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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, DC 20549
FORM 10-Q
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended March 31, 2024
Or
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from                   to                  i
Commission File No. 001-37660
AGR2023.jpg
Avangrid, Inc.
(Exact Name of Registrant as Specified in its Charter)
New York14-1798693
(State or other jurisdiction of incorporation or organization)(I.R.S. Employer Identification No.)
180 Marsh Hill Road
Orange,Connecticut06477
(Address of principal executive offices)(Zip Code)
Registrant’s telephone number, including area code: (207) 629-1190
Securities registered pursuant to Section 12(b) of the Act:
Title of each classTrading SymbolName of exchange on which registered
Common Stock, par value $0.01 per shareAGRNew York Stock Exchange
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes      No  
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).    Yes      No  
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.  
Large Accelerated FilerAccelerated Filer
Non-accelerated FilerSmaller Reporting Company
Emerging Growth Company  
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. 
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes      No  
As of April 23, 2024, the registrant had 386,906,260 shares of common stock, par value $0.01, outstanding.



Avangrid, Inc.
REPORT ON FORM 10-Q
For the Quarter Ended March 31, 2024
INDEX
 
2


GLOSSARY OF TERMS AND ABBREVIATIONS
Unless the context indicates otherwise, the terms “we,” “our” and the “Company” are used to refer to Avangrid, Inc. and its subsidiaries.
2023 Joint ProposalJoint proposal of NYSEG and RG&E and certain other signatory parties approved by the NYPSC on October 12, 2023, for a three-year rate plan for electric and gas service with effective date November 1, 2023.
AOCI Accumulated other comprehensive income
ARHI Avangrid Renewables Holdings, Inc.
ARP Alternative Revenue Programs
ASC Accounting Standards Codification
Avangrid Avangrid, Inc.
BGC The Berkshire Gas Company
PBR
Performance-Based Regulation
CAIDICustomer Average Interruption Duration Index
CfDs Contracts for Differences
CBPU.S. Customs and Border Protection
CFIUSCommittee on Foreign Investment in the United States
CL&P The Connecticut Light and Power Company
CMP Central Maine Power Company
CNG Connecticut Natural Gas Corporation
DEEP Connecticut Department of Energy and Environmental Protection
DIMP Distribution Integrity Management Program
DOCDepartment of Commerce
DPA Deferred Payment Arrangements
DPUMassachusetts Department of Public Utilities
EBITDA Earnings before interest, taxes, depreciation and amortization
ESM Earnings sharing mechanism
English StationThe former generation site on the Mill River in New Haven, Connecticut
Exchange Act The Securities Exchange Act of 1934, as amended
FASB Financial Accounting Standards Board
FCCFederal Communications Commission
FERC Federal Energy Regulatory Commission
FirstEnergy FirstEnergy Corp.
Form 10-K
Avangrid, Inc.’s Annual Report on Form 10-K for the year ended December 31, 2023, filed with the Securities and Exchange Commission on February 22, 2024.
HLBV Hypothetical Liquidation at Book Value
HSR
Hart-Scott-Rodino Antitrust Improvements Act of 1976
IRAInflation Reduction Act
IberdrolaIberdrola, S.A.
Iberdrola GroupThe group of companies controlled by Iberdrola, S.A.
Installed capacityThe production capacity of a power plant or wind farm based either on its rated (nameplate) capacity or actual capacity.
ISO Independent system operator
Klamath PlantKlamath gas-fired cogeneration facility located in the city of Klamath, Oregon.
KWKilowatts
MNG Maine Natural Gas Corporation
MPUC Maine Public Utility Commission
MtM Mark-to-market
MW Megawatts
MWh Megawatt-hours
NECECNew England Clean Energy Connect
Networks Avangrid Networks, Inc.
Non-GAAPFinancial measures that are not prepared in accordance with U.S. GAAP, including adjusted net income, adjusted earnings per share, adjusted EBITDA and adjusted EBITDA with tax credits.
NRCNuclear Regulatory Commission
NYPSC New York State Public Service Commission
NYSENew York Stock Exchange
NYSEG New York State Electric & Gas Corporation
NYSERDA New York State Energy Research and Development Authority
OCI Other comprehensive income
PJM PJM Interconnection, L.L.C.
PURA Connecticut Public Utilities Regulatory Authority
Renewables Avangrid Renewables, LLC
RDM Revenue Decoupling Mechanism
RG&E Rochester Gas and Electric Corporation
ROE Return on equity
SAIFISystem Average Interruption Frequency Index
SCG The Southern Connecticut Gas Company
SEC United States Securities and Exchange Commission
SOFRSecured Overnight Financing Rate
Tax Act Tax Cuts and Jobs Act of 2017 enacted by the U.S. federal government on December 22, 2017
TEF Tax equity financing arrangements
UFLPAUyghur Forced Labor Prevention Act
UI The United Illuminating Company
UIL UIL Holdings Corporation
U.S. GAAP Generally accepted accounting principles for financial reporting in the United States.
VIEs Variable interest entities
3


PART I. FINANCIAL INFORMATION

Item 1. Financial Statements
Avangrid, Inc. and Subsidiaries
Condensed Consolidated Statements of Income
(unaudited)
 
Three Months Ended March 31,
 20242023
(Millions, except for number of shares and per share data)  
Operating Revenues$2,417 $2,466 
Operating Expenses
Purchased power, natural gas and fuel used724 977 
Operations and maintenance792 761 
Depreciation and amortization298 280 
Taxes other than income taxes196 183 
Total Operating Expenses2,010 2,201 
Operating Income407 265 
Other Income and (Expense)  
Other income54 25 
Earnings from equity method investments6 2 
Interest expense, net of capitalization(125)(95)
Income Before Income Tax342 197 
Income tax expense (benefit)20 (18)
Net Income322 215 
Net loss attributable to noncontrolling interests29 30 
Net Income Attributable to Avangrid, Inc.$351 $245 
Earnings Per Common Share, Basic$0.91 $0.63 
Earnings Per Common Share, Diluted$0.91 $0.63 
Weighted-average Number of Common Shares Outstanding:
  
Basic386,916,234 386,744,996 
Diluted387,239,544 387,077,213 
The accompanying notes are an integral part of our condensed consolidated financial statements.
4


Avangrid, Inc. and Subsidiaries
Condensed Consolidated Statements of Comprehensive Income
(unaudited)
 
Three Months Ended March 31,
 20242023
(Millions)  
Net Income$322 $215 
Other Comprehensive Income
Unrealized loss from equity method investment, net of income taxes of $0 and $0, respectively
 (1)
Unrealized gain (loss) during the period on derivatives qualifying as cash flow hedges, net of income tax of $15 and $(1), respectively
39 (2)
Reclassification to net income of loss on cash flow hedges, net of income taxes $2 and $18, respectively
7 52 
Other Comprehensive Income 46 49 
Comprehensive Income368 264 
Net loss attributable to noncontrolling interests29 30 
Comprehensive Income Attributable to Avangrid, Inc.$397 $294 
The accompanying notes are an integral part of our condensed consolidated financial statements.
5


Avangrid, Inc. and Subsidiaries
Condensed Consolidated Balance Sheets
(unaudited)
 
 March 31,December 31,
As of20242023
(Millions)  
Assets  
Current Assets  
Cash and cash equivalents$152 $91 
Accounts receivable and unbilled revenues, net1,640 1,588 
Accounts receivable from affiliates5 11 
Notes receivable from affiliates4 4 
Derivative assets87 68 
Fuel and gas in storage169 185 
Materials and supplies321 310 
Prepayments and other current assets496 429 
Regulatory assets745 718 
Total Current Assets3,619 3,404 
Total Property, Plant and Equipment ($2,621 and $2,643 related to VIEs, respectively)
33,323 32,857 
Operating lease right-of-use assets204 195 
Equity method investments836 718 
Other investments49 46 
Regulatory assets3,061 2,811 
Other Assets
Goodwill3,119 3,119 
Intangible assets280 284 
Derivative assets185 162 
Other386 393 
Total Other Assets3,970 3,958 
Total Assets$45,062 $43,989 
The accompanying notes are an integral part of our condensed consolidated financial statements.
6


Avangrid, Inc. and Subsidiaries
Condensed Consolidated Balance Sheets
(unaudited)
 March 31,December 31,
As of20242023
(Millions, except share information)  
Liabilities  
Current Liabilities  
Current portion of debt$729 $612 
Notes payable1,862 1,347 
Notes payable to affiliates515 13 
Interest accrued116 104 
Accounts payable and accrued liabilities1,769 1,924 
Accounts payable to affiliates18  
Dividends payable171 170 
Taxes accrued88 66 
Operating lease liabilities15 16 
Derivative liabilities66 64 
Other current liabilities584 662 
Regulatory liabilities275 261 
Total Current Liabilities6,208 5,239 
Regulatory liabilities2,676 2,694 
Other Non-current Liabilities
Deferred income taxes2,501 2,451 
Deferred income979 996 
Pension and other postretirement546 554 
Operating lease liabilities208 199 
Derivative liabilities116 111 
Asset retirement obligations310 306 
Environmental remediation costs243 254 
Other527 525 
Total Other Non-current Liabilities5,430 5,396 
Non-current debt9,059 9,184 
Non-current debt to affiliate800 800 
Total Non-current Liabilities17,965 18,074 
Total Liabilities24,173 23,313 
Commitments and Contingencies  
Equity  
Stockholders’ Equity:  
Common stock, $.01 par value, 500,000,000 shares authorized, 388,008,132 and 387,872,787 shares issued; 386,906,260 and 386,770,915 shares outstanding, respectively
4 4 
Additional paid in capital17,702 17,701 
Treasury stock(47)(47)
Retained earnings2,196 2,015 
Accumulated other comprehensive income (loss)21 (25)
Total Stockholders’ Equity19,876 19,648 
Non-controlling interests1,013 1,028 
Total Equity20,889 20,676 
Total Liabilities and Equity$45,062 $43,989 
The accompanying notes are an integral part of our condensed consolidated financial statements.
7


Avangrid, Inc. and Subsidiaries
Condensed Consolidated Statements of Cash Flows
(unaudited)
Three Months Ended March 31,
 20242023
(Millions)
Cash Flow from Operating Activities:
Net income$322 $215 
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization298 280 
Regulatory assets/liabilities amortization and carrying cost15 (32)
Pension cost(3)(3)
Earnings from equity method investments(6)(2)
Distributions of earnings received from equity method investments3 6 
Unrealized (gain) loss on marked-to-market derivative contracts(17)4 
Deferred taxes4 (1)
Other non-cash items(22)(5)
Changes in operating assets and liabilities:
Current assets(141)82 
Noncurrent assets(255)(96)
Current liabilities(32)(242)
Noncurrent liabilities(13)(2)
Net Cash Provided by Operating Activities153 204 
Cash Flow from Investing Activities:
Capital expenditures(872)(836)
Contributions in aid of construction40 19 
Proceeds from sale of assets2 6 
Proceeds from notes receivable from affiliates 1 
Distributions received from equity method investments2 2 
Other investments and equity method investments, net(116)(11)
Net Cash Used in Investing Activities(944)(819)
Cash Flow from Financing Activities:
Repayments of non-current debt(3)(4)
Receipts of other short-term debt, net514 722 
Receipts of other short-term debt with affiliates500  
Repayments of financing leases(1)(1)
Issuance of common stock(2) 
Distributions to noncontrolling interests(39)(3)
Contributions from noncontrolling interests53 74 
Dividends paid(170)(170)
Net Cash Provided by Financing Activities852 618 
Net Increase in Cash, Cash Equivalents and Restricted Cash61 3 
Cash, Cash Equivalents and Restricted Cash, Beginning of Period94 72 
Cash, Cash Equivalents and Restricted Cash, End of Period$155 $75 
Supplemental Cash Flow Information
Cash paid for interest, net of amounts capitalized$103 $56 
Cash paid (refunded) for income taxes$3 $(1)
The accompanying notes are an integral part of our condensed consolidated financial statements.
8


Avangrid, Inc. and Subsidiaries
Condensed Consolidated Statements of Changes in Equity
(unaudited)

Avangrid, Inc. Stockholders
(Millions, except for number of shares )Number of shares (*)Common StockAdditional paid-in capitalTreasury StockRetained EarningsAccumulated Other Comprehensive LossTotal Stockholders’ EquityNoncontrolling InterestsTotal
As of December 31, 2022386,628,586 $3 $17,694 $(47)$1,910 $(180)$19,380 $962 $20,342 
Net income (loss)— — — — 245 — 245 (30)215 
Other comprehensive loss, net of tax of $17
— — — — — 49 49 — 49 
Comprehensive income264 
Dividends declared, $0.44/share
— — — — (170)— (170)— (170)
Issuance of common stock12,332 — — — — — — — — 
Stock-based compensation— — 3 — — — 3 — 3 
Distributions to noncontrolling interests— — — — — — — (3)(3)
Contributions from noncontrolling interests— — — — — — 74 74 
As of March 31, 2023386,640,918 $3 $17,697 $(47)$1,985 $(131)$19,507 $1,003 $20,510 
As of December 31, 2023386,770,915 $4 $17,701 $(47)$2,015 $(25)$19,648 $1,028 $20,676 
Net income (loss)— — — — 351 — 351 (29)322 
Other comprehensive income, net of tax of $17
— — — — — 46 46 — 46 
Comprehensive income368 
Dividends declared, $0.44/share
— — — — (170)— (170)— (170)
Issuance of common stock135,345 — (2)— — — (2)— (2)
Stock-based compensation— — 3 — — — 3 — 3 
Distributions to noncontrolling interests— — — — — — — (39)(39)
Contributions from noncontrolling interests— — — — — — 53 53 
As of March 31, 2024386,906,260 $4 $17,702 $(47)$2,196 $21 $19,876 $1,013 $20,889 
(*) Par value of share amounts is $0.01
The accompanying notes are an integral part of our condensed consolidated financial statements.
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Avangrid, Inc. and Subsidiaries
Notes to Condensed Consolidated Financial Statements
(unaudited)
Note 1. Background and Nature of Operations
Avangrid, Inc. (Avangrid, we or the Company) is an energy services holding company engaged in the regulated energy transmission and distribution business through its principal subsidiary, Avangrid Networks, Inc. (Networks), and in the renewable energy generation business through its principal subsidiary, Avangrid Renewables Holding, Inc. (ARHI). ARHI in turn holds subsidiaries including Avangrid Renewables, LLC (Renewables). Iberdrola, S.A. (Iberdrola), a corporation organized under the laws of the Kingdom of Spain, owns 81.6% of the outstanding common stock of Avangrid. The remaining outstanding shares are owned by various shareholders, with approximately 14.7% of Avangrid's outstanding shares publicly-traded on the New York Stock Exchange (NYSE).
Non-binding proposal from Iberdrola
On March 6, 2024, the Unaffiliated Committee (Committee) of the Board of Directors of Avangrid received a non-binding proposal from Iberdrola to acquire all of the issued and outstanding shares of common stock not owned by Iberdrola or its affiliates for $34.25 in cash per share. The Committee will review, evaluate, negotiate, and approve or disapprove the proposal, advised by independent legal and financial advisers, as well as any other alternative proposals or other strategic alternatives that may be available to Avangrid. No decision has yet been made with respect to Avangrid’s response to the proposal or any alternatives thereto and there can be no assurance that any definitive offer will be made, that any agreement will be executed or that the transaction proposed in the proposal or any other transaction will be approved or completed. The consummation of the proposed transaction is conditioned upon the approval of the proposed transaction by the Committee and by the shareholders of Avangrid that hold in the aggregate a majority of the outstanding shares of common stock that are not held by Iberdrola and its affiliates.
Note 2. Basis of Presentation
The accompanying condensed consolidated financial statements should be read in conjunction with the Form 10-K for the fiscal year ended December 31, 2023.
The accompanying unaudited financial statements are prepared on a consolidated basis and include the accounts of Avangrid and its consolidated subsidiaries, Networks and ARHI. All intercompany transactions and accounts have been eliminated in consolidation. The year-end balance sheet data was derived from audited financial statements. The unaudited condensed consolidated financial statements for the interim periods have been prepared in accordance with accounting principles generally accepted in the United States of America (U.S. GAAP) for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X. Accordingly, the interim condensed consolidated financial statements do not include all the information and note disclosures required by U.S. GAAP for complete financial statements.
In the opinion of management, the accompanying condensed consolidated financial statements contain all adjustments necessary to present fairly our condensed consolidated financial statements for the interim periods described herein. All such adjustments are of a normal and recurring nature, except as otherwise disclosed. The results for the three months ended March 31, 2024, are not necessarily indicative of the results for the entire fiscal year ending December 31, 2024.
Note 3. Significant Accounting Policies and New Accounting Pronouncements
The new accounting pronouncements we have adopted as of January 1, 2024, and reflected in our condensed consolidated financial statements are described below. There have been no other material changes to the significant accounting policies described in our Form 10-K for the fiscal year ended December 31, 2023, except for those described below resulting from the adoption of new authoritative accounting guidance issued by the Financial Accounting Standards Board (FASB).
Adoption of New Accounting Pronouncements
(a) Improvements to Reportable Segment Disclosures
In November 2023, the FASB issued guidance requiring incremental disclosures for reportable segments. These incremental requirements include disclosing significant expenses that are regularly provided to the chief operating decision maker (CODM) and other segment items, including a description of its composition. The other segment items category is the difference between segment revenue less the significant segment expenses, and each reported measure of segment profit or loss. The guidance clarifies that if the CODM reviews multiple measures of a segments total profit or loss, that the entity may under certain conditions report multiple measures in the segment footnote; however, if only one measure is reported, it should be the one that
10


best conforms with U.S. GAAP. The guidance requires disclosure of the title and position of the individual or the name of the group identified as the CODM. Finally, all annual disclosures are required in interim reporting starting in the first quarter of 2025. As the guidance impacts disclosures only, it will not have an impact to the consolidated financial results. These changes in disclosures will initially be reflected in the annual financial statement footnotes for the year ended December 31, 2024.
Accounting Pronouncements Issued but Not Yet Adopted
The following are new significant accounting pronouncements not yet adopted, including those issued since December 31, 2023, that we have evaluated or are evaluating to determine their effect on our condensed consolidated financial statements.
(a) Improvements to Income Tax Disclosures
In December 2023, the FASB issued guidance to enhance income tax disclosures. The standard is required to be adopted by public business entities for annual periods beginning after December 15, 2024. Early adoption is permitted. The two primary enhancements relate to disaggregation of the annual effective tax rate reconciliation and income taxes paid disclosures. For the rate reconciliation, it requires additional disaggregation of information in a tabular format using both percentages and amounts broken out into specific categories (e.g., state and local income tax net of federal income tax effect, foreign tax effects, effect of changes in tax laws, tax credits, changes in valuation allowances, nontaxable or nondeductible items, and changes in unrecognized tax benefits). For income taxes paid, it requires disaggregation by jurisdiction (e.g., federal, state and foreign). We do not expect the new guidance to have a material impact on our consolidated results of operations, financial position and cash flows.
Note 4. Revenue
We recognize revenue when we have satisfied our obligations under the terms of a contract with a customer, which generally occurs when the control of promised goods or services transfers to the customer. We measure revenue as the amount of consideration we expect to receive in exchange for providing those goods or services. Contracts with customers may include multiple performance obligations. For such contracts, we allocate revenue to each performance obligation based on its relative standalone selling price. We generally determine standalone selling prices based on the prices charged to customers. Certain revenues are not within the scope of the FASB issued ASC Topic 606, Revenue from Contracts with Customers (ASC 606), such as revenues from leasing, derivatives, other revenues that are not from contracts with customers and other contractual rights or obligations, and we account for such revenues in accordance with the applicable accounting standards. We exclude from revenue amounts collected on behalf of third parties, including any such taxes collected from customers and remitted to governmental authorities. We do not have any significant payment terms that are material because we receive payment at or shortly after the point of sale.
The following describes the principal activities, by reportable segment, from which we generate revenue. For more detailed information about our reportable segments, refer to Note 13.
Networks Segment
Networks derives its revenue primarily from tariff-based sales of electricity and natural gas service to customers in New York, Connecticut, Maine and Massachusetts with no defined contractual term. For such revenues, we recognize revenues in an amount derived from the commodities delivered to customers. Other major sources of revenue are electricity transmission and wholesale sales of electricity and natural gas.
Tariff-based sales are subject to the corresponding state regulatory authorities, which determine prices and other terms of service through the ratemaking process. The applicable tariffs are based on the cost of providing service. The utilities’ approved base rates are designed to recover their allowable operating costs, including energy costs, finance costs, and the costs of equity, the last of which reflect our capital ratio and a reasonable return on equity. We traditionally invoice our customers by applying approved base rates to usage. Maine state law prohibits the utility from providing the electricity commodity to customers. In New York, Connecticut and Massachusetts, customers have the option to obtain the electricity or natural gas commodity directly from the utility or from another supplier. For customers that receive their commodity from another supplier, the utility acts as an agent and delivers the electricity or natural gas provided by that supplier. Revenue in those cases is only for providing the service of delivery of the commodity. Networks entities calculate revenue earned but not yet billed based on the number of days not billed in the month, the estimated amount of energy delivered during those days and the estimated average price per customer class for that month. Differences between actual and estimated unbilled revenue are immaterial.
Transmission revenue results from others’ use of the utility’s transmission system to transmit electricity and is subject to FERC regulation, which establishes the prices and other terms of service. Long-term wholesale sales of electricity are based on individual bilateral contracts. Short-term wholesale sales of electricity are generally on a daily basis based on market prices and are administered by the Independent System Operator-New England (ISO-NE) and the New York Independent System
11


Operator (NYISO) or PJM Interconnection, L.L.C. (PJM), as applicable. Wholesale sales of natural gas are generally short-term based on market prices through contracts with the specific customer.
The performance obligation in all arrangements is satisfied over time because the customer simultaneously receives and consumes the benefits as Networks delivers or sells the electricity or natural gas or provides the delivery or transmission service. We record revenue for all of such sales based upon the regulatory-approved tariff and the volume delivered or transmitted, which corresponds to the amount that we have a right to invoice. There are no material initial incremental costs of obtaining a contract in any of the arrangements. Networks does not adjust the promised consideration for the effects of a significant financing component if it expects, at contract inception, that the time between the delivery of promised goods or service and customer payment will be one year or less. For its New York and Connecticut utilities, Networks assesses its DPAs at each balance sheet date for the existence of significant financing components, but has had no material adjustments as a result.
Certain Networks entities record revenue from Alternative Revenue Programs (ARPs), which is not ASC 606 revenue. Such programs represent contracts between the utilities and their regulators. The Networks ARPs include revenue decoupling mechanisms (RDMs), other ratemaking mechanisms, annual revenue requirement reconciliations and other demand side management programs. The Networks entities recognize and record only the initial recognition of “originating” ARP revenues (when the regulatory-specified conditions for recognition have been met). When they subsequently include those amounts in the price of utility service billed to customers, they record such amounts as a recovery of the associated regulatory asset or liability. When they owe amounts to customers in connection with ARPs, they evaluate those amounts on a quarterly basis and include them in the price of utility service billed to customers and do not reduce ARP revenues.
Networks also has various other sources of revenue including billing, collection, other administrative charges, sundry billings, rent of utility property and miscellaneous revenue. It classifies such revenues as other ASC 606 revenues to the extent they are not related to revenue generating activities from leasing, derivatives or ARPs.
Renewables Segment
Renewables derives its revenue primarily from the sale of energy, transmission, capacity and other related charges from its renewable wind, solar and thermal energy generating sources. For such revenues, we will recognize revenues in an amount derived from the commodities delivered and from services as they are made available. Renewables has bundled power purchase agreements consisting of electric energy, transmission, capacity and/or renewable energy credits (RECs). The related contracts are generally long-term with no stated contract amount, that is, the customer is entitled to all or a percentage of the unit’s output. Renewables also has unbundled sales of electric energy and capacity, RECs and natural gas, which are generally for periods of less than a year. The performance obligations in substantially all of both bundled and unbundled arrangements for electricity and natural gas are satisfied over time, for which we record revenue based on the amount invoiced to the customer for the actual energy delivered. The performance obligation for stand-alone RECs is satisfied at a point in time, for which we record revenue when the performance obligation is satisfied upon delivery of the REC. There are no significant financing elements in any of the arrangements. We recognize an asset for incremental costs of obtaining a contract with a customer when we expect the benefit of those costs to be longer than one year.
Renewables classifies certain contracts for the sale of electricity as derivatives, in accordance with the applicable accounting standards. Renewables also has revenue from its energy trading operations, which it generally classifies as derivative revenue. However, trading contracts not classified as derivatives are within the scope of ASC 606, with the performance obligation of the delivery of energy (electricity, natural gas) and settlement of the contracts satisfied at a point in time at which time we recognize the revenue. Renewables also has other ASC 606 revenue, which we recognize based on the amount invoiced to the customer.
Certain customers may receive cash credits, which we account for as variable consideration. Renewables estimates those amounts based on the expected amount to be provided to customers and reduces revenues recognized. We believe that there will not be significant changes to our estimates of variable consideration.
Other
Other, which does not represent a segment, includes miscellaneous Corporate revenues and intersegment eliminations.
Contract Assets and Liabilities
We have contract assets for costs from development success fees and construction delays, which were paid during solar farm assets development period. The contract assets are amortized ratably into expense over the 16 - 21 year life of the respective power purchase agreements (PPAs). Contract assets totaled $19 million and $9 million at  March 31, 2024 and December 31, 2023, respectively, and are presented in "Other non-current assets" on our condensed consolidated balance sheets.
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We have contract liabilities for revenue from transmission congestion contract (TCC) auctions, for which we receive payment at the beginning of an auction period, and amortize ratably each month into revenue over the applicable auction period. The auction periods range from six months to two years. TCC contract liabilities totaled $9 million and $18 million at March 31, 2024 and December 31, 2023, respectively, and are presented in "Other current liabilities" on our condensed consolidated balance sheets. We recognized $9 million and $17 million as revenue related to contract liabilities for the three months ended March 31, 2024 and 2023, respectively.
We apply a practical expedient to expense as incurred costs to obtain a contract when the amortization period is one year or less. We record costs incurred to obtain a contract within operating expenses, including amortization of capitalized costs.
Revenues disaggregated by major source for our reportable segments for the three months ended March 31, 2024 and 2023 are as follows:
Three Months Ended March 31, 2024
 NetworksRenewablesOther (b)Total
(Millions)
Regulated operations – electricity
$1,350 $ $ $1,350 
Regulated operations – natural gas
592   592 
Nonregulated operations – wind
 224  224 
Nonregulated operations – solar
 7  7 
Nonregulated operations – thermal
 91  91 
Other(a)20 (13)(1)6 
Revenue from contracts with customers
1,962 309 (1)2,270 
Leasing revenue2   2 
Derivative gains 87  87 
Alternative revenue programs
43   43 
Other revenue11 4  15 
Total operating revenues
$2,018 $400 $(1)$2,417 
Three Months Ended March 31, 2023
NetworksRenewablesOther (b)Total
(Millions)
Regulated operations – electricity
$1,308 $ $ $1,308 
Regulated operations – natural gas
722   722 
Nonregulated operations – wind
 216  216 
Nonregulated operations – solar
 4  4 
Nonregulated operations – thermal
 55  55 
Other(a)(3)(13) (16)
Revenue from contracts with customers
2,027 262  2,289 
Leasing revenue2   2 
Derivative gains 122  122 
Alternative revenue programs
37   37 
Other revenue10 6  16 
Total operating revenues
$2,076 $390 $ $2,466 
(a) Primarily includes certain intra-month trading activities, billing, collection and administrative charges, sundry billings and other miscellaneous revenue.
(b) Does not represent a segment. Includes Corporate and intersegment eliminations.
As of March 31, 2024 and December 31, 2023, accounts receivable balances related to contracts with customers were approximately $1,529 million and $1,441 million, respectively, including $426 million of unbilled revenues as of both March 31, 2024 and December 31, 2023, which are included in “Accounts receivable and unbilled revenues, net” on our condensed consolidated balance sheets.
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As of March 31, 2024, the aggregate amount of the transaction price allocated to performance obligations that are unsatisfied (or partially unsatisfied) were as follows:
As of March 31, 202420252026202720282029ThereafterTotal
(Millions)       
Revenue expected to be recognized on multiyear capacity and carbon-free energy sale contracts
30 10 7 5 5 49 106 
Revenue expected to be recognized on multiyear renewable energy credit sale contracts
72 48 26 3 1 1 151 
Total operating revenues$102 $58 $33 $8 $6 $50 $257 
As of March 31, 2024, the aggregate amount of the transaction price allocated to performance obligations that are unsatisfied (or partially unsatisfied) for the remainder of 2024 was $116 million.
We do not disclose information about remaining performance obligations for contracts for which we recognize revenue in the amount to which we have the right to invoice (e.g., usage-based pricing terms).
Note 5. 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 March 31, 2024, the total net amount of these items is approximately $1,157 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, 2023. The next two increases will occur on July 1, 2024, and 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 forecast 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 Earnings Sharing Mechanism (ESM) applicable to each business 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 will be used to reduce NYSEG's and RG&E’s respective outstanding regulatory asset deferral balances. In addition,
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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 Federal Energy Regulatory Commission (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.
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 the first half of 2024 and 50% of the second half of 2024. Supplier of last resort service is procured on a quarterly basis and UI has a wholesale power supply agreement in place for the first quarter 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 provided 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.
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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 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 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 seeks to maintain its current revenue decoupling and earning sharing mechanisms. Evidentiary hearings commenced on April 22, 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
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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 March 31, 2024 and December 31, 2023, respectively, consisted of:
March 31,December 31,
As of20242023
(Millions)
Pension and other post-retirement benefits$439 $445 
Pension and other post-retirement benefits cost deferrals57 58 
Storm costs1,052 868 
Rate adjustment mechanism42 24 
Revenue decoupling mechanism101 86 
Contracts for differences33 38 
Hardship programs25 23 
Deferred purchased gas6 16 
Environmental remediation costs244 240 
Debt premium57 58 
Unamortized losses on reacquired debt17 17 
Unfunded future income taxes601 578 
Federal tax depreciation normalization adjustment129 130 
Asset retirement obligation20 19 
Deferred meter replacement costs60 59 
COVID-19 cost recovery and late payment surcharge11 12 
Low income arrears forgiveness49 55 
Excess generation service charge86 52 
System Expansion19 22 
Non-bypassable charge124 103 
Hedges losses13 34 
Rate change levelization83 60 
Value of distributed energy resources44 49 
Uncollectible reserve114 104 
New York make-whole provision84 96 
Other296 283 
Total regulatory assets3,806 3,529 
Less: current portion745 718 
Total non-current regulatory assets$3,061 $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
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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 deferral and surcharge/sur-credit mechanism to recover/return deferred balances starting July 1, 2022.
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“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 asset 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 and systems benefit charge.
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Regulatory liabilities as of March 31, 2024 and December 31, 2023, respectively, consisted of:
March 31,December 31,
As of20242023
(Millions)
Energy efficiency portfolio standard$24 $15 
Gas supply charge and deferred natural gas cost10 8 
Pension and other post-retirement benefits cost deferrals88 89 
Carrying costs on deferred income tax bonus depreciation2 3 
Carrying costs on deferred income tax - Mixed Services 263(a)1 2 
2017 Tax Act1,187 1,190 
Accrued removal obligations1,135 1,139 
Positive benefit adjustment7 9 
Deferred property tax21 21 
Net plant reconciliation</