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 a regulatory order for the specific costs does not exist, 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, 2021, the total net amount of these items is an asset of approximately $1,306 million.

In an order issued on February 19, 2020, the MPUC authorized an increase in CMP's distribution revenue requirement of $17 million, or approximately 7.00%, based on an allowed ROE of 9.25% and a 50.00% equity ratio. The rate increase was effective March 1, 2020. The MPUC also imposed a 1.00% ROE reduction (to 8.25%) for management efficiency associated with CMP’s customer service performance following the implementation of its new billing system in 2017. The management efficiency adjustment will remain in effect until CMP has demonstrated satisfactory customer service performance on four specified service quality measures for a rolling average period of 18 months, which commenced on March 1, 2020. CMP has met the required rolling average benchmarks for all four of these quality measures and on September 20, 2021, filed with the MPUC a request for removal of the management efficiency adjustment. In addition to requesting the lifting of the management efficiency adjustment, CMP requested an accounting order to allow it to defer for future recovery the revenues it would effectively lose by not having the adjustment lifted by September 1, 2021.

The order provided additional funding for staffing increases, vegetation management programs and storm restoration costs, while retaining the basic tiered structure for storm cost recovery implemented in the 2014 stipulation. The MPUC order also retained the RDM implemented in 2014. The order denied CMP’s request to increase rates for higher costs associated with services provided by its affiliates and ordered the initiation of a management audit to evaluate whether CMP's current management structure, and the management and other services from its affiliates, are appropriate and in the interest of Maine customers. On July 12, 2021, the management audit report was issued and recommended retaining the current cap on management service costs. The report identified CMP's progress in delivering on several operational outcomes for its customers and recommended additional opportunities for improvement.

On November 19, 2020, the NYPSC approved a new three-year rate plan for NYSEG & RG&E (2020 Joint Proposal), with modifications to the rate increases at the two electric businesses. The effective date of new tariffs was December 1, 2020 with a make-whole provision back to April 17, 2020. The approved rates facilitate the companies’ transition to a cleaner energy future while allowing for important initiatives such as COVID-19 relief for customers and additional funding for vegetation management, hardening/resiliency and emergency preparedness. The rate plans continue the RAM designed to return or collect

certain defined reconciled revenues and costs, have new depreciation rates and continue existing RDMs for each business. The 2020 Joint Proposal bases delivery revenues on an 8.80% ROE and 48.00% equity ratio; however, for the earnings sharing mechanism (ESM), the equity ratio is the lower of the actual equity ratio or 50.00%. The below table provides a summary of the approved delivery rate increases and delivery rate percentages, including rate levelization and excluding energy efficiency, which is a pass-through, for all four businesses. Rate years 2 and 3 commence on May 1, 2021 and 2022, respectively.


	Year 1				Year 2				Year 3
	Rate Increase		Delivery Rate %		Rate Increase		Delivery Rate %		Rate Increase		Delivery Rate %
Utility	(Millions)		Increase		(Millions)		Increase		(Millions)		Increase
NYSEG Electric	$	34	4.6	%	$	46	5.9	%	$	36	4.2	%
NYSEG Gas	$	—	—	%	$	2	0.8	%	$	3	1.6	%
RG&E Electric	$	17	3.8	%	$	14	3.2	%	$	16	3.3	%
RG&E Gas	$	—	—	%	$	—	—	%	$	2	1.3	%

In 2016, the Connecticut Public Utilities Regulatory Authority (PURA) approved new distribution rate schedules for The United Illuminating Company (UI) for three years, which became effective January 1, 2017 and, among other things, provide for annual tariff increases and an ROE of 9.10% based on a 50.00% equity ratio, continued UI’s existing ESM pursuant to which UI and its customers share on a 50/50 basis all distribution earnings above the allowed ROE in a calendar year, continued the existing decoupling mechanism and approved the continuation of the requested storm reserve. Any dollars due to customers from the ESM continue to be first applied against any storm regulatory asset balance (if one exists at that time) or refunded to customers through a bill credit if such storm regulatory asset balance does not exist.

In 2017, PURA approved new tariffs for the Southern Connecticut Gas Company (SCG) effective January 1, 2018. 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 equity ratio of approximately 52.00%. Any dollars due to customers from the ESM will 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.

In 2018, PURA approved new tariffs for Connecticut Natural Gas Corporation (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.

In 2019, the Massachusetts Department of Public Utilities (DPU) approved new distribution rates for BGC. The distribution rate increase is based on a 9.70% ROE and 54.00% equity ratio. The new tariffs provide for the implementation of an RDM and pension expense tracker and also provide that BGC will not file to change base distribution rates to become effective before November 1, 2021.

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, on October 30, 2020, PURA reopened a docket related to new rate design and review, expanding the scope to consider (a) the implementation of an interim rate decrease; (b) low income rates; and (c) economic development rates. Separately, UI was due to make its annual RAM filing on March 8, 2021 for the approval of its RAM Rate Components reconciliations: Generation Services Charges, By-passable Federally Mandated Congestion Costs, System Benefits Charge, Transmission Adjustment Charge and RDM.

On March 9, 2021, UI, jointly with the Office of the CT Attorney General, the Office of CT Consumer Counsel, DEEP and PURA’s Office of Education, Outreach, and Enforcement entered into a settlement agreement and filed a motion to approve the settlement agreement, which addressed issues in both dockets.

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. The Company is reviewing the requirements of this program and evaluating next steps.

On August 6, 2020, the 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 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 $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. We cannot predict the outcome of these appeals.

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.


	September 30,		December 31,
As of	2021		2020
(Millions)
Pension and other post-retirement benefits	$	814	$	927
Pension and other post-retirement benefits cost deferrals	100		105
Storm costs	453		451
Rate adjustment mechanism	41		33
Revenue decoupling mechanism	53		58
Transmission revenue reconciliation mechanism	38		31
Contracts for differences	77		86
Hardship programs	22		20
Plant decommissioning	2		3
Deferred purchased gas	22		30
Deferred transmission expense	11		26
Environmental remediation costs	263		247
Debt premium	77		83
Unamortized losses on reacquired debt	23		26
Unfunded future income taxes	401		373
Federal tax depreciation normalization adjustment	144		148
Asset retirement obligation	21		21
Deferred meter replacement costs	42		33
COVID-19 cost recovery	20		1
Other	216		180
Total regulatory assets	2,840		2,882
Less: current portion	340		310
Total non-current regulatory assets	$	2,500	$	2,572

“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. The RAM, when triggered, is implemented in rates on July 1 of each year for return or collection over a twelve-month period.

“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 associated with allowable costs 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.

“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 forty-six 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” (ARO) 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 advanced metering infrastructure meters. This amount is being amortized over the initial depreciation period of related retired meters.


	September 30,		December 31,
As of	2021		2020
(Millions)
Energy efficiency portfolio standard	$	46	$	58
Gas supply charge and deferred natural gas cost	3		3
Pension and other post-retirement benefits cost deferrals	49		59
Carrying costs on deferred income tax bonus depreciation	27		34
Carrying costs on deferred income tax - Mixed Services 263A	8		11
2017 Tax Act	1,366		1,435
Rate Change Levelization	98		55
Revenue decoupling mechanism	20		9
Accrued removal obligations	1,195		1,184
Asset sale gain account	3		7
Economic development	28		28
Positive benefit adjustment	24		30
Theoretical reserve flow thru impact	7		10
Deferred property tax	24		31
Net plant reconciliation	17		20
Debt rate reconciliation	53		63
Rate refund – FERC ROE proceeding	35		33
Transmission congestion contracts	22		22
Merger-related rate credits	12		14
Accumulated deferred investment tax credits	24		25
Asset retirement obligation	18		18
Earning sharing provisions	14		17
Middletown/Norwalk local transmission network service collections	17		18
Low income programs	29		28
Non-firm margin sharing credits	20		14
New York 2018 winter storm settlement	6		9
Hedge gains	88		—
Other	168		176
Total regulatory liabilities	3,421		3,411
Less: current portion	367		274
Total non-current regulatory liabilities	$	3,054	$	3,137

“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. The amortization period in current rates is three years and began in 2020.

"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. The amortization period in current rates is three years and began in 2020.

"Carrying costs on deferred income tax - Mixed Services 263A" represent the carrying costs benefit of increased accumulated deferred income taxes created by IRC Section 263A. A portion of this balance is amortized through current rates, the remaining portion will be refunded in future periods through future rate cases. The amortization period in current rates is three years and began in 2020.

“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 resulted 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 and DPU instituted separate proceedings in New York, Maine, Connecticut and Massachusetts, respectively, that addressed the implications associated with the Tax Act on the utilities providing service in such states.

"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. The amortization period in current rates is five years and began in 2020.

“Economic development” represents the economic development program, which enables NYSEG and RG&E to foster economic development through attraction, expansion and retention of businesses within its service territory. If the level of actual expenditures for economic development allocated to NYSEG and RG&E varies in any rate year from the level provided for in rates, the difference is refunded to customers. A portion of this balance is amortized through current rates, the remaining portion will be refunded in future periods through future rate cases. The amortization period in current rates is three years and began in 2020.

“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. The amortization period in current rates is three years and began in 2020.

“Theoretical reserve flow thru impact” represents the differences from the rate allowance for applicable federal and state flow- through impacts related to the excess depreciation reserve amortization. It also represents the carrying cost on the differences. A portion of this balance is amortized through current rates, the remaining portion will be refunded in future periods through future rate cases. The amortization period in current rates is three to five years and began in 2020.

"Deferred property tax" represents the difference between actual expense for property taxes recoverable from customers and the amount provided 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. The amortization period in current rates is five years and began in 2020.

"Net plant reconciliation" represents the reconciliation of the actual electric and gas net plant and book depreciation to the targets set forth in the 2020 Joint Proposal. A portion of this balance is amortized through current rates, the remaining portion will be refunded in future periods through future rate cases. The amortization period in current rates is five years and began in 2020.

"Transmission congestion contracts" represents deferral of the Nine Mile 2 Nuclear Plant transmission congestion contract at RG&E. A portion of this balance is amortized through current rates; the remaining portion will be refunded in future periods through future rate cases. The amortization period in current rates is five years and began in 2020.

“Merger-related rate credits” resulted from the acquisition of UIL. This is being used to moderate increases in rates. During both the three and nine months ended September 30, 2021 and 2020, $1 million and $2 million, respectively, of rate credits were applied against customer bills.

"Asset retirement obligation" 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.

"New York 2018 winter storm settlement" represents the settlement amount with the NYPSC following the comprehensive investigation of New York’s major utility companies’ preparation and response to March 2018 storms. The balance is being amortized through current rates over a period of three years, ending in 2023.