FORM |
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
(State or other jurisdiction of incorporation or organization) | (I.R.S. Employer Identification No.) | ||||||||||
(Address of principal executive offices) | (Zip Code) |
Title of each class | Trading Symbol | Name of exchange on which registered | ||||||||||||
☒ | Accelerated Filer | ☐ | ||||||||||||
Non-accelerated Filer | ☐ | Smaller Reporting Company | ||||||||||||
Emerging Growth Company |
Item 1. | ||||||||
Item 2. | ||||||||
Item 3. | ||||||||
Item 4. | ||||||||
Item 1. | ||||||||
Item 1A. | ||||||||
Item 2. | ||||||||
Item 3. | ||||||||
Item 4. | ||||||||
Item 5. | ||||||||
Item 6. | ||||||||
2023 Joint Proposal | Joint 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 | |||||||
CAIDI | Customer Average Interruption Duration Index | |||||||
CfDs | Contracts for Differences | |||||||
CBP | U.S. Customs and Border Protection | |||||||
CFIUS | Committee 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 | |||||||
DOC | Department of Commerce | |||||||
DPA | Deferred Payment Arrangements | |||||||
DPU | Massachusetts Department of Public Utilities | |||||||
EBITDA | Earnings before interest, taxes, depreciation and amortization | |||||||
ESM | Earnings sharing mechanism | |||||||
English Station | The 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 | |||||||
FCC | Federal 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 | |||||||
IRA | Inflation Reduction Act | |||||||
Iberdrola | Iberdrola, S.A. | |||||||
Iberdrola Group | The group of companies controlled by Iberdrola, S.A. | |||||||
Installed capacity | The production capacity of a power plant or wind farm based either on its rated (nameplate) capacity or actual capacity. | |||||||
ISO | Independent system operator | |||||||
Klamath Plant | Klamath gas-fired cogeneration facility located in the city of Klamath, Oregon. | |||||||
KW | Kilowatts | |||||||
MNG | Maine Natural Gas Corporation | |||||||
MPUC | Maine Public Utility Commission | |||||||
MtM | Mark-to-market | |||||||
MW | Megawatts | |||||||
MWh | Megawatt-hours | |||||||
NECEC | New England Clean Energy Connect | |||||||
Networks | Avangrid Networks, Inc. | |||||||
Non-GAAP | Financial 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. | |||||||
NRC | Nuclear Regulatory Commission | |||||||
NYPSC | New York State Public Service Commission | |||||||
NYSE | New 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 | |||||||
SAIFI | System Average Interruption Frequency Index | |||||||
SCG | The Southern Connecticut Gas Company | |||||||
SEC | United States Securities and Exchange Commission | |||||||
SOFR | Secured 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 | |||||||
UFLPA | Uyghur 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 |
Three Months Ended March 31, | ||||||||||||||
2024 | 2023 | |||||||||||||
(Millions, except for number of shares and per share data) | ||||||||||||||
Operating Revenues | $ | $ | ||||||||||||
Operating Expenses | ||||||||||||||
Purchased power, natural gas and fuel used | ||||||||||||||
Operations and maintenance | ||||||||||||||
Depreciation and amortization | ||||||||||||||
Taxes other than income taxes | ||||||||||||||
Total Operating Expenses | ||||||||||||||
Operating Income | ||||||||||||||
Other Income and (Expense) | ||||||||||||||
Other income | ||||||||||||||
Earnings from equity method investments | ||||||||||||||
Interest expense, net of capitalization | ( | ( | ||||||||||||
Income Before Income Tax | ||||||||||||||
Income tax expense (benefit) | ( | |||||||||||||
Net Income | ||||||||||||||
Net loss attributable to noncontrolling interests | ||||||||||||||
Net Income Attributable to Avangrid, Inc. | $ | $ | ||||||||||||
Earnings Per Common Share, Basic | $ | $ | ||||||||||||
Earnings Per Common Share, Diluted | $ | $ | ||||||||||||
Weighted-average Number of Common Shares Outstanding: | ||||||||||||||
Basic | ||||||||||||||
Diluted |
Three Months Ended March 31, | ||||||||||||||
2024 | 2023 | |||||||||||||
(Millions) | ||||||||||||||
Net Income | $ | $ | ||||||||||||
Other Comprehensive Income | ||||||||||||||
Unrealized loss from equity method investment, net of income taxes of $ | ( | |||||||||||||
Unrealized gain (loss) during the period on derivatives qualifying as cash flow hedges, net of income tax of $ | ( | |||||||||||||
Reclassification to net income of loss on cash flow hedges, net of income taxes $ | ||||||||||||||
Other Comprehensive Income | ||||||||||||||
Comprehensive Income | ||||||||||||||
Net loss attributable to noncontrolling interests | ||||||||||||||
Comprehensive Income Attributable to Avangrid, Inc. | $ | $ |
March 31, | December 31, | |||||||||||||
As of | 2024 | 2023 | ||||||||||||
(Millions) | ||||||||||||||
Assets | ||||||||||||||
Current Assets | ||||||||||||||
Cash and cash equivalents | $ | $ | ||||||||||||
Accounts receivable and unbilled revenues, net | ||||||||||||||
Accounts receivable from affiliates | ||||||||||||||
Notes receivable from affiliates | ||||||||||||||
Derivative assets | ||||||||||||||
Fuel and gas in storage | ||||||||||||||
Materials and supplies | ||||||||||||||
Prepayments and other current assets | ||||||||||||||
Regulatory assets | ||||||||||||||
Total Current Assets | ||||||||||||||
Total Property, Plant and Equipment ($ | ||||||||||||||
Operating lease right-of-use assets | ||||||||||||||
Equity method investments | ||||||||||||||
Other investments | ||||||||||||||
Regulatory assets | ||||||||||||||
Other Assets | ||||||||||||||
Goodwill | ||||||||||||||
Intangible assets | ||||||||||||||
Derivative assets | ||||||||||||||
Other | ||||||||||||||
Total Other Assets | ||||||||||||||
Total Assets | $ | $ |
March 31, | December 31, | |||||||||||||
As of | 2024 | 2023 | ||||||||||||
(Millions, except share information) | ||||||||||||||
Liabilities | ||||||||||||||
Current Liabilities | ||||||||||||||
Current portion of debt | $ | $ | ||||||||||||
Notes payable | ||||||||||||||
Notes payable to affiliates | ||||||||||||||
Interest accrued | ||||||||||||||
Accounts payable and accrued liabilities | ||||||||||||||
Accounts payable to affiliates | ||||||||||||||
Dividends payable | ||||||||||||||
Taxes accrued | ||||||||||||||
Operating lease liabilities | ||||||||||||||
Derivative liabilities | ||||||||||||||
Other current liabilities | ||||||||||||||
Regulatory liabilities | ||||||||||||||
Total Current Liabilities | ||||||||||||||
Regulatory liabilities | ||||||||||||||
Other Non-current Liabilities | ||||||||||||||
Deferred income taxes | ||||||||||||||
Deferred income | ||||||||||||||
Pension and other postretirement | ||||||||||||||
Operating lease liabilities | ||||||||||||||
Derivative liabilities | ||||||||||||||
Asset retirement obligations | ||||||||||||||
Environmental remediation costs | ||||||||||||||
Other | ||||||||||||||
Total Other Non-current Liabilities | ||||||||||||||
Non-current debt | ||||||||||||||
Non-current debt to affiliate | ||||||||||||||
Total Non-current Liabilities | ||||||||||||||
Total Liabilities | ||||||||||||||
Commitments and Contingencies | ||||||||||||||
Equity | ||||||||||||||
Stockholders’ Equity: | ||||||||||||||
Common stock, $ | ||||||||||||||
Additional paid in capital | ||||||||||||||
Treasury stock | ( | ( | ||||||||||||
Retained earnings | ||||||||||||||
Accumulated other comprehensive income (loss) | ( | |||||||||||||
Total Stockholders’ Equity | ||||||||||||||
Non-controlling interests | ||||||||||||||
Total Equity | ||||||||||||||
Total Liabilities and Equity | $ | $ |
Three Months Ended March 31, | ||||||||||||||
2024 | 2023 | |||||||||||||
(Millions) | ||||||||||||||
Cash Flow from Operating Activities: | ||||||||||||||
Net income | $ | $ | ||||||||||||
Adjustments to reconcile net income to net cash provided by operating activities: | ||||||||||||||
Depreciation and amortization | ||||||||||||||
Regulatory assets/liabilities amortization and carrying cost | ( | |||||||||||||
Pension cost | ( | ( | ||||||||||||
Earnings from equity method investments | ( | ( | ||||||||||||
Distributions of earnings received from equity method investments | ||||||||||||||
Unrealized (gain) loss on marked-to-market derivative contracts | ( | |||||||||||||
Deferred taxes | ( | |||||||||||||
Other non-cash items | ( | ( | ||||||||||||
Changes in operating assets and liabilities: | ||||||||||||||
Current assets | ( | |||||||||||||
Noncurrent assets | ( | ( | ||||||||||||
Current liabilities | ( | ( | ||||||||||||
Noncurrent liabilities | ( | ( | ||||||||||||
Net Cash Provided by Operating Activities | ||||||||||||||
Cash Flow from Investing Activities: | ||||||||||||||
Capital expenditures | ( | ( | ||||||||||||
Contributions in aid of construction | ||||||||||||||
Proceeds from sale of assets | ||||||||||||||
Proceeds from notes receivable from affiliates | ||||||||||||||
Distributions received from equity method investments | ||||||||||||||
Other investments and equity method investments, net | ( | ( | ||||||||||||
Net Cash Used in Investing Activities | ( | ( | ||||||||||||
Cash Flow from Financing Activities: | ||||||||||||||
Repayments of non-current debt | ( | ( | ||||||||||||
Receipts of other short-term debt, net | ||||||||||||||
Receipts of other short-term debt with affiliates | ||||||||||||||
Repayments of financing leases | ( | ( | ||||||||||||
Issuance of common stock | ( | |||||||||||||
Distributions to noncontrolling interests | ( | ( | ||||||||||||
Contributions from noncontrolling interests | ||||||||||||||
Dividends paid | ( | ( | ||||||||||||
Net Cash Provided by Financing Activities | ||||||||||||||
Net Increase in Cash, Cash Equivalents and Restricted Cash | ||||||||||||||
Cash, Cash Equivalents and Restricted Cash, Beginning of Period | ||||||||||||||
Cash, Cash Equivalents and Restricted Cash, End of Period | $ | $ | ||||||||||||
Supplemental Cash Flow Information | ||||||||||||||
Cash paid for interest, net of amounts capitalized | $ | $ | ||||||||||||
Cash paid (refunded) for income taxes | $ | $ | ( |
Avangrid, Inc. Stockholders | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
(Millions, except for number of shares ) | Number of shares (*) | Common Stock | Additional paid-in capital | Treasury Stock | Retained Earnings | Accumulated Other Comprehensive Loss | Total Stockholders’ Equity | Noncontrolling Interests | Total | |||||||||||||||||||||||||||||||||||||||||||||||
As of December 31, 2022 | $ | $ | $ | ( | $ | $ | ( | $ | $ | $ | ||||||||||||||||||||||||||||||||||||||||||||||
Net income (loss) | — | — | — | — | — | ( | ||||||||||||||||||||||||||||||||||||||||||||||||||
Other comprehensive loss, net of tax of $ | — | — | — | — | — | — | ||||||||||||||||||||||||||||||||||||||||||||||||||
Comprehensive income | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Dividends declared, $ | — | — | — | — | ( | — | ( | — | ( | |||||||||||||||||||||||||||||||||||||||||||||||
Issuance of common stock | — | — | — | — | — | — | — | — | ||||||||||||||||||||||||||||||||||||||||||||||||
Stock-based compensation | — | — | — | — | — | — | ||||||||||||||||||||||||||||||||||||||||||||||||||
Distributions to noncontrolling interests | — | — | — | — | — | — | — | ( | ( | |||||||||||||||||||||||||||||||||||||||||||||||
Contributions from noncontrolling interests | — | — | — | — | — | — | ||||||||||||||||||||||||||||||||||||||||||||||||||
As of March 31, 2023 | $ | $ | $ | ( | $ | $ | ( | $ | $ | $ | ||||||||||||||||||||||||||||||||||||||||||||||
As of December 31, 2023 | $ | $ | $ | ( | $ | $ | ( | $ | $ | $ | ||||||||||||||||||||||||||||||||||||||||||||||
Net income (loss) | — | — | — | — | — | ( | ||||||||||||||||||||||||||||||||||||||||||||||||||
Other comprehensive income, net of tax of $ | — | — | — | — | — | — | ||||||||||||||||||||||||||||||||||||||||||||||||||
Comprehensive income | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Dividends declared, $ | — | — | — | — | ( | — | ( | — | ( | |||||||||||||||||||||||||||||||||||||||||||||||
Issuance of common stock | — | ( | — | — | — | ( | — | ( | ||||||||||||||||||||||||||||||||||||||||||||||||
Stock-based compensation | — | — | — | — | — | — | ||||||||||||||||||||||||||||||||||||||||||||||||||
Distributions to noncontrolling interests | — | — | — | — | — | — | — | ( | ( | |||||||||||||||||||||||||||||||||||||||||||||||
Contributions from noncontrolling interests | — | — | — | — | — | — | ||||||||||||||||||||||||||||||||||||||||||||||||||
As of March 31, 2024 | $ | $ | $ | ( | $ | $ | $ | $ | $ |
Three Months Ended March 31, 2024 | ||||||||||||||||||||||||||
Networks | Renewables | Other (b) | Total | |||||||||||||||||||||||
(Millions) | ||||||||||||||||||||||||||
Regulated operations – electricity | $ | $ | $ | $ | ||||||||||||||||||||||
Regulated operations – natural gas | ||||||||||||||||||||||||||
Nonregulated operations – wind | ||||||||||||||||||||||||||
Nonregulated operations – solar | ||||||||||||||||||||||||||
Nonregulated operations – thermal | ||||||||||||||||||||||||||
Other(a) | ( | ( | ||||||||||||||||||||||||
Revenue from contracts with customers | ( | |||||||||||||||||||||||||
Leasing revenue | ||||||||||||||||||||||||||
Derivative gains | ||||||||||||||||||||||||||
Alternative revenue programs | ||||||||||||||||||||||||||
Other revenue | ||||||||||||||||||||||||||
Total operating revenues | $ | $ | $ | ( | $ |
Three Months Ended March 31, 2023 | ||||||||||||||||||||||||||
Networks | Renewables | Other (b) | Total | |||||||||||||||||||||||
(Millions) | ||||||||||||||||||||||||||
Regulated operations – electricity | $ | $ | $ | $ | ||||||||||||||||||||||
Regulated operations – natural gas | ||||||||||||||||||||||||||
Nonregulated operations – wind | ||||||||||||||||||||||||||
Nonregulated operations – solar | ||||||||||||||||||||||||||
Nonregulated operations – thermal | ||||||||||||||||||||||||||
Other(a) | ( | ( | ( | |||||||||||||||||||||||
Revenue from contracts with customers | ||||||||||||||||||||||||||
Leasing revenue | ||||||||||||||||||||||||||
Derivative gains | ||||||||||||||||||||||||||
Alternative revenue programs | ||||||||||||||||||||||||||
Other revenue | ||||||||||||||||||||||||||
Total operating revenues | $ | $ | $ | $ |
As of March 31, 2024 | 2025 | 2026 | 2027 | 2028 | 2029 | Thereafter | Total | |||||||||||||||||||||||||||||||||||||
(Millions) | ||||||||||||||||||||||||||||||||||||||||||||
Revenue expected to be recognized on multiyear capacity and carbon-free energy sale contracts | ||||||||||||||||||||||||||||||||||||||||||||
Revenue expected to be recognized on multiyear renewable energy credit sale contracts | ||||||||||||||||||||||||||||||||||||||||||||
Total operating revenues | $ | $ | $ | $ | $ | $ | $ |
March 31, | December 31, | |||||||||||||
As of | 2024 | 2023 | ||||||||||||
(Millions) | ||||||||||||||
Pension and other post-retirement benefits | $ | $ | ||||||||||||
Pension and other post-retirement benefits cost deferrals | ||||||||||||||
Storm costs | ||||||||||||||
Rate adjustment mechanism | ||||||||||||||
Revenue decoupling mechanism | ||||||||||||||
Contracts for differences | ||||||||||||||
Hardship programs | ||||||||||||||
Deferred purchased gas | ||||||||||||||
Environmental remediation costs | ||||||||||||||
Debt premium | ||||||||||||||
Unamortized losses on reacquired debt | ||||||||||||||
Unfunded future income taxes | ||||||||||||||
Federal tax depreciation normalization adjustment | ||||||||||||||
Asset retirement obligation | ||||||||||||||
Deferred meter replacement costs | ||||||||||||||
COVID-19 cost recovery and late payment surcharge | ||||||||||||||
Low income arrears forgiveness | ||||||||||||||
Excess generation service charge | ||||||||||||||
System Expansion | ||||||||||||||
Non-bypassable charge | ||||||||||||||
Hedges losses | ||||||||||||||
Rate change levelization | ||||||||||||||
Value of distributed energy resources | ||||||||||||||
Uncollectible reserve | ||||||||||||||
New York make-whole provision | ||||||||||||||
Other | ||||||||||||||
Total regulatory assets | ||||||||||||||
Less: current portion | ||||||||||||||
Total non-current regulatory assets | $ | $ |
March 31, | December 31, | |||||||||||||
As of | 2024 | 2023 | ||||||||||||
(Millions) | ||||||||||||||
Energy efficiency portfolio standard | $ | $ | ||||||||||||
Gas supply charge and deferred natural gas cost | ||||||||||||||
Pension and other post-retirement benefits cost deferrals | ||||||||||||||
Carrying costs on deferred income tax bonus depreciation | ||||||||||||||
Carrying costs on deferred income tax - Mixed Services 263(a) | ||||||||||||||
2017 Tax Act | ||||||||||||||
Accrued removal obligations | ||||||||||||||
Positive benefit adjustment | ||||||||||||||
Deferred property tax | ||||||||||||||
Net plant reconciliation | ||||||||||||||
Debt rate reconciliation | ||||||||||||||
Rate refund – FERC ROE proceeding | ||||||||||||||
Transmission congestion contracts | ||||||||||||||
Merger-related rate credits | ||||||||||||||
Accumulated deferred investment tax credits | ||||||||||||||
Asset retirement obligation | ||||||||||||||
Middletown/Norwalk local transmission network service collections | ||||||||||||||
Non-firm margin sharing credits | ||||||||||||||
Non by-passable charges | ||||||||||||||
Transmission revenue reconciliation mechanism | ||||||||||||||
Other | ||||||||||||||
Total regulatory liabilities | ||||||||||||||
Less: current portion | ||||||||||||||
Total non-current regulatory liabilities | $ | $ |
As of March 31, 2024 | Level 1 | Level 2 | Level 3 | Netting | Total | |||||||||||||||||||||||||||
(Millions) | ||||||||||||||||||||||||||||||||
Equity investments with readily determinable fair values | $ | $ | $ | $ | — | $ | ||||||||||||||||||||||||||
Derivative assets | ||||||||||||||||||||||||||||||||
Derivative financial instruments - power | $ | $ | $ | $ | ( | $ | ||||||||||||||||||||||||||
Derivative financial instruments - gas | ( | |||||||||||||||||||||||||||||||
Contracts for differences | ||||||||||||||||||||||||||||||||
Derivative financial instruments – Other | ||||||||||||||||||||||||||||||||
Total | $ | $ | $ | $ | ( | $ | ||||||||||||||||||||||||||
Derivative liabilities | ||||||||||||||||||||||||||||||||
Derivative financial instruments - power | $ | ( | $ | ( | $ | ( | $ | $ | ( | |||||||||||||||||||||||
Derivative financial instruments - gas | ( | ( | ||||||||||||||||||||||||||||||
Contracts for differences | ( | ( | ||||||||||||||||||||||||||||||
Derivative financial instruments – Other | ( | ( | ||||||||||||||||||||||||||||||
Total | $ | ( | $ | ( | $ | ( | $ | $ | ( |
As of December 31, 2023 | Level 1 | Level 2 | Level 3 | Netting | Total | |||||||||||||||||||||||||||
(Millions) | ||||||||||||||||||||||||||||||||
Equity investments with readily determinable fair values | $ | $ | $ | $ | — | $ | ||||||||||||||||||||||||||
Derivative assets | ||||||||||||||||||||||||||||||||
Derivative financial instruments - power | $ | $ | $ | $ | ( | $ | ||||||||||||||||||||||||||
Derivative financial instruments - gas | ( | |||||||||||||||||||||||||||||||
Contracts for differences | ||||||||||||||||||||||||||||||||
Derivative financial instruments – Other | ||||||||||||||||||||||||||||||||
Total | $ | $ | $ | $ | ( | $ | ||||||||||||||||||||||||||
Derivative liabilities | ||||||||||||||||||||||||||||||||
Derivative financial instruments - power | $ | ( | $ | ( | $ | ( | $ | $ | ( | |||||||||||||||||||||||
Derivative financial instruments - gas | ( | ( | ( | |||||||||||||||||||||||||||||
Contracts for differences | ( | ( | ||||||||||||||||||||||||||||||
Derivative financial instruments - Other | ( | ( | ||||||||||||||||||||||||||||||
Total | $ | ( | $ | ( | $ | ( | $ | $ | ( |
Three Months Ended March 31, | ||||||||||||||
(Millions) | 2024 | 2023 | ||||||||||||
Fair Value Beginning of Period, | $ | $ | ||||||||||||
Gains recognized in operating revenues | ||||||||||||||
(Losses) recognized in operating revenues | ( | ( | ||||||||||||
( | ( | |||||||||||||
Gains recognized in OCI | ||||||||||||||
(Losses) recognized in OCI | ( | ( | ||||||||||||
( | ||||||||||||||
Net change recognized in regulatory assets and liabilities | ||||||||||||||
Purchases | ||||||||||||||
Settlements | ( | ( | ||||||||||||
Fair Value as of March 31, | $ | $ | ||||||||||||
$ | ( | $ | ( |
As of March 31, 2024 | ||||||||||||||||||||
Index | Avg. | Max. | Min. | |||||||||||||||||
Ameren ($/MWh) | $ | $ | $ | |||||||||||||||||
ComEd ($/MWh) | $ | $ | $ | |||||||||||||||||
ERCOT S hub ($/MWh) | $ | $ | $ | |||||||||||||||||
Mid C ($/MWh) | $ | $ | $ | |||||||||||||||||
AEP-DAYTON hub ($/MWh) | $ | $ | $ |
Range at | ||||||||
Unobservable Input | March 31, 2024 | |||||||
Risk of non-performance | ||||||||
Discount rate | ||||||||
Forward pricing ($ per KW-month) | $ |
As of March 31, 2024 | Current Assets | Noncurrent Assets | Current Liabilities | Noncurrent Liabilities | ||||||||||||||||||||||
(Millions) | ||||||||||||||||||||||||||
Not designated as hedging instruments | ||||||||||||||||||||||||||
Derivative assets | $ | $ | $ | $ | ||||||||||||||||||||||
Derivative liabilities | ( | ( | ( | ( | ||||||||||||||||||||||
( | ( | |||||||||||||||||||||||||
Designated as hedging instruments | ||||||||||||||||||||||||||
Derivative assets | ||||||||||||||||||||||||||
Derivative liabilities | ||||||||||||||||||||||||||
Total derivatives before offset of cash collateral | ( | ( | ||||||||||||||||||||||||
Cash collateral receivable | ||||||||||||||||||||||||||
Total derivatives as presented in the balance sheet | $ | $ | $ | ( | $ | ( |
As of December 31, 2023 | Current Assets | Noncurrent Assets | Current Liabilities | Noncurrent Liabilities | ||||||||||||||||||||||
(Millions) | ||||||||||||||||||||||||||
Not designated as hedging instruments | ||||||||||||||||||||||||||
Derivative assets | $ | $ | $ | $ | ||||||||||||||||||||||
Derivative liabilities | ( | ( | ( | ( | ||||||||||||||||||||||
( | ( | |||||||||||||||||||||||||
Designated as hedging instruments | ||||||||||||||||||||||||||
Derivative assets | ||||||||||||||||||||||||||
Derivative liabilities | ||||||||||||||||||||||||||
Total derivatives before offset of cash collateral | ( | ( | ||||||||||||||||||||||||
Cash collateral receivable | ||||||||||||||||||||||||||
Total derivatives as presented in the balance sheet | $ | $ | $ | ( | $ | ( |
March 31, | December 31, | |||||||||||||
As of | 2024 | 2023 | ||||||||||||
(Millions) | ||||||||||||||
Wholesale electricity purchase contracts (MWh) | ||||||||||||||
Natural gas purchase contracts (Dth) | ||||||||||||||
(Millions) | Loss or Gain Recognized in Regulatory Assets/Liabilities | Location of Loss (Gain) Reclassified from Regulatory Assets/Liabilities into Income | Loss (Gain) Reclassified from Regulatory Assets/Liabilities into Income | |||||||||||||||||||||||||||||
As of | Three Months Ended March 31, | |||||||||||||||||||||||||||||||
March 31, 2024 | Electricity | Natural Gas | 2024 | Electricity | Natural Gas | |||||||||||||||||||||||||||
Regulatory assets | $ | $ | Purchased power, natural gas and fuel used | $ | $ | |||||||||||||||||||||||||||
December 31, 2023 | 2023 | |||||||||||||||||||||||||||||||
Regulatory assets | $ | $ | Purchased power, natural gas and fuel used | $ | $ | |||||||||||||||||||||||||||
Three Months Ended March 31, | ||||||||||||||
2024 | 2023 | |||||||||||||
(Millions) | ||||||||||||||
Derivative liabilities | $ | $ |
Three Months Ended March 31, | Gain (Loss) Recognized in OCI on Derivatives (a) | Location of Loss (Gain) Reclassified from Accumulated OCI into Income | Loss (Gain) Reclassified from Accumulated OCI into Income | Total amount per Income Statement | ||||||||||||||||||||||
(Millions) | ||||||||||||||||||||||||||
2024 | ||||||||||||||||||||||||||
Interest rate contracts | $ | Interest expense | $ | $ | ||||||||||||||||||||||
Commodity contracts | Purchased power, natural gas and fuel used | |||||||||||||||||||||||||
Total | $ | $ | ||||||||||||||||||||||||
2023 | ||||||||||||||||||||||||||
Interest rate contracts | $ | Interest expense | $ | $ | ||||||||||||||||||||||
Commodity contracts | Purchased power, natural gas and fuel used | |||||||||||||||||||||||||
Total | $ | $ |
March 31, | December 31, | |||||||||||||
As of | 2024 | 2023 | ||||||||||||
(MWh/Dth in millions) | ||||||||||||||
Wholesale electricity purchase contracts | ||||||||||||||
Wholesale electricity sales contracts | ||||||||||||||
Natural gas and other fuel purchase contracts | ||||||||||||||
Financial power contracts | ||||||||||||||
Basis swaps – purchases | ||||||||||||||
Basis swaps – sales |
March 31, | December 31, | |||||||||||||
As of | 2024 | 2023 | ||||||||||||
(Millions) | ||||||||||||||
Wholesale electricity purchase contracts | $ | $ | ||||||||||||
Wholesale electricity sales contracts | ||||||||||||||
Natural gas and other fuel purchase contracts | ||||||||||||||
Financial power contracts | ||||||||||||||
Total | $ | $ |
As of March 31, 2024 | Current Assets | Noncurrent Assets | Current Liabilities | Noncurrent Liabilities | ||||||||||||||||||||||
(Millions) | ||||||||||||||||||||||||||
Not designated as hedging instruments | ||||||||||||||||||||||||||
Derivative assets | $ | $ | $ | $ | ||||||||||||||||||||||
Derivative liabilities | ( | ( | ( | ( | ||||||||||||||||||||||
( | ( | |||||||||||||||||||||||||
Designated as hedging instruments | ||||||||||||||||||||||||||
Derivative assets | ||||||||||||||||||||||||||
Derivative liabilities | ( | ( | ( | |||||||||||||||||||||||
( | ( | |||||||||||||||||||||||||
Total derivatives before offset of cash collateral | ( | ( | ||||||||||||||||||||||||
Cash collateral (payable) receivable | ( | |||||||||||||||||||||||||
Total derivatives as presented in the balance sheet | $ | $ | $ | ( | $ | ( |
As of December 31, 2023 | Current Assets | Noncurrent Assets | Current Liabilities | Noncurrent Liabilities | ||||||||||||||||||||||
(Millions) | ||||||||||||||||||||||||||
Not designated as hedging instruments | ||||||||||||||||||||||||||
Derivative assets | $ | $ | $ | $ | ||||||||||||||||||||||
Derivative liabilities | ( | ( | ( | |||||||||||||||||||||||
( | ( | |||||||||||||||||||||||||
Designated as hedging instruments | ||||||||||||||||||||||||||
Derivative assets | ||||||||||||||||||||||||||
Derivative liabilities | ( | ( | ( | |||||||||||||||||||||||
( | ( | |||||||||||||||||||||||||
Total derivatives before offset of cash collateral | ( | ( | ||||||||||||||||||||||||
Cash collateral receivable | ||||||||||||||||||||||||||
Total derivatives as presented in the balance sheet | $ | $ | $ | ( | $ | ( |
Three Months Ended March 31, 2024 | ||||||||||||||||||||
Trading | Non-trading | Total amount per income statement | ||||||||||||||||||
(Millions) | ||||||||||||||||||||
Operating Revenues | ||||||||||||||||||||
Wholesale electricity purchase contracts | $ | ( | $ | |||||||||||||||||
Wholesale electricity sales contracts | ||||||||||||||||||||
Financial power contracts | ( | |||||||||||||||||||
Financial and natural gas contracts | ( | |||||||||||||||||||
$ | $ | $ | ||||||||||||||||||
Purchased power, natural gas and fuel used | ||||||||||||||||||||
Wholesale electricity purchase contracts | $ | $ | ( | |||||||||||||||||
Financial power contracts | ||||||||||||||||||||
Financial and natural gas contracts | ||||||||||||||||||||
$ | $ | ( | $ | |||||||||||||||||
$ | $ |
Three Months Ended March 31, 2023 | ||||||||||||||||||||
Trading | Non-trading | Total amount per income statement | ||||||||||||||||||
(Millions) | ||||||||||||||||||||
Operating Revenues | ||||||||||||||||||||
Wholesale electricity purchase contracts | $ | ( | $ | |||||||||||||||||
Wholesale electricity sales contracts | ||||||||||||||||||||
Financial power contracts | ||||||||||||||||||||
Financial and natural gas contracts | ||||||||||||||||||||
$ | $ | $ | ||||||||||||||||||
Purchased power, natural gas and fuel used | ||||||||||||||||||||
Wholesale electricity purchase contracts | $ | $ | ( | |||||||||||||||||
Financial power contracts | ||||||||||||||||||||
Financial and natural gas contracts | ( | |||||||||||||||||||
$ | $ | ( | $ | |||||||||||||||||
$ | $ | ( |
Three Months Ended March 31, | Gain (Loss) Recognized in OCI on Derivatives (a) | Location of Loss Reclassified from Accumulated OCI into Income | Loss Reclassified from Accumulated OCI into Income | Total amount per Income Statement | ||||||||||||||||||||||
(Millions) | ||||||||||||||||||||||||||
2024 | ||||||||||||||||||||||||||
Interest rate contracts | $ | Interest Expense | $ | $ | ||||||||||||||||||||||
Commodity contracts | Operating revenues | $ | ||||||||||||||||||||||||
Total | $ | $ | ||||||||||||||||||||||||
2023 | ||||||||||||||||||||||||||
Interest rate contracts | $ | Interest Expense | $ | $ | ||||||||||||||||||||||
Commodity contracts | Operating revenues | $ | ||||||||||||||||||||||||
Total | $ | $ |
Three Months Ended March 31, | (Loss) Recognized in OCI on Derivatives (a) | Location of Loss Reclassified from Accumulated OCI into Income | Loss Reclassified from Accumulated OCI into Income | Total amount per Income Statement | ||||||||||||||||||||||
(Millions) | ||||||||||||||||||||||||||
2024 | ||||||||||||||||||||||||||
Interest rate contracts | $ | Interest expense | $ | $ | ||||||||||||||||||||||
2023 | ||||||||||||||||||||||||||
Interest rate contracts | $ | Interest expense | $ | $ | ||||||||||||||||||||||
Fair value of hedge | Location of Loss Recognized in Income Statement | Loss Recognized in Income Statement | Year to date total per Income Statement | |||||||||||||||||||||||
(Millions) | As of March 31, 2024 | Three Months Ended March 31, 2024 | ||||||||||||||||||||||||
Current Liabilities | $ | ( | Interest Expense | $ | $ | |||||||||||||||||||||
Non-current liabilities | $ | ( | ||||||||||||||||||||||||
Cumulative effect on hedged debt | ||||||||||||||||||||||||||
Current debt | $ | |||||||||||||||||||||||||
Non-current debt | $ |
Fair value of hedge | Location of (Gain) Recognized in Income Statement | (Gain) Recognized in Income Statement | Year to date total per Income Statement | |||||||||||||||||||||||
(Millions) | As of December 31, 2023 | Three Months Ended March 31, 2023 | ||||||||||||||||||||||||
Current Liabilities | $ | ( | Interest Expense | $ | $ | |||||||||||||||||||||
Non-current liabilities | $ | ( | ||||||||||||||||||||||||
Cumulative effect on hedged debt | ||||||||||||||||||||||||||
Current debt | $ | |||||||||||||||||||||||||
Non-current debt | $ |
Three Months Ended March 31, | ||||||||||||||
2024 | 2023 | |||||||||||||
(Millions) | ||||||||||||||
Service cost | $ | $ | ||||||||||||
Interest cost | ||||||||||||||
Expected return on plan assets | ( | ( | ||||||||||||
Amortization of: | ||||||||||||||
Prior service costs | ||||||||||||||
Actuarial loss | ||||||||||||||
Net Periodic Benefit Cost | $ | ( | $ | ( |
Three Months Ended March 31, | ||||||||||||||
2024 | 2023 | |||||||||||||
(Millions) | ||||||||||||||
Service cost | $ | $ | ||||||||||||
Interest cost | ||||||||||||||
Expected return on plan assets | ( | ( | ||||||||||||
Amortization of: | ||||||||||||||
Prior service costs | ||||||||||||||
Actuarial loss | ( | ( | ||||||||||||
Net Periodic Benefit Cost (Credit) | $ | $ | ( |
As of December 31, | Three Months Ended March 31, | As of March 31, | As of December 31, | Three Months Ended March 31, | As of March 31, | |||||||||||||||||||||||||||||||||
2023 | 2024 | 2024 | 2022 | 2023 | 2023 | |||||||||||||||||||||||||||||||||
(Millions) | ||||||||||||||||||||||||||||||||||||||
Net loss on pension plans | ( | ( | ( | ( | ||||||||||||||||||||||||||||||||||
Unrealized (loss) gain from equity method investment, net of income tax expense of $ | ( | |||||||||||||||||||||||||||||||||||||
Unrealized loss during period on derivatives qualifying as cash flow hedges, net of income tax benefit of $ | ( | ( | ( | ( | ( | |||||||||||||||||||||||||||||||||
Reclassification to net income of losses on cash flow hedges, net of income tax expense (benefit) of $ | ||||||||||||||||||||||||||||||||||||||
Loss (gain) on derivatives qualifying as cash flow hedges | ( | ( | ( | |||||||||||||||||||||||||||||||||||
Accumulated Other Comprehensive Income (Loss) | $ | ( | $ | $ | $ | ( | $ | $ | ( |
Three Months Ended March 31, | ||||||||||||||
2024 | 2023 | |||||||||||||
(Millions, except for number of shares and per share data) | ||||||||||||||
Numerator: | ||||||||||||||
Net income attributable to Avangrid | $ | $ | ||||||||||||
Denominator: | ||||||||||||||
Weighted average number of shares outstanding - basic | ||||||||||||||
Weighted average number of shares outstanding - diluted | ||||||||||||||
Earnings per share attributable to Avangrid | ||||||||||||||
Earnings Per Common Share, Basic | $ | $ | ||||||||||||
Earnings Per Common Share, Diluted | $ | $ |
Three Months Ended March 31, 2024 | Networks | Renewables | Other (a) | Avangrid Consolidated | ||||||||||||||||||||||
(Millions) | ||||||||||||||||||||||||||
Revenue - external | $ | $ | $ | $ | ||||||||||||||||||||||
Revenue - intersegment | ( | — | ||||||||||||||||||||||||
Depreciation and amortization | ||||||||||||||||||||||||||
Operating income (loss) | ( | |||||||||||||||||||||||||
Earnings from equity method investments | ||||||||||||||||||||||||||
Interest expense, net of capitalization | ||||||||||||||||||||||||||
Income tax expense (benefit) | ( | ( | ||||||||||||||||||||||||
Adjusted net income (loss) | ( | |||||||||||||||||||||||||
Capital expenditures | ||||||||||||||||||||||||||
As of March 31, 2024 | ||||||||||||||||||||||||||
Property, plant and equipment | ||||||||||||||||||||||||||
Equity method investments | ||||||||||||||||||||||||||
Total assets | $ | $ | $ | ( | $ |
Three Months Ended March 31, 2023 | Networks | Renewables | Other (a) | Avangrid Consolidated | ||||||||||||||||||||||
(Millions) | ||||||||||||||||||||||||||
Revenue - external | $ | $ | $ | $ | ||||||||||||||||||||||
Depreciation and amortization | ||||||||||||||||||||||||||
Operating income (loss) | ( | ( | ||||||||||||||||||||||||
Earnings (losses) from equity method investments | ( | |||||||||||||||||||||||||
Interest expense, net of capitalization | ||||||||||||||||||||||||||
Income tax expense (benefit) | ( | ( | ( | |||||||||||||||||||||||
Adjusted net income (loss) | ||||||||||||||||||||||||||
Capital expenditures | ||||||||||||||||||||||||||
As of December 31, 2023 | ||||||||||||||||||||||||||
Property, plant and equipment | ||||||||||||||||||||||||||
Equity method investments | ||||||||||||||||||||||||||
Total assets | $ | $ | $ | ( | $ |
Three Months Ended March 31, | ||||||||||||||
2024 | 2023 | |||||||||||||
(Millions) | ||||||||||||||
Adjusted Net Income Attributable to Avangrid, Inc. | $ | $ | ||||||||||||
Adjustments: | ||||||||||||||
Mark-to-market adjustments - Renewables (1) | ( | |||||||||||||
Accelerated depreciation from repowering (2) | ( | |||||||||||||
Income tax impact of adjustments | ( | |||||||||||||
Net Income Attributable to Avangrid, Inc. | $ | $ |
Three Months Ended March 31, | 2024 | 2023 | ||||||||||||||||||||||||
(Millions) | Sales To | Purchases From | Sales To | Purchases From | ||||||||||||||||||||||
Iberdrola, S.A. | $ | $ | ( | $ | $ | ( | ||||||||||||||||||||
Iberdrola Renovables Energía, S.L. | $ | $ | ( | $ | $ | ( | ||||||||||||||||||||
Iberdrola Financiación, S.A. | $ | $ | ( | $ | $ | ( | ||||||||||||||||||||
Vineyard Wind | $ | $ | $ | $ | ||||||||||||||||||||||
As of | March 31, 2024 | December 31, 2023 | ||||||||||||||||||||||||
(Millions) | Owed By | Owed To | Owed By | Owed To | ||||||||||||||||||||||
Iberdrola, S.A. | $ | $ | ( | $ | $ | |||||||||||||||||||||
Iberdrola Renovables Energía, S.L. | $ | $ | ( | $ | $ | |||||||||||||||||||||
Iberdrola Financiación, S.A. | $ | $ | ( | $ | $ | ( | ||||||||||||||||||||
Vineyard Wind | $ | $ | ( | $ | $ | ( | ||||||||||||||||||||
Iberdrola Solutions | $ | $ | ( | $ | $ | ( | ||||||||||||||||||||
Other | $ | $ | ( | $ | $ |
As of | March 31, 2024 | December 31, 2023 | ||||||||||||
(Millions) | ||||||||||||||
Trade receivables and unbilled revenues | $ | $ | ||||||||||||
Allowance for credit losses | ( | ( | ||||||||||||
Accounts receivable and unbilled revenues, net | $ | $ |
Three Months Ended March 31, | ||||||||||||||
(Millions) | 2024 | 2023 | ||||||||||||
As of Beginning of Period, | $ | $ | ||||||||||||
Current period provision | ||||||||||||||
Write-off as uncollectible | ( | ( | ||||||||||||
As of March 31, | $ | $ |
March 31, | December 31, | |||||||||||||
As of | 2024 | 2023 | ||||||||||||
(Millions) | ||||||||||||||
Property, plant and equipment | ||||||||||||||
Accumulated depreciation | $ | $ | ||||||||||||
Intangible assets | ||||||||||||||
Accumulated amortization | $ | $ |
Three Months Ended | Three Months Ended | |||||||||||||||||||||||||||||||||||||||||||||||||
March 31, 2024 | March 31, 2023 | |||||||||||||||||||||||||||||||||||||||||||||||||
Total | Networks | Renewables | Other(1) | Total | Networks | Renewables | Other(1) | |||||||||||||||||||||||||||||||||||||||||||
(in millions) | ||||||||||||||||||||||||||||||||||||||||||||||||||
Operating Revenues | $ | 2,417 | $ | 2,018 | $ | 400 | $ | (1) | $ | 2,466 | $ | 2,076 | $ | 390 | $ | — | ||||||||||||||||||||||||||||||||||
Operating Expenses | ||||||||||||||||||||||||||||||||||||||||||||||||||
Purchased power, natural gas and fuel used | 724 | 643 | 81 | — | 977 | 833 | 144 | — | ||||||||||||||||||||||||||||||||||||||||||
Operations and maintenance | 792 | 676 | 118 | (2) | 761 | 631 | 130 | — | ||||||||||||||||||||||||||||||||||||||||||
Depreciation and amortization | 298 | 178 | 118 | 2 | 280 | 174 | 105 | 1 | ||||||||||||||||||||||||||||||||||||||||||
Taxes other than income taxes | 196 | 168 | 23 | 5 | 183 | 161 | 21 | 1 | ||||||||||||||||||||||||||||||||||||||||||
Total Operating Expenses | 2,010 | 1,665 | 340 | 5 | 2,201 | 1,799 | 400 | 2 | ||||||||||||||||||||||||||||||||||||||||||
Operating Income | 407 | 353 | 60 | (6) | 265 | 277 | (10) | (2) | ||||||||||||||||||||||||||||||||||||||||||
Other Income (Expense) | ||||||||||||||||||||||||||||||||||||||||||||||||||
Other income (expense) | 54 | 58 | 1 | (5) | 25 | 29 | 2 | (6) | ||||||||||||||||||||||||||||||||||||||||||
Earnings (losses) from equity method investments | 6 | 4 | 2 | — | 2 | 4 | (2) | — | ||||||||||||||||||||||||||||||||||||||||||
Interest expense, net of capitalization | (125) | (89) | (4) | (32) | (95) | (70) | (6) | (19) | ||||||||||||||||||||||||||||||||||||||||||
Income (Loss) Before Income Tax | 342 | 326 | 59 | (43) | 197 | 240 | (16) | (27) | ||||||||||||||||||||||||||||||||||||||||||
Income tax expense (benefit) | 20 | 57 | (6) | (31) | (18) | 44 | (34) | (28) | ||||||||||||||||||||||||||||||||||||||||||
Net Income (Loss) | 322 | 269 | 65 | (12) | 215 | 196 | 18 | 1 | ||||||||||||||||||||||||||||||||||||||||||
Net loss (income) attributable to noncontrolling interests | 29 | (1) | 30 | — | 30 | (1) | 31 | — | ||||||||||||||||||||||||||||||||||||||||||
Net Income (Loss) Attributable to Avangrid, Inc. | $ | 351 | $ | 268 | $ | 95 | $ | (12) | $ | 245 | $ | 195 | $ | 49 | $ | 1 |
Three Months Ended March 31, 2024 | ||||||||||||||||||||||||||
Total | Networks | Renewables | Corporate* | |||||||||||||||||||||||
(in millions) | ||||||||||||||||||||||||||
Net Income Attributable to Avangrid, Inc. | $ | 351 | $ | 268 | $ | 95 | $ | (11) | ||||||||||||||||||
Adjustments: | ||||||||||||||||||||||||||
Mark-to-market adjustments - Renewables | (17) | — | (17) | — | ||||||||||||||||||||||
Accelerated depreciation from repowering | 3 | — | 3 | — | ||||||||||||||||||||||
Income tax impact of adjustments (1) | 4 | — | 4 | — | ||||||||||||||||||||||
Adjusted Net Income (2) | $ | 341 | $ | 268 | $ | 84 | $ | (11) | ||||||||||||||||||
Net (loss) income attributable to noncontrolling interests | (29) | 1 | (30) | — | ||||||||||||||||||||||
Income tax expense (benefit) | 16 | 57 | (10) | (31) | ||||||||||||||||||||||
Depreciation and amortization | 298 | 178 | 118 | 2 | ||||||||||||||||||||||
Interest expense, net of capitalization | 125 | 89 | 4 | 32 | ||||||||||||||||||||||
Other (income) expense | (54) | (58) | (1) | 5 | ||||||||||||||||||||||
(Earnings) losses from equity method investments | (6) | (4) | (2) | — | ||||||||||||||||||||||
Adjusted EBITDA (3) | $ | 691 | $ | 531 | $ | 163 | $ | (3) | ||||||||||||||||||
Retained PTCs and ITCs | 47 | — | 47 | — | ||||||||||||||||||||||
PTCs allocated to tax equity investors | 36 | — | 36 | — | ||||||||||||||||||||||
Adjusted EBITDA with Tax Credits (3) | $ | 775 | $ | 531 | $ | 247 | $ | (3) |
Three Months Ended March 31, 2023 | ||||||||||||||||||||||||||
Total | Networks | Renewables | Corporate* | |||||||||||||||||||||||
(in millions) | ||||||||||||||||||||||||||
Net Income (Loss) Attributable to Avangrid, Inc. | $ | 245 | $ | 195 | $ | 49 | $ | 1 | ||||||||||||||||||
Adjustments: | ||||||||||||||||||||||||||
Mark-to-market earnings – Renewables | 4 | — | 4 | — | ||||||||||||||||||||||
Income tax impact of adjustments (1) | (1) | — | (1) | — | ||||||||||||||||||||||
Adjusted Net Income (2) | $ | 248 | $ | 195 | $ | 51 | $ | 1 | ||||||||||||||||||
Net (loss) income attributable to noncontrolling interests | (30) | 1 | (31) | — | ||||||||||||||||||||||
Income tax expense (benefit) | (17) | 44 | (33) | (28) | ||||||||||||||||||||||
Depreciation and amortization | 280 | 174 | 105 | 1 | ||||||||||||||||||||||
Interest expense, net of capitalization | 95 | 70 | 6 | 19 | ||||||||||||||||||||||
Other (income) expense | (25) | (29) | (2) | 6 | ||||||||||||||||||||||
(Earnings) losses from equity method investments | (2) | (4) | 2 | — | ||||||||||||||||||||||
Adjusted EBITDA (3) | $ | 549 | $ | 451 | $ | 98 | $ | — | ||||||||||||||||||
Retained PTCs and ITCs | 45 | — | 45 | — | ||||||||||||||||||||||
PTCs allocated to tax equity investors | 39 | — | 39 | — | ||||||||||||||||||||||
Adjusted EBITDA with Tax Credits (3) | $ | 633 | $ | 451 | $ | 182 | $ | — |
Three Months Ended | ||||||||||||||
March 31, | ||||||||||||||
(Millions) | 2024 | 2023 | ||||||||||||
Networks | $ | 268 | $ | 195 | ||||||||||
Renewables | 95 | 49 | ||||||||||||
Corporate (1) | (11) | 1 | ||||||||||||
Net Income | $ | 351 | $ | 245 | ||||||||||
Adjustments: | ||||||||||||||
Mark-to-market adjustments - Renewables (2) | (17) | 4 | ||||||||||||
Accelerated depreciation from repowering (3) | 3 | — | ||||||||||||
Income tax impact of adjustments | 4 | (1) | ||||||||||||
Adjusted Net Income (4) | $ | 341 | $ | 248 |
Three Months Ended | ||||||||||||||
March 31, | ||||||||||||||
2024 | 2023 | |||||||||||||
Networks | $ | 0.69 | $ | 0.51 | ||||||||||
Renewables | 0.24 | 0.13 | ||||||||||||
Corporate (1) | (0.03) | — | ||||||||||||
Net Income | $ | 0.91 | $ | 0.63 | ||||||||||
Adjustments: | ||||||||||||||
Mark-to-market adjustments - Renewables (2) | (0.05) | 0.01 | ||||||||||||
Accelerated depreciation from repowering (3) | 0.01 | — | ||||||||||||
Income tax impact of adjustments | 0.01 | — | ||||||||||||
Adjusted Earnings Per Share (4) | $ | 0.88 | $ | 0.64 |
As of March 31, | As of December 31, | |||||||||||||
2024 | 2023 | |||||||||||||
(in millions) | ||||||||||||||
Cash and cash equivalents | $ | 152 | $ | 91 | ||||||||||
Avangrid Credit Facility | 3,575 | 3,575 | ||||||||||||
Iberdrola Group Credit Facility | 750 | 750 | ||||||||||||
Less: borrowings | (2,364) | (1,332) | ||||||||||||
Total | $ | 2,113 | $ | 3,084 |
Three Months Ended | ||||||||||||||
March 31, | ||||||||||||||
2024 | 2023 | |||||||||||||
(in millions) | ||||||||||||||
Net cash provided by operating activities | $ | 153 | $ | 204 | ||||||||||
Net cash used in investing activities | (944) | (819) | ||||||||||||
Net cash provided by financing activities | 852 | 618 | ||||||||||||
Net increase in cash, cash equivalents and restricted cash | $ | 61 | $ | 3 |
Exhibit Number | Description | ||||||||||
31.1 | |||||||||||
31.2 | |||||||||||
32 | |||||||||||
101.INS | XBRL Instance Document.* | ||||||||||
101.SCH | XBRL Taxonomy Extension Schema Document.* | ||||||||||
101.CAL | XBRL Taxonomy Extension Calculation Linkbase Document.* | ||||||||||
101.DEF | XBRL Taxonomy Extension Definition Linkbase Document.* | ||||||||||
101.LAB | XBRL Taxonomy Extension Label Linkbase Document.* | ||||||||||
101.PRE | XBRL Taxonomy Extension Presentation Linkbase Document.* | ||||||||||
Avangrid, Inc. | ||||||||
Date: April 24, 2024 | By: | /s/ Pedro Azagra Blázquez | ||||||
Pedro Azagra Blázquez | ||||||||
Director and Chief Executive Officer |
Date: April 24, 2024 | By: | /s/ Justin B. Lagasse | ||||||
Justin B. Lagasse | ||||||||
Senior Vice President - Chief Financial Officer and Controller |
Date: April 24, 2024 | /s/ Pedro Azagra Blázquez | |||||||
Pedro Azagra Blázquez | ||||||||
Director and Chief Executive Officer |
Date: April 24, 2024 | /s/ Justin B. Lagasse | |||||||
Justin B. Lagasse | ||||||||
Senior Vice President - Chief Financial Officer and Controller |
/s/ Pedro Azagra Blázquez | ||
Pedro Azagra Blázquez | ||
Director and Chief Executive Officer | ||
Avangrid, Inc. | ||
April 24, 2024 |
/s/ Justin B. Lagasse | ||
Justin B. Lagasse | ||
Senior Vice President - Chief Financial Officer and Controller | ||
Avangrid, Inc. | ||
April 24, 2024 |
Condensed Consolidated Statements of Comprehensive Income (unaudited) - USD ($) $ in Millions |
3 Months Ended | |
---|---|---|
Mar. 31, 2024 |
Mar. 31, 2023 |
|
Statement of Comprehensive Income [Abstract] | ||
Net Income | $ 322 | $ 215 |
Other Comprehensive Income | ||
Unrealized loss from equity method investment, net of income taxes of $0 and $0, respectively | 0 | (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 Income | 368 | 264 |
Net loss attributable to noncontrolling interests | 29 | 30 |
Comprehensive Income Attributable to Avangrid, Inc. | $ 397 | $ 294 |
Condensed Consolidated Statements of Comprehensive Income (unaudited) (Parenthetical) - USD ($) $ in Millions |
3 Months Ended | |
---|---|---|
Mar. 31, 2024 |
Mar. 31, 2023 |
|
Statement of Comprehensive Income [Abstract] | ||
Unrealized gain from equity method investment, income taxes | $ 0 | $ 0 |
Unrealized loss during the period on derivatives qualifying as cash flow hedges, income taxes | (15) | 1 |
Reclassification to net income of loss on cash flow hedges, income taxes | $ (2) | $ (18) |
Condensed Consolidated Balance Sheets (unaudited) (Parenthetical) - USD ($) $ in Millions |
Mar. 31, 2024 |
Dec. 31, 2023 |
---|---|---|
Property, plant and equipment | $ 33,323 | $ 32,857 |
Common stock, par value (in dollars per share) | $ 0.01 | $ 0.01 |
Common stock, authorized (in shares) | 500,000,000 | 500,000,000 |
Common stock, issued (in shares) | 388,008,132 | 387,872,787 |
Common stock, outstanding (in shares) | 386,906,260 | 386,770,915 |
Variable Interest Entity, Primary Beneficiary | ||
Property, plant and equipment | $ 2,621 | $ 2,643 |
Condensed Consolidated Statements of Changes in Equity (unaudited) (Parenthetical) - USD ($) $ in Millions |
3 Months Ended | |
---|---|---|
Mar. 31, 2024 |
Mar. 31, 2023 |
|
Statement of Stockholders' Equity [Abstract] | ||
Other comprehensive loss, tax | $ 17 | $ 17 |
Dividends declared (in dollars per share) | $ 0.44 | $ 0.44 |
Common stock, par value (in dollars per share) | $ 0.01 | $ 0.01 |
Background and Nature of Operations |
3 Months Ended |
---|---|
Mar. 31, 2024 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Background and Nature of Operations | 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
|
Basis of Presentation |
3 Months Ended |
---|---|
Mar. 31, 2024 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Basis of Presentation | 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.
|
Significant Accounting Policies and New Accounting Pronouncements |
3 Months Ended |
---|---|
Mar. 31, 2024 | |
Accounting Policies [Abstract] | |
Significant Accounting Policies and New Accounting Pronouncements | 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 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.
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Revenue |
3 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Revenue from Contract with Customer [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Revenue | 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 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. 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:
(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. 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, 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).
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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 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, 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. 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 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:
“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 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 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. Regulatory liabilities as of March 31, 2024 and December 31, 2023, respectively, consisted of:
“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 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. “Debt rate reconciliation” represents the over/under collection of costs related to debt instruments identified in the rate case. Costs would include interest, commissions and fees versus amounts included in rates. “Rate refund - FERC ROE proceeding” represents the reserve associated with the FERC proceeding around the base return on equity (ROE) reflected in ISO New England, Inc.’s (ISO-NE) open access transmission tariff (OATT). See Note 8 for more details. “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. “Merger-related rate credits” resulted from the acquisition of UIL. This is being used to moderate increases in rates. During the three months ended March 31, 2024 and 2023, $1 million and $1 million 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. “Middletown/Norwalk local transmission network service collections” represents allowance for funds used during construction of the Middletown/Norwalk transmission line, which is being amortized over the useful life of the project. “Non-firm margin sharing credits” represents the portion of interruptible and off-system sales revenue set aside to fund gas expansion projects. “Other” includes various items subject to reconciliation or being returned through rates, such as service quality metrics.
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Fair Value of Financial Instruments and Fair Value Measurements |
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Fair Value Disclosures [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Fair Value of Financial Instruments and Fair Value Measurements | Fair Value of Financial Instruments and Fair Value Measurements We determine the fair value of our derivative assets and liabilities and non-current equity investments associated with Networks’ activities utilizing market approach valuation techniques: •Our equity and other investments consist of Rabbi Trusts. Our Rabbi Trusts, which cover certain deferred compensation plans and non-qualified pension plan obligations, consists of equity and other investments. The Rabbi Trusts primarily invest in equity securities, fixed income and money market funds. Certain Rabbi Trusts also invest in trust or company owned life insurance policies. We measure the fair value of our Rabbi Trust portfolio using observable, unadjusted quoted market prices in active markets for identical assets and include the measurements in Level 1. We measure the fair value of the supplemental retirement benefit life insurance trust based on quoted prices in the active markets for the various funds within which the assets are held and include the measurement in Level 2. •NYSEG and RG&E enter into electric energy derivative contracts to hedge the forecasted purchases required to serve their electric load obligations. They hedge their electric load obligations using derivative contracts that are settled based upon Locational Based Marginal Pricing published by the NYISO. NYSEG and RG&E hedge approximately 70% of their electric load obligations using contracts for a NYISO location where an active market exists. The forward market prices used to value the companies’ open electric energy derivative contracts are based on quoted prices in active markets for identical assets or liabilities with no adjustment required and therefore we include the fair value measurements in Level 1. •NYSEG and RG&E enter into natural gas derivative contracts to hedge their forecasted purchases required to serve their natural gas load obligations. NYSEG and RG&E hedge up to approximately 55% of their forecasted winter demand through the use of financial transactions and storage withdrawals. The forward market prices used to value open natural gas derivative contracts are exchange-based prices for the identical derivative contracts traded actively on the New York Mercantile Exchange (NYMEX). We include the fair value measurements in Level 1 because we use prices quoted in an active market. •NYSEG, RG&E and CMP enter into fuel derivative contracts to hedge their unleaded and diesel fuel requirements for their fleet vehicles. Exchange-based forward market prices are used, but because an unobservable basis adjustment is added to the forward prices, we include the fair value measurement for these contracts in Level 3. •UI enters into CfDs, which are marked-to-market based on a probability-based expected cash flow analysis that is discounted at risk-free interest rates and an adjustment for non-performance risk using credit default swap rates. We include the fair value measurement for these contracts in Level 3 (See Note 7 for further discussion of CfDs). We determine the fair value of our derivative assets and liabilities associated with Renewables activities utilizing market approach valuation techniques. Exchange-traded transactions, such as NYMEX futures contracts, that are based on quoted market prices in active markets for identical products with no adjustment are included in fair value Level 1. Contracts with delivery periods of two years or less which are traded in active markets and are valued with or derived from observable market data for identical or similar products such as over-the-counter NYMEX foreign exchange swaps, and fixed price physical and basis and index trades are included in fair value Level 2. Contracts with delivery periods exceeding two years or that have unobservable inputs or inputs that cannot be corroborated with market data for identical or similar products are included in fair value Level 3. The unobservable inputs include modeled volumes on unit-contingent contracts, extrapolated power curves through May 2032 and scheduling assumptions on California power exports to cover Nevada physical power sales. The valuation for this category is based on our judgments about the assumptions market participants would use in pricing the asset or liability since limited market data exists. We determine the fair value of our interest rate derivative instruments based on a model whose inputs are observable, such as SOFR, forward interest rate curves or other relevant benchmark. We include the fair value measurement for these contracts in Level 2 (See Note 7 for further discussion of interest rate contracts). We determine the fair value of our foreign currency exchange derivative instruments based on current exchange rates compared to the rates at inception of the hedge. We include the fair value measurement for these contracts in Level 2. The carrying amounts for cash and cash equivalents, restricted cash, accounts receivable, accounts payable, notes payable, lease obligations and interest accrued approximate fair value. Restricted cash was $3 million as of both March 31, 2024 and December 31, 2023, respectively and is included in "Other Assets" on our condensed consolidated balance sheets. The financial instruments measured at fair value as of March 31, 2024 and December 31, 2023, respectively, consisted of:
The reconciliation of changes in the fair value of financial instruments based on Level 3 inputs for the three months ended March 31, 2024 and 2023, respectively, is as follows:
Level 3 Fair Value Measurement The table below illustrates the significant sources of unobservable inputs used in the fair value measurement of our Level 3 derivatives and the variability in prices for those transactions classified as Level 3 derivatives.
Our Level 3 valuations primarily consist of a Hydro PPA utilized for balancing services for the Northwest wind fleet, power swaps with delivery periods extending through May 2032 hedging Midwest and Texas wind farms and physical power sales agreements in Nevada. We considered the measurement uncertainty regarding the Level 3 gas and power positions to changes in the valuation inputs. Given the nature of the transactions in Level 3, the primary input to the valuation is the market price of gas or power for transactions with delivery periods exceeding two years. The fixed price power swaps are economic hedges of future power generation, with decreases in power prices resulting in unrealized gains and increases in power prices resulting in unrealized losses. The hydro PPA is a long capacity/energy position in the Northwest that provides balancing services with increases in power prices resulting in unrealized gains and decreases in power prices resulting in unrealized losses. The gas swaps are economic hedges of fuel purchases for a combined cycle gas plant, with increases in gas prices resulting in unrealized gains and decreases in gas prices resulting in unrealized losses. As all transactions are economic hedges of the underlying position, any changes in the fair value of these transactions will be offset by changes in the anticipated purchase/sales price of the underlying commodity. Two elements of the analytical infrastructure employed in valuing transactions are the price curves used in the calculation of market value and the modeled volumes on unit-contingent agreements. We maintain and document authorized trading points and associated forward price curves, and we develop and document models used in valuation of the various products. Transactions are valued in part on the basis of forward prices and estimated volumes. We maintain and document descriptions of these curves and their derivations. Forward price curves used in valuing the transactions are applied to the full duration of the transaction. The determination of fair value of the CfDs (see Note 7 for further details on CfDs) was based on a probability-based expected cash flow analysis that was discounted at risk-free interest rates, as applicable, and an adjustment for non-performance risk using credit default swap rates. Certain management assumptions were required, including development of pricing that extends over the term of the contracts. We believe this methodology provides the most reasonable estimates of the amount of future discounted cash flows associated with the CfDs. Additionally, on a quarterly basis, we perform analytics to ensure that the fair value of the derivatives is consistent with changes, if any, in the various fair value model inputs. Significant isolated changes in the risk of non-performance, the discount rate or the contract term pricing would result in an inverse change in the fair value of the CfDs. Additional quantitative information about Level 3 fair value measurements of the CfDs is as follows:
Fair Value of Debt As of March 31, 2024 and December 31, 2023, debt consisted of first mortgage bonds, unsecured pollution control notes and other various non-current debt securities. The estimated fair value of debt was $10,136 million and $10,266 million as of March 31, 2024 and December 31, 2023, respectively. The estimated fair value was determined, in most cases, by discounting the future cash flows at market interest rates. The interest rates used to make these calculations take into account the credit ratings of the borrowers in each case. The fair value of debt is considered Level 2 within the fair value hierarchy.
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Derivative Instruments and Hedging |
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Derivative Instruments and Hedging Activities Disclosure [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Derivative Instruments and Hedging | Derivative Instruments and Hedging Our operating and financing activities are exposed to certain risks, which are managed by using derivative instruments. All derivative instruments are recognized as either assets or liabilities at fair value on our condensed consolidated balance sheets in accordance with the accounting requirements concerning derivative instruments and hedging activities. (a) Networks activities The tables below present Networks' derivative positions as of March 31, 2024 and December 31, 2023, respectively, including those subject to master netting agreements and the location of the net derivative positions on our condensed consolidated balance sheets:
The net notional volumes of the outstanding derivative instruments associated with Networks' activities as of March 31, 2024 and December 31, 2023, respectively, consisted of:
Derivatives not designated as hedging instruments NYSEG and RG&E have an electric commodity charge that passes costs for the market price of electricity through rates. We use electricity contracts, both physical and financial, to manage fluctuations in electricity commodity prices in order to provide price stability to customers. We include the cost or benefit of those contracts in the amount expensed for electricity purchased when the related electricity is sold. We record changes in the fair value of electric hedge contracts to derivative assets and/or liabilities with an offset to regulatory assets and/or regulatory liabilities, in accordance with the accounting requirements concerning regulated operations. NYSEG and RG&E have purchased gas adjustment clauses that allow us to recover through rates any changes in the market price of purchased natural gas, substantially eliminating our exposure to natural gas price risk. NYSEG and RG&E use natural gas futures and forwards to manage fluctuations in natural gas commodity prices to provide price stability to customers. We include the cost or benefit of natural gas futures and forwards in the commodity cost that is passed on to customers when the related sales commitments are fulfilled. We record changes in the fair value of natural gas hedge contracts to derivative assets and/or liabilities with an offset to regulatory assets and/or regulatory liabilities in accordance with the accounting requirements for regulated operations. The amounts for electricity hedge contracts and natural gas hedge contracts recognized in regulatory liabilities and assets as of March 31, 2024 and December 31, 2023 and amounts reclassified from regulatory assets and liabilities into income for the three months ended March 31, 2024 and 2023 are as follows:
Pursuant to a PURA order, UI and Connecticut’s other electric utility, CL&P, each executed two long-term CfDs with certain incremental capacity resources, each of which specifies a capacity quantity and a monthly settlement that reflects the difference between a forward market price and the contract price. The costs or benefits of each contract will be paid by or allocated to customers and will be subject to a cost-sharing agreement between UI and CL&P pursuant to which approximately 20% of the cost or benefit is borne by or allocated to UI customers and approximately 80% is borne by or allocated to CL&P customers. PURA has determined that costs associated with these CfDs will be fully recoverable by UI and CL&P through electric rates, and UI has deferred recognition of costs (a regulatory asset) or obligations (a regulatory liability), including carrying costs. For those CfDs signed by CL&P, UI records its approximate 20% portion pursuant to the cost-sharing agreement noted above. As of March 31, 2024, UI has recorded a gross derivative asset of $1 million ($0 of which is related to UI’s portion of the CfD signed by CL&P), a regulatory asset of $33 million, a gross derivative liability of $34 million ($33 million of which is related to UI’s portion of the CfD signed by CL&P) and a regulatory liability of $0. As of December 31, 2023, UI had recorded a gross derivative asset of $1 million ($0 of which is related to UI’s portion of the CfD signed by CL&P), a regulatory asset of $38 million, a gross derivative liability of $39 million ($38 million of which is related to UI’s portion of the CfD signed by CL&P) and a regulatory liability of $0. The unrealized gains and losses from fair value adjustments to these derivatives, which are recorded in regulatory assets, for the three months ended March 31, 2024 and 2023, respectively, were as follows:
Derivatives designated as hedging instruments The effect of derivatives in cash flow hedging relationships on Other Comprehensive Income (OCI) and income for the three months ended March 31, 2024 and 2023, respectively, consisted of:
(a) Changes in accumulated OCI are reported on a pre-tax basis. The net loss in accumulated OCI related to previously settled forward starting swaps and accumulated amortization is $38 million and $39 million as of March 31, 2024 and December 31, 2023, respectively. For the three months ended March 31, 2024 and 2023, we recorded net derivative losses related to discontinued cash flow hedges of $1 million and $1 million, respectively. We will amortize approximately $4 million of discontinued cash flow hedges within the next twelve months. (b) Renewables activities Renewables sells fixed-price gas and power forwards to hedge our merchant wind assets from declining commodity prices for our Renewables business. Renewables also purchases fixed-price gas and basis swaps and sells fixed-price power in the forward market to hedge the spark spread or heat rate of our merchant thermal assets and enters into tolling arrangements to sell the output of its thermal generation facilities. Renewables has proprietary trading operations that enter into fixed-price power and gas forwards in addition to basis swaps. The intent is to speculate on fixed-price commodity and basis volatility in the U.S. commodity markets. Renewables will periodically designate derivative contracts as cash flow hedges for both its thermal and wind portfolios. The fair value changes are recorded in OCI. For thermal operations, Renewables will periodically designate both fixed price NYMEX gas contracts and natural gas basis swaps that hedge the fuel requirements of its Klamath Plant in Klamath, Oregon. Renewables will also designate fixed price power swaps at various locations in the U.S. market to hedge future power sales from its Klamath facility and various wind farms. The net notional volumes of outstanding derivative instruments associated with Renewables' activities as of March 31, 2024 and December 31, 2023, respectively, consisted of:
The fair values of derivative contracts associated with Renewables' activities as of March 31, 2024 and December 31, 2023, respectively, consisted of:
On May 27, 2021, Renewables entered into a forward interest rate swap, with a total notional amount of $935 million, to hedge the issuance of forecasted variable rate debt. The forward interest rate swap is designated and qualifies as a cash flow hedge. As part of the financial close of Vineyard Wind 1 described in Note 19, this hedge was novated to the lending institutions and the notional value changed to $956 million. As of March 31, 2024 and December 31, 2023, the fair value of the interest rate swap was $158 million and $122 million, respectively, as non-current assets. The gain or loss on the interest rate swap is reported as a component of accumulated OCI and will be reclassified into earnings in the period or periods during which the related interest expense on the debt is incurred. The tables below present Renewables' derivative positions as of March 31, 2024 and December 31, 2023, respectively, including those subject to master netting agreements and the location of the net derivative position on our condensed consolidated balance sheets:
Derivatives not designated as hedging instruments The effects of trading and non-trading derivatives associated with Renewables' activities for the three months ended March 31, 2024 and 2023, consisted of:
Derivatives designated as hedging instruments The effect of derivatives in cash flow hedging relationships on accumulated OCI and income for the three months ended March 31, 2024 and 2023, respectively, consisted of:
(a) Changes in OCI are reported on a pre-tax basis. Amounts are reclassified from accumulated OCI into income in the period during which the transaction being hedged affects earnings or when it becomes probable that a forecasted transaction being hedged would not occur. Notwithstanding future changes in prices, approximately $20 million of losses included in accumulated OCI at March 31, 2024, are expected to be reclassified into earnings within the next twelve months. We recorded immaterial amounts of net derivative losses related to discontinued cash flow hedges for both the three months ended March 31, 2024 and 2023. (c) Interest rate contracts Avangrid uses financial derivative instruments from time to time to alter its fixed and floating rate debt balances or to hedge fixed rates in anticipation of future fixed rate issuances. As of March 31, 2024 and December 31, 2023, the net loss in accumulated OCI related to previously settled interest rate contracts was $27 million and $29 million, respectively. For both the three months ended March 31, 2024 and 2023, we amortized into income $2 million of the loss related to settled interest rate contracts. We will amortize approximately $9 million of the net loss on the interest rate contracts within the next twelve months. The effect of derivatives in cash flow hedging relationships on accumulated OCI for the three months ended March 31, 2024 and 2023, respectively, consisted of:
(a) Changes in OCI are reported on a pre-tax basis. The amounts in accumulated OCI are being reclassified into earnings over the underlying debt maturity periods which end in 2025 and 2029. On July 15, 2021, Corporate entered into an interest rate swap to hedge the fair value of $750 million of existing debt included in "Non-current debt" on our consolidated balance sheets. The interest rate swap is designated and qualifies as a fair value hedge. The change in the fair value of the interest rate swap and the offsetting change in the fair value of the underlying debt are reported as components of "Interest expense." The effects on our consolidated financial statements as of and for the three months ended March 31, 2024 and 2023 are as follows:
(d) Counterparty credit risk management NYSEG and RG&E face risks related to counterparty performance on hedging contracts due to counterparty credit default. We have developed a matrix of unsecured credit thresholds that are applicable based on the respective counterparty’s or the counterparty guarantor’s credit rating, as provided by Moody’s or Standard & Poor’s. When our exposure to risk for a counterparty exceeds the unsecured credit threshold, the counterparty is required to post additional collateral or we will no longer transact with the counterparty until the exposure drops below the unsecured credit threshold. The wholesale power supply agreements of UI contain default provisions that include required performance assurance, including certain collateral obligations, in the event that UI’s credit ratings on senior debt were to fall below investment grade. If such an event had occurred as of March 31, 2024, UI would have had to post an aggregate of approximately $27 million in collateral. We have various master netting arrangements in the form of multiple contracts with various single counterparties that are subject to contractual agreements that provide for the net settlement of all contracts through a single payment. Those arrangements reduce our exposure to a counterparty in the event of a default on or termination of any single contract. For financial statement presentation purposes, we offset fair value amounts recognized for derivative instruments and fair value amounts recognized for the right to reclaim or the obligation to return cash collateral arising from derivative instruments executed with the same counterparty under a master netting arrangement. As of both March 31, 2024 and December 31, 2023, the amount of cash collateral under master netting arrangements that has not been offset against net derivative positions was $63 million. Derivative instruments settlements and collateral payments are included throughout the “Changes in operating assets and liabilities” section of operating activities in our condensed consolidated statements of cash flows. Certain of our derivative instruments contain provisions that require us to maintain an investment grade credit rating on our debt from each of the major credit rating agencies. If our debt were to fall below investment grade, we would be in violation of those provisions and the counterparties to the derivative instruments could request immediate payment or demand immediate and ongoing full overnight collateralization on derivative instruments in net liability positions. The aggregate fair value of all derivative instruments with credit risk related contingent features that are in a liability position as of March 31, 2024 was $13 million, for which we have posted collateral.
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Contingencies and Commitments |
3 Months Ended |
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Mar. 31, 2024 | |
Commitments and Contingencies Disclosure [Abstract] | |
Contingencies and Commitments | Contingencies and Commitments We are party to various legal disputes arising as part of our normal business activities. We assess our exposure to these matters and record estimated loss contingencies when a loss is probable and can be reasonably estimated. We do not provide for accrual of legal costs expected to be incurred in connection with a loss contingency. Transmission - ROE Complaint – CMP and UI On September 30, 2011, the Massachusetts Attorney General, DPU, PURA, New Hampshire Public Utilities Commission, Rhode Island Division of Public Utilities and Carriers, Vermont Department of Public Service, numerous New England consumer advocate agencies and transmission tariff customers collectively filed a joint complaint with the FERC, pursuant to sections 206 and 306 of the Federal Power Act against several NETOs claiming that the approved base ROE of 11.14% used by NETOs in calculating formula rates for transmission service under the ISO-New England Open Access Transmission Tariff (OATT) was not just and reasonable and seeking a reduction of the base ROE of 9.2%. CMP and UI are NETOs with assets and service rates that are governed by the OATT and will thereby be affected by any FERC order resulting from the filed complaint. On December 26, 2012, a second related complaint for a subsequent rate period was filed requesting the ROE be reduced to 8.7%. On July 31, 2014, a third related complaint was filed for a subsequent rate period requesting the ROE be reduced to 8.84%. On April 29, 2016, a fourth complaint was filed for a rate period subsequent to prior complaints requesting the base ROE be 8.61% and ROE Cap be 11.24%. On October 16, 2018, the FERC issued an order directing briefs and proposing a new methodology to calculate the NETOs ROE that is contained in NETOs’ transmission formula rate on file at FERC. We cannot predict the final outcome of the proceedings. Customer Invoice Dispute On May 4, 2021, Nike USA, Inc. (Nike), the buyer under a virtual PPA with a subsidiary of Renewables, provided notice that it disagrees with the settlement amounts included in certain invoices. The PPA provides for a monthly settlement between the parties based on the metered output of the project based on a stated hub price. The disagreement relates as to the appropriate hub price to use for settlement calculations, most notably during Winter Storm Uri in February of 2021. Nike has requested an adjustment to the invoices that would increase the amount payable by approximately $31 million. Renewables has responded that the invoices have been properly calculated in accordance with the provisions of the PPA, and that Nike is not entitled to any further payments. On June 16, 2023, Nike filed suit against the Company and certain subsidiaries of Renewables alleging breach of contract, and seeking more than $31 million in invoice adjustments, fees, and interest. The Company filed a motion to dismiss the complaint, which the Circuit Court of the State of Oregon for the County of Multnomah denied on October 25, 2023 following oral arguments. The case is currently proceeding with an expected trial beginning on October 14, 2024. We cannot predict the outcome of this matter. Solar Contractor Dispute Renewables, through certain subsidiaries, has Engineering, Procurement and Construction (EPC) contracts with Sterling and Wilson Solar Solutions, Inc. (SWSS) for the construction of two Solar farms–Lund Hill in Klickitat, WA (Lund Hill), and Pachwáywit Fields in Gillam County, OR (Montague). Renewables believes that SWSS is in default of a number of its obligations under the respective EPC contracts, including construction flaws and failing to pay certain subcontractors. As a result, Renewables drew on Letters of Credit for both Montague and Lund Hill. In response, SWSS filed liens on both projects totaling approximately $105 million claiming that this amount is due under EPC contracts. Renewables has bonded over the liens on both properties. On October 27, 2023, SWSS commenced foreclosure actions in Oregon on the lien at Montague, and added claims for breach of contract and quantum meruit, seeking up to $111.8 million. SWSS has also commenced foreclosure procedures in Washington State against Lund Hill seeking to close on its lien of $59.9 million. On February 26, 2024, SWSS filed a lawsuit against Lund Hill and Renewables in New York State court alleging breach of contract, quantum meruit and violation of the Prompt Payment Act, all based on the same facts as the previously filed foreclosure matter seeking $59.9 million in damages. We cannot predict the outcome of these disputes. Guarantee Commitments to Third Parties As of March 31, 2024, we had approximately $918 million of standby letters of credit, surety bonds, guarantees and indemnifications outstanding. We also provided a guaranty related to Renewables' commitment to contribute equity to Vineyard Wind and an indemnification of Vineyard Wind tax equity investors as described in Note 19, which are in addition to the amounts above. These instruments provide financial assurance to the business and trading partners of Avangrid, its subsidiaries and equity method investees in their normal course of business. The instruments only represent liabilities if Avangrid or its subsidiaries fail to deliver on contractual obligations. We therefore believe it is unlikely that any material liabilities associated with these instruments will be incurred and, accordingly, as of March 31, 2024, neither we nor our subsidiaries have any liabilities recorded for these instruments. NECEC Commitments On January 4, 2021, CMP transferred the NECEC project to NECEC Transmission LLC, a wholly-owned subsidiary of Networks. Among other things, NECEC Transmission LLC and/or CMP committed to approximately $90 million of future payments to support various programs in the state of Maine, of which approximately $11 million was paid through the three months ended March 31, 2024.
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Environmental Liabilities |
3 Months Ended |
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Mar. 31, 2024 | |
Environmental Remediation Obligations [Abstract] | |
Environmental Liabilities | Environmental Liabilities Environmental laws, regulations and compliance programs may occasionally require changes in our operations and facilities and may increase the cost of electric and natural gas service. We do not provide for accruals of legal costs expected to be incurred in connection with loss contingencies. Waste sites The Environmental Protection Agency and various state environmental agencies, as appropriate, have notified us that we are among the potentially responsible parties that may be liable for costs incurred to remediate certain hazardous substances at twenty-four waste sites, which do not include sites where gas was manufactured in the past. Sixteen of the twenty-four sites are included in the New York State Registry of Inactive Hazardous Waste Disposal Sites; two sites are included in Maine’s Uncontrolled Sites Program; and one site is included on the Massachusetts Non-Priority Confirmed Disposal Site list. The remaining sites are not included in any registry list. Finally, five of the twenty-four sites are also included on the National Priorities list. Any liability may be joint and several for certain sites. We have recorded an estimated liability of $6 million related to six of the twenty-four sites. We have paid remediation costs related to the remaining eighteen sites and do not expect to incur additional liabilities. Additionally, we have recorded an estimated liability of $10 million related to another ten sites where we believe it is probable that we will incur remediation and/or monitoring costs, although we have not been notified that we are among the potentially responsible parties or that we are regulated under State Resource Conservation and Recovery Act programs. It is possible the ultimate cost to remediate these sites may be significantly more than the accrued amount. As of March 31, 2024, our estimate for costs to remediate these sites ranges from $15 million to $22 million. Factors affecting the estimated remediation amount include the remedial action plan selected, the extent of site contamination, and the allocation of the clean-up costs. Manufactured Gas Plants We have a program to investigate and perform necessary remediation at our fifty-three sites where gas was manufactured in the past (Manufactured Gas Plants, or MGPs). Six sites are included in the New York State Registry, thirty-nine sites are included in the New York State Department of Environmental Conservation (NYSDEC) Multi-Site Order of Consent; two sites with individual NYSDEC Orders of Consent; two sites under a Brownfield Cleanup Program and two sites are included in Maine Department of Environmental Protection programs (none in the Voluntary Response Action Program, Brownfield Cleanup Program and Uncontrolled Sites Program). The remaining sites are not included in a formal program. We have entered into consent orders with various environmental agencies to investigate and, where necessary, remediate forty-one of the fifty-three sites. As of March 31, 2024, our estimate for all costs related to investigation and remediation of the fifty-three sites ranges from $117 million to $213 million. Our estimate could change materially based on facts and circumstances derived from site investigations, changes in required remedial actions, changes in technology relating to remedial alternatives and changes to current laws and regulations. Certain of our Connecticut and Massachusetts regulated gas companies own or have previously owned properties where MGPs had historically operated. MGP operations have led to contamination of soil and groundwater with petroleum hydrocarbons, benzene and metals, among other things, at these properties, the regulation and cleanup of which is regulated by the federal Resource Conservation and Recovery Act as well as other federal and state statutes and regulations. Each of the companies has or had an ownership interest in one or more of such properties contaminated as a result of MGP-related activities. Under the existing regulations, the cleanup of such sites requires state and at times, federal, regulators’ involvement and approval before cleanup can commence. In certain cases, such contamination has been evaluated, characterized and remediated. In other cases, the sites have been evaluated and characterized, but not yet remediated. Finally, at some of these sites, the scope of the contamination has not yet been fully characterized; as of March 31, 2024, no liability was recorded related to these sites and no amount of loss, if any, can be reasonably estimated at this time. In the past, the companies have received approval for the recovery of MGP-related remediation expenses from customers through rates and will seek recovery in rates for ongoing MGP-related remediation expenses for all of their MGP sites. As of both March 31, 2024 and December 31, 2023, the liability associated with our MGP sites in Connecticut was $112 million, the remediation costs of which could be significant and will be subject to a review by PURA as to whether these costs are recoverable in rates. As of March 31, 2024 and December 31, 2023, our total recorded liability to investigate and perform remediation at all known inactive MGP sites discussed above and other sites was $245 million and $250 million, respectively. We recorded a corresponding regulatory asset, net of insurance recoveries and the amount collected from FirstEnergy, as described below, because we expect to recover the net costs in rates. Our environmental liability accruals are recorded on an undiscounted basis and are expected to be paid through the year 2058. FirstEnergy NYSEG and RG&E each sued FirstEnergy under the Comprehensive Environmental Response, Compensation, and Liability Act to recover environmental cleanup costs at certain former MGP sites, which are included in the discussion above. In 2011, the District Court issued a decision and order in NYSEG’s favor, which was upheld on appeal, requiring FirstEnergy to pay NYSEG for past and future clean-up costs at the sixteen sites in dispute. In 2008, the District Court issued a decision and order in RG&E's favor requiring FirstEnergy to pay RG&E for past and future clean-up costs at the two MGP sites in dispute. FirstEnergy remains liable for a substantial share of clean up expenses at the MGP sites. Based on projections as of March 31, 2024, FirstEnergy’s share of clean-up costs owed to NYSEG & RG&E is estimated at approximately $8 million and $5 million, respectively. These amounts are being treated as contingent assets and have not been recorded as either a receivable or a decrease to the environmental provision. Any recovery will be flowed through to NYSEG and RG&E customers, as applicable. English Station On August 4, 2016, DEEP issued a partial consent order (the consent order), that requires UI to investigate and remediate certain environmental conditions within the perimeter of a former generation site on the Mill River in New Haven (English Station) that UI sold to Quinnipiac Energy in 2000. Under the consent order, to the extent that the cost of this investigation and remediation is less than $30 million, UI will remit to the State of Connecticut the difference between such cost and $30 million. UI must comply with the terms of the consent order, but may seek to recover costs above $30 million in consultation with the state. UI continues its activities to investigate and remediate the environmental conditions at the site. In 2023 and 2024, DEEP sent UI a series of letters requesting details on remediation plans and security, which UI has responded to. On January 25, 2024, DEEP issued a notice of declaratory ruling to determine the “high occupancy standard” necessary “to abate on-site pollution and impacts for industrial/commercial use of the Site…inside the buildings” as referenced in section (B)(1)(e)(4) of the Partial Consent Order. On February 26, 2024, UI was granted intervenor status and it subsequently submitted its written comments objecting to the proceedings on March 11, 2024. On January 29, 2024, DEEP served UI with a Summons and Complaint seeking injunctive relief and enforcement of the consent order from the Connecticut Superior Court. On April 9, 2024, the application to transfer the proceedings to the Complex Litigation Docket of the Connecticut Superior Court was granted. The court also granted UI’s Motion to Stay the proceeding until the April 30, 2024 court conference. As of both March 31, 2024 and December 31, 2023, the amount reserved related to English Station was $19 million. Since its inception, we have recorded $35 million to the reserve which has been offset with cash payments over time. We cannot predict the outcome of these proceedings. Eagle Takings Inquiry In April 2023, Avangrid Renewables received a letter from the U.S. Fish and Wildlife Service regarding certain bald and golden eagle fatalities that allegedly occurred at certain Avangrid Renewables facilities that are not covered by an eagle take permit. Avangrid Renewables has responded to the U.S. Fish and Wildlife Service providing information about the relevant eagle taking permit applications and relevant mitigation activity at each facility. On February 12, 2024, the U.S. Fish and Wildlife Service published a new Eagle Rule, superseding the 2016 Eagle Rule. Avangrid Renewables subsequently communicated to the U.S. Fish and Wildlife Service that it would be applying for the General Permit option under the new Eagle Rule and is waiting for the permit application form to become available in the preferred electronic permit platform, ePermits. The U.S. Fish and Wildlife Service acknowledged receipt of this communication. We cannot predict the outcome of these applications.
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Post-retirement and Similar Obligations |
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Post-retirement and Similar Obligations | Post-retirement and Similar Obligations We made $1 million of pension contributions for the three months ended March 31, 2024. We expect to make additional contributions of $27 million for the remainder of 2024. The components of net periodic benefit cost for pension benefits for the three months ended March 31, 2024 and 2023, respectively, consisted of:
The components of net periodic benefit cost for postretirement benefits for the three months ended March 31, 2024 and 2023, respectively, consisted of:
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Equity |
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Equity | Equity As of both March 31, 2024 and December 31, 2023, we had 103,889 shares of common stock held in trust, respectively, and no convertible preferred shares outstanding. During the three months ended March 31, 2024 and 2023, we issued 135,345 and 12,332 shares of common stock, respectively, each having a par value of $0.01, and released 0 shares of common stock held in trust. We maintain a repurchase agreement with J.P. Morgan Securities, LLC. (JPM), pursuant to which JPM will, from time to time, acquire, on behalf of Avangrid, shares of common stock of Avangrid. The purpose of the stock repurchase program is to allow Avangrid to maintain Iberdrola's relative ownership percentage of approximately 81.5%. The stock repurchase program may be suspended or discontinued at any time upon notice. As of March 31, 2024, a total of 997,983 shares have been repurchased in the open market, all of which are included as Avangrid treasury shares. The total cost of all repurchases, including commissions, was $47 million as of March 31, 2024. Accumulated Other Comprehensive Income (Loss) Accumulated Other Comprehensive Loss for the three months ended March 31, 2024 and 2023, respectively, consisted of:
(a) Foreign currency and interest rate contracts. (b) Reclassification is reflected in the operating expenses and interest expense, net of capitalization line items in our consolidated statements of income.
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Earnings Per Share |
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Earnings Per Share | Earnings Per Share Basic earnings per share is computed by dividing net income attributable to Avangrid by the weighted-average number of shares of our common stock outstanding. During the three months ended March 31, 2024 and 2023, while we did have securities that were dilutive, these securities did not result in a change in our earnings per share calculations. The calculations of basic and diluted earnings per share attributable to Avangrid, for the three months ended March 31, 2024 and 2023, respectively, consisted of:
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Segment Information |
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Segment Information | Segment Information Our segment reporting structure uses our management reporting structure as its foundation to reflect how Avangrid manages the business internally and is organized by type of business. We report our financial performance based on the following two reportable segments: •Networks: includes all of the energy transmission and distribution activities, any other regulated activity originating in New York and Maine and regulated electric distribution, electric transmission and gas distribution activities originating in Connecticut and Massachusetts. The Networks reportable segment includes nine rate regulated operating segments. These operating segments generally offer the same services distributed in similar fashions, have the same types of customers, have similar long-term economic characteristics and are subject to similar regulatory requirements, allowing these operations to be aggregated into one reportable segment. •Renewables: activities relating to renewable energy, mainly wind energy generation and trading related with such activities. The chief operating decision maker evaluates segment performance based on segment adjusted net income defined as net income adjusted to exclude mark-to-market earnings from changes in the fair value of derivative instruments and accelerated depreciation from the repowering of wind farms. Products and services are sold between reportable segments and affiliate companies at cost. Segment income, expense and assets presented in the accompanying tables include all intercompany transactions that are eliminated in our condensed consolidated financial statements. Refer to Note 4 - Revenue for more detailed information on revenue by segment. Segment information as of and for the three months ended March 31, 2024, consisted of:
(a) Includes Corporate and intersegment eliminations. Segment information for the three months ended March 31, 2023 and as of December 31, 2023, consisted of:
(a) Includes Corporate and intersegment eliminations. Reconciliation of Adjusted Net Income to Net Income attributable to Avangrid for the three months ended March 31, 2024 and 2023, respectively, is as follows:
(1)Mark-to-market earnings relates to earnings impacts from changes in the fair value of Renewables' derivative instruments associated with electricity and natural gas. (2)Represents the amount of accelerated depreciation derived from the repowering of wind farms in Renewables.
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Related Party Transactions |
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Related Party Transactions | Related Party Transactions We engage in related party transactions that are generally billed at cost and in accordance with applicable state and federal commission regulations. Related party transactions for the three months ended March 31, 2024 and 2023, respectively, consisted of:
Related party balances as of March 31, 2024 and December 31, 2023, respectively, consisted of:
Transactions with Iberdrola, our majority shareholder, relate predominantly to the provision and allocation of corporate services and management fees. All costs that can be specifically allocated, to the extent possible, are charged directly to the company receiving such services. In situations when Iberdrola corporate services are provided to two or more companies of Avangrid, any costs remaining after direct charges are allocated using agreed upon cost allocation methods designed to allocate such costs. We believe that the allocation method used is reasonable. See Note 15 for a discussion of the Iberdrola Intragroup Green Loan. There have been no guarantees provided or received for any related party receivables or payables. These balances are unsecured and are typically settled in cash. Interest is not charged on regular business transactions but is charged on outstanding loan balances. There have been no impairments or provisions made against any affiliated balances. Avangrid optimizes its liquidity position as part of the Iberdrola Group and is a party to a liquidity agreement with a financial institution, along with certain members of the Iberdrola Group. Cash surpluses remaining after meeting the liquidity requirements of Avangrid and its subsidiaries may be deposited at the financial institution. Deposits, or credit balances, serve as collateral against the debit balances of other parties to the liquidity agreement. The balance at both March 31, 2024 and December 31, 2023, was $0. On June 18, 2023, Avangrid's credit facility with Iberdrola Financiación, S.A.U., a subsidiary of Iberdrola, matured. The facility had a limit of $500 million. On July 19, 2023, we replaced this credit facility with an increased limit of $750 million and a maturity date of June 18, 2028. Avangrid pays a quarterly facility fee of 22.5 basis points (rate per annum) on the facility based on Avangrid’s current Moody’s and S&P ratings for senior unsecured long-term debt. As of March 31, 2024 and December 31, 2023, there was $500 million and $0 outstanding amount under this credit facility, respectively. We have a bi-lateral demand note agreement with Iberdrola Solutions, LLC, which had notes payable balances of $6 million and as of both March 31, 2024 and December 31, 2023. See Note 19 - Equity Method Investments for more information on transactions with our equity method investees.
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Other Financial Statement Items |
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Other Financial Statement Items | Other Financial Statement Items Accounts receivable and unbilled revenue, net Accounts receivable and unbilled revenues, net as of March 31, 2024 and December 31, 2023 consisted of:
The change in the allowance for credit losses for the three months ended March 31, 2024 and 2023 consisted of:
The Deferred Payment Arrangements (DPA) receivable balance was $116 million and $110 million as of March 31, 2024 and December 31, 2023, respectively. The allowance for credit losses for DPAs at March 31, 2024 and December 31, 2023 was $46 million and $44 million respectively. Furthermore, the change in the allowance for credit losses associated with the DPAs for the three months ended March 31, 2024 and 2023, was $2 million and $(2) million, respectively. Prepayments and other current assets Included in prepayments and other current assets are $164 million and $142 million of prepaid other taxes as of March 31, 2024 and December 31, 2023, respectively. Property, plant and equipment and intangible assets The accumulated depreciation and amortization as of March 31, 2024 and December 31, 2023, respectively, were as follows:
As of March 31, 2024 and 2023, accrued liabilities for property, plant and equipment additions were $553 million and $239 million, respectively. Debt Commercial Paper As of March 31, 2024 and December 31, 2023, there was $1,864 million and $1,332 million of commercial paper outstanding, respectively. As of March 31, 2024 and December 31, 2023, the weighted-average interest rate on commercial paper was 5.55% and 5.65%, respectively. Intragroup Green Loan On July 19, 2023, we entered into a green term loan agreement with Iberdrola Financiación, S.A.U., a subsidiary of Iberdrola, with an aggregate principal amount of $800 million maturing on July 13, 2033 at an interest rate of 5.45% (the Intragroup Green Loan). Other current liabilities Included in other current liabilities are $224 million and $236 million of advances received as of March 31, 2024 and December 31, 2023, respectively.
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Income Tax Expense |
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Mar. 31, 2024 | |
Income Tax Disclosure [Abstract] | |
Income Tax Expense | Income Tax Expense The effective tax rate, inclusive of federal and state income tax, for the three months ended March 31, 2024 was 5.8% which is below the federal statutory tax rate of 21%, primarily due to the recognition of production tax credits, the effect of the excess deferred tax amortization resulting from the Tax Act, the equity component of allowance for funds used during construction and other property related flow through items, partially offset by tax equity financing impacts and state taxes. The effective tax rate, inclusive of federal and state income tax, for the three months ended March 31, 2023 was (9.1)%, which is below the federal statutory tax rate of 21%, primarily due to the recognition of production tax credits associated with wind production, the effect of the excess deferred tax amortization resulting from the Tax Act and the equity component of allowance for funds used during construction.
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Stock-Based Compensation Expense |
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Mar. 31, 2024 | |
Share-Based Payment Arrangement [Abstract] | |
Stock-Based Compensation Expense | Stock-Based Compensation Expense The Avangrid, Inc. Amended and Restated Omnibus Incentive Plan (the Plan) provides for, among other things, the issuance of performance stock units (PSUs), restricted stock units (RSUs) and phantom share units (Phantom Shares). Performance Stock Units In March 2023, a total number of 677,752 PSUs, before applicable taxes, were approved to be earned by participants based on achievement of certain performance and market-based metrics for the 2021 to 2022 performance period and are payable in three equal installments, net of applicable taxes, in 2023, 2024 and 2025. The remaining unvested PSUs were forfeited. The second installment was paid in March 2024, and 126,311 shares of common stock were issued to settle this installment payment. During 2023 and 2024, 1,067,500 and 15,296 PSUs, respectively, were granted to certain executives of Avangrid with achievement measured based on certain performance and market-based metrics for the 2023 to 2025 performance period. The PSUs will be payable in three equal installments, net of applicable taxes, in 2026, 2027 and 2028. Restricted Stock Units In June 2022, 25,000 RSUs were granted to an officer of Avangrid. The RSUs vest in two equal installments in 2023 and 2024, provided that the grantee remains continuously employed with Avangrid through the applicable vesting dates. The fair value on the grant date was determined based on a price of $47.64 per share. The second and final installment of this RSU grant was settled in January 2024, net of applicable taxes, by issuing 9,034 shares of common stock. Phantom Share Units In February 2022, 9,000 Phantom Shares were granted to certain Avangrid executives and employees. These awards vest in four equal installments in 2022 - 2024 and will be settled in a cash amount equal to the number of Phantom Shares multiplied by the closing share price of Avangrid’s common stock on the respective vesting dates, subject to continued employment. The liability of these awards is measured based on the closing share price of Avangrid’s common stock at each reporting date until the date of settlement. In February 2024, $0.1 million was paid to settle the fourth and final installment under this plan. In February 2023, 81,000 Phantom Shares were granted to certain Avangrid executives and employees. These awards vest in three equal installments in 2024, 2025 and 2026 and will be settled in a cash amount equal to the number of Phantom Shares multiplied by the closing share price of Avangrid’s common stock on the respective vesting dates, subject to continued employment. The liability of these awards is measured based on the closing share price of Avangrid’s common stock at each reporting date until the date of settlement. In February 2024, $1.0 million was paid to settle the first installment under this plan. As of March 31, 2024 and December 31, 2023, the total liability was $1 million and $2 million, respectively, which is included in other current and non-current liabilities. The total stock-based compensation expense, which is included in "Operations and maintenance" in our condensed consolidated statements of income, for the three months ended March 31, 2024 and 2023, was $3 million and $4 million, respectively.
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Variable Interest Entities |
3 Months Ended |
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Mar. 31, 2024 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Variable Interest Entities | Variable Interest Entities We participate in certain partnership arrangements that qualify as VIEs. These arrangements consist of tax equity financing arrangements (TEFs) and partnerships in which an investor holds a noncontrolling interest and does not have substantive kick-out or participating rights. The sale of a membership interest in the TEFs represents the sale of an equity interest in a structure that is considered a sale of non-financial assets. Under the sale of non-financial assets, the membership interests in the TEFs we sell to third-party investors are reflected as noncontrolling interest on our condensed consolidated balance sheets valued based on an HLBV model. Earnings from the TEFs are recognized in net income attributable to noncontrolling interests in our condensed consolidated statements of income. We consolidate the entities that have TEFs based on being the primary beneficiary for these VIEs. The assets and liabilities of the VIEs totaled approximately $2,740 million and $196 million, respectively, at March 31, 2024. As of December 31, 2023, the assets and liabilities of VIEs totaled approximately $2,741 million and $174 million, respectively. At March 31, 2024 and December 31, 2023, the assets and liabilities of the VIEs consisted primarily of property, plant and equipment. Wind and solar power generation are subject to certain favorable tax treatments in the U.S. In order to monetize the tax benefits, we have entered into these structured institutional partnership investment transactions related to certain wind and solar farms. Under these structures, we contribute certain wind / solar assets, relating both to existing wind farms and wind farms / solar facilities that are being placed into operation at the time of the relevant transaction, and other parties invest in the share equity of the limited liability holding company. As consideration for their investment, the third parties make either an upfront cash payment or a combination of upfront cash and payments over time. We retain a class of membership interest and day-to-day operational and management control, subject to investor approval of certain major decisions. The third-party investors do not receive a lien on any assets and have no recourse against us for their upfront cash payments. The partnerships generally involve disproportionate allocations of profit or loss, cash distributions and tax benefits resulting from the wind farm energy generation between the investor and sponsor until the investor recovers its investment and achieves a targeted cumulative annual after-tax return. Once this target return is met, the relative sharing of profit or loss, cash distributions and taxable income or loss between the Company and the third party investor flips, with the sponsor generally receiving higher percentages thereafter. We also have a call option to acquire the third party investors’ membership interest within a defined time period after this target return is met. At March 31, 2024, El Cabo Wind, LLC (El Cabo), Patriot Wind Farm LLC (Patriot), Aeolus Wind Power VII, LLC (Aeolus VII), Aeolus VIII, and Solis I are our consolidated VIEs. Our El Cabo, Patriot, Aeolus VII, Aeolus VIII, and Solis I interests are not subject to any rights of investors that may restrict our ability to access or use the assets or to settle any existing liabilities associated with the interests. See Note 19 - Equity Method Investments for information on our VIE we do not consolidate.
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Equity Method Investments |
3 Months Ended |
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Mar. 31, 2024 | |
Equity Method Investments and Joint Ventures [Abstract] | |
Equity Method Investments | Equity Method Investments Renewables holds a 50% indirect ownership interest in Vineyard Wind 1, LLC (Vineyard Wind 1), a joint venture with Copenhagen Infrastructure Partners (CIP). Prior to a restructuring transaction that took place on January 10, 2022 (Restructuring Transaction), Renewables held a 50% ownership interest in Vineyard Wind, LLC (Vineyard Wind) which held rights to two easements from the U.S. Bureau of Ocean Energy Management (BOEM) for the development of offshore wind generation, Lease Area 501 which contained 166,886 acres and Lease Area 522 which contained 132,370 acres, both located southeast of Martha’s Vineyard. Lease Area 501 was subdivided in 2021, creating Lease Area 534. On September 15, 2021, Vineyard Wind closed on construction financing for the Vineyard Wind 1 project. Among other items, the Vineyard Wind 1 project was transferred into a separate joint venture, Vineyard Wind 1. Following the Restructuring Transaction, Vineyard Wind 1 remained a 50-50 joint venture and kept the rights to develop Lease Area 501, and Vineyard Wind was effectively dissolved where Renewables received rights to the Lease Area 534 and CIP received rights to Lease Area 522 as liquidating distributions. In contemplation of the liquidating distributions, Renewables also made an incremental payment of approximately $168 million to CIP in 2022. Concurrently with the closing on the construction financing for the Vineyard Wind 1 project, Renewables entered into a credit agreement with certain banks to provide future term loans and letters of credit up to a maximum of approximately $1.2 billion to finance a portion of its share of the cost of Vineyard Wind 1 at the maturity of the Vineyard Wind 1 project construction loan. Any term loans mature by October 15, 2031, subject to certain extension provisions. Renewables also entered into an Equity Contribution Agreement in which Renewables agreed to, among other things, make certain equity contributions to fund certain costs of developing and constructing the Vineyard Wind 1 project in accordance with the credit agreement. In addition, we issued a guaranty up to $827 million for Renewables' equity contributions under the Equity Contribution Agreement. As part of the Vineyard Wind 1 financial close, $152 million of Renewables prior contributions for the Vineyard Wind 1 project were returned in 2021. On October 24, 2023, Vineyard Wind 1 closed on a TEF agreement, pursuant to which Vineyard Wind 1 is expected to receive approximately $1.2 billion from tax equity investors in installments based on the number of turbines reaching or about to reach mechanical completion each month until the entire project reaches commercial operation date. Vineyard Wind 1 received the initial funding of $85 million from tax equity investors in 2023. The remaining $1.1 billion is expected to be received in 2024. In conjunction with the equity installments received since the closing of the TEF agreement, we have issued an indemnification of our joint share of the investor contributions. As of both March 31, 2024 and December 31, 2023, our total indemnified amount was $43 million. Vineyard Wind 1 is considered a VIE because it cannot finance its activities without additional support from its owners or third parties. Renewables is not the primary beneficiary of the entity since it does not have a controlling financial interest, and therefore we do not consolidate this entity. During 2024, Renewables made a capital contribution of $116 million to Vineyard Wind 1. As of March 31, 2024 and December 31, 2023, the carrying amount of Renewables' investments in Vineyard Wind LLC and Vineyard Wind 1 Pledgor LLC was $419 million and $297 million, respectively.
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Subsequent Event |
3 Months Ended |
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Mar. 31, 2024 | |
Subsequent Events [Abstract] | |
Subsequent Event | Subsequent Event On April 11, 2024, the board of directors of Avangrid declared a quarterly dividend of $0.44 per share on its common stock. This dividend is payable on July 1, 2024 to shareholders of record at the close of business on June 3, 2024.
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Significant Accounting Policies and New Accounting Pronouncements (Policies) |
3 Months Ended |
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Mar. 31, 2024 | |
Accounting Policies [Abstract] | |
Adoption of New Accounting Pronouncements and Accounting Pronouncements Issued but Not Yet Adopted | 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 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.
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Revenue recognition | 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 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. 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.
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Revenue (Tables) |
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Schedule of Revenues Disaggregated by Major Source for Reportable Segments | Revenues disaggregated by major source for our reportable segments for the three months ended March 31, 2024 and 2023 are as follows:
(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.
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Schedule of Aggregate Transaction Price Allocations | 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:
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Regulatory Assets and Liabilities (Tables) |
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Regulated Operations [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Schedule of Current and Non-Current Regulatory Assets | Regulatory assets as of March 31, 2024 and December 31, 2023, respectively, consisted of:
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Schedule of Current and Non-Current Regulatory Liabilities | Regulatory liabilities as of March 31, 2024 and December 31, 2023, respectively, consisted of:
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Fair Value of Financial Instruments and Fair Value Measurements (Tables) |
3 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Fair Value Disclosures [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Schedule of Fair Value Measurements | The financial instruments measured at fair value as of March 31, 2024 and December 31, 2023, respectively, consisted of:
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Summary of Fair Value, Financial instrument Based on Level 3 Reconciliation | The reconciliation of changes in the fair value of financial instruments based on Level 3 inputs for the three months ended March 31, 2024 and 2023, respectively, is as follows:
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Summary of Fair Value, Assets and Liabilities Level 3 Measurement, Valuation Techniques | The table below illustrates the significant sources of unobservable inputs used in the fair value measurement of our Level 3 derivatives and the variability in prices for those transactions classified as Level 3 derivatives.
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Derivative Instruments and Hedging (Tables) |
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Derivative Instruments and Hedging Activities Disclosure [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Schedule of Derivatives Instruments Statements of Financial Performance and Financial Position, Location in Condensed Consolidated Balance Sheet and Amounts | The tables below present Networks' derivative positions as of March 31, 2024 and December 31, 2023, respectively, including those subject to master netting agreements and the location of the net derivative positions on our condensed consolidated balance sheets:
The tables below present Renewables' derivative positions as of March 31, 2024 and December 31, 2023, respectively, including those subject to master netting agreements and the location of the net derivative position on our condensed consolidated balance sheets:
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Schedule of Notional Volumes of Outstanding Derivative Positions | The net notional volumes of the outstanding derivative instruments associated with Networks' activities as of March 31, 2024 and December 31, 2023, respectively, consisted of:
The net notional volumes of outstanding derivative instruments associated with Renewables' activities as of March 31, 2024 and December 31, 2023, respectively, consisted of:
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Summary of Unrealized Gains and Losses from Fair Value Adjustments | The amounts for electricity hedge contracts and natural gas hedge contracts recognized in regulatory liabilities and assets as of March 31, 2024 and December 31, 2023 and amounts reclassified from regulatory assets and liabilities into income for the three months ended March 31, 2024 and 2023 are as follows:
The unrealized gains and losses from fair value adjustments to these derivatives, which are recorded in regulatory assets, for the three months ended March 31, 2024 and 2023, respectively, were as follows:
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Derivative Instruments, Gain (Loss) | The effect of derivatives in cash flow hedging relationships on Other Comprehensive Income (OCI) and income for the three months ended March 31, 2024 and 2023, respectively, consisted of:
(a) Changes in accumulated OCI are reported on a pre-tax basis. The effect of derivatives in cash flow hedging relationships on accumulated OCI and income for the three months ended March 31, 2024 and 2023, respectively, consisted of:
(a) Changes in OCI are reported on a pre-tax basis.
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Schedule of Cash Flow Hedges Included in Accumulated Other Comprehensive Income (Loss) | The effect of derivatives in cash flow hedging relationships on accumulated OCI for the three months ended March 31, 2024 and 2023, respectively, consisted of:
(a) Changes in OCI are reported on a pre-tax basis. The amounts in accumulated OCI are being reclassified into earnings over the underlying debt maturity periods which end in 2025 and 2029.
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Schedule of Fair Value Hedging Instruments | The effects on our consolidated financial statements as of and for the three months ended March 31, 2024 and 2023 are as follows:
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Schedule of Fair Value, Net Derivative Contracts | The fair values of derivative contracts associated with Renewables' activities as of March 31, 2024 and December 31, 2023, respectively, consisted of:
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Effect of Derivatives Associated with Renewables and Gas Activities | The effects of trading and non-trading derivatives associated with Renewables' activities for the three months ended March 31, 2024 and 2023, consisted of:
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Post-retirement and Similar Obligations (Tables) |
3 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Mar. 31, 2024 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Retirement Benefits [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Components of Net Periodic Pension and Postretirement Benefits | The components of net periodic benefit cost for pension benefits for the three months ended March 31, 2024 and 2023, respectively, consisted of:
The components of net periodic benefit cost for postretirement benefits for the three months ended March 31, 2024 and 2023, respectively, consisted of:
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Equity (Tables) |
3 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Mar. 31, 2024 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Equity [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Schedule of Accumulated Other Comprehensive Income (Loss) | Accumulated Other Comprehensive Loss for the three months ended March 31, 2024 and 2023, respectively, consisted of:
(a) Foreign currency and interest rate contracts. (b) Reclassification is reflected in the operating expenses and interest expense, net of capitalization line items in our consolidated statements of income.
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Earnings Per Share (Tables) |
3 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Mar. 31, 2024 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Earnings Per Share [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Schedule of Earnings Per Share, Basic and Diluted | The calculations of basic and diluted earnings per share attributable to Avangrid, for the three months ended March 31, 2024 and 2023, respectively, consisted of:
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Segment Information (Tables) |
3 Months Ended | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Mar. 31, 2024 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Segment Reporting [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Schedule of Segment Information | Segment information as of and for the three months ended March 31, 2024, consisted of:
(a) Includes Corporate and intersegment eliminations. Segment information for the three months ended March 31, 2023 and as of December 31, 2023, consisted of:
(a) Includes Corporate and intersegment eliminations.
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Schedule of Reconciliation of Adjusted Net Income to Net Income | Reconciliation of Adjusted Net Income to Net Income attributable to Avangrid for the three months ended March 31, 2024 and 2023, respectively, is as follows:
(1)Mark-to-market earnings relates to earnings impacts from changes in the fair value of Renewables' derivative instruments associated with electricity and natural gas. (2)Represents the amount of accelerated depreciation derived from the repowering of wind farms in Renewables.
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Related Party Transactions (Tables) |
3 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Mar. 31, 2024 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Related Party Transactions [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Schedule of Related Party Transactions | Related party transactions for the three months ended March 31, 2024 and 2023, respectively, consisted of:
Related party balances as of March 31, 2024 and December 31, 2023, respectively, consisted of:
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Other Financial Statement Items (Tables) |
3 Months Ended | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Mar. 31, 2024 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Balance Sheet Related Disclosures [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Schedule of Accounts, Notes, Loans and Financing Receivable | Accounts receivable and unbilled revenues, net as of March 31, 2024 and December 31, 2023 consisted of:
The change in the allowance for credit losses for the three months ended March 31, 2024 and 2023 consisted of:
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Schedule of Accumulated Depreciation and Amortization | The accumulated depreciation and amortization as of March 31, 2024 and December 31, 2023, respectively, were as follows:
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Background and Nature Of Operations (Details) - $ / shares |
Mar. 31, 2024 |
Mar. 06, 2024 |
---|---|---|
Noncontrolling Interest [Line Items] | ||
Non-binding proposal to acquire common stock, price (in dollars per share) | $ 34.25 | |
Avangrid | Iberdrola, S.A. | ||
Noncontrolling Interest [Line Items] | ||
Parent company, ownership percentage | 81.60% | |
Avangrid | Various Shareholders | ||
Noncontrolling Interest [Line Items] | ||
Ownership percentage by noncontrolling owners | 14.70% |
Revenue - Narrative (Details) - USD ($) $ in Millions |
3 Months Ended | ||
---|---|---|---|
Mar. 31, 2024 |
Mar. 31, 2023 |
Dec. 31, 2023 |
|
Disaggregation of Revenue [Line Items] | |||
Contract assets | $ 19 | $ 9 | |
TCC contract liabilities | 9 | 18 | |
Revenue recognized | 9 | $ 17 | |
Accounts receivable related to contracts with customers | 1,529 | 1,441 | |
Unbilled contracts receivable | 426 | $ 426 | |
Revenue, remaining performance obligation, amount | $ 257 | ||
Minimum | |||
Disaggregation of Revenue [Line Items] | |||
Contract assets amortization term | 16 years | ||
Minimum | Transmission congestion contracts | |||
Disaggregation of Revenue [Line Items] | |||
Revenue auction period | 6 months | ||
Maximum | |||
Disaggregation of Revenue [Line Items] | |||
Contract assets amortization term | 21 years | ||
Maximum | Transmission congestion contracts | |||
Disaggregation of Revenue [Line Items] | |||
Revenue auction period | 2 years | ||
Networks | |||
Disaggregation of Revenue [Line Items] | |||
Revenue auction period | 1 year |
Revenue - Schedule of Revenues Disaggregated by Major Source for Reportable Segments (Details) - USD ($) $ in Millions |
3 Months Ended | |
---|---|---|
Mar. 31, 2024 |
Mar. 31, 2023 |
|
Segment Reporting Information [Line Items] | ||
Revenue from contracts with customers | $ 2,270 | $ 2,289 |
Leasing revenue | 2 | 2 |
Derivative gains (losses) | 87 | 122 |
Alternative revenue programs | 43 | 37 |
Other revenue | 15 | 16 |
Total operating revenues | 2,417 | 2,466 |
Regulated operations – electricity | ||
Segment Reporting Information [Line Items] | ||
Revenue from contracts with customers | 1,350 | 1,308 |
Regulated operations – natural gas | ||
Segment Reporting Information [Line Items] | ||
Revenue from contracts with customers | 592 | 722 |
Nonregulated operations – wind | ||
Segment Reporting Information [Line Items] | ||
Revenue from contracts with customers | 224 | 216 |
Nonregulated operations – solar | ||
Segment Reporting Information [Line Items] | ||
Revenue from contracts with customers | 7 | 4 |
Nonregulated operations – thermal | ||
Segment Reporting Information [Line Items] | ||
Revenue from contracts with customers | 91 | 55 |
Other | ||
Segment Reporting Information [Line Items] | ||
Revenue from contracts with customers | 6 | (16) |
Other | ||
Segment Reporting Information [Line Items] | ||
Revenue from contracts with customers | (1) | 0 |
Leasing revenue | 0 | 0 |
Derivative gains (losses) | 0 | 0 |
Alternative revenue programs | 0 | 0 |
Other revenue | 0 | 0 |
Total operating revenues | (1) | 0 |
Other | Regulated operations – electricity | ||
Segment Reporting Information [Line Items] | ||
Revenue from contracts with customers | 0 | 0 |
Other | Regulated operations – natural gas | ||
Segment Reporting Information [Line Items] | ||
Revenue from contracts with customers | 0 | 0 |
Other | Nonregulated operations – wind | ||
Segment Reporting Information [Line Items] | ||
Revenue from contracts with customers | 0 | 0 |
Other | Nonregulated operations – solar | ||
Segment Reporting Information [Line Items] | ||
Revenue from contracts with customers | 0 | 0 |
Other | Nonregulated operations – thermal | ||
Segment Reporting Information [Line Items] | ||
Revenue from contracts with customers | 0 | 0 |
Other | Other | ||
Segment Reporting Information [Line Items] | ||
Revenue from contracts with customers | (1) | 0 |
Networks | ||
Segment Reporting Information [Line Items] | ||
Total operating revenues | 2,018 | 2,076 |
Networks | Operating Segments | ||
Segment Reporting Information [Line Items] | ||
Revenue from contracts with customers | 1,962 | 2,027 |
Leasing revenue | 2 | 2 |
Derivative gains (losses) | 0 | 0 |
Alternative revenue programs | 43 | 37 |
Other revenue | 11 | 10 |
Total operating revenues | 2,017 | 2,076 |
Networks | Operating Segments | Regulated operations – electricity | ||
Segment Reporting Information [Line Items] | ||
Revenue from contracts with customers | 1,350 | 1,308 |
Networks | Operating Segments | Regulated operations – natural gas | ||
Segment Reporting Information [Line Items] | ||
Revenue from contracts with customers | 592 | 722 |
Networks | Operating Segments | Nonregulated operations – wind | ||
Segment Reporting Information [Line Items] | ||
Revenue from contracts with customers | 0 | 0 |
Networks | Operating Segments | Nonregulated operations – solar | ||
Segment Reporting Information [Line Items] | ||
Revenue from contracts with customers | 0 | 0 |
Networks | Operating Segments | Nonregulated operations – thermal | ||
Segment Reporting Information [Line Items] | ||
Revenue from contracts with customers | 0 | 0 |
Networks | Operating Segments | Other | ||
Segment Reporting Information [Line Items] | ||
Revenue from contracts with customers | 20 | (3) |
Renewables | ||
Segment Reporting Information [Line Items] | ||
Total operating revenues | 400 | 390 |
Renewables | Operating Segments | ||
Segment Reporting Information [Line Items] | ||
Revenue from contracts with customers | 309 | 262 |
Leasing revenue | 0 | 0 |
Derivative gains (losses) | 87 | 122 |
Alternative revenue programs | 0 | 0 |
Other revenue | 4 | 6 |
Total operating revenues | 400 | 390 |
Renewables | Operating Segments | Regulated operations – electricity | ||
Segment Reporting Information [Line Items] | ||
Revenue from contracts with customers | 0 | 0 |
Renewables | Operating Segments | Regulated operations – natural gas | ||
Segment Reporting Information [Line Items] | ||
Revenue from contracts with customers | 0 | 0 |
Renewables | Operating Segments | Nonregulated operations – wind | ||
Segment Reporting Information [Line Items] | ||
Revenue from contracts with customers | 224 | 216 |
Renewables | Operating Segments | Nonregulated operations – solar | ||
Segment Reporting Information [Line Items] | ||
Revenue from contracts with customers | 7 | 4 |
Renewables | Operating Segments | Nonregulated operations – thermal | ||
Segment Reporting Information [Line Items] | ||
Revenue from contracts with customers | 91 | 55 |
Renewables | Operating Segments | Other | ||
Segment Reporting Information [Line Items] | ||
Revenue from contracts with customers | $ (13) | $ (13) |
Revenue - Schedule of Aggregate Transaction Price Allocated to Unsatisfied Performance Obligations and Expected Time to Recognize Revenue (Details) $ in Millions |
Mar. 31, 2024
USD ($)
|
---|---|
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items] | |
Total operating revenues | $ 257 |
Revenue expected to be recognized on multiyear capacity and carbon-free energy sale contracts | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items] | |
Total operating revenues | 106 |
Revenue expected to be recognized on multiyear renewable energy credit sale contracts | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items] | |
Total operating revenues | 151 |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2024-04-01 | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items] | |
Total operating revenues | $ 116 |
Remaining performance obligation, period | 9 months |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2025-01-01 | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items] | |
Total operating revenues | $ 102 |
Remaining performance obligation, period | 1 year |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2025-01-01 | Revenue expected to be recognized on multiyear capacity and carbon-free energy sale contracts | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items] | |
Total operating revenues | $ 30 |
Remaining performance obligation, period | 1 year |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2025-01-01 | Revenue expected to be recognized on multiyear renewable energy credit sale contracts | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items] | |
Total operating revenues | $ 72 |
Remaining performance obligation, period | 1 year |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2025-01-01 | Revenue expected to be recognized on multiyear retail energy sales contracts in place | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items] | |
Remaining performance obligation, period | 1 year |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2026-01-01 | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items] | |
Total operating revenues | $ 58 |
Remaining performance obligation, period | 1 year |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2026-01-01 | Revenue expected to be recognized on multiyear capacity and carbon-free energy sale contracts | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items] | |
Total operating revenues | $ 10 |
Remaining performance obligation, period | 1 year |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2026-01-01 | Revenue expected to be recognized on multiyear renewable energy credit sale contracts | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items] | |
Total operating revenues | $ 48 |
Remaining performance obligation, period | 1 year |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2026-01-01 | Revenue expected to be recognized on multiyear retail energy sales contracts in place | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items] | |
Remaining performance obligation, period | 1 year |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2027-01-01 | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items] | |
Total operating revenues | $ 33 |
Remaining performance obligation, period | 1 year |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2027-01-01 | Revenue expected to be recognized on multiyear capacity and carbon-free energy sale contracts | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items] | |
Total operating revenues | $ 7 |
Remaining performance obligation, period | 1 year |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2027-01-01 | Revenue expected to be recognized on multiyear renewable energy credit sale contracts | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items] | |
Total operating revenues | $ 26 |
Remaining performance obligation, period | 1 year |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2027-01-01 | Revenue expected to be recognized on multiyear retail energy sales contracts in place | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items] | |
Remaining performance obligation, period | 1 year |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2028-01-01 | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items] | |
Total operating revenues | $ 8 |
Remaining performance obligation, period | 1 year |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2028-01-01 | Revenue expected to be recognized on multiyear capacity and carbon-free energy sale contracts | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items] | |
Total operating revenues | $ 5 |
Remaining performance obligation, period | 1 year |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2028-01-01 | Revenue expected to be recognized on multiyear renewable energy credit sale contracts | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items] | |
Total operating revenues | $ 3 |
Remaining performance obligation, period | 1 year |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2028-01-01 | Revenue expected to be recognized on multiyear retail energy sales contracts in place | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items] | |
Remaining performance obligation, period | 1 year |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2029-01-01 | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items] | |
Total operating revenues | $ 6 |
Remaining performance obligation, period | 1 year |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2029-01-01 | Revenue expected to be recognized on multiyear capacity and carbon-free energy sale contracts | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items] | |
Total operating revenues | $ 5 |
Remaining performance obligation, period | 1 year |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2029-01-01 | Revenue expected to be recognized on multiyear renewable energy credit sale contracts | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items] | |
Total operating revenues | $ 1 |
Remaining performance obligation, period | 1 year |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2029-01-01 | Revenue expected to be recognized on multiyear retail energy sales contracts in place | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items] | |
Remaining performance obligation, period | 1 year |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2030-01-01 | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items] | |
Total operating revenues | $ 50 |
Remaining performance obligation, period | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2030-01-01 | Revenue expected to be recognized on multiyear capacity and carbon-free energy sale contracts | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items] | |
Total operating revenues | $ 49 |
Remaining performance obligation, period | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2030-01-01 | Revenue expected to be recognized on multiyear renewable energy credit sale contracts | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items] | |
Total operating revenues | $ 1 |
Remaining performance obligation, period | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2030-01-01 | Revenue expected to be recognized on multiyear retail energy sales contracts in place | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items] | |
Remaining performance obligation, period |
Regulatory Assets and Liabilities - Narrative (Details) - USD ($) $ in Millions |
3 Months Ended | |
---|---|---|
Mar. 31, 2024 |
Mar. 31, 2023 |
|
Public Utilities, General Disclosures [Line Items] | ||
Unrecorded regulatory assets | $ 1,157 | |
Unfunded future income tax expense collection period | 46 years | |
Min. | ||
Public Utilities, General Disclosures [Line Items] | ||
Recovery period | 6 months | |
Max. | ||
Public Utilities, General Disclosures [Line Items] | ||
Recovery period | 30 months | |
UIL Holdings | ||
Public Utilities, General Disclosures [Line Items] | ||
Business combination merger related rate credits | $ 1 | $ 1 |
Central Maine Power | ||
Public Utilities, General Disclosures [Line Items] | ||
Deferred income tax recovery period | 32 years 6 months |
Regulatory Assets and Liabilities - CMP Distribution Rate Case (Details) - Central Maine Power $ in Thousands |
Jun. 06, 2023
USD ($)
|
---|---|
Public Utilities, General Disclosures [Line Items] | |
Distribution revenue requirement | $ 16,750 |
Approved return on equity | 9.35% |
Equity ratio | 50.00% |
Equity ratio for earnings sharing | 50.00% |
Public utilities, earnings sharing percentage calculation basis | 0.0100 |
Maximum penalty per year for failure to meet specified service quality indicator target | $ 8,800 |
Regulatory Assets and Liabilities - NYSEG and RG&E Rate Plans (Details) - USD ($) $ in Millions |
3 Months Ended | ||
---|---|---|---|
Jun. 14, 2023 |
Mar. 31, 2024 |
Dec. 31, 2023 |
|
Public Utilities, General Disclosures [Line Items] | |||
Regulatory assets | $ 3,806.0 | $ 3,529.0 | |
Deferred storm costs, amortization period | 10 years | ||
NYSEG and RG&E | |||
Public Utilities, General Disclosures [Line Items] | |||
Percentage of customers' portion of earnings above sharing threshold deferred To reduce outstanding regulatory asset deferral balances | 100.00% | ||
Percentage Of Service Provider's Portion Used To Reduce Outstanding Storm-Related Regulatory Asset Deferral Balance | 50.00% | ||
Capital investment amount projected | $ 634.0 | ||
NYSEG | Electricity | |||
Public Utilities, General Disclosures [Line Items] | |||
Approved return on equity | 9.20% | ||
Equity ratio | 48.00% | ||
Public utilities, recovery of Major Storm costs | 371.0 | ||
NYSEG | Natural Gas | |||
Public Utilities, General Disclosures [Line Items] | |||
Approved return on equity | 9.20% | ||
Equity ratio | 48.00% | ||
RG&E | Electricity | |||
Public Utilities, General Disclosures [Line Items] | |||
Approved return on equity | 9.20% | ||
Equity ratio | 48.00% | ||
Public utilities, recovery of Major Storm costs | 54.6 | ||
RG&E | Natural Gas | |||
Public Utilities, General Disclosures [Line Items] | |||
Approved return on equity | 9.20% | ||
Equity ratio | 48.00% | ||
Super Storm Costs | NYSEG | |||
Public Utilities, General Disclosures [Line Items] | |||
Regulatory assets | 52.3 | ||
Non-Super Storm Costs | NYSEG | |||
Public Utilities, General Disclosures [Line Items] | |||
Regulatory assets | $ 96.6 | ||
Regulatory items amortization period | 7 years | ||
Non-Super Storm Costs | RG&E | |||
Public Utilities, General Disclosures [Line Items] | |||
Regulatory assets | $ 19.6 | ||
Regulatory items amortization period | 2 years |
Regulatory Assets and Liabilities - New York Climate Leadership and Community Protection Act(Details) $ in Billions |
Oct. 17, 2023 |
Feb. 16, 2023
USD ($)
MW
|
---|---|---|
NYPSC | ||
Public Utilities, General Disclosures [Line Items] | ||
Public utilities, approved transmission upgrade costs | $ 4.4 | |
Public utilities, clean energy capacity (in MW) | MW | 3,500 | |
NYSEG and RG&E | ||
Public Utilities, General Disclosures [Line Items] | ||
Public utilities, approved transmission upgrade costs | $ 2.2 | |
Public utilities, utilization rate for construction work in progress | 100.00% |
Regulatory Assets and Liabilities - UI, CNG, SCG and BGC Rate Plans (Details) - USD ($) $ in Millions |
3 Months Ended | ||||||
---|---|---|---|---|---|---|---|
Nov. 03, 2023 |
Aug. 25, 2023 |
Jun. 24, 2022 |
Jan. 01, 2019 |
Jan. 01, 2018 |
Jan. 01, 2017 |
Mar. 31, 2024 |
|
Public Utilities, General Disclosures [Line Items] | |||||||
Percentage of standard service customers with wholesale power supply agreements in place for the second half of 2024 | 50.00% | ||||||
BGC | |||||||
Public Utilities, General Disclosures [Line Items] | |||||||
Average increase in customer bills, percentage | $ 5.6 | ||||||
Requested return on equity base percentage | 9.70% | ||||||
Customer receiving percentage | 54.00% | ||||||
PURA | |||||||
Public Utilities, General Disclosures [Line Items] | |||||||
Average increase in customer bills, percentage | $ 23.0 | ||||||
PURA | Max. | |||||||
Public Utilities, General Disclosures [Line Items] | |||||||
Average increase in base distribution rate, percentage | 6.60% | ||||||
PURA | Min. | |||||||
Public Utilities, General Disclosures [Line Items] | |||||||
Average increase in customer bills, percentage | 2.00% | ||||||
PURA | United Illuminating Company (UI) | |||||||
Public Utilities, General Disclosures [Line Items] | |||||||
Approved return on equity | 8.63% | 9.10% | |||||
Equity ratio | 50.00% | ||||||
Approved debt capital structure, percentage | 50.00% | ||||||
PURA | SCG | |||||||
Public Utilities, General Disclosures [Line Items] | |||||||
Approved return on equity | 9.25% | ||||||
Equity ratio | 52.00% | ||||||
Average increase in customer bills, percentage | $ 40.6 | ||||||
PURA | Connecticut Natural Gas Corporation (CNG) | |||||||
Public Utilities, General Disclosures [Line Items] | |||||||
Approved return on equity | 9.30% | ||||||
Average increase in customer bills, percentage | $ 19.8 | ||||||
PURA | Connecticut Natural Gas Corporation (CNG) | Electric And Gas Service Rate Plan Year One | |||||||
Public Utilities, General Disclosures [Line Items] | |||||||
Approved return on equity | 54.00% | ||||||
PURA | Connecticut Natural Gas Corporation (CNG) | Electric And Gas Service Rate Plan Year Two | |||||||
Public Utilities, General Disclosures [Line Items] | |||||||
Approved return on equity | 54.50% | ||||||
PURA | Connecticut Natural Gas Corporation (CNG) | Electric And Gas Service Rate Plan Year Three | |||||||
Public Utilities, General Disclosures [Line Items] | |||||||
Approved return on equity | 55.00% |
Regulatory Assets and Liabilities - Connecticut Energy Legislation (Details) |
Jun. 30, 2022
USD ($)
hour
|
---|---|
Regulated Operations [Abstract] | |
Energy legislation, customer compensation and reimbursement provisions, power outage hours benchmark (more than) | hour | 96 |
Energy legislation, customer compensation and reimbursement provisions, customer payment per day | $ 25 |
Energy legislation, customer compensation and reimbursement provisions, food and medicine reimbursement | $ 250 |
Regulatory Assets and Liabilities - PURA Investigation of the Preparation for and Response to the Tropical Storm Isaias and Connecticut Storm Reimbursement Legislation (Details) - USD ($) $ in Millions |
Jul. 14, 2021 |
May 06, 2021 |
Apr. 15, 2021 |
---|---|---|---|
Public Utilities, General Disclosures [Line Items] | |||
Civil penalty amount | $ 1 | $ 2 | |
United Illuminating Company (UI) | |||
Public Utilities, General Disclosures [Line Items] | |||
ROE reduction | 0.15% |
Regulatory Assets and Liabilities - Regulatory Assets (Details) - USD ($) $ in Millions |
Mar. 31, 2024 |
Dec. 31, 2023 |
---|---|---|
Regulatory Assets [Line Items] | ||
Total regulatory assets | $ 3,806 | $ 3,529 |
Less: current portion | 745 | 718 |
Regulatory assets | 3,061 | 2,811 |
Pension and other post-retirement benefits | ||
Regulatory Assets [Line Items] | ||
Total regulatory assets | 439 | 445 |
Pension and other post-retirement benefits cost deferrals | ||
Regulatory Assets [Line Items] | ||
Total regulatory assets | 57 | 58 |
Storm costs | ||
Regulatory Assets [Line Items] | ||
Total regulatory assets | 1,052 | 868 |
Rate adjustment mechanism | ||
Regulatory Assets [Line Items] | ||
Total regulatory assets | 42 | 24 |
Revenue decoupling mechanism | ||
Regulatory Assets [Line Items] | ||
Total regulatory assets | 101 | 86 |
Contracts for differences | ||
Regulatory Assets [Line Items] | ||
Total regulatory assets | 33 | 38 |
Hardship programs | ||
Regulatory Assets [Line Items] | ||
Total regulatory assets | 25 | 23 |
Deferred purchased gas | ||
Regulatory Assets [Line Items] | ||
Total regulatory assets | 6 | 16 |
Environmental remediation costs | ||
Regulatory Assets [Line Items] | ||
Total regulatory assets | 244 | 240 |
Debt premium | ||
Regulatory Assets [Line Items] | ||
Total regulatory assets | 57 | 58 |
Unamortized losses on reacquired debt | ||
Regulatory Assets [Line Items] | ||
Total regulatory assets | 17 | 17 |
Unfunded future income taxes | ||
Regulatory Assets [Line Items] | ||
Total regulatory assets | 601 | 578 |
Federal tax depreciation normalization adjustment | ||
Regulatory Assets [Line Items] | ||
Total regulatory assets | 129 | 130 |
Asset retirement obligation | ||
Regulatory Assets [Line Items] | ||
Total regulatory assets | 20 | 19 |
Deferred meter replacement costs | ||
Regulatory Assets [Line Items] | ||
Total regulatory assets | 60 | 59 |
COVID-19 cost recovery and late payment surcharge | ||
Regulatory Assets [Line Items] | ||
Total regulatory assets | 11 | 12 |
Low income arrears forgiveness | ||
Regulatory Assets [Line Items] | ||
Total regulatory assets | 49 | 55 |
Excess generation service charge | ||
Regulatory Assets [Line Items] | ||
Total regulatory assets | 86 | 52 |
System Expansion | ||
Regulatory Assets [Line Items] | ||
Total regulatory assets | 19 | 22 |
Non-bypassable charge | ||
Regulatory Assets [Line Items] | ||
Total regulatory assets | 124 | 103 |
Hedges losses | ||
Regulatory Assets [Line Items] | ||
Total regulatory assets | 13 | 34 |
Rate Change Levelization [Member] | ||
Regulatory Assets [Line Items] | ||
Total regulatory assets | 83 | 60 |
Value of distributed energy resources | ||
Regulatory Assets [Line Items] | ||
Total regulatory assets | 44 | 49 |
Uncollectible reserve | ||
Regulatory Assets [Line Items] | ||
Total regulatory assets | 114 | 104 |
New York make-whole provision | ||
Regulatory Assets [Line Items] | ||
Total regulatory assets | 84 | 96 |
Other | ||
Regulatory Assets [Line Items] | ||
Total regulatory assets | $ 296 | $ 283 |
Regulatory Assets and Liabilities - Regulatory Liabilities (Details) - USD ($) $ in Millions |
Mar. 31, 2024 |
Dec. 31, 2023 |
---|---|---|
Regulatory Liabilities [Line Items] | ||
Total regulatory liabilities | $ 2,951 | $ 2,955 |
Less: current portion | 275 | 261 |
Total non-current regulatory liabilities | 2,676 | 2,694 |
Energy efficiency portfolio standard | ||
Regulatory Liabilities [Line Items] | ||
Total regulatory liabilities | 24 | 15 |
Gas supply charge and deferred natural gas cost | ||
Regulatory Liabilities [Line Items] | ||
Total regulatory liabilities | 10 | 8 |
Pension and other post-retirement benefits cost deferrals | ||
Regulatory Liabilities [Line Items] | ||
Total regulatory liabilities | 88 | 89 |
Carrying costs on deferred income tax bonus depreciation | ||
Regulatory Liabilities [Line Items] | ||
Total regulatory liabilities | 2 | 3 |
Carrying costs on deferred income tax - Mixed Services 263(a) | ||
Regulatory Liabilities [Line Items] | ||
Total regulatory liabilities | 1 | 2 |
2017 Tax Act | ||
Regulatory Liabilities [Line Items] | ||
Total regulatory liabilities | 1,187 | 1,190 |
Accrued removal obligations | ||
Regulatory Liabilities [Line Items] | ||
Total regulatory liabilities | 1,135 | 1,139 |
Positive benefit adjustment | ||
Regulatory Liabilities [Line Items] | ||
Total regulatory liabilities | 7 | 9 |
Deferred property tax | ||
Regulatory Liabilities [Line Items] | ||
Total regulatory liabilities | 21 | 21 |
Net plant reconciliation | ||
Regulatory Liabilities [Line Items] | ||
Total regulatory liabilities | 23 | 23 |
Debt rate reconciliation | ||
Regulatory Liabilities [Line Items] | ||
Total regulatory liabilities | 16 | 18 |
Rate refund – FERC ROE proceeding | ||
Regulatory Liabilities [Line Items] | ||
Total regulatory liabilities | 40 | 39 |
Transmission congestion contracts | ||
Regulatory Liabilities [Line Items] | ||
Total regulatory liabilities | 24 | 26 |
Merger-related rate credits | ||
Regulatory Liabilities [Line Items] | ||
Total regulatory liabilities | 7 | 8 |
Accumulated deferred investment tax credits | ||
Regulatory Liabilities [Line Items] | ||
Total regulatory liabilities | 20 | 21 |
Asset retirement obligation | ||
Regulatory Liabilities [Line Items] | ||
Total regulatory liabilities | 19 | 19 |
Middletown/Norwalk local transmission network service collections | ||
Regulatory Liabilities [Line Items] | ||
Total regulatory liabilities | 16 | 16 |
Non-firm margin sharing credits | ||
Regulatory Liabilities [Line Items] | ||
Total regulatory liabilities | 39 | 34 |
Non by-passable charges | ||
Regulatory Liabilities [Line Items] | ||
Total regulatory liabilities | 6 | 9 |
Transmission revenue reconciliation mechanism | ||
Regulatory Liabilities [Line Items] | ||
Total regulatory liabilities | 32 | 57 |
Other | ||
Regulatory Liabilities [Line Items] | ||
Total regulatory liabilities | $ 234 | $ 209 |
Fair Value of Financial Instruments and Fair Value Measurements - Narrative (Details) - USD ($) $ in Millions |
3 Months Ended | |
---|---|---|
Mar. 31, 2024 |
Dec. 31, 2023 |
|
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative delivery period (in years) | 2 years | |
Fair value of debt | $ 10,136 | $ 10,266 |
Restricted Cash | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Restricted cash | $ 3 | $ 3 |
NYSEG and RG&E | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Percentage of electric load obligations hedged | 70.00% | |
Percentage of natural gas load obligations hedged | 55.00% |
Fair Value of Financial Instruments and Fair Value Measurements - Fair Value of Assets and Liabilities (Details) - USD ($) $ in Millions |
Mar. 31, 2024 |
Dec. 31, 2023 |
---|---|---|
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Equity investments with readily determinable fair values | $ 48 | $ 45 |
Netting adjustment | (95) | (81) |
Derivative assets | 272 | 230 |
Netting adjustment | 126 | 172 |
Derivative liabilities | (182) | (175) |
Derivative Financial Instruments, Power [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Netting adjustment | (80) | (69) |
Derivative assets | 109 | 102 |
Netting adjustment | 101 | 135 |
Derivative liabilities | (47) | (43) |
Derivative Financial Instruments, Gas [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Netting adjustment | (15) | (12) |
Derivative assets | 4 | 5 |
Netting adjustment | 25 | 37 |
Derivative liabilities | 0 | (1) |
Contracts for differences | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Netting adjustment | 0 | 0 |
Derivative assets | 1 | 1 |
Netting adjustment | 0 | 0 |
Derivative liabilities | (34) | (39) |
Derivative financial instruments – Other | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Netting adjustment | 0 | 0 |
Derivative assets | 158 | 122 |
Netting adjustment | 0 | 0 |
Derivative liabilities | (101) | (92) |
Level 1 | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Equity investments with readily determinable fair values | 30 | 29 |
Derivative assets, before netting | 23 | 15 |
Derivative liabilities, before netting | (36) | (49) |
Level 1 | Derivative Financial Instruments, Power [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative assets, before netting | 23 | 15 |
Derivative liabilities, before netting | (33) | (37) |
Level 1 | Derivative Financial Instruments, Gas [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative assets, before netting | 0 | 0 |
Derivative liabilities, before netting | (3) | (12) |
Level 1 | Contracts for differences | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative assets, before netting | 0 | 0 |
Derivative liabilities, before netting | 0 | 0 |
Level 1 | Derivative financial instruments – Other | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative assets, before netting | 0 | 0 |
Derivative liabilities, before netting | 0 | 0 |
Level 2 | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Equity investments with readily determinable fair values | 18 | 16 |
Derivative assets, before netting | 248 | 181 |
Derivative liabilities, before netting | (194) | (219) |
Level 2 | Derivative Financial Instruments, Power [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative assets, before netting | 71 | 42 |
Derivative liabilities, before netting | (71) | (101) |
Level 2 | Derivative Financial Instruments, Gas [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative assets, before netting | 19 | 17 |
Derivative liabilities, before netting | (22) | (26) |
Level 2 | Contracts for differences | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative assets, before netting | 0 | 0 |
Derivative liabilities, before netting | 0 | 0 |
Level 2 | Derivative financial instruments – Other | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative assets, before netting | 158 | 122 |
Derivative liabilities, before netting | (101) | (92) |
Level 3 | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Equity investments with readily determinable fair values | 0 | 0 |
Derivative assets, before netting | 96 | 115 |
Derivative liabilities, before netting | (78) | (79) |
Level 3 | Derivative Financial Instruments, Power [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative assets, before netting | 95 | 114 |
Derivative liabilities, before netting | (44) | (40) |
Level 3 | Derivative Financial Instruments, Gas [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative assets, before netting | 0 | 0 |
Derivative liabilities, before netting | 0 | 0 |
Level 3 | Contracts for differences | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative assets, before netting | 1 | 1 |
Derivative liabilities, before netting | (34) | (39) |
Level 3 | Derivative financial instruments – Other | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative assets, before netting | 0 | 0 |
Derivative liabilities, before netting | $ 0 | $ 0 |
Fair Value of Financial Instruments and Fair Value Measurements - Reconciliation of Changes in Fair Value of Financial Instruments (Details) - USD ($) $ in Millions |
3 Months Ended | |
---|---|---|
Mar. 31, 2024 |
Mar. 31, 2023 |
|
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Roll Forward] | ||
Fair Value Beginning of Period, | $ 36 | $ 16 |
Gains recognized in operating revenues | 3 | 0 |
(Losses) recognized in operating revenues | $ (19) | $ (3) |
Fair Value, Net Derivative Asset (Liability), Recurring Basis, Unobservable Input Reconciliation, Gain (Loss), Statement of Income or Comprehensive Income [Extensible Enumeration] | Revenues | Revenues |
Total losses recognized in operating revenues | $ (16) | $ (3) |
Gains recognized in OCI | 1 | 11 |
(Losses) recognized in OCI | $ (6) | $ (3) |
Fair Value, Net Derivative Asset (Liability), Recurring Basis, Unobservable Input Reconciliation, Gain (Loss), Statement of Other Comprehensive Income or Comprehensive Income [Extensible Enumeration] | Unrealized gain (loss) during the period on derivatives qualifying as cash flow hedges, net of income tax of $15 and $(1), respectively | Unrealized gain (loss) during the period on derivatives qualifying as cash flow hedges, net of income tax of $15 and $(1), respectively |
Total gains or losses recognized in OCI | $ (5) | $ 8 |
Net change recognized in regulatory assets and liabilities | 5 | 4 |
Purchases | 1 | 9 |
Settlements | (3) | (20) |
Fair Value as of March 31, | 18 | 14 |
Gains for the year included in operating revenues attributable to the change in unrealized gains relating to financial instruments still held at the reporting date | $ (16) | $ (3) |
Fair Value, Net Derivative Asset (Liability), Recurring Basis, Still Held, Unrealized Gain (Loss), Statement of Income or Comprehensive Income [Extensible Enumeration] | Revenues | Revenues |
Fair Value of Financial Instruments and Fair Value Measurements - Valuation of Instruments (Details) - Measurement Input, Commodity Forward Price |
Mar. 31, 2024
$ / MWh
|
---|---|
Ameren | Avg. | |
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items] | |
Derivative measurement input | 42.68 |
Ameren | Min. | |
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items] | |
Derivative measurement input | 19.58 |
Ameren | Max. | |
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items] | |
Derivative measurement input | 90.60 |
ComEd | Avg. | |
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items] | |
Derivative measurement input | 38.64 |
ComEd | Min. | |
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items] | |
Derivative measurement input | 15.39 |
ComEd | Max. | |
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items] | |
Derivative measurement input | 83.36 |
ERCOT S hub | Avg. | |
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items] | |
Derivative measurement input | 45.73 |
ERCOT S hub | Min. | |
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items] | |
Derivative measurement input | 16.17 |
ERCOT S hub | Max. | |
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items] | |
Derivative measurement input | 150.55 |
Mid C | Avg. | |
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items] | |
Derivative measurement input | 84.98 |
Mid C | Min. | |
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items] | |
Derivative measurement input | 16.95 |
Mid C | Max. | |
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items] | |
Derivative measurement input | 248.45 |
AEP-DAYTON hub | Avg. | |
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items] | |
Derivative measurement input | 42.79 |
AEP-DAYTON hub | Min. | |
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items] | |
Derivative measurement input | 20.58 |
AEP-DAYTON hub | Max. | |
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items] | |
Derivative measurement input | 94.32 |
Fair Value of Financial Instruments and Fair Value Measurements - Schedule of Fair Value Measurement (Details) - Contracts for differences - Level 3 |
Mar. 31, 2024
$ / kilowatt-MonthOfEnergy
|
---|---|
Minimum | Risk of non-performance | |
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items] | |
Derivative measurement input | 0.0052 |
Minimum | Discount rate | |
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items] | |
Derivative measurement input | 0.0384 |
Minimum | Measurement Input, Commodity Forward Price | |
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items] | |
Derivative measurement input | 2.00 |
Maximum | Risk of non-performance | |
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items] | |
Derivative measurement input | 0.0054 |
Maximum | Discount rate | |
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items] | |
Derivative measurement input | 0.0401 |
Maximum | Measurement Input, Commodity Forward Price | |
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items] | |
Derivative measurement input | 2.61 |
Derivative Instruments and Hedging - Offsetting of Derivatives, Locations in Condensed Consolidated Balance Sheet and Amounts of Derivatives (Details) - USD ($) $ in Millions |
Mar. 31, 2024 |
Dec. 31, 2023 |
---|---|---|
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||
Derivative assets | $ 272 | $ 230 |
Derivative liabilities | 182 | 175 |
Cash collateral (payable) receivable | (63) | |
Networks | Current Assets | ||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||
Total derivatives before offset of cash collateral, Asset | 1 | 1 |
Cash collateral (payable) receivable | 0 | 0 |
Total derivatives as presented in the balance sheet, Asset | 1 | 1 |
Networks | Current Assets | Not designated as hedging instruments | ||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||
Derivative assets | 20 | 13 |
Derivative liabilities | (19) | (12) |
Derivative assets | 1 | 1 |
Networks | Current Assets | Designated as hedging instruments | ||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||
Derivative assets | 0 | 0 |
Derivative liabilities | 0 | 0 |
Derivative assets | 0 | 0 |
Networks | Noncurrent Assets | ||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||
Total derivatives before offset of cash collateral, Asset | 0 | 0 |
Cash collateral (payable) receivable | 0 | 0 |
Total derivatives as presented in the balance sheet, Asset | 0 | 0 |
Networks | Noncurrent Assets | Not designated as hedging instruments | ||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||
Derivative assets | 5 | 3 |
Derivative liabilities | (5) | (3) |
Derivative assets | 0 | 0 |
Networks | Noncurrent Assets | Designated as hedging instruments | ||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||
Derivative assets | 0 | 0 |
Derivative liabilities | 0 | 0 |
Derivative assets | 0 | 0 |
Networks | Current Liabilities | ||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||
Total derivatives before offset of cash collateral, Liability | (23) | (45) |
Cash collateral receivable, Liability | 6 | 27 |
Total derivatives as presented in the balance sheet, Liability | (17) | (18) |
Networks | Current Liabilities | Not designated as hedging instruments | ||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||
Derivative assets | 19 | 12 |
Derivative liabilities | (42) | (57) |
Derivative liabilities | 23 | 45 |
Networks | Current Liabilities | Designated as hedging instruments | ||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||
Derivative assets | 0 | 0 |
Derivative liabilities | 0 | 0 |
Derivative liabilities | 0 | 0 |
Networks | Noncurrent Liabilities | ||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||
Total derivatives before offset of cash collateral, Liability | (24) | (29) |
Cash collateral receivable, Liability | 7 | 7 |
Total derivatives as presented in the balance sheet, Liability | (17) | (22) |
Networks | Noncurrent Liabilities | Not designated as hedging instruments | ||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||
Derivative assets | 5 | 3 |
Derivative liabilities | (29) | (32) |
Derivative liabilities | 24 | 29 |
Networks | Noncurrent Liabilities | Designated as hedging instruments | ||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||
Derivative assets | 0 | 0 |
Derivative liabilities | 0 | 0 |
Derivative liabilities | 0 | 0 |
Renewables | Current Assets | ||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||
Total derivatives before offset of cash collateral, Asset | 90 | 67 |
Cash collateral (payable) receivable | (4) | 0 |
Total derivatives as presented in the balance sheet, Asset | 86 | 67 |
Renewables | Current Assets | Not designated as hedging instruments | ||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||
Derivative assets | 64 | 53 |
Derivative liabilities | (3) | 0 |
Derivative assets | 61 | 53 |
Renewables | Current Assets | Designated as hedging instruments | ||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||
Derivative assets | 30 | 15 |
Derivative liabilities | (1) | (1) |
Derivative assets | 29 | 14 |
Renewables | Noncurrent Assets | ||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||
Total derivatives before offset of cash collateral, Asset | 185 | 162 |
Cash collateral (payable) receivable | 0 | 0 |
Total derivatives as presented in the balance sheet, Asset | 185 | 162 |
Renewables | Noncurrent Assets | Not designated as hedging instruments | ||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||
Derivative assets | 48 | 52 |
Derivative liabilities | (1) | (3) |
Derivative assets | 47 | 49 |
Renewables | Noncurrent Assets | Designated as hedging instruments | ||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||
Derivative assets | 138 | 113 |
Derivative liabilities | 0 | 0 |
Derivative assets | 138 | 113 |
Renewables | Current Liabilities | ||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||
Total derivatives before offset of cash collateral, Liability | (33) | (60) |
Cash collateral receivable, Liability | 14 | 43 |
Total derivatives as presented in the balance sheet, Liability | (19) | (17) |
Renewables | Current Liabilities | Not designated as hedging instruments | ||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||
Derivative assets | 43 | 53 |
Derivative liabilities | (53) | (73) |
Derivative liabilities | 10 | 20 |
Renewables | Current Liabilities | Designated as hedging instruments | ||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||
Derivative assets | 14 | 7 |
Derivative liabilities | (37) | (47) |
Derivative liabilities | 23 | 40 |
Renewables | Noncurrent Liabilities | ||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||
Total derivatives before offset of cash collateral, Liability | (36) | (39) |
Cash collateral receivable, Liability | 8 | 13 |
Total derivatives as presented in the balance sheet, Liability | (28) | (26) |
Renewables | Noncurrent Liabilities | Not designated as hedging instruments | ||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||
Derivative assets | 5 | 1 |
Derivative liabilities | (7) | (4) |
Derivative liabilities | 2 | 3 |
Renewables | Noncurrent Liabilities | Designated as hedging instruments | ||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||
Derivative assets | 1 | 1 |
Derivative liabilities | (35) | (37) |
Derivative liabilities | $ 34 | $ 36 |
Derivative Instruments and Hedging - Net Notional Volume (Details) MWh in Millions, MMBTU in Millions, $ in Millions |
3 Months Ended | 12 Months Ended |
---|---|---|
Mar. 31, 2024
USD ($)
MMBTU
MWh
|
Dec. 31, 2023
USD ($)
MWh
MMBTU
|
|
Networks | Wholesale electricity purchase contracts (MWh) | Long | ||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||
Derivative, nonmonetary notional amount, energy measure | MWh | 6.0 | 5.6 |
Networks | Natural gas purchase contracts (Dth) | Long | ||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||
Derivative, nonmonetary notional amount, energy measure | MMBTU | 9.3 | 10.7 |
Renewables | ||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||
Derivative assets (liabilities), fair value | $ | $ 67 | $ 64 |
Renewables | Wholesale electricity purchase contracts (MWh) | Long | ||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||
Derivative, nonmonetary notional amount, energy measure | MWh | 1.0 | 1.0 |
Derivative assets (liabilities), fair value | $ | $ 8 | $ 29 |
Renewables | Wholesale electricity purchase contracts (MWh) | Short | ||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||
Derivative, nonmonetary notional amount, energy measure | MWh | 6.0 | 6.0 |
Derivative assets (liabilities), fair value | $ | $ 46 | $ 14 |
Renewables | Natural gas and other fuel purchase contracts | Long | ||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||
Derivative, nonmonetary notional amount, energy measure | MMBTU | 14.0 | 21.0 |
Derivative assets (liabilities), fair value | $ | $ 3 | $ 4 |
Renewables | Financial power contracts | ||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||
Derivative, nonmonetary notional amount, energy measure | MMBTU | 4.0 | 4.0 |
Derivative assets (liabilities), fair value | $ | $ 10 | $ 17 |
Renewables | Basis swaps | Long | ||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||
Derivative, nonmonetary notional amount, energy measure | MMBTU | 21.0 | 24.0 |
Renewables | Basis swaps | Short | ||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||
Derivative, nonmonetary notional amount, energy measure | MMBTU | 1.0 | 1.0 |
Derivative Instruments and Hedging - Summary of Unrealized Gains and Losses from Fair Value Adjustments (Details) - USD ($) $ in Millions |
3 Months Ended | ||
---|---|---|---|
Mar. 31, 2024 |
Mar. 31, 2023 |
Dec. 31, 2023 |
|
Derivative liabilities | |||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |||
Loss (Gain) Reclassified from Regulatory Assets/Liabilities into Income | $ 5 | $ 4 | |
Electricity | Regulatory assets | |||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |||
Loss or Gain Recognized in Regulatory Assets/Liabilities | 10 | $ 22 | |
Loss (Gain) Reclassified from Regulatory Assets/Liabilities into Income | 20 | 49 | |
Natural Gas | Regulatory assets | |||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |||
Loss or Gain Recognized in Regulatory Assets/Liabilities | 3 | $ 12 | |
Loss (Gain) Reclassified from Regulatory Assets/Liabilities into Income | $ 11 | $ 6 |
Derivative Instruments and Hedging - Additional Information (Details) $ in Millions |
3 Months Ended | |||||
---|---|---|---|---|---|---|
Mar. 31, 2024
USD ($)
instrument
|
Mar. 31, 2023
USD ($)
|
Dec. 31, 2023
USD ($)
|
Sep. 15, 2021
USD ($)
|
Jul. 15, 2021
USD ($)
|
May 27, 2021
USD ($)
|
|
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||||||
Regulatory assets | $ 3,806 | $ 3,529 | ||||
Regulatory liabilities | 2,951 | 2,955 | ||||
Derivative assets | 185 | 162 | ||||
Derivative liabilities | 182 | 175 | ||||
Aggregate fair value of additional collateral | 27 | |||||
Cash collateral pledged | 63 | |||||
Collateral already posted | $ 13 | |||||
Contracts for differences | ||||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||||||
Number of derivative instruments | instrument | 2 | |||||
Derivative liabilities | $ 34 | 39 | ||||
Interest rate contracts | ||||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||||||
Gain (loss) recognized in OCI on derivatives | 0 | $ 0 | ||||
Previously Settled Interest Rate Contracts | ||||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||||||
Gain (loss) recognized in OCI on derivatives | (2) | (2) | ||||
Cash Flow Hedging | Interest rate contracts | ||||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||||||
Cash flow hedge gain (loss) to be reclassified within twelve months | (9) | |||||
Cash Flow Hedging | Previously Settled Interest Rate Contracts | ||||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||||||
Net loss related to previously settled forward starting swaps | 27 | 29 | ||||
Fair Value Hedging | Interest Rate Swap | ||||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||||||
Derivative liabilities | $ 750 | |||||
Networks | ||||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||||||
Gain (loss) recognized in OCI on derivatives | 0 | 0 | ||||
Networks | Cash Flow Hedging | ||||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||||||
Gain (loss) recognized in OCI on derivatives | (1) | (1) | ||||
Cash flow hedge gain (loss) to be reclassified within twelve months | 4 | |||||
Networks | Cash Flow Hedging | Previously Settled Forward Starting Swaps | ||||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||||||
Net loss related to previously settled forward starting swaps | 38 | 39 | ||||
Renewables | ||||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||||||
Gain (loss) recognized in OCI on derivatives | 56 | 113 | ||||
Renewables | Interest rate contracts | ||||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||||||
Gain (loss) recognized in OCI on derivatives | 36 | $ 90 | ||||
Renewables | Cash Flow Hedging | ||||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||||||
Cash flow hedge gain (loss) to be reclassified within twelve months | (20) | |||||
Renewables | Cash Flow Hedging | Interest Rate Swap | ||||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||||||
Derivative notional amount | $ 956 | $ 935 | ||||
Derivative assets | $ 158 | 122 | ||||
UI | Contracts for differences | ||||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||||||
Percentage of cost or benefit on contract allocated to customers | 20.00% | |||||
Gross derivative asset | $ 1 | 1 | ||||
Regulatory assets | 33 | 38 | ||||
Gross amounts of recognized liabilities | 34 | 39 | ||||
Regulatory liabilities | $ 0 | 0 | ||||
CL&P | Contracts for differences | ||||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||||||
Percentage of cost or benefit on contract allocated to customers | 80.00% | |||||
Gross derivative asset | $ 0 | 0 | ||||
Gross amounts of recognized liabilities | $ 33 | $ 38 |
Derivative Instruments and Hedging - Effect of Derivatives in Cash Flow Hedging (Details) - USD ($) $ in Millions |
3 Months Ended | |
---|---|---|
Mar. 31, 2024 |
Mar. 31, 2023 |
|
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||
Interest expense | $ 125 | $ 95 |
Purchased power, natural gas and fuel used | 724 | 977 |
Revenues | 2,417 | 2,466 |
Networks | ||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||
Gain (Loss) Recognized in OCI on Derivatives | 0 | 0 |
Loss (Gain) Reclassified from Accumulated OCI into Income | 1 | 1 |
Revenues | 2,018 | 2,076 |
Renewables | ||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||
Gain (Loss) Recognized in OCI on Derivatives | 56 | 113 |
Loss (Gain) Reclassified from Accumulated OCI into Income | 5 | 66 |
Revenues | 400 | 390 |
Interest rate contracts | ||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||
Gain (Loss) Recognized in OCI on Derivatives | 0 | 0 |
Interest rate contracts | Interest expense | ||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||
Loss (Gain) Reclassified from Accumulated OCI into Income | 2 | 2 |
Interest rate contracts | Networks | Interest expense | ||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||
Gain (Loss) Recognized in OCI on Derivatives | 0 | 0 |
Loss (Gain) Reclassified from Accumulated OCI into Income | 1 | 1 |
Interest rate contracts | Renewables | ||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||
Gain (Loss) Recognized in OCI on Derivatives | 36 | 90 |
Loss (Gain) Reclassified from Accumulated OCI into Income | 0 | 0 |
Interest expense | 125 | 95 |
Commodity contracts | Networks | Purchased power, natural gas and fuel used | ||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||
Gain (Loss) Recognized in OCI on Derivatives | 0 | 0 |
Loss (Gain) Reclassified from Accumulated OCI into Income | 0 | 0 |
Commodity contracts | Renewables | ||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||
Gain (Loss) Recognized in OCI on Derivatives | 20 | 23 |
Loss (Gain) Reclassified from Accumulated OCI into Income | 5 | 66 |
Revenues | $ 2,417 | $ 2,466 |
Derivative Instruments and Hedging - Fair Value of Derivative Contract (Details) - Renewables - USD ($) $ in Millions |
Mar. 31, 2024 |
Dec. 31, 2023 |
---|---|---|
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||
Derivative assets (liabilities), fair value | $ 67 | $ 64 |
Financial power contracts | ||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||
Derivative assets (liabilities), fair value | 10 | 17 |
Long | Wholesale electricity purchase contracts (MWh) | ||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||
Derivative assets (liabilities), fair value | 8 | 29 |
Long | Natural gas and other fuel purchase contracts | ||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||
Derivative assets (liabilities), fair value | 3 | 4 |
Short | Wholesale electricity purchase contracts (MWh) | ||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||
Derivative assets (liabilities), fair value | $ 46 | $ 14 |
Derivative Instruments and Hedging - Effect of Trading and Non-trading Derivatives (Details) - USD ($) $ in Millions |
3 Months Ended | |
---|---|---|
Mar. 31, 2024 |
Mar. 31, 2023 |
|
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||
Derivative, gain (loss) on derivative, net | $ 87 | $ 122 |
Operating revenues | 2,417 | 2,466 |
Utilities operating expense, purchased power | $ 724 | $ 977 |
Derivative, Gain (Loss), Statement of Income or Comprehensive Income [Extensible Enumeration] | Operating revenues, Utilities operating expense, purchased power | Operating revenues, Utilities operating expense, purchased power |
Renewables | ||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||
Operating revenues | $ 400 | $ 390 |
Renewables | Trading | ||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||
Derivative, gain (loss) on derivative, net | 6 | 5 |
Renewables | Trading | Operating Revenues | ||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||
Derivative, gain (loss) on derivative, net | $ 6 | $ 5 |
Derivative, Gain (Loss), Statement of Income or Comprehensive Income [Extensible Enumeration] | Operating revenues | Operating revenues, Utilities operating expense, purchased power |
Renewables | Trading | Purchased power, natural gas and fuel used | ||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||
Derivative, gain (loss) on derivative, net | $ 0 | $ 0 |
Derivative, Gain (Loss), Statement of Income or Comprehensive Income [Extensible Enumeration] | Utilities operating expense, purchased power | Operating revenues, Utilities operating expense, purchased power |
Renewables | Trading | Wholesale electricity purchase contracts (MWh) | Long | Operating Revenues | ||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||
Derivative, gain (loss) on derivative, net | $ (3) | $ (4) |
Renewables | Trading | Wholesale electricity purchase contracts (MWh) | Long | Purchased power, natural gas and fuel used | ||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||
Derivative, gain (loss) on derivative, net | 0 | 0 |
Renewables | Trading | Wholesale electricity purchase contracts (MWh) | Short | ||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||
Derivative, gain (loss) on derivative, net | 11 | 7 |
Renewables | Trading | Financial power contracts | Operating Revenues | ||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||
Derivative, gain (loss) on derivative, net | (2) | 2 |
Renewables | Trading | Financial power contracts | Purchased power, natural gas and fuel used | ||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||
Derivative, gain (loss) on derivative, net | 0 | 0 |
Renewables | Trading | Financial and natural gas contracts | Operating Revenues | ||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||
Derivative, gain (loss) on derivative, net | 0 | 0 |
Renewables | Trading | Financial and natural gas contracts | Purchased power, natural gas and fuel used | ||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||
Derivative, gain (loss) on derivative, net | 0 | 0 |
Renewables | Non-trading | ||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||
Derivative, gain (loss) on derivative, net | 13 | (6) |
Operating revenues | 2,417 | 2,466 |
Utilities operating expense, purchased power | 724 | 977 |
Renewables | Non-trading | Operating Revenues | ||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||
Derivative, gain (loss) on derivative, net | $ 22 | $ 50 |
Derivative, Gain (Loss), Statement of Income or Comprehensive Income [Extensible Enumeration] | Operating revenues | Operating revenues, Utilities operating expense, purchased power |
Renewables | Non-trading | Purchased power, natural gas and fuel used | ||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||
Derivative, gain (loss) on derivative, net | $ (9) | $ (56) |
Derivative, Gain (Loss), Statement of Income or Comprehensive Income [Extensible Enumeration] | Utilities operating expense, purchased power | Operating revenues, Utilities operating expense, purchased power |
Renewables | Non-trading | Wholesale electricity purchase contracts (MWh) | Long | Operating Revenues | ||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||
Derivative, gain (loss) on derivative, net | $ 0 | $ 1 |
Renewables | Non-trading | Wholesale electricity purchase contracts (MWh) | Long | Purchased power, natural gas and fuel used | ||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||
Derivative, gain (loss) on derivative, net | (17) | (35) |
Renewables | Non-trading | Wholesale electricity purchase contracts (MWh) | Short | ||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||
Derivative, gain (loss) on derivative, net | 22 | 24 |
Renewables | Non-trading | Financial power contracts | Operating Revenues | ||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||
Derivative, gain (loss) on derivative, net | 2 | 15 |
Renewables | Non-trading | Financial power contracts | Purchased power, natural gas and fuel used | ||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||
Derivative, gain (loss) on derivative, net | 0 | 0 |
Renewables | Non-trading | Financial and natural gas contracts | Operating Revenues | ||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||
Derivative, gain (loss) on derivative, net | (2) | 10 |
Renewables | Non-trading | Financial and natural gas contracts | Purchased power, natural gas and fuel used | ||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||
Derivative, gain (loss) on derivative, net | $ 8 | $ (21) |
Derivative Instruments and Hedging - Schedule of Fair Value Hedge (Details) - Interest Rate Swap - USD ($) $ in Millions |
3 Months Ended | ||
---|---|---|---|
Mar. 31, 2024 |
Mar. 31, 2023 |
Dec. 31, 2023 |
|
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |||
(Gain) loss on fair value hedges recognized in Income Statement | $ 11 | $ 7 | |
Current Liabilities | |||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |||
Hedged liability, fair value hedge | (29) | $ (26) | |
Non-current liabilities | |||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |||
Hedged liability, fair value hedge | (71) | (63) | |
Current debt | |||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |||
Cumulative effect on hedged debt | 0 | 0 | |
Non-current debt | |||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |||
Cumulative effect on hedged debt | 100 | $ 89 | |
Fair Value Hedging | |||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |||
Year to date total per Income Statement | $ 125 | $ 95 |
Contingencies and Commitments (Details) - USD ($) $ in Millions |
12 Months Ended | ||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|
Feb. 26, 2024 |
Oct. 27, 2023 |
Apr. 29, 2016 |
Jul. 31, 2014 |
Dec. 26, 2012 |
Sep. 30, 2011 |
Dec. 31, 2021 |
Mar. 31, 2024 |
Jun. 16, 2023 |
May 04, 2021 |
Jan. 04, 2021 |
|
Loss Contingencies [Line Items] | |||||||||||
Standby letters of credit, surety bonds, guarantees and indemnifications outstanding | $ 918.0 | ||||||||||
Future payments committed | $ 90.0 | ||||||||||
NECEC commitment, payment during period | $ 11.0 | ||||||||||
Transmission - ROE Complaint | |||||||||||
Loss Contingencies [Line Items] | |||||||||||
Requested return on equity base percentage | 11.14% | ||||||||||
Customer Service Invoice Dispute | |||||||||||
Loss Contingencies [Line Items] | |||||||||||
Litigation settlement, adjustment amount requested | $ 31.0 | $ 31.0 | |||||||||
Solar Contractor Dispute | |||||||||||
Loss Contingencies [Line Items] | |||||||||||
Amount of liens claimed due under contracts | $ 105.0 | ||||||||||
Loss contingency, damages sought value | $ 59.9 | $ 111.8 | |||||||||
Litigation settlement, amount of lien seeking to close | $ 59.9 | ||||||||||
Unfavorable Regulatory Action | Complaint I | |||||||||||
Loss Contingencies [Line Items] | |||||||||||
Requested return on equity base percentage | 9.20% | ||||||||||
Unfavorable Regulatory Action | Transmission - ROE Complaint Two | |||||||||||
Loss Contingencies [Line Items] | |||||||||||
Requested return on equity base percentage | 8.70% | ||||||||||
Unfavorable Regulatory Action | Transmission - ROE Complaint Three | |||||||||||
Loss Contingencies [Line Items] | |||||||||||
Requested return on equity base percentage | 8.84% | ||||||||||
Unfavorable Regulatory Action | Transmission - ROE Complaint Four | |||||||||||
Loss Contingencies [Line Items] | |||||||||||
Requested return on equity base percentage | 8.61% | ||||||||||
Unfavorable Regulatory Action | Transmission - ROE Complaint Four | Max. | |||||||||||
Loss Contingencies [Line Items] | |||||||||||
Requested return on equity base percentage | 11.24% |
Environmental Liabilities (Details) |
3 Months Ended | 12 Months Ended | 80 Months Ended | |||
---|---|---|---|---|---|---|
Mar. 31, 2024
USD ($)
site
|
Dec. 31, 2012
site
|
Dec. 31, 2009
site
|
Mar. 31, 2023
USD ($)
|
Dec. 31, 2023
USD ($)
|
Aug. 04, 2016
USD ($)
|
|
Environmental Exit Cost [Line Items] | ||||||
Number of sites with potential remediation obligations | 24 | |||||
Number of sites with liability recorded | 6 | |||||
Number of sits note expected to incur additional liabilities | 18 | |||||
Number of additional sites with liability recorded | 10 | |||||
Number of sites where gas was manufactured in the past | 53 | |||||
Number of sites for which we have entered into consent orders to investigate and remediate | 41 | |||||
Accrual related to investigation and remediation | $ | $ 245,000,000 | $ 250,000,000 | ||||
Accrual related to investigation and remediation, amount recorded to date | $ | $ 35,000,000 | |||||
FirstEnergy | ||||||
Environmental Exit Cost [Line Items] | ||||||
Number of sites in dispute | 16 | |||||
United Illuminating Company (UI) | ||||||
Environmental Exit Cost [Line Items] | ||||||
Accrual related to investigation and remediation | $ | 19,000,000 | |||||
Cost of investigation and remediation | $ | $ 30,000,000 | |||||
Min. | ||||||
Environmental Exit Cost [Line Items] | ||||||
Estimated environmental liability | $ | 15,000,000 | |||||
Max. | ||||||
Environmental Exit Cost [Line Items] | ||||||
Estimated environmental liability | $ | $ 22,000,000 | |||||
New York State Registry | ||||||
Environmental Exit Cost [Line Items] | ||||||
Number of sites with potential remediation obligations | 16 | |||||
Number of sites where gas was manufactured in the past | 6 | |||||
Maine's Uncontrolled Sites Program | ||||||
Environmental Exit Cost [Line Items] | ||||||
Number of sites with potential remediation obligations | 2 | |||||
Number of sites where gas was manufactured in the past | 0 | |||||
Brownfield Cleanup Program | ||||||
Environmental Exit Cost [Line Items] | ||||||
Number of sites where gas was manufactured in the past | 2 | |||||
Massachusetts Non-Priority Confirmed Disposal Site List | ||||||
Environmental Exit Cost [Line Items] | ||||||
Number of sites with potential remediation obligations | 1 | |||||
National Priorities List | ||||||
Environmental Exit Cost [Line Items] | ||||||
Number of sites with potential remediation obligations | 5 | |||||
Hazardous Substances Waste Sites With Liability Recorded | ||||||
Environmental Exit Cost [Line Items] | ||||||
Estimated environmental liability | $ | $ 6,000,000 | |||||
Hazardous Substances Waste Sites Will Incur Remediation And / Or Monitoring Costs | ||||||
Environmental Exit Cost [Line Items] | ||||||
Estimated environmental liability | $ | $ 10,000,000 | |||||
New York State Department of Environmental Conservation (NYSDEC) Multi-Site Order Of Consent | ||||||
Environmental Exit Cost [Line Items] | ||||||
Number of sites where gas was manufactured in the past | 39 | |||||
Sites With Individual NYSDEC Orders Of Consent | ||||||
Environmental Exit Cost [Line Items] | ||||||
Number of sites where gas was manufactured in the past | 2 | |||||
Manufactured Gas Plants | Connecticut | ||||||
Environmental Exit Cost [Line Items] | ||||||
Accrual related to investigation and remediation | $ | $ 112,000,000 | $ 112,000,000 | ||||
Manufactured Gas Plants | Min. | ||||||
Environmental Exit Cost [Line Items] | ||||||
Accrual related to investigation and remediation | $ | 117,000,000 | |||||
Manufactured Gas Plants | Max. | ||||||
Environmental Exit Cost [Line Items] | ||||||
Accrual related to investigation and remediation | $ | 213,000,000 | |||||
Properties Where MGPs Had Historically Operated | ||||||
Environmental Exit Cost [Line Items] | ||||||
Accrual related to investigation and remediation | $ | 0 | |||||
MGP Sites | FirstEnergy | ||||||
Environmental Exit Cost [Line Items] | ||||||
Number of sites in dispute | 2 | |||||
NYSEG | FirstEnergy | ||||||
Environmental Exit Cost [Line Items] | ||||||
Accrual related to investigation and remediation | $ | 8,000,000 | |||||
RG&E | FirstEnergy | ||||||
Environmental Exit Cost [Line Items] | ||||||
Accrual related to investigation and remediation | $ | $ 5,000,000 | |||||
Maine's Voluntary Response Action Program | ||||||
Environmental Exit Cost [Line Items] | ||||||
Number of sites for which we have entered into consent orders to investigate and remediate | 2 |
Post-retirement and Similar Obligations - Additional Information (Details) $ in Millions |
3 Months Ended |
---|---|
Mar. 31, 2024
USD ($)
| |
Retirement Benefits [Abstract] | |
Defined benefit, pension contributions | $ 1 |
Expected future employer contributions in current fiscal year | $ 27 |
Post-retirement and Similar Obligations - Periodic Benefit Costs Net (Details) - USD ($) $ in Millions |
3 Months Ended | |
---|---|---|
Mar. 31, 2024 |
Mar. 31, 2023 |
|
Pension Plan | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Service cost | $ 2 | $ 2 |
Interest cost | 28 | 30 |
Expected return on plan assets | (40) | (36) |
Prior service costs | 0 | 0 |
Actuarial loss | 7 | 1 |
Net Periodic Benefit Cost | (3) | (3) |
Other Postretirement Benefit Plan | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Service cost | 0 | 0 |
Interest cost | 3 | 3 |
Expected return on plan assets | (1) | (1) |
Prior service costs | 0 | 0 |
Actuarial loss | (1) | (3) |
Net Periodic Benefit Cost | $ 1 | $ (1) |
Equity - Additional Information (Details) - USD ($) $ / shares in Units, $ in Millions |
3 Months Ended | |||
---|---|---|---|---|
Mar. 31, 2024 |
Mar. 31, 2023 |
Dec. 31, 2023 |
Dec. 31, 2022 |
|
Class of Stock [Line Items] | ||||
Common stock, held in trust (in shares) | 103,889 | 103,889 | ||
Common stock, par value (in dollars per share) | $ 0.01 | $ 0.01 | $ 0.01 | $ 0.01 |
Release of common stock held in trust (in shares) | 0 | 0 | ||
Treasury shares (in shares) | 997,983 | |||
Repurchases of common stock | $ 47 | $ 47 | ||
Iberdrola Renewables Holding Inc | ||||
Class of Stock [Line Items] | ||||
Percentage of equity owned by parent | 81.50% | |||
Convertible Preferred Stock | ||||
Class of Stock [Line Items] | ||||
Convertible preferred stock, shares outstanding (in shares) | 0 | 0 | ||
Common Stock | ||||
Class of Stock [Line Items] | ||||
Issuances of common stock (in shares) | 135,345 | 12,332 |
Equity - Accumulated Other Comprehensive Income (Loss) (Details) - USD ($) $ in Millions |
3 Months Ended | |
---|---|---|
Mar. 31, 2024 |
Mar. 31, 2023 |
|
AOCI Attributable to Parent, Net of Tax [Roll Forward] | ||
Balance, beginning of period | $ 20,676 | $ 20,342 |
Other comprehensive income (loss), net of tax | 46 | 49 |
Balance, end of period | 20,889 | 20,510 |
Unrealized (loss) gain from equity method investment, income tax expense | 0 | 0 |
Unrealized loss during period on derivatives qualifying as cash flow hedges, income tax benefit | 15 | (1) |
Reclassification to net income of loss on cash flow hedges, income taxes | 2 | 18 |
Net loss on pension plans | ||
AOCI Attributable to Parent, Net of Tax [Roll Forward] | ||
Balance, beginning of period | (21) | (20) |
Other comprehensive income (loss), net of tax | 0 | 0 |
Balance, end of period | (21) | (20) |
Unrealized (loss) gain from equity method investment | ||
AOCI Attributable to Parent, Net of Tax [Roll Forward] | ||
Balance, beginning of period | 18 | 13 |
Other comprehensive income (loss), net of tax | 0 | (1) |
Balance, end of period | 18 | 12 |
Unrealized loss during period on derivatives qualifying as cash flow hedges | ||
AOCI Attributable to Parent, Net of Tax [Roll Forward] | ||
Balance, beginning of period | (178) | (195) |
Other comprehensive income (loss), net of tax | 39 | (2) |
Balance, end of period | (139) | (197) |
Reclassification to net income of losses on cash flow hedges | ||
AOCI Attributable to Parent, Net of Tax [Roll Forward] | ||
Balance, beginning of period | 156 | 22 |
Other comprehensive income (loss), net of tax | 7 | 52 |
Balance, end of period | 163 | 74 |
Loss (gain) on derivatives qualifying as cash flow hedges | ||
AOCI Attributable to Parent, Net of Tax [Roll Forward] | ||
Balance, beginning of period | (22) | (173) |
Other comprehensive income (loss), net of tax | 46 | 50 |
Balance, end of period | 24 | (123) |
Accumulated Other Comprehensive Income (Loss) | ||
AOCI Attributable to Parent, Net of Tax [Roll Forward] | ||
Balance, beginning of period | (25) | (180) |
Other comprehensive income (loss), net of tax | 46 | 49 |
Balance, end of period | $ 21 | $ (131) |
Earnings Per Share (Details) - USD ($) $ / shares in Units, $ in Millions |
3 Months Ended | |
---|---|---|
Mar. 31, 2024 |
Mar. 31, 2023 |
|
Numerator: | ||
Net income attributable to Avangrid, basic | $ 351 | $ 245 |
Net income attributable to Avangrid, diluted | $ 351 | $ 245 |
Denominator: | ||
Weighted average number of shares outstanding - basic (in shares) | 386,916,234 | 386,744,996 |
Weighted average number of shares outstanding - diluted (in shares) | 387,239,544 | 387,077,213 |
Earnings per share attributable to Avangrid | ||
Earnings Per Common Share, Basic (in dollars per share) | $ 0.91 | $ 0.63 |
Earnings Per Common Share, Diluted (in dollars per share) | $ 0.91 | $ 0.63 |
Segment Information - Additional Information (Details) |
3 Months Ended |
---|---|
Mar. 31, 2024
segment
| |
Segment Reporting Information [Line Items] | |
Number of reportable segments | 2 |
Networks | |
Segment Reporting Information [Line Items] | |
Number of reportable segments | 1 |
Number of operating segments | 9 |
Segment Information - By Segment (Details) - USD ($) $ in Millions |
3 Months Ended | ||
---|---|---|---|
Mar. 31, 2024 |
Mar. 31, 2023 |
Dec. 31, 2023 |
|
Segment Reporting Information [Line Items] | |||
Revenues | $ 2,417 | $ 2,466 | |
Depreciation and amortization | 298 | 280 | |
Operating income (loss) | 407 | 265 | |
Earnings (losses) from equity method investments | 6 | 2 | |
Interest expense, net of capitalization | 125 | 95 | |
Income tax expense (benefit) | 20 | (18) | |
Adjusted net income (loss) | 341 | 248 | |
Capital expenditures | 872 | 836 | |
Property, plant and equipment | 33,323 | $ 32,857 | |
Equity method investments | 836 | 718 | |
Total assets | 45,062 | 43,989 | |
Intersegment Eliminations | |||
Segment Reporting Information [Line Items] | |||
Revenues | (1) | ||
Other | |||
Segment Reporting Information [Line Items] | |||
Revenues | 0 | 0 | |
Depreciation and amortization | 2 | 1 | |
Operating income (loss) | (6) | (2) | |
Earnings (losses) from equity method investments | 0 | 0 | |
Interest expense, net of capitalization | 32 | 19 | |
Income tax expense (benefit) | (31) | (28) | |
Adjusted net income (loss) | (11) | 1 | |
Capital expenditures | 2 | 0 | |
Property, plant and equipment | 12 | 12 | |
Equity method investments | 0 | 0 | |
Total assets | (290) | (962) | |
Networks | |||
Segment Reporting Information [Line Items] | |||
Revenues | 2,018 | 2,076 | |
Networks | Operating Segments | |||
Segment Reporting Information [Line Items] | |||
Revenues | 2,017 | 2,076 | |
Depreciation and amortization | 178 | 174 | |
Operating income (loss) | 353 | 277 | |
Earnings (losses) from equity method investments | 4 | 4 | |
Interest expense, net of capitalization | 89 | 70 | |
Income tax expense (benefit) | 57 | 44 | |
Adjusted net income (loss) | 268 | 195 | |
Capital expenditures | 691 | 609 | |
Property, plant and equipment | 22,068 | 21,692 | |
Equity method investments | 188 | 186 | |
Total assets | 31,238 | 30,413 | |
Networks | Intersegment Eliminations | |||
Segment Reporting Information [Line Items] | |||
Revenues | 1 | ||
Renewables | |||
Segment Reporting Information [Line Items] | |||
Revenues | 400 | 390 | |
Renewables | Operating Segments | |||
Segment Reporting Information [Line Items] | |||
Revenues | 400 | 390 | |
Depreciation and amortization | 118 | 105 | |
Operating income (loss) | 60 | (10) | |
Earnings (losses) from equity method investments | 2 | (2) | |
Interest expense, net of capitalization | 4 | 6 | |
Income tax expense (benefit) | (6) | (34) | |
Adjusted net income (loss) | 84 | 51 | |
Capital expenditures | 179 | $ 227 | |
Property, plant and equipment | 11,243 | 11,153 | |
Equity method investments | 648 | 532 | |
Total assets | 14,114 | $ 14,538 | |
Renewables | Intersegment Eliminations | |||
Segment Reporting Information [Line Items] | |||
Revenues | $ 0 |
Segment Information - Reconciliation of Adjusted Net Income to Net Income (Details) - USD ($) $ in Millions |
3 Months Ended | |
---|---|---|
Mar. 31, 2024 |
Mar. 31, 2023 |
|
Segment Reporting [Abstract] | ||
Adjusted Net Income Attributable to Avangrid, Inc. | $ 341 | $ 248 |
Adjustments: | ||
Mark-to-market earnings - Renewables | 17 | (4) |
Accelerated depreciation from repowering | (3) | 0 |
Income tax impact of adjustments | (4) | 1 |
Net Income Attributable to Avangrid, Inc. | $ 351 | $ 245 |
Related Party Transactions - Schedule of Related Party Transactions (Details) - Related Party - USD ($) $ in Millions |
3 Months Ended | |
---|---|---|
Mar. 31, 2024 |
Mar. 31, 2023 |
|
Sales To | Iberdrola, S.A. | ||
Related Party Transaction [Line Items] | ||
Related party transaction, amount | $ 0 | $ 0 |
Sales To | Iberdrola Renovables Energía, S.L. | ||
Related Party Transaction [Line Items] | ||
Related party transaction, amount | 0 | 0 |
Sales To | Iberdrola Financiación, S.A. | ||
Related Party Transaction [Line Items] | ||
Related party transaction, amount | 0 | 0 |
Sales To | Vineyard Wind | ||
Related Party Transaction [Line Items] | ||
Related party transaction, amount | 3 | 2 |
Purchases From | Iberdrola, S.A. | ||
Related Party Transaction [Line Items] | ||
Related party transaction, amount | (12) | (11) |
Purchases From | Iberdrola Renovables Energía, S.L. | ||
Related Party Transaction [Line Items] | ||
Related party transaction, amount | (2) | (2) |
Purchases From | Iberdrola Financiación, S.A. | ||
Related Party Transaction [Line Items] | ||
Related party transaction, amount | (16) | (4) |
Purchases From | Vineyard Wind | ||
Related Party Transaction [Line Items] | ||
Related party transaction, amount | $ 0 | $ 0 |
Related Party Transactions - Schedule of Related Party Balances (Details) - Related Party - USD ($) $ in Millions |
Mar. 31, 2024 |
Dec. 31, 2023 |
---|---|---|
Related Party Transaction [Line Items] | ||
Owed By | $ 5 | $ 11 |
Owed To | (18) | 0 |
Iberdrola Renovables Energía, S.L. | ||
Related Party Transaction [Line Items] | ||
Owed By | 0 | 4 |
Owed To | (2) | 0 |
Vineyard Wind | ||
Related Party Transaction [Line Items] | ||
Owed By | 4 | 6 |
Owed To | (8) | (8) |
Iberdrola, S.A. | ||
Related Party Transaction [Line Items] | ||
Owed By | 1 | 1 |
Owed To | (12) | 0 |
Iberdrola Solutions | ||
Related Party Transaction [Line Items] | ||
Owed By | 0 | 0 |
Owed To | (6) | (6) |
Other | ||
Related Party Transaction [Line Items] | ||
Owed By | 4 | 4 |
Owed To | (1) | 0 |
Iberdrola Financiación, S.A. | ||
Related Party Transaction [Line Items] | ||
Owed By | 0 | 0 |
Owed To | $ (1,304) | $ (799) |
Related Party Transactions - Additional Information (Details) - USD ($) |
3 Months Ended | |||
---|---|---|---|---|
Mar. 31, 2024 |
Dec. 31, 2023 |
Jul. 19, 2023 |
Jun. 18, 2023 |
|
Iberdrola Financiacion, S.A.U | ||||
Related Party Transaction [Line Items] | ||||
Credit facility, amount outstanding | $ 500,000,000 | $ 0 | ||
Related Party | ||||
Related Party Transaction [Line Items] | ||||
Notes payable | 515,000,000 | 13,000,000 | ||
Related Party | Iberdrola Solutions | ||||
Related Party Transaction [Line Items] | ||||
Notes payable | 6,000,000 | 6,000,000 | ||
Related Party | Affiliated Entity | ||||
Related Party Transaction [Line Items] | ||||
Impairments | 0 | |||
Related Party | Iberdrola | ||||
Related Party Transaction [Line Items] | ||||
Deposit balance | $ 0 | $ 0 | ||
Related Party | Iberdrola Financiacion, S.A.U | ||||
Related Party Transaction [Line Items] | ||||
Line of credit facility, maximum borrowing capacity | $ 750,000,000 | $ 500,000,000 | ||
Credit facility fees percentage | 0.225% |
Other Financial Statement Items - Accounts Receivable and Unbilled Revenue (Details) - Nonrelated Party - USD ($) $ in Millions |
Mar. 31, 2024 |
Dec. 31, 2023 |
---|---|---|
Supplemental Balance Sheet Information [Line Items] | ||
Trade receivables and unbilled revenues | $ 1,809 | $ 1,749 |
Allowance for credit losses | (169) | (161) |
Accounts receivable and unbilled revenues, net | $ 1,640 | $ 1,588 |
Other Financial Statement Items - Allowance For Credit Losses (Details) - USD ($) $ in Millions |
3 Months Ended | |
---|---|---|
Mar. 31, 2024 |
Mar. 31, 2023 |
|
Accounts Receivable, Allowance for Credit Loss [Roll Forward] | ||
Beginning balance | $ 169 | $ 148 |
Current period provision | 46 | 17 |
Write-off as uncollectible | (38) | (24) |
Ending balance | $ 161 | $ 155 |
Other Financial Statement Items - Additional Information (Details) - USD ($) $ in Millions |
3 Months Ended | |||||
---|---|---|---|---|---|---|
Mar. 31, 2024 |
Mar. 31, 2023 |
Dec. 31, 2023 |
Jul. 19, 2023 |
Jul. 03, 2023 |
Dec. 31, 2022 |
|
Supplemental Balance Sheet Information [Line Items] | ||||||
Allowance for doubtful accounts, deferred payment arrangement | $ 169 | $ 148 | $ 161 | $ 155 | ||
Provision for doubtful accounts, accounts receivable | 46 | 17 | ||||
Prepaid other taxes | 164 | 142 | ||||
Accrued liabilities for property, plant and equipment additions | 553 | 239 | ||||
Commercial paper | 1,864 | 1,332 | ||||
Advances received | $ 224 | $ 236 | ||||
Commercial Paper | ||||||
Supplemental Balance Sheet Information [Line Items] | ||||||
Weighted-average interest rate | 5.55% | 5.65% | ||||
Intragroup Green Loan | Subordinated Debt | ||||||
Supplemental Balance Sheet Information [Line Items] | ||||||
Face amount of debt | $ 800 | |||||
Fixed interest rate | 5.45% | |||||
Deferred Payment Arrangements | ||||||
Supplemental Balance Sheet Information [Line Items] | ||||||
Accounts receivable | $ 116 | $ 110 | ||||
Allowance for doubtful accounts, deferred payment arrangement | 46 | $ 44 | ||||
Provision for doubtful accounts, accounts receivable | $ 2 | $ (2) |
Other Financial Statement Items - Schedule of Accumulated Depreciation and Amortization (Details) - USD ($) $ in Millions |
Mar. 31, 2024 |
Dec. 31, 2023 |
---|---|---|
Property, plant and equipment | ||
Accumulated depreciation | $ 12,732 | $ 12,479 |
Intangible assets | ||
Accumulated amortization | $ 357 | $ 351 |
Income Tax Expense (Details) |
3 Months Ended | |
---|---|---|
Mar. 31, 2024 |
Mar. 31, 2023 |
|
Income Tax Disclosure [Abstract] | ||
Effective income tax rate | 5.80% | (9.10%) |
Stock-Based Compensation Expense (Details) $ / shares in Units, $ in Millions |
1 Months Ended | 3 Months Ended | 12 Months Ended | |||||||
---|---|---|---|---|---|---|---|---|---|---|
Mar. 31, 2024
USD ($)
shares
|
Feb. 29, 2024
USD ($)
|
Jan. 31, 2024
shares
|
Mar. 31, 2023
installment
shares
|
Feb. 28, 2023
installment
shares
|
Jun. 30, 2022
installment
$ / shares
shares
|
Feb. 28, 2022
installment
shares
|
Mar. 31, 2024
USD ($)
installment
shares
|
Mar. 31, 2023
USD ($)
|
Dec. 31, 2023
USD ($)
shares
|
|
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||||||
Stock-based compensation expense | $ | $ 3.0 | $ 4.0 | ||||||||
Performance Shares Units (PSUs) | ||||||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||||||
Number of shares granted (in shares) | 677,752 | 15,296 | 1,067,500 | |||||||
Number of vesting installments | installment | 3 | 3 | ||||||||
Number of shares issued (in shares) | 126,311 | |||||||||
Restricted Stock Units (RSUs) | Executive Officer | ||||||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||||||
Number of shares granted (in shares) | 25,000 | |||||||||
Number of vesting installments | installment | 2 | |||||||||
Number of shares issued (in shares) | 9,034 | |||||||||
Grant date fair value (in dollars per share) | $ / shares | $ 47.64 | |||||||||
Phantom Shares | ||||||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||||||
Number of shares granted (in shares) | 81,000 | 9,000 | ||||||||
Number of vesting installments | installment | 3 | 4 | ||||||||
Share based compensation liability | $ | $ 1.0 | $ 1.0 | $ 2.0 | |||||||
Phantom Shares | February 2022 Grant | ||||||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||||||
Cash used to settle award | $ | $ 0.1 | |||||||||
Phantom Shares | February 2023 Grant | ||||||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||||||
Cash used to settle award | $ | $ 1.0 |
Variable Interest Entities (Details) - USD ($) $ in Millions |
Mar. 31, 2024 |
Dec. 31, 2023 |
---|---|---|
Variable Interest Entity [Line Items] | ||
Assets of variable interest entities (VIEs) | $ 45,062 | $ 43,989 |
Liabilities of variable interest entities (VIEs) | 24,173 | 23,313 |
Variable Interest Entity, Primary Beneficiary | ||
Variable Interest Entity [Line Items] | ||
Assets of variable interest entities (VIEs) | 2,740 | 2,741 |
Liabilities of variable interest entities (VIEs) | $ 196 | $ 174 |
Equity Method Investments (Details) $ in Millions |
3 Months Ended | 12 Months Ended | ||||
---|---|---|---|---|---|---|
Oct. 24, 2023
USD ($)
|
Mar. 31, 2024
USD ($)
|
Dec. 31, 2022
USD ($)
a
easement
|
Dec. 31, 2023
USD ($)
|
Jan. 10, 2022
USD ($)
|
Sep. 15, 2021
USD ($)
|
|
Schedule of Equity Method Investments [Line Items] | ||||||
Remaining amount expected from tax equity investors in installments | $ 1,100 | |||||
TEF agreement, total indemnified amount | $ 43 | |||||
Equity method investments | $ 836 | 718 | ||||
Vineyard Wind 1, LLC | ||||||
Schedule of Equity Method Investments [Line Items] | ||||||
Equity method investment, ownership percentage | 50.00% | 50.00% | ||||
Remaining amount expected from tax equity investors in installments | $ 1,200 | |||||
TEF agreement, amount received from tax equity investors | $ 85 | |||||
TEF agreement, total indemnified amount | $ 43 | |||||
Vineyard Wind 1, LLC | Renewables | ||||||
Schedule of Equity Method Investments [Line Items] | ||||||
Capital amount contributed | 116 | |||||
Vineyard Wind, LLC | ||||||
Schedule of Equity Method Investments [Line Items] | ||||||
Equity method investment, ownership percentage | 50.00% | |||||
Number of easements | easement | 2 | |||||
Equity method investments | $ 419 | $ 297 | ||||
Vineyard Wind, LLC | Lease Area 501 | ||||||
Schedule of Equity Method Investments [Line Items] | ||||||
Area of land (in acres) | a | 166,886 | |||||
Vineyard Wind, LLC | Lease Area 522 | ||||||
Schedule of Equity Method Investments [Line Items] | ||||||
Area of land (in acres) | a | 132,370 | |||||
Joint Venture With CIP | ||||||
Schedule of Equity Method Investments [Line Items] | ||||||
Amount of guaranty issued | $ 827 | |||||
Amount contributed to acquire easement contract, returned | $ 152 | |||||
Joint Venture With CIP | Letter of Credit | ||||||
Schedule of Equity Method Investments [Line Items] | ||||||
Line of credit facility, maximum borrowing capacity | $ 1,200 | |||||
Joint Venture With CIP | Renewables | ||||||
Schedule of Equity Method Investments [Line Items] | ||||||
Joint venture restructuring agreement, payment amount | $ 168 |
Subsequent Event (Details) - $ / shares |
3 Months Ended | ||
---|---|---|---|
Apr. 11, 2024 |
Mar. 31, 2024 |
Mar. 31, 2023 |
|
Subsequent Event [Line Items] | |||
Dividends declared (in dollars per share) | $ 0.44 | $ 0.44 | |
Subsequent Event | |||
Subsequent Event [Line Items] | |||
Dividends declared (in dollars per share) | $ 0.44 |
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