Avangrid (AGR) 10-K 2 Mar 20 2019 FY Annual report Financial data

Cover Page

Cover Page - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Feb. 28, 2020	Jun. 30, 2019
Cover page.
Document Type	10-K
Document Annual Report	true
Document Period End Date	Dec. 31, 2019
Document Transition Report	false
Entity File Number	001-37660
Entity Registrant Name	Avangrid, Inc.
Entity Incorporation, State or Country Code	NY
Entity Tax Identification Number	14-1798693
Entity Address, Address Line One	180 Marsh Hill Road
Entity Address, City or Town	Orange,
Entity Address, State or Province	CT
Entity Address, Postal Zip Code	06477
City Area Code	207
Local Phone Number	629-1200
Title of 12(b) Security	Common Stock, par value $0.01 per share
Trading Symbol	AGR
Security Exchange Name	NYSE
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Filer Category	Large Accelerated Filer
Entity Small Business	false
Entity Emerging Growth Company	false
Entity Shell Company	false
Entity Public Float			$ 2,836
Entity Common Stock, Shares Outstanding		309,005,272
Amendment Flag	false
Document Fiscal Year Focus	2019
Document Fiscal Period Focus	FY
Entity Central Index Key	0001634997
Current Fiscal Year End Date	--12-31
Documents Incorporated by Reference	Portions of the documents listed below have been incorporated by reference into the indicated parts of this report, as specified in the responses to the item numbers involved. Designated portions of the Proxy Statement relating to the 2020 Annual Meeting of the Shareholders are incorporated by reference into Part III to the extent described therein.

Consolidated Statements of Inco

Consolidated Statements of Income - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Income Statement [Abstract]
Operating revenues	$ 6,338	$ 6,478	$ 5,963
Operating Expenses
Purchased power, natural gas and fuel used	1,509	1,653	1,338
Operations and maintenance	2,301	2,248	2,091
Loss from assets held for sale	0	16	642
Depreciation and amortization	934	855	824
Taxes other than income taxes, net	591	579	563
Total Operating Expenses	5,335	5,351	5,458
Operating Income	1,003	1,127	505
Other Income and (Expense)
Other income (expense)	119	(66)	(62)
Earnings (losses) from equity method investments	3	10	(40)
Interest expense, net of capitalization	(306)	(303)	(280)
Income Before Income Tax	819	768	123
Income tax (benefit) expense	143	170	(259)
Net Income	676	598	382
Net loss (income) attributable to noncontrolling interests	24	(3)	(1)
Net Income Attributable to Avangrid, Inc.	$ 700	$ 595	$ 381
Earnings Per Common Share, Basic (in dollars per share)	$ 2.26	$ 1.92	$ 1.23
Earnings Per Common Share, Diluted (in dollars per share)	$ 2.26	$ 1.92	$ 1.23
Weighted-average Number of Common Shares Outstanding:
Basic (in shares)	309,491,082	309,503,319	309,502,861
Diluted (in shares)	309,514,910	309,712,628	309,661,883

Consolidated Statements of Comp

Consolidated Statements of Comprehensive Income - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Statement of Comprehensive Income [Abstract]
Net Income	$ 676	$ 598	$ 382
Other Comprehensive Income
Gain on defined benefit plans, net of income taxes of $(0.3) and $1.1, respectively	1	3	0
Amortization of pension cost for nonqualified plans, net of income taxes of $(1.0), $0.3 and $0.2, respectively	(1)	1	1
Unrealized (loss) gain during the year on derivatives qualifying as cash flow hedges, net of income taxes of $(8.6), $(6.6) and $15.2, respectively	(22)
Unrealized (loss) gain during the year on derivatives qualifying as cash flow hedges, net of income taxes of $(8.6), $(6.6) and $15.2, respectively		(21)	25
Reclassification to net income of losses (gains) on cash flow hedges, net of income taxes of $2.7, $(6.5) and $9.3, respectively	11
Reclassification to net income of losses (gains) on cash flow hedges, net of income taxes of $2.7, $(6.5) and $9.3, respectively		(8)	14
Other Comprehensive (Loss) Income	(11)	(25)	40
Comprehensive Income	665	573	422
Net loss (income) attributable to noncontrolling interests	24	(3)	(1)
Comprehensive Income Attributable to Avangrid, Inc.	$ 689	$ 570	$ 421

Consolidated Statements of Co_2

Consolidated Statements of Comprehensive Income (Parenthetical) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Statement of Comprehensive Income [Abstract]
Gain on defined benefit plans, income tax expense (benefit)	$ (0.3)	$ 1.1
Gain on defined benefit plans, income tax expense (benefit)	(1)	0.3
Unrealized gain (loss) during period on derivatives qualified as cash flow hedges, income tax (expense) benefit	(8.6)
Unrealized gain (loss) during period on derivatives qualified as cash flow hedges, income tax (expense) benefit		(6.6)
Reclassification to net income of (gains) losses on cash flow hedges, income tax expense	$ 2.7
Reclassification to net income of (gains) losses on cash flow hedges, income tax expense		$ (6.5)

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Current Assets
Cash and cash equivalents	$ 178	$ 36
Accounts receivable and unbilled revenues, net	1,082	1,142
Accounts receivable from affiliates	10	6
Derivative assets	11	16
Fuel and gas in storage	110	109
Materials and supplies	141	126
Prepayments and other current assets	199	229
Regulatory assets	294	299
Total Current Assets	2,025	1,963
Total Property, Plant and Equipment ($787 and $726 related to VIEs, respectively)	25,218	23,459
Operating lease right-of-use assets	70
Equity method investments	645	366
Other investments	63	58
Regulatory assets	2,567	2,640
Deferred income taxes regulatory	0	6
Other Assets
Goodwill	3,119	3,127
Intangible assets	314	323
Derivative assets	84	63
Other	311	162
Total Other Assets	3,828	3,675
Total Assets	34,416	32,167
Current Liabilities
Current portion of debt	730	394
Notes payable	560	587
Interest accrued	72	62
Accounts payable and accrued liabilities	1,361	1,132
Accounts payable to affiliates	64	58
Dividends payable	136	136
Taxes accrued	56	59
Operating lease liabilities	12
Derivative liabilities	20	44
Other current liabilities	334	327
Regulatory liabilities	242	205
Total Current Liabilities	3,587	3,004
Regulatory liabilities	3,281	3,223
Other Non-current Liabilities
Deferred income taxes	1,814	1,530
Deferred income	1,274	1,385
Pension and other postretirement	1,100	1,102
Operating lease liabilities	65
Derivative liabilities	85	97
Asset retirement obligations	190	217
Environmental remediation costs	338	339
Other	380	499
Total Other Non-current Liabilities	5,246	5,169
Non-current debt	6,716	5,368
Total Non-current Liabilities	15,243	13,760
Total Liabilities	18,830	16,764
Commitments and Contingencies	0	0
Stockholders' Equity:
Common stock, $.01 par value, 500,000,000 shares authorized, 309,752,140 shares issued; 309,005,272 shares outstanding	3	3
Additional paid-in capital	13,660	13,657
Treasury Stock	(12)	(12)
Retained earnings	1,681	1,528
Accumulated other comprehensive loss	(95)	(72)
Total Stockholders’ Equity	15,237	15,104
Noncontrolling interests	349	299
Total Equity	15,586	15,403
Total Liabilities and Equity	$ 34,416	$ 32,167

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Property, Plant and Equipment, VIEs	$ 25,218	$ 23,459
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)	309,752,140	309,752,140
Common stock, outstanding (in shares)	309,005,272	309,005,272
Variable Interest Entity, Primary Beneficiary
Property, Plant and Equipment, VIEs	$ 787	$ 726

Consolidated Statements of Cash

Consolidated Statements of Cash Flows - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Cash Flow from Operating Activities
Net Income	$ 676	$ 598	$ 382
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation and amortization	934	855	824
Loss from assets held for sale	0	16	642
Accretion expenses	12	12	10
Regulatory assets/liabilities amortization and carrying cost	64	73	62
Pension cost	91	123	112
Earnings from equity method investments	(3)	(10)	40
Distribution of earnings from equity method investments	12	14	16
Unrealized (gains) losses on marked to market derivative contracts	(76)	22	17
Gain from divestment and disposal of property	(135)	(10)	(2)
Deferred taxes	138	151	(251)
Other non-cash items	(51)	(27)	(73)
Changes in operating assets and liabilities:
Current assets	126	(117)	(89)
Noncurrent assets	(152)	(87)	218
Current liabilities	(5)	98	116
Noncurrent liabilities	(38)	80	(261)
Net Cash Provided by Operating Activities	1,593	1,791	1,763
Cash Flow from Investing Activities
Capital expenditures	(2,740)	(1,787)	(2,416)
Contributions in aid of construction	74	60	57
Proceeds from sale of equity method and other investment	108	186	0
Proceeds from sale of property, plant and equipment	18	18	12
Payments to affiliates	(2)	0	0
Cash distribution from equity method investments	5	4	4
Other investments and equity method investments, net	(176)	(45)	2
Net Cash (used in) provided by Investing Activities	(2,713)	(1,564)	(2,341)
Cash Flow from Financing Activities
Non-current debt issuances	2,137	597	888
Repayments of non-current debt	(346)	(217)	(305)
(Repayments) receipts of other short-term debt, net	(28)	(201)
(Repayments) receipts of other short-term debt, net			625
Repayments of financing leases	(27)	(13)	(33)
Payments on tax equity financing arrangements	0	0	(113)
Repurchase of common stock	0	(4)	(3)
Issuance of common stock	0	(2)	(1)
Distributions to noncontrolling interests	(63)	(76)	0
Contributions from noncontrolling interests	133	223	5
Dividends paid	(545)	(537)	(535)
Net Cash Provided by (Used in) Financing Activities	1,261	(230)	528
Net Increase (Decrease) in Cash, Cash Equivalents and Restricted Cash	141	(3)	(50)
Cash, Cash Equivalents and Restricted Cash, Beginning of Year	43	46	96
Cash, Cash Equivalents and Restricted Cash, End of Year	184	43	46
Supplemental Cash Flow Information
Cash paid for interest, net of amounts capitalized	266	224	202
Cash paid (refunded) for income taxes	$ 2	$ (13)	$ 13

Consolidated Statements of Chan

Consolidated Statements of Changes in Equity - USD ($) $ in Millions		Total	Total Stockholders' Equity	Common Stock		Additional paid-in capital	Treasury Stock	Retained Earnings	Accumulated Other Comprehensive Income (Loss)	Non-controlling Interests
Balance at beginning of period (in shares) at Dec. 31, 2016	[1]			308,993,149
Balance at beginning of period at Dec. 31, 2016		$ 15,208	$ 15,195	$ 3		$ 13,653	$ (5)	$ 1,630	$ (86)	$ 13
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income		382	381					381		1
Other comprehensive income, net of tax		40	40						40
Comprehensive Income		422
Dividends declared		(535)	(535)					(535)
Release of common stock held in trust (in shares)	[1]			5,649
Release of common stock held in trust		0
Issuance of common stock (in shares)	[1]			70,493
Issuance of common stock		(1)	(1)			(1)
Repurchase of common stock (in shares)	[1]			(64,019)
Repurchase of common stock		(3)	(3)				(3)
Stock-based compensation		1	1			1
Transaction with noncontrolling interests		4	(1)					(1)		5
Balance at end of period (in shares) at Dec. 31, 2017	[1]			309,005,272
Balance at end of period at Dec. 31, 2017		15,096	15,077	$ 3		13,653	(8)	1,475	(46)	19
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income		598	595					595		3
Other comprehensive income, net of tax		(25)	(25)						(25)
Comprehensive Income		573
Dividends declared		$ (540)	(540)					(540)
Issuance of common stock (in shares)		81,208		81,208	[1]
Issuance of common stock		$ (2)	(2)			1		(3)
Repurchase of common stock (in shares)	[1]			(81,208)
Repurchase of common stock		(4)	(4)				(4)
Stock-based compensation		3	3			3
Distributions to noncontrolling interests		(76)								(76)
Contributions from noncontrolling interests		$ 217	4					4		213
Balance at end of period (in shares) at Dec. 31, 2018		309,005,272		309,005,272	[1]
Balance at end of period at Dec. 31, 2018		$ 15,403	15,104	$ 3		13,657	(12)	1,528	(72)	299
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income		676	700					700		(24)
Other comprehensive income, net of tax		(11)	(11)						(11)
Comprehensive Income		665
Dividends declared		$ (545)	(545)					(545)
Issuance of common stock (in shares)		0
Repurchase of common stock (in shares)		(115,831)
Stock-based compensation		$ 3	3			3
Distributions to noncontrolling interests		(63)	(4)					(4)		(59)
Contributions from noncontrolling interests		$ 124	(9)					(9)		133
Balance at end of period (in shares) at Dec. 31, 2019		309,005,272		309,005,272	[1]
Balance at end of period at Dec. 31, 2019		$ 15,586	$ 15,237	$ 3		$ 13,660	$ (12)	$ 1,681	$ (95)	$ 349
[1]	Par value of share amounts is $.01

Consolidated Statements of Ch_2

Consolidated Statements of Changes in Equity (Parenthetical) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Statement of Stockholders' Equity [Abstract]
Par value (in dollars per share)	$ 0.01	$ 0.01	$ 0.01
Other comprehensive income (loss), tax	$ (7.2)	$ (11.7)	$ 24.7
Dividends declared (in dollars per share)	$ 1.76	$ 1.744	$ 1.728

Background and Nature of Operat

Background and Nature of Operations	12 Months Ended
	Dec. 31, 2019
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Background and Nature of Operations	Background and Nature of Operations Avangrid, Inc., formerly Iberdrola USA, 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 81.5% of the outstanding common stock of AVANGRID. The remaining outstanding shares are publicly traded on the New York Stock Exchange and owned by various shareholders. AVANGRID was organized in 1997 as NGE Resources, Inc. under the laws of New York as the holding company for its principal operating utility companies. In December 2017, management committed to a plan to sell the gas storage and trading businesses because they represented non-core businesses that were not aligned with our strategic objectives. On March 1, 2018 , the Company closed a transaction to sell Enstor Energy Services, LLC, which operated AVANGRID’s gas trading business, to CCI U.S. Asset Holdings LLC, a subsidiary of Castleton Commodities International, LLC (CCI). On May 1, 2018 , the Company closed a transaction to sell Enstor Gas, LLC (Gas), which operated AVANGRID’s gas storage business, to Amphora Gas Storage USA, LLC.

Basis of Presentation

Basis of Presentation	12 Months Ended
	Dec. 31, 2019
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Basis of Presentation	Basis of PresentationThe accompanying consolidated financial statements have been prepared in accordance with U.S. GAAP and are presented on a consolidated basis, and therefore include the accounts of AVANGRID and its consolidated subsidiaries, Networks and ARHI. All intercompany transactions and accounts have been eliminated in all periods presented.

Summary of Significant Accounti

Summary of Significant Accounting Policies, New Accounting Pronouncements, and Use of Estimates	12 Months Ended
	Dec. 31, 2019
Accounting Policies [Abstract]
Summary of Significant Accounting Policies, New Accounting Pronouncements, and Use of Estimates	Summary of Significant Accounting Policies, New Accounting Pronouncements and Use of Estimates Significant Accounting Policies We consider the following policies to be the most significant in understanding the judgments that are involved in preparing our consolidated financial statements: (a) Principles of consolidation We consolidate the entities in which we have a controlling financial interest, after the elimination of intercompany transactions. We account for investments in common stock where we have the ability to exercise significant influence, but not control, using the equity method of accounting. (b) Revenue recognition We recognize revenues when we transfer control of promised goods or services to our customers in an amount that reflects the consideration we expect to be entitled to in exchange for those goods or services. Refer to Note 4 for further details. (c) Regulatory accounting We account for our regulated utilities' operations in accordance with the authoritative guidance applicable to entities with regulated operations that meet the following criteria: (i) rates are established or approved by a third-party regulator; (ii) rates are designed to recover the entity’s cost of providing regulated services or products and; (iii) there is a reasonable expectation that rates are set at levels that will recover the entity’s costs and be collected from customers. Regulatory assets represent incurred costs that have been deferred because of their probable future recovery from customers through regulated rates. Regulatory liabilities represent: (i) the excess recovery of costs or accrued credits that have been deferred because it is probable such amounts will be returned to customers through future regulated rates; or (ii) billings in advance of expenditures for approved regulatory programs. Regulatory assets and liabilities are amortized and the related expense or revenue is recognized in the consolidated statements of income consistent with the recovery or refund included in customer rates. We believe that it is probable that our currently recorded regulatory assets and liabilities will be recovered or settled in future rates. (d) Business combinations and assets acquisitions We apply the acquisition method of accounting to account for business combinations. The consideration transferred for an acquisition is the fair value of the assets transferred, the liabilities incurred by the acquirer to former owners of the acquiree and the equity interests issued by the acquirer. Acquisition related costs are expensed as incurred. Identifiable assets acquired and liabilities and contingent liabilities assumed in a business combination are measured initially at their fair values at the acquisition date. The excess of the consideration transferred over the fair value of the identifiable net assets acquired is recorded as goodwill. We recognize adjustments to provisional amounts relating to a business combination that are identified during the measurement period in the reporting period in which the adjustment amounts are determined. In contrast to a business combination, we classify a transaction as an asset acquisition when substantially all of the fair value of the gross assets acquired is concentrated in a single identifiable asset or group of similar identifiable assets or otherwise does not meet the definition of a business. (e) Noncontrolling interests Noncontrolling interests represent the portion of our net income (loss), comprehensive income (loss) and net assets that is not allocable to us and is calculated based on our ownership percentage. For holdings where the economic allocations are not based pro rata on ownership percentages, we use the balance sheet-oriented hypothetical liquidation at book value (HLBV) method, to reflect the substantive profit sharing arrangement. Under the HLBV method, the amounts reported as "Noncontrolling interests" and "Net income (loss) attributable to noncontrolling interests" in our consolidated balance sheets and consolidated statements of income represent the amounts the noncontrolling interest would hypothetically receive at each balance sheet reporting date under the liquidation provisions of each holding’s ownership agreement assuming the net assets of the projects were liquidated at recorded amounts determined in accordance with U.S. GAAP and distributed to the investors. The noncontrolling interest in our statements of income and comprehensive income is determined as the difference in noncontrolling interests on our consolidated balance sheets at the start, or at inception of the noncontrolling interest if applicable, and end of each reporting period, after taking into account any capital transactions between the holdings and the third party. The noncontrolling interest balances in the holdings are reported as a component of equity on our consolidated balance sheets. (f) Equity method investments We account for joint ventures that do not meet consolidation criteria using the equity method. We reflect earnings (losses) recognized under the equity method in the consolidated statements of income as "Earnings (losses) from equity method investments." We recognize dividends received from joint ventures as a reduction in the carrying amount of the investment and not as dividend income. We assess and record an impairment of our equity method investments in earnings for a decline in value that is determined to be other than temporary (OTTI). (g) Goodwill and other intangible assets Goodwill represents future economic benefits arising from other assets acquired in a business combination that are not individually identified and separately recognized. Goodwill is initially measured at cost, being the excess of the aggregate of the consideration transferred, the fair value of any noncontrolling interest and the acquisition date fair value of any previously held equity interest in the acquiree over the fair value of the net identifiable assets acquired and liabilities assumed. Goodwill is not amortized, but is subject to an assessment for impairment performed in the fourth quarter or more frequently if events occur or circumstances change that would more likely than not reduce the fair value of a reporting unit below its carrying amount. A reporting unit is an operating segment or one level below an operating segment and is the level at which we test goodwill for impairment. In assessing goodwill for impairment, we have the option of first performing a qualitative assessment to determine whether a quantitative assessment is necessary (step zero). If we determine, on the basis of qualitative factors, that the fair value of the reporting unit is more likely than not greater than the carrying amount, no further testing is required. If we bypass step zero or perform the qualitative assessment, but determine that it is more likely than not that its fair value is less than its carrying amount, we perform a quantitative two step fair value based test. Step one compares the fair value of the reporting unit to its carrying amount, including goodwill. If the carrying amount of the reporting unit exceeds its fair value, step two is performed. Step two requires an allocation of fair value to the individual assets and liabilities using business combination accounting guidance to determine the implied fair value of goodwill. If the implied fair value of goodwill is less than its carrying amount, we record an impairment loss as a reduction to goodwill and a charge to operating expenses. Intangible assets acquired separately are measured on initial recognition at cost. The cost of intangible assets acquired in a business combination is their fair value at the date of acquisition. Following initial recognition, intangible assets are carried at cost less any accumulated amortization and impairment losses. The useful lives of intangible assets are assessed as either finite or indefinite. Intangible assets with finite lives are amortized on a straight-line basis over the useful economic life, which ranges from four to forty years , and assessed for impairment whenever there is an indication that the intangible asset may be impaired. The amortization expense on intangible assets with finite lives is recognized in our consolidated statements of income within the expense category that is consistent with the function of the intangible assets. (h) Property, plant and equipment Property, plant and equipment are accounted for at historical cost. In cases where we are required to dismantle installations or to recondition the site on which they are located, we record the estimated cost of removal or reconditioning as an asset retirement obligation (ARO) and an equal amount is added to the carrying amount of the asset. Development and construction of our various facilities are carried out in stages. Project costs are expensed during early stage development activities. Once certain development milestones are achieved and it is probable that we can obtain future economic benefits from a project, we capitalize salaries and wages for persons directly involved in the project, and engineering, permits, licenses, wind measurement and insurance costs. Development projects in construction are reviewed periodically for any indications of impairment. Assets are transferred from “Construction work in progress” to “Property, plant and equipment” when they are available for service. Wind turbine and related equipment costs, other project construction costs and interest costs related to the project are capitalized during the construction period through substantial completion. AROs are recorded at the date projects achieve commercial operation. The cost of plant and equipment in use is depreciated on a straight-line basis, less any estimated residual value. The main asset categories are depreciated over the following estimated useful lives: Major class Asset Category Estimated Useful Life (years) Combined cycle plants 35-75 Hydroelectric power stations 45-90 Plant Wind power stations 25-40 Transport facilities 40-75 Distribution facilities 5-82 Equipment Conventional meters and measuring devices 7-41 Computer software 4-25 Other Buildings 30-82 Operations offices 5-75 Networks determines depreciation expense using the straight-line method, based on the average service lives of groups of depreciable property, which include estimated cost of removal, in service at each operating company. Consistent with FERC accounting requirements, Networks charges the original cost of utility plant retired or otherwise disposed to accumulated depreciation. The Networks composite rates for depreciation were 2.9% of average depreciable property for 2019 and 2.8% for 2018 . We charge repairs and minor replacements to operating expenses, and capitalize renewals and betterments, including certain indirect costs. Allowance for funds used during construction (AFUDC), applicable to Networks' entities applying regulatory accounting, is a noncash item that represents the allowed cost of capital, including a return on equity (ROE), used to finance construction projects. The portion of AFUDC attributable to borrowed funds is recorded as a reduction of interest expense and the remainder is recorded as other income. (i) Leases We determine if an arrangement is a lease at inception. We classify a lease as a finance lease if it meets any one of specified criteria that in essence transfers ownership of the underlying asset to us by the end of the lease term. If a lease does not meet any of those criteria, we classify it as an operating lease. On our consolidated balance sheets, we include, for operating leases: "Operating lease right-of-use (ROU) assets" and "Operating lease liabilities (current and non-current)"; and for finance leases: finance lease ROU assets in "Other assets" and liabilities in "Other current liabilities" and "Other liabilities." ROU assets represent our right to use an underlying asset for the lease term and lease liabilities represent our obligation to make lease payments arising from the lease. We recognize lease ROU assets and liabilities at commencement of an arrangement based on the present value of lease payments over the lease term. Most of our leases do not provide an implicit rate, so we use our incremental borrowing rate based on information available at the lease commencement date to determine the present value of future payments. A lease ROU asset also includes any lease payments made at or before commencement date, minus any lease incentives received, and includes initial direct costs incurred. We do not record leases with an initial term of 12 months or less on the balance sheet for all classes of underlying assets, and we recognize lease expense for those leases on a straight-line basis over the lease term. We include variable lease payments that depend on an index or a rate in the ROU asset and lease liability measurement based on the index or rate at the commencement date, or upon a modification. We do not include variable lease payments that do not depend on an index or a rate in the ROU asset and lease liability measurement. A lease term includes options to extend or terminate the lease when it is reasonably certain that we will exercise that option. We recognize lease (rent) expense for operating lease payments on a straight-line basis over the lease term, or for our regulated companies we recognize the amount eligible for recovery under their rate plans, such as actual amounts paid. We amortize finance lease ROU assets on a straight-line basis over the lease term and recognize interest expense based on the outstanding lease liability. We have lease agreements with lease and non-lease components, and account for lease components and associated non-lease components together as a single lease component, for all classes of underlying assets. (j) Impairment of long-lived assets We evaluate property, plant and equipment and other long-lived assets for impairment when events or changes in circumstances indicate that the carrying amount may not be recoverable. An impairment evaluation is based on undiscounted cash flow analysis at the lowest level to which cash flows of the long-lived assets or asset groups are largely independent of the cash flows of other assets and liabilities. An impairment loss is required to be recognized if the carrying amount of the asset exceeds the undiscounted future net cash flows associated with that asset. The impairment loss to be recognized is the amount by which the carrying amount of the long-lived asset exceeds the asset’s fair value. Depending on the asset, fair value may be determined by use of a discounted cash flow model (DCF), with assumptions consistent with a market participant’s view of the exit price of the asset. (k) Fair value measurement Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants as of the measurement date. The fair value measurement is based on the presumption that the transaction to sell the asset or transfer the liability takes place in either the principal market for the asset or liability, or, in the absence of a principal market, in the most advantageous market for the asset or liability. The fair value of an asset or a liability is measured using the assumptions that market participants would use when pricing the asset or liability, assuming that market participants act in their economic best interest. A fair value measurement of a non-financial asset takes into account a market participant’s ability to generate economic benefits by using the asset according to its highest and best use, or by selling it to another market participant that would use the asset according to its highest and best use. We use valuation techniques that are appropriate in the circumstances and for which sufficient data is available to measure fair value, maximizing the use of relevant observable inputs and minimizing the use of unobservable inputs. All assets and liabilities for which fair value is measured or disclosed in the consolidated financial statements are categorized within the fair value hierarchy based on the transparency of input to the valuation of an asset or liability as of the measurement date. The three input levels of the fair value hierarchy are as follows: • Level 1 - inputs to the valuation methodology are quoted prices (unadjusted) for identical assets or liabilities in active markets. • Level 2 - inputs to the valuation methodology include quoted prices for similar assets and liabilities in active markets, and inputs that are observable for the asset or liability either directly or indirectly, for substantially the full term of the contract. • Level 3 - one or more inputs to the valuation methodology are unobservable or cannot be corroborated with market data. Categorization within the fair value hierarchy is based on the lowest level of input that is significant to the fair value measurement. Certain investments are not categorized within the fair value hierarchy. These investments are measured based on the fair value of the underlying investments but may not be readily redeemable at that fair valu e. (l) Equity investments with readily determinable fair values We measure equity investments with readily determinable fair values at fair value, with changes in fair value reported in net income. (m) Derivatives and hedge accounting Derivatives are recognized on our consolidated balance sheets at their fair value, except for certain electricity commodity purchases and sales contracts for both capacity and energy (physical contracts) that qualify for, and are elected under, the normal purchases and normal sales exception. To be a derivative under the accounting standards for derivatives and hedging, an agreement would need to have a notional and an underlying, require little or no initial net investment and could be net settled. We recognize changes in the fair value of a derivative contract in earnings unless specific hedge accounting criteria are met. Derivatives that qualify and are designated for hedge accounting are classified as cash flow hedges. We report the gain or loss on the derivative instrument as a component of Other Comprehensive Income (OCI) and later reclassify amounts into earnings when the underlying transaction occurs, which we present in the same income statement line item as the earnings effect of the hedged item. For all designated and qualifying hedges, we maintain formal documentation of the hedge and effectiveness testing in accordance with the accounting standards for derivatives and hedging. If we determine that the derivative is no longer highly effective as a hedge, we will discontinue hedge accounting prospectively. For cash flow hedges of forecasted transactions, we estimate the future cash flows of the forecasted transactions and evaluate the probability of the occurrence and timing of such transactions. If we determine it is probable that the forecasted transaction will not occur, we immediately recognize in earnings hedge gains and losses previously recorded in OCI. Changes in conditions or the occurrence of unforeseen events could require discontinuance of the hedge accounting or could affect the timing of the reclassification of gains or losses on cash flow hedges from OCI into earnings. For our regulated operations, we record changes in the fair value of electric and natural gas hedge contracts derivative assets or liabilities with an offset to regulatory assets or regulatory liabilities. We offset fair value amounts recognized for derivative instruments and fair value amounts recognized for the right to reclaim cash collateral or the obligation to return cash collateral arising from derivative instruments executed with the same counterparty under a master netting arrangement. (n) Cash and cash equivalents Cash and cash equivalents include cash, bank accounts, and other highly-liquid short-term investments. We consider all highly liquid investments with a maturity date of three months or less when acquired to be cash equivalents and include those investments in “Cash and cash equivalents.” Restricted cash represents cash legally set aside for a specified purpose or as part of an agreement with a third party. Restricted cash is included in “Other non-current assets” on our consolidated balance sheets. Book overdrafts representing outstanding checks in excess of funds on deposit are classified as “Accounts payable and accrued liabilities” on our consolidated balance sheets. Changes in book overdrafts are reported in the operating activities section of our consolidated statements of cash flows. (o) Accounts receivable and unbilled revenue, net We record accounts receivable at amounts billed to customers. Certain accounts receivable and payable related to our wholesale activities associated with generation and delivery of electric energy and associated environmental attributes, origination and marketing, natural gas storage, hub services, and energy management, are subject to master netting agreements with counterparties, whereby we have the legal right to offset the balances and are settled on a net basis. Receivables and payables subject to such agreements are presented on our consolidated balance sheets on a net basis. Accounts receivable include amounts due under Deferred Payment Arrangements (DPA). A DPA allows the account balance to be paid in installments over an extended period of time without interest, which generally exceeds one year, by negotiating mutually acceptable payment terms. The utility companies generally must continue to serve a customer who cannot pay an account balance in full if the customer (i) pays a reasonable portion of the balance; (ii) agrees to pay the balance in installments; and (iii) agrees to pay future bills within thirty days until the DPA is paid in full. Failure to make payments on a DPA results in the full amount of a receivable under a DPA being due. These accounts are part of the regular operating cycle and are classified as short term. The allowance for doubtful accounts is established by using both historical average loss percentages to project future losses, and a specific allowance is established for known credit issues or for specific items not considered in the historical average calculation. Amounts are written off when we believe that a receivable will not be recovered. (p) Variable interest entities An entity is considered to be a variable interest entity (VIE) when its total equity investment at risk is not sufficient to permit the entity to finance its activities without additional subordinated financial support, or its equity investors, as a group, lack the characteristics of having a controlling financial interest. A reporting company is required to consolidate a VIE as its primary beneficiary when it has both the power to direct the activities of the VIE that most significantly impact the VIE's economic performance, and the obligation to absorb losses or the right to receive benefits from the VIE that could potentially be significant to the VIE. We evaluate whether an entity is a VIE whenever reconsideration events as defined by the accounting guidance occur (See Note 20). We have undertaken several structured institutional partnership investment transactions that bring in external investors in certain of our wind farms in exchange for cash. Following an analysis of the economic substance of these transactions, we classify the consideration received at the inception of the arrangement as noncontrolling interests on our consolidated balance sheets. Subsequently, the HLBV method allocates earnings to the noncontrolling interest, which considers the cash and tax benefits provided to the tax equity investors. (q) Debentures, bonds and bank borrowings Bonds, debentures and bank borrowings are recorded as a liability equal to the proceeds of the borrowings. The difference between the proceeds and the face amount of the issued liability is treated as discount or premium and is accreted as interest expense or income over the life of the instrument. Incremental costs associated with issuance of the debt instruments are deferred and amortized over the same period as debt discount or premium. Bonds, debentures and bank borrowings are presented net of unamortized discount, premium and debt issuance costs on our consolidated balance sheets. (r) Inventory Inventory comprises fuel and gas in storage and materials and supplies. This gas is recorded as inventory. Injections of inventory into storage are priced at the market purchase cost at the time of injection, and withdrawals of working gas from storage are priced at the weighted-average cost in storage. We continuously monitor the weighted-average cost of gas value to ensure it remains at the lower of cost and net realizable value. Inventories to support gas operations are reported on our consolidated balance sheets within “Fuel and gas in storage.” We also have materials and supplies inventories that are used for construction of new facilities and repairs of existing facilities. These inventories are carried and withdrawn at the lower of cost and net realizable value and reported on our consolidated balance sheets within “Materials and supplies.” (s) Government grants Our unregulated subsidiaries record government grants related to depreciable assets within deferred income and subsequently amortize them to earnings as an offset to depreciation and amortization expense over the useful life of the related asset. Our regulated subsidiaries record government grants as a reduction to utility plant to be recovered through rate base, in accordance with the prescribed FERC accounting. In accounting for government grants related to operating and maintenance costs, amounts receivable are recognized as an offset to expenses in our consolidated statements of income in the period in which the expenses are incurred. (t ) Deferred income Apart from government grants, we occasionally receive revenues from transactions in advance of the resulting performance obligations arising from the transaction. It is our policy to defer such revenues on our consolidated balance sheets and amortize them into earnings when revenue recognition criteria are met. (u) Asset retirement obligations We record the fair value of the liability for an ARO and a conditional ARO in the period in which it is incurred, capitalizing the cost by increasing the carrying amount of the related long-lived asset. The ARO is associated with our long-lived assets and primarily consists of obligations related to removal or retirement of asbestos, polychlorinated biphenyl-contaminated equipment, gas pipeline, cast iron gas mains and electricity generation facilities. The liability is adjusted periodically to reflect revisions to either the timing or amount of the original estimated undiscounted cash flows over time. The liability is accreted to its present value each period and the capitalized cost is depreciated over the useful life of the related asset. Upon settlement, we will either settle the obligation at its recorded amount or incur a gain or a loss. Our regulated utilities defer any timing differences between rate recovery and depreciation expense and accretion as either a regulatory asset or a regulatory liability. The term conditional ARO refers to an entity’s legal obligation to perform an asset retirement activity in which the timing or method of settlement are conditional on a future event that may or may not be within the entity’s control. If an entity has sufficient information to reasonably estimate the fair value of the liability for a conditional ARO, it must recognize that liability at the time the liability is incurred. Our regulated utilities meet the requirements concerning accounting for regulated operations and we recognize a regulatory liability for the difference between removal costs collected in rates and actual costs incurred. These are classified as accrued removal obligations. (v) Environmental remediation liability In recording our liabilities for environmental remediation costs the amount of liability for a site is the best estimate, when determinable; otherwise it is based on the minimum liability or the lower end of the range when there is a range of estimated losses. Our environmental liabilities are recorded on an undiscounted basis. Our environmental liability accruals are expected to be paid through the year 2057 . (w) Post-employment and other employee benefits We sponsor defined benefit pension plans that cover the majority of our employees. We also provide health care and life insurance benefits through various postretirement plans for eligible retirees. We evaluate our actuarial assumptions on an annual basis and consider changes based on market conditions and other factors. All of our qualified defined benefit plans are funded in amounts calculated by independent actuaries, based on actuarial assumptions proposed by management. We account for defined benefit pension or other postretirement plans, recognizing an asset or liability for the overfunded or underfunded plan status. For a pension plan, the asset or liability is the difference between the fair value of the plan’s assets and the projected benefit obligation. For any other postretirement benefit plan, the asset or liability is the difference between the fair value of the plan’s assets and the accumulated postretirement benefit obligation. Our utility operations reflect all unrecognized prior service costs and credits and unrecognized actuarial gains and losses as regulatory assets rather than in other comprehensive income, as management believes it is probable that such items will be recoverable through the ratemaking process. We use a December 31st measurement date for our benefits plans. We amortize prior service costs for both the pension and other postretirement benefits plans on a straight-line basis over the average remaining service period of participants expected to receive benefits. Unrecognized actuarial gains and losses related to the pension and other postretirement benefits plans are amortized over the average remaining service period or 10 years , considering any requirement by the regulators for our Networks subsidiaries. Our policy is to calculate the expected return on plan assets using the market related value of assets. That value is determined by recognizing the difference between actual returns and expected returns over a five-year period. (x) Income taxes We use the asset and liability method of accounting for income taxes. Deferred tax assets and liabilities reflect the expected future tax consequences, based on enacted tax laws, of temporary differences between the tax basis of assets and liabilities and their financial reporting amounts. In accordance with U.S. GAAP for regulated industries, certain of our regulated subsidiaries have established a regulatory asset for the net revenue requirements to be recovered from customers for the related future tax expense associated with certain of these temporary differences. We defer the investment tax credits when earned and amortize them over the estimated lives of the related assets. We also recognize the income tax consequences of intra-entity transfers of assets other than inventory when the transfer occurs. Deferred tax assets and liabilities are measured at the expected tax rate for the period in which the asset or liability will be realized or settled, based on legislation enacted as of the balance sheet date. Changes in deferred income tax assets and liabilities that are associated with components of OCI are charged or credited directly to OCI. Significant judgment is required in determining income tax provisions and evaluating tax positions. Our tax positions are evaluated under a more-likely-than-not recognition threshold before they are recognized for financial reporting purposes. We record valuation allowances to reduce deferred tax assets when it is more likely than not that we will not realize all or a portion of a tax benefit. Deferred tax assets and liabilities are netted and classified as non-current on our consolidated balance sheets. We record the excess of state franchise tax computed as the higher of a tax based on income or a tax based on capital in “Taxes other than income taxes” and “Taxes accrued” in our consolidated financial statements. Positions taken or expected to be taken on tax returns, including the decision to exclude certain income or transactions from a return, are recognized in the financial statements when it is

Revenue

Revenue	12 Months Ended
	Dec. 31, 2019
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 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 reportable segments, refer to Note 24. 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. 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 Federal Energy Regulatory Commission (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 transmission service. We record revenue for all of those 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. Networks does not have any material significant payment terms because it receives payment at or shortly after the point of sale. For its New York utilities, Networks assesses its deferred payment arrangements 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, 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 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 material initial incremental costs of obtaining a contract or significant financing elements in any of the arrangements. 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, derives its revenues primarily from providing natural gas storage services to customers, gas trading operations generally classified as derivative revenue in accordance with the applicable accounting standards, gas trading contracts not classified as derivatives, and other miscellaneous revenues including intersegment eliminations. Contract Costs, Contract Liabilities and Practical Expedient 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. We have contract assets for costs from development success fees, which we paid during the solar asset development period in 2018, and will amortize ratably into expense over the 15 -year life of the power purchase agreement (PPA), expected to commence in December 2021 upon commercial operation. We also have a contract asset for costs incurred to cancel a PPA, which we will amortize over the 10 -year contract period of the replacement PPA that will commence upon completion of the project. Contract assets totaled $12 million and $9 million at December 31, 2019 and December 31, 2018 , respectively, and are presented in "Other non-current assets" on our 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 $10 million and $9 million at December 31, 2019 and December 31, 2018 , respectively, and are presented in "Other current liabilities" on our consolidated balance sheets. We recognized $21 million and $13 million as revenue during the years ended December 31, 2019 and December 31, 2018 , 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 years ended December 31, 2019 and December 31, 2018 are as follows: Year Ended December 31, 2019 Networks Renewables Other (b) Total (Millions) Regulated operations – electricity $ 3,485 $ — $ — $ 3,485 Regulated operations – natural gas 1,479 — — 1,479 Nonregulated operations – wind — 805 — 805 Nonregulated operations – solar — 26 — 26 Nonregulated operations – thermal — 29 — 29 Nonregulated operations – gas storage — — — — Other(a) 91 62 (12 ) 141 Revenue from contracts with customers 5,055 922 (12 ) 5,965 Leasing revenue 6 — — 6 Derivative revenue — 244 — 244 Alternative revenue programs 75 — — 75 Other revenue 28 20 — 48 Total operating revenues $ 5,164 $ 1,186 $ (12 ) $ 6,338 Year Ended December 31, 2018 Networks Renewables Other (b) Total (Millions) Regulated operations – electricity $ 3,641 $ — $ — $ 3,641 Regulated operations – natural gas 1,473 — — 1,473 Nonregulated operations – wind — 637 — 637 Nonregulated operations – solar — 17 — 17 Nonregulated operations – thermal — 47 — 47 Nonregulated operations – gas storage — — 10 10 Other(a) 58 (68 ) 9 (1 ) Revenue from contracts with customers 5,172 633 19 5,824 Leasing revenue 38 346 — 384 Derivative revenue — 124 10 134 Alternative revenue programs 80 — — 80 Other revenue 20 36 — 56 Total operating revenues $ 5,310 $ 1,139 $ 29 $ 6,478 (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, Gas and intersegment eliminations. As of December 31, 2019 and December 31, 2018 , accounts receivable balances related to contracts with customers were approximately $1,050 million and $1,118 million , respectively, including $345 million and $374 million of unbilled revenue, which are included in “Accounts receivable and unbilled revenues, net” on our consolidated balance sheets. As of December 31, 2019 , the aggregate amount of the transaction price allocated to performance obligations that are unsatisfied (or partially unsatisfied) were as follows: As of December 31, 2019 2020 2021 2022 2023 2024 Thereafter Total (Millions) Revenue expected to be recognized on multiyear retail energy sales contracts in place $ 1 $ 1 $ 1 $ 1 $ 1 $ — $ 5 Revenue expected to be recognized on multiyear capacity and carbon-free energy sale contracts 35 27 19 11 8 25 126 Revenue expected to be recognized on multiyear renewable energy credit sale contracts 22 16 8 5 4 8 63 Total operating revenues $ 58 $ 44 $ 28 $ 17 $ 13 $ 33 $ 194 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).

Industry Regulation

Industry Regulation	12 Months Ended
	Dec. 31, 2019
Regulated Operations [Abstract]
Industry Regulation	Industry Regulation Electricity and Natural Gas Distribution – Maine, New York, Connecticut and Massachusetts The NYSEG and RG&E rate cases, the Maine distribution rate case and associated proceedings, the Federal Energy Regulatory Commission (FERC) Transmission Return on Equity (ROE) case, the Connecticut rate plans, Reforming Energy Vision (REV), the storm proceedings in New York and the Tax Act are some of the most important specific regulatory processes that currently affect Networks. The revenues of Networks companies are essentially regulated, being based on tariffs established in accordance with administrative procedures set by the various regulatory bodies. The tariffs applied to the Networks companies are approved by the regulatory commissions of the different states and are based on the cost of providing service. The revenues of each of the Networks companies are set to be sufficient to cover its operating costs, including energy costs, finance costs and the costs of equity, the last of which reflects our capital ratio and a reasonable ROE. Energy costs that are incurred in the New York and New England wholesale markets are passed on to consumers. The difference between energy costs that are budgeted and those that are actually incurred by the utilities is offset by applying compensation procedures that result in either immediate or deferred tariff adjustments. These procedures apply to other costs, which are in most cases exceptional, such as the effects of extreme weather conditions, environmental factors, regulatory and accounting changes, and treatment of vulnerable customers, that are offset in the tariff process. Any New York and Connecticut revenues that allow a utility to exceed target returns, usually the result of better than expected cost efficiency, are generally shared between the utility and its customers, resulting in future tariff reductions. Each of Networks’ eight utility companies must comply with regulatory procedures that differ in form but in all cases conform to the basic framework outlined above. Generally, tariff reviews cover various years and provide for a reasonable ROE, protection from, and automatic adjustments for, exceptional costs incurred and efficiency incentives. The distribution rates and allowed ROEs for Networks’ regulated utilities in New York are subject to regulation by the New York Public Service Commission (NYPSC), in Maine by the Maine Public Utilities Commission (MPUC), in Connecticut by the Connecticut Public Utilities Regulatory Authority (PURA) and in Massachusetts by the Department of Public Utilities (DPU). CMP Distribution Rate Case On May 1, 2013, CMP submitted its required distribution rate request with the MPUC. On July 3, 2014, after a fourteen -month review process, CMP filed a rate stipulation agreement on the majority of the financial matters with the MPUC. The stipulation agreement was approved by the MPUC on August 25, 2014. The stipulation agreement also noted that certain rate design matters would be litigated, which the MPUC ruled on October 14, 2014. The rate stipulation agreement provided for an annual CMP distribution tariff increase of 10.7% or $24.3 million . The rate increase was based on a 9.45% ROE and 50% equity capital. CMP was authorized to implement a Rate Decoupling Mechanism (RDM) which reduces distribution revenue variations associated with energy efficiency and weather impacts on sales volumes. CMP also adjusted its storm costs recovery mechanism whereby it is allowed to collect in rates a storm allowance and to defer actual storm costs when such storm event costs exceed $3.5 million . CMP and customers share storm costs that exceed a certain balance on a fifty -fifty basis, with CMP’s exposure limited to $3 million annually. CMP made a separate regulatory filing for a new customer billing system. In accordance with the stipulation agreement, a new billing system was needed and CMP made its filing on February 27, 2015 to request a separate rate recovery mechanism. On October 20, 2015, the MPUC issued an order approving a stipulation agreement authorizing CMP to proceed with the customer billing system investment. The approved stipulation allows CMP to recover the system costs effective July 1, 2017. The rate stipulation does not have a predetermined rate term. CMP had the option to file for new distribution rates at its own discretion. The rate stipulation does not contain service quality targets or penalties. The rate stipulation also does not contain any earnings sharing requirements. On May 29, 2018, a ten-person complaint was filed with the MPUC against CMP, Networks and AVANGRID. The complaint requested that the MPUC open a rate case to determine if CMP is making excessive returns on investment and, therefore, whether CMP’s retail rates should be lower. The complaint also requested the MPUC deny certain costs associated with the October 2017 windstorm. On July 24, 2018, the MPUC issued an order dismissing the complaint and its associated request to deny the recovery of costs associated with the October 2017 windstorm. The order initiated an investigation into CMP’s rates and revenue requirement and directed CMP to make a filing consistent with the requirements for a general rate case no later than October 15, 2018. Consistent with the order in the ten-person complaint proceeding, on August 7, 2018, the MPUC issued a Notice of Investigation, opening the proceeding in which CMP would make its rate case filing and through which the MPUC will examine the rates and revenue requirements of CMP. On October 15, 2018, CMP filed a general rate case as directed by the MPUC requesting a ROE of 10% and an equity ratio of 55% . The company proposed to use savings arising out of changes in federal taxation pursuant to the Tax Act to keep its distribution prices stable while making its electric system more reliable. CMP’s general rate case filing included a proposal to enhance the resiliency of the energy grid by expanding vegetation management and pursuing additional reliability measures such as pole replacements and addition of tree wire in selected areas. Such investments are designed to strengthen CMP’s power grid so it can better stand up to severe weather. On December 20, 2018, the MPUC released the findings of the forensic audit of CMP’s customer billing system and customer communication practices. On January 14, 2019, the MPUC issued an Order and Notice of Investigation initiating an investigation of CMP’s metering and billing practices and initiating a separate investigation of the audit of CMP’s customer service and communication practices and incorporating such investigation into the general rate case. On February 22, 2019, the MPUC staff issued a Bench Analysis (BA) on all revenue requirement issues in this case, including customer service issues. The BA included, among other things, a proposal to reduce CMP’s existing distribution rates by $2.0 - $3.6 million , inclusive of one-time items from July 2018, and implement a management efficiency adjustment as part of the rate setting process to reduce the MPUC staff recommended "unadjusted ROE of 9.35% by 75 to 100 basis points. On April 12, 2019, CMP filed rebuttal testimony to the Bench Analysis and intervenor testimony. On June 17, 2019, the MPUC Staff issued its Reply Bench Analysis in response to CMP’s rebuttal testimony, which included a reduction of the "unadjusted" ROE recommendation to 8.75% based on current market conditions, maintained the proposed management efficiency adjustment of 75 to 100 basis points and proposed to maintain the current cap of $31.4 million on the shared service costs provided to CMP until a management audit on the cost effectiveness of such services is completed. The Maine Office of the Public Advocate (OPA) for utility issues filed a motion to delay CMP's rate order decision to allow incorporation of the results of the separate metering and billing investigation. CMP did not oppose this motion. In August 2019, the MPUC granted the OPA motion stating the outcome of the metering and billing investigation could aid the Commission in its final determination in the rate case. Regarding the other two tracks of the rate case (1) rate design and (2) the affiliate services market study; the MPUC decided those tracks can proceed and decisions on those issues can occur at the same time the Commission decides the revenue requirement issues. Finally, the MPUC decided not to address CMP’s request to defer lost revenues with carrying costs or its request that the proposed service quality metrics and other tracking mechanisms be effective October 1, 2019. The MPUC decided to address those matters in its ultimate decision in the rate case. In an order issued on February 19, 2020, the MPUC authorized an increase in CMP's distribution revenue requirement of $17 million , or approximately 7% , based on an allowed ROE of 9.25% and a 50% equity ratio. The rate increase is effective March 1, 2020. The MPUC also imposed a 1.00% ROE reduction (to 8.25% ) for management efficiency associated with CMP’s customer service performance following the implementation of its new billing system in 2017. The management efficiency adjustment will remain in effect until CMP Company has demonstrated satisfactory customer service performance on four specified service quality measures for a period of 18 consecutive months with measurement commencing on March 1, 2020. The order provides additional funding for staffing increases, vegetation management programs and storm restoration costs, while retaining the basic tiered structure for storm cost recovery implemented in the 2014 stipulation. The MPUC order also retains the revenue decoupling mechanism implemented in 2014. The order denies CMP’s request to increase rates for higher costs associated with services provided by its affiliates and will instead initiate a management audit to assess the quality of these services as well as the impacts of the AVANGRID management structure on the quality of CMP’s customer service. NYSEG and RG&E Rate Plans and Rate Case Filings On June 15, 2016, the NYPSC approved NYSEG's and RG&E's Joint Proposal for a three-year rate plan for electric and gas service which balanced the varied interests of the signatory parties including but not limited to maintaining the companies’ credit quality and mitigating the rate impacts to customers. The Joint Proposal reflects many customer benefits including: acceleration of the companies’ natural gas leak prone main replacement programs and increased funding for electric vegetation management to provide continued safe and reliable service. The delivery rate increases in the Joint Proposal can be summarized as follows: May 1, 2016 May 1, 2017 May 1, 2018 Rate Increase Delivery Rate Increase Rate Increase Delivery Rate Increase Rate Increase Delivery Rate Increase Utility (Millions) % (Millions) % (Millions) % NYSEG Electric $ 29.6 4.10 % $ 29.9 4.10 % $ 30.3 4.10 % NYSEG Gas $ 13.1 7.30 % $ 13.9 7.30 % $ 14.8 7.30 % RG&E Electric $ 3.0 0.70 % $ 21.6 5.00 % $ 25.9 5.70 % RG&E Gas $ 8.8 5.20 % $ 7.7 4.40 % $ 9.5 5.20 % The allowed rate of return on common equity for NYSEG Electric, NYSEG Gas, RG&E Electric and RG&E Gas is 9.00% . The equity ratio for each company is 48% ; however, the equity ratio is set at the actual up to 50% for earnings sharing calculation purposes. The customer share of any earnings above allowed levels increases as the ROE increases, with customers receiving 50% , 75% and 90% of earnings over 9.5% , 10.0% and 10.5% ROE, respectively, in the first rate year covering the period May 1, 2016 – April 30, 2017. The earnings sharing levels increase in rate year two (May 1, 2017 – April 30, 2018) to 9.65% , 10.15% and 10.65% ROE, respectively. The earnings sharing levels further increase in rate year three (May 1, 2018 – April 30, 2019) to 9.75% , 10.25% and 10.75% ROE, respectively. The rate plans also include the implementation of a rate adjustment mechanism (RAM) designed to return or collect certain defined reconciled revenues and costs, new depreciation rates and continuation of the existing RDM for each business. The Joint Proposal reflects the recovery of deferred NYSEG Electric storm costs of approximately $262 million , of which $123 million is being amortized over ten years and the remaining $139 million is being amortized over five years . The proposal also continues reserve accounting for qualifying Major Storms ( $21.4 million annually for NYSEG Electric and $2.5 million annually for RG&E Electric). Incremental maintenance costs incurred to restore service in qualifying divisions will be chargeable to the Major Storm Reserve provided they meet certain thresholds. The Joint Proposal maintains NYSEG’s and RG&E’s current electric reliability performance measures (and associated potential negative revenue adjustments for failing to meet established performance levels) which include the system average interruption frequency index (SAIFI) and the customer average interruption duration index (CAIDI). The Joint Proposal also modifies certain gas safety performance measures at the companies, including those relating to the replacement of leak prone mains, leak backlog management, emergency response and damage prevention. The proposal establishes threshold performance levels for designated aspects of customer service quality and continues and expands NYSEG’s and RG&E’s bill reduction and arrears forgiveness Low Income Programs with increased funding levels included in the proposal. The Joint Proposal provides for the implementation of NYSEG’s Energy Smart Community (ESC) Project in the Ithaca region which serves as a test-bed for implementation and deployment of Reforming the Energy Vision (REV) initiatives. The ESC Project is supported by NYSEG’s planned Distribution Automation upgrades and Advanced Metering Infrastructure (AMI) implementation for customers on circuits in the Ithaca region. The companies also are pursuing Non-Wires Alternative projects as described in the proposal. Other REV-related incremental costs and fees are included in the RAM to the extent cost recovery is not provided for elsewhere. Under the proposal, the RAM is applicable to all customers and serves to return or collect RAM Eligible Deferrals and Costs, including: (1) property taxes; (2) Major Storm deferral balances; (3) gas leak prone pipe replacement; (4) REV costs and fees which are not covered by other recovery mechanisms; and (5) NYSEG Electric Pole Attachment revenues. RG&E implemented a RAM in July 2018 since certain eligibility thresholds were exceeded. The Joint Proposal provides for partial or full reconciliation of certain expenses including, but not limited to: pensions and other postretirement benefits; property taxes; variable rate debt and new fixed rate debt; gas research and development; environmental remediation costs; major storms; nuclear electric insurance limited credits; economic development; and low income programs. The Joint Proposal also includes a downward-only Net Plant reconciliation. In addition, the Joint Proposal includes downward-only reconciliations for the costs of electric distribution and gas vegetation management, pipeline integrity and incremental maintenance. The Joint Proposal provides that NYSEG and RG&E continue their electric RDMs on a total revenue per class basis and their gas RDMs on a revenue per customer basis. On May 20, 2019, NYSEG and RG&E filed rate cases with the New York State Department of Public Service (NYDPS) for new tariffs. The effective date of new tariffs, assuming an approximately 11-month suspension period, will be April 20, 2020. The proposed rates facilitate the companies’ transition to a cleaner energy future while allowing for important initiatives such as vegetation management, hardening/resiliency and emergency preparedness. The companies are requesting delivery revenues to be based on a 9.50% ROE and 50% equity ratio. The below table provides a summary of the initial proposed delivery rate increases, delivery revenue percentages and total revenue percentages for all four businesses: Requested Revenue Increase Delivery Revenue Total Revenue Utility (Millions) % % NYSEG Electric $ 156.7 20.4 % 10.4 % NYSEG Gas $ 6.3 3.0 % 1.4 % RG&E Electric $ 31.7 7.0 % 4.1 % RG&E Gas $ 5.8 3.3 % 1.4 % NYPSC staff and other parties filed responsive testimony on September 15, 2019. NYPSC staff is recommending an 8.2% ROE and 48% equity. NYPSC staff recommended the following rate increases/decreases: NYSEG electric a rate increase of $76.7 million , NYSEG Gas a rate decrease of $15.9 million , RG&E Electric a rate increase of $0.7 million and RG&E Gas a rate decrease of $22.5 million . NYPSC Staff is also recommending NYSEG credit the environmental reserve by $31.1 million due to the legal rulings in 2017 and 2018 that denied insurance claims against OneBeacon and Century Indemnity in an insurance lawsuit. The companies entered into settlement discussion with the staff and other parties in October 2019. On February 26, 2020, the companies filed notice with the NYPSC that an agreement in principle has been reached among the companies, the NYDPS staff and certain other parties to the matter. As a result, drafting of a joint proposal (settlement agreement) has commenced. 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 2020, 70% of its standard service load for the second half of 2020 and 40% of its standard service load for the first half of 2021. Supplier of last resort service is procured on a quarterly basis and UI has wholesale power supply agreement in place for the second quarter of 2020. However, from time to time there are no bidders in the procurement process for supplier of last resort service and, in such cases, UI manages the load directly. In December 2016, the PURA approved new distribution rate schedules for UI for three years , which became effective January 1, 2017 and, among other things, provide for annual tariff increases and an ROE of 9.10% based on a 50% equity ratio, continued UI’s existing ESM pursuant to which UI and its customers share on a fifty -fifty basis all distribution earnings above the allowed ROE in a calendar year, continued the existing decoupling mechanism and approved the continuation of the requested storm reserve. Any dollars due to customers from the ESM continue to be first applied against any storm regulatory asset balance (if one exists at that time) or refunded to customers through a bill credit if such storm regulatory asset balance does not exist. In December 2017, PURA approved new tariffs for the Southern Connecticut Gas Company (SCG) effective January 1, 2018 for a three-year rate plan with rate increases of $1.5 million , $4.7 million and $5.0 million in 2018, 2019 and 2020, respectively. The new tariffs also include an RDM and Distribution Integrity Management Program (DIMP) mechanism similar to the mechanisms authorized for Connecticut Natural Gas Corporation (CNG), ESM, the amortization of certain regulatory liabilities (most notably accumulated hardship deferral balances and certain accumulated deferred income taxes) and tariff increases based on a ROE of 9.25% and approximately 52% equity level. Any dollars due to customers from the ESM will be first applied against any environmental regulatory asset balance as defined in the settlement agreement (if one exists at that time) or refunded to customers through a bill credit if such environmental regulatory asset balance does not exist. In December, 2018, PURA approved new tariffs for CNG effective January 1, 2019 for a three-year rate plan with rate increases of $9.9 million , $4.6 million and $5.2 million in 2019, 2020 and 2021, respectively. The new tariffs continued the RDM and DIMP mechanism, ESM and tariff increases based on an ROE of 9.30% , and an equity ratio of 54% in 2019, 54.50% in 2020 and 55% in 2021. On January 18, 2019, the DPU approved a settlement agreement between BGC and the Massachusetts Attorney General’s Office providing for new distribution rates for BGC. The settlement agreement provides for a $1.6 million distribution base rate increase effective February 1, 2019 (with a make-whole provision back to January 1, 2019), and an additional $0.7 million base distribution increase effective November 1, 2019, if certain investments are made by BGC. The distribution rate increase is based on a 9.70% ROE and 54% equity ratio. The settlement agreement provides for the implementation of a RDM and pension expense tracker and also provides that BGC will not file to change base distribution to become effective before November 1, 2021. REV In April 2014, the NYPSC commenced a proceeding entitled REV, which is a wide-ranging initiative to reform New York State’s energy industry and regulatory practices. REV has been divided into two tracks, Track 1 for Market Design and Technology, and Track 2 for Regulatory Reform. REV and its related proceedings have and will continue to propose regulatory changes that are intended to promote more efficient use of energy, deeper penetration of renewable energy resources such as wind and solar and wider deployment of distributed energy resources (DER), such as micro grids, on-site power supplies and storage. REV is also intended to promote greater use of advanced energy management products to enhance demand elasticity and efficiencies. Track 1 of this initiative involves a collaborative process to examine the role of distribution utilities in enabling market-based deployment of DER to promote load management and greater system efficiency, including peak load reductions. NYSEG is participating in the initiative with other New York utilities. The NYPSC issued a 2015 order in Track 1, which acknowledges the utilities’ role as a Distribution System Platform (DSP) provider, and required the utilities to file an initial Distribution System Implementation Plan (DSIP) by June 30, 2016, followed by bi-annual updates. The companies filed the initial DSIP, which also included information regarding the potential deployment of Automated Metering Infrastructure (AMI) across its entire service territory. In December 2016, the companies filed a petition to the NYPSC requesting approval for cost recovery associated with the full deployment of AMI. A collaborative associated with this petition began in the first quarter of 2017, was suspended in the second quarter of 2017, subsequently resumed in the first quarter of 2018 and then further suspended and has been included in the companies’ May 20, 2019 rate filing. Other various proceedings have also been initiated by the NYPSC which are REV related, and each proceeding has its own schedule. These proceedings include the Clean Energy Standard, Value of DER and Net Energy Metering, Demand Response Tariffs and Community Choice Aggregation. As part of the Clean Energy Standard proceeding, all electric utilities were ordered to begin payments to New York State Energy Research and Development Authority (NYSERDA) for RECs and Zero Emissions Credits beginning in 2017. Track 2 of the REV initiative is also underway, and through a NYPSC staff whitepaper review process, is examining potential changes in current regulatory, tariff, market design and incentive structures that could better align utility interests with achieving New York state and NYPSC’s policy objectives. New York utilities will also be addressing related regulatory issues in their individual rate cases. A Track 2 order was issued in May 2016, and includes guidance related to the potential for Earnings Adjustment Mechanisms (EAMs), Platform Service Revenues, innovative rate designs and data utilization and security. The companies, in December 2016, filed a proposal for the implementation of EAMs in the areas of System Efficiency, Energy Efficiency, Interconnections and Clean Air. A collaborative process to review the companies’ petition was suspended in 2017. A proposal for EAMs was included in the companies’ May 20, 2019 rate filing. In March 2017, the NYPSC issued three separate REV-related orders. These orders created a series of filing requirements for NYSEG and RG&E beginning in March 2017 and extending through the end of 2018. The three orders involve: 1) modifications to the electric utilities’ proposed interconnection EAM framework; 2) further DSIP requirements, including filing of an updated DSIP plan by mid-2018 and implementing two energy storage projects at each company by the end of 2018; and 3) Net Energy Metering Transition including implementation of Phase One of the Value of DER. In September 2017, the NYPSC issued another order related to the Value of DER, requiring tariff filings, changes to Standard Interconnection Requirements and planning for the implementation of automated consolidated billing. In July 2018, NYSEG and RG&E submitted an updated DSIP plan consistent with guidance received from the NY Department of Public Service. As of the end of 2018, both NYSEG and RG&E had deployed two energy storage projects each, consistent with the March 2017 NYPSC order requirements. In December 2018, the NYPSC staff submitted whitepapers on standby and buyback service rate design, future value stack compensation and capacity value compensation. The NYPSC ruled on the proposals set forth in the whitepapers on May 16, 2019. NYSEG and RG&E filed proposed standby and buyback rates with the NYPSC on September 24, 2019. The NYPSC also issued an order on value stack compensation for high-capacity-factor Resources on December 12, 2019. CMP Customer Billing System Investigation On March 1, 2018, the MPUC issued a Notice of Investigation initiating a summary investigation into CMP’s metering, billing and customer communications practices. Due to the highly technical nature of CMP’s customer billing system, on March 22, 2018 the MPUC issued an Order Initiating Audit commencing a forensic audit of CMP’s customer billing system to identify any errors that have, or continue to result in billing inaccuracies. On July 10, 2018, the MPUC issued an Order Modifying Scope of Audit, which expanded the scope of the audit to include CMP’s customer communication practices. On December 20, 2018, the MPUC released the findings of the forensic audit of CMP’s customer billing system and customer communication practices. On January 14, 2019, the MPUC issued an Order and Notice of Investigation initiating an investigation of CMP’s metering and billing, practices and initiating a separate investigation of the audit of CMP’s customer service and communication practices and incorporating such investigation into CMP’s general rate case. On September 3, 2019, the MPUC issued its Bench Analysis in the Metering and Billing Investigation and supported the findings of the independent audit. On September 7, the OPA issued testimony and findings from a separate audit firm which agreed with certain portions of the independent audit and also stated that continuing problems still persist in CMP’s billing system. CMP provided rebuttal testimony on October 16, 2019. On January 9, 2020 the hearing examiners issued their report whereby they recommended that the Commission find that the evidence in the record shows that there is no systemic problem within CMP’s metering and billing systems that has caused erroneous high usage on customers’ bills. Instead, the evidence-including the detailed forensic audit conducted by an independent third-party auditor-demonstrates that CMP’s metering and billing systems have been, and continue to be, recording and transmitting customer usage data accurately, and, with the exception of discrete billing calculation and presentation issues, customers’ billed amounts have been accurate. On January 30, 2020, the MPUC Commissioners deliberated and based on the verbal discussion, the Commissioners indicated that CMP’s Metering and Billing system is accurately reporting data; there is no systemic root cause for high usage complaints and errors related to CMP’s metering and billing system are localized and random, not systemic. The Commissioners were critical of CMP finding that CMP failed to implement proper testing of the SmartCare system prior to go-live; CMP’s implementation of SmartCare was imprudent; CMP’s SmartCare implementation experienced an unacceptable number of billing errors, delayed or estimated bills, bill presentment issues and unreasonable time required to address these issues; and the implementation issues were compounded by inadequate staffing, resulting in the inability of customers to contact a CMP representative. In its February 19, 2020 order in the CMP’s distribution rate case proceeding discussed above the MPUC imposed a reduction of 100 basis points in ROE, as a management efficiency adjustment, to address concerns with CMP’s customer service performance following the implementation of its new billing system in 2017. The management efficiency adjustment will remain in effect until CMP has demonstrated satisfactory customer service performance on four specified service quality measures for a period of 18 consecutive months with measurement commencing on March 1, 2020. Tax Cuts and Jobs Act On December 22, 2017, the Tax Cuts and Jobs Act of 2017 (the Tax Act) was signed into law. The Tax Act significantly changed the federal taxation of business entities including, among other things, implementing a federal corporate tax rate decrease from 35% to 21% for tax years beginning after December 31, 2017. Reductions in accumulated deferred income tax balances due to the reduction in the corporate income tax rates 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 have instituted separate proceedings in New York, Maine, Connecticut, Massachusetts and the FERC, respectively, to review and address the implications of the Tax Act on the utilities. In New York, the NYPSC staff issued a proposal on March 29, 2018, whereby the staff recommended that Tax Act benefits be returned to customers beginning October 1, 2018. Comments on this staff proposal were submitted by the Joint Utilities of New York with a separate Appendix by each respective major utility on June 27, 2018, including our New York utility companies. NYSEG and RG&E have stated that they believe Tax Act benefits should be utilized for utility programs for the benefit of customers, including for new projects such as AMI, other future resiliency investments and to recover deferred regulatory assets. On August 9, 2018, the NYPSC issued an Order requiring sur-credits effective October 1, 2018. The sur-credits for NYSEG and RG&E reflected the lower effective tax rate of 21%. For NYSEG Gas, RG&E Electric and RG&E Gas the NYPSC also required the sur-credit to include the return to customers of the January - September 2018 Tax Act savings over three years. The NYPSC allowed NYSEG Electric to continue to defer the January - September 2018 Tax Act savings as well as to continue to preserve the protected and unprotected Tax Act savings until the companies' next rate cases. In Connecticut, UI and SCG expect Tax Act savings to be deferred until they are reflected in tariffs in a future rate case, unless PURA determines otherwise. CNG and Berkshire included Tax Act savings in rate cases that were filed with PURA and the DPU, respectively, in the second quarter of 2018. In Maine, CMP adjusted rates beginning July 1, 2018 to pass back to customers the Tax Act savings after offsetting for recovery of deferred 2017 storm costs. In its February 19, 2020 order in the CMP’s distribution rate case proceeding discussed above, the MPUC approved CMP’s distribution related accumulated deferred income tax balances associated with the Tax Act

Regulatory Assets and Liabiliti

Regulatory Assets and Liabilities	12 Months Ended
	Dec. 31, 2019
Regulated Operations [Abstract]
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 the rate base or accruing carrying costs are the 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. The total net amount of these items is approximately $1,749 million . 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 December 31, 2019 and 2018 consisted of: As of December 31, 2019 2018 (Millions) Pension and other post-retirement benefits cost deferrals $ 125 $ 141 Pension and other post-retirement benefits 1,061 1,138 Storm costs 272 346 Rate adjustment mechanism 79 18 Reliability support services — 13 Revenue decoupling mechanism 19 7 Transmission revenue reconciliation mechanism 5 11 Contracts for differences 92 97 Hardship programs 29 26 Plant decommissioning 5 11 Deferred purchased gas 25 37 Deferred transmission expense 11 11 Environmental remediation costs 277 278 Debt premium 97 118 Unamortized losses on reacquired debt 29 23 Unfunded future income taxes 399 371 Federal tax depreciation normalization adjustment 153 157 Asset retirement obligation 17 18 Deferred meter replacement costs 27 29 Other 139 95 Total regulatory assets 2,861 2,945 Less: current portion 294 299 Total non-current regulatory assets $ 2,567 $ 2,646 “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. The recovery of these amounts will be determined in future proceedings. “Storm costs” for CMP, NYSEG and RG&E 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. As of December 31, 2019, deferred storm costs include $78 million and $37 million at NYSEG being recovered over ten and five year periods, respectively, from the June 2016 approval of the Joint Proposal by the NYPSC, and $96 million and $27 million at NYSEG and RG&E, respectively, not included in the Joint Proposal. The recovery of amounts not included in the Joint Proposal will occur through the RAM or determined as part of the current rate proceedings. “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. “Reliability support services” represents the difference between actual expenses for reliability support services and the amount provided for in rates. “Deferred meter replacement costs” represent the deferral of the book value of retired meters which were replaced by AMI meters. This amount is being amortized over the initial depreciation period of related retired meters. “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. “Deferred Transmission Expense” represents deferred transmission income or expense and fluctuates based upon actual revenues and revenue requirements. “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 fifty 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 rates years covering 2011 forward. The recovery period in New York is from 27 to 39 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. “Other” includes post term amortization deferrals and various items subject to reconciliation including hedge losses and deferred property tax. Regulatory liabilities as of December 31, 2019 and 2018 consisted of: As of December 31, 2019 2018 (Millions) Energy efficiency portfolio standard $ 72 $ 56 Gas supply charge and deferred natural gas cost 11 4 Pension and other post-retirement benefits cost deferrals 80 97 Carrying costs on deferred income tax bonus depreciation 49 72 Carrying costs on deferred income tax - Mixed Services 263(a) 15 20 2017 Tax Act 1,548 1,509 Revenue decoupling mechanism 17 19 Accrued removal obligations 1,173 1,153 Asset sale gain account 10 10 Economic development 27 28 Positive benefit adjustment 37 39 Theoretical reserve flow thru impact 14 19 Deferred property tax 17 25 Net plant reconciliation 23 19 Debt rate reconciliation 67 49 Rate refund – FERC ROE proceeding 32 29 Transmission congestion contracts 23 21 Merger-related rate credits 16 18 Accumulated deferred investment tax credits 13 14 Asset retirement obligation 14 13 Earnings sharing provisions 28 17 Middletown/Norwalk local transmission network service collections 18 19 Low income programs 33 38 Non-firm margin sharing credits 16 10 New York 2018 winter storm settlement 11 — Other 159 130 Total regulatory liabilities 3,523 3,428 Less: current portion 242 205 Total non-current regulatory liabilities $ 3,281 $ 3,223 “Energy efficiency portfolio standard” represents the difference between revenue billed to customers through an energy efficiency charge and the costs of our energy efficiency programs as approved by the state authorities. This may be refunded to customers within the next year. “Pension and other postretirement benefits” represent the actuarial gains on other postretirement plans that will be reflected in customer rates when they are amortized and recognized in future expenses. Because no funds have yet been received for this, a regulatory liability is not reflected within rate base. They also represent the difference between actual expense for pension and other postretirement benefits and the amount provided for in rates. Recovery of these amounts will be determined in future proceedings. “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. The amortization period is five years following the approval of the Joint Proposal by the NYPSC. “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 and DPU have instituted separate proceedings in New York, Maine, Connecticut and Massachusetts, respectively, to review and address the implications associated with the Tax Act on the utilities providing service in such states. “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. “Asset sale gain account” represents the gain on NYSEG’s 2001 sale of its interest in Nine Mile Point 2 nuclear generating station located in Oswego, New York. The net proceeds from the Nine Mile Point 2 nuclear generating station were placed in this account and will be used to benefit customers. The amortization period is five years and began in 2016. “Economic development” represents the economic development program which enables NYSEG and RG&E to foster economic development through attraction, expansion and retention of businesses within its service territory. If the level of actual expenditures for economic development allocated to NYSEG and RG&E varies in any rate year from the level provided for in rates, the difference is refunded to customers. The amortization period is five years and began in 2016. “Positive benefit adjustment” resulted from Iberdrola’s 2008 acquisition of AVANGRID (formerly Energy East Corporation). This is being used to moderate increases in rates. The amortization period is five years and began in 2016. “Theoretical reserve flow thru impact” represents the differences from the rate allowance for applicable federal and state flow through impacts related to the excess depreciation reserve amortization. It also represents the carrying cost on the differences. The amortization period is five years and began in 2016. “Merger-related rate credits” resulted from the acquisition of UIL. This is being used to moderate increases in rates. In the years ended December 31, 2019 and 2018 , respectively, $2 million and $3 million of rate credits were applied against customer bills. “Low Income Programs” represent various hardship and payment plan programs approved for recovery. “Other” includes various items subject to reconciliation including excess generation service charge, rate change levelization and RAM.

Goodwill and Intangible assets

Goodwill and Intangible assets	12 Months Ended
	Dec. 31, 2019
Goodwill and Intangible Assets Disclosure [Abstract]
Goodwill and Intangible assets	Goodwill and Intangible assets Goodwill by reportable segment as of December 31, 2019 and 2018 consisted of: As of December 31, 2019 2018 (Millions) Networks $ 2,747 $ 2,747 Renewables 372 380 Total $ 3,119 $ 3,127 During 2019, Renewables' goodwill was reduced by $8 million as a result of the sale of a 50% interest in the Poseidon projects described in Note 22. During 2018 , there were no changes in gross amounts and accumulated losses of goodwill for the Networks and Renewables reportable segments. Goodwill Impairment Assessment For impairment testing purposes our reporting units are the same as operating segments, except for Networks, which contains three reporting units, Maine, New York and UIL. The goodwill for the Maine reporting unit resulted from the purchase of CMP by Energy East Corporation in 2000 and amounted to $325 million . Separately, the goodwill for the New York reporting unit resulted primarily from the purchase of RG&E by Energy East in 2002 and amounted to $654 million . The goodwill for the UIL reporting unit was generated from the acquisition of UIL on December 16, 2015, and amounts to $1,768 million . Our annual impairment testing takes place as of October 1. Our step zero qualitative assessment involves evaluating key events and circumstances that could affect the fair value of our reporting units, as well as other factors. Events and circumstances evaluated include macroeconomic conditions, industry, regulatory and market considerations, cost factors and their effect on earnings and cash flows, overall financial performance as compared with projected results and actual results of relevant prior periods, other relevant entity specific events and events affecting a reporting unit. Our step one impairment testing includes various assumptions, primarily the discount rate, which is based on an estimate of a market participant's marginal, weighted average cost of capital and forecasted cash flows. We test the reasonableness of the conclusions of our step one impairment testing using a range of discount rates and a range of assumptions for long term cash flows. We had no impairment of goodwill in 2019 and 2018 as a result of our impairment testing. Intangible assets Intangible assets include those assets acquired in business acquisitions and intangible assets acquired and developed from external third parties and from affiliated companies. Following is a summary of intangible assets as of December 31, 2019 and 2018 : As of December 31, 2019 Gross Carrying Amount Accumulated Amortization Net Carrying Amount (Millions) Wind development $ 591 $ (289 ) $ 302 Other 28 (16 ) 12 Total Intangible Assets $ 619 $ (305 ) $ 314 As of December 31, 2018 Gross Carrying Amount Accumulated Amortization Net Carrying Amount (Millions) Wind development $ 588 $ (275 ) $ 313 Other 25 (15 ) 10 Total Intangible Assets $ 613 $ (290 ) $ 323 Wind development costs, with the exception of future ‘pipeline’ development costs, are amortized on a straight-line basis in accordance with the life of the related assets once placed in service. Amortization expense for both the years ended December 31, 2019 and 2018 was $15 million , and for the year ended December 31, 2017, amortization expense was $22 million . We believe our future cash flows will support the recoverability of our intangible assets. We expect amortization expense for the five years subsequent to December 31, 2019 , to be as follows: Year ending December 31, Amount (Millions) 2020 $ 15 2021 $ 14 2022 $ 13 2023 $ 12 2024 $ 12

Property, Plant and Equipment

Property, Plant and Equipment	12 Months Ended
	Dec. 31, 2019
Property, Plant and Equipment [Abstract]
Property, Plant and Equipment	Property, Plant and Equipment Property, plant and equipment as of December 31, 2019 , consisted of: As of December 31, 2019 Regulated Nonregulated Total (Millions) Electric generation, distribution, transmission and other $ 15,092 $ 12,360 $ 27,452 Natural gas transportation, distribution and other 4,387 13 4,400 Other common operating property — 258 258 Total Property, Plant and Equipment in Service 19,479 12,631 32,110 Total accumulated depreciation (4,969 ) (4,090 ) (9,059 ) Total Net Property, Plant and Equipment in Service 14,510 8,541 23,051 Construction work in progress 1,269 898 2,167 Total Property, Plant and Equipment $ 15,779 $ 9,439 $ 25,218 Property, plant and equipment as of December 31, 2018 , consisted of: As of December 31, 2018 Regulated Nonregulated Total (Millions) Electric generation, distribution, transmission and other $ 14,242 $ 11,669 $ 25,911 Natural gas transportation, distribution and other 4,058 13 4,071 Other common operating property — 226 226 Total Property, Plant and Equipment in Service (a) 18,300 11,908 30,208 Total accumulated depreciation (b) (4,615 ) (3,744 ) (8,359 ) Total Net Property, Plant and Equipment in Service 13,685 8,164 21,849 Construction work in progress 1,010 600 1,610 Total Property, Plant and Equipment $ 14,695 $ 8,764 $ 23,459 (a) Includes capitalized leases of $226 million primarily related to electric generation, distribution, transmission and other. Finance leases (formerly known as capital leases) are no longer included in property plant and equipment after adoption of ASC 842 on January 1, 2019. See Note 3 for further information. (b) Includes accumulated amortization of capitalized leases of $76 million . Capitalized interest costs were $55 million , $26 million and $28 million for the years ended December 31, 2019 , 2018 and 2017 , respectively. Accrued liabilities for property, plant and equipment additions were $357 million , $154 million and $209 million as of December 31, 2019 , 2018 and 2017 , respectively. We impaired or wrote off amounts of $11 million , $0 and $5 million for the years ended December 31, 2019 , 2018 and 2017 , respectively, resulting from reassessment of the economic feasibility of our various Renewables development projects under construction. Depreciation expense for the years ended December 31, 2019 , 2018 and 2017 , amounted to $919 million , $840 million and $802 million , respectively.

Asset retirement obligations

Asset retirement obligations	12 Months Ended
	Dec. 31, 2019
Asset Retirement Obligation Disclosure [Abstract]
Asset retirement obligations	Asset retirement obligations AROs are intended to meet the costs for dismantling and restoration work that we have committed to carry out at our operational facilities. The reconciliation of ARO carrying amounts for the years ended December 31, 2019 and 2018 consisted of: (Millions) As of December 31, 2017 $ 196 Liabilities settled during the year (1 ) Liabilities incurred during the year 5 Accretion expense 12 Revisions in estimated cash flows 5 As of December 31, 2018 $ 217 Liabilities settled during the year (5 ) Liabilities incurred during the year 6 Accretion expense 12 Revisions in estimated cash flows (a) (40 ) As of December 31, 2019 $ 190 (a) Represents a reduction in our estimate of expected cash flows required for retirement activities related to our renewable energy facilities. Several of the wind generation facilities have restricted cash for purposes of settling AROs. Restricted cash related to AROs was $2 million as of both December 31, 2019 and 2018 . These amounts have been included in “Other Assets” on our consolidated balance sheets. Accretion expenses are included in “Operations and maintenance” in our consolidated statements of income. We have AROs for which a liability has not been recognized because the fair value cannot be reasonably estimated due to indeterminate settlement dates, including for the removal of hydroelectric dams due to structural inadequacy or for decommissioning; the removal of property upon termination of an easement, right-of-way or franchise; and costs for abandonment of certain types of gas mains.

Debt

Debt	12 Months Ended
	Dec. 31, 2019
Debt Disclosure [Abstract]
Debt	Debt Long-term debt as of December 31, 2019 and 2018 consisted of: As of December 31, 2019 2018 (Millions) Maturity Dates Balances Interest Rates Balances Interest Rates First mortgage bonds - fixed (a) 2021-2049 $ 2,218 3.07%-8.00% $ 2,055 3.07%-10.06% Unsecured pollution control notes - fixed 2020-2029 538 2.00%-3.50% 526 2.00%-3.50% Term loan - variable 2021 500 2.40% — Other various non-current debt - fixed 2020-2049 4,228 2.80%-10.48% 3,127 2.80%-10.48% Obligations under capital leases (b) — 89 4.00%-4.44% Unamortized debt issuance costs and discount (38 ) (35 ) Total Debt 7,446 5,762 Less: debt due within one year, included in current liabilities 730 394 Total Non-current Debt $ 6,716 $ 5,368 (a) The first mortgage bonds have pledged collateral of substantially all the respective utility’s in service properties of approximately $6,876 million . (b) Due to the adoption of ASC 842 in 2019 (see Notes 3 and 13 for more information), capital leases, now known as financing leases, are no longer reported as part of long-term debt. On January 15, 2019, UI, CNG, SCG and BGC issued $195 million in aggregate amount of notes/bonds with maturity dates ranging from 2029 to 2049 and fixed interest rates ranging from 4.07% to 4.52% . On April 1, 2019, NYSEG issued $12 million of Indiana County Industrial Development Authority Pollution Control Revenue Bonds in a private placement maturing in 2024 with a 2.65% fixed interest rate. On May 16, 2019, we issued $750 million of senior unsecured notes maturing in 2029 at a fixed interest rate of 3.80% . On June 3, 2019, CMP issued $240 million aggregate principal amount of first mortgage bonds with maturity dates ranging from 2026 to 2034 and fixed interest rates ranging from 3.87% to 4.20% . On August 27, 2019, RG&E issued $150 million aggregate principal amount of first mortgage bonds maturing in 2027 at a fixed interest rate of 3.10% . On September 5, 2019, NYSEG issued $300 million aggregate principal amount of senior unsecured notes maturing in 2049 at a fixed interest rate of 3.30% . On December 31, 2019, we entered into a $500 million term loan credit agreement with two financial institutions. The agreement expires on June 30, 2021 and has a variable interest rate based on the London Interbank Offer Rate (LIBOR). The initial rate was set at 2.40% on December 31, 2019. Long-term debt maturities, including sinking fund obligations, due over the next five years consists of: 2020 2021 2022 2023 2024 Total (Millions) $ 730 $ 801 $ 363 $ 439 $ 612 $ 2,945 We make certain standard covenants to lenders in our third-party debt agreements, including, in certain agreements, covenants regarding the ratio of indebtedness to total capitalization. A breach of any covenant in the existing credit facilities or the agreements governing our other indebtedness would result in an event of default. Certain events of default may trigger automatic acceleration. Other events of default may be remedied by the borrower within a specified period or waived by the lenders and, if not remedied or waived, give the lenders the right to accelerate. Neither we nor any of our subsidiaries were in breach of covenants or of any obligation that could trigger the early redemption of our debt as of both December 31, 2019 and 2018 . Fair Value of Debt The estimated fair value of debt amounted to $8,168 million and $5,952 million as of December 31, 2019 and 2018 , respectively. The estimated fair value was determined, in most cases, by discounting the future cash flows at market interest rates. The interest rate curve used to make these calculations takes into account the risks associated with the electricity industry and the credit ratings of the borrowers in each case. The fair value of debt is considered Level 2 within the fair value hierarchy. Short-term Debt Outstanding Notes Payable AVANGRID had $560 million and $587 million of notes payable as of December 31, 2019 and 2018 , respectively. As of December 31, 2019 and 2018 , the balance consisted of $562 million and $589 million , respectively, of commercial paper, presented net of discounts on the balance sheet. AVANGRID has a commercial paper program with a limit of $2 billion which is backstopped by the AVANGRID credit facility described below. AVANGRID Credit Facility AVANGRID and its subsidiaries, NYSEG, RG&E, CMP, UI, CNG, SCG and BGC have a revolving credit facility with a syndicate of banks, or the AVANGRID Credit Facility, that provides for maximum borrowings of up to $2.5 billion in the aggregate. Under the terms of the AVANGRID Credit Facility, each joint borrower has a maximum borrowing entitlement, or sublimit, which can be periodically adjusted to address specific short-term capital funding needs, subject to the maximum limit contained in the agreement. AVANGRID’s maximum sublimit is $2 billion , NYSEG, RG&E, CMP and UI have maximum sublimits of $400 million , CNG and SCG have maximum sublimits of $150 million and BGC has a maximum sublimit of $40 million . Under the AVANGRID Credit Facility, each of the borrowers will pay an annual facility fee that is dependent on their credit rating. As of December 31, 2019, the facility fees range from 10.0 to 17.5 basis points. During 2019, we extended the maturity date for the AVANGRID Credit Facility by one year to June 29, 2024. Since the facility is a backstop to the AVANGRID commercial paper program, the amounts available under the facility as of December 31, 2019 and December 31, 2018 were $1,938 million and $1,911 million , respectively. Iberdrola Group Credit Facility AVANGRID has a credit facility with Iberdrola Financiacion, S.A.U., a company of the Iberdrola Group. The facility has a limit of $500 million and matures on June 18, 2023 . AVANGRID pays a facility fee of 10.5 basis points annually on the facility. As of both December 31, 2019 and 2018 , there was no outstanding amount under this credit facility.

Fair Value of Financial Instrum

Fair Value of Financial Instruments and Fair Value Measurements	12 Months Ended
	Dec. 31, 2019
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 for deferred compensation plans and a supplemental retirement benefit life insurance trust. The Rabbi Trusts primarily include equity securities and money market funds. 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. 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). Because we use prices quoted in an active market we include the fair value measurements in Level 1. • 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 12 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 historical volatilities and correlations for tolling arrangements and extrapolated values for certain power swaps. 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 swap derivative instruments based on a model whose inputs are observable, such as the London Interbank Offered Rate (LIBOR) forward interest rate curves. We include the fair value measurement for these contracts in Level 2 (See Note 12 for further discussion of interest rate swaps). 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 their estimated fair values and are considered Level 1. Restricted cash was $6 million and $7 million as of December 31, 2019 and 2018 , respectively, which is included in “Other Assets” on our consolidated balance sheets. The financial instruments measured at fair value as of December 31, 2019 and 2018 consisted of: As of As of December 31, 2019 Level 1 Level 2 Level 3 Netting Total (Millions) Equity and other investments with readily determinable fair values $ 38 $ 13 $ — $ — $ 51 Derivative assets Derivative financial instruments - power $ 4 $ 23 $ 120 $ (54 ) $ 93 Derivative financial instruments - gas — 40 31 (71 ) — Contracts for differences — — 2 — 2 Total $ 4 $ 63 $ 153 $ (125 ) $ 95 Derivative liabilities Derivative financial instruments - power $ (28 ) $ (43 ) $ (29 ) $ 92 $ (8 ) Derivative financial instruments - gas (4 ) (26 ) (5 ) 33 (2 ) Contracts for differences — — (94 ) — (94 ) Derivative financial instruments – Other — (1 ) — — (1 ) Total $ (32 ) $ (70 ) $ (128 ) $ 125 $ (105 ) As of As of December 31, 2018 Level 1 Level 2 Level 3 Netting Total (Millions) Equity and other investments with readily determinable fair values $ 37 $ 10 $ — $ — $ 47 Derivative assets Derivative financial instruments - power $ 17 $ 23 $ 91 $ (59 ) $ 72 Derivative financial instruments - gas 1 20 36 (55 ) 2 Contracts for differences — — 5 — 5 Total $ 18 $ 43 $ 132 $ (114 ) $ 79 Derivative liabilities Derivative financial instruments - power $ (12 ) $ (41 ) $ (36 ) $ 77 $ (12 ) Derivative financial instruments - gas (1 ) (23 ) (7 ) 22 (9 ) Contracts for differences — — (102 ) — (102 ) Derivative financial instruments – Other — (16 ) (2 ) — (18 ) Total $ (13 ) $ (80 ) $ (147 ) $ 99 $ (141 ) The reconciliation of changes in the fair value of financial instruments based on Level 3 inputs for the years ended December 31, 2019 , 2018 and 2017 consisted of: (Millions) 2019 2018 2017 Fair value as of January 1, $ (15 ) $ 6 $ 31 Gains for the year recognized in operating revenues 53 18 18 Losses for the year recognized in operating revenues (2 ) (9 ) (1 ) Total gains or losses for the period recognized in operating revenues 51 9 17 Gains recognized in OCI 2 — 2 Losses recognized in OCI (3 ) (5 ) (1 ) Total gains or losses recognized in OCI (1 ) (5 ) 1 Net change recognized in regulatory assets and liabilities 5 (5 ) (17 ) Purchases (22 ) (6 ) (5 ) Settlements 4 (10 ) (17 ) Transfers out of Level 3 (a) 3 (4 ) (4 ) Fair value as of December 31, $ 25 $ (15 ) $ 6 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 $ 51 $ 9 $ 17 (a) Transfers out of Level 3 were the result of increased observability of market data. For assets and liabilities that are recognized in the consolidated financial statements at fair value on a recurring basis, we determine whether transfers have occurred between levels in the hierarchy by re-assessing categorization based on the lowest level of input that is significant to the fair value measurement as a whole at the end of each reporting period. There have been no transfers between Level 1 and Level 2 during the years reported. 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. As of December 31, 2019 Instruments Instrument Description Valuation Technique Valuation Inputs Index Avg. Max. Min. Fixed price power and gas swaps with delivery period > two years Transactions with delivery periods exceeding two years Transactions are valued against forward market prices on a discounted basis Observable and extrapolated forward gas and power prices not all of which can be corroborated by market data for identical or similar products NYMEX ($/MMBtu) $ 2.90 $ 4.90 $ 2.07 Indiana hub ($/MWh) $ 30.54 $ 61.12 $ 19.10 Mid C ($/MWh) $ 24.75 $ 105.00 $ (0.50 ) Minn hub ($/MWh) $ 25.10 $ 52.17 $ 12.51 NoIL hub ($/MWh) $ 27.36 $ 55.39 $ 15.50 Ercot S hub ($/MWh) $ 31.00 $ 248.39 $ 14.62 Our Level 3 valuations primarily consist of NYMEX gas and fixed price power swaps with delivery periods extending through 2024 and 2032, respectively. The gas swaps are used to hedge merchant wind positions. The power swaps are used to hedge merchant wind production in the West and Midwest. We performed a sensitivity analysis around the Level 3 gas and power positions to changes in the valuation inputs. Given the nature of the transactions in Level 3, the only material 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 gas swaps are economic hedges of merchant generation, with decreases in gas prices resulting in unrealized gains and increases 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 models themselves. 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 price, correlation and volatility curves. 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 12 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: Range at Unobservable Input December 31, 2019 Risk of non-performance 0.05% - 0.45% Discount rate 1.69% - 1.83% Forward pricing ($ per KW-month) $3.80 - $7.03

Derivative Instruments and Hedg

Derivative Instruments and Hedging	12 Months Ended
	Dec. 31, 2019
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Derivative Instruments and Hedging	Derivative Instruments and Hedging Our Networks, Renewables and Gas 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 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 December 31, 2019 and 2018 , respectively, including those subject to master netting agreements and the location of the net derivative positions on our consolidated balance sheets: As of December 31, 2019 Current Assets Noncurrent Assets Current Liabilities Noncurrent Liabilities (Millions) Not designated as hedging instruments Derivative assets $ 1 $ 4 $ 1 $ 2 Derivative liabilities (1 ) (2 ) (39 ) (86 ) — 2 (38 ) (84 ) Designated as hedging instruments Derivative assets — — — — Derivative liabilities — — (1 ) (1 ) — — (1 ) (1 ) Total derivatives before offset of cash collateral — 2 (39 ) (85 ) Cash collateral receivable — — 27 1 Total derivatives as presented in the balance sheet $ — $ 2 $ (12 ) $ (84 ) As of December 31, 2018 Current Assets Noncurrent Assets Current Liabilities Noncurrent Liabilities (Millions) Not designated as hedging instruments Derivative assets $ 18 $ 6 $ 10 $ 3 Derivative liabilities (10 ) (3 ) (21 ) (93 ) 8 3 (11 ) (90 ) Designated as hedging instruments Derivative assets — — — — Derivative liabilities — — (2 ) — — — (2 ) — Total derivatives before offset of cash collateral 8 3 (13 ) (90 ) Cash collateral receivable — — — — Total derivatives as presented in the balance sheet $ 8 $ 3 $ (13 ) $ (90 ) The net notional volumes of the outstanding derivative instruments associated with Networks' activities as of December 31, 2019 and 2018 , respectively, consisted of: As of December 31, 2019 2018 (Millions) Wholesale electricity purchase contracts (MWh) 5.1 4.9 Natural gas purchase contracts (Dth) 8.5 7.8 Fleet fuel purchase contracts (Gallons) 2.2 2.1 Derivatives not designated as hedging instruments NYSEG and RG&E have an electric commodity charge that passes through rates costs for the market price of electricity. 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 their 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 December 31, 2019 and 2018 and amounts reclassified from regulatory assets and liabilities into income for the years ended 2019 , 2018 and 2017 are as follows: (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 For the Year Ended December 31, December 31, 2019 Electricity Natural Gas 2019 Electricity Natural Gas Regulatory assets $ 24 $ 4 Purchased power, natural gas and fuel used $ 25 $ 1 Regulatory liabilities $ — $ — December 31, 2018 2018 Regulatory assets $ — $ — Purchased power, natural gas and fuel used $ (10 ) $ (1 ) Regulatory liabilities $ 5 $ — 2017 Purchased power, natural gas and fuel used $ 37 $ — 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 December 31, 2019 , UI has recorded a gross derivative asset of $2 million ( $0 of which is related to UI’s portion of the CfD signed by CL&P), a regulatory asset of $92 million , a gross derivative liability of $94 million ( $92 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, 2018 , UI has recorded a gross derivative asset of $5 million ( $0 of which is related to UI’s portion of the CfD signed by CL&P), a regulatory asset of $97 million , a gross derivative liability of $102 million ( $96 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 or regulatory liabilities, for the years ended December 31, 2019 , 2018 and 2017 , respectively, were as follows: Years Ended December 31, 2019 2018 2017 (Millions) Derivative Assets $ (3 ) $ (6 ) $ (8 ) Derivative Liabilities $ 8 $ 1 $ (9 ) Derivatives designated as hedging instruments The effect of derivatives in cash flow hedging relationships on OCI and income for the years ended December 31, 2019 , 2018 and 2017 , respectively, consisted of: Year Ended December 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) 2019 Interest rate contracts $ — Interest expense $ 6 $ 306 Commodity contracts — Purchased power, natural gas and fuel used 1 1,509 Foreign currency exchange contracts (1 ) — Total $ (1 ) $ 7 2018 Interest rate contracts $ — Interest expense $ 8 $ 303 Commodity contracts (1 ) Purchased power, natural gas and fuel used — 1,653 Total $ (1 ) $ 8 2017 Interest rate contracts $ — Interest expense $ 8 $ 280 Commodity contracts (1 ) Purchased power, natural gas and fuel used 1 1,338 Total $ (1 ) $ 9 (a) Changes in accumulated OCI are reported in pre-tax basis. On June 20, 2019, Networks entered into a forward contract to hedge the foreign currency exchange risk of approximately $100 million in forecasted capital expenditures through June 2023. The forward foreign currency contracts are designated and qualify as cash flow hedges and are expected to be settled upon the payment to vendors for capital expenditures. The gain or loss on the foreign exchange derivative is reported as a component of accumulated OCI and will be reclassified into earnings over the useful life of the underlying capital expenditures. The net loss in accumulated OCI related to previously settled forward starting swaps and accumulated amortization is $55 million and $61 million , as of December 31, 2019 and 2018 , respectively. We recorded $6 million in net derivative losses related to discontinued cash flow hedges in each of the years ended December 31, 2019 , 2018 and 2017 . We will amortize approximately $4 million of discontinued cash flow hedges in 2020. The unrealized loss of $1 million on hedge derivatives is reported in OCI because the forecasted transaction is considered to be probable as of December 31, 2019 . We expect that immaterial amounts of those losses will be reclassified into earnings within the next twelve months . The maximum length of time over which we are hedging our exposure to the variability in future cash flows for forecasted fleet fuel transactions is twelve months . (b) Renewables and Gas activities The below presented quantitative information includes derivative financial instruments associated with Gas activities, which were sold during 2018. We sell fixed-price gas and power forwards to hedge our merchant wind assets from declining commodity prices for our Renewables business. We also purchase fixed-price gas and basis swaps and sell fixed-price power in the forward market to hedge the spark spread or heat rate of our merchant thermal assets. We also enter into tolling arrangements to sell the output of our 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 December 31, 2019 and 2018 , respectively, consisted of: As of December 31, 2019 2018 (MWh/Dth in Millions) Wholesale electricity purchase contracts 4 5 Wholesale electricity sales contracts 9 6 Natural gas and other fuel purchase contracts 29 29 Financial power contracts 10 11 Basis swaps - purchases 42 42 Basis swaps - sales 1 4 The fair values of derivative contracts associated with Renewables' activities as of December 31, 2019 and 2018 , respectively, consisted of: As of December 31, 2019 2018 (Millions) Wholesale electricity purchase contracts $ 10 $ 11 Wholesale electricity sales contracts 4 (12 ) Natural gas and other fuel purchase contracts (2 ) (2 ) Financial power contracts 73 55 Basis swaps - purchases — (6 ) Total $ 85 $ 46 The tables below present Renewables' derivative positions as of December 31, 2019 and 2018 , respectively, including those subject to master netting agreements and the location of the net derivative position on our consolidated balance sheets: As of December 31, 2019 Current Assets Noncurrent Assets Current Liabilities Noncurrent Liabilities (Millions) Not designated as hedging instruments Derivative assets $ 23 $ 110 $ 42 $ 13 Derivative liabilities (1 ) (7 ) (48 ) (18 ) 22 103 (6 ) (5 ) Designated as hedging instruments Derivative assets — 18 5 4 Derivative liabilities — (9 ) (13 ) (6 ) — 9 (8 ) (2 ) Total derivatives before offset of cash collateral 22 112 (14 ) (7 ) Cash collateral (payable) receivable (11 ) (30 ) 7 6 Total derivatives as presented in the balance sheet $ 11 $ 82 $ (7 ) $ (1 ) As of December 31, 2018 Current Assets Noncurrent Assets Current Liabilities Noncurrent Liabilities (Millions) Not designated as hedging instruments Derivative assets $ 19 $ 96 $ 29 $ 17 Derivative liabilities (5 ) (3 ) (48 ) (35 ) 14 93 (19 ) (18 ) Designated as hedging instruments Derivative assets 2 1 2 4 Derivative liabilities — — (7 ) (10 ) 2 1 (5 ) (6 ) Total derivatives before offset of cash collateral 16 94 (24 ) (24 ) Cash collateral (payable) receivable (8 ) (34 ) 9 17 Total derivatives as presented in the balance sheet $ 8 $ 60 $ (15 ) $ (7 ) Derivatives not designated as hedging instruments The effects of trading and non-trading derivatives associated with Renewables' activities for the year ended December 31, 2019 , consisted of: Year Ended December 31, 2019 Trading Non-trading Total amount per income statement (Millions) Operating Revenues Wholesale electricity purchase contracts $ (1 ) $ — Wholesale electricity sales contracts 3 40 Financial power contracts (3 ) 23 Financial and natural gas contracts (1 ) 1 Total (loss) gain included in operating revenues $ (2 ) $ 64 $ 1,338 Purchased power, natural gas and fuel used Wholesale electricity purchase contracts $ — $ — Wholesale electricity sales contracts — — Financial power contracts — (1 ) Financial and natural gas contracts — 15 Total gain included in purchased power, natural gas and fuel used $ — $ 14 $ 1,509 Total (Loss) Gain $ (2 ) $ 78 During September 2019, Renewables liquidated a portion of one of its wholesale electricity sales contracts and recorded a gain of $43 million for the year ended December 31, 2019 . The effects of trading and non-trading derivatives associated with Renewables' and Gas' activities for the years ended December 31, 2018 and 2017 , consisted of: Years Ended December 31, 2018 2017 (Millions) Trading Non-trading Trading Non-trading Wholesale electricity purchase contracts $ 4 $ 11 $ (3 ) $ 1 Wholesale electricity sales contracts (2 ) (15 ) 4 (3 ) Financial power contracts — (19 ) (1 ) (5 ) Financial and natural gas contracts 4 — (8 ) — Natural gas and other fuel purchase contracts — — — (8 ) Total Gain (Loss) $ 6 $ (23 ) $ (8 ) $ (15 ) Derivatives designated as hedging instruments The effect of derivatives in cash flow hedging relationships on accumulated OCI and income for the years ended December 31, 2019 , 2018 and 2017 consisted of: Year Ended December 31, (Loss) Gain Recognized in OCI on Derivatives (a) Location of Gain Reclassified from Accumulated OCI into Income Loss (Gain) Reclassified from Accumulated OCI into Income Total amount per Income Statement (Millions) 2019 Commodity contracts $ (5 ) Operating revenues $ 3 $ 6,338 2018 Commodity contracts $ (11 ) Operating revenues $ (22 ) $ 6,478 2017 Commodity contracts $ 41 Operating revenues $ 14 $ 5,963 (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 $6 million of loss included in accumulated OCI at December 31, 2019 is expected to be reclassified into earnings within the next 12 months . We recorded immaterial amounts of net derivative losses related to discontinued cash flow hedges for the years ended December 31, 2019 , 2018 and 2017 . (c) Interest rate swaps 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. In May 2019, we settled interest rate swaps designated as cash flow hedges related to the issuance of the $750 million in debt described in Note 10. The net loss in accumulated OCI related to these interest rate swaps is $38 million as of December 31, 2019 . We amortized into income $2 million of the loss related to the settled interest rate swaps for the year ended December 31, 2019 . We will amortize into income approximately $4 million of the net loss on the interest rate swaps during 2020. The table below presents our interest rate swap derivative positions as of December 31, 2019 and 2018 , respectively, including the location of the net derivative positions on our consolidated balance sheets: As of December 31, 2019 Current Liabilities (Millions) Designated as hedging instruments Derivative liabilities $ — As of December 31, 2018 (Millions) Designated as hedging instruments Derivative liabilities $ (16 ) The effect of derivatives in cash flow hedging relationships on accumulated OCI for the years ended December 31, 2019 and 2018 , respectively, consisted of: Years Ended December 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) 2019 Interest rate contracts $ (24 ) Interest expense $ 2 $ 306 2018 Interest rate contracts $ (16 ) Interest expense $ — $ 303 (a) Changes in OCI are reported on a pre-tax basis. The amount in accumulated OCI is being reclassified into earnings over the underlying debt maturity period which ends in 2029. On January 31, 2020, AVANGRID entered into two forward interest rate swaps, with a total notional amount of $600 million , to hedge the issuance of forecasted fixed rate debt in the first quarter of 2020. The forward interest rate swaps are designated and qualify as cash flow hedges, have mandatory termination dates of March 31, 2020, and are expected to be settled upon the forecasted debt issuance. The gains or losses on the interest rate swap derivatives will be reported as a component of accumulated OCI and reclassified into earnings in the period or periods during which the related interest expense of the forecasted debt is incurred. (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 rating on senior debt were to fall below investment grade. If such an event had occurred as of December 31, 2019 , UI would have had to post an aggregate of approximately $18 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. The amount of cash collateral under master netting arrangements that has not been offset against net derivative positions was $21 million and $26 million as of December 31, 2019 and 2018 , respectively. Derivative instruments settlements and collateral payments are included throughout the "Changes in operating assets and liabilities" section of operating activities in the 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 December 31, 2019 is $28 million , for which we have posted collateral.

Leases

Leases	12 Months Ended
	Dec. 31, 2019
Leases [Abstract]
Leases	Leases We have operating leases for office buildings, facilities, vehicles and certain equipment. Our finance leases are primarily related to electric generation, and certain buildings, vehicles and equipment. Certain of our lease agreements include rental payments adjusted periodically for inflation or are based on other periodic input measures. Our leases do not contain any material residual value guarantees or material restrictive covenants. Our leases have remaining lease terms of 1 year to 64 years , some of which may include options to extend the leases for up to 40 years , and some of which may include options to terminate. We consider extension or termination options in the lease term if it is reasonably certain we will exercise the option. The components of lease cost for the year ended December 31, 2019 were as follows: For the Year Ended December 31, 2019 (Millions) Lease cost Finance lease cost Amortization of right-of-use assets $ 12 Interest on lease liabilities 3 Total finance lease cost 15 Operating lease cost 18 Short-term lease cost 5 Variable lease cost 2 Total lease cost $ 40 Balance sheet and other information for the year ended December 31, 2019 was as follows: As of December 31, 2019 (Millions, except lease term and discount rate) Operating Leases Operating lease right-of-use assets $ 70 Operating lease liabilities, current 12 Operating lease liabilities, long-term 65 Total operating lease liabilities $ 77 Finance Leases Other assets $ 133 Other current liabilities 9 Other non-current liabilities 54 Total finance lease liabilities $ 63 Weighted-average Remaining Lease Term (years) Finance leases 7.59 Operating leases 12.98 Weighted-average Discount Rate Finance leases 5.35 % Operating leases 3.62 % For the year ended December 31, 2019 , supplemental cash flow information related to leases was as follows: For the Year Ended December 31, 2019 (Millions) Cash paid for amounts included in the measurement of lease liabilities: Operating cash flows from operating leases $ 13 Operating cash flows from finance leases $ 3 Financing cash flows from finance leases $ 27 Right-of-use assets obtained in exchange for lease obligations: Finance leases $ 1 Operating leases $ 3 As of December 31, 2019 , maturities of lease liabilities were as follows: Finance Leases Operating Leases (Millions) Year ending December 31, 2020 $ 10 $ 14 2021 7 13 2022 3 10 2023 50 7 2024 — 6 Thereafter 2 51 Total lease payments 72 101 Less: imputed interest (9 ) (24 ) Total $ 63 $ 77 Renewables has a sale-leaseback arrangement (as a seller-lessee) on a solar generation facility. The finance lease liability outstanding (including the current portion thereof) was $50 million and $52 million at December 31, 2019 and December 31, 2018 , respectively. In 2013, Renewables sold the generation facility to a consortium of buyers (referred to as “Trusts”) and simultaneously entered into an agreement with the Trusts for the right to use the facility for up to 15 years with an early buyout option in year 10 . The gain on the sale of the generation facility was deferred and is being amortized to depreciation expense over the 25 -year life of the facility. Most of our leases do not provide an implicit rate in the lease; thus we use our incremental borrowing rate based on the information available at the commencement date in determining the present value of lease payments. We used the incremental borrowing rate on January 1, 2019, for operating leases that commenced prior to that date. Comparative 2018 and 2017 Leases Disclosures The following are the 2018 annual lease disclosures, presented in accordance with ASC 840. Operating lease expense relating to operational facilities, office building leases and vehicle and equipment leases was $59 million , $72 million and $71 million for the years ended December 31, 2018, 2017 and 2016, respectively. Amounts related to contingent payments predominantly linked to electricity generation at the respective facilities were $11 million , $19 million and $22 million for the years ended December 31, 2018, 2017 and 2016, respectively. Leases for most of the land on which wind farm facilities are located have various renewal and termination clauses. On January 16, 2014, as required by the NYPSC, NYSEG renewed a Reliability Support Services Agreement (RSS Agreement) with Cayuga Operating Company, LLC (Cayuga) for Cayuga to provide reliability support services to maintain necessary system reliability through June 2017. Cayuga owns and operates the Cayuga Generating Facility (Facility), a coal-fired generating station that includes two generating units. Cayuga operates and maintains the RSS units and manages and complies with scheduling deadlines and requirements for maintaining the Facility and the RSS units as eligible energy and capacity providers and complies with dispatch instructions. NYSEG paid Cayuga a monthly fixed price and also paid for capital expenditures for specified capital projects. NYSEG was entitled to a share of any capacity and energy revenues earned by Cayuga. We accounted for this arrangement as an operating lease. The net expense incurred under this operating lease was $18 million for the year ended December 31, 2017, and $38 million for the year ended December 31, 2016. On October 21, 2015, RG&E, GNPP and multiple intervenors filed a joint proposal with the regulator for approval of the modified RSS Agreement for the continued operation of the Ginna Facility. On February 23, 2016, the NYPSC unanimously adopted the joint proposal, which provided for a term of the RSSA from April 1, 2015, through March 31, 2017 and RG&E monthly payments to GNPP in the amount of $15 million . RG&E was entitled to 70% of revenues from GNPP’s sales into the energy and capacity markets, while GNPP was entitled to 30% of such revenues. We accounted for this arrangement as an operating lease. The net expense incurred under this operating lease was $6 million for the year ended December 31, 2017, and $115 million for the year ended December 31, 2016. Total future minimum lease payments as of December 31, 2018 consisted of: Year Operating Leases Capital Leases Total (Millions) 2019 $ 31 $ 30 $ 61 2020 39 10 49 2021 38 7 45 2022 35 2 37 2023 33 50 83 Thereafter 735 2 737 Total $ 911 $ 101 $ 1,012
Leases	Leases We have operating leases for office buildings, facilities, vehicles and certain equipment. Our finance leases are primarily related to electric generation, and certain buildings, vehicles and equipment. Certain of our lease agreements include rental payments adjusted periodically for inflation or are based on other periodic input measures. Our leases do not contain any material residual value guarantees or material restrictive covenants. Our leases have remaining lease terms of 1 year to 64 years , some of which may include options to extend the leases for up to 40 years , and some of which may include options to terminate. We consider extension or termination options in the lease term if it is reasonably certain we will exercise the option. The components of lease cost for the year ended December 31, 2019 were as follows: For the Year Ended December 31, 2019 (Millions) Lease cost Finance lease cost Amortization of right-of-use assets $ 12 Interest on lease liabilities 3 Total finance lease cost 15 Operating lease cost 18 Short-term lease cost 5 Variable lease cost 2 Total lease cost $ 40 Balance sheet and other information for the year ended December 31, 2019 was as follows: As of December 31, 2019 (Millions, except lease term and discount rate) Operating Leases Operating lease right-of-use assets $ 70 Operating lease liabilities, current 12 Operating lease liabilities, long-term 65 Total operating lease liabilities $ 77 Finance Leases Other assets $ 133 Other current liabilities 9 Other non-current liabilities 54 Total finance lease liabilities $ 63 Weighted-average Remaining Lease Term (years) Finance leases 7.59 Operating leases 12.98 Weighted-average Discount Rate Finance leases 5.35 % Operating leases 3.62 % For the year ended December 31, 2019 , supplemental cash flow information related to leases was as follows: For the Year Ended December 31, 2019 (Millions) Cash paid for amounts included in the measurement of lease liabilities: Operating cash flows from operating leases $ 13 Operating cash flows from finance leases $ 3 Financing cash flows from finance leases $ 27 Right-of-use assets obtained in exchange for lease obligations: Finance leases $ 1 Operating leases $ 3 As of December 31, 2019 , maturities of lease liabilities were as follows: Finance Leases Operating Leases (Millions) Year ending December 31, 2020 $ 10 $ 14 2021 7 13 2022 3 10 2023 50 7 2024 — 6 Thereafter 2 51 Total lease payments 72 101 Less: imputed interest (9 ) (24 ) Total $ 63 $ 77 Renewables has a sale-leaseback arrangement (as a seller-lessee) on a solar generation facility. The finance lease liability outstanding (including the current portion thereof) was $50 million and $52 million at December 31, 2019 and December 31, 2018 , respectively. In 2013, Renewables sold the generation facility to a consortium of buyers (referred to as “Trusts”) and simultaneously entered into an agreement with the Trusts for the right to use the facility for up to 15 years with an early buyout option in year 10 . The gain on the sale of the generation facility was deferred and is being amortized to depreciation expense over the 25 -year life of the facility. Most of our leases do not provide an implicit rate in the lease; thus we use our incremental borrowing rate based on the information available at the commencement date in determining the present value of lease payments. We used the incremental borrowing rate on January 1, 2019, for operating leases that commenced prior to that date. Comparative 2018 and 2017 Leases Disclosures The following are the 2018 annual lease disclosures, presented in accordance with ASC 840. Operating lease expense relating to operational facilities, office building leases and vehicle and equipment leases was $59 million , $72 million and $71 million for the years ended December 31, 2018, 2017 and 2016, respectively. Amounts related to contingent payments predominantly linked to electricity generation at the respective facilities were $11 million , $19 million and $22 million for the years ended December 31, 2018, 2017 and 2016, respectively. Leases for most of the land on which wind farm facilities are located have various renewal and termination clauses. On January 16, 2014, as required by the NYPSC, NYSEG renewed a Reliability Support Services Agreement (RSS Agreement) with Cayuga Operating Company, LLC (Cayuga) for Cayuga to provide reliability support services to maintain necessary system reliability through June 2017. Cayuga owns and operates the Cayuga Generating Facility (Facility), a coal-fired generating station that includes two generating units. Cayuga operates and maintains the RSS units and manages and complies with scheduling deadlines and requirements for maintaining the Facility and the RSS units as eligible energy and capacity providers and complies with dispatch instructions. NYSEG paid Cayuga a monthly fixed price and also paid for capital expenditures for specified capital projects. NYSEG was entitled to a share of any capacity and energy revenues earned by Cayuga. We accounted for this arrangement as an operating lease. The net expense incurred under this operating lease was $18 million for the year ended December 31, 2017, and $38 million for the year ended December 31, 2016. On October 21, 2015, RG&E, GNPP and multiple intervenors filed a joint proposal with the regulator for approval of the modified RSS Agreement for the continued operation of the Ginna Facility. On February 23, 2016, the NYPSC unanimously adopted the joint proposal, which provided for a term of the RSSA from April 1, 2015, through March 31, 2017 and RG&E monthly payments to GNPP in the amount of $15 million . RG&E was entitled to 70% of revenues from GNPP’s sales into the energy and capacity markets, while GNPP was entitled to 30% of such revenues. We accounted for this arrangement as an operating lease. The net expense incurred under this operating lease was $6 million for the year ended December 31, 2017, and $115 million for the year ended December 31, 2016. Total future minimum lease payments as of December 31, 2018 consisted of: Year Operating Leases Capital Leases Total (Millions) 2019 $ 31 $ 30 $ 61 2020 39 10 49 2021 38 7 45 2022 35 2 37 2023 33 50 83 Thereafter 735 2 737 Total $ 911 $ 101 $ 1,012

Commitments and Contingent Liab

Commitments and Contingent Liabilities	12 Months Ended
	Dec. 31, 2019
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingent Liabilities	Commitments and Contingent Liabilities 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 likely 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 New England Transmission Owners (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 with refunds to customers for the 15 -month refund periods beginning October 1, 2011 (Complaint I), December 27, 2012 (Complaint II), July 31, 2014 (Complaint III) and April 29, 2016 (Complaint IV). On October 16, 2014, the FERC issued its decision in Complaint I setting the base ROE at 10.57% and a maximum total ROE of 11.74% (base plus incentive ROEs) for the October 2011 – December 2012 period as well as prospectively from October 16, 2014. On March 3, 2015, the FERC upheld its decision and further clarified that the 11.74% ROE cap will be applied on a project specific basis and not on a transmission owner’s total average transmission return. The complaints were consolidated and the administrative law judge issued an initial decision on March 22, 2016. The initial decision determined that, (1) for the fifteen month refund period in Complaint II, the base ROE should be 9.59% and that the ROE Cap (base ROE plus incentive ROEs) should be 10.42% and (2) for the fifteen month refund period in Complaint III and prospectively, the base ROE should be 10.90% and that the ROE Cap should be 12.19% . The initial decision in Complaints II and III is the administrative law judge’s recommendation to the FERC Commissioners. CMP and UI reserved for refunds for Complaints I, II and III consistent with the FERC’s March 3, 2015 decision in Complaint I. Refunds were provided to customers for Complaint I. The CMP and UI total reserve associated with Complaints II and III is $25 million and $7 million , respectively, as of December 31, 2019 , which has not changed since December 31, 2018, except for the accrual of carrying costs. If adopted as final by the FERC, the impact of the initial decision by the FERC administrative law judge would be an additional aggregate reserve for Complaints II and III of $17 million , which is based upon currently available information for these proceedings. Following various intermediate hearings, orders and appellate decisions, 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 the FERC (the October 2018 Order). The FERC proposes to use this new methodology to resolve Complaints I, II, III and IV filed by the New England state consumer advocates. The new proposed ROE methodology set forth in the October 2018 Order considers more than just the two-step discounted cash flow (DCF) analysis adopted in the FERC order on Complaint I vacated by the Court. The new proposed ROE methodology uses three financial analyses (i.e., DCF, the capital-asset pricing model and the expected earnings analysis) to produce a range of returns to narrow the zone of reasonableness when assessing whether a complainant has met its initial burden of demonstrating that the utility’s existing ROE is unjust and unreasonable. The new proposed ROE methodology establishes a range of just and reasonable ROEs of 9.60% to 10.99% and proposes a just and reasonable base ROE of 10.41% with a new ROE cap of 13.08% . Pursuant to the October 2018 Order, the NETOs filed initial briefs on the proposed methodology in all four Complaints on January 11, 2019 and replied to the initial briefs on March 8, 2019. On November 21, 2019, the FERC issued rulings on two complaints challenging the base return on equity for Midcontinent Independent System Operator, or MISO transmission owners. These rulings established a new zone of reasonableness based on equal weighting of the DCF and capital-asset pricing model for establishing the base return on equity. This resulted in a base return on equity of 9.88% as the midpoint of the zone of reasonableness. Various parties have requested rehearing on this decision. We cannot predict the outcome of this proceeding, and the potential impact it may have in establishing a precedent for our pending four Complaints. California Energy Crisis Litigation Two California agencies brought a complaint in 2001 against a long-term PPA entered into by Renewables, as seller, to the California Department of Water Resources, as purchaser, alleging that the terms and conditions of the PPA were unjust and unreasonable. The FERC dismissed Renewables from the proceedings; however, the Ninth Circuit Court of Appeals reversed the FERC's dismissal of Renewables from the proceeding. Joining with two other parties, Renewables filed a petition for certiorari in the United States Supreme Court on May 3, 2007. In an order entered on June 27, 2008, the Supreme Court granted Renewables’ petition for certiorari, vacated the appellate court's judgment, and remanded the case to the appellate court for further consideration in light of the Supreme Court’s decision in a similar case. In light of the Supreme Court's order, on December 4, 2008, the Ninth Circuit Court of Appeals vacated its prior opinion and remanded the complaint proceedings to the FERC for further proceedings consistent with the Supreme Court's rulings. In 2014, the FERC assigned an administrative law judge to conduct evidentiary hearings. Following discovery, the FERC trial staff recommended that the complaint against Renewables be dismissed. A hearing was held before a FERC administrative law judge in November and early December 2015. A preliminary proposed ruling by the administrative law judge was issued on April 12, 2016. The proposed ruling found no evidence that Renewables had engaged in any unlawful market conduct that would justify finding the Renewables PPAs unjust and unreasonable. However, the proposed ruling did conclude that the price of the PPAs imposed an excessive burden on customers in the amount of $259 million . Renewables position, as presented at hearings and agreed by the FERC trial staff, is that Renewables entered into bilateral power purchase contracts appropriately and complied with all applicable legal standards and requirements. The parties have submitted briefs on exceptions to the administrative law judge’s proposed ruling to the FERC. There is no specific timetable for the FERC’s ruling. In April 2018, Renewables requested, based on the nearly two years of delay from the preliminary proposed ruling and the Supreme Court precedent, that the FERC issue a final decision expeditiously. We cannot predict the outcome of this proceeding. New York State Department of Public Service Investigation of the Preparation for and Response to the March 2018 Winter Storms In March 2018, following two severe winter storms that impacted more than a million electric utility customers in New York, including 520,000 NYSEG and RG&E customers, the New York State Department of Public Service (NYDPS) commenced a comprehensive investigation of the preparation and response to those events by New York's major electric utility companies. The investigation was expanded in the spring of 2018 to include other 2018 New York spring storm events. On April 18, 2019, the NYDPS staff issued a report (the 2018 Staff Report) of the findings from their investigation. The 2018 Staff Report identified 94 recommendations for corrective actions to be implemented in the utilities Emergency Response Plans, or ERPs. The report also identified potential violations by several of the utilities, including NYSEG and RG&E. Also on April 18, 2019, the NYPSC issued an Order Instituting Proceeding and to Show Cause directed to all major electric utilities in New York, including NYSEG and RG&E. The order directs the utilities, including NYSEG and RG&E, to show cause why the NYPSC should not pursue civil and/or administrative penalties for the apparent failure to follow their respective ERPs as approved and mandated by the NYPSC. The NYPSC also directs the utilities, within 30 days , to address whether the NYPSC should mandate, reject or modify in whole or in part, the 94 recommendations contained in the 2018 Staff Report. On May 20, 2019, NYSEG and RG&E responded to the portion of the Order to Show Cause with respect to the recommendations contained in the 2018 Staff Report. The Commission granted the companies a series of extensions to respond to the portion of the Order to Show Cause with respect to why the Commission should not pursue a penalty action. A petition requesting Commission approval of a joint settlement agreement was filed with the Commission on December 17, 2019. On February 6, 2020, the Commission approved the joint settlement agreement, which allows the companies to avoid litigation and provides for payment by the companies of penalty of $10.5 million . NYPSC directs Counsel to commence Judicial Enforcement Proceeding against NYSEG On April 18, 2019, the NYPSC issued an Order Directing Counsel to the Commission to commence a special proceeding or an action in New York State Supreme Court to stop and prevent ongoing future violations by NYSEG of NYPSC regulations and orders. On December 24, 2019, the Commission filed a verified petition to commence the action against NYSEG. At the same time, NYSEG and the Commission settled the causes of action asserted in the verified petition and entered into a consent and stipulation and also submitted a joint motion to the court requesting that the court approve and enter a consent order and judgment reflecting the settlement. The consent order and judgment was issued by the court on January 24, 2020. Class Actions Regarding LDC Gas Transportation Service on Algonquin Gas Transmission Breiding et al. v. Eversource and Avangrid - Class Action . On November 16, 2017, a class action lawsuit was filed in the U.S. District Court for the District of Massachusetts on behalf of customers in New England against the Company and Eversource alleging that certain of their respective subsidiaries that take gas transportation service over the Algonquin Gas Transmission (AGT), which for AVANGRID would be its indirect subsidiaries SCG and CNG, engaged in pipeline capacity scheduling practices on AGT that resulted in artificially increased electricity prices in New England. These allegations were based on the conclusions of a whitepaper issued by the Environmental Defense Fund (EDF), an environmental advocacy organization, on October 10, 2017, purporting to analyze the relationship between the New England electricity market and the New England local gas distribution companies. The plaintiffs assert claims under federal antitrust law, state antitrust, unfair competition and consumer protection laws, and under the common law of unjust enrichment. They seek damages, disgorgement, restitution, injunctive relief and attorney fees and costs. On February 27, 2018, the FERC released the results of a FERC staff inquiry into the pipeline capacity scheduling practices on the AGT. The inquiry arose out of the allegations made by the EDF in its whitepaper. The FERC announced that, based on an extensive review of public and non-public data, it had determined that the EDF study was flawed and led to incorrect conclusions. FERC also stated that the staff inquiry revealed no evidence of anticompetitive withholding of natural gas pipeline capacity on the AGT and that it would take no further action on the matter. On April 27, 2018, the Company filed a Motion to Dismiss all of the claims based on federal preemption and lack of any evidence of antitrust behavior, citing, among other reasons, the results of the FERC staff inquiry conclusion. The plaintiffs filed opposition to the motion to dismiss on May 25, 2018. On September 11, 2018, the District Court granted the Company’s Motion and dismissed all claims. On January 29, 2019, the plaintiffs filed a brief in support of appeal and on April 26, 2019, the Company and Eversource filed a joint brief in opposition. On May 17, 2019, the plaintiffs filed a reply to the opposition. On September 18, 2019, the First Circuit Court of Appeals affirmed the district court’s dismissal of the plaintiff’s claims. The plaintiffs filed a motion seeking en banc review on October 16, 2019. On November 15, 2019, the First Circuit Court of Appeals denied the motion. PNE Energy Supply LLC v. Eversource Energy and Avangrid, Inc. - Class Action . On August 10, 2018, PNE Energy Supply LLC, a competitive energy supplier located in New England that purchases electricity in the day-ahead and real time wholesale electric market, filed a civil antitrust action, on behalf of itself and those similarly situated, against the Company and Eversource alleging that their respective gas subsidiaries illegally manipulated the supply of pipeline capacity in the “secondary capacity market” in order to artificially inflate New England natural gas and electricity prices. These allegations were also based on the conclusions of the whitepaper issued by EDF. The plaintiff claims to represent entities who purchased electricity directly in the wholesale electricity market that it claims was targeted by the alleged anticompetitive conduct of Eversource and the Company. On September 28, 2018, the Company filed a Motion to Dismiss all of the claims based on federal preemption and lack of any evidence of antitrust behavior, citing, among other reasons, the results of the FERC staff inquiry and the dismissal of the related case, "Breiding et al. v. Eversource and Avangrid," by the same court in September. The plaintiffs filed opposition to the motion to dismiss on October 26, 2018 and the Company filed a reply on November 15, 2018. The district court heard oral arguments on the motion to dismiss on January 18, 2019. On April 26, 2019, the Company filed a brief in support of its motion to dismiss, and on June 7, 2019, the district court granted the Company’s Motion to Dismiss and dismissed all claims. On July 3, 2019, the plaintiffs filed notice of appeal in the U.S. Court of Appeals for the First Circuit and, on October 18, 2019, filed a brief in support of appeal. We cannot predict the outcome of this class action lawsuit. Yankee Nuclear Spent Fuel Disposal Claim CMP has an ownership interest in Maine Yankee Atomic Power Company, Connecticut Yankee Atomic Power Company and Yankee Atomic Electric Company (the Yankee Companies), three New England single-unit decommissioned nuclear reactor sites, and UI has an ownership interest in Connecticut Yankee Atomic Power Company. Pursuant to the statute of limitations, the Yankee Companies file a lawsuit periodically to recover damages from the Department of Energy (DOE) for breach of the Nuclear Spent Fuel Disposal Contract to remove spent nuclear fuel and greater than class C waste as required by contract. On May 22, 2017, the Yankee Companies filed a next case in the Federal Court of Claims (Court), seeking damages for the period from January 1, 2013 through December 31, 2016. The Court issued its decision on the trial on February 21, 2019, awarding the Yankee Companies a combined $103 million (Connecticut Yankee $41 million , Maine Yankee $34 million and Yankee Atomic $28 million ) and on April 23, 2019, the award became final. The damage awards are returned to customers either through customer refunds or by reducing future costs. Refunds or reductions in costs are reflected in the Yankee Companies billings to shareholders, including CMP and UI. CMP and UI received their proportionate share of the awards, based on percentage of ownership, totaling $8 million which will be returned to customers. Gas Storage Indemnification Claims On May 1, 2018, ARHI closed a transaction to sell our gas storage business to Amphora Gas Storage USA, LLC. On October 30, 2019, ARHI received notice of a claim for indemnification from Amphora Gas Storage USA, LLC under the purchase agreement with respect to such sale in the amount of approximately $20 million related to, among other things, certain alleged violations of occupational, health and safety requirements, the condition and sufficiency of assets and a third party intellectual property infringement claim. Pursuant to the terms of the purchase agreement, the aggregate amount for which ARHI may be responsible to indemnify Amphora Gas Storage USA, LLC for all claims arising under the purchase agreement, other than those related to certain fundamental representations, tax matters and claims involving fraud, shall not exceed 15% of the purchase price, or approximately $10 million . We cannot predict the outcome of this matter. Power, Gas and Other Arrangements Power and Gas Supply Arrangements – Networks NYSEG and RG&E are the providers of last resort for customers. As a result, the companies buy physical energy and capacity from the NYISO. In accordance with the NYPSC's February 26, 2008 Order, NYSEG and RG&E are required to hedge on behalf of non-demand billed customers. The physical electric capacity purchases we make from parties other than the NYISO are to comply with the hedge requirement for electric capacity. The companies enter into financial swaps to comply with the hedge requirement for physical electric energy purchases. Other purchases, from some Independent Power Producers (IPPs) and NYPA are from contracts entered into many years ago when the companies made purchases under contract as part of their supply portfolio to meet their load requirement. More recent IPP purchases are required to comply with the companies’ Public Utility Regulatory Policies Act (PURPA) purchase obligation. NYSEG, RG&E, SCG, CNG and BGC (collectively, the Regulated Gas Companies) satisfy their natural gas supply requirements through purchases from various producers and suppliers, withdrawals from natural gas storage, capacity contracts and winter peaking supplies and resources. The Regulated Gas Companies operate diverse portfolios of gas supply, firm transportation capacity, gas storage and peaking resources. Actual gas costs incurred by each of the Regulated Gas Companies are passed through to customers through state regulated purchased gas adjustment mechanisms, subject to regulatory review. The Regulated Gas Companies purchase the majority of their natural gas supply at market prices under seasonal, monthly or mid-term supply contracts and the remainder is acquired on the spot market. The Regulated Gas Companies diversify their sources of supply by amount purchased and location and primarily acquire gas at various locations in the U.S. Gulf of Mexico region, in the Appalachia region and in Canada. The Regulated Gas Companies acquire firm transportation capacity on interstate pipelines under long-term contracts and utilize that capacity to transport both natural gas supply purchased and natural gas withdrawn from storage to the local distribution system. The Regulated Gas Companies acquire firm underground natural gas storage capacity using long-term contracts and fill the storage facilities with gas in the summer months for subsequent withdrawal in the winter months. Winter peaking resources are primarily attached to the local distribution systems and are either owned or are contracted for by the Regulated Gas Companies, each of which is a Local Distribution Company. Each Regulated Gas Company owns or has rights to the natural gas stored in an LNG facility directly attached to its distribution system. Other arrangements include contractual obligations for property, plant and equipment, material and services on order but not yet delivered at December 31, 2019 . Power, Gas and Other Arrangements – Renewables Gas purchase commitments consist of firm transport capacity to fuel the Cogen and Peaking gas generators. Power purchase commitments include the following: (i) a 55 MW Biomass PPA for 12 years ( two years remaining) with a guaranteed output of 34.4 MW flat and a schedule of fixed price rates depending on season and time of day, (ii) long-term firm transmission agreements with fixed monthly capacity payments that allow the delivery of electricity from wind and thermal generation sources to various customers and (iii) a 95.6 MW (average) three -year purchase of hydro capacity and energy to provide balancing services to the NW wind assets that has monthly fixed payments (beginning in 2019 and expiring in 2021) and (iv) a five -year purchase of 52 MW (average) hydro capacity and energy to provide balancing services to the NW wind assets that has monthly fixed payments (beginning in 2019 and expiring in 2023 ). Power sales commitments include: (i) a 55 MW Biomass off-take agreement for 12 years ( two years remaining) with guaranteed annual production of 34.4 MW flat with a schedule of fixed price rates depending on season and time of day, (ii) a retail renewable power sales agreement for 12 MW (average) expiring in 2026, (iii) fixed price, fixed volume power sales off the Klamath Cogen facility, (iv) a seasonal tolling arrangement off the Klamath peaking facility with fixed capacity charges through 2024; (v) fixed price, fixed volume renewable energy credit sales off merchant wind facilities, (vi) sales of merchant wind farm capacity to various ISOs and sales of ancillary services (e.g., regulation and frequency response, generator imbalance, etc.) to third parties from Renewables’ Balancing Authority. Renewables has easement contracts which are no longer considered leases under ASC 842 (see Note 3 for further details). These easement contracts still represent contractual obligations and are now included in the table below. Forward purchases and sales commitments under power, gas and other arrangements as of December 31, 2019 consisted of: Year Purchases Sales (Millions) 2020 $ 1,396 $ 192 2021 177 138 2022 87 72 2023 68 52 2024 44 39 Thereafter 830 87 Totals $ 2,602 $ 580 Guarantee Commitments to Third Parties As of December 31, 2019 , we had approximately $474 million of standby letters of credit, surety bonds, guarantees and indemnifications outstanding. These instruments provide financial assurance to the business and trading partners of AVANGRID and its subsidiaries 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 December 31, 2019 , neither we nor our subsidiaries have any liabilities recorded for these instruments.

Environmental Liabilities

Environmental Liabilities	12 Months Ended
	Dec. 31, 2019
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-five waste sites, which do not include sites where gas was manufactured in the past. Seventeen of the twenty-five sites are included in the New York State Registry of Inactive Hazardous Waste Disposal Sites; six 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, seven of the twenty-five 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 $5 million related to ten of the twenty-five sites. We have paid remediation costs related to the remaining fifteen sites and do not expect to incur additional liabilities. Additionally, we have recorded an estimated liability of $8 million related to another eleven 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. Our estimate for costs to remediate these sites ranges from $12 million to $21 million as of December 31, 2019 . 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). Eight sites are included in the New York State Registry; three sites are included in the New York State Department of Environmental Conservation Multi-Site Order on Consent; three sites are part of Maine’s Voluntary Response Action Program with two such sites part of Maine’s Uncontrolled Sites Program. The remaining sites are not included in any registry list. We have entered into consent orders with various environmental agencies to investigate and, where necessary, remediate forty-one of the fifty-three sites. Our estimate for all costs related to investigation and remediation of the fifty-three sites ranges from $164 million to $430 million as of December 31, 2019 . 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 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; no liability was recorded related to these sites as of December 31, 2019 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 December 31, 2019 and 2018 , the liability associated with our MGP sites in Connecticut, 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, was $97 million and $99 million , respectively. Our total recorded liability to investigate and perform remediation at all known inactive MGP sites discussed above and other sites was $349 million and $366 million as of December 31, 2019 and 2018 , 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 2057 . FirstEnergy NYSEG sued FirstEnergy under the Comprehensive Environmental Response, Compensation, and Liability Act to recover environmental cleanup costs at sixteen former MGP sites, which are included in the discussion above. In July 2011, the District Court issued a decision and order in NYSEG’s favor, requiring FirstEnergy to pay NYSEG approximately $60 million for past and future clean-up costs at the sixteen sites in dispute. On September 9, 2011, FirstEnergy paid NYSEG $30 million , representing their share of past costs of $27 million and pre-judgment interest of $3 million . FirstEnergy appealed the decision to the Second Circuit Court of Appeals. On September 11, 2014, the Second Circuit Court of Appeals affirmed the District Court’s decision in NYSEG’s favor, but modified the decision for nine sites, reducing NYSEG’s damages for incurred costs from $27 million to $22 million , excluding interest, and reducing FirstEnergy’s allocable share of future costs at these sites. NYSEG refunded FirstEnergy the excess $5 million in November 2014. FirstEnergy remains liable for a substantial share of clean up expenses at nine MGP sites. Based on current projections, FirstEnergy’s share is estimated at approximately $21 million . This amount is being treated as a contingent asset and has not been recorded as either a receivable or a decrease to the environmental provision. Any recovery will be flowed through to NYSEG customers. English Station In January 2012, Evergreen Power, LLC (Evergreen Power) and Asnat Realty LLC (Asnat), then owners of a former generation site on the Mill River in New Haven (the English Station site) that UI sold to Quinnipiac Energy in 2000, filed a lawsuit in federal district court in Connecticut related to environmental remediation at the English Station site. This proceeding was stayed in 2014 pending resolutions of other proceedings before the DEEP concerning the English Station site. In December 2016, the court administratively closed the file without prejudice to reopen upon the filing of a motion to reopen by any party. In December 2013, Evergreen Power and Asnat filed a subsequent lawsuit related to the English Station site. On April 16, 2018, the plaintiffs filed a revised complaint alleging fraud and unjust enrichment against UIL and UI and adding former UIL officers as named defendants alleging fraud. On February 21, 2019, the court granted our Motion to Strike with respect to all counts except for the count against UI for unjust enrichment. The counts stricken include all counts against the individual defendants as well as against UIL. The plaintiffs have appealed the court's decision to strike. We cannot predict the outcome of this matter. On April 8, 2013, DEEP issued an administrative order addressed to UI, Evergreen Power, Asnat and others, ordering the parties to take certain actions related to investigating and remediating the English Station site. This proceeding was stayed while DEEP and UI continue to work through the remediation process pursuant to the consent order described below. Status reports are periodically filed with DEEP. On August 4, 2016, DEEP issued a partial consent order (the consent order), that, subject to its terms and conditions, requires UI to investigate and remediate certain environmental conditions within the perimeter of the English Station site. 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 to be used for a public purpose as determined in the discretion of the Governor of the State of Connecticut, the Attorney General of the State of Connecticut and the Commissioner of DEEP. UI is obligated to comply with the terms of the consent order even if the cost of such compliance exceeds $30 million . Under the terms of the consent order, the state will discuss options with UI on recovering or funding any cost above $30 million such as through public funding or recovery from third parties; however, it is not bound to agree to or support any means of recovery or funding. UI has initiated its process to investigate and remediate the environmental conditions within the perimeter of the English Station site pursuant to the consent order. As of December 31, 2019 and 2018 , the amount reserved for this matter was $16 million and $20 million , respectively. We cannot predict the outcome of this matter .

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2019
Income Tax Disclosure [Abstract]
Income Taxes	Income Taxes Upon enactment of the Tax Act, the Company remeasured its existing deferred income tax balances as of December 31, 2017 to reflect the decrease in the corporate income tax rate from 35% to 21% , which resulted in a material decrease to its net deferred income tax liability balances based on reasonable estimates that could be determined at that time. The Company’s non-regulatory businesses recorded a corresponding net increase or decrease to income tax expense, while the utility operations recorded corresponding regulatory liabilities or assets to the extent that such amounts are probable of settlement or recovery through customer rates. The amount and timing of potential settlements of the established net regulatory liabilities are determined by the regulated utilities’ respective rate regulators and IRS Normalization rules. As of December 31, 2018, the Company has completed the measurement and accounting of certain effects of the Tax Act which have been reflected in the consolidated financial statements. Current and deferred taxes charged to expense (benefit) for the years ended December 31, 2019 , 2018 and 2017 consisted of: Years Ended December 31, 2019 2018 2017 (Millions) Current Federal $ 11 $ 17 $ (20 ) State (6 ) 2 12 Current taxes charged to expense (benefit) 5 19 (8 ) Deferred Federal 152 233 (124 ) State 44 (12 ) (73 ) Deferred taxes charged to expense (benefit) 196 221 (197 ) Production tax credits (57 ) (68 ) (53 ) Investment tax credits (1 ) (2 ) (1 ) Total Income Tax Expense (Benefit) $ 143 $ 170 $ (259 ) The differences between tax expense per the statements of income and tax expense at the 21% statutory federal tax rate for the years ended December 31, 2019 and 2018 and 35% statutory federal tax rate for the year ended December 31, 2017 consisted of: Years Ended December 31, 2019 2018 2017 (Millions) Tax expense at federal statutory rate $ 172 $ 161 $ 43 Depreciation and amortization not normalized (23 ) (5 ) 9 Investment tax credit amortization (1 ) (2 ) (1 ) Tax return related adjustments (2 ) (6 ) 7 Production tax credits (57 ) (68 ) (53 ) Tax equity financing arrangements 8 — (10 ) Federal tax rate impact on held for sale classification — 21 82 State tax expense (benefit), net of federal benefit 30 (8 ) (40 ) Tax Act - remeasurement — 46 (328 ) Other, net 16 31 32 Total Income Tax Expense (Benefit) $ 143 $ 170 $ (259 ) Deferred tax assets and liabilities as of December 31, 2019 and 2018 consisted of: As of December 31, 2019 2018 (Millions) Deferred Income Tax Liabilities (Assets) Property related $ 4,007 $ 3,787 Unfunded future income taxes 101 107 Federal and state tax credits (632 ) (691 ) Federal and state NOL’s (989 ) (993 ) Joint ventures/partnerships 136 132 Nontaxable grant revenue (335 ) (354 ) Pension and other post-retirement benefits 43 8 Tax Act - tax on regulatory remeasurement (409 ) (393 ) Valuation allowance 33 23 Other (141 ) (102 ) Deferred Income Tax Liabilities 1,814 1,524 Classified as regulatory assets — (6 ) Total Deferred Income Tax Liabilities $ 1,814 $ 1,530 Deferred tax assets $ 2,506 $ 2,533 Deferred tax liabilities 4,320 4,057 Net Accumulated Deferred Income Tax Liabilities $ 1,814 $ 1,524 As of December 31, 2019 , we had gross federal tax net operating losses of $3.6 billion , federal renewable energy and investment tax credits, federal R&D tax credits and other federal credits of $600 million , state tax effected net operating losses of $289 million in several jurisdictions and miscellaneous state tax credits of $142 million available to carry forward and reduce future income tax liabilities. We recognized a valuation allowance of $33 million . The federal net operating losses begin to expire in 2028, while the federal tax credits begin to expire in 2023. The more significant state net operating losses begin to expire in 2021. Valuation allowances are recorded to reduce deferred tax assets when it is more likely than not that all or a portion of a tax benefit will not be realized. The valuation allowance for deferred tax assets as of December 31, 2019 and 2018 was $33 million and $23 million , respectively. Valuation allowances have been established on various federal tax credits, state net operating losses and state tax credit carryforwards. The Company has recorded a federal valuation allowance on its federal tax credit carryforwards of $4 million and has recorded a state valuation allowance on its state net operating losses and state tax credit carryforwards of $29 million . The $10 million increase in valuation allowance from 2018 to 2019 includes an increase of $4 million for additional valuation allowance on Federal tax credit carryforwards and an increase of $6 million on state net operating losses and state tax credits. The reconciliation of unrecognized income tax benefits for the years ended December 31, 2019 , 2018 and 2017 consisted of: Years ended December 31, 2019 2018 2017 (Millions) Beginning Balance $ 153 $ 45 $ 40 Increases for tax positions related to prior years 14 111 23 Increases for tax positions related to current year 16 — — Decreases for tax positions related to prior years (18 ) (3 ) (16 ) Reduction for tax position related to settlements with taxing authorities (17 ) — (2 ) Ending Balance $ 148 $ 153 $ 45 Unrecognized income tax benefits represent income tax positions taken on income tax returns but not yet recognized in the consolidated financial statements. The accounting guidance for uncertainty in income taxes provides that the financial effects of a tax position shall initially be recognized when it is more likely than not based on the technical merits the position will be sustained upon examination, assuming the position will be audited and the taxing authority has full knowledge of all relevant information. Accruals for interest and penalties on tax reserves were immaterial for the years ended December 31, 2019 , 2018 and 2017 . If recognized, $98 million of the total gross unrecognized tax benefits would affect the effective tax rate. It is estimated that no unrecognized tax benefits are anticipated to result in a net increase or decrease within twelve months of December 31, 2019 . AVANGRID and its subsidiaries, without ARHI, have been audited for the federal tax years 1998 through 2009. The results of these audits, net of reserves already provided, were immaterial. Tax years 2010 and forward are open for potential federal adjustments. All New York state returns, which were filed without ARHI, are closed through 2011 and Maine state returns are closed through 2015. All federal tax returns filed by ARHI from the periods ended March 31, 2004, to December 31, 2009, are closed for adjustment. All New York combined state returns are closed for adjustment through 2011. Generally, the adjustment period for the individual states we filed in is at least as long as the federal period. As of December 31, 2019 , UIL is subject to audit of its federal tax return for years 2014 through its short period 2015. UIL income tax years 2011 through its short period in 2015 are open and subject to Connecticut and Massachusetts audit.

Post-retirement and Similar Obl

Post-retirement and Similar Obligations	12 Months Ended
	Dec. 31, 2019
Retirement Benefits [Abstract]
Post-retirement and Similar Obligations	Post-retirement and Similar Obligations Networks has funded noncontributory defined benefit pension plans that cover eligible Networks employees and retirees. The plans provide defined benefits based on years of service and final average salary for employees hired before 2002. Most employees hired in 2002, or later based upon the plan, are covered under a cash balance plan or formula where their benefit accumulates based on a percentage of annual salary and credited interest. During 2013, Networks announced that they would discontinue, effective December 31, 2013, the cash balance accruals for all non-union employees covered under the cash balance plans or formula. At the same time, the plans were closed to newly-hired non-union employees. The plans had been closed to newly-hired union employees in prior years. CMP’s unionized employees covered under a cash balance plan ceased to receive accruals as of December 31, 2014. NYSEG’s unionized employees covered under the cash balance plans ceased to receive accruals as of December 31, 2015. Their earned balances will continue to accrue interest but will no longer be increased by a flat dollar amount or percentage of pay, as defined by the plan. Instead, they will receive a contribution to their account under their respective company’s defined contribution plan. There was no change to the defined benefit plans for employees covered under the plans that provide defined benefits based on years of service and final average salary. Employees not participating in a defined benefit plan are eligible to receive an enhanced or core 401(k) Company matching contribution, depending on whether they are union or non-union employees, respectively. Networks has other postretirement health care benefit plans that cover eligible employees and retirees. The plans were closed to newly-hired non-union employees at the end of 2010. The plans had been closed to union employees in prior years. The pre-Medicare-eligible healthcare plans are contributory and participants’ contributions are adjusted annually. Networks average contribution to these plans is limited at a level determined in prior periods. Except for a small group of “grandfathered” retirees, all Medicare eligible retirees that choose to participate are provided with a subsidy through a Health Reimbursement Account (HRA) to purchase coverage on the individual market. With the acquisition of UIL, Networks also includes pension and other postretirement plans of UIL operating utility companies. The UI pension plans cover about one half of employees of UIL. The plan was closed to newly-hired employees in 2005. UI also has a non-qualified supplemental pension plan for certain employees. The Regulated Gas Companies in Connecticut and Massachusetts have multiple qualified pension plans covering eligible union and management employees and retirees. The union plans are all closed to new hires, and the non-union plans were closed as of December 31, 2017. These entities also have non-qualified supplemental pension plans for certain employees and retirees. The qualified pension plans are traditional defined benefit plans or cash balance plans for those hired on or after specified dates. In some cases, neither of these plans is offered to new employees and have been replaced with enhanced 401(k) plans for those hired on or after specified dates. Employees not participating in a defined benefit plan are eligible to receive an enhanced or core 401(k) Company matching contribution. In addition to providing pension benefits, UI also provides other postretirement benefits, consisting principally of health care and life insurance benefits, for retired employees and their dependents. The plans were closed to newly-hired non-union employees at the end of April 2005 and to newly-hired union employees at the end of March 2005. The healthcare plans are contributory and participants’ contributions are adjusted annually. For Medicare eligible non-union retirees, UI provides a subsidy through an HRA for retirees to purchase coverage on the individual market. Medicare eligible union retirees have the option of receiving a subsidy through an HRA or paying contributions and participating in company-sponsored retiree health plans. SCG and CNG also have plans providing other postretirement benefits for eligible employees and retirees. The SCG plans were closed to newly-hired non-union employees at the end of 1995, the SCG plans were closed to newly-hired union employees by the end of March 2010 and to newly-hired CNG union employees by end of March 2011. These benefits consist primarily of health care, prescription drug and life insurance benefits for retired employees and their dependents. For Medicare eligible non-union retirees, SCG and CNG provide a subsidy through an HRA for retirees to purchase coverage on the individual market. Medicare eligible union retirees have the option of receiving a subsidy through an HRA or paying contributions and participating in company-sponsored retiree health plans. ARHI has a funded defined benefit pension plan for eligible employees hired prior to January 1, 2008. The benefit is based on the participant’s age, service and five years average pay at the time of the freeze date of April 30, 2011. ARHI has other postretirement health care benefit plans covering eligible retirees and employees hired prior to January 1, 2008. Health and life insurance rates are based on age and service points at the time of retirement. Effective July 1, 2019, all Medicare eligible ARHI retirees that choose to participate are provided with a subsidy through a Health Reimbursement Account (HRA) to purchase coverage on the individual market. Obligations and funded status of Networks and ARHI as of December 31, 2019 and 2018 consisted of: Pension Benefits Postretirement Benefits As of December 31, 2019 2018 2019 2018 (Millions) Change in benefit obligation Benefit obligation as of January 1, $ 3,374 $ 3,593 $ 425 $ 491 Service cost 41 44 3 4 Interest cost 130 128 16 19 Plan participants’ contributions — — — 9 Plan Amendments (2 ) — — (3 ) Actuarial loss (gain) 347 (159 ) 26 (55 ) Benefits paid (221 ) (237 ) (31 ) (41 ) Reclassified from held for sale — 5 — 1 Benefit Obligation as of December 31, 3,669 3,374 439 425 Change in plan assets Fair value of plan assets as of January 1, 2,544 2,865 148 165 Actual return (loss) on plan assets 460 (135 ) 22 (5 ) Employer contributions 65 48 16 20 Plan participants’ contributions — — — 9 Benefits paid (221 ) (237 ) (31 ) (41 ) Reclassified from held for sale — 3 — — Fair Value of Plan Assets as of December 31, 2,848 2,544 155 148 Funded Status as of December 31, $ (821 ) $ (830 ) $ (284 ) $ (277 ) Amounts recognized as of December 31, 2019 and 2018 consisted of: Pension Benefits Postretirement Benefits As of December 31, 2019 2018 2019 2018 (Millions) Current liabilities $ — $ — $ (5 ) $ (5 ) Non-current liabilities (821 ) (830 ) (279 ) (272 ) Total $ (821 ) $ (830 ) $ (284 ) $ (277 ) Amounts recognized in OCI for ARHI for the years ended December 31, 2019 , 2018 and 2017 , consisted of: Pension Benefits Postretirement Benefits Years Ended December 31, 2019 2018 2017 2019 2018 2017 (Millions) Net loss (gain) $ 23 $ 24 $ 25 $ (8 ) $ (7 ) $ (4 ) We have determined that all Networks’ regulated operating companies are allowed to defer as regulatory assets or regulatory liabilities items that would have otherwise been recorded in accumulated OCI pursuant to the accounting requirements concerning defined benefit pension and other postretirement plans. Amounts recognized as regulatory assets or regulatory liabilities for Networks for the years ended December 31, 2019 , 2018 and 2017 consisted of: Pension Benefits Postretirement Benefits Years Ended December 31, 2019 2018 2017 2019 2018 2017 (Millions) Net loss (gain) $ 706 $ 762 $ 737 $ 13 $ (8 ) $ 35 Prior service cost (credit) $ 4 $ 4 $ 6 $ (21 ) $ (25 ) $ (31 ) Our accumulated benefit obligation (ABO) for all defined benefit pension plans of Networks and ARHI was $3,451 million and $3,174 million as of December 31, 2019 and 2018 , respectively. CMP’s and NYSEG’s postretirement benefits were partially funded as of December 31, 2019 and 2018 . The projected benefit obligation (PBO) and the ABO exceeded the fair value of pension plan assets for all plans of Networks and ARHI as of December 31, 2019 and 2018 . The aggregate PBO and ABO and the fair value of plan assets for underfunded plans of Networks and ARHI as of December 31, 2019 and 2018 consisted of: PBO in excess of plan assets As of December 31, 2019 2018 (Millions) Projected benefit obligation $ 3,669 $ 3,374 Fair value of plan assets $ 2,848 $ 2,544 ABO in excess of plan assets As of December 31, 2019 2018 (Millions) Accumulated benefit obligation $ 3,451 $ 3,174 Fair value of plan assets $ 2,848 $ 2,544 Components of Networks’ net periodic benefit cost and other changes in plan assets and benefit obligations recognized in income and regulatory assets and liabilities for the years ended December 31, 2019 , 2018 and 2017 consisted of: (Millions) Pension Benefits Postretirement Benefits For the years ended December 31, 2019 2018 2017 2019 2018 2017 Net Periodic Benefit Cost: Service cost $ 41 $ 44 $ 42 $ 3 $ 4 $ 5 Interest cost 128 126 137 16 18 21 Expected return on plan assets (190 ) (199 ) (195 ) (7 ) (8 ) (8 ) Amortization of prior service (benefit) cost (1 ) 1 2 (10 ) (9 ) (9 ) Amortization of net loss 113 149 126 1 6 5 Net Periodic Benefit Cost 91 121 112 3 11 14 Other changes in plan assets and benefit obligations recognized in regulatory assets and regulatory liabilities: Net loss (gain) 80 175 3 13 (37 ) (5 ) Amortization of net loss (113 ) (149 ) (126 ) (1 ) (6 ) (5 ) Current year prior service cost (2 ) — — — (3 ) — Amortization of prior service benefit (cost) 1 (1 ) (2 ) 10 9 9 Total Other Changes (34 ) 25 (125 ) 22 (37 ) (1 ) Total Recognized $ 57 $ 146 $ (13 ) $ 25 $ (26 ) $ 13 Components of ARHI’s net periodic benefit cost and other changes in plan assets and benefit obligations recognized in income and OCI for the years ended December 31, 2019 , 2018 and 2017 consisted of: (Millions) Pension Benefits Postretirement Benefits For the years ended December 31, 2019 2018 2017 2019 2018 2017 Net Periodic Benefit Cost: Service cost $ 1 $ — $ — $ — $ — $ — Interest cost 2 2 2 — 1 1 Expected return on plan assets (2 ) (2 ) (2 ) — — — Amortization of net loss (gain) 1 1 1 (1 ) — — Settlement charge — 1 — — — — Net Periodic Benefit Cost 2 2 1 (1 ) 1 1 Other Changes in plan assets and benefit obligations recognized in OCI: Net loss (gain) — 1 2 — (3 ) (1 ) Amortization of net (loss) gain (1 ) (1 ) (1 ) 1 — — Amortization of prior service cost — — — (2 ) — — Total Other Changes (1 ) — 1 (1 ) (3 ) (1 ) Total Recognized $ 1 $ 2 $ 2 $ (2 ) $ (2 ) $ — The net periodic benefit cost for postretirement benefits represents the amount expensed for providing health care benefits to retirees and their eligible dependents. We include the service cost component in other operating expenses net of capitalized portion and include the components of net periodic benefit cost other than the service cost component in other expense. Amounts expected to be amortized from regulatory assets or liabilities into net periodic benefit cost for the year ending December 31, 2020 consist of: Pension Benefits Postretirement Benefits (Millions) Estimated net loss $ 123 $ 2 Estimated prior service cost (benefit) $ 1 $ (9 ) Amounts expected to be amortized from OCI into net periodic benefit cost for the year ending December 31, 2020 consist of: Pension Benefits Postretirement Benefits (Millions) Estimated net loss (gain) $ 2 $ (1 ) We expect that no pension benefit or postretirement benefit plan assets will be returned to us during the year ending December 31, 2020. The weighted-average assumptions used to determine benefit obligations for Networks and ARHI as of December 31, 2019 and 2018 consisted of: Pension Benefits Postretirement Benefits As of December 31, 2019 2018 2019 2018 Discount rate - Networks 2.93% / 3.19% 3.93% / 4.09% 2.93% / 3.19% 3.93% / 4.09% Discount rate - ARHI 3.10 % 4.09 % 3.10 % 4.09 % Rate of compensation increase - Networks 3.00% - 6.50% 3.50% - 4.20% — — The discount rate is the rate at which the benefit obligations could presently be effectively settled. We determined the discount rates by developing yield curves derived from a portfolio of high grade noncallable bonds with yields that closely match the duration of the expected cash flows of our benefit obligations. The weighted-average assumptions used to determine net periodic benefit cost for Networks and ARHI for the years ended December 31, 2019 , 2018 and 2017 consisted of: Pension Benefits Postretirement Benefits Years Ended December 31, 2019 2018 2017 2019 2018 2017 Discount rate - Networks 3.93% / 4.09% 3.63% / 3.80% 4.12% / 4.24% 3.93% / 4.09% 3.63% / 3.80% 4.12% / 4.24% Discount rate - ARHI 4.09 % 3.80 % 3.81 % 4.09 % 3.80 % 3.81 % Expected long-term return on plan assets - Networks 7.00% / 7.40% 7.00% / 7.40% 7.00% / 7.50% 4.90% - 7.00% 6.13 % 6.13 % Expected long-term return on plan assets - ARHI 5.50 % 5.50 % 5.50 % 5.50 % 5.50 % 5.50 % Expected long-term return on plan assets - nontaxable trust - Networks — — — 6.40 % 6.40 % 6.50 % Expected long-term return on plan assets - taxable trust - Networks — — — 4.20 % 4.20 % 4.25 % Rate of compensation increase - Networks 3.50%-4.20% 3.50% - 4.20% 3.50% - 4.20% — — — We developed our expected long-term rate of return on plan assets assumption based on a review of long-term historical returns for the major asset classes, the target asset allocations, and the effect of rebalancing of plan assets discussed below. Our analysis considered current capital market conditions and projected conditions. NYSEG, RG&E and UIL amortize unrecognized actuarial gains and losses over ten years from the time they are incurred as required by the NYPSC, PURA and DPU. Our other companies use the standard amortization methodology under which amounts in excess of ten-percent of the greater of the projected benefit obligation or market related value are amortized over the plan participants’ average remaining service to retirement. Assumed health care cost trend rates used to determine benefit obligations as of December 31, 2019 and 2018 consisted of: As of December 31, 2019 2018 Health care cost trend rate assumed for next year - Networks 7.00%/7.75% 7.50%/8.50% Health care cost trend rate assumed for next year - ARHI 6.75% / 7.50% 7.00%/7.75% Rate to which cost trend rate is assumed to decline (ultimate trend rate) - Networks 4.50 % 4.50 % Rate to which cost trend rate is assumed to decline (ultimate trend rate) - ARHI 4.50 % 4.50 % Year that the rate reaches the ultimate trend rate - Networks 2029 / 2027 2030 / 2028 Year that the rate reaches the ultimate trend rate - ARHI 2029 / 2027 2029 / 2027 The effects of a one-percent change in the assumed health care cost trend rates would have the following effects: 1% Increase 1% Decrease (Millions) Effect on total of service and interest cost $ 1 $ — Effect on postretirement benefit obligation $ 12 $ (11 ) Contributions We make annual contributions in accordance with our funding policy of not less than the minimum amounts as required by applicable regulations. Networks expects to contribute $82 million to the pension benefit plans during 2020. Estimated Future Benefit Payments Expected benefit payments and Medicare Prescription Drug, Improvement and Modernization Act of 2003 subsidy receipts reflecting expected future service for Networks and ARHI as of December 31, 2019 consisted of: (Millions) Pension Benefits Postretirement Benefits Medicare Act Subsidy Receipts 2020 $ 209 $ 32 $ 1 2021 $ 210 $ 32 $ 1 2022 $ 216 $ 31 $ — 2023 $ 217 $ 30 $ — 2024 $ 219 $ 29 $ — 2025 - 2028 $ 1,097 $ 134 $ 2 Non-Qualified Pension Plans Networks and ARHI also sponsor various unfunded pension plans for certain current employees, former employees and former directors. The total liability for these plans, which is included in Other current and Other non-current liabilities on our consolidated balance sheets, was $56 million and $54 million at December 31, 2019 and 2018 , respectively. Plan Assets Our pension benefits plan assets for Networks and ARHI were consolidated from three legacy master trusts to one new master trust in 2019. A consolidated trust provides for a uniform investment manager lineup and an efficient, cost effective means of allocating expenses and investment performance to each plan. Our primary investment objective is to ensure that current and future benefit obligations are adequately funded and with volatility commensurate with our risk tolerance. Preservation of capital and achievement of sufficient total return to fund accrued and future benefits obligations are of highest concern. Our primary means for achieving capital preservation is through diversification of the trusts’ investments while avoiding significant concentrations of risk in any one area of the securities markets. Further diversification is achieved within each asset group through utilizing multiple asset managers and systematic allocation to various asset classes and providing broad exposure to different segments of the equity, fixed income and alternative investment markets. The asset allocation policy is the most important consideration in achieving our objective of superior investment returns while minimizing risk. Networks and ARHI have established target asset allocation policies within allowable ranges for their pension benefits plan assets within broad categories of asset classes made up of Return-Seeking investments and Liability-Hedging investments. Networks currently has target allocations ranging from 35% - 70% for Return-Seeking assets and 34% - 65% for Liability-Hedging assets. ARHI currently has a target allocation of 60% for Return-Seeking assets and 40% for Liability-Hedging assets. Return-Seeking assets also include investments in real estate, global asset allocation strategies and hedge funds. Liability-Hedging investments generally consist of long-term corporate bonds, annuity contracts, long-term treasury STRIPS and opportunistic fixed income investments. Systematic rebalancing within the target ranges increases the probability that the annualized return on the investments will be enhanced, while realizing lower overall risk, should any asset categories drift outside their specified ranges. The fair values of pension benefits plan assets, by asset category, as of December 31, 2019 , consisted of: As of December 31, 2019 Fair Value Measurements (Millions) Total Level 1 Level 2 Level 3 Asset Category Cash and cash equivalents $ 42 $ — $ 42 $ — U.S. government securities 87 87 — — Registered investment companies 464 464 — — Corporate bonds 458 — 458 — Preferred stocks 1 1 — — Common collective trusts 572 — 572 — Other, principally annuity, fixed income 84 — 84 — $ 1,708 $ 552 $ 1,156 $ — Other investments measured at net asset value 1,140 Total $ 2,848 The fair values of pension benefits plan assets, by asset category, as of December 31, 2018 (a), consisted of: As of December 31, 2018 Fair Value Measurements (Millions) Total Level 1 Level 2 Level 3 Asset Category Cash and cash equivalents $ 52 $ — $ 52 $ — U.S. government securities 15 15 — — Registered investment companies 424 421 3 — Corporate bonds 413 — 413 — Preferred stocks 3 — 3 — Common collective trusts 634 — 634 — Other, principally annuity, fixed income 71 — 71 — $ 1,612 $ 436 $ 1,176 $ — Other investments measured at net asset value 932 Total $ 2,544 (a) Certain amounts have been reclassified within this table to conform to the 2019 presentation. Valuation Techniques We value our pension benefits plan assets as follows: • Cash and cash equivalents – Level 1: at cost, plus accrued interest, which approximates fair value. Level 2: proprietary cash associated with other investments, based on yields currently available on comparable securities of issuers with similar credit ratings. • U.S. government securities – at the closing price reported in the active market in which the security is traded. • Corporate bonds – based on yields currently available on comparable securities of issuers with similar credit ratings. • Preferred stocks – at the closing price reported in the active market in which the individual investment is traded. • Common collective trusts/Registered investment companies – Level 1: at the closing price reported in the active market in which the individual investment is traded. Level 2 - the fair value is primarily derived from the quoted prices in active markets of the underlying securities. Because the fund shares are offered to a limited group of investors, they are not considered to be traded in an active market. • Other investments, principally annuity and fixed income – based on yields currently available on comparable securities of issuers with similar credit ratings. • Other investments measured at net asset value (NAV) – fund shares offered to a limited group of investors and alternative investments, such as private equity and real estate oriented investments, partnership/joint ventures and hedge funds are valued using the NAV as a practical expedient. Our postretirement benefits plan assets are held with trustees in multiple voluntary employees’ beneficiary association (VEBA) and 401(h) arrangements and are invested among and within various asset classes to achieve sufficient diversification in accordance with our risk tolerance. This is achieved for our postretirement benefits plan assets through the utilization of multiple institutional mutual and money market funds, providing exposure to different segments of the fixed income, equity and short-term cash markets. Approximately 37% of the postretirement benefits plan assets are invested in VEBA and 401(h) arrangements that are not subject to income taxes with the remainder being invested in arrangements subject to income taxes. Networks has established a target asset allocation policy within allowable ranges for postretirement benefits plan assets of 45% - 65% for equity securities, 25% - 45% for fixed income and 5% - 25% for all other investment types. ARHI’s asset allocation policy has a target allocation of 45% in equity securities, 50% in fixed income and 5% for cash and cash equivalents investments. Equity investments are diversified across U.S. and non-U.S. stocks, investment styles, and market capitalization ranges. Fixed income investments are primarily invested in U.S. bonds and may also include some non-U.S. bonds. Other asset classes, including alternative investments, are used to enhance long-term returns while improving portfolio diversification. We primarily minimize the risk of large losses through diversification but also through monitoring and managing other aspects of risk through quarterly investment portfolio reviews. Systematic rebalancing within target ranges increases the probability that the annualized return on investments will be enhanced, while realizing lower overall risk, should any asset categories drift outside their specified ranges. The fair values of other postretirement benefits plan assets, by asset category, as of December 31, 2019 consisted of: As of December 31, 2019 Fair Value Measurements (Millions) Total Level 1 Level 2 Level 3 Asset Category Cash and cash equivalents $ 31 $ — $ 31 $ — Common stocks 16 16 — — Registered investment companies 98 98 — — Corporate bonds 2 — 2 — Other, principally annuity, fixed income 8 — 8 — Total $ 155 $ 114 $ 41 $ — The fair values of other postretirement benefits plan assets, by asset category, as of December 31, 2018 (a) consisted of: As of December 31, 2018 Fair Value Measurements (Millions) Total Level 1 Level 2 Level 3 Asset Category Cash and cash equivalents $ 9 $ 5 $ 4 $ — Common stocks 15 15 — — Registered investment companies 115 115 — — Corporate bonds 2 — 2 — Other, principally annuity, fixed income 7 — 7 — Total $ 148 $ 135 $ 13 $ — (a) Certain amounts have been reclassified within this table to conform to the 2019 presentation. Valuation Techniques We value our postretirement benefits plan assets as follows: • Cash and cash equivalents – Level 1: at cost, plus accrued interest, which approximates fair value. Level 2: proprietary cash associated with other investments, based on yields currently available on comparable securities of issuers with similar credit ratings. • Common stocks and registered investment companies – at the closing price reported in the active market in which the individual investment is traded. • Corporate bonds – based on yields currently available on comparable securities of issuers with similar credit ratings. • Other investments, principally annuity and fixed income – based on yields currently available on comparable securities of issuers with similar credit ratings. Pension and postretirement benefit plan equity securities did not include any Iberdrola common stock as of both December 31, 2019 and 2018 . Defined contribution plans We also have defined contribution plans defined as 401 (k)s for all eligible AVANGRID employees. There are various match formulas depending on years of service, age, and pension plan closure/freeze date. The annual contributions made through these plans for AVANGRID amounted to $40 million , $37 million and $36 million for 2019 , 2018 and 2017 respectively.

Equity

Equity	12 Months Ended
	Dec. 31, 2019
Equity [Abstract]
Equity	Equity As of December 31, 2019 , our share capital consisted of 500,000,000 shares of common stock authorized, 309,752,140 shares issued and 309,005,272 shares outstanding, 81.5% of which are owned by Iberdrola, each having a par value of $0.01 , for a total value of common stock of $3 million and additional paid in capital of $13,660 million . As of December 31, 2018 , our share capital consisted of 500,000,000 shares of common stock authorized, 309,752,140 shares issued and 309,005,272 shares outstanding, 81.5% of which were owned by Iberdrola, each having a par value of $ $0.01 , for a total value of common stock capital of $3 million and additional paid in capital of $13,657 million . We had 485,810 shares of common stock held in trust and no convertible preferred shares outstanding as of both December 31, 2019 and December 31, 2018 . During the year ended December 31, 2019 , we issued no shares of common stock and released no shares of common stock held in trust each having a par value of $0.01 . During the year ended December 31, 2018 , we issued 81,208 shares of common stock and released no shares of common stock held in trust, each having a par value of $0.01 . 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 the relative ownership percentage of Iberdrola at 81.5% . The stock repurchase program may be suspended or discontinued at any time upon notice. Out of a total of 261,058 treasury shares of common stock of AVANGRID as of December 31, 2019 , 115,831 shares were repurchased during 2016, 64,019 shares were repurchased in May 2017 and 81,208 shares were repurchased in May 2018, all in the open market. The total cost of repurchases, including commissions, was $12 million as of December 31, 2019 . Accumulated OCI (Loss) Accumulated OCI (Loss) for the years ended December 31, 2019 , 2018 and 2017 consisted of: Accumulated Other Comprehensive Income (Loss) As of December 31, 2016 2017 Change As of December 31, 2017 Adoption of new accounting standard 2018 Change As of December 31, 2018 Adoption of new accounting standard 2019 Change As of December 31, 2019 (Millions) Change in revaluation of defined benefit plans, net of income tax expense (benefit) of $1.1 for 2018 and $(0.3) for 2019 $ (14 ) $ — $ (14 ) $ — $ 3 $ (11 ) $ (2 ) $ 1 $ (12 ) Loss (gain) for nonqualified pension plans, net of income tax expense (benefit) of $0.2 for 2017, $0.3 for 2018 and $(1.0) for 2019 (7 ) 1 (6 ) (1 ) 1 (6 ) — (1 ) (7 ) Unrealized (loss) gain on derivatives qualifying as cash flow hedges: Unrealized gain (loss) during period on derivatives qualifying as cash flow hedges, net of income tax expense (benefit) of $15.2 for 2017, $(6.6) for 2018 and $(8.6) for 2019 5 25 30 — (21 ) 9 — (22 ) (13 ) Reclassification to net income of losses (gains) on cash flow hedges, net of income tax expense (benefit) of $9.3 for 2017, $(6.5) for 2018 and $2.7 for 2019 (a) (70 ) 14 (56 ) — (8 ) (64 ) (10 ) 11 (63 ) Gain (loss) on derivatives qualifying as cash flow hedges (65 ) 39 (26 ) — (29 ) (55 ) (10 ) (11 ) (76 ) Accumulated Other Comprehensive (Loss) Income $ (86 ) $ 40 $ (46 ) $ (1 ) $ (25 ) $ (72 ) $ (12 ) $ (11 ) $ (95 ) (a) Reclassification is reflected in the operating expenses line item in the consolidated statements of income.

Earnings Per Share

Earnings Per Share	12 Months Ended
	Dec. 31, 2019
Earnings Per Share [Abstract]
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. In 2019 , 2018 and 2017 , while we did have securities that were dilutive, these securities did not result in a change to our earnings per share calculations for the years ended December 31, 2019 , 2018 and 2017 . The calculations of basic and diluted earnings per share attributable to AVANGRID for the years ended December 31, 2019 , 2018 and 2017 , consisted of: Years Ended December 31, 2019 2018 2017 (Millions, except for number of shares and per share data) Numerator: Net income attributable to AVANGRID $ 700 $ 595 $ 381 Denominator: Weighted average number of shares outstanding - basic 309,491,082 309,503,319 309,502,861 Weighted average number of shares outstanding - diluted 309,514,910 309,712,628 309,661,883 Earnings per share attributable to AVANGRID Earnings Per Common Share, Basic $ 2.26 $ 1.92 $ 1.23 Earnings Per Common Share, Diluted $ 2.26 $ 1.92 $ 1.23

Variable Interest Entities

Variable Interest Entities	12 Months Ended
	Dec. 31, 2019
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 consolidated balance sheets valued based on an HLBV model. Earnings from the TEFs are recognized in net income attributable to noncontrolling interests in our consolidated statements of income. We consolidate the entities that have TEFs based on being the primary beneficiary for these VIEs. On June 28, 2019, we acquired Patriot Wind Farm LLC and associated entities (Patriot) which have constructed a 226 MW wind farm in Nueces County, Texas for a total purchase price of $317 million . The wind farm constitutes substantially all of the value of the consideration paid to the seller; therefore, the purchase was accounted for as an asset acquisition. We allocated the purchase price to property, plant and equipment of $344 million , derivative liabilities of $26 million and other liabilities of $1 million . In conjunction with the purchase, we entered into a TEF with a third-party investor at a sale price of $128 million . The assets and liabilities of the VIEs totaled approximately $806 million and $29 million , respectively, at December 31, 2019 . As of December 31, 2018 the assets and liabilities of VIEs totaled approximately $876 million and $50 million , respectively. At both December 31, 2019 and 2018 , the assets and liabilities of the VIEs consisted primarily of property, plant and equipment and equity method investments. At December 31, 2019 and 2018 , equity method investments of VIEs were approximately $0 and $101 million , respectively. Wind power generation is 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 farms. Under these structures, we contribute certain wind assets, relating both to existing wind farms and wind farms 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 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. On September 30, 2019, Renewables contributed $50 million to Aeolus Wind Power II LLC (Aeolus), including $31 million to third party investors, to accelerate the third-party investors recovering their investment and achieving their cumulative after-tax return. On December 13 2019, we repurchased the remaining 4.4% of Aeolus we did not control from the third-party investors. The difference between the amount paid of $14 million and the noncontrolling interest balance of $10 million was recorded as an adjustment to equity because there was no change in control as a result of the transaction. After the transaction, Aeolus is no longer considered a VIE. At December 31, 2019 , we consider El Cabo Wind, LLC (El Cabo) and Patriot to be VIEs. Our El Cabo and Patriot 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. In February 2020, tax equity financing agreements were executed for a portfolio of three newly-constructed wind farms and one repowering of an existing wind farm. The portfolio company, named Aeolus Wind Power VII LLC, will be comprised of Karankawa Wind, LLC, Montague Wind Power Facility, LLC, Otter Creek Wind Farm LLC, and Mountain View Power Partners III, LLC (collectively “Aeolus VII”), and will total 681 MW of wind power. We received $237 million from two tax equity investors on March 2, 2020, which represents their investment in the first two of these wind farms that have reached commercial operations. The third facility will be transacted once it reaches commercial operations later in 2020.

Grants, Government Incentives a

Grants, Government Incentives and Deferred Income	12 Months Ended
	Dec. 31, 2019
Other Liabilities Disclosure [Abstract]
Grants, Government Incentives and Deferred Income	Grants, Government Incentives and Deferred Income The changes in deferred income as of December 31, 2019 and 2018 consisted of: (Millions) Government grants Other deferred income Total As of December 31, 2017 $ 1,427 $ 19 $ 1,446 Additions 9 — 9 Recognized in income (69 ) (1 ) (70 ) As of December 31, 2018 1,367 18 1,385 Disposals (3 ) — (3 ) Derecognition due to sale (a) (38 ) — (38 ) Recognized in income (68 ) (2 ) (70 ) As of December 31, 2019 $ 1,258 $ 16 $ 1,274 (a) Grants no longer controlled by us due to the 2019 sale of a 50% interest in the Poseidon projects. See Note 22 for further information. Within deferred income, we classify grants we received under Section 1603 of the American Recovery and Reinvestment Act of 2009, where the United States Department of Treasury (DOT) provides eligible parties the option of claiming grants for specified energy property in lieu of tax credits, which we claimed for the majority of our qualifying properties. Deferred income has been recorded for the grant amounts and is amortized as an offset against depreciation expense using the straight-line method over the estimated useful life of the associated property to which the grants apply. We recognize a net deferred tax asset for the book to tax basis differences related to the property for income tax purposes within the nontaxable grant revenue deferred income tax liabilities (see Note 16 – Income Taxes). We are required to comply with certain terms and conditions applicable to each grant and, if a disqualifying event should occur as specified in the grant’s terms and conditions, we are required to repay the grant funds to the DOT. We believe we are in compliance with each grant’s terms and conditions as of December 31, 2019 and 2018 .

Equity Method Investments

Equity Method Investments	12 Months Ended
	Dec. 31, 2019
Equity Method Investments and Joint Ventures [Abstract]
Equity Method Investment	Equity Method Investments On December 13, 2019, Renewables transferred a 50% ownership in a wind farm and a solar project located in Arizona (Poseidon) to an unaffiliated third party involving total consideration of $112 million , excluding closing costs, and recognized a gain of $96 million , net of tax. The pre-tax gain of $134 million is included in "Other income (expense)" in our consolidated statements of income. The net gain includes $50 million related to the remeasurement of our retained investment in Poseidon which was valued based on the consideration received in the transaction. The transaction was accounted for as the sale of a business and resulted in a loss of control. The retained 50% ownership is accounted for as an equity method investment. As of December 31, 2019, the carrying value of Poseidon was $111 million . In August 2018, we acquired the remaining 50% ownership of a joint venture, which owns and operates a 162 MW wind farm located in Southeast Colorado (Colorado Wind Ventures LLC), which commenced operations in January 2004. The wind farm, being a single asset, constituted substantially all of the fair value of the gross assets acquired and, therefore, the transaction was considered an asset acquisition. We accounted for this venture under the equity method of accounting through the date of the asset acquisition. During the year ended December 31, 2017, we recorded an OTTI of $49 million on this investment. The fair value for OTTI calculation purposes was determined using Level 3 inputs and was estimated based on a discounted cash flows valuation technique utilizing the net amount of estimated future cash inflows and outflows related to the respective PPA. In December 2018, we sold 80% of our wholly owned subsidiary, Coyote Ridge Wind, LLC (Coyote Ridge), including substantially all of the related tax benefits, to WEC Infrastructure in exchange for $144 million of total proceeds with $84 million received in 2019 to complete the transaction. We recorded a gain of $4 million and $10 million from this transaction in “Other expense" in our consolidated statements of income for the years ended December 31, 2019 and 2018, respectively. We account for the remaining 20% membership interest under the equity method of accounting. The carrying amount of our investment was $14 million and $5 million as of December 31, 2019 and 2018 . We have two 50 -50 joint ventures with Horizon Wind Energy, LLC, which own and operate the Flat Rock Windpower LLC and the Flat Rock Wind Power II LLC wind farms located in upstate New York. Flat Rock Wind Power LLC, which commenced operations in January 2006, has a 231 MW capacity. Flat Rock Wind Power II LLC commenced operations in September 2007 and has a 91 MW capacity. We account for the Flat Rock joint ventures under the equity method of accounting. The carrying amount of these investments was $105 million and $114 million for Flat Rock Wind Power LLC, and $49 million and $53 million for Flat Rock Wind Power II LLC, as of December 31, 2019 and 2018 , respectively. We hold a 50% voting interest in Vineyard Wind, LLC (Vineyard Wind), a joint venture with Copenhagen Infrastructure Partners. Vineyard Wind acquired an easement from the U.S. Bureau of Ocean Energy Management containing rights to develop offshore wind generation in a 260 -square mile area located southeast of Martha’s Vineyard. The area subject to easement has the capacity for siting up to approximately 3,000 MW . In May 2018, Vineyard Wind was selected by the Massachusetts Electric Distribution Companies (EDCs) to construct and operate Vineyard Wind’s proposed 800 MW wind farm and electricity transmission project pursuant to the Massachusetts Green Communities Act Section 83C RFP for offshore wind energy projects. During 2019, contributions were made to a new offshore development project of $106 million to enter into the easement contract. In December 2019, DEEP selected Vineyard Wind to provide 804 MW of offshore wind through the development of its Park City Wind Project. As of December 31, 2019, Renewables has contributed $120 million to Vineyard Wind under the provisions of the LLC agreement. In January 2020, Renewables contributed an additional $13 million to Vineyard Wind. We expect to provide additional capital contributions. There was $5 million and $0 receivable from Vineyard Wind as of December 31, 2019 and 2018 , respectively. Renewables, through its joint venture in Vineyard Wind, was awarded a second Massachusetts offshore easement. We account for this venture under the equity method of accounting. The carrying amount of this investment was $227 million and $52 million as of December 31, 2019 and 2018 , respectively. Through UI, we are party to a 50 -50 joint venture with Clearway Energy, Inc. in GenConn, which operates two peaking generation plants in Connecticut. The investment in GenConn is being accounted for as an equity investment, the carrying value of which was $113 million and $119 million as of December 31, 2019 and 2018 , respectively. Networks holds an approximate 20% ownership interest in New York TransCo. Through New York TransCo, Networks has formed a partnership with Central Hudson Gas and Electric Corporation, Consolidated Edison, Inc., National Grid, plc and Orange and Rockland Utilities, Inc. to develop a portfolio of interconnected transmission lines and substations to fulfill the objectives of the New York energy highway initiative, which is a proposal to install up to 3,200 MW of new electric generation and transmission capacity in order to deliver more power generated from upstate New York power plants to downstate New York. On April 8, 2019, New York Transco was selected as the developer for Segment B of the AC Transmission Public Policy Project by the NYISO. The selected project, New York Energy Solution (NYES), replaces nearly 80-year old transmission assets located in the upper to mid-Hudson Valley with streamlined, modernized technology, to enable surplus clean energy resources in upstate New York and help achieve the State’s energy goals. The total project cost is $600 million plus interconnection costs. NYSEG’s contribution as 20% co-owner is $120 million . As of December 31, 2019 and 2018 , the amount receivable from New York TransCo was $0 and $1 million , respectively. The investment in New York TransCo is being accounted for as an equity investment, the carrying value of which was $26 million and $23 million , as of December 31, 2019 and 2018 , respectively. New York Transco is subject to regulatory approval of its rates, terms, and conditions with the FERC. None of our joint ventures have any contingent liabilities or capital commitments. Distributions received from equity method investments amounted to $17 million , $18 million and $20 million for the years ended December 31, 2019 , 2018 and 2017 respectively, which are reflected as either distributions of earnings or as returns of capital in the operating and investing sections of the consolidated statements of cash flows, respectively. In addition, during the years ended December 31, 2019 and 2018 , we received $9 million and $8 million of distributions in RECs from our equity method investments. As of December 31, 2019 , there was an immaterial amount of undistributed earnings from our equity method investments. Capitalized interest costs related to equity method investments were $7 million and $0 for the years ended December 31, 2019 and 2018, respectively.

Other Financial Statements Item

Other Financial Statements Items	12 Months Ended
	Dec. 31, 2019
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Other Financial Statements Items	Other Financial Statements Items Loss from assets held for sale In connection with the 2018 sale of our gas trading and storage businesses, we recorded a loss from held for sale measurement of $16 million and $642 million , respectively, for the years ended December 31, 2018 and 2017, which is included in “Loss from assets held for sale” in our consolidated statements of income. Other income (expense) Other income (expense) for the years ended December 31, 2019 , 2018 and 2017 consisted of: Years ended December 31, 2019 2018 2017 (Millions) Gain on sale of assets (a) $ 148 $ 10 $ — Allowance for funds used during construction 46 30 36 Carrying costs on regulatory assets 21 21 11 Non-service component of net periodic benefit cost (79 ) (128 ) (120 ) Other (17 ) 1 11 Total Other Income (Expense) $ 119 $ (66 ) $ (62 ) (a) 2019 includes a $134 million gain from the sale of 50% of our interest in the Poseidon projects, and 2018 includes a $10 million gain from the sale of our interest in Coyote Ridge (see Note 22). Accounts Receivable Accounts receivable as of December 31, 2019 and 2018 consisted of: As of December 31, 2019 2018 (Millions) Trade receivables $ 1,151 $ 1,204 Allowance for bad debts (69 ) (62 ) Total Accounts Receivable $ 1,082 $ 1,142 The allowance for bad debts relates entirely to gas and electricity consumers and comprises an amount that has been reserved following historical averages of loss percentages. The change in the allowance for bad debts as of December 31, 2019 and 2018 consisted of: (Millions) As of December 31, 2016 $ 64 Current period provision 69 Write-off as uncollectible (69 ) As of December 31, 2017 $ 64 Current period provision 74 Write-off as uncollectible (76 ) As of December 31, 2018 $ 62 Current period provision 92 Write-off as uncollectible (85 ) As of December 31, 2019 $ 69 DPA receivable balances were $65 million and $62 million as of December 31, 2019 and 2018 , respectively. Prepayments and Other Current Assets Prepayments and other current assets as of December 31, 2019 and 2018 consisted of: As of December 31, 2019 2018 (Millions) Prepaid other taxes $ 123 $ 137 Broker margin and collateral accounts 33 37 Other pledged deposits 3 6 Prepaid expenses 34 43 Other 6 6 Total $ 199 $ 229 Other current liabilities Other current liabilities as of December 31, 2019 and 2018 consisted of: As of December 31, 2019 2018 (Millions) Advances received $ 140 $ 129 Accrued salaries 89 81 Short-term environmental provisions 40 60 Collateral deposits received 44 42 Pension and other postretirement 5 5 Finance leases 9 — Other 7 10 Total $ 334 $ 327

Segment Information

Segment Information	12 Months Ended
	Dec. 31, 2019
Segment Reporting [Abstract]
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 eight 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 restructuring charges, mark-to-market earnings from changes in the fair value of derivative instruments, loss from held for sale measurement, accelerated depreciation derived from repowering of wind farms, OTTI on equity method investment, impact of the Tax Act and adjustments for the non-core Gas storage business. 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 consolidated financial statements. Refer to Note 4 - Revenue for more detailed information on revenue by segment. Segment information as of and for the year ended December 31, 2019 consisted of: For the year ended December 31, 2019 Networks Renewables Other(a) AVANGRID Consolidated Revenue - external $ 5,150 $ 1,186 $ 2 $ 6,338 Revenue - intersegment 14 — (14 ) — Depreciation and amortization 550 383 1 934 Operating income 893 95 15 1,003 Earnings (losses) from equity method investments 11 (8 ) — 3 Interest expense, net of capitalization 269 10 27 306 Income tax expense (benefit) 153 4 (14 ) 143 Capital expenditures 1,612 1,125 3 2,740 Adjusted net income 466 223 (15 ) 673 As of December 31, 2019 Property, plant and equipment 15,840 9,368 10 25,218 Equity method investments 139 506 — 645 Total assets $ 23,250 $ 13,163 $ (1,997 ) $ 34,416 (a) Includes Corporate and intersegment eliminations. Segment information as of and for the year ended December 31, 2018 consisted of: For the year ended December 31, 2018 Networks Renewables Other(a) AVANGRID Consolidated Revenue - external $ 5,304 $ 1,137 $ 37 $ 6,478 Revenue - intersegment 6 2 (8 ) — Loss from assets held for sale — — 16 16 Depreciation and amortization 503 352 — 855 Operating income 975 136 16 1,127 Earnings (losses) from equity method investments 13 (3 ) — 10 Interest expense, net of capitalization 260 33 10 303 Income tax expense (benefit) 169 (31 ) 32 170 Capital expenditures 1,377 410 — 1,787 Adjusted net income 486 185 13 684 As of December 31, 2018 Property, plant and equipment 14,754 8,697 8 23,459 Equity method investments 142 224 — 366 Total assets $ 22,239 $ 10,703 $ (775 ) $ 32,167 (a) Includes Corporate, Gas and intersegment eliminations. Segment information for the year ended December 31, 2017 consisted of: For the year ended December 31, 2017 Networks Renewables Other (a) AVANGRID Consolidated Revenue - external $ 4,950 $ 1,038 $ (25 ) $ 5,963 Revenue - intersegment 11 9 (20 ) — Loss from assets held for sale — — 642 642 Depreciation and amortization 474 325 25 824 Operating income (loss) 1,114 92 (701 ) 505 Earnings (losses) from equity method investments 15 (55 ) — (40 ) Interest expense, net of capitalization 244 28 8 280 Income tax expense (benefit) 316 (320 ) (255 ) (259 ) Capital expenditures 1,305 1,097 14 2,416 Adjusted net income $ 507 $ 120 $ 55 $ 682 (a) Includes Corporate, Gas and intersegment eliminations. Reconciliation of Adjusted Net Income to Net Income attributable to AVANGRID for the years ended December 31, 2019 , 2018 and 2017 is as follows: Years Ended December 31, 2019 2018 2017 (Millions) Adjusted Net Income Attributable to Avangrid, Inc. $ 673 $ 684 $ 682 Adjustments: Impairment of equity method and other investment (1) — — (49 ) Restructuring charges (2) (6 ) (4 ) (20 ) Mark-to-market adjustments - Renewables (3) 76 (25 ) (15 ) Loss from held for sale measurement (4) — (16 ) (642 ) Impact of the Tax Act (5) — (46 ) 328 Accelerated depreciation from repowering (6) (33 ) (3 ) — Income tax impact of adjustments (10 ) (6 ) 162 Gas Storage, net of tax (7) — 11 (64 ) Net Income Attributable to Avangrid, Inc. $ 700 $ 595 $ 381 (1) Represents OTTI on equity method investment recorded in 2017. (2) Restructuring and severance related charges relate to costs resulted from restructuring actions involving initial targeted voluntary workforce reductions and related costs in our plan to vacate a lease, predominantly within the Networks segment and costs to implement an initiative to mitigate costs and achieve sustainable growth (See Note 27 - Restructuring and Severance Related Expenses – for further details). (3) Mark-to-market earnings relates to earnings impacts from changes in the fair value of Renewables' derivative instruments associated with electricity and natural gas. (4) Represents loss from measurement of assets and liabilities held for sale in connection with the committed plan to sell the gas trading and storage businesses. (5) Represents the impact from measurement of deferred income tax balances as a result of the Tax Act enacted by the U.S. federal government on December 22, 2017. (6) Represents the amount of accelerated depreciation derived from repowering wind farms in Renewables. (7) Removal of the impact from Gas activity in the reconciliation to AVANGRID Net Income.

Related Party Transactions

Related Party Transactions	12 Months Ended
	Dec. 31, 2019
Related Party Transactions [Abstract]
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 years ended December 31, 2019 , 2018 and 2017 , respectively, consisted of: Years Ended December 31, 2019 2018 2017 (Millions) Sales To Purchases From Sales To Purchases From Sales To Purchases From Iberdrola Canada Energy Services, Ltd $ — $ — $ — $ (5 ) $ — $ (33 ) Iberdrola Renovables Energia, S.L. $ — $ (9 ) $ — $ (14 ) $ — $ (9 ) Iberdrola, S.A. $ 1 $ (42 ) $ 1 $ (38 ) $ 1 $ (36 ) Iberdrola Financiación, S.A. $ — $ (3 ) $ — $ (3 ) $ — $ (2 ) Iberdrola Energia Monterrey, S.A. de C.V. $ — $ — $ 3 $ — $ 46 $ — Vineyard Wind $ 13 $ — $ 3 $ — $ — $ — Other $ 2 $ (3 ) $ 2 $ (5 ) $ 1 $ (1 ) In addition to the statements of income items above, we made purchases of turbines for wind farms from Siemens-Gamesa, in which Iberdrola has an 8.1% ownership. The amounts capitalized for these transactions were $18 million and $6 million for the years ended December 31, 2019 and 2018 , respectively. In February 2020, Iberdrola sold its entire ownership share in Siemens-Gamesa; therefore, future transactions will not be considered related party. Related party balances as of December 31, 2019 and 2018 , respectively, consisted of: As of December 31, 2019 2018 (Millions) Owed By Owed To Owed By Owed To Siemens-Gamesa $ — $ (18 ) $ — $ (14 ) Iberdrola, S.A. $ 1 $ (42 ) $ 1 $ (40 ) Iberdrola Renovables Energía, S.L. $ — $ — $ 4 $ — Vineyard Wind $ 5 $ — $ — $ — Other $ 4 $ (4 ) $ 1 $ (4 ) 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. Transactions with Iberdrola Canada Energy Services (ICES) predominantly relate to the purchase of gas for ARHI’s gas-fired cogeneration facility in Klamath, Oregon. There are no notes payable amounts owed to ICES as of both December 31, 2019 and December 31, 2018 . Transactions with Iberdrola Energia Monterrey predominantly relate to the sale of gas by Enstor Gas for the power generation plant in Monterrey, Mexico. 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. Refer to Note 22 - Equity Method Investments for information on transactions with our equity method investees. AVANGRID manages its overall 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 December 31, 2019 and 2018 was $150 million and $0 , respectively. AVANGRID has a credit facility with Iberdrola Financiacion, S.A.U., a company of the Iberdrola Group. The facility has a limit of $500 million and matures on June 18, 2023 . AVANGRID pays a facility fee of 10.5 basis points annually on the facility. As of both December 31, 2019 and 2018 , there were no amounts outstanding under this credit facility.

Stock-Based Compensation

Stock-Based Compensation	12 Months Ended
	Dec. 31, 2019
Share-based Payment Arrangement [Abstract]
Stock-Based Compensation	Stock-Based Compensation Under the Avangrid, Inc. Omnibus Incentive Plan, 1,298,683 performance stock units (PSUs) were granted to certain officers and employees of AVANGRID in July 2016. In 2017, 2018 and 2019, an additional 85,759 , 75,350 and 3,881 PSUs, respectively, were granted to officers and employees of AVANGRID under this plan. The PSUs will vest upon achievement of certain performance and market-based metrics related to the 2016 through 2019 plan and will be payable in three equal installments in 2020, 2021 and 2022. As of December 31, 2019 , the total number of shares authorized for stock-based compensation plans was 2,500,000 . The fair value of the PSUs on the grant date was $31.80 per share, which is expensed on a straight-line basis over the requisite service period of approximately seven years based on expected achievement. The fair value of the PSUs was determined using valuation techniques to forecast possible future stock prices, applying a weighted average historical stock price volatility of AVANGRID and industry companies, a risk-free rate of interest that is equal, as of the grant date, to the yield of the zero-coupon U.S. Treasury bill and a reduction for the respective dividend yield calculated based on the most recent quarterly dividend payment and the stock price as of the grant date. In June and October 2018, pursuant to the Avangrid, Inc. Omnibus Incentive Plan two restricted stock units (RSUs) awards of 60,000 and 8,000 RSUs, respectively, were granted to certain officers of AVANGRID. The RSUs vest in full in one installment in June and December 2020, respectively for each award, provided that the award holders remain continuously employed with AVANGRID through such dates. The fair value on the grant date was determined based on a price of $50.40 and $47.59 per share, respectively, for June and October 2018 awards. The total stock-based compensation expense, which is included in "Operations and maintenance" of our consolidated statements of income for the years ended December 31, 2019 , 2018 and 2017 was $3 million , $2 million and $1 million , respectively. The total income tax benefit recognized for stock-based compensation arrangements for each of the years ended December 31, 2019 , 2018 and 2017 , was $1 million . A summary of the status of the AVANGRID's nonvested PSUs and RSUs as of December 31, 2019 , and changes during the fiscal year ended December 31, 2019 , is presented below: Number of PSUs Weighted Average Grant Date Fair Value Nonvested Balance – December 31, 2018 1,268,722 $ 32.80 Granted 6,284 $ 38.78 Forfeited (726 ) $ 31.80 Nonvested Balance – December 31, 2019 1,274,280 $ 32.83 As of December 31, 2019 , total unrecognized costs for non-vested PSUs and RSUs were $3 million . The weighted-average period over which the PSU and RSUs costs will be recognized is approximately 2 years . The weighted-average grant date fair value of PSUs and RSUs granted during the year was $38.78 per share for the year ended December 31, 2019 .

Restructuring and Severance Rel

Restructuring and Severance Related Expenses	12 Months Ended
	Dec. 31, 2019
Restructuring and Related Activities [Abstract]
Restructuring and Severance Related Expenses	Restructuring and Severance Related Expenses In 2017, we announced initial targeted voluntary workforce reductions predominantly within the Networks segment. Those actions primarily include: reducing our workforce through voluntary programs in various areas to better align our people resources with business demands and priorities; reorganizing our human resources function to substantially consolidate in Connecticut, as well as related costs to vacate a lease and relocate employees; and reducing our information technology (IT) workforce to make increasing use of external services for operations, support, and development of systems. In 2019, we also announced changes across the Company aimed to mitigate costs and deliver sustainable growth, including among others, outsourcing and insourcing of certain areas of the Company and technology initiatives that help improve efficiency and reduce costs. For the years ended December 31, 2019 , 2018 and 2017 , those decisions and transactions resulted in restructuring charges of $4 million , $3 million and $15 million , respectively, for severance expenses and $4 million for lease termination expenses in 2017 , which are included in “Operations and maintenance” in the consolidated statements of income and approximately $1 million of accelerated amortization of leasehold improvements, which are included in “Depreciation and amortization” in the consolidated statements of income for the year ended December 31, 2017. The remaining costs for severance agreements are being accrued ratably over the remaining service periods, which span intermittent periods through December 2019. For the year ended December 31, 2019 , the severance and lease restructuring charges reserves, which are recorded in “Other current liabilities” and “Other liabilities”, consisted of: For the Year Ended December 31, 2019 (Millions) Beginning Balance $ 4 Restructuring and severance related expenses 4 Payments (3 ) Ending Balance $ 5

Quarterly financial data (unaud

Quarterly financial data (unaudited)	12 Months Ended
	Dec. 31, 2019
Selected Quarterly Financial Information [Abstract]
Quarterly financial data (unaudited)	Quarterly financial data (unaudited) Selected quarterly financial data for 2019 and 2018 are set forth below: 1st Quarter 2nd Quarter 3rd Quarter 4th Quarter (Millions, except per share data) 2019 Operating revenues $ 1,842 $ 1,400 $ 1,487 $ 1,609 Operating Income $ 341 $ 207 $ 239 $ 216 Net Income $ 216 $ 105 $ 139 $ 216 Net Income attributable to Avangrid, Inc. $ 217 $ 110 $ 150 $ 223 Earnings Per Common Share, Basic and Diluted: (1) $ 0.70 $ 0.36 $ 0.48 $ 0.72 2018 Operating revenues $ 1,865 $ 1,402 $ 1,546 $ 1,665 Operating Income $ 403 $ 222 $ 253 $ 249 Net Income $ 238 $ 110 $ 134 $ 116 Net Income attributable to Avangrid, Inc. $ 244 $ 107 $ 125 $ 119 Earnings Per Common Share, Basic and Diluted: (1) $ 0.79 0.35/0.34 $ 0.40 $ 0.38 (1) Based on 309.5 million weighted average number of shares outstanding each quarter in both 2019 and 2018 for basic and diluted earnings per share. The third and fourth quarters of 2019 include, respectively, a gain of $43 million ( $32 million after income tax) from liquidation of a portion of wholesale electricity sales contracts and a gain of $134 million ( $96 million after income tax) from the sale of 50% of our interest in the Poseidon projects. The first and second quarters of 2018 include a loss of $5 million and $10 million , respectively, associated with measurement of held for sale assets of gas trading and storage business, $14 million and $17 million after income taxes. Additionally, the second and fourth quarters of 2018 include the impacts of $7 million and $39 million , respectively, from the measurement of deferred income tax balances as a result of the Tax Act enacted on December 22, 2017 by the U.S. federal government.

Subsequent events

Subsequent events	12 Months Ended
	Dec. 31, 2019
Subsequent Events [Abstract]
Subsequent events	Subsequent events On February 19, 2020 the board of directors of AVANGRID declared a quarterly dividend of $0.44 per share on its common stock. This dividend is payable on April 1, 2020 to shareholders of record at the close of business on March 6, 2020 .

Condensed Financial Information

Condensed Financial Information of Parent	12 Months Ended
	Dec. 31, 2019
Condensed Financial Information Disclosure [Abstract]
Condensed Financial Information of Parent	Schedule I –Financial Statements of Parent AVANGRID, INC. (PARENT) CONDENSED FINANCIAL INFORMATION OF PARENT STATEMENTS OF INCOME FOR THE YEARS ENDED December 31, 2019 , 2018 AND 2017 (Millions) Years Ended December 31, 2019 2018 2017 Operating Revenues $ — $ — $ — Operating Expenses Operating expense 3 3 3 Taxes other than income taxes (12 ) (11 ) 5 Total Operating Expenses (9 ) (8 ) 8 Operating Income (Loss) 9 8 (8 ) Other Income Other income 59 48 58 Equity earnings of subsidiaries 711 604 312 Interest expense (93 ) (56 ) (29 ) Income Before Income Tax 686 604 333 Income tax (benefit) expense (14 ) 9 (48 ) Net Income $ 700 $ 595 $ 381 See accompanying notes to Schedule I. Schedule I –Financial Statements of Parent AVANGRID, INC. (PARENT) CONDENSED FINANCIAL INFORMATION OF PARENT STATEMENTS OF COMPREHENSIVE INCOME FOR THE YEARS ENDED December 31, 2019 , 2018 , AND 2017 (Millions) Years Ended December 31, 2019 2018 2017 Net Income $ 700 $ 595 $ 381 Other comprehensive (loss) income of subsidiaries (11 ) (25 ) 40 Comprehensive Income $ 689 $ 570 $ 421 See accompanying notes to Schedule I. Schedule I –Financial Statements of Parent AVANGRID, INC. (PARENT) CONDENSED FINANCIAL INFORMATION OF PARENT BALANCE SHEETS AS OF December 31, 2019 AND 2018 (Millions) As of December 31, 2019 2018 Assets Current Assets Cash and cash equivalents $ 146 $ — Accounts receivable from subsidiaries 22 306 Notes receivable from subsidiaries 2,529 666 Prepayments and other current assets — 21 Total current assets 2,697 993 Investments in subsidiaries 16,859 16,067 Other assets Deferred income taxes 374 312 Other 3 1 Total other assets 377 313 Total Assets $ 19,933 $ 17,373 Liabilities Current Liabilities Current portion of debt $ 456 $ 8 Notes payable 561 588 Notes payable to subsidiaries 1,674 456 Accounts payable and accrued liabilities 2 10 Accounts payable to subsidiaries 7 9 Interest accrued 10 7 Interest accrued subsidiaries 18 6 Dividends payable 136 136 Taxes accrued 24 — Total current liabilities 2,888 1,220 Non-current debt 1,808 1,049 Total Liabilities 4,696 2,269 Equity Stockholders' Equity: Common stock 3 3 Additional paid-in capital 13,660 13,657 Treasury Stock (12 ) (12 ) Retained earnings 1,681 1,528 Accumulated other comprehensive loss (95 ) (72 ) Total Equity 15,237 15,104 Total Liabilities and Equity $ 19,933 $ 17,373 See accompanying notes to Schedule I. Schedule I –Financial Statements of Parent AVANGRID, INC. (PARENT) CONDENSED FINANCIAL INFORMATION OF PARENT STATEMENTS OF CASH FLOWS FOR THE YEARS ENDED December 31, 2019 , 2018 , AND 2017 (Millions) Years Ended December 31, 2019 2018 2017 Net Cash used in Operating Activities $ (1,299 ) $ (323 ) $ (1 ) Cash Flow from Investing Activities Notes receivable from subsidiaries 633 462 (532 ) Investments in subsidiaries (399 ) (48 ) — Return of capital from investments in subsidiaries 433 116 308 Net Cash (used in) provided by Investing Activities 667 530 (224 ) Cash Flow from Financing Activities Receipts (repayments) of short-term notes payable from subsidiaries, net 107 246 (246 ) (Repayments) receipts of short-term notes payable (27 ) 82 357 Proceeds of non-current debt 1,243 — 594 Repurchase of common stock — (4 ) (3 ) Issuance of common stock — (2 ) (1 ) Dividends paid (545 ) (537 ) (535 ) Net Cash provided by (used in) Financing Activities 778 (215 ) 166 Net Increase (Decrease) in Cash and Cash Equivalents 146 (8 ) (59 ) Cash and Cash Equivalents, Beginning of Year — 8 67 Cash and Cash Equivalents, End of Year $ 146 $ — $ 8 Supplemental Cash Flow Information Cash paid for interest $ 85 $ 55 $ 52 Cash paid (refunded) payment for income taxes $ 43 $ 55 $ (8 ) See accompanying notes to Schedule I. Avangrid, Inc. (AVANGRID), formerly Iberdrola USA, Inc., is a holding company and conducts substantially all of its business through its subsidiaries. Substantially all of its consolidated assets are held by such subsidiaries. Accordingly, its cash flow and its ability to meet its obligations are largely dependent upon the earnings of these subsidiaries and the distribution of other payment of such earnings to in the form of dividends, loans or advances or repayment of loans and advances from it. These condensed financial statements and related footnotes have been prepared in accordance with regulatory statute 210.12-04 of Regulation S-X. These statements should be read in conjunction with the consolidated financial statements and notes thereto of AVANGRID and subsidiaries (AVANGRID Group). AVANGRID indirectly or directly owns all of the ownership interests of its significant subsidiaries. AVANGRID relies on dividends or loans from its subsidiaries to fund dividends to its primary shareholder. AVANGRID’s significant accounting policies are consistent with those of the AVANGRID Group. For the purposes of these condensed financial statements, AVANGRID’s wholly owned and majority owned subsidiaries are recorded based upon its proportionate share of the subsidiaries net assets. As of December 31, 2019 , AVANGRID share capital consisted of 500,000,000 shares of common stock authorized, 309,752,140 shares issued and 309,005,272 shares outstanding, 81.5% of which are owned by Iberdrola, each having a par value of $0.01 , for a total value of common stock of $3 million and additional paid in capital of $13,660 million . As of December 31, 2018 , AVANGRID share capital consisted of 500,000,000 shares of common stock authorized, 309,752,140 shares issued and 309,005,272 shares outstanding, 81.5% of which were owned by Iberdrola, each having a par value of $ $0.01 , for a total value of common stock capital of $3 million and additional paid in of $13,657 million . AVANGRID had 485,810 shares of common stock held in trust and no convertible preferred shares outstanding as of both December 31, 2019 and 2018 . During the year ended December 31, 2019 , AVANGRID issued no shares of common stock and released no shares of common stock held in trust. During the year ended December 31, 2018 , AVANGRID issued 81,208 shares of common stock and released 0 shares of common stock held in trust each having a par value of $0.01 . AVANGRID has 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 the relative ownership percentage of Iberdrola at 81.5% . The stock repurchase program may be suspended or discontinued at any time upon notice. Out of 261,058 treasury shares of common stock of AVANGRID as of December 31, 2019 , 115,831 shares were repurchased during 2018 , 64,019 shares were repurchased in May 2017 and 81,208 shares were repurchased in May 2018, all in the open market. The total cost of repurchase, including commissions, was $12 million as of December 31, 2019 . On February 19, 2020 the board of directors of AVANGRID declared a quarterly dividend of $0.44 per share on its common stock. This dividend is payable on April 1, 2020 to shareholders of record at the close of business on March 6, 2020 . Supplemental Indenture On December 19, 2016, AVANGRID, its subsidiary, UIL, and The Bank of New York Mellon, entered into a supplemental indenture, pursuant to which AVANGRID assumed from UIL all the obligations under the indenture dated as of October 7, 2010 between UIL and The Bank of New York Mellon and all obligations relating to $450 million in aggregate principal amount of 4.625% notes due 2020 issued by UIL in 2010 prior to the merger. For the purpose of the supplemental indenture, a capital contribution of $483 million was made by AVANGRID to UIL in December 2016. On November 21, 2017, AVANGRID issued $600 million aggregate principal amount of its 3.150% notes maturing in 2024 . Proceeds of the offering were used to reduce short-term debt incurred to fund capital expenditures associated with development of renewable energy generation facilities. Net proceeds of the offering after the price discount and issuance-related expenses were $594 million . On May 16, 2019, AVANGRID issued $750 million aggregate principal amount of its 3.80% notes maturing in 2029 . Proceeds of the offering were used to finance and/or refinance, in whole or in part, one or more eligible renewable energy generation facilities. Net proceeds of the offering after the price discount and issuance-related expenses were $743 million . On December 31, 2019, we entered into a $500 million term loan credit agreement with two financial institutions. The agreement expires on June 30, 2021 and has a floating interest rate which was 2.40% as of December 31, 2019. Cash dividends paid by subsidiary are as follows: Years ended December 31, 2019 2018 2017 (millions) AVANGRID Networks $ 433 $ 116 $ 308 In 2019, AVANGRID made capital contributions of $108 million and $50 million , respectively, to its subsidiaries, UI and NYSEG. In 2018, AVANGRID made a capital contribution of $50 million to its subsidiary, UI. During 2019 and 2018 , AVANGRID recorded a net non-cash contribution and dividend of $219 million and $1,515 million , respectively, to and from its subsidiaries to zero out their account balances of notes receivables and payables.

Summary of Significant Accoun_2

Summary of Significant Accounting Policies, New Accounting Pronouncements, and Use of Estimates (Policies)	12 Months Ended
	Dec. 31, 2019
Accounting Policies [Abstract]
Principles of consolidation	Principles of consolidation We consolidate the entities in which we have a controlling financial interest, after the elimination of intercompany transactions. We account for investments in common stock where we have the ability to exercise significant influence, but not control, using the equity method of accounting.
Revenue recognition	Revenue recognitionWe recognize revenues when we transfer control of promised goods or services to our customers in an amount that reflects the consideration we expect to be entitled to in exchange for those goods or services. 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 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 reportable segments, refer to Note 24. 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. 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 Federal Energy Regulatory Commission (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 transmission service. We record revenue for all of those 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. Networks does not have any material significant payment terms because it receives payment at or shortly after the point of sale. For its New York utilities, Networks assesses its deferred payment arrangements 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, 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 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 material initial incremental costs of obtaining a contract or significant financing elements in any of the arrangements. 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, derives its revenues primarily from providing natural gas storage services to customers, gas trading operations generally classified as derivative revenue in accordance with the applicable accounting standards, gas trading contracts not classified as derivatives, and other miscellaneous revenues including intersegment eliminations. Contract Costs, Contract Liabilities and Practical Expedient 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. We have contract assets for costs from development success fees, which we paid during the solar asset development period in 2018, and will amortize ratably into expense over the 15 -year life of the power purchase agreement (PPA), expected to commence in December 2021 upon commercial operation. We also have a contract asset for costs incurred to cancel a PPA, which we will amortize over the 10 -year contract period of the replacement PPA that will commence upon completion of the project. Contract assets totaled $12 million and $9 million at December 31, 2019 and December 31, 2018 , respectively, and are presented in "Other non-current assets" on our 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 $10 million and $9 million at December 31, 2019 and December 31, 2018 , respectively, and are presented in "Other current liabilities" on our consolidated balance sheets. We recognized $21 million and $13 million as revenue during the years ended December 31, 2019 and December 31, 2018 , 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.
Regulatory accounting	Regulatory accounting We account for our regulated utilities' operations in accordance with the authoritative guidance applicable to entities with regulated operations that meet the following criteria: (i) rates are established or approved by a third-party regulator; (ii) rates are designed to recover the entity’s cost of providing regulated services or products and; (iii) there is a reasonable expectation that rates are set at levels that will recover the entity’s costs and be collected from customers. Regulatory assets represent incurred costs that have been deferred because of their probable future recovery from customers through regulated rates. Regulatory liabilities represent: (i) the excess recovery of costs or accrued credits that have been deferred because it is probable such amounts will be returned to customers through future regulated rates; or (ii) billings in advance of expenditures for approved regulatory programs. Regulatory assets and liabilities are amortized and the related expense or revenue is recognized in the consolidated statements of income consistent with the recovery or refund included in customer rates. We believe that it is probable that our currently recorded regulatory assets and liabilities will be recovered or settled in future rates.
Business combinations and assets acquisitions	Business combinations and assets acquisitions We apply the acquisition method of accounting to account for business combinations. The consideration transferred for an acquisition is the fair value of the assets transferred, the liabilities incurred by the acquirer to former owners of the acquiree and the equity interests issued by the acquirer. Acquisition related costs are expensed as incurred. Identifiable assets acquired and liabilities and contingent liabilities assumed in a business combination are measured initially at their fair values at the acquisition date. The excess of the consideration transferred over the fair value of the identifiable net assets acquired is recorded as goodwill. We recognize adjustments to provisional amounts relating to a business combination that are identified during the measurement period in the reporting period in which the adjustment amounts are determined. In contrast to a business combination, we classify a transaction as an asset acquisition when substantially all of the fair value of the gross assets acquired is concentrated in a single identifiable asset or group of similar identifiable assets or otherwise does not meet the definition of a business.
Noncontrolling interests	Noncontrolling interests Noncontrolling interests represent the portion of our net income (loss), comprehensive income (loss) and net assets that is not allocable to us and is calculated based on our ownership percentage. For holdings where the economic allocations are not based pro rata on ownership percentages, we use the balance sheet-oriented hypothetical liquidation at book value (HLBV) method, to reflect the substantive profit sharing arrangement.
Equity method investments	Equity method investments We account for joint ventures that do not meet consolidation criteria using the equity method. We reflect earnings (losses) recognized under the equity method in the consolidated statements of income as "Earnings (losses) from equity method investments." We recognize dividends received from joint ventures as a reduction in the carrying amount of the investment and not as dividend income. We assess and record an impairment of our equity method investments in earnings for a decline in value that is determined to be other than temporary (OTTI).
Goodwill and other intangible assets	Goodwill and other intangible assets Goodwill represents future economic benefits arising from other assets acquired in a business combination that are not individually identified and separately recognized. Goodwill is initially measured at cost, being the excess of the aggregate of the consideration transferred, the fair value of any noncontrolling interest and the acquisition date fair value of any previously held equity interest in the acquiree over the fair value of the net identifiable assets acquired and liabilities assumed. Goodwill is not amortized, but is subject to an assessment for impairment performed in the fourth quarter or more frequently if events occur or circumstances change that would more likely than not reduce the fair value of a reporting unit below its carrying amount. A reporting unit is an operating segment or one level below an operating segment and is the level at which we test goodwill for impairment. In assessing goodwill for impairment, we have the option of first performing a qualitative assessment to determine whether a quantitative assessment is necessary (step zero). If we determine, on the basis of qualitative factors, that the fair value of the reporting unit is more likely than not greater than the carrying amount, no further testing is required. If we bypass step zero or perform the qualitative assessment, but determine that it is more likely than not that its fair value is less than its carrying amount, we perform a quantitative two step fair value based test. Step one compares the fair value of the reporting unit to its carrying amount, including goodwill. If the carrying amount of the reporting unit exceeds its fair value, step two is performed. Step two requires an allocation of fair value to the individual assets and liabilities using business combination accounting guidance to determine the implied fair value of goodwill. If the implied fair value of goodwill is less than its carrying amount, we record an impairment loss as a reduction to goodwill and a charge to operating expenses. Intangible assets acquired separately are measured on initial recognition at cost. The cost of intangible assets acquired in a business combination is their fair value at the date of acquisition. Following initial recognition, intangible assets are carried at cost less any accumulated amortization and impairment losses. The useful lives of intangible assets are assessed as either finite or indefinite. Intangible assets with finite lives are amortized on a straight-line basis over the useful economic life, which ranges from four to forty years , and assessed for impairment whenever there is an indication that the intangible asset may be impaired. The amortization expense on intangible assets with finite lives is recognized in our consolidated statements of income within the expense category that is consistent with the function of the intangible assets.
Property, plant and equipment	Property, plant and equipment Property, plant and equipment are accounted for at historical cost. In cases where we are required to dismantle installations or to recondition the site on which they are located, we record the estimated cost of removal or reconditioning as an asset retirement obligation (ARO) and an equal amount is added to the carrying amount of the asset. Development and construction of our various facilities are carried out in stages. Project costs are expensed during early stage development activities. Once certain development milestones are achieved and it is probable that we can obtain future economic benefits from a project, we capitalize salaries and wages for persons directly involved in the project, and engineering, permits, licenses, wind measurement and insurance costs. Development projects in construction are reviewed periodically for any indications of impairment. Assets are transferred from “Construction work in progress” to “Property, plant and equipment” when they are available for service. Wind turbine and related equipment costs, other project construction costs and interest costs related to the project are capitalized during the construction period through substantial completion. AROs are recorded at the date projects achieve commercial operation. The cost of plant and equipment in use is depreciated on a straight-line basis, less any estimated residual value. The main asset categories are depreciated over the following estimated useful lives: Major class Asset Category Estimated Useful Life (years) Combined cycle plants 35-75 Hydroelectric power stations 45-90 Plant Wind power stations 25-40 Transport facilities 40-75 Distribution facilities 5-82 Equipment Conventional meters and measuring devices 7-41 Computer software 4-25 Other Buildings 30-82 Operations offices 5-75 Networks determines depreciation expense using the straight-line method, based on the average service lives of groups of depreciable property, which include estimated cost of removal, in service at each operating company. Consistent with FERC accounting requirements, Networks charges the original cost of utility plant retired or otherwise disposed to accumulated depreciation. The Networks composite rates for depreciation were 2.9% of average depreciable property for 2019 and 2.8% for 2018 . We charge repairs and minor replacements to operating expenses, and capitalize renewals and betterments, including certain indirect costs. Allowance for funds used during construction (AFUDC), applicable to Networks' entities applying regulatory accounting, is a noncash item that represents the allowed cost of capital, including a return on equity (ROE), used to finance construction projects. The portion of AFUDC attributable to borrowed funds is recorded as a reduction of interest expense and the remainder is recorded as other income.
Leases	Leases We determine if an arrangement is a lease at inception. We classify a lease as a finance lease if it meets any one of specified criteria that in essence transfers ownership of the underlying asset to us by the end of the lease term. If a lease does not meet any of those criteria, we classify it as an operating lease. On our consolidated balance sheets, we include, for operating leases: "Operating lease right-of-use (ROU) assets" and "Operating lease liabilities (current and non-current)"; and for finance leases: finance lease ROU assets in "Other assets" and liabilities in "Other current liabilities" and "Other liabilities." ROU assets represent our right to use an underlying asset for the lease term and lease liabilities represent our obligation to make lease payments arising from the lease. We recognize lease ROU assets and liabilities at commencement of an arrangement based on the present value of lease payments over the lease term. Most of our leases do not provide an implicit rate, so we use our incremental borrowing rate based on information available at the lease commencement date to determine the present value of future payments. A lease ROU asset also includes any lease payments made at or before commencement date, minus any lease incentives received, and includes initial direct costs incurred. We do not record leases with an initial term of 12 months or less on the balance sheet for all classes of underlying assets, and we recognize lease expense for those leases on a straight-line basis over the lease term. We include variable lease payments that depend on an index or a rate in the ROU asset and lease liability measurement based on the index or rate at the commencement date, or upon a modification. We do not include variable lease payments that do not depend on an index or a rate in the ROU asset and lease liability measurement. A lease term includes options to extend or terminate the lease when it is reasonably certain that we will exercise that option. We recognize lease (rent) expense for operating lease payments on a straight-line basis over the lease term, or for our regulated companies we recognize the amount eligible for recovery under their rate plans, such as actual amounts paid. We amortize finance lease ROU assets on a straight-line basis over the lease term and recognize interest expense based on the outstanding lease liability. We have lease agreements with lease and non-lease components, and account for lease components and associated non-lease components together as a single lease component, for all classes of underlying assets.
Impairment of long-lived assets	Impairment of long-lived assets We evaluate property, plant and equipment and other long-lived assets for impairment when events or changes in circumstances indicate that the carrying amount may not be recoverable. An impairment evaluation is based on undiscounted cash flow analysis at the lowest level to which cash flows of the long-lived assets or asset groups are largely independent of the cash flows of other assets and liabilities. An impairment loss is required to be recognized if the carrying amount of the asset exceeds the undiscounted future net cash flows associated with that asset. The impairment loss to be recognized is the amount by which the carrying amount of the long-lived asset exceeds the asset’s fair value. Depending on the asset, fair value may be determined by use of a discounted cash flow model (DCF), with assumptions consistent with a market participant’s view of the exit price of the asset.
Fair value measurement	Fair value measurement Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants as of the measurement date. The fair value measurement is based on the presumption that the transaction to sell the asset or transfer the liability takes place in either the principal market for the asset or liability, or, in the absence of a principal market, in the most advantageous market for the asset or liability. The fair value of an asset or a liability is measured using the assumptions that market participants would use when pricing the asset or liability, assuming that market participants act in their economic best interest. A fair value measurement of a non-financial asset takes into account a market participant’s ability to generate economic benefits by using the asset according to its highest and best use, or by selling it to another market participant that would use the asset according to its highest and best use. We use valuation techniques that are appropriate in the circumstances and for which sufficient data is available to measure fair value, maximizing the use of relevant observable inputs and minimizing the use of unobservable inputs. All assets and liabilities for which fair value is measured or disclosed in the consolidated financial statements are categorized within the fair value hierarchy based on the transparency of input to the valuation of an asset or liability as of the measurement date. The three input levels of the fair value hierarchy are as follows: • Level 1 - inputs to the valuation methodology are quoted prices (unadjusted) for identical assets or liabilities in active markets. • Level 2 - inputs to the valuation methodology include quoted prices for similar assets and liabilities in active markets, and inputs that are observable for the asset or liability either directly or indirectly, for substantially the full term of the contract. • Level 3 - one or more inputs to the valuation methodology are unobservable or cannot be corroborated with market data. Categorization within the fair value hierarchy is based on the lowest level of input that is significant to the fair value measurement. Certain investments are not categorized within the fair value hierarchy. These investments are measured based on the fair value of the underlying investments but may not be readily redeemable at that fair valu e.
Equity investments with readily determinable fair values	Equity investments with readily determinable fair values We measure equity investments with readily determinable fair values at fair value, with changes in fair value reported in net income.
Derivatives and hedge accounting	Derivatives and hedge accounting Derivatives are recognized on our consolidated balance sheets at their fair value, except for certain electricity commodity purchases and sales contracts for both capacity and energy (physical contracts) that qualify for, and are elected under, the normal purchases and normal sales exception. To be a derivative under the accounting standards for derivatives and hedging, an agreement would need to have a notional and an underlying, require little or no initial net investment and could be net settled. We recognize changes in the fair value of a derivative contract in earnings unless specific hedge accounting criteria are met. Derivatives that qualify and are designated for hedge accounting are classified as cash flow hedges. We report the gain or loss on the derivative instrument as a component of Other Comprehensive Income (OCI) and later reclassify amounts into earnings when the underlying transaction occurs, which we present in the same income statement line item as the earnings effect of the hedged item. For all designated and qualifying hedges, we maintain formal documentation of the hedge and effectiveness testing in accordance with the accounting standards for derivatives and hedging. If we determine that the derivative is no longer highly effective as a hedge, we will discontinue hedge accounting prospectively. For cash flow hedges of forecasted transactions, we estimate the future cash flows of the forecasted transactions and evaluate the probability of the occurrence and timing of such transactions. If we determine it is probable that the forecasted transaction will not occur, we immediately recognize in earnings hedge gains and losses previously recorded in OCI. Changes in conditions or the occurrence of unforeseen events could require discontinuance of the hedge accounting or could affect the timing of the reclassification of gains or losses on cash flow hedges from OCI into earnings. For our regulated operations, we record changes in the fair value of electric and natural gas hedge contracts derivative assets or liabilities with an offset to regulatory assets or regulatory liabilities. We offset fair value amounts recognized for derivative instruments and fair value amounts recognized for the right to reclaim cash collateral or the obligation to return cash collateral arising from derivative instruments executed with the same counterparty under a master netting arrangement.
Cash and cash equivalents	Cash and cash equivalents Cash and cash equivalents include cash, bank accounts, and other highly-liquid short-term investments. We consider all highly liquid investments with a maturity date of three months or less when acquired to be cash equivalents and include those investments in “Cash and cash equivalents.” Restricted cash represents cash legally set aside for a specified purpose or as part of an agreement with a third party. Restricted cash is included in “Other non-current assets” on our consolidated balance sheets. Book overdrafts representing outstanding checks in excess of funds on deposit are classified as “Accounts payable and accrued liabilities” on our consolidated balance sheets. Changes in book overdrafts are reported in the operating activities section of our consolidated statements of cash flows.
Accounts receivable and unbilled revenue, net	Accounts receivable and unbilled revenue, net We record accounts receivable at amounts billed to customers. Certain accounts receivable and payable related to our wholesale activities associated with generation and delivery of electric energy and associated environmental attributes, origination and marketing, natural gas storage, hub services, and energy management, are subject to master netting agreements with counterparties, whereby we have the legal right to offset the balances and are settled on a net basis. Receivables and payables subject to such agreements are presented on our consolidated balance sheets on a net basis. Accounts receivable include amounts due under Deferred Payment Arrangements (DPA). A DPA allows the account balance to be paid in installments over an extended period of time without interest, which generally exceeds one year, by negotiating mutually acceptable payment terms. The utility companies generally must continue to serve a customer who cannot pay an account balance in full if the customer (i) pays a reasonable portion of the balance; (ii) agrees to pay the balance in installments; and (iii) agrees to pay future bills within thirty days until the DPA is paid in full. Failure to make payments on a DPA results in the full amount of a receivable under a DPA being due. These accounts are part of the regular operating cycle and are classified as short term. The allowance for doubtful accounts is established by using both historical average loss percentages to project future losses, and a specific allowance is established for known credit issues or for specific items not considered in the historical average calculation. Amounts are written off when we believe that a receivable will not be recovered.
Variable interest entities	Variable interest entities An entity is considered to be a variable interest entity (VIE) when its total equity investment at risk is not sufficient to permit the entity to finance its activities without additional subordinated financial support, or its equity investors, as a group, lack the characteristics of having a controlling financial interest. A reporting company is required to consolidate a VIE as its primary beneficiary when it has both the power to direct the activities of the VIE that most significantly impact the VIE's economic performance, and the obligation to absorb losses or the right to receive benefits from the VIE that could potentially be significant to the VIE. We evaluate whether an entity is a VIE whenever reconsideration events as defined by the accounting guidance occur (See Note 20). We have undertaken several structured institutional partnership investment transactions that bring in external investors in certain of our wind farms in exchange for cash. Following an analysis of the economic substance of these transactions, we classify the consideration received at the inception of the arrangement as noncontrolling interests on our consolidated balance sheets. Subsequently, the HLBV method allocates earnings to the noncontrolling interest, which considers the cash and tax benefits provided to the tax equity investors.
Debentures, bonds and bank borrowings	Debentures, bonds and bank borrowings Bonds, debentures and bank borrowings are recorded as a liability equal to the proceeds of the borrowings. The difference between the proceeds and the face amount of the issued liability is treated as discount or premium and is accreted as interest expense or income over the life of the instrument. Incremental costs associated with issuance of the debt instruments are deferred and amortized over the same period as debt discount or premium. Bonds, debentures and bank borrowings are presented net of unamortized discount, premium and debt issuance costs on our consolidated balance sheets.
Inventory	Inventory Inventory comprises fuel and gas in storage and materials and supplies. This gas is recorded as inventory. Injections of inventory into storage are priced at the market purchase cost at the time of injection, and withdrawals of working gas from storage are priced at the weighted-average cost in storage. We continuously monitor the weighted-average cost of gas value to ensure it remains at the lower of cost and net realizable value. Inventories to support gas operations are reported on our consolidated balance sheets within “Fuel and gas in storage.” We also have materials and supplies inventories that are used for construction of new facilities and repairs of existing facilities. These inventories are carried and withdrawn at the lower of cost and net realizable value and reported on our consolidated balance sheets within “Materials and supplies.”
Government grants and Deferred income	Government grants Our unregulated subsidiaries record government grants related to depreciable assets within deferred income and subsequently amortize them to earnings as an offset to depreciation and amortization expense over the useful life of the related asset. Our regulated subsidiaries record government grants as a reduction to utility plant to be recovered through rate base, in accordance with the prescribed FERC accounting. In accounting for government grants related to operating and maintenance costs, amounts receivable are recognized as an offset to expenses in our consolidated statements of income in the period in which the expenses are incurred. (t ) Deferred income Apart from government grants, we occasionally receive revenues from transactions in advance of the resulting performance obligations arising from the transaction. It is our policy to defer such revenues on our consolidated balance sheets and amortize them into earnings when revenue recognition criteria are met.
Asset retirement obligations	Asset retirement obligations We record the fair value of the liability for an ARO and a conditional ARO in the period in which it is incurred, capitalizing the cost by increasing the carrying amount of the related long-lived asset. The ARO is associated with our long-lived assets and primarily consists of obligations related to removal or retirement of asbestos, polychlorinated biphenyl-contaminated equipment, gas pipeline, cast iron gas mains and electricity generation facilities. The liability is adjusted periodically to reflect revisions to either the timing or amount of the original estimated undiscounted cash flows over time. The liability is accreted to its present value each period and the capitalized cost is depreciated over the useful life of the related asset. Upon settlement, we will either settle the obligation at its recorded amount or incur a gain or a loss. Our regulated utilities defer any timing differences between rate recovery and depreciation expense and accretion as either a regulatory asset or a regulatory liability. The term conditional ARO refers to an entity’s legal obligation to perform an asset retirement activity in which the timing or method of settlement are conditional on a future event that may or may not be within the entity’s control. If an entity has sufficient information to reasonably estimate the fair value of the liability for a conditional ARO, it must recognize that liability at the time the liability is incurred. Our regulated utilities meet the requirements concerning accounting for regulated operations and we recognize a regulatory liability for the difference between removal costs collected in rates and actual costs incurred. These are classified as accrued removal obligations.
Environmental remediation liability	Environmental remediation liability In recording our liabilities for environmental remediation costs the amount of liability for a site is the best estimate, when determinable; otherwise it is based on the minimum liability or the lower end of the range when there is a range of estimated losses. Our environmental liabilities are recorded on an undiscounted basis. Our environmental liability accruals are expected to be paid through the year 2057 .
Post-employment and other employee benefits	Post-employment and other employee benefits We sponsor defined benefit pension plans that cover the majority of our employees. We also provide health care and life insurance benefits through various postretirement plans for eligible retirees. We evaluate our actuarial assumptions on an annual basis and consider changes based on market conditions and other factors. All of our qualified defined benefit plans are funded in amounts calculated by independent actuaries, based on actuarial assumptions proposed by management. We account for defined benefit pension or other postretirement plans, recognizing an asset or liability for the overfunded or underfunded plan status. For a pension plan, the asset or liability is the difference between the fair value of the plan’s assets and the projected benefit obligation. For any other postretirement benefit plan, the asset or liability is the difference between the fair value of the plan’s assets and the accumulated postretirement benefit obligation. Our utility operations reflect all unrecognized prior service costs and credits and unrecognized actuarial gains and losses as regulatory assets rather than in other comprehensive income, as management believes it is probable that such items will be recoverable through the ratemaking process. We use a December 31st measurement date for our benefits plans. We amortize prior service costs for both the pension and other postretirement benefits plans on a straight-line basis over the average remaining service period of participants expected to receive benefits. Unrecognized actuarial gains and losses related to the pension and other postretirement benefits plans are amortized over the average remaining service period or 10 years , considering any requirement by the regulators for our Networks subsidiaries. Our policy is to calculate the expected return on plan assets using the market related value of assets. That value is determined by recognizing the difference between actual returns and expected returns over a five-year period.
Income taxes	Income taxes We use the asset and liability method of accounting for income taxes. Deferred tax assets and liabilities reflect the expected future tax consequences, based on enacted tax laws, of temporary differences between the tax basis of assets and liabilities and their financial reporting amounts. In accordance with U.S. GAAP for regulated industries, certain of our regulated subsidiaries have established a regulatory asset for the net revenue requirements to be recovered from customers for the related future tax expense associated with certain of these temporary differences. We defer the investment tax credits when earned and amortize them over the estimated lives of the related assets. We also recognize the income tax consequences of intra-entity transfers of assets other than inventory when the transfer occurs. Deferred tax assets and liabilities are measured at the expected tax rate for the period in which the asset or liability will be realized or settled, based on legislation enacted as of the balance sheet date. Changes in deferred income tax assets and liabilities that are associated with components of OCI are charged or credited directly to OCI. Significant judgment is required in determining income tax provisions and evaluating tax positions. Our tax positions are evaluated under a more-likely-than-not recognition threshold before they are recognized for financial reporting purposes. We record valuation allowances to reduce deferred tax assets when it is more likely than not that we will not realize all or a portion of a tax benefit. Deferred tax assets and liabilities are netted and classified as non-current on our consolidated balance sheets. We record the excess of state franchise tax computed as the higher of a tax based on income or a tax based on capital in “Taxes other than income taxes” and “Taxes accrued” in our consolidated financial statements. Positions taken or expected to be taken on tax returns, including the decision to exclude certain income or transactions from a return, are recognized in the financial statements when it is more likely than not the tax position can be sustained based solely on the technical merits of the position. The amount of a tax return position that is not recognized in the financial statements is disclosed as an unrecognized tax benefit. Changes in assumptions on tax benefits may also impact interest expense or interest income and may result in the recognition of tax penalties. Interest and penalties related to unrecognized tax benefits are recorded within “Interest expense, net of capitalization” and “Other income and (expense)” in our consolidated statements of income. Uncertain tax positions have been classified as non-current unless expected to be paid within one year. In 2019, we netted our liability for uncertain tax positions against all same jurisdiction deferred tax assets, net operating losses and tax credit carryforwards. Our policy is to recognize interest and penalties on uncertain tax positions as a component of interest expense in the consolidated statements of income. Federal production tax credits applicable to our renewable energy facilities, that are not part of a tax equity financing arrangement, are recognized as a reduction in income tax expense with a corresponding reduction in deferred income tax liabilities. Our income tax expense, deferred tax assets and liabilities, and liabilities for unrecognized tax benefits reflect management’s best assessment of estimated current and future taxes to be paid. Significant judgments and estimates are required in determining the consolidated income tax components of the financial statements.
Stock-based compensation	Stock-based compensation Stock-based compensation represents costs related to stock-based awards granted to employees. We account for stock-based payment transactions based on the estimated fair value of awards reflecting forfeitures when they occur. The recognition period for these costs begins at either the applicable service inception date or grant date and continues throughout the requisite service period, or until the employee becomes retirement eligible, if earlier.
Adoption of New Accounting Pronouncements and Accounting Pronouncements Issued But Not Yet Adopted	Adoption of New Accounting Pronouncements (a) Leases In February 2016, the Financial Accounting Standards Board (FASB) issued Accounting Standards Codification (ASC) Topic 842, Leases , with subsequent amendments issued in 2018. The new lease guidance affects all companies and organizations that lease assets, and requires them to record on their balance sheet ROU assets and lease liabilities for the rights and obligations created by those leases. Under ASC 842, a lease is an arrangement that conveys the right to control the use of an identified asset for a period of time in exchange for consideration. The new guidance retains a distinction between finance leases and operating leases, while requiring companies to recognize both types of leases on their balance sheet. The classification criteria for distinguishing between finance leases and operating leases are substantially similar to the criteria for distinguishing between capital leases and operating leases in legacy U.S. GAAP - ASC 840. Lessor accounting remains substantially the same as ASC 840, but with some targeted improvements to align lessor accounting with the lessee accounting model and with the revised revenue recognition guidance under ASC 606. The new standard and amendments require new qualitative and quantitative disclosures for both lessees and lessors. We adopted ASC 842 effective January 1, 2019, and elected the optional transition method under which we initially applied the standard on that date without adjusting amounts for prior periods, which we continue to present in accordance with ASC 840, including related disclosures. We recorded the cumulative effect of applying the new leases guidance as an adjustment to beginning retained earnings. In connection with our adoption, we: • did not elect the package of three practical expedients available under the transition provisions which would have allowed us to not reassess: (i) whether expired or existing contracts were or contained leases, (ii) the lease classification for expired or existing leases, and (iii) whether previously capitalized initial direct costs for existing leases would qualify for capitalization under ASC 842. • elected the land easement practical expedient and did not reassess land easements that did not meet the definition of a lease prior to adoption. • used hindsight for determining the lease term and assessing the likelihood that a lease purchase option will be exercised in applying the new leases guidance. • did not separate lease and associated non-lease components for transitioned leases, but instead are accounting for them together as a single lease component. In March 2019, the FASB issued additional amendments to ASC 842 for minor codification improvements, which we early applied effective January 1, 2019, with no material effect to our consolidated results of operations, financial position and cash flows. The cumulative effects of the changes to our consolidated balance sheet as of January 1, 2019, were as follows: Balance at December 31, 2018 Adjustments Due to ASC 842 Balance at January 1, 2019 (Millions) Assets Total Property, Plant and Equipment $ 23,459 $ (147 ) $ 23,312 Operating lease right-of-use assets — 82 82 Other assets 162 146 308 Liabilities Current portion of debt $ 394 $ (28 ) $ 366 Operating lease liabilities, current — 8 8 Other current liabilities 327 28 355 Operating lease liabilities, long-term — 74 74 Other non-current liabilities 499 61 560 Non-current debt 5,368 (61 ) 5,307 Equity Retained earnings $ 1,528 $ (1 ) $ 1,527 Our adoption did not change the classification of lease-related expenses in our consolidated statements of income, and we do not expect significant changes to our pattern of expense recognition. Certain contracts previously classified as lessor leases, consisting mainly of Renewables’ power purchase agreements, no longer meet the definition of a lease under ASC 842. As such, these contracts are accounted for under other U.S. GAAP, but there were no changes to our pattern of revenue recognition. As a result, our adoption will not materially affect our cash flows. In comparison to our operating leases obligations disclosed as of December 31, 2018, certain land easement contracts that previously met the definition of a lease do not meet the ASC 842 definition of a lease, and therefore we excluded them from the transition adjustment. Our accounting for finance (formerly capital) leases is substantially unchanged. Refer to Note 13 for further details. (b) Targeted improvements to accounting for hedging activities In August 2017, the FASB issued targeted amendments with the objective to better align hedge accounting with an entity’s risk management activities in the financial statements and to simplify the application of hedge accounting. The amendments address concerns of financial statement preparers over difficulties with applying hedge accounting and limitations for hedging both nonfinancial and financial risks and concerns of financial statement users over how hedging activities are reported in financial statements. The amended presentation and disclosure guidance is required only prospectively. Changes to the hedge accounting guidance to address those concerns: 1) expand hedge accounting for nonfinancial and financial risk components and amend measurement methodologies to more closely align hedge accounting with an entity’s risk management activities; 2) eliminate the separate measurement and reporting of hedge ineffectiveness to reduce the complexity of preparing and understanding hedge results; 3) enhance disclosures and change the presentation of hedge results to align the effects of the hedging instrument and the hedged item in order to enhance transparency, comparability and understandability of hedge results; and 4) simplify the way assessments of hedge effectiveness may be performed to reduce the cost and complexity of applying hedge accounting. The amendments ease the administrative burden of hedge documentation requirements and assessing hedge effectiveness going forward. We adopted the hedge accounting amendments on January 1, 2019, and had no cumulative-effect adjustment to retained earnings because there were no amounts of ineffectiveness recorded for any existing hedges as of that date. Concurrently with the above targeted improvements, we adopted the additional amendments the FASB issued in October 2018 that permit use of the Overnight Index Swap rate based on the Secured Overnight Financing Rate as a U.S. benchmark interest rate for hedge accounting purposes. Use of that rate is in addition to the already eligible benchmark interest rates, which are: interest rates on direct Treasury obligations of the U.S. government, the London Interbank Offered Rate swap rate, the OIS Rate based on the Fed Funds Effective Rate and the Securities Industry and Financial Markets Association Municipal Swap Rate. (c) Reclassification of certain tax effects from accumulated other comprehensive income In February 2018, the FASB issued amendments to address a financial reporting issue that arose as a consequence of the Tax Cuts and Jobs Act of 2017 (the Tax Act) that the U.S. federal government enacted on December 22, 2017. Under previous guidance, an entity was required to include the adjustment of deferred taxes for the effect of a change in tax laws or rates in income from continuing operations, thus the associated tax effects of items within AOCI (referred to as stranded tax effects) did not reflect the appropriate tax rate. The amendments allow a reclassification from AOCI to retained earnings to eliminate the stranded tax effects resulting from the Tax Act. The amendments only relate to the reclassification of the income tax effects of the Tax Act, and do not affect the underlying guidance that requires the effect of a change in tax laws or rates to be included in income from continuing operations. We adopted the amendments effective January 1, 2019, and elected to reclassify the stranded tax effects of the Tax Act from AOCI to retained earnings at the beginning of the period of adoption. As a result, we reclassified approximately $12 million from AOCI to retained earnings within our consolidated statements of changes in equity. Accounting Pronouncements Issued But Not Yet Adopted The following are new accounting pronouncements not yet adopted that we have evaluated or are evaluating to determine their effect on our consolidated financial statements. (a) Measurement of credit losses on financial instruments, amendments and updates The FASB issued an accounting standards update in June 2016 that requires more timely recording of credit losses on loans and other financial instruments. The amendments affect entities that hold financial assets and net investment in leases that are not accounted for at fair value through net income (loans, debt securities, trade receivables, net investments in leases, off-balance-sheet credit exposures, etc.). They require an entity to present a financial asset (or group of financial assets) that is measured at amortized cost basis at the net amount expected to be collected. The allowance for credit losses is a valuation account that is deducted from the amortized cost basis of the financial asset(s) to present the net carrying value at the amount expected to be collected on the financial asset. The income statement reflects the measurement of credit losses for newly recognized financial assets, as well as the expected increases or decreases of expected credit losses that have taken place during the period. The measurement of expected credit losses is based on relevant information about past events, including historical experience, current conditions, and reasonable and supportable forecasts that affect the collectability of the reported amount. An entity must use judgment in determining the relevant information and estimation methods appropriate in its circumstances. The FASB subsequently issued various updates to this new guidance to clarify transition and scope requirements, make narrow-scope codification improvements and corrections and provide targeted transition relief. The new guidance, including the subsequent amendments, is effective for public entities that are SEC filers for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years. Entities are to apply the amendments on a modified retrospective basis for most instruments. Early adoption is allowed. Our implementation plan and steps included: evaluating financial assets within scope; documenting related technical accounting issues, policy considerations and financial reporting implications; and identifying changes to processes and controls to ensure all aspects of the new guidance were effectively addressed. Our adoption of the guidance on January 1, 2020, including our transition adjustment, will not materially affect our consolidated results of operations, financial position and cash flows. (b) Simplifying the test for goodwill impairment In January 2017, the FASB issued amendments to simplify the test for goodwill impairment, which are required for public entities and certain other entities that have goodwill reported in their financial statements. The amendments simplify the subsequent measurement of goodwill by eliminating Step 2 from the goodwill impairment test, which requires the valuation of assets acquired and liabilities assumed using business combination accounting guidance. Under the new guidance, an entity should perform its annual, or interim, goodwill impairment test by comparing the fair value of a reporting unit with its carrying amount. An entity should recognize an impairment charge for the amount by which the carrying amount exceeds the reporting unit’s fair value; but the loss recognized should not exceed the total amount of goodwill allocated to that reporting unit. Also, an entity should consider income tax effects from any tax deductible goodwill on the carrying amount of the reporting unit when measuring the goodwill impairment loss, if applicable. Certain requirements are eliminated for any reporting unit with a zero or negative carrying amount; therefore the same impairment assessment applies to all reporting units. An entity still has the option to perform the qualitative assessment for a reporting unit to determine if the quantitative impairment test is necessary. The amendments are effective for public entities for annual and interim periods in fiscal years beginning after December 15, 2019, with the amendments applied on a prospective basis. Early adoption is allowed. Our adoption of the amendments on January 1, 2020, will not materially affect our results of operations, financial position, cash flows and disclosures. (c) Changes to the disclosure requirements for fair value measurement and defined benefit plans In August 2018, the FASB issued amendments related to disclosure requirements for both fair value measurement and defined benefit plans. The amendments concerning fair value measurement remove, modify and add certain disclosure requirements in order to improve the overall usefulness of the disclosures and reduce unnecessary costs to companies to prepare the disclosures. The amendments to fair value measurement disclosures are effective for all entities for fiscal years beginning after December 15, 2019, and interim periods within those fiscal years. Early adoption is permitted as specified. Certain amendments are to be applied prospectively, and all others are to be applied retrospectively. Our adoption of the amendments on January 1, 2020, will not materially affect our disclosures. The amendments concerning disclosure requirements for defined benefit plans are narrow in scope and apply to all employers that sponsor defined benefit pension or other postretirement plans. They remove disclosures that are no longer considered cost beneficial, add certain new relevant disclosures and clarify specific requirements of disclosures concerning information for defined benefit pension plans. The amendments to defined benefit plan disclosures are effective for fiscal years ending after December 15, 2020. Early adoption is permitted and application is to be on a retrospective basis. Our adoption of the amendments on January 1, 2020, will not materially affect our disclosures. (d) Targeted improvements to related party guidance for VIEs In October 2018, the FASB issued amendments that affect reporting entities that are required to determine whether they should consolidate a legal entity under the consolidation guidance applicable to VIEs. The targeted improvements specifically applicable to public business entities clarify that indirect interests held through related parties in common control arrangements should be considered on a proportional basis for determining whether fees paid to decision makers and service providers are variable interests. The amendments are effective for public business entities for fiscal years beginning after December 15, 2019, and interim periods within those fiscal years. Early adoption is permitted. Our adoption of the amendments on January 1, 2020, will not materially affect our consolidated results of operations, financial position, cash flows and disclosures. (e) Clarifying guidance for certain collaborative arrangements with respect to revenue recognition The FASB issued amendments in November 2018 to clarify the interaction between the guidance for certain collaborative arrangements and the guidance applicable to ASC 606. A collaborative arrangement is a contractual arrangement under which two or more parties actively participate in a joint operating activity and are exposed to significant risks and rewards that depend on the activity’s commercial success. The targeted improvements clarify that certain transactions between collaborative arrangement participants are within the scope of ASC 606 and thus subject to all of its guidance. The amendments are effective for public business entities for fiscal years beginning after December 15, 2019, and interim periods within those fiscal years. Early adoption is permitted, including adoption in any interim period for which financial statements have not been issued. Retrospective application to the date of initial application of ASC 606 is required. Our adoption of the amendments on January 1, 2020, will not materially affect our consolidated results of operations, financial position, cash flows and disclosures. (f) Simplifying the accounting for income taxes In December 2019, the FASB issued an accounting standards update that is intended to reduce complexity in accounting for income taxes. The amendments remove specific exceptions to the general principles in ASC 740, Income Taxes , eliminating the need for an entity to analyze whether the following apply in a given period: (1) exception to the incremental approach for intra-period tax allocation, (2) exceptions to accounting for basis differences when there are ownership changes in foreign investments and (3) exception in interim period income tax accounting for year-to-date losses that exceed anticipated losses. The amendments also improve financial statement preparers’ application of income-tax related guidance and simplify U. S. GAAP for (1) franchise taxes that are partially based on income, (2) transactions with a government that result in a step up in the tax basis of goodwill, (3) separate financial statements of legal entities that are not subject to tax and (4) enacted changes in tax laws in interim periods. The amendments are effective for public business entities for fiscal years beginning after December 15, 2020, and interim periods within those fiscal years. Early adoption is permitted, including adoption in any interim period for which financial statements have not been issued, with adoption of all amendments in the same period. Application is on a retrospective and/or modified retrospective basis, or a prospective basis, depending on the amendment aspect. We expect our adoption will not materially affect our consolidated results of operations, financial position and cash flows.
Use of Estimates and Assumptions	Use of Estimates and Assumptions
Union collective bargaining agreements	Union collective bargaining agreements We have approximately 49.0% of the employees covered by a collective bargaining agreement. Agreements which will expire within the coming year apply to approximately 25.5% of our employees.

Summary of Significant Accoun_3

Summary of Significant Accounting Policies, New Accounting Pronouncements, and Use of Estimates (Tables)	12 Months Ended
	Dec. 31, 2019
Accounting Policies [Abstract]
Schedule of Estimated Useful Lives	The main asset categories are depreciated over the following estimated useful lives: Major class Asset Category Estimated Useful Life (years) Combined cycle plants 35-75 Hydroelectric power stations 45-90 Plant Wind power stations 25-40 Transport facilities 40-75 Distribution facilities 5-82 Equipment Conventional meters and measuring devices 7-41 Computer software 4-25 Other Buildings 30-82 Operations offices 5-75 Property, plant and equipment as of December 31, 2019 , consisted of: As of December 31, 2019 Regulated Nonregulated Total (Millions) Electric generation, distribution, transmission and other $ 15,092 $ 12,360 $ 27,452 Natural gas transportation, distribution and other 4,387 13 4,400 Other common operating property — 258 258 Total Property, Plant and Equipment in Service 19,479 12,631 32,110 Total accumulated depreciation (4,969 ) (4,090 ) (9,059 ) Total Net Property, Plant and Equipment in Service 14,510 8,541 23,051 Construction work in progress 1,269 898 2,167 Total Property, Plant and Equipment $ 15,779 $ 9,439 $ 25,218 Property, plant and equipment as of December 31, 2018 , consisted of: As of December 31, 2018 Regulated Nonregulated Total (Millions) Electric generation, distribution, transmission and other $ 14,242 $ 11,669 $ 25,911 Natural gas transportation, distribution and other 4,058 13 4,071 Other common operating property — 226 226 Total Property, Plant and Equipment in Service (a) 18,300 11,908 30,208 Total accumulated depreciation (b) (4,615 ) (3,744 ) (8,359 ) Total Net Property, Plant and Equipment in Service 13,685 8,164 21,849 Construction work in progress 1,010 600 1,610 Total Property, Plant and Equipment $ 14,695 $ 8,764 $ 23,459 (a) Includes capitalized leases of $226 million primarily related to electric generation, distribution, transmission and other. Finance leases (formerly known as capital leases) are no longer included in property plant and equipment after adoption of ASC 842 on January 1, 2019. See Note 3 for further information. (b) Includes accumulated amortization of capitalized leases of $76 million .
Schedule of New Accounting Pronouncements	The cumulative effects of the changes to our consolidated balance sheet as of January 1, 2019, were as follows: Balance at December 31, 2018 Adjustments Due to ASC 842 Balance at January 1, 2019 (Millions) Assets Total Property, Plant and Equipment $ 23,459 $ (147 ) $ 23,312 Operating lease right-of-use assets — 82 82 Other assets 162 146 308 Liabilities Current portion of debt $ 394 $ (28 ) $ 366 Operating lease liabilities, current — 8 8 Other current liabilities 327 28 355 Operating lease liabilities, long-term — 74 74 Other non-current liabilities 499 61 560 Non-current debt 5,368 (61 ) 5,307 Equity Retained earnings $ 1,528 $ (1 ) $ 1,527

Revenue (Tables)

Revenue (Tables)	12 Months Ended
	Dec. 31, 2019
Revenue from Contract with Customer [Abstract]
Schedule of Revenues Disaggregated by Major Source for Reportable Segments	Revenues disaggregated by major source for our reportable segments for the years ended December 31, 2019 and December 31, 2018 are as follows: Year Ended December 31, 2019 Networks Renewables Other (b) Total (Millions) Regulated operations – electricity $ 3,485 $ — $ — $ 3,485 Regulated operations – natural gas 1,479 — — 1,479 Nonregulated operations – wind — 805 — 805 Nonregulated operations – solar — 26 — 26 Nonregulated operations – thermal — 29 — 29 Nonregulated operations – gas storage — — — — Other(a) 91 62 (12 ) 141 Revenue from contracts with customers 5,055 922 (12 ) 5,965 Leasing revenue 6 — — 6 Derivative revenue — 244 — 244 Alternative revenue programs 75 — — 75 Other revenue 28 20 — 48 Total operating revenues $ 5,164 $ 1,186 $ (12 ) $ 6,338 Year Ended December 31, 2018 Networks Renewables Other (b) Total (Millions) Regulated operations – electricity $ 3,641 $ — $ — $ 3,641 Regulated operations – natural gas 1,473 — — 1,473 Nonregulated operations – wind — 637 — 637 Nonregulated operations – solar — 17 — 17 Nonregulated operations – thermal — 47 — 47 Nonregulated operations – gas storage — — 10 10 Other(a) 58 (68 ) 9 (1 ) Revenue from contracts with customers 5,172 633 19 5,824 Leasing revenue 38 346 — 384 Derivative revenue — 124 10 134 Alternative revenue programs 80 — — 80 Other revenue 20 36 — 56 Total operating revenues $ 5,310 $ 1,139 $ 29 $ 6,478 (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, Gas and intersegment eliminations.
Schedule of Aggregate Transaction Price Allocations	As of December 31, 2019 , the aggregate amount of the transaction price allocated to performance obligations that are unsatisfied (or partially unsatisfied) were as follows: As of December 31, 2019 2020 2021 2022 2023 2024 Thereafter Total (Millions) Revenue expected to be recognized on multiyear retail energy sales contracts in place $ 1 $ 1 $ 1 $ 1 $ 1 $ — $ 5 Revenue expected to be recognized on multiyear capacity and carbon-free energy sale contracts 35 27 19 11 8 25 126 Revenue expected to be recognized on multiyear renewable energy credit sale contracts 22 16 8 5 4 8 63 Total operating revenues $ 58 $ 44 $ 28 $ 17 $ 13 $ 33 $ 194

Industry Regulation (Tables)

Industry Regulation (Tables)	12 Months Ended
	Dec. 31, 2019
Regulated Operations [Abstract]
Electric and Gas Delivery Rate Increase	The delivery rate increases in the Joint Proposal can be summarized as follows: May 1, 2016 May 1, 2017 May 1, 2018 Rate Increase Delivery Rate Increase Rate Increase Delivery Rate Increase Rate Increase Delivery Rate Increase Utility (Millions) % (Millions) % (Millions) % NYSEG Electric $ 29.6 4.10 % $ 29.9 4.10 % $ 30.3 4.10 % NYSEG Gas $ 13.1 7.30 % $ 13.9 7.30 % $ 14.8 7.30 % RG&E Electric $ 3.0 0.70 % $ 21.6 5.00 % $ 25.9 5.70 % RG&E Gas $ 8.8 5.20 % $ 7.7 4.40 % $ 9.5 5.20 %
Schedule of Delivery Rate Increases	The below table provides a summary of the initial proposed delivery rate increases, delivery revenue percentages and total revenue percentages for all four businesses: Requested Revenue Increase Delivery Revenue Total Revenue Utility (Millions) % % NYSEG Electric $ 156.7 20.4 % 10.4 % NYSEG Gas $ 6.3 3.0 % 1.4 % RG&E Electric $ 31.7 7.0 % 4.1 % RG&E Gas $ 5.8 3.3 % 1.4 %

Regulatory Assets and Liabili_2

Regulatory Assets and Liabilities (Tables)	12 Months Ended
	Dec. 31, 2019
Regulated Operations [Abstract]
Schedule of Regulatory Assets	Regulatory assets as of December 31, 2019 and 2018 consisted of: As of December 31, 2019 2018 (Millions) Pension and other post-retirement benefits cost deferrals $ 125 $ 141 Pension and other post-retirement benefits 1,061 1,138 Storm costs 272 346 Rate adjustment mechanism 79 18 Reliability support services — 13 Revenue decoupling mechanism 19 7 Transmission revenue reconciliation mechanism 5 11 Contracts for differences 92 97 Hardship programs 29 26 Plant decommissioning 5 11 Deferred purchased gas 25 37 Deferred transmission expense 11 11 Environmental remediation costs 277 278 Debt premium 97 118 Unamortized losses on reacquired debt 29 23 Unfunded future income taxes 399 371 Federal tax depreciation normalization adjustment 153 157 Asset retirement obligation 17 18 Deferred meter replacement costs 27 29 Other 139 95 Total regulatory assets 2,861 2,945 Less: current portion 294 299 Total non-current regulatory assets $ 2,567 $ 2,646
Schedule of Regulatory Liabilities	Regulatory liabilities as of December 31, 2019 and 2018 consisted of: As of December 31, 2019 2018 (Millions) Energy efficiency portfolio standard $ 72 $ 56 Gas supply charge and deferred natural gas cost 11 4 Pension and other post-retirement benefits cost deferrals 80 97 Carrying costs on deferred income tax bonus depreciation 49 72 Carrying costs on deferred income tax - Mixed Services 263(a) 15 20 2017 Tax Act 1,548 1,509 Revenue decoupling mechanism 17 19 Accrued removal obligations 1,173 1,153 Asset sale gain account 10 10 Economic development 27 28 Positive benefit adjustment 37 39 Theoretical reserve flow thru impact 14 19 Deferred property tax 17 25 Net plant reconciliation 23 19 Debt rate reconciliation 67 49 Rate refund – FERC ROE proceeding 32 29 Transmission congestion contracts 23 21 Merger-related rate credits 16 18 Accumulated deferred investment tax credits 13 14 Asset retirement obligation 14 13 Earnings sharing provisions 28 17 Middletown/Norwalk local transmission network service collections 18 19 Low income programs 33 38 Non-firm margin sharing credits 16 10 New York 2018 winter storm settlement 11 — Other 159 130 Total regulatory liabilities 3,523 3,428 Less: current portion 242 205 Total non-current regulatory liabilities $ 3,281 $ 3,223

Goodwill and Intangible assets

Goodwill and Intangible assets (Tables)	12 Months Ended
	Dec. 31, 2019
Goodwill and Intangible Assets Disclosure [Abstract]
Schedule of Goodwill by Reportable Segment	Goodwill by reportable segment as of December 31, 2019 and 2018 consisted of: As of December 31, 2019 2018 (Millions) Networks $ 2,747 $ 2,747 Renewables 372 380 Total $ 3,119 $ 3,127
Schedule of Intangible Assets Acquired and Developed	Intangible assets include those assets acquired in business acquisitions and intangible assets acquired and developed from external third parties and from affiliated companies. Following is a summary of intangible assets as of December 31, 2019 and 2018 : As of December 31, 2019 Gross Carrying Amount Accumulated Amortization Net Carrying Amount (Millions) Wind development $ 591 $ (289 ) $ 302 Other 28 (16 ) 12 Total Intangible Assets $ 619 $ (305 ) $ 314 As of December 31, 2018 Gross Carrying Amount Accumulated Amortization Net Carrying Amount (Millions) Wind development $ 588 $ (275 ) $ 313 Other 25 (15 ) 10 Total Intangible Assets $ 613 $ (290 ) $ 323
Schedule of Expect Amortization Expense	We expect amortization expense for the five years subsequent to December 31, 2019 , to be as follows: Year ending December 31, Amount (Millions) 2020 $ 15 2021 $ 14 2022 $ 13 2023 $ 12 2024 $ 12

Property, Plant and Equipment (

Property, Plant and Equipment (Tables)	12 Months Ended
	Dec. 31, 2019
Property, Plant and Equipment [Abstract]
Schedule of Property, Plant and Equipment	The main asset categories are depreciated over the following estimated useful lives: Major class Asset Category Estimated Useful Life (years) Combined cycle plants 35-75 Hydroelectric power stations 45-90 Plant Wind power stations 25-40 Transport facilities 40-75 Distribution facilities 5-82 Equipment Conventional meters and measuring devices 7-41 Computer software 4-25 Other Buildings 30-82 Operations offices 5-75 Property, plant and equipment as of December 31, 2019 , consisted of: As of December 31, 2019 Regulated Nonregulated Total (Millions) Electric generation, distribution, transmission and other $ 15,092 $ 12,360 $ 27,452 Natural gas transportation, distribution and other 4,387 13 4,400 Other common operating property — 258 258 Total Property, Plant and Equipment in Service 19,479 12,631 32,110 Total accumulated depreciation (4,969 ) (4,090 ) (9,059 ) Total Net Property, Plant and Equipment in Service 14,510 8,541 23,051 Construction work in progress 1,269 898 2,167 Total Property, Plant and Equipment $ 15,779 $ 9,439 $ 25,218 Property, plant and equipment as of December 31, 2018 , consisted of: As of December 31, 2018 Regulated Nonregulated Total (Millions) Electric generation, distribution, transmission and other $ 14,242 $ 11,669 $ 25,911 Natural gas transportation, distribution and other 4,058 13 4,071 Other common operating property — 226 226 Total Property, Plant and Equipment in Service (a) 18,300 11,908 30,208 Total accumulated depreciation (b) (4,615 ) (3,744 ) (8,359 ) Total Net Property, Plant and Equipment in Service 13,685 8,164 21,849 Construction work in progress 1,010 600 1,610 Total Property, Plant and Equipment $ 14,695 $ 8,764 $ 23,459 (a) Includes capitalized leases of $226 million primarily related to electric generation, distribution, transmission and other. Finance leases (formerly known as capital leases) are no longer included in property plant and equipment after adoption of ASC 842 on January 1, 2019. See Note 3 for further information. (b) Includes accumulated amortization of capitalized leases of $76 million .

Asset retirement obligations (T

Asset retirement obligations (Tables)	12 Months Ended
	Dec. 31, 2019
Table Text Block Supplement [Abstract]
Schedule of Asset Retirement Obligations	The reconciliation of ARO carrying amounts for the years ended December 31, 2019 and 2018 consisted of: (Millions) As of December 31, 2017 $ 196 Liabilities settled during the year (1 ) Liabilities incurred during the year 5 Accretion expense 12 Revisions in estimated cash flows 5 As of December 31, 2018 $ 217 Liabilities settled during the year (5 ) Liabilities incurred during the year 6 Accretion expense 12 Revisions in estimated cash flows (a) (40 ) As of December 31, 2019 $ 190 (a) Represents a reduction in our estimate of expected cash flows required for retirement activities related to our renewable energy facilities.

Debt (Tables)

Debt (Tables)	12 Months Ended
	Dec. 31, 2019
Debt Disclosure [Abstract]
Schedule of Long-term Debt	Long-term debt as of December 31, 2019 and 2018 consisted of: As of December 31, 2019 2018 (Millions) Maturity Dates Balances Interest Rates Balances Interest Rates First mortgage bonds - fixed (a) 2021-2049 $ 2,218 3.07%-8.00% $ 2,055 3.07%-10.06% Unsecured pollution control notes - fixed 2020-2029 538 2.00%-3.50% 526 2.00%-3.50% Term loan - variable 2021 500 2.40% — Other various non-current debt - fixed 2020-2049 4,228 2.80%-10.48% 3,127 2.80%-10.48% Obligations under capital leases (b) — 89 4.00%-4.44% Unamortized debt issuance costs and discount (38 ) (35 ) Total Debt 7,446 5,762 Less: debt due within one year, included in current liabilities 730 394 Total Non-current Debt $ 6,716 $ 5,368 (a) The first mortgage bonds have pledged collateral of substantially all the respective utility’s in service properties of approximately $6,876 million . (b) Due to the adoption of ASC 842 in 2019 (see Notes 3 and 13 for more information), capital leases, now known as financing leases, are no longer reported as part of long-term debt.
Schedule of Maturities and Repayments of Long-term Debt	Long-term debt maturities, including sinking fund obligations, due over the next five years consists of: 2020 2021 2022 2023 2024 Total (Millions) $ 730 $ 801 $ 363 $ 439 $ 612 $ 2,945

Fair Value of Financial Instr_2

Fair Value of Financial Instruments and Fair Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2019
Fair Value Disclosures [Abstract]
Schedule of Fair Value Measurements	The financial instruments measured at fair value as of December 31, 2019 and 2018 consisted of: As of As of December 31, 2019 Level 1 Level 2 Level 3 Netting Total (Millions) Equity and other investments with readily determinable fair values $ 38 $ 13 $ — $ — $ 51 Derivative assets Derivative financial instruments - power $ 4 $ 23 $ 120 $ (54 ) $ 93 Derivative financial instruments - gas — 40 31 (71 ) — Contracts for differences — — 2 — 2 Total $ 4 $ 63 $ 153 $ (125 ) $ 95 Derivative liabilities Derivative financial instruments - power $ (28 ) $ (43 ) $ (29 ) $ 92 $ (8 ) Derivative financial instruments - gas (4 ) (26 ) (5 ) 33 (2 ) Contracts for differences — — (94 ) — (94 ) Derivative financial instruments – Other — (1 ) — — (1 ) Total $ (32 ) $ (70 ) $ (128 ) $ 125 $ (105 ) As of As of December 31, 2018 Level 1 Level 2 Level 3 Netting Total (Millions) Equity and other investments with readily determinable fair values $ 37 $ 10 $ — $ — $ 47 Derivative assets Derivative financial instruments - power $ 17 $ 23 $ 91 $ (59 ) $ 72 Derivative financial instruments - gas 1 20 36 (55 ) 2 Contracts for differences — — 5 — 5 Total $ 18 $ 43 $ 132 $ (114 ) $ 79 Derivative liabilities Derivative financial instruments - power $ (12 ) $ (41 ) $ (36 ) $ 77 $ (12 ) Derivative financial instruments - gas (1 ) (23 ) (7 ) 22 (9 ) Contracts for differences — — (102 ) — (102 ) Derivative financial instruments – Other — (16 ) (2 ) — (18 ) Total $ (13 ) $ (80 ) $ (147 ) $ 99 $ (141 )
Fair Value, Financial instrument Based on Level 3 Reconciliation	Additional quantitative information about Level 3 fair value measurements of the CfDs is as follows: Range at Unobservable Input December 31, 2019 Risk of non-performance 0.05% - 0.45% Discount rate 1.69% - 1.83% Forward pricing ($ per KW-month) $3.80 - $7.03 The reconciliation of changes in the fair value of financial instruments based on Level 3 inputs for the years ended December 31, 2019 , 2018 and 2017 consisted of: (Millions) 2019 2018 2017 Fair value as of January 1, $ (15 ) $ 6 $ 31 Gains for the year recognized in operating revenues 53 18 18 Losses for the year recognized in operating revenues (2 ) (9 ) (1 ) Total gains or losses for the period recognized in operating revenues 51 9 17 Gains recognized in OCI 2 — 2 Losses recognized in OCI (3 ) (5 ) (1 ) Total gains or losses recognized in OCI (1 ) (5 ) 1 Net change recognized in regulatory assets and liabilities 5 (5 ) (17 ) Purchases (22 ) (6 ) (5 ) Settlements 4 (10 ) (17 ) Transfers out of Level 3 (a) 3 (4 ) (4 ) Fair value as of December 31, $ 25 $ (15 ) $ 6 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 $ 51 $ 9 $ 17 (a) Transfers out of Level 3 were the result of increased observability of market data.
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. As of December 31, 2019 Instruments Instrument Description Valuation Technique Valuation Inputs Index Avg. Max. Min. Fixed price power and gas swaps with delivery period > two years Transactions with delivery periods exceeding two years Transactions are valued against forward market prices on a discounted basis Observable and extrapolated forward gas and power prices not all of which can be corroborated by market data for identical or similar products NYMEX ($/MMBtu) $ 2.90 $ 4.90 $ 2.07 Indiana hub ($/MWh) $ 30.54 $ 61.12 $ 19.10 Mid C ($/MWh) $ 24.75 $ 105.00 $ (0.50 ) Minn hub ($/MWh) $ 25.10 $ 52.17 $ 12.51 NoIL hub ($/MWh) $ 27.36 $ 55.39 $ 15.50 Ercot S hub ($/MWh) $ 31.00 $ 248.39 $ 14.62

Derivative Instruments and He_2

Derivative Instruments and Hedging (Tables)	12 Months Ended
	Dec. 31, 2019
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Schedule of Derivatives Instruments Statements of Financial Performance and Financial Position, Location in Consolidated Balance Sheet and Amounts	December 31, 2019 and 2018 , respectively, including those subject to master netting agreements and the location of the net derivative position on our consolidated balance sheets: As of December 31, 2019 Current Assets Noncurrent Assets Current Liabilities Noncurrent Liabilities (Millions) Not designated as hedging instruments Derivative assets $ 23 $ 110 $ 42 $ 13 Derivative liabilities (1 ) (7 ) (48 ) (18 ) 22 103 (6 ) (5 ) Designated as hedging instruments Derivative assets — 18 5 4 Derivative liabilities — (9 ) (13 ) (6 ) — 9 (8 ) (2 ) Total derivatives before offset of cash collateral 22 112 (14 ) (7 ) Cash collateral (payable) receivable (11 ) (30 ) 7 6 Total derivatives as presented in the balance sheet $ 11 $ 82 $ (7 ) $ (1 ) As of December 31, 2018 Current Assets Noncurrent Assets Current Liabilities Noncurrent Liabilities (Millions) Not designated as hedging instruments Derivative assets $ 19 $ 96 $ 29 $ 17 Derivative liabilities (5 ) (3 ) (48 ) (35 ) 14 93 (19 ) (18 ) Designated as hedging instruments Derivative assets 2 1 2 4 Derivative liabilities — — (7 ) (10 ) 2 1 (5 ) (6 ) Total derivatives before offset of cash collateral 16 94 (24 ) (24 ) Cash collateral (payable) receivable (8 ) (34 ) 9 17 Total derivatives as presented in the balance sheet $ 8 $ 60 $ (15 ) $ (7 ) The tables below present Networks' derivative positions as of December 31, 2019 and 2018 , respectively, including those subject to master netting agreements and the location of the net derivative positions on our consolidated balance sheets: As of December 31, 2019 Current Assets Noncurrent Assets Current Liabilities Noncurrent Liabilities (Millions) Not designated as hedging instruments Derivative assets $ 1 $ 4 $ 1 $ 2 Derivative liabilities (1 ) (2 ) (39 ) (86 ) — 2 (38 ) (84 ) Designated as hedging instruments Derivative assets — — — — Derivative liabilities — — (1 ) (1 ) — — (1 ) (1 ) Total derivatives before offset of cash collateral — 2 (39 ) (85 ) Cash collateral receivable — — 27 1 Total derivatives as presented in the balance sheet $ — $ 2 $ (12 ) $ (84 ) As of December 31, 2018 Current Assets Noncurrent Assets Current Liabilities Noncurrent Liabilities (Millions) Not designated as hedging instruments Derivative assets $ 18 $ 6 $ 10 $ 3 Derivative liabilities (10 ) (3 ) (21 ) (93 ) 8 3 (11 ) (90 ) Designated as hedging instruments Derivative assets — — — — Derivative liabilities — — (2 ) — — — (2 ) — Total derivatives before offset of cash collateral 8 3 (13 ) (90 ) Cash collateral receivable — — — — Total derivatives as presented in the balance sheet $ 8 $ 3 $ (13 ) $ (90 )
Schedule of Notional Volumes of Outstanding Derivative Positions	The net notional volumes of the outstanding derivative instruments associated with Networks' activities as of December 31, 2019 and 2018 , respectively, consisted of: As of December 31, 2019 2018 (Millions) Wholesale electricity purchase contracts (MWh) 5.1 4.9 Natural gas purchase contracts (Dth) 8.5 7.8 Fleet fuel purchase contracts (Gallons) 2.2 2.1 The net notional volumes of outstanding derivative instruments associated with Renewables' activities as of December 31, 2019 and 2018 , respectively, consisted of: As of December 31, 2019 2018 (MWh/Dth in Millions) Wholesale electricity purchase contracts 4 5 Wholesale electricity sales contracts 9 6 Natural gas and other fuel purchase contracts 29 29 Financial power contracts 10 11 Basis swaps - purchases 42 42 Basis swaps - sales 1 4
Summary of Unrealized Gains and Losses from Fair Value Adjustments	The unrealized gains and losses from fair value adjustments to these derivatives, which are recorded in regulatory assets or regulatory liabilities, for the years ended December 31, 2019 , 2018 and 2017 , respectively, were as follows: Years Ended December 31, 2019 2018 2017 (Millions) Derivative Assets $ (3 ) $ (6 ) $ (8 ) Derivative Liabilities $ 8 $ 1 $ (9 ) The amounts for electricity hedge contracts and natural gas hedge contracts recognized in regulatory liabilities and assets as of December 31, 2019 and 2018 and amounts reclassified from regulatory assets and liabilities into income for the years ended 2019 , 2018 and 2017 are as follows: (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 For the Year Ended December 31, December 31, 2019 Electricity Natural Gas 2019 Electricity Natural Gas Regulatory assets $ 24 $ 4 Purchased power, natural gas and fuel used $ 25 $ 1 Regulatory liabilities $ — $ — December 31, 2018 2018 Regulatory assets $ — $ — Purchased power, natural gas and fuel used $ (10 ) $ (1 ) Regulatory liabilities $ 5 $ — 2017 Purchased power, natural gas and fuel used $ 37 $ —
Schedule of Fair Value, Net Derivative Contracts	The fair values of derivative contracts associated with Renewables' activities as of December 31, 2019 and 2018 , respectively, consisted of: As of December 31, 2019 2018 (Millions) Wholesale electricity purchase contracts $ 10 $ 11 Wholesale electricity sales contracts 4 (12 ) Natural gas and other fuel purchase contracts (2 ) (2 ) Financial power contracts 73 55 Basis swaps - purchases — (6 ) Total $ 85 $ 46
Effect of Derivatives Associated with Renewables and Gas Activities	The effects of trading and non-trading derivatives associated with Renewables' activities for the year ended December 31, 2019 , consisted of: Year Ended December 31, 2019 Trading Non-trading Total amount per income statement (Millions) Operating Revenues Wholesale electricity purchase contracts $ (1 ) $ — Wholesale electricity sales contracts 3 40 Financial power contracts (3 ) 23 Financial and natural gas contracts (1 ) 1 Total (loss) gain included in operating revenues $ (2 ) $ 64 $ 1,338 Purchased power, natural gas and fuel used Wholesale electricity purchase contracts $ — $ — Wholesale electricity sales contracts — — Financial power contracts — (1 ) Financial and natural gas contracts — 15 Total gain included in purchased power, natural gas and fuel used $ — $ 14 $ 1,509 Total (Loss) Gain $ (2 ) $ 78 During September 2019, Renewables liquidated a portion of one of its wholesale electricity sales contracts and recorded a gain of $43 million for the year ended December 31, 2019 . The effects of trading and non-trading derivatives associated with Renewables' and Gas' activities for the years ended December 31, 2018 and 2017 , consisted of: Years Ended December 31, 2018 2017 (Millions) Trading Non-trading Trading Non-trading Wholesale electricity purchase contracts $ 4 $ 11 $ (3 ) $ 1 Wholesale electricity sales contracts (2 ) (15 ) 4 (3 ) Financial power contracts — (19 ) (1 ) (5 ) Financial and natural gas contracts 4 — (8 ) — Natural gas and other fuel purchase contracts — — — (8 ) Total Gain (Loss) $ 6 $ (23 ) $ (8 ) $ (15 )
Schedule of Derivative Instruments	The table below presents our interest rate swap derivative positions as of December 31, 2019 and 2018 , respectively, including the location of the net derivative positions on our consolidated balance sheets: As of December 31, 2019 Current Liabilities (Millions) Designated as hedging instruments Derivative liabilities $ — As of December 31, 2018 (Millions) Designated as hedging instruments Derivative liabilities $ (16 )
Derivative Instruments, Gain (Loss) [Table Text Block]	The effect of derivatives in cash flow hedging relationships on OCI and income for the years ended December 31, 2019 , 2018 and 2017 , respectively, consisted of: Year Ended December 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) 2019 Interest rate contracts $ — Interest expense $ 6 $ 306 Commodity contracts — Purchased power, natural gas and fuel used 1 1,509 Foreign currency exchange contracts (1 ) — Total $ (1 ) $ 7 2018 Interest rate contracts $ — Interest expense $ 8 $ 303 Commodity contracts (1 ) Purchased power, natural gas and fuel used — 1,653 Total $ (1 ) $ 8 2017 Interest rate contracts $ — Interest expense $ 8 $ 280 Commodity contracts (1 ) Purchased power, natural gas and fuel used 1 1,338 Total $ (1 ) $ 9 (a) Changes in accumulated OCI are reported in pre-tax basis. The effect of derivatives in cash flow hedging relationships on accumulated OCI and income for the years ended December 31, 2019 , 2018 and 2017 consisted of: Year Ended December 31, (Loss) Gain Recognized in OCI on Derivatives (a) Location of Gain Reclassified from Accumulated OCI into Income Loss (Gain) Reclassified from Accumulated OCI into Income Total amount per Income Statement (Millions) 2019 Commodity contracts $ (5 ) Operating revenues $ 3 $ 6,338 2018 Commodity contracts $ (11 ) Operating revenues $ (22 ) $ 6,478 2017 Commodity contracts $ 41 Operating revenues $ 14 $ 5,963 (a) Changes in OCI are reported on a pre-tax basis. The effect of derivatives in cash flow hedging relationships on accumulated OCI for the years ended December 31, 2019 and 2018 , respectively, consisted of: Years Ended December 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) 2019 Interest rate contracts $ (24 ) Interest expense $ 2 $ 306 2018 Interest rate contracts $ (16 ) Interest expense $ — $ 303 (a) Changes in OCI are reported on a pre-tax basis. The amount in accumulated OCI is being reclassified into earnings over the underlying debt maturity period which ends in 2029.

Leases (Tables)

Leases (Tables)	12 Months Ended
	Dec. 31, 2019
Leases [Abstract]
Lease, Cost	For the year ended December 31, 2019 , supplemental cash flow information related to leases was as follows: For the Year Ended December 31, 2019 (Millions) Cash paid for amounts included in the measurement of lease liabilities: Operating cash flows from operating leases $ 13 Operating cash flows from finance leases $ 3 Financing cash flows from finance leases $ 27 Right-of-use assets obtained in exchange for lease obligations: Finance leases $ 1 Operating leases $ 3 The components of lease cost for the year ended December 31, 2019 were as follows: For the Year Ended December 31, 2019 (Millions) Lease cost Finance lease cost Amortization of right-of-use assets $ 12 Interest on lease liabilities 3 Total finance lease cost 15 Operating lease cost 18 Short-term lease cost 5 Variable lease cost 2 Total lease cost $ 40
Assets And Liabilities, Lessee	Balance sheet and other information for the year ended December 31, 2019 was as follows: As of December 31, 2019 (Millions, except lease term and discount rate) Operating Leases Operating lease right-of-use assets $ 70 Operating lease liabilities, current 12 Operating lease liabilities, long-term 65 Total operating lease liabilities $ 77 Finance Leases Other assets $ 133 Other current liabilities 9 Other non-current liabilities 54 Total finance lease liabilities $ 63 Weighted-average Remaining Lease Term (years) Finance leases 7.59 Operating leases 12.98 Weighted-average Discount Rate Finance leases 5.35 % Operating leases 3.62 %
Finance Lease Maturity	As of December 31, 2019 , maturities of lease liabilities were as follows: Finance Leases Operating Leases (Millions) Year ending December 31, 2020 $ 10 $ 14 2021 7 13 2022 3 10 2023 50 7 2024 — 6 Thereafter 2 51 Total lease payments 72 101 Less: imputed interest (9 ) (24 ) Total $ 63 $ 77
Operating Lease Maturity	As of December 31, 2019 , maturities of lease liabilities were as follows: Finance Leases Operating Leases (Millions) Year ending December 31, 2020 $ 10 $ 14 2021 7 13 2022 3 10 2023 50 7 2024 — 6 Thereafter 2 51 Total lease payments 72 101 Less: imputed interest (9 ) (24 ) Total $ 63 $ 77
Future Minimum Payments, Operating Leases	Total future minimum lease payments as of December 31, 2018 consisted of: Year Operating Leases Capital Leases Total (Millions) 2019 $ 31 $ 30 $ 61 2020 39 10 49 2021 38 7 45 2022 35 2 37 2023 33 50 83 Thereafter 735 2 737 Total $ 911 $ 101 $ 1,012
Future Minimum Payments, Capital Leases	Total future minimum lease payments as of December 31, 2018 consisted of: Year Operating Leases Capital Leases Total (Millions) 2019 $ 31 $ 30 $ 61 2020 39 10 49 2021 38 7 45 2022 35 2 37 2023 33 50 83 Thereafter 735 2 737 Total $ 911 $ 101 $ 1,012

Commitments and Contingent Li_2

Commitments and Contingent Liabilities (Tables)	12 Months Ended
	Dec. 31, 2019
Commitments and Contingencies Disclosure [Abstract]
Forward Purchase and Sales Commitment Arrangement	Forward purchases and sales commitments under power, gas and other arrangements as of December 31, 2019 consisted of: Year Purchases Sales (Millions) 2020 $ 1,396 $ 192 2021 177 138 2022 87 72 2023 68 52 2024 44 39 Thereafter 830 87 Totals $ 2,602 $ 580

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2019
Income Tax Disclosure [Abstract]
Schedule of Current and Deferred Taxes Charged to (Benefit) Expense	As of December 31, 2018, the Company has completed the measurement and accounting of certain effects of the Tax Act which have been reflected in the consolidated financial statements. Current and deferred taxes charged to expense (benefit) for the years ended December 31, 2019 , 2018 and 2017 consisted of: Years Ended December 31, 2019 2018 2017 (Millions) Current Federal $ 11 $ 17 $ (20 ) State (6 ) 2 12 Current taxes charged to expense (benefit) 5 19 (8 ) Deferred Federal 152 233 (124 ) State 44 (12 ) (73 ) Deferred taxes charged to expense (benefit) 196 221 (197 ) Production tax credits (57 ) (68 ) (53 ) Investment tax credits (1 ) (2 ) (1 ) Total Income Tax Expense (Benefit) $ 143 $ 170 $ (259 )
Schedule of Differences between Tax Expense Per Statements of Income and Tax Expense at Statutory Federal Tax Rate	The differences between tax expense per the statements of income and tax expense at the 21% statutory federal tax rate for the years ended December 31, 2019 and 2018 and 35% statutory federal tax rate for the year ended December 31, 2017 consisted of: Years Ended December 31, 2019 2018 2017 (Millions) Tax expense at federal statutory rate $ 172 $ 161 $ 43 Depreciation and amortization not normalized (23 ) (5 ) 9 Investment tax credit amortization (1 ) (2 ) (1 ) Tax return related adjustments (2 ) (6 ) 7 Production tax credits (57 ) (68 ) (53 ) Tax equity financing arrangements 8 — (10 ) Federal tax rate impact on held for sale classification — 21 82 State tax expense (benefit), net of federal benefit 30 (8 ) (40 ) Tax Act - remeasurement — 46 (328 ) Other, net 16 31 32 Total Income Tax Expense (Benefit) $ 143 $ 170 $ (259 )
Schedule of Deferred Tax Assets and Liabilities	Deferred tax assets and liabilities as of December 31, 2019 and 2018 consisted of: As of December 31, 2019 2018 (Millions) Deferred Income Tax Liabilities (Assets) Property related $ 4,007 $ 3,787 Unfunded future income taxes 101 107 Federal and state tax credits (632 ) (691 ) Federal and state NOL’s (989 ) (993 ) Joint ventures/partnerships 136 132 Nontaxable grant revenue (335 ) (354 ) Pension and other post-retirement benefits 43 8 Tax Act - tax on regulatory remeasurement (409 ) (393 ) Valuation allowance 33 23 Other (141 ) (102 ) Deferred Income Tax Liabilities 1,814 1,524 Classified as regulatory assets — (6 ) Total Deferred Income Tax Liabilities $ 1,814 $ 1,530 Deferred tax assets $ 2,506 $ 2,533 Deferred tax liabilities 4,320 4,057 Net Accumulated Deferred Income Tax Liabilities $ 1,814 $ 1,524
Schedule of Reconciliation of Unrecognized Income Tax Benefits	The reconciliation of unrecognized income tax benefits for the years ended December 31, 2019 , 2018 and 2017 consisted of: Years ended December 31, 2019 2018 2017 (Millions) Beginning Balance $ 153 $ 45 $ 40 Increases for tax positions related to prior years 14 111 23 Increases for tax positions related to current year 16 — — Decreases for tax positions related to prior years (18 ) (3 ) (16 ) Reduction for tax position related to settlements with taxing authorities (17 ) — (2 ) Ending Balance $ 148 $ 153 $ 45

Post-retirement and Similar O_2

Post-retirement and Similar Obligations (Tables)	12 Months Ended
	Dec. 31, 2019
Retirement Benefits [Abstract]
Obligations and Funded Status	Obligations and funded status of Networks and ARHI as of December 31, 2019 and 2018 consisted of: Pension Benefits Postretirement Benefits As of December 31, 2019 2018 2019 2018 (Millions) Change in benefit obligation Benefit obligation as of January 1, $ 3,374 $ 3,593 $ 425 $ 491 Service cost 41 44 3 4 Interest cost 130 128 16 19 Plan participants’ contributions — — — 9 Plan Amendments (2 ) — — (3 ) Actuarial loss (gain) 347 (159 ) 26 (55 ) Benefits paid (221 ) (237 ) (31 ) (41 ) Reclassified from held for sale — 5 — 1 Benefit Obligation as of December 31, 3,669 3,374 439 425 Change in plan assets Fair value of plan assets as of January 1, 2,544 2,865 148 165 Actual return (loss) on plan assets 460 (135 ) 22 (5 ) Employer contributions 65 48 16 20 Plan participants’ contributions — — — 9 Benefits paid (221 ) (237 ) (31 ) (41 ) Reclassified from held for sale — 3 — — Fair Value of Plan Assets as of December 31, 2,848 2,544 155 148 Funded Status as of December 31, $ (821 ) $ (830 ) $ (284 ) $ (277 )
Schedule of Amounts Recognized in Balance Sheet	Amounts recognized as of December 31, 2019 and 2018 consisted of: Pension Benefits Postretirement Benefits As of December 31, 2019 2018 2019 2018 (Millions) Current liabilities $ — $ — $ (5 ) $ (5 ) Non-current liabilities (821 ) (830 ) (279 ) (272 ) Total $ (821 ) $ (830 ) $ (284 ) $ (277 )
Summary of Amounts Recognized in OCI	Amounts recognized in OCI for ARHI for the years ended December 31, 2019 , 2018 and 2017 , consisted of: Pension Benefits Postretirement Benefits Years Ended December 31, 2019 2018 2017 2019 2018 2017 (Millions) Net loss (gain) $ 23 $ 24 $ 25 $ (8 ) $ (7 ) $ (4 )
Net Periodic Benefit Cost and Other Changes in Plan Assets and Benefit Obligations	Components of Networks’ net periodic benefit cost and other changes in plan assets and benefit obligations recognized in income and regulatory assets and liabilities for the years ended December 31, 2019 , 2018 and 2017 consisted of: (Millions) Pension Benefits Postretirement Benefits For the years ended December 31, 2019 2018 2017 2019 2018 2017 Net Periodic Benefit Cost: Service cost $ 41 $ 44 $ 42 $ 3 $ 4 $ 5 Interest cost 128 126 137 16 18 21 Expected return on plan assets (190 ) (199 ) (195 ) (7 ) (8 ) (8 ) Amortization of prior service (benefit) cost (1 ) 1 2 (10 ) (9 ) (9 ) Amortization of net loss 113 149 126 1 6 5 Net Periodic Benefit Cost 91 121 112 3 11 14 Other changes in plan assets and benefit obligations recognized in regulatory assets and regulatory liabilities: Net loss (gain) 80 175 3 13 (37 ) (5 ) Amortization of net loss (113 ) (149 ) (126 ) (1 ) (6 ) (5 ) Current year prior service cost (2 ) — — — (3 ) — Amortization of prior service benefit (cost) 1 (1 ) (2 ) 10 9 9 Total Other Changes (34 ) 25 (125 ) 22 (37 ) (1 ) Total Recognized $ 57 $ 146 $ (13 ) $ 25 $ (26 ) $ 13 Components of ARHI’s net periodic benefit cost and other changes in plan assets and benefit obligations recognized in income and OCI for the years ended December 31, 2019 , 2018 and 2017 consisted of: (Millions) Pension Benefits Postretirement Benefits For the years ended December 31, 2019 2018 2017 2019 2018 2017 Net Periodic Benefit Cost: Service cost $ 1 $ — $ — $ — $ — $ — Interest cost 2 2 2 — 1 1 Expected return on plan assets (2 ) (2 ) (2 ) — — — Amortization of net loss (gain) 1 1 1 (1 ) — — Settlement charge — 1 — — — — Net Periodic Benefit Cost 2 2 1 (1 ) 1 1 Other Changes in plan assets and benefit obligations recognized in OCI: Net loss (gain) — 1 2 — (3 ) (1 ) Amortization of net (loss) gain (1 ) (1 ) (1 ) 1 — — Amortization of prior service cost — — — (2 ) — — Total Other Changes (1 ) — 1 (1 ) (3 ) (1 ) Total Recognized $ 1 $ 2 $ 2 $ (2 ) $ (2 ) $ — Amounts recognized as regulatory assets or regulatory liabilities for Networks for the years ended December 31, 2019 , 2018 and 2017 consisted of: Pension Benefits Postretirement Benefits Years Ended December 31, 2019 2018 2017 2019 2018 2017 (Millions) Net loss (gain) $ 706 $ 762 $ 737 $ 13 $ (8 ) $ 35 Prior service cost (credit) $ 4 $ 4 $ 6 $ (21 ) $ (25 ) $ (31 )
Aggregate PBO and ABO and Fair Value of Plan Assets for Underfunded Plans	The aggregate PBO and ABO and the fair value of plan assets for underfunded plans of Networks and ARHI as of December 31, 2019 and 2018 consisted of: PBO in excess of plan assets As of December 31, 2019 2018 (Millions) Projected benefit obligation $ 3,669 $ 3,374 Fair value of plan assets $ 2,848 $ 2,544 ABO in excess of plan assets As of December 31, 2019 2018 (Millions) Accumulated benefit obligation $ 3,451 $ 3,174 Fair value of plan assets $ 2,848 $ 2,544
Amounts Expected to be Amortized for Net Periodic Benefit Cost	Amounts expected to be amortized from regulatory assets or liabilities into net periodic benefit cost for the year ending December 31, 2020 consist of: Pension Benefits Postretirement Benefits (Millions) Estimated net loss $ 123 $ 2 Estimated prior service cost (benefit) $ 1 $ (9 ) Amounts expected to be amortized from OCI into net periodic benefit cost for the year ending December 31, 2020 consist of: Pension Benefits Postretirement Benefits (Millions) Estimated net loss (gain) $ 2 $ (1 )
Weighted Average Assumptions Used to Determine Benefit Obligations and Net periodic Benefit Cost	The weighted-average assumptions used to determine benefit obligations for Networks and ARHI as of December 31, 2019 and 2018 consisted of: Pension Benefits Postretirement Benefits As of December 31, 2019 2018 2019 2018 Discount rate - Networks 2.93% / 3.19% 3.93% / 4.09% 2.93% / 3.19% 3.93% / 4.09% Discount rate - ARHI 3.10 % 4.09 % 3.10 % 4.09 % Rate of compensation increase - Networks 3.00% - 6.50% 3.50% - 4.20% — — The weighted-average assumptions used to determine net periodic benefit cost for Networks and ARHI for the years ended December 31, 2019 , 2018 and 2017 consisted of: Pension Benefits Postretirement Benefits Years Ended December 31, 2019 2018 2017 2019 2018 2017 Discount rate - Networks 3.93% / 4.09% 3.63% / 3.80% 4.12% / 4.24% 3.93% / 4.09% 3.63% / 3.80% 4.12% / 4.24% Discount rate - ARHI 4.09 % 3.80 % 3.81 % 4.09 % 3.80 % 3.81 % Expected long-term return on plan assets - Networks 7.00% / 7.40% 7.00% / 7.40% 7.00% / 7.50% 4.90% - 7.00% 6.13 % 6.13 % Expected long-term return on plan assets - ARHI 5.50 % 5.50 % 5.50 % 5.50 % 5.50 % 5.50 % Expected long-term return on plan assets - nontaxable trust - Networks — — — 6.40 % 6.40 % 6.50 % Expected long-term return on plan assets - taxable trust - Networks — — — 4.20 % 4.20 % 4.25 % Rate of compensation increase - Networks 3.50%-4.20% 3.50% - 4.20% 3.50% - 4.20% — — —
Assumed Health Care Cost Trend Rates Used to Determine Benefit Obligations	Assumed health care cost trend rates used to determine benefit obligations as of December 31, 2019 and 2018 consisted of: As of December 31, 2019 2018 Health care cost trend rate assumed for next year - Networks 7.00%/7.75% 7.50%/8.50% Health care cost trend rate assumed for next year - ARHI 6.75% / 7.50% 7.00%/7.75% Rate to which cost trend rate is assumed to decline (ultimate trend rate) - Networks 4.50 % 4.50 % Rate to which cost trend rate is assumed to decline (ultimate trend rate) - ARHI 4.50 % 4.50 % Year that the rate reaches the ultimate trend rate - Networks 2029 / 2027 2030 / 2028 Year that the rate reaches the ultimate trend rate - ARHI 2029 / 2027 2029 / 2027
One Percent Change in Assumed Health Care Cost Trend Rates	The effects of a one-percent change in the assumed health care cost trend rates would have the following effects: 1% Increase 1% Decrease (Millions) Effect on total of service and interest cost $ 1 $ — Effect on postretirement benefit obligation $ 12 $ (11 )
Expected Future Benefits Payments	Expected benefit payments and Medicare Prescription Drug, Improvement and Modernization Act of 2003 subsidy receipts reflecting expected future service for Networks and ARHI as of December 31, 2019 consisted of: (Millions) Pension Benefits Postretirement Benefits Medicare Act Subsidy Receipts 2020 $ 209 $ 32 $ 1 2021 $ 210 $ 32 $ 1 2022 $ 216 $ 31 $ — 2023 $ 217 $ 30 $ — 2024 $ 219 $ 29 $ — 2025 - 2028 $ 1,097 $ 134 $ 2
Fair Values of Pension Benefits Plan Assets, by Asset Category	The fair values of pension benefits plan assets, by asset category, as of December 31, 2019 , consisted of: As of December 31, 2019 Fair Value Measurements (Millions) Total Level 1 Level 2 Level 3 Asset Category Cash and cash equivalents $ 42 $ — $ 42 $ — U.S. government securities 87 87 — — Registered investment companies 464 464 — — Corporate bonds 458 — 458 — Preferred stocks 1 1 — — Common collective trusts 572 — 572 — Other, principally annuity, fixed income 84 — 84 — $ 1,708 $ 552 $ 1,156 $ — Other investments measured at net asset value 1,140 Total $ 2,848 The fair values of pension benefits plan assets, by asset category, as of December 31, 2018 (a), consisted of: As of December 31, 2018 Fair Value Measurements (Millions) Total Level 1 Level 2 Level 3 Asset Category Cash and cash equivalents $ 52 $ — $ 52 $ — U.S. government securities 15 15 — — Registered investment companies 424 421 3 — Corporate bonds 413 — 413 — Preferred stocks 3 — 3 — Common collective trusts 634 — 634 — Other, principally annuity, fixed income 71 — 71 — $ 1,612 $ 436 $ 1,176 $ — Other investments measured at net asset value 932 Total $ 2,544 (a) Certain amounts have been reclassified within this table to conform to the 2019 presentation.
Fair Value of Other Postretirement Benefits Plan Assets, by Asset Category	The fair values of other postretirement benefits plan assets, by asset category, as of December 31, 2019 consisted of: As of December 31, 2019 Fair Value Measurements (Millions) Total Level 1 Level 2 Level 3 Asset Category Cash and cash equivalents $ 31 $ — $ 31 $ — Common stocks 16 16 — — Registered investment companies 98 98 — — Corporate bonds 2 — 2 — Other, principally annuity, fixed income 8 — 8 — Total $ 155 $ 114 $ 41 $ — The fair values of other postretirement benefits plan assets, by asset category, as of December 31, 2018 (a) consisted of: As of December 31, 2018 Fair Value Measurements (Millions) Total Level 1 Level 2 Level 3 Asset Category Cash and cash equivalents $ 9 $ 5 $ 4 $ — Common stocks 15 15 — — Registered investment companies 115 115 — — Corporate bonds 2 — 2 — Other, principally annuity, fixed income 7 — 7 — Total $ 148 $ 135 $ 13 $ — (a) Certain amounts have been reclassified within this table to conform to the 2019 presentation.

Equity (Tables)

Equity (Tables)	12 Months Ended
	Dec. 31, 2019
Equity [Abstract]
Accumulated Other Comprehensive Income (Loss)	Accumulated OCI (Loss) for the years ended December 31, 2019 , 2018 and 2017 consisted of: Accumulated Other Comprehensive Income (Loss) As of December 31, 2016 2017 Change As of December 31, 2017 Adoption of new accounting standard 2018 Change As of December 31, 2018 Adoption of new accounting standard 2019 Change As of December 31, 2019 (Millions) Change in revaluation of defined benefit plans, net of income tax expense (benefit) of $1.1 for 2018 and $(0.3) for 2019 $ (14 ) $ — $ (14 ) $ — $ 3 $ (11 ) $ (2 ) $ 1 $ (12 ) Loss (gain) for nonqualified pension plans, net of income tax expense (benefit) of $0.2 for 2017, $0.3 for 2018 and $(1.0) for 2019 (7 ) 1 (6 ) (1 ) 1 (6 ) — (1 ) (7 ) Unrealized (loss) gain on derivatives qualifying as cash flow hedges: Unrealized gain (loss) during period on derivatives qualifying as cash flow hedges, net of income tax expense (benefit) of $15.2 for 2017, $(6.6) for 2018 and $(8.6) for 2019 5 25 30 — (21 ) 9 — (22 ) (13 ) Reclassification to net income of losses (gains) on cash flow hedges, net of income tax expense (benefit) of $9.3 for 2017, $(6.5) for 2018 and $2.7 for 2019 (a) (70 ) 14 (56 ) — (8 ) (64 ) (10 ) 11 (63 ) Gain (loss) on derivatives qualifying as cash flow hedges (65 ) 39 (26 ) — (29 ) (55 ) (10 ) (11 ) (76 ) Accumulated Other Comprehensive (Loss) Income $ (86 ) $ 40 $ (46 ) $ (1 ) $ (25 ) $ (72 ) $ (12 ) $ (11 ) $ (95 ) (a) Reclassification is reflected in the operating expenses line item in the consolidated statements of income.

Earnings Per Share (Tables)

Earnings Per Share (Tables)	12 Months Ended
	Dec. 31, 2019
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 years ended December 31, 2019 , 2018 and 2017 , consisted of: Years Ended December 31, 2019 2018 2017 (Millions, except for number of shares and per share data) Numerator: Net income attributable to AVANGRID $ 700 $ 595 $ 381 Denominator: Weighted average number of shares outstanding - basic 309,491,082 309,503,319 309,502,861 Weighted average number of shares outstanding - diluted 309,514,910 309,712,628 309,661,883 Earnings per share attributable to AVANGRID Earnings Per Common Share, Basic $ 2.26 $ 1.92 $ 1.23 Earnings Per Common Share, Diluted $ 2.26 $ 1.92 $ 1.23

Grants, Government Incentives_2

Grants, Government Incentives and Deferred Income (Tables)	12 Months Ended
	Dec. 31, 2019
Other Liabilities Disclosure [Abstract]
Schedule of Changes in Deferred Income	The changes in deferred income as of December 31, 2019 and 2018 consisted of: (Millions) Government grants Other deferred income Total As of December 31, 2017 $ 1,427 $ 19 $ 1,446 Additions 9 — 9 Recognized in income (69 ) (1 ) (70 ) As of December 31, 2018 1,367 18 1,385 Disposals (3 ) — (3 ) Derecognition due to sale (a) (38 ) — (38 ) Recognized in income (68 ) (2 ) (70 ) As of December 31, 2019 $ 1,258 $ 16 $ 1,274 (a) Grants no longer controlled by us due to the 2019 sale of a 50% interest in the Poseidon projects. See Note 22 for further information.

Other Financial Statements It_2

Other Financial Statements Items (Tables)	12 Months Ended
	Dec. 31, 2019
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Schedule of Other Income and (Expense)	Other income (expense) for the years ended December 31, 2019 , 2018 and 2017 consisted of: Years ended December 31, 2019 2018 2017 (Millions) Gain on sale of assets (a) $ 148 $ 10 $ — Allowance for funds used during construction 46 30 36 Carrying costs on regulatory assets 21 21 11 Non-service component of net periodic benefit cost (79 ) (128 ) (120 ) Other (17 ) 1 11 Total Other Income (Expense) $ 119 $ (66 ) $ (62 ) (a) 2019 includes a $134 million gain from the sale of 50% of our interest in the Poseidon projects, and 2018 includes a $10 million gain from the sale of our interest in Coyote Ridge (see Note 22).
Schedule of Accounts Receivable and Change in Allowance For Bad Debts	Accounts receivable as of December 31, 2019 and 2018 consisted of: As of December 31, 2019 2018 (Millions) Trade receivables $ 1,151 $ 1,204 Allowance for bad debts (69 ) (62 ) Total Accounts Receivable $ 1,082 $ 1,142 The allowance for bad debts relates entirely to gas and electricity consumers and comprises an amount that has been reserved following historical averages of loss percentages. The change in the allowance for bad debts as of December 31, 2019 and 2018 consisted of: (Millions) As of December 31, 2016 $ 64 Current period provision 69 Write-off as uncollectible (69 ) As of December 31, 2017 $ 64 Current period provision 74 Write-off as uncollectible (76 ) As of December 31, 2018 $ 62 Current period provision 92 Write-off as uncollectible (85 ) As of December 31, 2019 $ 69
Schedule of Prepayments and Other Current Assets	Prepayments and other current assets as of December 31, 2019 and 2018 consisted of: As of December 31, 2019 2018 (Millions) Prepaid other taxes $ 123 $ 137 Broker margin and collateral accounts 33 37 Other pledged deposits 3 6 Prepaid expenses 34 43 Other 6 6 Total $ 199 $ 229
Schedule of Other Current Liabilities	Other current liabilities as of December 31, 2019 and 2018 consisted of: As of December 31, 2019 2018 (Millions) Advances received $ 140 $ 129 Accrued salaries 89 81 Short-term environmental provisions 40 60 Collateral deposits received 44 42 Pension and other postretirement 5 5 Finance leases 9 — Other 7 10 Total $ 334 $ 327

Segment Information (Tables)

Segment Information (Tables)	12 Months Ended
	Dec. 31, 2019
Segment Reporting [Abstract]
Schedule of Segment Information	Segment information as of and for the year ended December 31, 2019 consisted of: For the year ended December 31, 2019 Networks Renewables Other(a) AVANGRID Consolidated Revenue - external $ 5,150 $ 1,186 $ 2 $ 6,338 Revenue - intersegment 14 — (14 ) — Depreciation and amortization 550 383 1 934 Operating income 893 95 15 1,003 Earnings (losses) from equity method investments 11 (8 ) — 3 Interest expense, net of capitalization 269 10 27 306 Income tax expense (benefit) 153 4 (14 ) 143 Capital expenditures 1,612 1,125 3 2,740 Adjusted net income 466 223 (15 ) 673 As of December 31, 2019 Property, plant and equipment 15,840 9,368 10 25,218 Equity method investments 139 506 — 645 Total assets $ 23,250 $ 13,163 $ (1,997 ) $ 34,416 (a) Includes Corporate and intersegment eliminations. Segment information as of and for the year ended December 31, 2018 consisted of: For the year ended December 31, 2018 Networks Renewables Other(a) AVANGRID Consolidated Revenue - external $ 5,304 $ 1,137 $ 37 $ 6,478 Revenue - intersegment 6 2 (8 ) — Loss from assets held for sale — — 16 16 Depreciation and amortization 503 352 — 855 Operating income 975 136 16 1,127 Earnings (losses) from equity method investments 13 (3 ) — 10 Interest expense, net of capitalization 260 33 10 303 Income tax expense (benefit) 169 (31 ) 32 170 Capital expenditures 1,377 410 — 1,787 Adjusted net income 486 185 13 684 As of December 31, 2018 Property, plant and equipment 14,754 8,697 8 23,459 Equity method investments 142 224 — 366 Total assets $ 22,239 $ 10,703 $ (775 ) $ 32,167 (a) Includes Corporate, Gas and intersegment eliminations. Segment information for the year ended December 31, 2017 consisted of: For the year ended December 31, 2017 Networks Renewables Other (a) AVANGRID Consolidated Revenue - external $ 4,950 $ 1,038 $ (25 ) $ 5,963 Revenue - intersegment 11 9 (20 ) — Loss from assets held for sale — — 642 642 Depreciation and amortization 474 325 25 824 Operating income (loss) 1,114 92 (701 ) 505 Earnings (losses) from equity method investments 15 (55 ) — (40 ) Interest expense, net of capitalization 244 28 8 280 Income tax expense (benefit) 316 (320 ) (255 ) (259 ) Capital expenditures 1,305 1,097 14 2,416 Adjusted net income $ 507 $ 120 $ 55 $ 682 (a) Includes Corporate, Gas and intersegment eliminations.
Schedule of Reconciliation of Consolidated EBITDA to Consolidated Net Income	Reconciliation of Adjusted Net Income to Net Income attributable to AVANGRID for the years ended December 31, 2019 , 2018 and 2017 is as follows: Years Ended December 31, 2019 2018 2017 (Millions) Adjusted Net Income Attributable to Avangrid, Inc. $ 673 $ 684 $ 682 Adjustments: Impairment of equity method and other investment (1) — — (49 ) Restructuring charges (2) (6 ) (4 ) (20 ) Mark-to-market adjustments - Renewables (3) 76 (25 ) (15 ) Loss from held for sale measurement (4) — (16 ) (642 ) Impact of the Tax Act (5) — (46 ) 328 Accelerated depreciation from repowering (6) (33 ) (3 ) — Income tax impact of adjustments (10 ) (6 ) 162 Gas Storage, net of tax (7) — 11 (64 ) Net Income Attributable to Avangrid, Inc. $ 700 $ 595 $ 381 (1) Represents OTTI on equity method investment recorded in 2017. (2) Restructuring and severance related charges relate to costs resulted from restructuring actions involving initial targeted voluntary workforce reductions and related costs in our plan to vacate a lease, predominantly within the Networks segment and costs to implement an initiative to mitigate costs and achieve sustainable growth (See Note 27 - Restructuring and Severance Related Expenses – for further details). (3) Mark-to-market earnings relates to earnings impacts from changes in the fair value of Renewables' derivative instruments associated with electricity and natural gas. (4) Represents loss from measurement of assets and liabilities held for sale in connection with the committed plan to sell the gas trading and storage businesses. (5) Represents the impact from measurement of deferred income tax balances as a result of the Tax Act enacted by the U.S. federal government on December 22, 2017. (6) Represents the amount of accelerated depreciation derived from repowering wind farms in Renewables. (7) Removal of the impact from Gas activity in the reconciliation to AVANGRID Net Income.

Related Party Transactions (Tab

Related Party Transactions (Tables)	12 Months Ended
	Dec. 31, 2019
Related Party Transactions [Abstract]
Schedule of Related Party Transactions and Balances	Related party balances as of December 31, 2019 and 2018 , respectively, consisted of: As of December 31, 2019 2018 (Millions) Owed By Owed To Owed By Owed To Siemens-Gamesa $ — $ (18 ) $ — $ (14 ) Iberdrola, S.A. $ 1 $ (42 ) $ 1 $ (40 ) Iberdrola Renovables Energía, S.L. $ — $ — $ 4 $ — Vineyard Wind $ 5 $ — $ — $ — Other $ 4 $ (4 ) $ 1 $ (4 ) Related party transactions for the years ended December 31, 2019 , 2018 and 2017 , respectively, consisted of: Years Ended December 31, 2019 2018 2017 (Millions) Sales To Purchases From Sales To Purchases From Sales To Purchases From Iberdrola Canada Energy Services, Ltd $ — $ — $ — $ (5 ) $ — $ (33 ) Iberdrola Renovables Energia, S.L. $ — $ (9 ) $ — $ (14 ) $ — $ (9 ) Iberdrola, S.A. $ 1 $ (42 ) $ 1 $ (38 ) $ 1 $ (36 ) Iberdrola Financiación, S.A. $ — $ (3 ) $ — $ (3 ) $ — $ (2 ) Iberdrola Energia Monterrey, S.A. de C.V. $ — $ — $ 3 $ — $ 46 $ — Vineyard Wind $ 13 $ — $ 3 $ — $ — $ — Other $ 2 $ (3 ) $ 2 $ (5 ) $ 1 $ (1 )

Stock-Based Compensation (Table

Stock-Based Compensation (Tables)	12 Months Ended
	Dec. 31, 2019
Share-based Payment Arrangement [Abstract]
Summary of Nonvested PSUs	A summary of the status of the AVANGRID's nonvested PSUs and RSUs as of December 31, 2019 , and changes during the fiscal year ended December 31, 2019 , is presented below: Number of PSUs Weighted Average Grant Date Fair Value Nonvested Balance – December 31, 2018 1,268,722 $ 32.80 Granted 6,284 $ 38.78 Forfeited (726 ) $ 31.80 Nonvested Balance – December 31, 2019 1,274,280 $ 32.83

Restructuring and Severance R_2

Restructuring and Severance Related Expenses (Tables)	12 Months Ended
	Dec. 31, 2019
Restructuring and Related Activities [Abstract]
Summary of Severance and Lease Restructuring Charges Reserves Recorded in Other Current Liabilities and Other Liabilities	For the year ended December 31, 2019 , the severance and lease restructuring charges reserves, which are recorded in “Other current liabilities” and “Other liabilities”, consisted of: For the Year Ended December 31, 2019 (Millions) Beginning Balance $ 4 Restructuring and severance related expenses 4 Payments (3 ) Ending Balance $ 5

Quarterly financial data (una_2

Quarterly financial data (unaudited) (Tables)	12 Months Ended
	Dec. 31, 2019
Selected Quarterly Financial Information [Abstract]
Schedule of Quarterly Financial Data	Selected quarterly financial data for 2019 and 2018 are set forth below: 1st Quarter 2nd Quarter 3rd Quarter 4th Quarter (Millions, except per share data) 2019 Operating revenues $ 1,842 $ 1,400 $ 1,487 $ 1,609 Operating Income $ 341 $ 207 $ 239 $ 216 Net Income $ 216 $ 105 $ 139 $ 216 Net Income attributable to Avangrid, Inc. $ 217 $ 110 $ 150 $ 223 Earnings Per Common Share, Basic and Diluted: (1) $ 0.70 $ 0.36 $ 0.48 $ 0.72 2018 Operating revenues $ 1,865 $ 1,402 $ 1,546 $ 1,665 Operating Income $ 403 $ 222 $ 253 $ 249 Net Income $ 238 $ 110 $ 134 $ 116 Net Income attributable to Avangrid, Inc. $ 244 $ 107 $ 125 $ 119 Earnings Per Common Share, Basic and Diluted: (1) $ 0.79 0.35/0.34 $ 0.40 $ 0.38 (1) Based on 309.5 million weighted average number of shares outstanding each quarter in both 2019 and 2018 for basic and diluted earnings per share.

Background and Nature of Oper_2

Background and Nature of Operations (Details)	Dec. 31, 2019
Avangrid | Iberdrola S.A.
Noncontrolling Interest [Line Items]
Parent company, ownership percentage	81.50%

Summary of Significant Accoun_4

Summary of Significant Accounting Policies, New Accounting Pronouncements, and Use of Estimates - Additional Information (Details) - USD ($) $ in Millions	Jan. 01, 2019	Dec. 31, 2019
Finite-Lived Intangible Assets [Line Items]
Average remaining service period		10 years
Reclassification from aoci to retained earnings	$ 12
Min.
Finite-Lived Intangible Assets [Line Items]
Useful economic life		4 years
Max.
Finite-Lived Intangible Assets [Line Items]
Useful economic life		40 years

Summary of Significant Accoun_5

Summary of Significant Accounting Policies, New Accounting Pronouncements, and Use of Estimates - Property, Plant and Equipment (Details)	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Property, Plant and Equipment [Line Items]
Composite rate	2.90%	2.80%
Min. | Plant | Combined cycle plants
Property, Plant and Equipment [Line Items]
Estimated Useful Life (years)	35 years
Min. | Plant | Hydroelectric power stations
Property, Plant and Equipment [Line Items]
Estimated Useful Life (years)	35 years
Min. | Plant | Wind power stations
Property, Plant and Equipment [Line Items]
Estimated Useful Life (years)	20 years
Min. | Plant | Transport facilities
Property, Plant and Equipment [Line Items]
Estimated Useful Life (years)	40 years
Min. | Plant | Distribution facilities
Property, Plant and Equipment [Line Items]
Estimated Useful Life (years)	5 years
Min. | Equipment | Conventional meters and measuring devices
Property, Plant and Equipment [Line Items]
Estimated Useful Life (years)	7 years
Min. | Equipment | Computer software
Property, Plant and Equipment [Line Items]
Estimated Useful Life (years)	4 years
Min. | Other | Buildings
Property, Plant and Equipment [Line Items]
Estimated Useful Life (years)	30 years
Min. | Other | Operations offices
Property, Plant and Equipment [Line Items]
Estimated Useful Life (years)	5 years
Max. | Plant | Combined cycle plants
Property, Plant and Equipment [Line Items]
Estimated Useful Life (years)	75 years
Max. | Plant | Hydroelectric power stations
Property, Plant and Equipment [Line Items]
Estimated Useful Life (years)	90 years
Max. | Plant | Wind power stations
Property, Plant and Equipment [Line Items]
Estimated Useful Life (years)	40 years
Max. | Plant | Transport facilities
Property, Plant and Equipment [Line Items]
Estimated Useful Life (years)	75 years
Max. | Plant | Distribution facilities
Property, Plant and Equipment [Line Items]
Estimated Useful Life (years)	82 years
Max. | Equipment | Conventional meters and measuring devices
Property, Plant and Equipment [Line Items]
Estimated Useful Life (years)	41 years
Max. | Equipment | Computer software
Property, Plant and Equipment [Line Items]
Estimated Useful Life (years)	25 years
Max. | Other | Buildings
Property, Plant and Equipment [Line Items]
Estimated Useful Life (years)	82 years
Max. | Other | Operations offices
Property, Plant and Equipment [Line Items]
Estimated Useful Life (years)	75 years

Summary of Significant Accoun_6

Summary of Significant Accounting Policies, New Accounting Pronouncements, and Use of Estimates - Leases (Details) - USD ($) $ in Millions	Dec. 31, 2019	Jan. 01, 2019	Dec. 31, 2018
Assets
Total Property, Plant and Equipment ($787 and $726 related to VIEs, respectively)	$ 25,218	$ 23,312	$ 23,459
Operating lease right-of-use assets	70	82
Other	311	308	162
Liabilities
Current portion of debt	730	366	394
Operating lease liabilities, current	12	8
Other current liabilities	334	355	327
Operating lease liabilities, long-term	65	74
Other	380	560	499
Non-current debt	6,716	5,307	5,368
Equity
Retained earnings	$ 1,681	1,527	$ 1,528
Adjustments Due to ASC 842
Assets
Total Property, Plant and Equipment ($787 and $726 related to VIEs, respectively)		(147)
Operating lease right-of-use assets		82
Other		146
Liabilities
Current portion of debt		(28)
Operating lease liabilities, current		8
Other current liabilities		28
Operating lease liabilities, long-term		74
Other		61
Non-current debt		(61)
Equity
Retained earnings		$ (1)

Summary of Significant Accoun_7

Summary of Significant Accounting Policies, New Accounting Pronouncements, and Use of Estimates - Union Collective Bargaining Agreements (Details) - Unionized Employees Concentration Risk	12 Months Ended
	Dec. 31, 2019
Employees covered by a collective bargaining agreement
Concentration Risk [Line Items]
Percentage of employees covered by collective bargaining agreement	49.00%
Agreements which will expire within the coming year
Concentration Risk [Line Items]
Percentage of employees covered by collective bargaining agreement	25.50%

Revenue - Narrative (Details)

Revenue - Narrative (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Disaggregation of Revenue [Line Items]
Contract asset amortization term	10 years
Contract assets, noncurrent	$ 12	$ 9
Contract liabilities, current	10	9
Contract liabilities, revenue recognized	21	13
Accounts receivable related to contracts with customers	1,050	1,118
Unbilled contracts receivable	$ 345	$ 374
Min. | Transmission Congestion Contracts
Disaggregation of Revenue [Line Items]
Revenue performance obligation, timing	P6M
Max. | Transmission Congestion Contracts
Disaggregation of Revenue [Line Items]
Revenue performance obligation, timing	P2Y
Networks
Disaggregation of Revenue [Line Items]
Revenue performance obligation, timing	P1Y
Renewables
Disaggregation of Revenue [Line Items]
Capitalized contract cost amortization term	15 years

Revenue - Schedule of Revenues

Revenue - Schedule of Revenues Disaggregated by Major Source for Reportable Segments (Details) - USD ($) $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Segment Reporting Information [Line Items]
Revenue from contracts with customers									$ 5,965	$ 5,824
Leasing revenue									6
Leasing revenue										384
Derivative revenue									244	134
Alternative revenue programs									75	80
Other revenue									48	56
Total operating revenues	$ 1,609	$ 1,487	$ 1,400	$ 1,842	$ 1,665	$ 1,546	$ 1,402	$ 1,865	6,338	6,478	$ 5,963
Regulated operations – electricity
Segment Reporting Information [Line Items]
Revenue from contracts with customers									3,485	3,641
Regulated operations – natural gas
Segment Reporting Information [Line Items]
Revenue from contracts with customers									1,479	1,473
Nonregulated operations – wind
Segment Reporting Information [Line Items]
Revenue from contracts with customers									805	637
Nonregulated operations – solar
Segment Reporting Information [Line Items]
Revenue from contracts with customers									26	17
Nonregulated operations – thermal
Segment Reporting Information [Line Items]
Revenue from contracts with customers									29	47
Nonregulated operations – gas storage
Segment Reporting Information [Line Items]
Revenue from contracts with customers									0	10
Other
Segment Reporting Information [Line Items]
Revenue from contracts with customers									141	(1)
Networks
Segment Reporting Information [Line Items]
Total operating revenues									5,150	5,304
Renewables
Segment Reporting Information [Line Items]
Total operating revenues									1,186	1,137
Operating Segments | Networks
Segment Reporting Information [Line Items]
Revenue from contracts with customers									5,055	5,172
Leasing revenue									6
Leasing revenue										38
Derivative revenue									0	0
Alternative revenue programs									75	80
Other revenue									28	20
Total operating revenues									5,164	5,310	4,950
Operating Segments | Networks | Regulated operations – electricity
Segment Reporting Information [Line Items]
Revenue from contracts with customers									3,485	3,641
Operating Segments | Networks | Regulated operations – natural gas
Segment Reporting Information [Line Items]
Revenue from contracts with customers									1,479	1,473
Operating Segments | Networks | Nonregulated operations – wind
Segment Reporting Information [Line Items]
Revenue from contracts with customers									0	0
Operating Segments | Networks | Nonregulated operations – solar
Segment Reporting Information [Line Items]
Revenue from contracts with customers									0	0
Operating Segments | Networks | Nonregulated operations – thermal
Segment Reporting Information [Line Items]
Revenue from contracts with customers									0	0
Operating Segments | Networks | Nonregulated operations – gas storage
Segment Reporting Information [Line Items]
Revenue from contracts with customers									0	0
Operating Segments | Networks | Other
Segment Reporting Information [Line Items]
Revenue from contracts with customers									91	58
Operating Segments | Renewables
Segment Reporting Information [Line Items]
Revenue from contracts with customers									922	633
Leasing revenue									0
Leasing revenue										346
Derivative revenue									244	124
Alternative revenue programs									0	0
Other revenue									20	36
Total operating revenues									1,186	1,139	$ 1,038
Operating Segments | Renewables | Regulated operations – electricity
Segment Reporting Information [Line Items]
Revenue from contracts with customers									0	0
Operating Segments | Renewables | Regulated operations – natural gas
Segment Reporting Information [Line Items]
Revenue from contracts with customers									0	0
Operating Segments | Renewables | Nonregulated operations – wind
Segment Reporting Information [Line Items]
Revenue from contracts with customers									805	637
Operating Segments | Renewables | Nonregulated operations – solar
Segment Reporting Information [Line Items]
Revenue from contracts with customers									26	17
Operating Segments | Renewables | Nonregulated operations – thermal
Segment Reporting Information [Line Items]
Revenue from contracts with customers									29	47
Operating Segments | Renewables | Nonregulated operations – gas storage
Segment Reporting Information [Line Items]
Revenue from contracts with customers									0	0
Operating Segments | Renewables | Other
Segment Reporting Information [Line Items]
Revenue from contracts with customers									62	(68)
Other
Segment Reporting Information [Line Items]
Revenue from contracts with customers									(12)	19
Leasing revenue									0
Leasing revenue										0
Derivative revenue									0	10
Alternative revenue programs									0	0
Other revenue									0	0
Total operating revenues									(12)	29
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 | Nonregulated operations – gas storage
Segment Reporting Information [Line Items]
Revenue from contracts with customers									0	10
Other | Other
Segment Reporting Information [Line Items]
Revenue from contracts with customers									$ (12)	$ 9

Revenue - Schedule of Aggregate

Revenue - Schedule of Aggregate Transaction Price Allocated to Unsatisfied Performance Obligations and Expected Time to Recognize Revenue (Details) $ in Millions	Dec. 31, 2019USD ($)
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2020-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total operating revenues	$ 58
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2020-01-01 | Revenue expected to be recognized on multiyear retail energy sales contracts in place
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total operating revenues	$ 1
Remaining performance obligation, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2020-01-01 | 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	$ 35
Remaining performance obligation, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2020-01-01 | 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	$ 22
Remaining performance obligation, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2021-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total operating revenues	$ 44
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2021-01-01 | Revenue expected to be recognized on multiyear retail energy sales contracts in place
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total operating revenues	$ 1
Remaining performance obligation, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2021-01-01 | 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	$ 27
Remaining performance obligation, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2021-01-01 | 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	$ 16
Remaining performance obligation, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2022-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total operating revenues	$ 28
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2022-01-01 | Revenue expected to be recognized on multiyear retail energy sales contracts in place
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total operating revenues	$ 1
Remaining performance obligation, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2022-01-01 | 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	$ 19
Remaining performance obligation, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2022-01-01 | 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	$ 8
Remaining performance obligation, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2023-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total operating revenues	$ 17
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2023-01-01 | Revenue expected to be recognized on multiyear retail energy sales contracts in place
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total operating revenues	$ 1
Remaining performance obligation, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2023-01-01 | 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	$ 11
Remaining performance obligation, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2023-01-01 | 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	$ 5
Remaining performance obligation, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2024-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total operating revenues	$ 13
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2024-01-01 | Revenue expected to be recognized on multiyear retail energy sales contracts in place
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total operating revenues	$ 1
Remaining performance obligation, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2024-01-01 | 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	$ 8
Remaining performance obligation, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2024-01-01 | 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	$ 4
Remaining performance obligation, period	1 year
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	$ 33
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]
Total operating revenues	$ 0
Remaining performance obligation, period
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	$ 25
Remaining performance obligation, period
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	$ 8
Remaining performance obligation, period
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: (nil)
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total operating revenues	$ 194
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: (nil) | Revenue expected to be recognized on multiyear retail energy sales contracts in place
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total operating revenues	$ 5
Remaining performance obligation, period
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: (nil) | 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	$ 126
Remaining performance obligation, period
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: (nil) | 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	$ 63
Remaining performance obligation, period

Industry Regulation - Additiona

Industry Regulation - Additional Information (Details) MWh in Millions

Feb. 19, 2020USD ($)

Jan. 30, 2020

Jan. 21, 2020

Jan. 09, 2020

Dec. 09, 2019USD ($)

Nov. 01, 2019USD ($)

Sep. 15, 2019USD ($)

Jun. 17, 2019USD ($)

May 31, 2019projectagreement

May 20, 2019USD ($)

Feb. 01, 2019USD ($)

Jan. 14, 2019USD ($)

Jan. 01, 2019USD ($)

Dec. 28, 2018MWhproject

Dec. 19, 2018agreement

Oct. 15, 2018

Sep. 10, 2018USD ($)

Jan. 01, 2018USD ($)

Jan. 01, 2017

Jun. 15, 2016

Feb. 23, 2016USD ($)

Jul. 03, 2014

Mar. 31, 2010USD ($)MW

Nov. 30, 2019project

Aug. 31, 2019MW

Oct. 31, 2018agreementMW

Dec. 31, 2017

Mar. 31, 2017projectorder

Dec. 31, 2016

Dec. 31, 2019USD ($)companyplantMW

Apr. 30, 2019

Dec. 31, 2018USD ($)

Apr. 30, 2018

Apr. 30, 2017

Mar. 31, 2017

Jun. 30, 2017USD ($)

Aug. 04, 2016USD ($)

Public Utilities, General Disclosures [Line Items]

Number of networks supply companies | company

8,000,000

Proposed ROE for the year 2018

9.70%

9.10%

Equity ratio

54.00%

50.00%

Percentage of distribution earnings

50.00%

Purchase obligation per year

$ 2,602,000,000

Approved return on equity

9.88%

Accrual for environmental loss contingencies

$ 349,000,000

$ 366,000,000

Percentage of standard service customers with wholesale power supply agreements in place for the second half of 2018

70.00%

Percentage of standard service customers with wholesale power supply agreements in place for the first half of 2019

40.00%

Equity ratio, year three

55.00%

Number of REV related orders issued | order

3

Number of energy storage projects | project

2

Regulatory assets

$ 2,861,000,000

2,945,000,000

Minimum deferred cost required for offset per month

$ 2,300,000

Number of average months used to set rate

13 months

Restricted net assets

$ 5,090,000,000

Number of peaking generation plants | plant

2

Storm costs

Public Utilities, General Disclosures [Line Items]

Regulatory assets

$ 272,000,000

346,000,000

Federal Tax Depreciation Normalization Adjustment

Public Utilities, General Disclosures [Line Items]

Regulatory assets

$ 153,000,000

$ 157,000,000

CMP Distribution

Public Utilities, General Disclosures [Line Items]

Distribution rate review process period

14 months

Annual distribution tariff increase percentage

10.70%

Annual distribution tariff increase

$ 24,300,000

Distribution tariff rate increased based on ROE

9.45%

Distribution tariff rate increased based on equity capital

50.00%

Recovery mechanism when storm cost exceed

$ 3,500,000

Sharing basis of storm cost

50.00%

Exposure limit of storm cost

$ 3,000,000

Proposed ROE for the year 2018

10.00%

Equity ratio

55.00%

Period of purchase commitment

20 years

Number of megawatts energy to be purchased from evergreen Rollins wind | MW

60

Purchase obligation per year

$ 7,000,000

Central Maine Power

Public Utilities, General Disclosures [Line Items]

Percentage of return on equity

8.75%

9.35%

Current cap on shared service costs

$ 31,400,000

NYSEG Gas

Public Utilities, General Disclosures [Line Items]

Equity ratio

48.00%

Percentage of return on equity

9.75%

9.65%

9.50%

Approved return on equity

9.00%

Equity ratio for earnings sharing

50.00%

Customer receiving percentage

50.00%

RG&E Electric

Public Utilities, General Disclosures [Line Items]

Equity ratio

48.00%

Percentage of return on equity

10.25%

10.15%

10.00%

Approved return on equity

9.00%

Equity ratio for earnings sharing

50.00%

Customer receiving percentage

75.00%

Percentage of revenue entitled

70.00%

Maximum amount of investment under credit agreement

$ 110,000,000

RG&E Electric | Deferred Storm Cost Amortization 1 Year

Public Utilities, General Disclosures [Line Items]

Amortization of deferred storm cost

$ 2,500,000

NYDPS

Public Utilities, General Disclosures [Line Items]

Percentage of return on equity

9.50%

Equity ratio for earnings sharing

50.00%

NYPSC

Public Utilities, General Disclosures [Line Items]

Equity ratio

48.00%

Public utilities regulatory authority distribution rate

8.20%

RG&E

Public Utilities, General Disclosures [Line Items]

Percentage of revenue entitled

70.00%

NYSEG

Public Utilities, General Disclosures [Line Items]

Depreciation amortization period

3 years

Accrual for environmental loss contingencies

$ 31,100,000

RG&E Gas

Public Utilities, General Disclosures [Line Items]

Equity ratio

48.00%

Percentage of return on equity

10.75%

10.65%

10.50%

Approved return on equity

9.00%

Equity ratio for earnings sharing

50.00%

Customer receiving percentage

90.00%

NYSEG Electric

Public Utilities, General Disclosures [Line Items]

Equity ratio

48.00%

Approved return on equity

9.00%

Equity ratio for earnings sharing

50.00%

Recovery of deferred storm costs

$ 262,000,000

NYSEG Electric | Storm costs

Public Utilities, General Disclosures [Line Items]

Depreciation amortization period

10 years

NYSEG Electric | Regulatory Items Other Than Storm Costs

Public Utilities, General Disclosures [Line Items]

Depreciation amortization period

5 years

NYSEG Electric | Storm costs, ten year recovery

Public Utilities, General Disclosures [Line Items]

Amortization of deferred storm cost

$ 123,000,000

NYSEG Electric | Storm costs, five year recovery

Public Utilities, General Disclosures [Line Items]

Amortization of deferred storm cost

139,000,000

NYSEG Electric | Deferred Storm Cost Amortization 1 Year

Public Utilities, General Disclosures [Line Items]

Amortization of deferred storm cost

$ 21,400,000

SCG

Public Utilities, General Disclosures [Line Items]

Proposed ROE for the year 2018

9.25%

Equity ratio

52.00%

Depreciation amortization period

3 years

Amount of proposed ROE for year one

$ 1,500,000

Amount of proposed ROE for year two

4,700,000

Amount of proposed ROE for year three

$ 5,000,000

PURA

Public Utilities, General Disclosures [Line Items]

Proposed ROE for the year 2018

9.30%

Equity ratio

54.00%

Depreciation amortization period

3 years

New distribution rate schedule, period

3 years

Amount of proposed ROE for year one

$ 9,900,000

Amount of proposed ROE for year two

4,600,000

Amount of proposed ROE for year three

$ 5,200,000

Equity ratio, year two

54.50%

BGC

Public Utilities, General Disclosures [Line Items]

Amount of proposed ROE for year one

$ 1,600,000

Amount of proposed ROE for year two

$ 700,000

RG&E & GNPP

Public Utilities, General Disclosures [Line Items]

Modified agreement monthly payment amount

$ 15,400,000

United Illuminating Company (UI)

Public Utilities, General Disclosures [Line Items]

Period of purchase commitment

21 years

Accrual for environmental loss contingencies

$ 16,000,000

$ 20,000,000

$ 30,000,000

Maximum amount of commitment to purchase renewable energy credits (recs) from new facilities behind distribution customer meters

200,000,000

Maximum annual commitment level obligation after year six

14,000,000

Additional maximum annual commitment

$ 64,000,000

Number of power purchase agreements | agreement

5

5

Proposed off shore wind | MW

50

Solicitation period

6 years

Vineyard Wind

Public Utilities, General Disclosures [Line Items]

Proposed off shore wind | MW

804

Ginna Nuclear Power Plant LLC

Public Utilities, General Disclosures [Line Items]

Single-unit pressurized water reactor | MW

581

Percentage of revenue entitled

30.00%

GenConn Devon | Electric Transmission and Distribution

Public Utilities, General Disclosures [Line Items]

Revenue requirements for equity investment in peaking generation

$ 25,000,000

GenConn Middletown | Electric Transmission and Distribution

Public Utilities, General Disclosures [Line Items]

Revenue requirements for equity investment in peaking generation

$ 29,000,000

Subsequent Event | Power Tax

Public Utilities, General Disclosures [Line Items]

Depreciation amortization period

32 years 6 months

Subsequent Event | Central Maine Power

Public Utilities, General Disclosures [Line Items]

Annual distribution tariff increase percentage

7.00%

Distribution tariff rate increased based on ROE

9.25%

Distribution tariff rate increased based on equity capital

50.00%

ROE reduction

1.00%

Customer service performance period

18 months

18 months

Proposed distribution tariff rate decrease based on return on equity

8.25%

0.75%

Distribution revenue requirement

$ 17,000,000

Min.

Public Utilities, General Disclosures [Line Items]

Approved return on equity

3.00%

Min. | Central Maine Power

Public Utilities, General Disclosures [Line Items]

Proposed distribution tariff rate decrease

$ 2,000,000

Proposed distribution tariff rate decrease based on return on equity

0.75%

0.75%

Max.

Public Utilities, General Disclosures [Line Items]

Proposed off shore wind | MW

2,000

Max. | Central Maine Power

Public Utilities, General Disclosures [Line Items]

Proposed distribution tariff rate decrease

$ 3,600,000

Proposed distribution tariff rate decrease based on return on equity

1.00%

1.00%

Electricity | NYPSC

Public Utilities, General Disclosures [Line Items]

Amount of proposed ROE

76,700,000

Electricity | RG&E

Public Utilities, General Disclosures [Line Items]

Requested increase in costs

$ 31,700,000

Amount of proposed ROE

700,000

Electricity | NYSEG

Public Utilities, General Disclosures [Line Items]

Requested increase in costs

156,700,000

Derivative financial instruments - gas | NYPSC

Public Utilities, General Disclosures [Line Items]

Amount of proposed ROE

15,900,000

Derivative financial instruments - gas | RG&E

Public Utilities, General Disclosures [Line Items]

Requested increase in costs

5,800,000

Amount of proposed ROE

$ 22,500,000

Derivative financial instruments - gas | NYSEG

Public Utilities, General Disclosures [Line Items]

Requested increase in costs

$ 6,300,000

GenConn

Public Utilities, General Disclosures [Line Items]

Equity interest percentage

50.00%

Dirigo Solar, LLC | CMP Distribution

Public Utilities, General Disclosures [Line Items]

Period of purchase commitment

20 years

Purchase obligation per year

$ 4,000,000

Maine Aqua Ventus I GP LLC | CMP Distribution

Public Utilities, General Disclosures [Line Items]

Period of purchase commitment

20 years

Purchase obligation per year

$ 12,000,000

DEEP

Public Utilities, General Disclosures [Line Items]

Number of power purchase agreements | agreement

10

Number of projects | project

10

12

9

Derivative, non-monetary notional amount, energy measure (in MWh) | MWh

12

Industry Regulation - Electric

Industry Regulation - Electric and Gas Delivery Rate Increase (Details) - USD ($) $ in Millions	May 01, 2018	May 01, 2017	May 01, 2016
NYSEG Electric
Public Utilities, General Disclosures [Line Items]
Rate Increase	$ 30.3	$ 29.9	$ 29.6
Delivery Rate Increase	4.10%	4.10%	4.10%
NYSEG Gas
Public Utilities, General Disclosures [Line Items]
Rate Increase	$ 14.8	$ 13.9	$ 13.1
Delivery Rate Increase	7.30%	7.30%	7.30%
RG&E Electric
Public Utilities, General Disclosures [Line Items]
Rate Increase	$ 25.9	$ 21.6	$ 3
Delivery Rate Increase	5.70%	5.00%	0.70%
RG&E Gas
Public Utilities, General Disclosures [Line Items]
Rate Increase	$ 9.5	$ 7.7	$ 8.8
Delivery Rate Increase	5.20%	4.40%	5.20%

Industry Regulation - Rate Incr

Industry Regulation - Rate Increases (Details) $ in Millions	May 20, 2019USD ($)
NYSEG | Electricity
Public Utility, Property, Plant and Equipment [Line Items]
Requested Revenue Increase	$ 156.7
Delivery Revenue	20.40%
Total Revenue	10.40%
NYSEG | Gas
Public Utility, Property, Plant and Equipment [Line Items]
Requested Revenue Increase	$ 6.3
Delivery Revenue	3.00%
Total Revenue	1.40%
RG&E | Electricity
Public Utility, Property, Plant and Equipment [Line Items]
Requested Revenue Increase	$ 31.7
Delivery Revenue	7.00%
Total Revenue	4.10%
RG&E | Gas
Public Utility, Property, Plant and Equipment [Line Items]
Requested Revenue Increase	$ 5.8
Delivery Revenue	3.30%
Total Revenue	1.40%

Regulatory Assets and Liabili_3

Regulatory Assets and Liabilities - Regulatory Assets Narrative (Details) - USD ($) $ in Millions	Jun. 15, 2016	Dec. 31, 2019	Dec. 31, 2018	Jun. 30, 2017
Regulated Operations [Abstract]
Unrecorded regulatory assets		$ 1,749
Regulatory Assets [Line Items]
Deferred costs				$ 2.3
Unfunded future income tax expense collection period		50 years
New York | Min.
Regulatory Assets [Line Items]
Deferred income tax recovery period		27 years
New York | Max.
Regulatory Assets [Line Items]
Deferred income tax recovery period		39 years
NYSEG
Regulatory Assets [Line Items]
Depreciation amortization period	3 years
Deferred storm costs not included in joint proposal		$ 96
NYSEG | Storm costs, ten year recovery
Regulatory Assets [Line Items]
Deferred costs		$ 78
Depreciation amortization period		10 years
NYSEG | Storm costs
Regulatory Assets [Line Items]
Deferred costs		$ 37
Depreciation amortization period			5 years
RG&E
Regulatory Assets [Line Items]
Deferred storm costs not included in joint proposal		$ 27
Central Maine Power
Regulatory Assets [Line Items]
Deferred income tax recovery period		32 years 6 months

Regulatory Assets and Liabili_4

Regulatory Assets and Liabilities - Schedule of Regulatory Assets (Details) - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Regulatory Assets [Line Items]
Total regulatory assets	$ 2,861	$ 2,945
Less: current portion	294	299
Total non-current regulatory assets	2,567	2,646
Pension and other post-retirement benefits cost deferrals
Regulatory Assets [Line Items]
Total regulatory assets	125	141
Pension and other post-retirement benefits
Regulatory Assets [Line Items]
Total regulatory assets	1,061	1,138
Storm costs
Regulatory Assets [Line Items]
Total regulatory assets	272	346
Rate adjustment mechanism
Regulatory Assets [Line Items]
Total regulatory assets	79	18
Reliability support services
Regulatory Assets [Line Items]
Total regulatory assets	0	13
Revenue decoupling mechanism
Regulatory Assets [Line Items]
Total regulatory assets	19	7
Transmission revenue reconciliation mechanism
Regulatory Assets [Line Items]
Total regulatory assets	5	11
Contracts for differences
Regulatory Assets [Line Items]
Total regulatory assets	92	97
Hardship programs
Regulatory Assets [Line Items]
Total regulatory assets	29	26
Plant decommissioning
Regulatory Assets [Line Items]
Total regulatory assets	5	11
Deferred purchased gas
Regulatory Assets [Line Items]
Total regulatory assets	25	37
Deferred transmission expense
Regulatory Assets [Line Items]
Total regulatory assets	11	11
Environmental remediation costs
Regulatory Assets [Line Items]
Total regulatory assets	277	278
Debt premium
Regulatory Assets [Line Items]
Total regulatory assets	97	118
Unamortized losses on reacquired debt
Regulatory Assets [Line Items]
Total regulatory assets	29	23
Unfunded future income taxes
Regulatory Assets [Line Items]
Total regulatory assets	399	371
Federal tax depreciation normalization adjustment
Regulatory Assets [Line Items]
Total regulatory assets	153	157
Asset retirement obligation
Regulatory Assets [Line Items]
Total regulatory assets	17	18
Deferred meter replacement costs
Regulatory Assets [Line Items]
Total regulatory assets	27	29
Other
Regulatory Assets [Line Items]
Total regulatory assets	$ 139	$ 95

Regulatory Assets and Liabili_5

Regulatory Assets and Liabilities - Schedule of Regulatory Liabilities (Details) - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Regulatory Liabilities [Line Items]
Total regulatory liabilities	$ 3,523	$ 3,428
Less: current portion	242	205
Total non-current regulatory liabilities	3,281	3,223
Energy efficiency portfolio standard
Regulatory Liabilities [Line Items]
Total regulatory liabilities	72	56
Gas supply charge and deferred natural gas cost
Regulatory Liabilities [Line Items]
Total regulatory liabilities	11	4
Pension and other post-retirement benefits cost deferrals
Regulatory Liabilities [Line Items]
Total regulatory liabilities	80	97
Carrying costs on deferred income tax bonus depreciation
Regulatory Liabilities [Line Items]
Total regulatory liabilities	49	72
Carrying costs on deferred income tax - Mixed Services 263(a)
Regulatory Liabilities [Line Items]
Total regulatory liabilities	15	20
2017 Tax Act
Regulatory Liabilities [Line Items]
Total regulatory liabilities	1,548	1,509
Revenue decoupling mechanism
Regulatory Liabilities [Line Items]
Total regulatory liabilities	17	19
Accrued removal obligations
Regulatory Liabilities [Line Items]
Total regulatory liabilities	1,173	1,153
Asset sale gain account
Regulatory Liabilities [Line Items]
Total regulatory liabilities	10	10
Economic development
Regulatory Liabilities [Line Items]
Total regulatory liabilities	27	28
Positive benefit adjustment
Regulatory Liabilities [Line Items]
Total regulatory liabilities	37	39
Theoretical reserve flow thru impact
Regulatory Liabilities [Line Items]
Total regulatory liabilities	14	19
Deferred property tax
Regulatory Liabilities [Line Items]
Total regulatory liabilities	17	25
Net plant reconciliation
Regulatory Liabilities [Line Items]
Total regulatory liabilities	23	19
Variable rate debt
Regulatory Liabilities [Line Items]
Total regulatory liabilities	67	49
Rate refund – FERC ROE proceeding
Regulatory Liabilities [Line Items]
Total regulatory liabilities	32	29
Transmission congestion contracts
Regulatory Liabilities [Line Items]
Total regulatory liabilities	23	21
Merger-related rate credits
Regulatory Liabilities [Line Items]
Total regulatory liabilities	16	18
Accumulated deferred investment tax credits
Regulatory Liabilities [Line Items]
Total regulatory liabilities	13	14
Asset retirement obligation
Regulatory Liabilities [Line Items]
Total regulatory liabilities	14	13
Earnings sharing provisions
Regulatory Liabilities [Line Items]
Total regulatory liabilities	28	17
Middletown/Norwalk local transmission network service collections
Regulatory Liabilities [Line Items]
Total regulatory liabilities	18	19
Low income programs
Regulatory Liabilities [Line Items]
Total regulatory liabilities	33	38
Non-firm margin sharing credits
Regulatory Liabilities [Line Items]
Total regulatory liabilities	16	10
New York 2018 winter storm settlement
Regulatory Liabilities [Line Items]
Total regulatory liabilities	11	0
Other
Regulatory Liabilities [Line Items]
Total regulatory liabilities	$ 159	$ 130

Regulatory Assets and Liabili_6

Regulatory Assets and Liabilities - Regulatory Liabilities Narrative (Details) $ in Millions	12 Months Ended
	Dec. 31, 2019USD ($)station	Dec. 31, 2018USD ($)
Positive benefit adjustment
Regulatory Liabilities [Line Items]
Regulatory liability, amortization period	5 years
Theoretical reserve flow thru impact
Regulatory Liabilities [Line Items]
Regulatory liability, amortization period	5 years
New York
Regulatory Liabilities [Line Items]
Regulatory liability, amortization period	5 years
UIL Holdings
Regulatory Liabilities [Line Items]
Business combination merger related rate credits | $	$ 2	$ 3
Oswego | New York
Regulatory Liabilities [Line Items]
Number of nuclear generating stations | station	2
NYPSC
Regulatory Liabilities [Line Items]
Regulatory liability, amortization period	5 years
NYSEG and RG&E
Regulatory Liabilities [Line Items]
Regulatory liability, amortization period	5 years

Goodwill and Intangible asset_2

Goodwill and Intangible assets - Schedule of Goodwill by Reportable Segment (Details) - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Goodwill [Line Items]
Goodwill	$ 3,119	$ 3,127
Networks
Goodwill [Line Items]
Goodwill	2,747	2,747
Renewables
Goodwill [Line Items]
Goodwill	$ 372	$ 380

Goodwill and Intangible asset_3

Goodwill and Intangible assets - Additional Information (Details)	Dec. 16, 2015USD ($)	Dec. 31, 2019	Dec. 31, 2019USD ($)reporting_unit	Dec. 31, 2018USD ($)	Dec. 31, 2017USD ($)	Dec. 31, 2002USD ($)	Dec. 31, 2000USD ($)
Goodwill [Line Items]
Goodwill reduction			$ 8,000,000
Impairment of goodwill			0	$ 0
Amortization expense			$ 15,000,000	$ 15,000,000	$ 22,000,000
Maine Reporting Unit
Goodwill [Line Items]
Goodwill							$ 325,000,000
New York Reporting Unit
Goodwill [Line Items]
Goodwill						$ 654,000,000
UIL Reporting Unit
Goodwill [Line Items]
Goodwill	$ 1,768,000,000
Poseidon Project
Goodwill [Line Items]
Ownership percentage sold		50.00%	50.00%
Networks
Goodwill [Line Items]
Number of reporting units | reporting_unit			3

Goodwill and Intangible asset_4

Goodwill and Intangible assets - Summary of Intangible Assets (Details) - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Finite-Lived Intangible Assets [Line Items]
Gross Carrying Amount	$ 619	$ 613
Accumulated Amortization	(305)	(290)
Net Carrying Amount	314	323
Wind development
Finite-Lived Intangible Assets [Line Items]
Gross Carrying Amount	591	588
Accumulated Amortization	(289)	(275)
Net Carrying Amount	302	313
Other
Finite-Lived Intangible Assets [Line Items]
Gross Carrying Amount	28	25
Accumulated Amortization	(16)	(15)
Net Carrying Amount	$ 12	$ 10

Goodwill and Intangible asset_5

Goodwill and Intangible assets - Schedule of Amortization Expense (Details) $ in Millions	Dec. 31, 2019USD ($)
Year ending December 31,
2020	$ 15
2021	14
2022	13
2023	12
2024	$ 12

Property, Plant and Equipment -

Property, Plant and Equipment - Schedule of Property, Plant and Equipment (Details) - USD ($) $ in Millions	Dec. 31, 2019	Jan. 01, 2019	Dec. 31, 2018
Property, Plant and Equipment [Line Items]
Total Property, Plant and Equipment in Service	$ 32,110		$ 30,208
Total accumulated depreciation	(9,059)		(8,359)
Total Net Property, Plant and Equipment in Service	23,051		21,849
Construction work in progress	2,167		1,610
Total Property, Plant and Equipment	25,218	$ 23,312	23,459
Capital lease obligations			89
Accumulated amortization of capitalized leases			76
Electric generation, distribution, transmission and other
Property, Plant and Equipment [Line Items]
Total Property, Plant and Equipment in Service	27,452		25,911
Capital lease obligations			226
Natural gas transportation, distribution and other
Property, Plant and Equipment [Line Items]
Total Property, Plant and Equipment in Service	4,400		4,071
Other common operating property
Property, Plant and Equipment [Line Items]
Total Property, Plant and Equipment in Service	258		226
Regulated
Property, Plant and Equipment [Line Items]
Total Property, Plant and Equipment in Service	19,479		18,300
Total accumulated depreciation	(4,969)		(4,615)
Total Net Property, Plant and Equipment in Service	14,510		13,685
Construction work in progress	1,269		1,010
Total Property, Plant and Equipment	15,779		14,695
Regulated | Electric generation, distribution, transmission and other
Property, Plant and Equipment [Line Items]
Total Property, Plant and Equipment in Service	15,092		14,242
Regulated | Natural gas transportation, distribution and other
Property, Plant and Equipment [Line Items]
Total Property, Plant and Equipment in Service	4,387		4,058
Regulated | Other common operating property
Property, Plant and Equipment [Line Items]
Total Property, Plant and Equipment in Service	0		0
Nonregulated
Property, Plant and Equipment [Line Items]
Total Property, Plant and Equipment in Service	12,631		11,908
Total accumulated depreciation	(4,090)		(3,744)
Total Net Property, Plant and Equipment in Service	8,541		8,164
Construction work in progress	898		600
Total Property, Plant and Equipment	9,439		8,764
Nonregulated | Electric generation, distribution, transmission and other
Property, Plant and Equipment [Line Items]
Total Property, Plant and Equipment in Service	12,360		11,669
Nonregulated | Natural gas transportation, distribution and other
Property, Plant and Equipment [Line Items]
Total Property, Plant and Equipment in Service	13		13
Nonregulated | Other common operating property
Property, Plant and Equipment [Line Items]
Total Property, Plant and Equipment in Service	$ 258		$ 226

Property, Plant and Equipment_2

Property, Plant and Equipment - Additional Information (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Property, Plant and Equipment [Abstract]
Interest costs capitalized	$ 55	$ 26	$ 28
Accrued liabilities for property, plant and equipment additions	357	154	209
Tangible asset impairment charges	11	0	5
Depreciation	$ 919	$ 840	$ 802

Asset retirement obligations -

Asset retirement obligations - Reconciliation of ARO (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning Balance	$ 217	$ 196
Liabilities settled during the year	(5)	(1)
Liabilities incurred during the year	6	5
Accretion expense	12	12
Revisions in estimated cash flows	(40)	5
Ending Balance	$ 190	$ 217

Asset retirement obligations _2

Asset retirement obligations - Additional Information (Details) - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Asset Retirement Obligation Disclosure [Abstract]
Asset retirement obligation, restricted cash	$ 2	$ 2

Debt - Schedule of Long-term De

Debt - Schedule of Long-term Debt (Details) - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Debt Instrument [Line Items]
Capital lease obligations		$ 89
Unamortized debt issuance costs and discount	$ (38)	(35)
Total Debt	7,446	5,762
Less: debt due within one year, included in current liabilities	730	394
Total Non-current Debt	6,716	5,368
First mortgage bonds - fixed
Debt Instrument [Line Items]
Long-term debt	2,218	$ 2,055
Bond pledged as collateral	$ 6,876
First mortgage bonds - fixed | Min.
Debt Instrument [Line Items]
Debt instrument, interest rate	3.07%	3.07%
First mortgage bonds - fixed | Max.
Debt Instrument [Line Items]
Debt instrument, interest rate	8.00%	10.06%
Unsecured pollution control notes - fixed
Debt Instrument [Line Items]
Long-term debt	$ 538	$ 526
Unsecured pollution control notes - fixed | Min.
Debt Instrument [Line Items]
Debt instrument, interest rate	2.00%	2.00%
Unsecured pollution control notes - fixed | Max.
Debt Instrument [Line Items]
Debt instrument, interest rate	3.50%	3.50%
Term loan - variable
Debt Instrument [Line Items]
Long-term debt	$ 500	$ 0
Debt instrument, interest rate	2.40%
Other various non-current debt - fixed
Debt Instrument [Line Items]
Long-term debt	$ 4,228	$ 3,127
Other various non-current debt - fixed | Min.
Debt Instrument [Line Items]
Debt instrument, interest rate	2.80%	2.80%
Other various non-current debt - fixed | Max.
Debt Instrument [Line Items]
Debt instrument, interest rate	10.48%	10.48%
Obligations under capital leases | Min.
Debt Instrument [Line Items]
Debt instrument, interest rate		4.00%
Obligations under capital leases | Max.
Debt Instrument [Line Items]
Debt instrument, interest rate		4.44%

Debt - Additional Information (

Debt - Additional Information (Details) - USD ($)	12 Months Ended
	Dec. 31, 2019	Sep. 05, 2019	Aug. 27, 2019	Jun. 03, 2019	May 31, 2019	May 16, 2019	Apr. 01, 2019	Jan. 15, 2019	Dec. 31, 2018
Debt Instrument [Line Items]
Estimated fair value of debt	$ 8,168,000,000								$ 5,952,000,000
Notes payable	560,000,000								587,000,000
Commercial paper	562,000,000								589,000,000
UIL Credit Facility
Debt Instrument [Line Items]
Credit facility maximum borrowing capacity	$ 2,000,000,000
AVANGRID Credit Facility | Min.
Debt Instrument [Line Items]
Credit facility initial fees range	0.10%
AVANGRID Credit Facility | Max.
Debt Instrument [Line Items]
Credit facility initial fees range	0.175%
Senior Unsecured Notes Due 2029
Debt Instrument [Line Items]
Debt instrument principal amount					$ 750,000,000
Senior Notes | Senior Notes Due 2029 through 2049
Debt Instrument [Line Items]
Debt instrument principal amount								$ 195,000,000
Senior Notes | Senior Notes Due 2029 through 2049 | Min.
Debt Instrument [Line Items]
Interest rate on outstanding loans								4.07%
Senior Notes | Senior Notes Due 2029 through 2049 | Max.
Debt Instrument [Line Items]
Interest rate on outstanding loans								4.52%
Senior Notes | Senior Notes Due 2024
Debt Instrument [Line Items]
Debt instrument principal amount							$ 12,000,000
Interest rate on outstanding loans							2.65%
Senior Notes | Senior Unsecured Notes Due 2029
Debt Instrument [Line Items]
Debt instrument principal amount						$ 750,000,000
Interest rate on outstanding loans						3.80%
Senior Notes | Senior Notes Due 2026 through 2034
Debt Instrument [Line Items]
Debt instrument principal amount				$ 240,000,000
Senior Notes | Senior Notes Due 2026 through 2034 | Min.
Debt Instrument [Line Items]
Interest rate on outstanding loans				3.87%
Senior Notes | Senior Notes Due 2026 through 2034 | Max.
Debt Instrument [Line Items]
Interest rate on outstanding loans				4.20%
Senior Notes | Senior Notes Due 2027
Debt Instrument [Line Items]
Debt instrument principal amount			$ 150,000,000
Interest rate on outstanding loans			3.10%
Senior Notes | Senior Notes Due 2049
Debt Instrument [Line Items]
Debt instrument principal amount		$ 300,000,000
Interest rate on outstanding loans		3.30%
Term Loan Credit
Debt Instrument [Line Items]
Debt instrument principal amount	$ 500,000,000
Line of Credit
Debt Instrument [Line Items]
Credit facility remaining borrowing capacity	1,938,000,000								$ 1,911,000,000
Line of Credit | Revolving Credit Facility
Debt Instrument [Line Items]
Credit facility maximum borrowing capacity	2,500,000,000
Line of Credit | AVANGRID Credit Facility
Debt Instrument [Line Items]
Credit facility maximum borrowing capacity	$ 2,000,000,000
Extension term	1 year
Line of Credit | NYSEG, RGE, CMP and UI | AVANGRID Credit Facility
Debt Instrument [Line Items]
Credit facility maximum borrowing capacity	$ 400,000,000
Line of Credit | CNG and SCG | AVANGRID Credit Facility
Debt Instrument [Line Items]
Credit facility maximum borrowing capacity	150,000,000
Line of Credit | BGC | AVANGRID Credit Facility
Debt Instrument [Line Items]
Credit facility maximum borrowing capacity	40,000,000
Line of Credit | Iberdrola Financiacion S A U | Revolving Credit Facility
Debt Instrument [Line Items]
Credit facility maximum borrowing capacity	$ 500,000,000
Credit facility initial fees range	0.105%
Credit facility amount drawn	$ 0
London Interbank Offered Rate (LIBOR) | Term Loan Credit
Debt Instrument [Line Items]
Floating interest rate	2.40%

Debt - Schedule of Maturities a

Debt - Schedule of Maturities and Repayments of Long-term Debt (Details) $ in Millions	Dec. 31, 2019USD ($)
Debt Disclosure [Abstract]
2020	$ 730
2021	801
2022	363
2023	439
2024	612
Total	$ 2,945

Fair Value of Financial Instr_3

Fair Value of Financial Instruments and Fair Value Measurements - Additional Information (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Restricted cash	$ 6	$ 7
Max.
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair value input, gas or power delivery period (in years)	2 years
RG&E
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Percentage of electric load obligations using contracts for a NYISO location	70.00%

Fair Value of Financial Instr_4

Fair Value of Financial Instruments and Fair Value Measurements - Fair Value of Assets and Liabilities (Details) - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Netting	$ (125)	$ (114)
Total	95	79
Netting	125	99
Total	(105)	(141)
Equity and other investments with readily determinable fair values
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Equity and other investments with readily determinable fair values	51	47
Derivative financial instruments - power
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Netting	(54)	(59)
Total	93	72
Netting	92	77
Total	(8)	(12)
Derivative financial instruments - gas
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Netting	(71)	(55)
Total	0	2
Netting	33	22
Total	(2)	(9)
Contracts for differences
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Netting	0	0
Total	2	5
Netting	0	0
Total	(94)	(102)
Derivative financial instruments – Other
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Netting	0	0
Total	(1)	(18)
Level 1
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	4	18
Derivative liabilities	(32)	(13)
Level 1 | Equity and other investments with readily determinable fair values
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Equity and other investments with readily determinable fair values	38	37
Level 1 | Derivative financial instruments - power
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	4	17
Derivative liabilities	(28)	(12)
Level 1 | Derivative financial instruments - gas
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	0	1
Derivative liabilities	(4)	(1)
Level 1 | Contracts for differences
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	0	0
Derivative liabilities	0	0
Level 1 | Derivative financial instruments – Other
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative liabilities	0	0
Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	63	43
Derivative liabilities	(70)	(80)
Level 2 | Equity and other investments with readily determinable fair values
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Equity and other investments with readily determinable fair values	13	10
Level 2 | Derivative financial instruments - power
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	23	23
Derivative liabilities	(43)	(41)
Level 2 | Derivative financial instruments - gas
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	40	20
Derivative liabilities	(26)	(23)
Level 2 | Contracts for differences
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	0	0
Derivative liabilities	0	0
Level 2 | Derivative financial instruments – Other
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative liabilities	(1)	(16)
Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	153	132
Derivative liabilities	(128)	(147)
Level 3 | Equity and other investments with readily determinable fair values
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Equity and other investments with readily determinable fair values	0	0
Level 3 | Derivative financial instruments - power
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	120	91
Derivative liabilities	(29)	(36)
Level 3 | Derivative financial instruments - gas
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	31	36
Derivative liabilities	(5)	(7)
Level 3 | Contracts for differences
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	2	5
Derivative liabilities	(94)	(102)
Level 3 | Derivative financial instruments – Other
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative liabilities	$ 0	$ (2)

Fair Value of Financial Instr_5

Fair Value of Financial Instruments and Fair Value Measurements - Reconciliation of Changes in Fair Value of Financial Instruments (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Roll Forward]
Fair value as of January 1,	$ (15)	$ 6	$ 31
Gains for the year recognized in operating revenues	53	18	18
Losses for the year recognized in operating revenues	(2)	(9)	(1)
Total gains or losses for the period recognized in operating revenues	51	9	17
Gains recognized in OCI	2	0	2
Losses recognized in OCI	(3)	(5)	(1)
Total gains or losses recognized in OCI	(1)	(5)	1
Net change recognized in regulatory assets and liabilities	5	(5)	(17)
Purchases	(22)	(6)	(5)
Settlements	4	(10)	(17)
Transfers out of Level 3	3	(4)	(4)
Fair value as of December 31,	25	(15)	6
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	$ 51	$ 9	$ 17

Fair Value of Financial Instr_6

Fair Value of Financial Instruments and Fair Value Measurements - Valuation of Instruments (Details) - Observable and extrapolated forward gas and power prices not all of which can be corroborated by market data for identical or similar products	Dec. 31, 2019$ / MWh
NYMEX | Avg.
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Discount rate	2.90
NYMEX | Max.
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Discount rate	4.90
NYMEX | Min.
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Discount rate	2.07
Indiana Hub | Avg.
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Discount rate	30.54
Indiana Hub | Max.
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Discount rate	61.12
Indiana Hub | Min.
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Discount rate	19.10
Mid C | Avg.
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Discount rate	24.75
Mid C | Max.
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Discount rate	105
Mid C | Min.
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Discount rate	(0.50)
Minn Hub | Avg.
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Discount rate	25.10
Minn Hub | Max.
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Discount rate	52.17
Minn Hub | Min.
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Discount rate	12.51
Noil Hub | Avg.
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Discount rate	27.36
Noil Hub | Max.
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Discount rate	55.39
Noil Hub | Min.
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Discount rate	15.50
Ercot S hub | Avg.
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Discount rate	31
Ercot S hub | Max.
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Discount rate	248.39
Ercot S hub | Min.
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Discount rate	14.62

Fair Value of Financial Instr_7

Fair Value of Financial Instruments and Fair Value Measurements - Schedule of Fair Value Measurement (Details) - Contracts for differences - Level 3	Dec. 31, 2019$ / MWh
Min. | Risk of non-performance
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Discount rate	0.0005
Min. | Discount rate
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Discount rate	0.0169
Min. | Forward pricing
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Discount rate	3.80
Max. | Risk of non-performance
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Discount rate	0.0045
Max. | Discount rate
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Discount rate	0.0183
Max. | Forward pricing
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Discount rate	7.03

Derivative Instruments and He_3

Derivative Instruments and Hedging - Offsetting of Derivatives, Locations in Consolidated Balance Sheet and Amounts of Derivatives (Details) - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total	$ 95	$ 79
Total	(105)	(141)
Cash collateral (payable) receivable, asset	(21)	(26)
Current Liabilities | Designated as hedging instruments
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative liabilities	0	16
Networks | Current Assets
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total derivatives before offset of cash collateral, asset	0	8
Cash collateral (payable) receivable, asset	0	0
Total derivatives as presented in the balance sheet	0	8
Networks | Current Assets | Not designated as hedging instruments
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets	1	18
Derivative liabilities	(1)	(10)
Total	0	8
Networks | Current Assets | Designated as hedging instruments
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets	0	0
Derivative liabilities	0	0
Total	0	0
Networks | Noncurrent Assets
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total derivatives before offset of cash collateral, asset	2	3
Cash collateral (payable) receivable, asset	0	0
Total derivatives as presented in the balance sheet	2	3
Networks | Noncurrent Assets | Not designated as hedging instruments
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets	4	6
Derivative liabilities	(2)	(3)
Total	2	3
Networks | Noncurrent Assets | Designated as hedging instruments
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets	0	0
Derivative liabilities	0	0
Total	0	0
Networks | Current Liabilities
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total derivatives before offset of cash collateral, liability	(39)	(13)
Cash collateral (payable) receivable, liability	27	0
Total derivatives as presented in the balance sheet	(12)	(13)
Networks | Current Liabilities | Not designated as hedging instruments
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets	1	10
Derivative liabilities	(39)	(21)
Total	(38)	(11)
Networks | Current Liabilities | Designated as hedging instruments
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets	0	0
Derivative liabilities	(1)	(2)
Total	(1)	(2)
Networks | Noncurrent Liabilities
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total derivatives before offset of cash collateral, liability	(85)	(90)
Cash collateral (payable) receivable, liability	1	0
Total derivatives as presented in the balance sheet	(84)	(90)
Networks | Noncurrent Liabilities | Not designated as hedging instruments
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets	2	3
Derivative liabilities	(86)	(93)
Total	(84)	(90)
Networks | Noncurrent Liabilities | Designated as hedging instruments
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets	0	0
Derivative liabilities	(1)	0
Total	(1)	0
Renewables | Current Assets
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total derivatives before offset of cash collateral, asset	22	16
Cash collateral (payable) receivable, asset	(11)	(8)
Total derivatives as presented in the balance sheet	11	8
Renewables | Current Assets | Not designated as hedging instruments
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets	23	19
Derivative liabilities	(1)	(5)
Total	22	14
Renewables | Current Assets | Designated as hedging instruments
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets	0	2
Derivative liabilities	0	0
Total	0	2
Renewables | Noncurrent Assets
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total derivatives before offset of cash collateral, asset	112	94
Cash collateral (payable) receivable, asset	(30)	(34)
Total derivatives as presented in the balance sheet	82	60
Renewables | Noncurrent Assets | Not designated as hedging instruments
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets	110	96
Derivative liabilities	(7)	(3)
Total	103	93
Renewables | Noncurrent Assets | Designated as hedging instruments
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets	18	1
Derivative liabilities	(9)	0
Total	9	1
Renewables | Current Liabilities
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total derivatives before offset of cash collateral, liability	(14)	(24)
Cash collateral (payable) receivable, liability	7	9
Total derivatives as presented in the balance sheet	(7)	(15)
Renewables | Current Liabilities | Not designated as hedging instruments
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets	42	29
Derivative liabilities	(48)	(48)
Total	(6)	(19)
Renewables | Current Liabilities | Designated as hedging instruments
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets	5	2
Derivative liabilities	(13)	(7)
Total	(8)	(5)
Renewables | Noncurrent Liabilities
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total derivatives before offset of cash collateral, liability	(7)	(24)
Cash collateral (payable) receivable, liability	6	17
Total derivatives as presented in the balance sheet	(1)	(7)
Renewables | Noncurrent Liabilities | Not designated as hedging instruments
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets	13	17
Derivative liabilities	(18)	(35)
Total	(5)	(18)
Renewables | Noncurrent Liabilities | Designated as hedging instruments
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets	4	4
Derivative liabilities	(6)	(10)
Total	$ (2)	$ (6)

Derivative Instruments and He_4

Derivative Instruments and Hedging - Net Notional Volume (Details) gal in Millions, MWh in Millions, MMBTU in Millions	12 Months Ended
	Dec. 31, 2019MWhMMBTUgal	Dec. 31, 2018MWhMMBTUgal
Networks | Wholesale electricity contracts | Long
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, non-monetary notional amount, energy measure | MWh	5.1	4.9
Networks | Natural Gas Contracts | Long
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, non-monetary notional amount, energy measure	8.5	7.8
Networks | Fleet Fuel Contracts | Long
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, non-monetary notional amount | gal	2.2	2.1
Renewables | Long | Basis Swaps
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, non-monetary notional amount, energy measure	42	42
Renewables | Short | Basis Swaps
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, non-monetary notional amount, energy measure	1	4
Renewables | Wholesale electricity contracts | Long
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, non-monetary notional amount, energy measure | MWh	4	5
Renewables | Wholesale electricity contracts | Short
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, non-monetary notional amount, energy measure | MWh	9	6
Renewables | Natural gas and other fuel purchase contracts | Long
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, non-monetary notional amount, energy measure	29	29
Renewables | Financial power contracts
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, non-monetary notional amount, energy measure	10	11

Derivative Instruments and He_5

Derivative Instruments and Hedging - Summary of Unrealized Gains and Losses from Fair Value Adjustments (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Derivative Assets
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Loss (Gain) Reclassified from Regulatory Assets/Liabilities into Income	$ (3)	$ (6)	$ (8)
Derivative Liabilities
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Loss (Gain) Reclassified from Regulatory Assets/Liabilities into Income	8	1	(9)
Electricity
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Loss (Gain) Reclassified from Regulatory Assets/Liabilities into Income			37
Electricity | Regulatory Assets
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Loss or Gain Recognized in Regulatory Assets/Liabilities	24	0
Loss (Gain) Reclassified from Regulatory Assets/Liabilities into Income	25	(10)
Electricity | Regulatory Liabilities
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Loss or Gain Recognized in Regulatory Assets/Liabilities	0	5
Natural Gas
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Loss (Gain) Reclassified from Regulatory Assets/Liabilities into Income			$ 0
Natural Gas | Regulatory Assets
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Loss or Gain Recognized in Regulatory Assets/Liabilities	4	0
Loss (Gain) Reclassified from Regulatory Assets/Liabilities into Income	1	(1)
Natural Gas | Regulatory Liabilities
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Loss or Gain Recognized in Regulatory Assets/Liabilities	$ 0	$ 0

Derivative Instruments and He_6

Derivative Instruments and Hedging - Additional Information (Details)	12 Months Ended
	Dec. 31, 2019USD ($)	Dec. 31, 2018USD ($)	Dec. 31, 2017USD ($)	Jan. 31, 2020USD ($)instrument	Jun. 20, 2019USD ($)	May 31, 2019USD ($)
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Regulatory assets	$ 2,861,000,000	$ 2,945,000,000
Regulatory liabilities	3,523,000,000	3,428,000,000
Net derivative losses related to discontinued cash flow hedges	38,000,000
Reclassification to net income of losses (gains) on cash flow hedges, net of income taxes of $2.7, $(6.5) and $9.3, respectively		(8,000,000)	$ 14,000,000
Gain reclassified from regulatory assets and liabilities into income	43,000,000
Net derivative losses related to discontinued cash flow hedges	38,000,000
Cash collateral pledged	21,000,000	26,000,000
Aggregate fair value of all derivative instruments with credit risk related contingent features that are in a liability position	28,000,000
Interest Rate Swap
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Net loss in accumulated OCI related to discontinued cash flow hedge	2,000,000
Amortization of net loss	4,000,000
Senior Unsecured Notes Due 2029
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Debt instrument, face amount						$ 750,000,000
Networks
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Net derivative losses related to discontinued cash flow hedges	1,000,000	1,000,000	1,000,000
Net derivative losses related to discontinued cash flow hedges	1,000,000	1,000,000	1,000,000
Networks | Cash Flow Hedging
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Forward contract to hedge foreign currency exchange risk					$ 100,000,000
Net derivative losses related to discontinued cash flow hedges	6,000,000	6,000,000	6,000,000
Reclassification to net income of losses (gains) on cash flow hedges, net of income taxes of $2.7, $(6.5) and $9.3, respectively	4,000,000
Unrealized loss	1,000,000
Net derivative losses related to discontinued cash flow hedges	$ 6,000,000	6,000,000	$ 6,000,000
Unrealized loss, estimate of time to transfer	12 months
Networks | Cash Flow Hedging | Fuel Derivatives | Max.
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Maximum period of time of cash flow hedges	12 months
Networks | Cash Flow Hedging | Forward starting swaps
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Net loss related to previously settled forward starting swaps	$ 55,000,000	61,000,000
Renewables | Cash Flow Hedging
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Net derivative losses related to discontinued cash flow hedges	6,000,000
Net derivative losses related to discontinued cash flow hedges	$ 6,000,000
Unrealized loss, estimate of time to transfer	12 months
UI
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets	$ 2,000,000	5,000,000
Regulatory assets	92,000,000	97,000,000
Derivative liabilities	94,000,000	102,000,000
Regulatory liabilities	0	0
Derivative collateral obligation to be paid in decrease in credit rating below investment grade	$ 18,000,000
Contracts for differences | UI
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Percentage of cost or benefit on contract allocated to customers	20.00%
Contracts for differences | CL&P
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Percentage of cost or benefit on contract allocated to customers	80.00%
Derivative assets	$ 0	0
Derivative liabilities	$ 92,000,000	$ 96,000,000
Subsequent Event | Interest Rate Swap
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Number of instruments held | instrument				2
Notional amount				$ 600,000,000

Derivative Instruments and He_7

Derivative Instruments and Hedging - Effect of Derivatives in Cash Flow Hedging (Details) - USD ($) $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Derivative Instruments and Hedging Activities Disclosures [Line Items]
(Loss) Gain Recognized in OCI on Derivatives (a)									$ (38)
Interest expense									306	$ 303	$ 280
Purchased power, natural gas and fuel used									1,509	1,653	1,338
Operating revenues	$ 1,609	$ 1,487	$ 1,400	$ 1,842	$ 1,665	$ 1,546	$ 1,402	$ 1,865	6,338	6,478	5,963
Networks
Derivative Instruments and Hedging Activities Disclosures [Line Items]
(Loss) Gain Recognized in OCI on Derivatives (a)									(1)	(1)	(1)
Loss (Gain) Reclassified from Accumulated OCI into Income									7	8	9
Operating revenues									5,150	5,304
Renewables
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Operating revenues									1,186	1,137
Interest rate contracts
Derivative Instruments and Hedging Activities Disclosures [Line Items]
(Loss) Gain Recognized in OCI on Derivatives (a)									(24)	(16)
Interest rate contracts | Interest expense
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Loss (Gain) Reclassified from Accumulated OCI into Income									2	0
Interest rate contracts | Networks | Interest expense
Derivative Instruments and Hedging Activities Disclosures [Line Items]
(Loss) Gain Recognized in OCI on Derivatives (a)									0	0	0
Loss (Gain) Reclassified from Accumulated OCI into Income									6	8	8
Commodity contracts | Networks | Purchased power, natural gas and fuel used
Derivative Instruments and Hedging Activities Disclosures [Line Items]
(Loss) Gain Recognized in OCI on Derivatives (a)									0	(1)	(1)
Loss (Gain) Reclassified from Accumulated OCI into Income									1	0	1
Commodity contracts | Renewables
Derivative Instruments and Hedging Activities Disclosures [Line Items]
(Loss) Gain Recognized in OCI on Derivatives (a)									(5)	(11)	41
Commodity contracts | Renewables | Operating revenues
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Loss (Gain) Reclassified from Accumulated OCI into Income									3	(22)	14
Operating revenues									6,338	$ 6,478	$ 5,963
Foreign currency exchange contracts | Networks | Purchased power, natural gas and fuel used
Derivative Instruments and Hedging Activities Disclosures [Line Items]
(Loss) Gain Recognized in OCI on Derivatives (a)									(1)
Loss (Gain) Reclassified from Accumulated OCI into Income									$ 0

Derivative Instruments and He_8

Derivative Instruments and Hedging - Fair Value of Derivative Contract (Details) - Renewables - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total	$ 85	$ 46
Financial power contracts
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total	73	55
Long | Wholesale electricity contracts
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total	10	11
Long | Natural gas and other fuel purchase contracts
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total	(2)	(2)
Long | Basis Swaps
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total	0	(6)
Short | Wholesale electricity contracts
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total	$ 4	$ (12)

Derivative Instruments and He_9

Derivative Instruments and Hedging - Effect of Trading and Non Trading Derivatives (Details) - USD ($) $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total Gain (Loss)									$ 43
Operating revenues	$ 1,609	$ 1,487	$ 1,400	$ 1,842	$ 1,665	$ 1,546	$ 1,402	$ 1,865	6,338	$ 6,478	$ 5,963
Purchased power, natural gas and fuel used									1,509	1,653	1,338
Renewables
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Operating revenues									1,186	1,137
Renewables | Trading
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total Gain (Loss)									(2)	6	(8)
Renewables | Trading | Wholesale electricity contracts | Long
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total Gain (Loss)										4	(3)
Renewables | Trading | Wholesale electricity contracts | Short
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total Gain (Loss)										(2)	4
Renewables | Trading | Financial power contracts
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total Gain (Loss)										0	(1)
Renewables | Trading | Financial and natural gas contracts
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total Gain (Loss)										4	(8)
Renewables | Trading | Natural gas and other fuel purchase contracts
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total Gain (Loss)										0	0
Renewables | Non-trading
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total Gain (Loss)									78	(23)	(15)
Renewables | Non-trading | Wholesale electricity contracts | Long
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total Gain (Loss)										11	1
Renewables | Non-trading | Wholesale electricity contracts | Short
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total Gain (Loss)										(15)	(3)
Renewables | Non-trading | Financial power contracts
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total Gain (Loss)										(19)	(5)
Renewables | Non-trading | Financial and natural gas contracts
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total Gain (Loss)										0	0
Renewables | Non-trading | Natural gas and other fuel purchase contracts
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total Gain (Loss)										$ 0	$ (8)
Renewables | Operating Revenues | Trading
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total Gain (Loss)									(2)
Renewables | Operating Revenues | Trading | Wholesale electricity contracts | Long
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total Gain (Loss)									(1)
Renewables | Operating Revenues | Trading | Wholesale electricity contracts | Short
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total Gain (Loss)									3
Renewables | Operating Revenues | Trading | Financial power contracts
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total Gain (Loss)									(3)
Renewables | Operating Revenues | Trading | Financial and natural gas contracts
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total Gain (Loss)									(1)
Renewables | Operating Revenues | Non-trading
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total Gain (Loss)									64
Operating revenues									1,338
Renewables | Operating Revenues | Non-trading | Wholesale electricity contracts | Long
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total Gain (Loss)									0
Renewables | Operating Revenues | Non-trading | Wholesale electricity contracts | Short
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total Gain (Loss)									40
Renewables | Operating Revenues | Non-trading | Financial power contracts
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total Gain (Loss)									23
Renewables | Operating Revenues | Non-trading | Financial and natural gas contracts
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total Gain (Loss)									1
Renewables | Purchased power, natural gas and fuel used | Trading
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total Gain (Loss)									0
Renewables | Purchased power, natural gas and fuel used | Trading | Wholesale electricity contracts | Long
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total Gain (Loss)									0
Renewables | Purchased power, natural gas and fuel used | Trading | Wholesale electricity contracts | Short
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total Gain (Loss)									0
Renewables | Purchased power, natural gas and fuel used | Trading | Financial power contracts
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total Gain (Loss)									0
Renewables | Purchased power, natural gas and fuel used | Trading | Financial and natural gas contracts
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total Gain (Loss)									0
Renewables | Purchased power, natural gas and fuel used | Non-trading
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total Gain (Loss)									14
Purchased power, natural gas and fuel used									1,509
Renewables | Purchased power, natural gas and fuel used | Non-trading | Wholesale electricity contracts | Long
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total Gain (Loss)									0
Renewables | Purchased power, natural gas and fuel used | Non-trading | Wholesale electricity contracts | Short
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total Gain (Loss)									0
Renewables | Purchased power, natural gas and fuel used | Non-trading | Financial power contracts
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total Gain (Loss)									(1)
Renewables | Purchased power, natural gas and fuel used | Non-trading | Financial and natural gas contracts
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total Gain (Loss)									$ 15

Leases - Narrative (Details)

Leases - Narrative (Details) - USD ($) $ in Millions	12 Months Ended				24 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Mar. 31, 2017
Lessee, Lease, Description [Line Items]
Renewal term	40 years
Finance lease liabilities	$ 63
Finance lease liabilities		$ 89
Operating lease expense		59	$ 72	$ 71
Contingent payments		11	19	22
Leasing revenue		384
NYSEG
Lessee, Lease, Description [Line Items]
Operating lease expense			18	38
GNPP
Lessee, Lease, Description [Line Items]
Percentage of revenue share					30.00%
RG&E
Lessee, Lease, Description [Line Items]
Operating lease expense			$ 6	$ 115
Leasing revenue					$ 15
Percentage of revenue share					70.00%
Renewables
Lessee, Lease, Description [Line Items]
Finance lease liabilities	$ 50
Finance lease liabilities		$ 52
Finance lease term	15 years
Early buyout option term	10 years
Generation Facility | Renewables
Lessee, Lease, Description [Line Items]
Useful life of facility	25 years
Min.
Lessee, Lease, Description [Line Items]
Remaining lease term	1 year
Max.
Lessee, Lease, Description [Line Items]
Remaining lease term	64 years

Leases - Lease Cost (Details)

Leases - Lease Cost (Details) $ in Millions	12 Months Ended
	Dec. 31, 2019USD ($)
Finance lease cost
Amortization of right-of-use assets	$ 12
Interest on lease liabilities	3
Total finance lease cost	15
Operating lease cost	18
Short-term lease cost	5
Variable lease cost	2
Total lease cost	$ 40

Leases - Supplemental Balance S

Leases - Supplemental Balance Sheet (Details) - USD ($) $ in Millions	Dec. 31, 2019	Jan. 01, 2019
Operating Leases
Operating lease right-of-use assets	$ 70	$ 82
Operating lease liabilities, current	12	8
Operating lease liabilities, long-term	65	$ 74
Total operating lease liabilities	77
Finance Leases
Other assets	133
Other current liabilities	9
Other non-current liabilities	54
Total finance lease liabilities	$ 63
Weighted-average Remaining Lease Term (years)
Finance leases	7 years 7 months 2 days
Operating leases	12 years 11 months 23 days
Weighted-average Discount Rate
Finance leases	5.35%
Operating leases	3.62%

Leases - Supplemental Cash Flow

Leases - Supplemental Cash Flow (Details) $ in Millions	12 Months Ended
	Dec. 31, 2019USD ($)
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows from operating leases	$ 13
Operating cash flows from finance leases	3
Financing cash flows from finance leases	27
Right-of-use assets obtained in exchange for lease obligations:
Finance leases	1
Operating leases	$ 3

Leases - Lease Maturities (Deta

Leases - Lease Maturities (Details) $ in Millions	Dec. 31, 2019USD ($)
Finance Leases
2020	$ 10
2021	7
2022	3
2023	50
2024	0
Thereafter	2
Total lease payments	72
Less: imputed interest	(9)
Total	63
Operating Leases
2020	14
2021	13
2022	10
2023	7
2024	6
Thereafter	51
Total lease payments	101
Less: imputed interest	(24)
Total	$ 77

Leases - Minimum Lease Payments

Leases - Minimum Lease Payments (Details) $ in Millions	Dec. 31, 2018USD ($)
Operating Leases
2019	$ 31
2020	39
2021	38
2022	35
2023	33
Thereafter	735
Total	911
Capital Leases
2019	30
2020	10
2021	7
2022	2
2023	50
Thereafter	2
Total	101
Total
2019	61
2020	49
2021	45
2022	37
2023	83
Thereafter	737
Total	$ 1,012

Commitments and Contingent Li_3

Commitments and Contingent Liabilities - Additional Information (Details) customer in Thousands, $ in Millions

Feb. 06, 2020USD ($)

Nov. 21, 2019complaint

Apr. 23, 2019USD ($)

Apr. 18, 2019recommendation

Feb. 21, 2019USD ($)

Jan. 11, 2019complaint

Mar. 22, 2016

Mar. 03, 2015

Oct. 16, 2014

Sep. 30, 2011

Oct. 31, 2018

Apr. 30, 2018

Dec. 31, 2019USD ($)MW

Oct. 30, 2019USD ($)

Dec. 31, 2018USD ($)

Mar. 31, 2018customerstorm

Apr. 12, 2016USD ($)

Loss Contingencies [Line Items]

Refund period, term

15 months

Approved return on equity

9.88%

Regulatory liabilities

$ 3,281

$ 3,223

Number of complaints | complaint

2

Price of the PPAs

$ 259

Requested renewables delay from preliminary proposed ruling period

2 years

Standby letters of credit

$ 474

Power purchase commitments

Loss Contingencies [Line Items]

Power purchase commitment | MW

55

Period of purchase commitment

12 years

Power purchase commitment, remaining period

2 years

Power purchase commitments | Guaranteed output / Guaranteed annual production

Loss Contingencies [Line Items]

Power purchase commitment | MW

34.4

Power sales commitments

Loss Contingencies [Line Items]

Power purchase commitment | MW

55

Period of purchase commitment

12 years

Power purchase commitment, remaining period

2 years

Power sales commitments | Guaranteed output / Guaranteed annual production

Loss Contingencies [Line Items]

Power purchase commitment | MW

34.4

NYPSC

Loss Contingencies [Line Items]

Order instituting proceeding and to show cause, period

30 days

Number of recommendations | recommendation

94

Yankee Companies

Loss Contingencies [Line Items]

Litigation settlement, amount awarded to other party

$ 103

Litigation settlement, amount awarded from other party

$ 8

Connecticut Yankee

Loss Contingencies [Line Items]

Litigation settlement, amount awarded to other party

41

Maine Yankee

Loss Contingencies [Line Items]

Litigation settlement, amount awarded to other party

34

Yankee Atomic

Loss Contingencies [Line Items]

Litigation settlement, amount awarded to other party

$ 28

March 2018 Windstorm

Loss Contingencies [Line Items]

Number of severe winter storms | storm

2

Number of affected customers | customer

520

Min.

Loss Contingencies [Line Items]

Approved return on equity

3.00%

Complaint III

Loss Contingencies [Line Items]

Regulatory liabilities

$ 7

Complaint II

Loss Contingencies [Line Items]

Regulatory liabilities

25

Complaint II and III

Loss Contingencies [Line Items]

Reasonably possible loss, in additional reserve, pre tax

$ 17

Unfavorable Regulatory Action | Complaint I

Loss Contingencies [Line Items]

Refund period, term

15 months

Approved return on equity

9.59%

10.57%

Number of complaints | complaint

4

Unfavorable Regulatory Action | Complaint I | Min.

Loss Contingencies [Line Items]

Approved return on equity

9.60%

Requested existing base return on equity base percentage

10.41%

Unfavorable Regulatory Action | Complaint I | Max.

Loss Contingencies [Line Items]

Approved return on equity

10.42%

11.74%

11.74%

10.99%

Requested existing base return on equity base percentage

13.08%

Unfavorable Regulatory Action | Complaint III

Loss Contingencies [Line Items]

Approved return on equity

10.90%

Unfavorable Regulatory Action | Complaint III | Max.

Loss Contingencies [Line Items]

Approved return on equity

12.19%

Before Amendment

Loss Contingencies [Line Items]

Requested return on equity base percentage

11.14%

Beginning in 2019 and Expiring in 2021 | Power purchase commitments | Hydro Capacity And Energy

Loss Contingencies [Line Items]

Power purchase commitment | MW

95.6

Period of purchase commitment

3 years

Beginning in 2019 and Expiring in 2023 | Power purchase commitments | Hydro Capacity And Energy

Loss Contingencies [Line Items]

Power purchase commitment | MW

52

Period of purchase commitment

5 years

Expiring in 2026 | Power sales commitments | Guaranteed output / Guaranteed annual production

Loss Contingencies [Line Items]

Power purchase commitment | MW

12

Amphora Gas Storage USA, LLC

Loss Contingencies [Line Items]

Loss contingency, range of possible loss, portion not accrued

$ 20

Indemnification liability, percentage of purchase price, maximum

15.00%

Indemnification liability, amount, maximum

$ 10

Subsequent Event | RG&E

Loss Contingencies [Line Items]

Litigation settlement, amount awarded to other party

$ 10.5

Commitments and Contingent Li_4

Commitments and Contingent Liabilities - Schedule of Forward Purchases and Sales Commitments Under Power, Gas, and Other Arrangements (Details) $ in Millions	12 Months Ended
	Dec. 31, 2019USD ($)
Purchases
2020	$ 1,396
2021	177
2022	87
2023	68
2024	44
Thereafter	830
Totals	2,602
Sales
2020	192
2021	138
2022	72
2023	52
2024	39
Thereafter	87
Totals	$ 580

Environmental Liabilities (Deta

Environmental Liabilities (Details)	Sep. 11, 2014USD ($)	Sep. 09, 2011USD ($)	Nov. 30, 2014USD ($)	Jul. 31, 2011USD ($)site	Dec. 31, 2019USD ($)site	Dec. 31, 2018USD ($)	Aug. 04, 2016USD ($)
Environmental Exit Cost [Line Items]
Number of sites with potential remediation obligations (sites) | site					25
Number of inactive hazardous waste disposal sites with liability recorded | site					10
Number of inactive hazardous waste disposal sites not expected to incur additional liabilities | site					15
Number of additional inactive hazardous waste disposal sites with liability recorded | site					11
Number of sites where gas was manufactured in the past | site					53
Number of sites for which we have entered into consent orders to investigate and remediate | site					41
Costs related to investigation and remediation					$ 349,000,000	$ 366,000,000
Accrual for environmental loss contingencies	$ 27,000,000				$ 21,000,000
Number of sites court modified decision | site					9
Damages for incurred costs payment amount	$ 22,000,000
Refund of environmental remediation cost paid			$ 5,000,000
First Energy
Environmental Exit Cost [Line Items]
Former manufactured gas sites | site				16
Reasonably possible loss, in additional reserve, net of tax				$ 60,000,000
Environmental costs paid		$ 30,000,000
First Energy | Past Costs
Environmental Exit Cost [Line Items]
Accrual for environmental loss contingencies		27,000,000
First Energy | Pre-judgment Interest
Environmental Exit Cost [Line Items]
Environmental costs paid		$ 3,000,000
United Illuminating Company (UI)
Environmental Exit Cost [Line Items]
Costs related to investigation and remediation					$ 16,000,000	20,000,000	$ 30,000,000
New York State Registry
Environmental Exit Cost [Line Items]
Number of sites with potential remediation obligations (sites) | site					17
Number of sites where gas was manufactured in the past | site					8
Maine's Uncontrolled Sites Program
Environmental Exit Cost [Line Items]
Number of sites with potential remediation obligations (sites) | site					6
Number of sites where gas was manufactured in the past | site					2
Massachusetts Non- Priority Confirmed Disposal Site List
Environmental Exit Cost [Line Items]
Number of sites with potential remediation obligations (sites) | site					1
National Priorities List
Environmental Exit Cost [Line Items]
Number of sites with potential remediation obligations (sites) | site					7
Ten of Twenty-five Sites
Environmental Exit Cost [Line Items]
Estimated environmental liability					$ 5,000,000
Another Eleven Sites
Environmental Exit Cost [Line Items]
Estimated environmental liability					8,000,000
Another Eleven Sites | Min.
Environmental Exit Cost [Line Items]
Estimated environmental liability					12,000,000
Another Eleven Sites | Max.
Environmental Exit Cost [Line Items]
Estimated environmental liability					$ 21,000,000
New York Voluntary Cleanup Program
Environmental Exit Cost [Line Items]
Number of sites where gas was manufactured in the past | site					3
Maine's Voluntary Response Action Program
Environmental Exit Cost [Line Items]
Number of sites where gas was manufactured in the past | site					3
Manufactured Gas Plants | Connecticut
Environmental Exit Cost [Line Items]
Costs related to investigation and remediation					$ 97,000,000	$ 99,000,000
Manufactured Gas Plants | Min.
Environmental Exit Cost [Line Items]
Costs related to investigation and remediation					164,000,000
Manufactured Gas Plants | Max.
Environmental Exit Cost [Line Items]
Costs related to investigation and remediation					430,000,000
Properties Where MGPs Had Historically Operated
Environmental Exit Cost [Line Items]
Costs related to investigation and remediation					$ 0

Income Taxes - Schedule of Curr

Income Taxes - Schedule of Current and Deferred Taxes Charged to (Benefit) Expense (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Current
Federal	$ 11	$ 17	$ (20)
State	(6)	2	12
Current taxes charged to expense (benefit)	5	19	(8)
Deferred
Federal	152	233	(124)
State	44	(12)	(73)
Deferred taxes charged to expense (benefit)	196	221	(197)
Production tax credits	(57)	(68)	(53)
Investment tax credits	(1)	(2)	(1)
Total Income Tax Expense (Benefit)	$ 143	$ 170	$ (259)

Income Taxes - Schedule of Diff

Income Taxes - Schedule of Differences between Tax Expense Per Statements of Income and Tax Expense at Statutory Federal Tax Rate (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Income Tax Disclosure [Abstract]
Tax expense at federal statutory rate	$ 172	$ 161	$ 43
Depreciation and amortization not normalized	(23)	(5)	9
Investment tax credit amortization	(1)	(2)	(1)
Tax return related adjustments	(2)	(6)	7
Production tax credits	(57)	(68)	(53)
Tax equity financing arrangements	8	0	(10)
Federal tax rate impact on held for sale classification	0	21	82
State tax expense (benefit), net of federal benefit	30	(8)	(40)
Tax Act - remeasurement	0	46	(328)
Other, net	16	31	32
Total Income Tax Expense (Benefit)	$ 143	$ 170	$ (259)

Income Taxes - Schedule of Defe

Income Taxes - Schedule of Deferred Tax Assets and Liabilities (Details) - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Deferred Income Tax Liabilities (Assets)
Property related	$ 4,007	$ 3,787
Unfunded future income taxes	101	107
Federal and state tax credits	(632)	(691)
Federal and state NOL’s	(989)	(993)
Joint ventures/partnerships	136	132
Nontaxable grant revenue	(335)	(354)
Pension and other post-retirement benefits	43	8
Tax Act - tax on regulatory remeasurement	(409)	(393)
Valuation allowance	33	23
Valuation allowance	(141)	(102)
Deferred Income Tax Liabilities	1,814	1,524
Classified as regulatory assets	0	(6)
Total Deferred Income Tax Liabilities	1,814	1,530
Deferred tax assets	2,506	2,533
Deferred tax liabilities	4,320	4,057
Net Accumulated Deferred Income Tax Liabilities	$ 1,814	$ 1,524

Income Taxes - Additional Infor

Income Taxes - Additional Information (Details) - USD ($)	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Income Taxes [Line Items]
Recognized valuation allowance	$ 33,000,000
Valuation allowance for deferred tax assets	33,000,000	$ 23,000,000
Decrease in valuation allowance, net of federal benefit	10,000,000
Additional valuation on state net operating losses	4,000,000
Additional valuation on state net operating losses release in Maine super credits	6,000,000
Unrecognized tax benefits that would impact effective tax rate	98,000,000
Net increase (decrease) to unrecognized tax benefits	0
Federal
Income Taxes [Line Items]
Net operating loss carry forwards	3,600,000,000
Recognized valuation allowance	4,000,000
State
Income Taxes [Line Items]
Net operating loss carry forwards	289,000,000
Tax credit carry forward	142,000,000
Recognized valuation allowance	29,000,000
Renewable Energy and Investment | Federal
Income Taxes [Line Items]
Tax credit carry forward	$ 600,000,000

Income Taxes - Schedule of Reco

Income Taxes - Schedule of Reconciliation of Unrecognized Income Tax Benefits (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Beginning Balance	$ 153	$ 45	$ 40
Increases for tax positions related to prior years	14	111	23
Increases for tax positions related to current year	16	0	0
Decreases for tax positions related to prior years	(18)	(3)	(16)
Reduction for tax position related to settlements with taxing authorities	(17)	0	(2)
Ending Balance	$ 148	$ 153	$ 45

Post-retirement and Similar O_3

Post-retirement and Similar Obligations - Obligations and Funded Status (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Pension Benefits
Change in benefit obligation
Benefit obligation as of January 1,	$ 3,374	$ 3,593
Service cost	41	44
Interest cost	130	128
Plan participants’ contributions	0	0
Plan Amendments	(2)	0
Actuarial loss (gain)	347	(159)
Benefits paid	(221)	(237)
Reclassified from held for sale	0	5
Benefit Obligation as of December 31,	3,669	3,374
Change in plan assets
Fair value of plan assets as of January 1,	2,544	2,865
Actual return (loss) on plan assets	460	(135)
Employer contributions	65	48
Plan participants’ contributions	0	0
Benefits paid	(221)	(237)
Reclassified from held for sale	0	3
Fair Value of Plan Assets as of December 31,	2,848	2,544
Funded Status as of December 31,	(821)	(830)
Postretirement Benefits
Change in benefit obligation
Benefit obligation as of January 1,	425	491
Service cost	3	4
Interest cost	16	19
Plan participants’ contributions	0	9
Plan Amendments	0	(3)
Actuarial loss (gain)	26	(55)
Benefits paid	(31)	(41)
Reclassified from held for sale	0	1
Benefit Obligation as of December 31,	439	425
Change in plan assets
Fair value of plan assets as of January 1,	148	165
Actual return (loss) on plan assets	22	(5)
Employer contributions	16	20
Plan participants’ contributions	0	9
Benefits paid	(31)	(41)
Reclassified from held for sale	0	0
Fair Value of Plan Assets as of December 31,	155	148
Funded Status as of December 31,	$ (284)	$ (277)

Post-retirement and Similar O_4

Post-retirement and Similar Obligations - Summary of Liabilities Amount Recognized (Details) - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Current liabilities	$ 0	$ 0
Non-current liabilities	(821)	(830)
Total	(821)	(830)
Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Current liabilities	(5)	(5)
Non-current liabilities	(279)	(272)
Total	$ (284)	$ (277)

Post-retirement and Similar O_5

Post-retirement and Similar Obligations - Summary of Amounts Recognized in Other Comprehensive Income (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Net loss (gain)	$ 23	$ 24	$ 25
Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Net loss (gain)	$ (8)	$ (7)	$ (4)

Post-retirement and Similar O_6

Post-retirement and Similar Obligations - Summary of Recognized as Regulatory Assets or Regulatory Liabilities (Details) - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Net loss (gain)	$ 706	$ 762	$ 737
Prior service cost (credit)	4	4	6
Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Net loss (gain)	13	(8)	35
Prior service cost (credit)	$ (21)	$ (25)	$ (31)

Post-retirement and Similar O_7

Post-retirement and Similar Obligations - Additional Information (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Defined Benefit Plan Disclosure [Line Items]
Accumulated benefit obligation	$ 3,451	$ 3,174
Amortization period	10 years
Annual contributions made	$ 40	37	$ 36
Non-Qualified Pension Plans
Defined Benefit Plan Disclosure [Line Items]
Other current and other non-current liabilities	$ 56	54
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Period of average pay at the time of the freeze date	5 years
Other current and other non-current liabilities	$ 821	830
Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Other current and other non-current liabilities	$ 284	$ 277
Postretirement Benefits | VEBA and 401(h) arrangements
Defined Benefit Plan Disclosure [Line Items]
Benefits plan, target asset allocation	37.00%
Networks | Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Expected contribution for pension benefit plans during 2018	$ 82
Networks | Pension Benefits | Return-Seeking assets | Min.
Defined Benefit Plan Disclosure [Line Items]
Benefits plan, target asset allocation	35.00%
Networks | Pension Benefits | Return-Seeking assets | Max.
Defined Benefit Plan Disclosure [Line Items]
Benefits plan, target asset allocation	70.00%
Networks | Pension Benefits | Liability-Hedging assets | Min.
Defined Benefit Plan Disclosure [Line Items]
Benefits plan, target asset allocation	34.00%
Networks | Pension Benefits | Liability-Hedging assets | Max.
Defined Benefit Plan Disclosure [Line Items]
Benefits plan, target asset allocation	65.00%
Networks | Postretirement Benefits | Equity Securities | Min.
Defined Benefit Plan Disclosure [Line Items]
Benefits plan, target asset allocation	45.00%
Networks | Postretirement Benefits | Equity Securities | Max.
Defined Benefit Plan Disclosure [Line Items]
Benefits plan, target asset allocation	65.00%
Networks | Postretirement Benefits | Fixed Income | Min.
Defined Benefit Plan Disclosure [Line Items]
Benefits plan, target asset allocation	25.00%
Networks | Postretirement Benefits | Fixed Income | Max.
Defined Benefit Plan Disclosure [Line Items]
Benefits plan, target asset allocation	45.00%
Networks | Postretirement Benefits | Other Investment Types | Min.
Defined Benefit Plan Disclosure [Line Items]
Benefits plan, target asset allocation	5.00%
Networks | Postretirement Benefits | Other Investment Types | Max.
Defined Benefit Plan Disclosure [Line Items]
Benefits plan, target asset allocation	25.00%
ARHI | Pension Benefits | Return-Seeking assets
Defined Benefit Plan Disclosure [Line Items]
Benefits plan, target asset allocation	60.00%
ARHI | Pension Benefits | Liability-Hedging assets
Defined Benefit Plan Disclosure [Line Items]
Benefits plan, target asset allocation	40.00%
ARHI | Postretirement Benefits | Equity Securities
Defined Benefit Plan Disclosure [Line Items]
Benefits plan, target asset allocation	45.00%
ARHI | Postretirement Benefits | Fixed Income
Defined Benefit Plan Disclosure [Line Items]
Benefits plan, target asset allocation	50.00%
ARHI | Postretirement Benefits | Cash and Cash Equivalents
Defined Benefit Plan Disclosure [Line Items]
Benefits plan, target asset allocation	5.00%

Post-retirement and Similar O_8

Post-retirement and Similar Obligations - Schedule of Aggregate PBO and ABO and Fair Value of Plan Assets for Underfunded Plans (Details) - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Retirement Benefits [Abstract]
Projected benefit obligation	$ 3,669	$ 3,374
Fair value of plan assets	2,848	2,544
Accumulated benefit obligation	3,451	3,174
Fair value of plan assets	$ 2,848	$ 2,544

Post-retirement and Similar O_9

Post-retirement and Similar Obligations - Schedule of Net Periodic Benefit Cost and Other Changes in Plan Assets and Benefit Obligations Recognized (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Pension Benefits
Net Periodic Benefit Cost:
Service cost	$ 41	$ 44
Interest cost	130	128
Other changes in plan assets and benefit obligations recognized in regulatory assets and regulatory liabilities:
Total Other Changes	23	24	$ 25
Postretirement Benefits
Net Periodic Benefit Cost:
Service cost	3	4
Interest cost	16	19
Other changes in plan assets and benefit obligations recognized in regulatory assets and regulatory liabilities:
Total Other Changes	(8)	(7)	(4)
Networks | Pension Benefits
Net Periodic Benefit Cost:
Service cost	41	44	42
Interest cost	128	126	137
Expected return on plan assets	(190)	(199)	(195)
Amortization of prior service (benefit) cost	(1)	1	2
Amortization of net loss	113	149	126
Net Periodic Benefit Cost	91	121	112
Other changes in plan assets and benefit obligations recognized in regulatory assets and regulatory liabilities:
Net loss (gain)	80	175	3
Amortization of net loss	(113)	(149)	(126)
Current year prior service cost	(2)	0	0
Amortization of prior service benefit (cost)	1	(1)	(2)
Total Other Changes	(34)	25	(125)
Total Recognized	57	146	(13)
Networks | Postretirement Benefits
Net Periodic Benefit Cost:
Service cost	3	4	5
Interest cost	16	18	21
Expected return on plan assets	(7)	(8)	(8)
Amortization of prior service (benefit) cost	(10)	(9)	(9)
Amortization of net loss	1	6	5
Net Periodic Benefit Cost	3	11	14
Other changes in plan assets and benefit obligations recognized in regulatory assets and regulatory liabilities:
Net loss (gain)	13	(37)	(5)
Amortization of net loss	(1)	(6)	(5)
Current year prior service cost	0	(3)	0
Amortization of prior service benefit (cost)	10	9	9
Total Other Changes	22	(37)	(1)
Total Recognized	25	(26)	13
ARHI | Pension Benefits
Net Periodic Benefit Cost:
Service cost	1	0	0
Interest cost	2	2	2
Expected return on plan assets	(2)	(2)	(2)
Amortization of net loss	1	1	1
Settlement charge	0	1	0
Net Periodic Benefit Cost	2	2	1
Other changes in plan assets and benefit obligations recognized in regulatory assets and regulatory liabilities:
Net loss (gain)	0	1	2
Amortization of net loss	(1)	(1)	(1)
Amortization of prior service benefit (cost)	0	0	0
Total Other Changes	(1)	0	1
Total Recognized	1	2	2
ARHI | Postretirement Benefits
Net Periodic Benefit Cost:
Service cost	0	0	0
Interest cost	0	1	1
Expected return on plan assets	0	0	0
Amortization of net loss	(1)	0	0
Settlement charge	0	0	0
Net Periodic Benefit Cost	(1)	1	1
Other changes in plan assets and benefit obligations recognized in regulatory assets and regulatory liabilities:
Net loss (gain)	0	(3)	(1)
Amortization of net loss	1	0	0
Amortization of prior service benefit (cost)	(2)	0	0
Total Other Changes	(1)	(3)	(1)
Total Recognized	$ (2)	$ (2)	$ 0

Post-retirement and Similar _10

Post-retirement and Similar Obligations - Schedule of Amounts Expected to be Amortized from Regulatory Assets or Liabilities and OCI into Net Periodic Benefit Cost (Details) $ in Millions	Dec. 31, 2019USD ($)
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Estimated net loss (gain)	$ 123
Estimated prior service cost (benefit)	1
Estimated net loss (gain)	2
Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Estimated net loss (gain)	2
Estimated prior service cost (benefit)	(9)
Estimated net loss (gain)	$ (1)

Post-retirement and Similar _11

Post-retirement and Similar Obligations - Schedule of Weighted-Average Assumptions Used to Determine Benefit Obligations and Net Periodic Benefit Cost (Details)	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Pension Benefits | Networks
Defined Benefit Plan Disclosure [Line Items]
Expected long-term return on plan assets			7.00%
Rate of compensation increase - net periodic benefit			3.50%
Pension Benefits | Networks | Min.
Defined Benefit Plan Disclosure [Line Items]
Discount rate - benefit obligations	2.93%	3.93%
Rate of compensation increase - benefit obligations	3.00%	3.50%
Discount rate - net periodic benefit	3.93%	3.63%	4.12%
Expected long-term return on plan assets	7.00%	7.00%
Rate of compensation increase - net periodic benefit	3.50%	3.50%
Pension Benefits | Networks | Max.
Defined Benefit Plan Disclosure [Line Items]
Discount rate - benefit obligations	3.19%	4.09%
Rate of compensation increase - benefit obligations	6.50%	4.20%
Discount rate - net periodic benefit	4.09%	3.80%	4.24%
Expected long-term return on plan assets	7.40%	7.40%	7.50%
Rate of compensation increase - net periodic benefit	4.20%	4.20%	4.20%
Pension Benefits | ARHI
Defined Benefit Plan Disclosure [Line Items]
Discount rate - benefit obligations	3.10%	4.09%
Discount rate - net periodic benefit	4.09%	3.80%	3.81%
Expected long-term return on plan assets	5.50%	5.50%	5.50%
Postretirement Benefits | Networks
Defined Benefit Plan Disclosure [Line Items]
Expected long-term return on plan assets		6.13%	6.13%
Postretirement Benefits | Networks | Nontaxable Trust
Defined Benefit Plan Disclosure [Line Items]
Expected long-term return on plan assets	6.40%	6.40%	6.50%
Postretirement Benefits | Networks | Taxable Trust
Defined Benefit Plan Disclosure [Line Items]
Expected long-term return on plan assets	4.20%	4.20%	4.25%
Postretirement Benefits | Networks | Min.
Defined Benefit Plan Disclosure [Line Items]
Discount rate - benefit obligations	2.93%	3.93%
Discount rate - net periodic benefit	3.93%	3.63%	4.12%
Expected long-term return on plan assets	4.90%
Postretirement Benefits | Networks | Max.
Defined Benefit Plan Disclosure [Line Items]
Discount rate - benefit obligations	3.19%	4.09%
Discount rate - net periodic benefit	4.09%	3.80%	4.24%
Expected long-term return on plan assets	7.00%
Postretirement Benefits | ARHI
Defined Benefit Plan Disclosure [Line Items]
Discount rate - benefit obligations	3.10%	4.09%

Post-retirement and Similar _12

Post-retirement and Similar Obligations - Schedule of Assumed Health Care Cost Trend Rates Used to Determine Benefit Obligations (Details)	Dec. 31, 2019	Dec. 31, 2018
Networks
Defined Benefit Plan Disclosure [Line Items]
Rate to which cost trend rate is assumed to decline (ultimate trend rate)	4.50%	4.50%
Networks | Min.
Defined Benefit Plan Disclosure [Line Items]
Health care cost trend rate assumed for next year	7.00%	7.50%
Networks | Max.
Defined Benefit Plan Disclosure [Line Items]
Health care cost trend rate assumed for next year	7.75%	8.50%
ARHI
Defined Benefit Plan Disclosure [Line Items]
Rate to which cost trend rate is assumed to decline (ultimate trend rate)	4.50%	4.50%
ARHI | Min.
Defined Benefit Plan Disclosure [Line Items]
Health care cost trend rate assumed for next year	6.75%	7.00%
ARHI | Max.
Defined Benefit Plan Disclosure [Line Items]
Health care cost trend rate assumed for next year	7.50%	7.75%

Post-retirement and Similar _13

Post-retirement and Similar Obligations - Schedule of Effects of One-Percent Change In Assumed Health Care Cost Trend Rates (Details) $ in Millions	12 Months Ended
	Dec. 31, 2019USD ($)
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Effect on total of service and interest cost, 1% Increase	$ 1
Effect on total of service and interest cost, 1% Decrease	0
Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Effect on postretirement benefit obligation, 1% Increase	12
Effect on postretirement benefit obligation, 1% Decrease	$ (11)

Post-retirement and Similar _14

Post-retirement and Similar Obligations - Estimated Future Benefit Payments (Details) $ in Millions	Dec. 31, 2019USD ($)
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
2020	$ 209
2021	210
2022	216
2023	217
2024	219
2025 - 2028	1,097
Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
2020	32
2021	32
2022	31
2023	30
2024	29
2025 - 2028	134
Medicare Act Subsidy Receipts
Defined Benefit Plan Disclosure [Line Items]
2020	1
2021	1
2022	0
2023	0
2024	0
2025 - 2028	$ 2

Post-retirement and Similar _15

Post-retirement and Similar Obligations - Fair Value of Benefits Plan Assets by Asset Category (Details) - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Fair value of assets, by asset category	$ 1,708	$ 1,612
Defined Benefit Plan, Plan Assets, Amount	2,848	2,544	$ 2,865
Pension Benefits | Cash and cash equivalents
Defined Benefit Plan Disclosure [Line Items]
Fair value of assets, by asset category	42	52
Pension Benefits | U.S. government securities
Defined Benefit Plan Disclosure [Line Items]
Fair value of assets, by asset category	87	15
Pension Benefits | Registered investment companies
Defined Benefit Plan Disclosure [Line Items]
Fair value of assets, by asset category	464	424
Pension Benefits | Corporate bonds
Defined Benefit Plan Disclosure [Line Items]
Fair value of assets, by asset category	458	413
Pension Benefits | Preferred stocks
Defined Benefit Plan Disclosure [Line Items]
Fair value of assets, by asset category	1	3
Pension Benefits | Common collective trusts
Defined Benefit Plan Disclosure [Line Items]
Fair value of assets, by asset category	572	634
Pension Benefits | Other, principally annuity, fixed income
Defined Benefit Plan Disclosure [Line Items]
Fair value of assets, by asset category	84	71
Pension Benefits | Level 1
Defined Benefit Plan Disclosure [Line Items]
Fair value of assets, by asset category	552	436
Pension Benefits | Level 1 | Cash and cash equivalents
Defined Benefit Plan Disclosure [Line Items]
Fair value of assets, by asset category	0	0
Pension Benefits | Level 1 | U.S. government securities
Defined Benefit Plan Disclosure [Line Items]
Fair value of assets, by asset category	87	15
Pension Benefits | Level 1 | Registered investment companies
Defined Benefit Plan Disclosure [Line Items]
Fair value of assets, by asset category	464	421
Pension Benefits | Level 1 | Corporate bonds
Defined Benefit Plan Disclosure [Line Items]
Fair value of assets, by asset category	0	0
Pension Benefits | Level 1 | Preferred stocks
Defined Benefit Plan Disclosure [Line Items]
Fair value of assets, by asset category	1	0
Pension Benefits | Level 1 | Common collective trusts
Defined Benefit Plan Disclosure [Line Items]
Fair value of assets, by asset category	0	0
Pension Benefits | Level 1 | Other, principally annuity, fixed income
Defined Benefit Plan Disclosure [Line Items]
Fair value of assets, by asset category	0	0
Pension Benefits | Level 2
Defined Benefit Plan Disclosure [Line Items]
Fair value of assets, by asset category	1,156	1,176
Pension Benefits | Level 2 | Cash and cash equivalents
Defined Benefit Plan Disclosure [Line Items]
Fair value of assets, by asset category	42	52
Pension Benefits | Level 2 | U.S. government securities
Defined Benefit Plan Disclosure [Line Items]
Fair value of assets, by asset category	0	0
Pension Benefits | Level 2 | Registered investment companies
Defined Benefit Plan Disclosure [Line Items]
Fair value of assets, by asset category	0	3
Pension Benefits | Level 2 | Corporate bonds
Defined Benefit Plan Disclosure [Line Items]
Fair value of assets, by asset category	458	413
Pension Benefits | Level 2 | Preferred stocks
Defined Benefit Plan Disclosure [Line Items]
Fair value of assets, by asset category	0	3
Pension Benefits | Level 2 | Common collective trusts
Defined Benefit Plan Disclosure [Line Items]
Fair value of assets, by asset category	572	634
Pension Benefits | Level 2 | Other, principally annuity, fixed income
Defined Benefit Plan Disclosure [Line Items]
Fair value of assets, by asset category	84	71
Pension Benefits | Level 3
Defined Benefit Plan Disclosure [Line Items]
Fair value of assets, by asset category	0	0
Pension Benefits | Level 3 | Cash and cash equivalents
Defined Benefit Plan Disclosure [Line Items]
Fair value of assets, by asset category	0	0
Pension Benefits | Level 3 | U.S. government securities
Defined Benefit Plan Disclosure [Line Items]
Fair value of assets, by asset category	0	0
Pension Benefits | Level 3 | Registered investment companies
Defined Benefit Plan Disclosure [Line Items]
Fair value of assets, by asset category	0	0
Pension Benefits | Level 3 | Corporate bonds
Defined Benefit Plan Disclosure [Line Items]
Fair value of assets, by asset category	0	0
Pension Benefits | Level 3 | Preferred stocks
Defined Benefit Plan Disclosure [Line Items]
Fair value of assets, by asset category	0	0
Pension Benefits | Level 3 | Common collective trusts
Defined Benefit Plan Disclosure [Line Items]
Fair value of assets, by asset category	0	0
Pension Benefits | Level 3 | Other, principally annuity, fixed income
Defined Benefit Plan Disclosure [Line Items]
Fair value of assets, by asset category	0	0
Pension Benefits | Other investments measured at net asset value
Defined Benefit Plan Disclosure [Line Items]
Other investments measured at net asset value	1,140	932
Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount	155	148	$ 165
Postretirement Benefits | Cash and cash equivalents
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount	31	9
Postretirement Benefits | Common Stock
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount	16	15
Postretirement Benefits | Registered investment companies
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount	98	115
Postretirement Benefits | Corporate bonds
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount	2	2
Postretirement Benefits | Other, principally annuity, fixed income
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount	8	7
Postretirement Benefits | Level 1
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount	114	135
Postretirement Benefits | Level 1 | Cash and cash equivalents
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount	0	5
Postretirement Benefits | Level 1 | Common Stock
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount	16	15
Postretirement Benefits | Level 1 | Registered investment companies
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount	98	115
Postretirement Benefits | Level 1 | Corporate bonds
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount	0	0
Postretirement Benefits | Level 1 | Other, principally annuity, fixed income
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount	0	0
Postretirement Benefits | Level 2
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount	41	13
Postretirement Benefits | Level 2 | Cash and cash equivalents
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount	31	4
Postretirement Benefits | Level 2 | Common Stock
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount	0	0
Postretirement Benefits | Level 2 | Registered investment companies
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount	0	0
Postretirement Benefits | Level 2 | Corporate bonds
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount	2	2
Postretirement Benefits | Level 2 | Other, principally annuity, fixed income
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount	8	7
Postretirement Benefits | Level 3
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount	0	0
Postretirement Benefits | Level 3 | Cash and cash equivalents
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount	0	0
Postretirement Benefits | Level 3 | Common Stock
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount	0	0
Postretirement Benefits | Level 3 | Registered investment companies
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount	0	0
Postretirement Benefits | Level 3 | Corporate bonds
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount	0	0
Postretirement Benefits | Level 3 | Other, principally annuity, fixed income
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount	$ 0	$ 0

Equity - Additional Information

Equity - Additional Information (Details) - USD ($) $ / shares in Units, $ in Millions	1 Months Ended		12 Months Ended
	May 31, 2018	May 31, 2017	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Class of Stock [Line Items]
Common stock, authorized (in shares)			500,000,000	500,000,000
Common stock, issued (in shares)			309,752,140	309,752,140
Common stock, outstanding (in shares)			309,005,272	309,005,272
Common stock, par value (in dollars per share)			$ 0.01	$ 0.01	$ 0.01	$ 0.01
Common stock			$ 3	$ 3
Additional paid-in capital			$ 13,660	$ 13,657
Treasury stock (in shares)			485,810
Convertible preferred stock, shares outstanding (in shares)			0	0
Issuance of common stock (in shares)			0	81,208
Release of common stock held in trust (in shares)			0	0
Treasury shares of common stock (in shares)			261,058
Repurchase of common stock (in shares)	81,208	64,019	115,831
Repurchases of common stock			$ 12	$ 12
Iberdrola Renewables Holding, Inc
Class of Stock [Line Items]
Percentage of equity owned by parent			81.50%

Equity - Accumulated Other Comp

Equity - Accumulated Other Comprehensive Income (Loss) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Jan. 01, 2019	Jan. 01, 2018
Accumulated Other Comprehensive Income (Loss)
Balance at beginning of period	$ 15,403	$ 15,096	$ 15,208
Change	(11)	(25)	40
Adoption of new accounting standards				$ (1)	$ 136
Balance at end of period	15,586	15,403	15,096
Gain on defined benefit plans, income tax expense (benefit)	(1)	0.3	0.2
Unrealized gain (loss) during period on derivatives qualified as cash flow hedges, income tax (expense) benefit	(8.6)
Unrealized gain (loss) during period on derivatives qualified as cash flow hedges, income tax (expense) benefit		(6.6)	15.2
Reclassification to net income of (gains) losses on cash flow hedges, income tax expense	2.7
Reclassification to net income of (gains) losses on cash flow hedges, income tax expense		(6.5)	9.3
Qualified Plan
Accumulated Other Comprehensive Income (Loss)
Gain on defined benefit plans, income tax expense (benefit)	(0.3)	1.1
Non-Qualified Pension Plans
Accumulated Other Comprehensive Income (Loss)
Gain on defined benefit plans, income tax expense (benefit)	(1)	0.3	0.2
Change in revaluation of defined benefit plans, net of income tax expense (benefit)
Accumulated Other Comprehensive Income (Loss)
Balance at beginning of period	(11)	(14)	(14)
Change	1	3	0
Adoption of new accounting standards				(2)	0
Balance at end of period	(12)	(11)	(14)
Loss (gain) for nonqualified pension plans, net of income tax expense (benefit)
Accumulated Other Comprehensive Income (Loss)
Balance at beginning of period	(6)	(6)	(7)
Change	(1)	1	1
Adoption of new accounting standards				0	(1)
Balance at end of period	(7)	(6)	(6)
Unrealized gain (loss) during period on derivatives qualifying as cash flow hedges, net of income tax expense (benefit)
Accumulated Other Comprehensive Income (Loss)
Balance at beginning of period	9	30	5
Change	(22)	(21)	25
Adoption of new accounting standards				0	0
Balance at end of period	(13)	9	30
Reclassification to net income of losses (gains) on cash flow hedges, net of income tax expense (benefit)
Accumulated Other Comprehensive Income (Loss)
Balance at beginning of period	(64)	(56)	(70)
Change	11	(8)	14
Adoption of new accounting standards				(10)	0
Balance at end of period	(63)	(64)	(56)
Gain (loss) on derivatives qualifying as cash flow hedges
Accumulated Other Comprehensive Income (Loss)
Balance at beginning of period	(55)	(26)	(65)
Change		(29)	39
Adoption of new accounting standards					0
Balance at end of period		(55)	(26)
Gain (loss) on derivatives qualifying as cash flow hedges
Accumulated Other Comprehensive Income (Loss)
Change	(11)
Adoption of new accounting standards				(10)
Balance at end of period	(76)
Accumulated Other Comprehensive (Loss) Income
Accumulated Other Comprehensive Income (Loss)
Balance at beginning of period	(72)	(46)	(86)
Change	(11)	(25)	40
Adoption of new accounting standards				$ (12)	$ (1)
Balance at end of period	$ (95)	$ (72)	$ (46)

Earnings Per Share (Details)

Earnings Per Share (Details) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Numerator:
Net income attributable to AVANGRID	$ 223	$ 150	$ 110	$ 217	$ 119	$ 125	$ 107	$ 244	$ 700	$ 595	$ 381
Denominator:
Weighted average number of shares outstanding - basic (in shares)									309,491,082	309,503,319	309,502,861
Weighted average number of shares outstanding - diluted (in shares)									309,514,910	309,712,628	309,661,883
Earnings per share attributable to AVANGRID
Earnings Per Common Share, Basic (in dollars per share)							$ 0.35		$ 2.26	$ 1.92	$ 1.23
Earnings Per Common Share, Diluted (in dollars per share)							$ 0.34		$ 2.26	$ 1.92	$ 1.23

Variable Interest Entities (Det

Variable Interest Entities (Details) $ in Millions	Mar. 02, 2020USD ($)	Dec. 13, 2019USD ($)	Jun. 28, 2019USD ($)MW	Feb. 29, 2020MW	Dec. 31, 2019USD ($)	Sep. 30, 2019USD ($)	Dec. 31, 2018USD ($)
Variable Interest Entity [Line Items]
Equity method investments of variable interest entities (VIEs)					$ 645		$ 366
Patriot Wind Farm LLC
Variable Interest Entity [Line Items]
Proposed wind farm and electricity transmission project capacity (in MW) | MW			226
Asset acquisition, consideration transferred			$ 317
Asset acquisition, recognized identifiable assets acquired and liabilities assumed, property, plant, and equipment			344
Asset acquisition, recognized identifiable assets acquired and liabilities assumed, derivative liabilities			26
Asset acquisition, recognized identifiable assets acquired and liabilities assumed, other liabilities			1
Tax equity financing arrangements noncurrent			$ 128
Aeolus Wind Power II LLC
Variable Interest Entity [Line Items]
Noncontrolling interest in variable interest entity						$ 50
Noncontrolling interest in variable interest entity, amount to third party investors						$ 31
Equity interest percentage		4.40%
Payments to noncontrolling interests		$ 14
Noncontrolling interest remaining balance		$ 10
Variable Interest Entity, Primary Beneficiary
Variable Interest Entity [Line Items]
Assets of variable interest entities (VIEs)					806		876
Liabilities of variable interest entities (VIEs)					29		50
Equity method investments of variable interest entities (VIEs)					$ 0		$ 101
Subsequent Event | Aeolus Wind Power VII LLC
Variable Interest Entity [Line Items]
Proposed wind farm and electricity transmission project capacity (in MW) | MW				681
Proceeds from contributed capital	$ 237

Grants, Government Incentives_3

Grants, Government Incentives and Deferred Income (Details) - USD ($) $ in Millions	3 Months Ended	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2019	Dec. 31, 2018
Deferred Credits and Other Liabilities [Roll Forward]
Balance at beginning of period		$ 1,385	$ 1,446
Additions			9
Additions and disposals		(3)
Derecognition due to sale		(38)
Recognized in income		(70)	(70)
Balance at end of period	$ 1,274	$ 1,274	1,385
Poseidon Project
Deferred Credits and Other Liabilities [Roll Forward]
Ownership percentage sold	50.00%	50.00%
Government grants
Deferred Credits and Other Liabilities [Roll Forward]
Balance at beginning of period		$ 1,367	1,427
Additions			9
Additions and disposals		(3)
Derecognition due to sale		(38)
Recognized in income		(68)	(69)
Balance at end of period	$ 1,258	1,258	1,367
Other deferred income
Deferred Credits and Other Liabilities [Roll Forward]
Balance at beginning of period		18	19
Additions			0
Additions and disposals		0
Derecognition due to sale		0
Recognized in income		(2)	(1)
Balance at end of period	$ 16	$ 16	$ 18

Equity Method Investments (Deta

Equity Method Investments (Details)	Dec. 13, 2019USD ($)	Jan. 31, 2020USD ($)	Dec. 31, 2019USD ($)mi²plantjoint_ventureMW	Dec. 31, 2018USD ($)	Aug. 31, 2018MW	May 31, 2018MW	Dec. 31, 2019USD ($)mi²plantjoint_ventureMW	Dec. 31, 2018USD ($)	Dec. 31, 2017USD ($)
Schedule of Equity Method Investments [Line Items]
OTTI recorded on investment							$ 0	$ 0	$ 49,000,000
Equity method investments			$ 645,000,000	$ 366,000,000			$ 645,000,000	366,000,000
Number of peaking generation plants | plant			2				2
Distribution of earnings from equity method investments							$ 17,000,000	18,000,000	20,000,000
Equity method investment, distributions received in RECs							9,000,000	8,000,000
Capitalized interest costs							7,000,000	0
Arizona Wind Farm
Schedule of Equity Method Investments [Line Items]
Business combination, equity interest percentage	50.00%
Equity method investments			$ 111,000,000				$ 111,000,000
Colorado Wind Ventures, LLC
Schedule of Equity Method Investments [Line Items]
Additional percentage acquired					50.00%
Leased are transmission capacity (in MW) | MW					162
OTTI recorded on investment									$ 49,000,000
Coyote Ridge Wind LLC
Schedule of Equity Method Investments [Line Items]
Business combination, equity interest percentage			20.00%				20.00%
Ownership interest, percentage sold				80.00%
Proceeds from sale of portion of subsidiary				$ 144,000,000			$ 84,000,000
Gain (loss) on sale							4,000,000	10,000,000
Equity method investments			$ 14,000,000	5,000,000			$ 14,000,000	5,000,000
Horizon Wind Energy LLC
Schedule of Equity Method Investments [Line Items]
Business combination, equity interest percentage			50.00%				50.00%
Number of joint ventures | joint_venture			2				2
Flat Rock Wind Power LLC
Schedule of Equity Method Investments [Line Items]
Leased are transmission capacity (in MW) | MW							231
Equity method investments			$ 105,000,000	114,000,000			$ 105,000,000	114,000,000
Flat Rock Wind Power II LLC
Schedule of Equity Method Investments [Line Items]
Leased are transmission capacity (in MW) | MW							91
Equity method investments			$ 49,000,000	53,000,000			$ 49,000,000	53,000,000
Vineyard Wind, LLC
Schedule of Equity Method Investments [Line Items]
Business combination, equity interest percentage			50.00%				50.00%
Leased are transmission capacity (in MW) | MW							3,000
Equity method investments			$ 227,000,000	52,000,000			$ 227,000,000	52,000,000
Area of land | mi²			260				260
Proposed wind farm and electricity transmission project capacity (in MW) | MW			804			800
Amount funded to date							$ 106,000,000
Portion of amount receivable from related parties			$ 5,000,000	0			5,000,000	0
Vineyard Wind, LLC | Renewables
Schedule of Equity Method Investments [Line Items]
Amount funded to date							$ 120,000,000
Clearway Energy, Inc
Schedule of Equity Method Investments [Line Items]
Business combination, equity interest percentage			50.00%				50.00%
Equity method investments			$ 113,000,000	119,000,000			$ 113,000,000	119,000,000
Number of peaking generation plants | plant			2				2
New York TransCo.
Schedule of Equity Method Investments [Line Items]
Business combination, equity interest percentage			20.00%				20.00%
Leased are transmission capacity (in MW) | MW							3,200
Equity method investments			$ 26,000,000	23,000,000			$ 26,000,000	23,000,000
Amount funded to date							600,000,000
Portion of amount receivable from related parties			$ 0	$ 1,000,000			$ 0	$ 1,000,000
New York TransCo. | NYSEG
Schedule of Equity Method Investments [Line Items]
Business combination, equity interest percentage			20.00%				20.00%
Amount funded to date							$ 120,000,000
Subsequent Event | Vineyard Wind, LLC | Renewables
Schedule of Equity Method Investments [Line Items]
Amount funded to date		$ 13,000,000
Sale of Business | Arizona Wind Farm
Schedule of Equity Method Investments [Line Items]
Held-for-sale, percentage of ownership to be transferred	50.00%
Assets held for sale, consideration receivable	$ 112,000,000
Gain on sale of business, net of tax	96,000,000
Gain on sale of business, pre-tax	134,000,000
Gain on remeasurement of retained investment	$ 50,000,000

Other Financial Statements It_3

Other Financial Statements Items - Additional Information (Details) - USD ($) $ in Millions	3 Months Ended		12 Months Ended
	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Accounts, Notes, Loans and Financing Receivable [Line Items]
Loss from assets held for sale			$ 0	$ 16	$ 642
Deferred Payment Arrangements
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts receivable			$ 65	62
Gas Trading and Storage Businesses
Accounts, Notes, Loans and Financing Receivable [Line Items]
Loss from assets held for sale	$ 10	$ 5
Held for Sale | Gas Trading and Storage Businesses
Accounts, Notes, Loans and Financing Receivable [Line Items]
Loss from assets held for sale				$ 16	$ 642

Other Financial Statements It_4

Other Financial Statements Items - Schedule of Other Income and (Expense) (Details) - USD ($) $ in Millions	3 Months Ended	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Gain on sale of assets		$ 148	$ 10	$ 0
Allowance for funds used during construction		46	30	36
Carrying costs on regulatory assets		21	21	11
Non-service component of net periodic benefit cost		(79)	(128)	(120)
Other		(17)	1	11
Total Other Income (Expense)		119	(66)	$ (62)
Poseidon Project
Schedule of Investments [Line Items]
Gain (loss) on sale	$ 134	$ 134
Ownership percentage sold	50.00%	50.00%
Coyote Ridge Wind LLC
Schedule of Investments [Line Items]
Gain (loss) on sale		$ 4	$ 10

Other Financial Statements It_5

Other Financial Statements Items - Schedule of Accounts Receivable (Details) - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Trade receivables	$ 1,151	$ 1,204
Allowance for bad debts	(69)	(62)	$ (64)	$ (64)
Total Accounts Receivable	$ 1,082	$ 1,142

Other Financial Statements It_6

Other Financial Statements Items - Schedule of Change in Allowance For Bad Debts (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Accounts Receivable, Allowance for Credit Loss [Roll Forward]
Beginning balance	$ 62	$ 64	$ 64
Current period provision	92	74	69
Write-off as uncollectible	(85)	(76)	(69)
Ending balance	$ 69	$ 62	$ 64

Other Financial Statements It_7

Other Financial Statements Items - Schedule of Prepayments and Other Current Assets (Details) - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Prepaid other taxes	$ 123	$ 137
Broker margin and collateral accounts	33	37
Other pledged deposits	3	6
Prepaid expenses	34	43
Other	6	6
Total	$ 199	$ 229

Other Financial Statements It_8

Other Financial Statements Items - Schedule of Other Current Liabilities (Details) - USD ($) $ in Millions	Dec. 31, 2019	Jan. 01, 2019	Dec. 31, 2018
Payables and Accruals [Abstract]
Advances received	$ 140		$ 129
Accrued salaries	89		81
Short-term environmental provisions	40		60
Collateral deposits received	44		42
Pension and other postretirement	5		5
Finance leases	9
Finance leases			0
Other	7		10
Total	$ 334	$ 355	$ 327

Segment Information - Additiona

Segment Information - Additional Information (Details)	12 Months Ended
	Dec. 31, 2019segment
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	8

Segment Information - By Segmen

Segment Information - By Segment (Details) - USD ($) $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Jan. 01, 2019
Segment Reporting Information [Line Items]
Operating revenues	$ 1,609	$ 1,487	$ 1,400	$ 1,842	$ 1,665	$ 1,546	$ 1,402	$ 1,865	$ 6,338	$ 6,478	$ 5,963
Loss from assets held for sale									0	16	642
Depreciation and amortization									934	855	824
Operating income (loss)	216	$ 239	$ 207	$ 341	249	$ 253	$ 222	$ 403	1,003	1,127	505
Earnings (losses) from equity method investments									3	10	(40)
Interest expense, net of capitalization									306	303	280
Income tax (benefit) expense									143	170	(259)
Capital expenditures									2,740	1,787	2,416
Adjusted net income									673	684	682
Property, plant and equipment	25,218				23,459				25,218	23,459		$ 23,312
Equity method investments	645				366				645	366
Total assets	34,416				32,167				34,416	32,167
Networks
Segment Reporting Information [Line Items]
Operating revenues									5,150	5,304
Renewables
Segment Reporting Information [Line Items]
Operating revenues									1,186	1,137
Operating Segments | Networks
Segment Reporting Information [Line Items]
Operating revenues									5,164	5,310	4,950
Loss from assets held for sale										0	0
Depreciation and amortization									550	503	474
Operating income (loss)									893	975	1,114
Earnings (losses) from equity method investments									11	13	15
Interest expense, net of capitalization									269	260	244
Income tax (benefit) expense									153	169	316
Capital expenditures									1,612	1,377	1,305
Adjusted net income									466	486	507
Property, plant and equipment	15,840				14,754				15,840	14,754
Equity method investments	139				142				139	142
Total assets	23,250				22,239				23,250	22,239
Operating Segments | Renewables
Segment Reporting Information [Line Items]
Operating revenues									1,186	1,139	1,038
Loss from assets held for sale										0	0
Depreciation and amortization									383	352	325
Operating income (loss)									95	136	92
Earnings (losses) from equity method investments									(8)	(3)	(55)
Interest expense, net of capitalization									10	33	28
Income tax (benefit) expense									4	(31)	(320)
Capital expenditures									1,125	410	1,097
Adjusted net income									223	185	120
Property, plant and equipment	9,368				8,697				9,368	8,697
Equity method investments	506				224				506	224
Total assets	13,163				10,703				13,163	10,703
Intersegment Eliminations
Segment Reporting Information [Line Items]
Operating revenues									(14)	(8)	(20)
Intersegment Eliminations | Networks
Segment Reporting Information [Line Items]
Operating revenues									(14)	(6)	(11)
Intersegment Eliminations | Renewables
Segment Reporting Information [Line Items]
Operating revenues									0	(2)	(9)
Other
Segment Reporting Information [Line Items]
Operating revenues									2	37	(25)
Loss from assets held for sale										16	642
Depreciation and amortization									1	0	25
Operating income (loss)									15	16	(701)
Earnings (losses) from equity method investments									0	0	0
Interest expense, net of capitalization									27	10	8
Income tax (benefit) expense									(14)	32	(255)
Capital expenditures									3	0	14
Adjusted net income									(15)	13	$ 55
Property, plant and equipment	10				8				10	8
Equity method investments	0				0				0	0
Total assets	$ (1,997)				$ (775)				$ (1,997)	$ (775)

Segment Information - Reconcili

Segment Information - Reconciliation of Consolidated EBITDA to Consolidated Net Income (Details) - USD ($) $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Segment Reporting [Abstract]
Adjusted Net Income Attributable to Avangrid, Inc.									$ 673	$ 684	$ 682
Impairment of equity method and other investment									0	0	(49)
Restructuring charges									(6)	(4)	(20)
Mark-to-market adjustments - Renewables									76	(25)	(15)
Loss from held for sale measurement									0	(16)	(642)
Impact of the Tax Act									0	(46)	328
Accelerated depreciation from repowering									(33)	(3)	0
Income tax impact of adjustments									(10)	(6)	162
Gas Storage, net of tax									0	11	(64)
Net Income Attributable to Avangrid, Inc.	$ 223	$ 150	$ 110	$ 217	$ 119	$ 125	$ 107	$ 244	$ 700	$ 595	$ 381

Related Party Transactions - Sc

Related Party Transactions - Schedule of Related Party Transactions (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Iberdrola Canada Energy Services, Ltd
Related Party Transaction [Line Items]
Sales To	$ 0	$ 0	$ 0
Purchases From	0	(5)	(33)
Iberdrola Renovables Energia, S.L.
Related Party Transaction [Line Items]
Sales To	0	0	0
Purchases From	(9)	(14)	(9)
Iberdrola, S.A.
Related Party Transaction [Line Items]
Sales To	1	1	1
Purchases From	(42)	(38)	(36)
Iberdrola Financiación, S.A.
Related Party Transaction [Line Items]
Sales To	0	0	0
Purchases From	(3)	(3)	(2)
Iberdrola Energia Monterrey, S.A. de C.V.
Related Party Transaction [Line Items]
Sales To	0	3	46
Purchases From	0	0	0
Vineyard Wind
Related Party Transaction [Line Items]
Sales To	13	3	0
Purchases From	0	0	0
Other
Related Party Transaction [Line Items]
Sales To	2	2	1
Purchases From	$ (3)	$ (5)	$ (1)

Related Party Transactions - Ad

Related Party Transactions - Additional Information (Details) - USD ($)	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Related Party Transaction [Line Items]
Impairments	$ 0	$ 16,000,000	$ 642,000,000
Iberdrola
Related Party Transaction [Line Items]
Deposit balance	150,000,000	0
Iberdrola Canada Energy Services, Ltd
Related Party Transaction [Line Items]
Notes payable, related parties	0	0
Affiliated Entity
Related Party Transaction [Line Items]
Impairments	0
Iberdrola Financiacion S A U
Related Party Transaction [Line Items]
Credit facility maximum borrowing capacity	$ 500,000,000
Credit facility initial fees range	0.105%
Credit facility, amount outstanding	$ 0	0
Siemens-Gamesa | Iberdrola
Related Party Transaction [Line Items]
Business acquisition, percentage of voting interests acquired	8.10%
Related party transaction, amount	$ 18,000,000	$ 6,000,000

Related Party Transactions - _2

Related Party Transactions - Schedule of Related Party Balances (Details) - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Siemens-Gamesa
Related Party Transaction [Line Items]
Owed By	$ 0	$ 0
Owed To	(18)	(14)
Iberdrola, S.A.
Related Party Transaction [Line Items]
Owed By	1	1
Owed To	(42)	(40)
Iberdrola Renovables Energia, S.L.
Related Party Transaction [Line Items]
Owed By	0	4
Owed To	0	0
Vineyard Wind
Related Party Transaction [Line Items]
Owed By	5	0
Owed To	0	0
Other
Related Party Transaction [Line Items]
Owed By	4	1
Owed To	$ (4)	$ (4)

Stock-Based Compensation - Addi

Stock-Based Compensation - Additional Information (Details) $ / shares in Units, $ in Millions	1 Months Ended			12 Months Ended
	Oct. 31, 2018$ / sharesshares	Jun. 30, 2018$ / sharesshares	Jul. 31, 2016$ / sharesshares	Dec. 31, 2019USD ($)installment$ / sharesshares	Dec. 31, 2018USD ($)shares	Dec. 31, 2017USD ($)shares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of PSUs granted (in shares)				6,284,000,000
Number of shares authorized for stock-based compensation plans (in shares)				2,500,000
Share-based payment award options grant date fair value (in dollars per share) | $ / shares				$ 38.78
Stock-based compensation expense | $				$ 3	$ 2	$ 1
Income tax benefit recognized for stock-based compensation arrangements | $				1	$ 1	$ 1
Unrecognized cost for non-vested PSUs | $				$ 3
Recognition of PSU costs, weighted-average period				2 years
Performance Shares Units | Officers and Employees
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of PSUs granted (in shares)			1,298,683	3,881	75,350	85,759
Number of installment payments of employee related payables (in installments) | installment				3
Share-based payment award options grant date fair value (in dollars per share) | $ / shares			$ 31.80
Share-based payment award options requisite service period			7 years
Restricted Stock Units (RSUs) | Executive Officer
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of PSUs granted (in shares)	8,000	60,000
Number of installment payments of employee related payables (in installments) | installment				1
Share-based payment award options grant date fair value (in dollars per share) | $ / shares	$ 47.59	$ 50.40

Stock-Based Compensation - Summ

Stock-Based Compensation - Summary of Nonvested PSUs and RSUs (Details)	12 Months Ended
	Dec. 31, 2019$ / sharesshares
Number of PSUs
Nonvested Balance – beginning of year (in shares) | shares	1,268,722,000,000
Granted (in shares) | shares	6,284,000,000
Forfeited (in shares) | shares	(726,000,000)
Nonvested Balance – end of year (in shares) | shares	1,274,280,000,000
Weighted Average Grant Date Fair Value
Nonvested Balance – beginning of year (in dollars per share) | $ / shares	$ 32.80
Granted (in dollars per share) | $ / shares	38.78
Forfeited (in dollars per share) | $ / shares	31.80
Nonvested Balance – end of year (in dollars per share) | $ / shares	$ 32.83

Restructuring and Severance R_3

Restructuring and Severance Related Expenses - Additional Information (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Restructuring Cost and Reserve [Line Items]
Severance expenses	$ 4	$ 3	$ 15
Lease termination expenses			4
Accelerated amortization of leasehold improvements	$ 33	$ 3	0
Depreciation And Amortization
Restructuring Cost and Reserve [Line Items]
Accelerated amortization of leasehold improvements			$ 1

Restructuring and Severance R_4

Restructuring and Severance Related Expenses - Summary of Severance and Lease Restructuring Charges Reserves Recorded in Other Current Liabilities and Other Liabilities (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Restructuring Reserve [Roll Forward]
Restructuring and severance related expenses	$ 6	$ 4	$ 20
Severance And Lease Restructuring
Restructuring Reserve [Roll Forward]
Beginning Balance	4
Restructuring and severance related expenses	4
Payments	(3)
Ending Balance	$ 5	$ 4

Quarterly financial data (una_3

Quarterly financial data (unaudited) - Quarterly Financial Information (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Selected Quarterly Financial Information [Abstract]
Operating revenues	$ 1,609	$ 1,487	$ 1,400	$ 1,842	$ 1,665	$ 1,546	$ 1,402	$ 1,865	$ 6,338	$ 6,478	$ 5,963
Operating Income	216	239	207	341	249	253	222	403	1,003	1,127	505
Net Income	216	139	105	216	116	134	110	238	676	598	382
Net Income attributable to Avangrid, Inc.	$ 223	$ 150	$ 110	$ 217	$ 119	$ 125	$ 107	$ 244	$ 700	$ 595	$ 381
Earnings Per Common Share, Basic and Diluted (in dollars per share)	$ 0.72	$ 0.48	$ 0.36	$ 0.70	$ 0.38	$ 0.40		$ 0.79
Weighted average shares outstanding, basic and diluted (in shares)	309.5	309.5	309.5	309.5	309.5	309.5	309.5	309.5
Earnings Per Common Share, Basic (in dollars per share)							$ 0.35		$ 2.26	$ 1.92	$ 1.23
Earnings Per Common Share, Diluted (in dollars per share)							$ 0.34		$ 2.26	$ 1.92	$ 1.23

Quarterly financial data (una_4

Quarterly financial data (unaudited) - Additional Information (Details) - USD ($) $ in Millions	3 Months Ended					12 Months Ended
	Dec. 31, 2019	Sep. 30, 2019	Dec. 31, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Selected Quarterly Financial Information [Line Items]
Gain (loss) on assets held for sale						$ 0	$ (16)	$ (642)
Gain (loss) on assets held for sale, after income taxes						0	$ (16)	$ (642)
Measurement of deferred income tax balances result of Tax Act			$ 39	$ 7
Wholesale electricity contracts
Selected Quarterly Financial Information [Line Items]
Gain (loss) on assets held for sale		$ 43
Gain (loss) on assets held for sale, after income taxes		$ 32
Gas Trading and Storage Businesses
Selected Quarterly Financial Information [Line Items]
Gain (loss) on assets held for sale				(10)	$ (5)
Gain (loss) on assets held for sale, after income taxes				$ 17	$ 14
Poseidon Project
Selected Quarterly Financial Information [Line Items]
Gain (loss) on assets held for sale, after income taxes	$ 96
Gain (loss) on sale	$ 134					$ 134
Ownership percentage sold	50.00%					50.00%

Subsequent events (Details)

Subsequent events (Details) - $ / shares	Feb. 19, 2020	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Subsequent Event [Line Items]
Dividends declared (in dollars per share)		$ 1.76	$ 1.744	$ 1.728
Subsequent Event
Subsequent Event [Line Items]
Dividends declared (in dollars per share)	$ 0.44

Condensed Financial Informati_2

Condensed Financial Information of Parent - Condensed Statement of Income (Details) - USD ($) $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Condensed Income Statements, Captions [Line Items]
Operating revenues	$ 1,609	$ 1,487	$ 1,400	$ 1,842	$ 1,665	$ 1,546	$ 1,402	$ 1,865	$ 6,338	$ 6,478	$ 5,963
Operating Expenses
Taxes other than income taxes									591	579	563
Total Operating Expenses									5,335	5,351	5,458
Operating Income	216	239	207	341	249	253	222	403	1,003	1,127	505
Other Income
Other income									119	(66)	(62)
Equity earnings of subsidiaries									3	10	(40)
Interest expense									(306)	(303)	(280)
Income Before Income Tax									819	768	123
Income tax (benefit) expense									143	170	(259)
Net Income Attributable to Avangrid, Inc.	$ 223	$ 150	$ 110	$ 217	$ 119	$ 125	$ 107	$ 244	700	595	381
AVANGRID Networks
Condensed Income Statements, Captions [Line Items]
Operating revenues									0	0	0
Operating Expenses
Operating expense									3	3	3
Taxes other than income taxes									(12)	(11)	5
Total Operating Expenses									(9)	(8)	8
Operating Income									9	8	(8)
Other Income
Other income									59	48	58
Equity earnings of subsidiaries									711	604	312
Interest expense									(93)	(56)	(29)
Income Before Income Tax									686	604	333
Income tax (benefit) expense									(14)	9	(48)
Net Income Attributable to Avangrid, Inc.									$ 700	$ 595	$ 381

Condensed Financial Informati_3

Condensed Financial Information of Parent - Statements of Comprehensive Income (Details) - USD ($) $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Condensed Statement of Income Captions [Line Items]
Net Income	$ 223	$ 150	$ 110	$ 217	$ 119	$ 125	$ 107	$ 244	$ 700	$ 595	$ 381
Other comprehensive (loss) income of subsidiaries									(11)	(25)	40
Comprehensive Income Attributable to Avangrid, Inc.									689	570	421
AVANGRID Networks
Condensed Statement of Income Captions [Line Items]
Net Income									700	595	381
Other comprehensive (loss) income of subsidiaries									(11)	(25)	40
Comprehensive Income Attributable to Avangrid, Inc.									$ 689	$ 570	$ 421

Condensed Financial Informati_4

Condensed Financial Information of Parent - Balance Sheets (Details) - USD ($) $ in Millions	Dec. 31, 2019	Jan. 01, 2019	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Current Assets
Cash and cash equivalents	$ 178		$ 36
Accounts receivable from subsidiaries	1,082		1,142
Prepayments and other current assets	199		229
Total Current Assets	2,025		1,963
Investments in subsidiaries	63		58
Other Assets
Other	311	$ 308	162
Total Other Assets	3,828		3,675
Total Assets	34,416		32,167
Current Liabilities
Current portion of debt	730	366	394
Notes payable	560		587
Accounts payable and accrued liabilities	1,361		1,132
Interest accrued	72		62
Dividends payable	136		136
Taxes accrued	56		59
Total Current Liabilities	3,587		3,004
Non-current debt	6,716	5,307	5,368
Total Liabilities	18,830		16,764
Stockholders' Equity:
Common stock	3		3
Additional paid-in capital	13,660		13,657
Treasury Stock	(12)		(12)
Retained earnings	1,681	$ 1,527	1,528
Accumulated other comprehensive loss	(95)		(72)
Total Equity	15,586		15,403	$ 15,096	$ 15,208
Total Liabilities and Equity	34,416		32,167
AVANGRID Networks
Current Assets
Cash and cash equivalents	146		0
Accounts receivable from subsidiaries	22		306
Notes receivable from subsidiaries	2,529		666
Prepayments and other current assets	0		21
Total Current Assets	2,697		993
Investments in subsidiaries	16,859		16,067
Other Assets
Deferred income taxes	374		312
Other	3		1
Total Other Assets	377		313
Total Assets	19,933		17,373
Current Liabilities
Current portion of debt	456		8
Notes payable	561		588
Notes payable to subsidiaries	1,674		456
Accounts payable and accrued liabilities	2		10
Accounts payable to subsidiaries	7		9
Interest accrued	10		7
Interest accrued subsidiaries	18		6
Dividends payable	136		136
Taxes accrued	24		0
Total Current Liabilities	2,888		1,220
Non-current debt	1,808		1,049
Total Liabilities	4,696		2,269
Stockholders' Equity:
Common stock	3		3
Additional paid-in capital	13,660		13,657
Treasury Stock	(12)		(12)
Retained earnings	1,681		1,528
Accumulated other comprehensive loss	(95)		(72)
Total Equity	15,237		15,104
Total Liabilities and Equity	$ 19,933		$ 17,373

Condensed Financial Informati_5

Condensed Financial Information of Parent - Statement of Cash Flows (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Condensed Cash Flow Statements, Captions [Line Items]
Net Cash used in Operating Activities	$ 1,593	$ 1,791	$ 1,763
Cash Flow from Investing Activities
Net Cash (used in) provided by Investing Activities	(2,713)	(1,564)	(2,341)
Cash Flow from Financing Activities
Non-current debt issuances	2,137	597	888
Repurchase of common stock	0	(4)	(3)
Issuance of common stock	0	(2)	(1)
Dividends paid	(545)	(537)	(535)
Net Cash Provided by (Used in) Financing Activities	1,261	(230)	528
Net Increase (Decrease) in Cash, Cash Equivalents and Restricted Cash	141	(3)	(50)
Cash, Cash Equivalents and Restricted Cash, Beginning of Year	43	46	96
Cash, Cash Equivalents and Restricted Cash, End of Year	184	43	46
Supplemental Cash Flow Information
Cash paid for interest	266	224	202
Cash paid (refunded) payment for income taxes	2	(13)	13
AVANGRID Networks
Condensed Cash Flow Statements, Captions [Line Items]
Net Cash used in Operating Activities	(1,299)	(323)	(1)
Cash Flow from Investing Activities
Notes receivable from subsidiaries	633	462	(532)
Investments in subsidiaries	(399)	(48)	0
Return of capital from investments in subsidiaries	433	116	308
Net Cash (used in) provided by Investing Activities	667	530	(224)
Cash Flow from Financing Activities
Receipts (repayments) of short-term notes payable from subsidiaries, net	107	246
Receipts (repayments) of short-term notes payable from subsidiaries, net			(246)
(Repayments) receipts of short-term notes payable	(27)
(Repayments) receipts of short-term notes payable		82	357
Non-current debt issuances	1,243	0	594
Repurchase of common stock	0	(4)	(3)
Issuance of common stock	0	(2)	(1)
Dividends paid	(545)	(537)	(535)
Net Cash Provided by (Used in) Financing Activities	778	(215)	166
Net Increase (Decrease) in Cash, Cash Equivalents and Restricted Cash	146	(8)	(59)
Cash, Cash Equivalents and Restricted Cash, Beginning of Year	0	8	67
Cash, Cash Equivalents and Restricted Cash, End of Year	146	0	8
Supplemental Cash Flow Information
Cash paid for interest	85	55	52
Cash paid (refunded) payment for income taxes	$ 43	$ 55	$ (8)

Condensed Financial Informati_6

Condensed Financial Information of Parent - Common Stock (Details) - USD ($) $ / shares in Units, $ in Millions	1 Months Ended		12 Months Ended
	May 31, 2018	May 31, 2017	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Business Acquisition [Line Items]
Common stock, authorized (in shares)			500,000,000	500,000,000
Common stock, issued (in shares)			309,752,140	309,752,140
Common stock, outstanding (in shares)			309,005,272	309,005,272
Common stock, par value (in dollars per share)			$ 0.01	$ 0.01	$ 0.01	$ 0.01
Common stock			$ 3	$ 3
Additional paid-in capital			$ 13,660	$ 13,657
Treasury stock (in shares)			485,810
Convertible preferred stock, shares outstanding (in shares)			0	0
Issuance of common stock (in shares)			0	81,208
Release of common stock held in trust (in shares)			0	0
Treasury shares of common stock (in shares)			261,058
Repurchase of common stock (in shares)	81,208	64,019	115,831
Treasury stock			$ 12	$ 12
Dividends declared (in dollars per share)			$ 1.76	$ 1.744	$ 1.728
AVANGRID Networks
Business Acquisition [Line Items]
Common stock, authorized (in shares)			500,000,000	500,000,000
Common stock, issued (in shares)			309,752,140	309,752,140
Common stock, outstanding (in shares)			309,005,272	309,005,272
Common stock, par value (in dollars per share)			$ 0.01	$ 0.01
Common stock			$ 3	$ 3
Additional paid-in capital			$ 13,660	$ 13,657
Treasury stock (in shares)			485,810	485,810
Convertible preferred stock, shares outstanding (in shares)			0	0
Issuance of common stock (in shares)	81,208		0
Release of common stock held in trust (in shares)			0	0
Treasury shares of common stock (in shares)			261,058
Repurchase of common stock (in shares)		64,019		115,831
Treasury stock			$ 12	$ 12
Iberdrola Renewables Holding, Inc
Business Acquisition [Line Items]
Percentage of equity owned by parent			81.50%
Iberdrola Renewables Holding, Inc | AVANGRID Networks
Business Acquisition [Line Items]
Percentage of equity owned by parent			81.50%	81.50%

Condensed Financial Informati_7

Condensed Financial Information of Parent - Debt (Details) - USD ($)	May 16, 2019	Nov. 21, 2017	Dec. 31, 2016	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Dec. 19, 2016
Debt Instrument [Line Items]
Capital contribution to subsidiary by parent				$ 2,000,000	$ 0	$ 0
Non-current note issuance				2,137,000,000	597,000,000	888,000,000
AVANGRID Networks
Debt Instrument [Line Items]
Debt instrument principal amount							$ 450,000,000
Debt instrument, interest rate							4.625%
Capital contribution to subsidiary by parent			$ 483,000,000
Non-current note issuance				1,243,000,000	$ 0	$ 594,000,000
AVANGRID Networks | 3.150% Notes due 2024
Debt Instrument [Line Items]
Debt instrument principal amount		$ 600,000,000
Debt instrument, interest rate		3.15%
Non-current note issuance		$ 594,000,000
AVANGRID Networks | 3.800% Notes due 2029
Debt Instrument [Line Items]
Debt instrument principal amount	$ 750,000,000
Debt instrument, interest rate	3.80%
Non-current note issuance	$ 743,000,000
Term Loan Credit
Debt Instrument [Line Items]
Debt instrument principal amount				$ 500,000,000
London Interbank Offered Rate (LIBOR) | Term Loan Credit
Debt Instrument [Line Items]
Debt instrument, basis spread on variable rate				2.40%

Condensed Financial Informati_8

Condensed Financial Information of Parent - Cash Dividends Paid by Subsidiaries (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
AVANGRID Networks
Cash Dividend [Line Items]
Cash dividends paid	$ 433	$ 116	$ 308

Condensed Financial Informati_9

Condensed Financial Information of Parent - Cash Dividends Paid by Subsidiaries Additional Information (Details) - USD ($) $ in Millions	1 Months Ended	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Cash Dividend [Line Items]
Capital contribution to subsidiary by parent		$ 2	$ 0	$ 0
AVANGRID Networks
Cash Dividend [Line Items]
Capital contribution to subsidiary by parent	$ 483
Non cash contribution/dividend recorded by parent company		219	1,515
AVANGRID Networks | United Illuminating Company (UI)
Cash Dividend [Line Items]
Capital contribution to subsidiary by parent		108	$ 50
AVANGRID Networks | NYSEG
Cash Dividend [Line Items]
Capital contribution to subsidiary by parent		$ 50

Uncategorized Items - agr201910

Label	Element	Value
Retained Earnings [Member]
Cumulative Effect of New Accounting Principle in Period of Adoption	us-gaap_CumulativeEffectOfNewAccountingPrincipleInPeriodOfAdoption	$ 11,000,000
Cumulative Effect of New Accounting Principle in Period of Adoption	us-gaap_CumulativeEffectOfNewAccountingPrincipleInPeriodOfAdoption	(3,000,000)
Noncontrolling Interest [Member]
Cumulative Effect of New Accounting Principle in Period of Adoption	us-gaap_CumulativeEffectOfNewAccountingPrincipleInPeriodOfAdoption	140,000,000
Parent [Member]
Cumulative Effect of New Accounting Principle in Period of Adoption	us-gaap_CumulativeEffectOfNewAccountingPrincipleInPeriodOfAdoption	(4,000,000)
Cumulative Effect of New Accounting Principle in Period of Adoption	us-gaap_CumulativeEffectOfNewAccountingPrincipleInPeriodOfAdoption	$ (1,000,000)