1, 2025. The amount of each increase is $16.75 million. These revenue increases include amounts for operations and maintenance but are primarily driven by increases in capital investment forecasted by CMP to occur during the period covered by the Stipulation. The Stipulation also imposes a service quality indicator incentive mechanism on CMP. The incentive is provided by a penalty mechanism that would impose a maximum of $8.8 million per year for a failure to meet specified service quality indicator targets. NYSEG and RG&E Rate Plans On June 14, 2023, NYSEG and RG&E filed a Joint Proposal (2023 JP) settlement for a three-year rate plan with the NYPSC. For purposes of the 2023 JP, the three rate years are defined as the 12 months ending April 30, 2024 (New York Rate Year 1); April 30, 2025 (New York Rate Year 2); and April 30, 2026 (New York Rate Year 3); respectively. On October 12, 2023, the NYPSC approved the 2023 JP, commencing May 1, 2023 and continuing through April 30, 2026. The effective date of new tariffs was November 1, 2023 with a make-whole provision back to May 1, 2023. The 2023 JP, as approved, includes levelization across the three years of the rate plan for delivery rates for NYSEG's and RG&E’s Electric and Gas businesses with an allowed rate of return on common equity for NYSEG Electric, NYSEG Gas, RG&E Electric and RG&E Gas of 9.20%. The common equity ratio for each business is 48.00%. The 2023 JP also includes an Earnings Sharing Mechanism (ESM) applicable to each business that varies based on the earned ROE with 100% of the customers’ portion of earnings above the sharing threshold that would otherwise be deferred for the benefit of customers used to reduce NYSEG's and RG&E’s respective outstanding regulatory asset deferral balances. In addition, 50% of NYSEG's and RG&E’s portion will be used to reduce their respective outstanding storm-related regulatory asset deferral balances to the extent such balances exist. The 2023 JP further enhances distribution vegetation management, maintains gas safety performance measures, establishes threshold performance levels for designated aspects of customer service quality, and includes three Electric Reliability Performance Measures (SAIFI, CAIDI, and Distribution Line Inspection Program Metric for Level II Deficiencies) with a negative revenue adjustment (NRA) beginning with calendar year 2023, if NYSEG fails to meet its annual SAIFI performance metric. NYSEG and RG&E will continue a RAM to return or collect the remaining Customer Bill Credits established in the prior rate plan and will continue an Electric Revenue Decoupling Mechanism on a total revenue per class basis. The 2023 JP reflects the recovery of deferred NYSEG Electric and RG&E Electric Major Storm costs of approximately $371 million and $54.6 million, respectively. NYSEG’s remaining super storm regulatory asset of $52.3 million and the non-super storm regulatory asset of $96.6 million from the 2020 Joint Proposal are being amortized over seven years. RG&E’s remaining non-super storm regulatory asset of $19.6 million established prior to the 2020 Joint Proposal is being amortized over two years. All other deferred storm costs at both NYSEG and RG&E are being amortized over 10 years. The 2023 JP gradually increases NYSEG’s and RG&E’s Major Storm rate allowances over the term of the 2023 JP to better align NYSEG’s and RG&E’s actual Major Storm costs with such rate allowances and to support NYSEG’s and RG&E’s credit metrics. The 2023 JP contains provisions consistent with, supportive of, and in furtherance of the objectives of the Climate Leadership and Community Protection Act (CLCPA) including provisions that will, among other things, increase funding for energy efficiency programs, enhance the electric system in anticipation of increased electrification and increase funding for electric heat pump programs, provide funding for improved electric and gas reliability and resiliency, encourage non-pipe and non-wire alternatives, and replace leak prone pipe. The 2023 JP also includes support for $634 million of capital investment for CLCPA Phase 1 investments projected to be placed in-service beyond the three-year rate plan. New York CLCPA On February 16, 2023, the NYPSC issued an order to authorize transmission upgrades solely to support new renewable generation sources pursuant to the implementation of the Accelerated Renewable Growth and Community Benefit Act as part of the CLCPA Phase 2. The order approves an estimated $4.4 billion in transmission upgrades proposed by upstate utilities to help integrate 3,500 MW of clean energy capacity into the grid, of which NYSEG and RG&E are approved for estimated upgrade costs of $2.2 billion, including participation with other upstate utilities on certain projects. On October 17, 2023, NYSEG and RG&E filed a petition requesting approval from the NYPSC to seek authorization from the FERC, to utilize 100 percent construction work in progress (CWIP), in rate base for the local transmission upgrades under the CLCPA Phase 2. On April 18, 2024, the NYPSC approved the petition to allow NYSEG and RG&E to seek FERC approval along with adding other related reporting requirements. On July 5, 2024, FERC conditionally accepted NYSEG and RG&E’s application for CWIP and the 100% Abandoned Plant incentive (Abandoned Plant), subject to further compliance, for projects that are subject to subsequent permitting approval by the NYPSC under Article VII of New York State’s Public Service Law, effective July 8, 2024, and denied the application for CWIP and Abandoned Plant for projects not subject to Article VII permitting approval. On August 2, 2024, NYSEG and RG&E sought clarification, or in the alternative rehearing, of the July 5, 2024 order. Rehearing was denied after 30 days by operation of law, and the order denying rehearing states that the issue will be addressed in a future order. On October 1, FERC ruled on NYSEG and RG&E’s request for clarification/rehearing. FERC confirmed that any projects that receive state siting approval orders that include the required reliability and/or congestion reduction determinations can qualify for incentives, not limited to the projects listed in the July order as Article VII projects. FERC denied clarification and rehearing to include CWIP in rate base prior to FERC’s acceptance of the state siting orders. UI, CNG, SCG and BGC Rate Plans Under Connecticut law, The United Illuminating Company’s (UI) retail electricity customers are able to choose their electricity supplier while UI remains their electric distribution company. UI purchases power for those of its customers under standard service rates who do not choose a retail electric supplier and have a maximum demand of less than 500 kilowatts and its customers under supplier of last resort service for those who are not eligible for standard service and who do not choose to purchase electric generation service from a retail electric supplier. The cost of the power is a “pass-through” to those customers through the Generation Service Charge on their bills. UI has wholesale power supply agreements in place for its entire standard service load for 2024, 80% of the first half of 2025 and 20% of the second half of 2025. Supplier of last resort service is procured on a quarterly basis and UI has a wholesale power supply agreement in place for the first, second, third and fourth quarters of 2024. On September 9, 2022, UI filed a distribution revenue requirement case proposing a three-year rate plan commencing September 1, 2023 through August 31, 2026. The filing was based on a test year ending December 31, 2021, for the rate years beginning September 1, 2023 (UI Rate Year 1), September 1, 2024 (UI Rate Year 2), and September 1, 2025 (UI Rate Year 3). On August 25, 2023, PURA issued its Final Decision for a one-year rate plan commencing on September 1, 2023, providing for a rate increase of $23 million based on an allowed ROE of 9.1% that was reduced to 8.63% by certain adjustments. The Final Decision established a capital structure consisting of 50% common equity and 50% debt. The Final Decision results in an average increase in base distribution rates of about 6.6% and an average increase in customer bills of about 2% compared to current levels. On September 18, 2023, UI filed an appeal of the PURA's Final Decision in Connecticut Superior Court, because of factual and legal errors related to the treatment of deferred assets, plant in service, and operating expenses. We cannot predict the outcome of this matter. In 2017, PURA approved new tariffs for SCG effective January 1, 2018 for a three-year rate plan with annual rate increases. The new tariffs also include an RDM and Distribution Integrity Management Program (DIMP) mechanism, ESM, the amortization of certain regulatory liabilities (most notably accumulated hardship deferral balances and certain accumulated deferred income taxes) and tariff increases based on an ROE of 9.25% and an approximately 52.00% equity ratio. Any dollars due to customers from the ESM are to be first applied against any environmental regulatory asset balance as defined in the settlement agreement (if one exists at that time) or refunded to customers through a bill credit if such environmental regulatory asset balance does not exist. On September 30, 2024, UI filed a Notice of Intent to file an application between November 1 and 30, 2024, to adjust its rates and charges. The UI Application will propose to amend UI’s existing rate schedules effective November 1, 2025, in order to address a significant deficiency in distribution-related operating revenues. More specifically, the UI Application will propose a change in base distribution rates to be implemented in the rate year beginning November 1, 2025, with proposed rates designed to provide incremental operating revenues of approximately $105 million. UI’s Application is also expected to include several measures to moderate the impact of the proposed rate update for customers, including, a low-income discount rate to provide rate relief to UI’s disadvantaged customers, as well as proposing to continue an economic development rate to support continued commercial growth in UI’s service territory. We cannot predict the outcome of this matter. In 2018, PURA approved new tariffs for CNG effective January 1, 2019 for a three-year rate plan with annual rate increases. The new tariffs continued the RDM and DIMP mechanism. ESM and tariff increases are based on an ROE of 9.30% and an equity ratio of 54.00% in 2019, 54.50% in 2020 and 55.00% in 2021. On November 3, 2023, CNG and SCG filed a distribution revenue requirement case proposing a one-year rate plan commencing November 1, 2024 through October 31, 2025, for each company respectively. CNG requested that PURA approve new distribution rates to recover an increase in revenue requirements of approximately $19.8 million, and SCG requested approval of new distribution rates to recover an increase in revenue requirements of approximately $40.6 million. CNG’s and SCG’s rate plans also included several measures to moderate the impact of the proposed rate update for all customers, including, the adoption of a low-income discount rate and each company seeks to maintain their current revenue decoupling and earning sharing mechanisms. Evidentiary hearings commenced on April 22, 2024 and a draft decision was issued by PURA on October 4, 2024, providing for a rate decrease of $38.8 million and $36.6 million, respectively, for CNG and SCG, based on an allowed ROE of 9.2% for both companies. The Company currently is evaluating the draft decision, and expects to respond to PURA within the established timeframe. The final decision is expected in the fourth quarter of 2024 with new rates commencing November 1, 2024. We cannot predict the outcome of this matter. On June 24, 2022, BGC filed a Settlement Agreement with the Massachusetts Attorney General’s Office (AGO) for DPU approval negotiated between BGC and the AGO in lieu of a fully litigated rate case before the DPU. The Settlement Agreement allowed for agreed-upon adjustments to BGC’s revenue requirement as well as various step increases BGC shall be entitled to on January 1, 2023 and January 1, 2024. It provided for the opportunity to increase BGC’s revenue requirement by as much as $5.6 million over current rates (reflective of a 9.70% ROE and a 54.00% equity ratio as well as other stepped adjustments) through January 1, 2024. The Settlement Agreement was approved in its entirety by the DPU on October 27, 2022, and new rates went into effect January 1, 2023. Connecticut Energy Legislation On October 7, 2020, the Governor of Connecticut signed into law an energy bill that, among other things, instructs PURA to revise the rate-making structure in Connecticut to adopt performance-based rates for each electric distribution company, increases the maximum civil penalties assessable for failures in emergency preparedness, and provides for certain penalties and reimbursements to customers after storm outages greater than 96 hours and extends rate case timelines. Pursuant to the legislation, PURA opened a docket to consider the implementation of the associated customer compensation and reimbursement provisions in emergency events where customers were without power for more than 96 consecutive hours. On June 30, 2021, PURA issued a final decision implementing the legislative mandate to create a program pursuant to which residential customers will receive $25 for each day without power after 96 hours and also receive reimbursement of $250 for spoiled food and medicine. The decision emphasizes that no costs incurred in connection with this program are recoverable from customers. On June 29, 2023 the Governor of Connecticut signed SB7 into law, which included language that Level 1 storm events were exempt from the waiver. We will continue to review the requirements of the program for the next legislative session. PURA Investigation of the Preparation for and Response to the Tropical Storm Isaias and Connecticut Storm Reimbursement Legislation On August 6, 2020, PURA opened a docket to investigate the preparation for and response to Tropical Storm Isaias by the electric distribution companies in Connecticut including UI. Following hearings and the submission of testimony, PURA issued a final decision on April 15, 2021, finding that UI “generally met standards of acceptable performance in its preparation and response to Tropical Storm Isaias," subject to certain exceptions noted in the decision, but ordered a 15-basis point reduction to UI's ROE in its next rate case to incentivize better performance and indicated that penalties could be forthcoming in the penalty phase of the proceedings. On June 11, 2021, UI filed an appeal of PURA’s decision with the Connecticut Superior Court. On May 6, 2021, in connection with its findings in the Tropical Storm Isaias docket, PURA issued a Notice of Violation to UI for allegedly failing to comply with standards of acceptable performance in emergency preparation or restoration of service in an emergency and with orders of the Authority, and for violations of accident reporting requirements. PURA assessed a civil penalty in the total amount of approximately $2 million. PURA held a hearing on this matter and, in an order dated July 14, 2021, reduced the civil penalty to approximately $1 million. UI filed an appeal of PURA’s decision with the Connecticut Superior Court. This appeal and the appeal of PURA’s decision on the Tropical Storm Isaias docket have been consolidated. Following oral arguments in October 2022, the court denied UI’s appeal and affirmed PURA’s decisions in their entirety. UI filed a notice of appeal to Connecticut's Appellate court on November 7, 2022. This matter has been briefed and oral argument was held December 11, 2023. We cannot predict the outcome of this proceeding. Regulatory Assets and Liabilities The regulatory assets and regulatory liabilities shown in the tables below result from various regulatory orders that allow for the deferral and/or reconciliation of specific costs. Regulatory assets and regulatory liabilities are classified as current when recovery or refund in the coming year is allowed or required through a specific order or when the rates related to a specific regulatory asset or regulatory liability are subject to automatic annual adjustment. Regulatory assets as of September 30, 2024 and December 31, 2023, respectively, consisted of: September 30, December 31, As of 2024 2023 (Millions) Pension and other post-retirement benefits $ 450 $ 445 Pension and other post-retirement benefits cost deferrals 56 58 Storm costs 1,219 868 Rate adjustment mechanism 28 24 Revenue decoupling mechanism 105 86 Contracts for differences 24 38 Hardship programs 24 23 Deferred purchased gas 14 16 Environmental remediation costs 259 240 Debt premium 53 58 Unamortized losses on reacquired debt 16 17 Unfunded future income taxes 619 578 Federal tax depreciation normalization adjustment 126 130 Asset retirement obligation 20 19 Deferred meter replacement costs 59 59 COVID-19 cost recovery and late payment surcharge 10 12 Low income arrears forgiveness 39 55 Excess generation service charge 42 52 System Expansion 22 22 Non-bypassable charge 142 103 Hedge losses 14 34 Rate change levelization 95 60 Value of distributed energy resources 53 49 Uncollectible reserve 139 104 New York make-whole provision 63 96 Other 373 283 Total regulatory assets 4,064 3,529 Less: current portion 914 718 Total non-current regulatory assets $ 3,150 $ 2,811 “Pension and other post-retirement benefits” represent the actuarial losses on the pension and other post-retirement plans that will be reflected in customer rates when they are amortized and recognized in future pension expenses. “Pension and other post-retirement benefits cost deferrals” include the difference between actual expense for pension and other post-retirement benefits and the amount provided for in rates for certain of our regulated utilities. A portion of this balance is amortized through current rates, the remaining portion will be refunded in future periods through future rate cases. “Storm costs” for CMP, NYSEG, RG&E and UI are allowed in rates based on an estimate of the routine costs of service restoration. The companies are also allowed to defer unusually high levels of service restoration costs resulting from major storms when they meet certain criteria for severity and duration. A portion of this balance is amortized through current rates, and the remaining portion will be determined through future rate cases. “Rate adjustment mechanism” represents an interim rate change to return or collect certain defined reconciled revenues and costs for NYSEG and RG&E following the approval of the Joint Proposal by the NYPSC. The RAM, when triggered, is implemented in rates on July 1 of each year for return or collection over a twelve-month period. "Revenue decoupling mechanism" represents the mechanism established to disassociate the utility's profits from its delivery/commodity sales. “Contracts for Differences” represent the deferral of unrealized gains and losses on contracts for differences derivative contracts. The balance fluctuates based upon quarterly market analysis performed on the related derivatives. The amounts, which do not earn a return, are fully offset by a corresponding derivative asset/liability. “Hardship Programs” represent hardship customer accounts deferred for future recovery to the extent they exceed the amount in rates. “Deferred Purchased Gas” represents the difference between actual gas costs and gas costs collected in rates. “Environmental remediation costs” includes spending that has occurred and is eligible for future recovery in customer rates. Environmental costs are currently recovered through a reserve mechanism whereby projected spending is included in rates with any variance recorded as a regulatory asset or a regulatory liability. The amortization period will be established in future proceedings and will depend upon the timing of spending for the remediation costs. It also includes the anticipated future rate recovery of costs that are recorded as environmental liabilities since these will be recovered when incurred. Because no funds have yet been expended for the regulatory asset related to future spending, it does not accrue carrying costs and is not included within rate base. “Debt premium” represents the regulatory asset recorded to offset the fair value adjustment to the regulatory component of the non-current debt of UIL at the acquisition date. This amount is being amortized to interest expense over the remaining term of the related outstanding debt instruments. “Unamortized losses on reacquired debt” represent deferred losses on debt reacquisitions that will be recovered over the remaining original amortization period of the reacquired debt. “Unfunded future income taxes” represent unrecovered federal and state income taxes primarily resulting from regulatory flow through accounting treatment and are the offset to the unfunded future deferred income tax liability recorded. The income tax benefits or charges for certain plant related timing differences, such as removal costs, are immediately flowed through to, or collected from, customers. This amount is being amortized as the amounts related to temporary differences that give rise to the deferrals are recovered in rates. These amounts are being collected over a period of 46 years, and the NYPSC staff has initiated an audit, as required, of the unfunded future income taxes and other tax assets to verify the balances. “Federal tax depreciation normalization adjustment” represents the revenue requirement impact of the difference in the deferred income tax expense required to be recorded under the IRS normalization rules and the amount of deferred income tax expense that was included in cost of service for rate years covering 2011 forward. The recovery period in New York is from 25 to 35 years and for CMP 32.5 years beginning in 2020. “Asset retirement obligations” represents the differences in timing of the recognition of costs associated with our AROs and the collection of such amounts through rates. This amount is being amortized at the related depreciation and accretion amounts of the underlying liability. “Deferred meter replacement costs” represent the deferral of the book value of retired meters which were replaced or are planned to be replaced by AMI meters. This amount is being amortized over the initial depreciation period of related retired meters. "COVID-19 cost recovery and late payment surcharge" represents: a) deferred COVID-19-related costs in the state of Connecticut based on the order issued by PURA on April 29, 2020, requiring utilities to track COVID-19-related expenses and lost revenue and create a regulatory asset, and b) deferred lost late payment revenue in the state of New York based on the order issued by the NYPSC on June 17, 2022, approving a deferral and surcharge/sur-credit mechanism to recover/return deferred balances starting July 1, 2022. “Low-income arrears forgiveness” represents deferred bill credits in the state of New York based on the order issued by the NYPSC on June 16, 2022, approving deferral of bill credits for low-income customers and recovery of regulatory assets from all customers over five years for RG&E and three years for NYSEG. Surcharge started August 1, 2022. “Excess generation service charge” represents deferred generation-related costs or revenues for future recovery from or return to customers. The amount fluctuates based upon timing differences between revenues collected from rates and actual costs incurred. “System expansion” represents expenses not covered by system expansion rates related to expanding the natural gas system and converting customers to natural gas. “Non-bypassable charges” represent non-bypassable federally mandated congestion costs or revenues for future recovery from or return to customers. The amount fluctuates based upon timing differences between revenues collected from rates and actual costs incurred. “Hedge losses” represents the deferred fair value losses on electric and gas hedge contracts. “Rate change levelization" adjusts the New York delivery rate increases across the three-year plan to avoid unnecessary spikes and offsetting dips in customer rates. A portion of this balance is amortized through current rates, the remaining portion will be refunded in future periods through future rate cases. “Value of distributed energy resources” represents the mechanism to compensate for energy created by distributed energy resources, such as solar. “Uncollectible reserve” includes the anticipated future rate recovery of costs that are recorded as uncollectible since those will be recovered when incurred. Because no funds have yet been expended for the regulatory asset related to future uncollectible expense, it does not accrue carrying costs and is not included within rate base. It also includes the variance between actual uncollectible expense and uncollectible expense included in rates that is eligible for future recovery in customer rates. The amortization period will be established in future proceedings. “New York make-whole provision” represents the regulatory asset to recover revenues that would have been received by NYSEG/RGE had Rate Year 1 rates approved in the 22-E-0317 et al. joint proposal gone into effect on the effective date of May 1, 2023. The balance is being recovered through a separately stated make-whole rate, effective November 1, 2022, over 6-30 months. “Other” includes various items subject to reconciliation including vegetation management, systems benefit charge and transmission reconciliations. Regulatory liabilities as of September 30, 2024 and December 31, 2023, respectively, consisted of: September 30, December 31, As of 2024 2023 (Millions) Energy efficiency portfolio standard $ 23 $ 15 Gas supply charge and deferred natural gas cost 1 8 Pension and other post-retirement benefits cost deferrals 96 89 Carrying costs on deferred income tax bonus depreciation 1 3 Carrying costs on deferred income tax - Mixed Services 263(a) 1 2 2017 Tax Act 1,152 1,190 Accrued removal obligations 1,124 1,139 Positive benefit adjustment 4 9 Deferred property tax 23 21 Net plant reconciliation 21 23 Debt rate reconciliation 10 18 Rate refund – FERC ROE proceeding 41 39 Transmission congestion contracts 20 26 Merger-related rate credits 6 8 Accumulated deferred investment tax credits 19 21 Asset retirement obligation 19 19 Middletown/Norwalk local transmission network service collections 15 16 Non-firm margin sharing credits 43 34 Non by-passable charges 5 9 Transmission revenue reconciliation mechanism 4 57 Other 164 209 Total regulatory liabilities 2,792 2,955 Less: current portion 156 261 Total non-current regulatory liabilities $ 2,636 $ 2,694 “Energy efficiency portfolio standard” represents the costs of energy efficiency programs deferred for future recovery to the extent they exceed the amount in rates. A portion of this balance is amortized through current rates, the remaining portion will be refunded in future periods through future rate cases. “Gas supply charge and deferred natural gas cost" reflects the actual costs of purchasing, transporting and storing of natural gas. Gas supply reconciliation is determined by comparing actual gas supply expenses to the monthly gas cost recoveries in rates. Prior rate year balances are collected/returned to customers beginning the next calendar year. “Pension and other postretirement benefits cost deferrals” include the difference between actual expense for pension and other post-retirement benefits and the amount provided for in rates for certain of our regulated utilities. A portion of this balance is amortized through current rates, the remaining portion will be refunded in future periods through future rate cases. “Carrying costs on deferred income tax bonus depreciation” represent the carrying costs benefit of increased accumulated deferred income taxes created by the change in tax law allowing bonus depreciation. A portion of this balance is amortized through current rates, the remaining portion will be refunded in future periods through future rate cases. "Carrying costs on deferred income tax - Mixed Services 263(a)" represent the carrying costs benefit of increased accumulated deferred income taxes created by Section 263 (a) IRC. A portion of this balance is amortized through current rates, the remaining portion will be refunded in future periods through future rate cases. “2017 Tax Act” represents the impact from remeasurement of deferred income tax balances as a result of the Tax Act enacted by the U.S. federal government on December 22, 2017. Reductions in accumulated deferred income tax balances due to the reduction in the corporate income tax rates from 35% to 21% under the provisions of the Tax Act will result in amounts previously and currently collected from utility customers for these deferred taxes to be refundable to such customers, generally through reductions in future rates. The NYPSC, MPUC, PURA, DPU and the FERC held separate proceedings in New York, Maine, Connecticut, Massachusetts and the FERC, respectively, and for the majority of our regulated utilities, authorized the amortization periods for the return of regulatory liabilities and the recovery of regulatory assets, including the authorization of sur-credits to return the related benefits to rate payers in certain jurisdictions. “Accrued removal obligations” represent the differences between asset removal costs recorded and amounts collected in rates for those costs. The amortization period is dependent upon the asset removal costs of underlying assets and the life of the utility plant. “Positive benefit adjustment” resulted from Iberdrola’s 2008 acquisition of Avangrid (formerly Energy East Corporation). This is being used to moderate increases in rates. A portion of this balance is amortized through current rates, the remaining portion will be refunded in future periods through future rate cases. “Deferred property tax” represents the difference between actual expense for property taxes recoverable from customers and the amount provided for in rates . A portion of this balance is amortized through current rates, the remaining portion will be refunded in future periods through future rate cases. “Net plant reconciliation” represents the reconciliation of the actual el |
