agr-20240930

美國

證券交易委員會

華盛頓特區20549

表格 10-Q


☒			根據1934年證券交易法第13或15(d)節的季度報告

截至季度結束日期的財務報告2024年9月30日

或者


☐			根據1934年證券交易法第13或15(d)節的轉型報告書

在過渡期內到 i

委員會文件號 001-40368001-37660

avangrid, inc。

（依據其憲章指定的註冊名稱）


紐約		14-1798693
（設立或組織的其他管轄區域）		（納稅人識別號碼）
180 Marsh Hill Road
Orange,	康涅狄格州	06477
，（主要行政辦公地址）		(郵政編碼)

公司電話號碼，包括區號：（207) 629-1190

在法案第12(b)條的規定下注冊的證券：

每個課程的標題

交易符號

註冊的交易所名稱

普通股，面值每股0.01美元

AGR

紐約證券交易所

請在檢查標記處註明註冊人（1）是否已在證券交易法第13或15（d）條所規定的過去12個月（或註冊人需要提交此類報告的較短期間）內提交了所有必須提交的報告，並且（2）自過去90天以來一直受到此類提交要求的限制。是 ☒ 否 ☐

請勾選是否在前12個月（或註冊人被要求提交這些文件的較短期間）的交互式數據文件的每個文件都是根據本章節規則405和s-t法規（§232.405）要求提交的。是 ☒ 否 ☐

勾選適用的選項，表示公司是否屬於大型加速報告公司、加速報告公司、非加速報告公司、較小的報告公司或新興成長公司。詳見交易所法案第120億.2條，有關「大型加速報告公司」、「加速報告公司」、「較小的報告公司」和「新興成長公司」的定義。

大型加速存取器

☒

快速提交者

☐

非加速申報人

☐

較小的報告公司

☐

新興成長公司

☐

如果是新興成長型企業，請勾選此項，表示註冊者已選擇不使用根據《交易所法》第13(a)條提供的任何新的或修訂後的財務會計準則的延長過渡期進行遵守。☐

請打勾表明註冊人是否爲殼公司（根據證券交易法規則12b-2定義）。是☐ 否 ☒

截至2024年10月22日，登記者持有386,911,024 普通股股票，面值0.01美元，流通股。

avangrid, inc。

有關第10-Q表格的報告書

截至2024年9月30日季度結束

指數


術語和縮寫詞彙表		3
第一部分財務信息		4
第 1 項。	財務報表	4
第 2 項。	管理層對財務狀況和經營業績的討論和分析	50
第 3 項。	關於市場風險的定量和定性披露	69
第 4 項。	控制和程序	69
第二部分。其他信息		70
第 1 項。	法律訴訟	70
第 1A 項。	風險因素	70
第 2 項。	未註冊的股權證券銷售和所得款項的使用	70
第 3 項。	優先證券違約	70
第 4 項。	礦山安全披露	70
第 5 項。	其他信息	70
第 6 項。	展品	70
簽名		71

術語和縮略語詞彙表

除非上下文另有指示，「我們」、「我們的」和「公司」這些術語均指艾萬格公司及其子公司。


2023年聯合提案						紐約州公共服務委員會於2023年10月12日批准的NYSEG和RG&E以及其他簽署方的聯合提案，涉及爲電力和燃料幣服務制定爲期三年的價格計劃，生效日期爲2023年11月1日。
未實現其他綜合收益						累計其他綜合收益
ARHI						阿萬格瑞可再生能源控股有限公司
ARP						替代營收計劃
ASC						會計準則編碼
avangrid						avangrid, inc。
BGC						伯克希爾燃氣公司
BSEE						美國安全與環保執法局
PBR						基於績效的監管
CAIDI						客戶平均中斷持續時間指數
價差合約						差價合約
CBP						美國海關和邊境保護局
中康和光電						康潤能源
交易所						中緬電力公司
天然氣						康潤能源公司
深水						康潤能源和環保部門
DIMP						分銷完整性管理計劃
DOC						商務部
《國防生產法》（DPA）						遞延付款安排
DPU						馬薩諸塞州公用事業部
EBITDA						利息、稅項、折舊和攤銷前收益
esm						收益分享機制
英格蘭站						康涅狄格州紐黑文Mill River的前一代工地
使擁有公司註冊證券類別10%以上股權的官員、董事或實際股東代表簽署人遞交表格3、4和5（包括修正版及有關聯合遞交協議）,符合證券交易法案第16(a)條及其下屬規則規定的要求；						根據修訂後的1934年證券交易法
FASB						財務會計準則委員會
FCC						Federal Communications Commission
聯邦能源監管機構（FERC）						聯邦能源監管委員會
第一能源						第一能源股份有限公司。
10-K表格						Avangrid, Inc.’s Annual Report on Form 10-k for the year ended December 31, 2023, filed with the Securities and Exchange Commission on February 22, 2024.
諧波受限通量矢量						帳面價值假設清算
HSR						Hart-Scott-Rodino Antitrust Improvements Act of 1976
IRA						通貨膨脹削減法案
伊比利半島						伊比利亞公司
伊比利半島集團						由伊比利半島控制的公司集團
已裝機容量						電廠或風力發電廠的生產能力，基於額定（銘牌）容量或實際容量
將股權獎勵視爲「激勵股票期權（ISO）」（incentive stock option）的期權。						獨立系統運營商
克拉馬斯發電廠						克拉馬斯燃氣供熱聯合發電廠位於俄勒岡州克拉馬斯市。
德意志銀行分析師德里克·約翰斯頓將Kennedy-Wilson Holdings（紐交所：KW）的評級從持有升級爲買入，並宣佈了22美元的目標價格。						千瓦
合併						按照《併購協議》規定的條款和條件，與西班牙伊比利亞公司和Merger Sub合併，avangrid公司將繼續作爲存續公司，併成爲西班牙伊比利亞公司的全資子公司。
併購協議						《併購協議及合併計劃》，於2024年5月17日簽署，其中參與方包括avangrid公司、西班牙伊比利亞公司和Merger Sub。
合併子公司						Arizona Merger Sub, Inc., a New York corporation and wholly-owned subsidiary of Iberdrola.
MNG						Maine Natural Gas Corporation
MPUC						Maine Public Utility Commission
對沖的賬面價值變動(MtM)						市場價格調整
兆瓦						兆瓦
兆瓦時						兆瓦時
NECEC						新英格蘭清潔能源連接
網絡板塊						avangrid網絡公司
非通用會計原則						未按照美國通用會計準則準備的財務指標，包括調整後的淨利潤、調整後的每股收益、調整後的EBITDA和帶稅收抵免的調整後的EBITDA。
NRC						核監管委員會
NYPSC						紐約州公共事業委員會
NYSE						請使用moomoo賬號登錄查看New York Stock Exchange
紐交所						紐約州電力與天然氣公司
紐約州能源研究和發展局						PJM
收益						其他綜合收益
PJM互連公司						PJM互連公司
瓦爾達						康涅狄格州公用事業監管局
可再生能源						avangrid可再生能源有限責任公司
RDM						營業收入分離機制
RG&E						羅切斯特燃氣電力公司
毛利潤 (以十億計)						淨資產回報率
SAIFI						系統平均故障間隔頻率指數
SCG						南康涅狄格燃氣公司
SEC						美國證券交易委員會
SOFR						擔保隔夜融資利率
稅法						2017年12月22日，美國聯邦政府頒佈了2017年的《減稅和就業法案》
TEF						稅收公平融資安排
UI						聯合照明公司
UIL						UIL控股有限公司
非附屬委員會						Avangrid, Inc.董事會的非附屬委員會，由獨立和無利害關係的董事組成
美國通用會計準則						美國財務報告的通用會計準則。
VIEs						2019年7月31日，Cloud Chain Network and Technology (Tianjin) Co., Limited (CCM Tianjin或 WFOE，以前稱爲Chain Cloud Mall Network and Technology (Tianjin) Co., Limited)，E-commerce Tianjin和E-commerce Tianjin的股東中國公民薛澤堯先生和徐凱先生，簽訂以下協議，或統稱「變量利益實體協議」或「VIE 協議」，根據此協議，CCM Tianjin擁有控制和運營E-commerce Tianjin業務（「VIE業務」）的合同權利。因此，根據ASC 810，自那時起，E-Commerce Tianjin納入了公司的合併財務報表中。

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

Avangrid, Inc. and Subsidiaries

Condensed Consolidated Statements of Income

(unaudited)


	Three Months Ended September 30,				Nine Months Ended September 30,
	2024		2023		2024		2023
(Millions, except for number of shares and per share data)
Operating Revenues	$	2,083	$	1,974	$	6,423	$	6,027
Operating Expenses
Purchased power, natural gas and fuel used	457		482		1,610		1,844
Operations and maintenance	866		924		2,477		2,319
Depreciation and amortization	327		303		935		868
Taxes other than income taxes	179		176		539		516
Total Operating Expenses	1,829		1,885		5,561		5,547
Operating Income	254		89		862		480
Other Income and (Expense)
Other income	65		42		176		96
Earnings (Losses) from equity method investments	4		(1)		15		5
Interest expense, net of capitalization	(132)		(107)		(379)		(301)
Income Before Income Tax	191		23		674		280
Income tax expense (benefit)	19		(8)		52		(17)
Net Income	172		31		622		297
Net loss attributable to noncontrolling interests	33		28		103		92
Net Income Attributable to Avangrid, Inc.	$	205	$	59	$	725	$	389
Earnings Per Common Share, Basic	$	0.53	$	0.15	$	1.87	$	1.00
Earnings Per Common Share, Diluted	$	0.53	$	0.15	$	1.87	$	1.00
Weighted-average Number of Common Shares Outstanding:
Basic	387,010,149		386,869,341		386,978,958		386,788,279
Diluted	387,434,841		387,322,281		387,322,300		387,122,498

The accompanying notes are an integral part of our condensed consolidated financial statements.

Avangrid, Inc. and Subsidiaries

Condensed Consolidated Statements of Comprehensive Income

(unaudited)


	Three Months Ended September 30,				Nine Months Ended September 30,
	2024		2023		2024		2023
(Millions)
Net Income	$	172	$	31	$	622	$	297
Other Comprehensive Income (Loss)

Amortization of pension cost, net of income tax of $0 and $0 for the three months ended, respectively, and $0 and $1 for the nine months ended, respectively	—		—		1		2
Unrealized (loss) gain from equity method investment, net of income taxes of $0 and $0 for the three months ended, respectively, and $(1) and $1 for the nine months ended, respectively	—		(1)		(2)		4
Unrealized (loss) gain during the period on derivatives qualifying as cash flow hedges, net of income taxes of $(6) and $11 for the three months ended, respectively, and $11 and $22 for the nine months ended, respectively	(17)		30		29		62
Reclassification to net income of losses on cash flow hedges, net of income taxes $7 and $15 for the three months ended, respectively, and $10 and $39 for the nine months ended, respectively	20		40		28		107
Other Comprehensive Income	3		69		56		175
Comprehensive Income	175		100		678		472
Net loss attributable to noncontrolling interests	33		28		103		92
Comprehensive Income Attributable to Avangrid, Inc.	$	208	$	128	$	781	$	564

The accompanying notes are an integral part of our condensed consolidated financial statements.

Avangrid, Inc. and Subsidiaries

Condensed Consolidated Balance Sheets

(unaudited)


	September 30,		December 31,
As of	2024		2023
(Millions)
Assets
Current Assets
Cash and cash equivalents	$	148	$	91
Accounts receivable and unbilled revenues, net	1,352		1,588
Accounts receivable from affiliates	6		11
Notes receivable from affiliates	4		4
Derivative assets	83		68
Fuel and gas in storage	187		185
Materials and supplies	344		310
Prepayments and other current assets	628		492
Regulatory assets	914		718
Total Current Assets	3,666		3,467
Total Property, Plant and Equipment ($2,576 and $2,643 related to VIEs, respectively)	34,683		32,794
Operating lease right-of-use assets	206		195
Equity method investments	1,060		718
Other investments	52		46
Regulatory assets	3,150		2,811
Other Assets
Goodwill	3,119		3,119
Intangible assets	271		284
Derivative assets	171		162
Other	355		393
Total Other Assets	3,916		3,958
Total Assets	$	46,733	$	43,989

The accompanying notes are an integral part of our condensed consolidated financial statements.

Avangrid, Inc. and Subsidiaries

Condensed Consolidated Balance Sheets

(unaudited)


	September 30,		December 31,
As of	2024		2023
(Millions, except share information)
Liabilities
Current Liabilities
Current portion of debt	$	1,620	$	612
Notes payable	2,225		1,347
Notes payable to affiliates	8		13
Interest accrued	131		104
Accounts payable and accrued liabilities	1,752		1,924
Accounts payable to affiliates	56		—
Dividends payable	341		170
Taxes accrued	110		66
Operating lease liabilities	15		16
Derivative liabilities	42		64
Other current liabilities	683		662
Regulatory liabilities	156		261
Total Current Liabilities	7,139		5,239
Regulatory liabilities	2,636		2,694
Other Non-current Liabilities
Deferred income taxes	2,544		2,451
Deferred income	981		996
Pension and other postretirement	508		554
Operating lease liabilities	210		199
Derivative liabilities	78		111
Asset retirement obligations	326		306
Environmental remediation costs	249		254
Other	533		525
Total Other Non-current Liabilities	5,429		5,396
Non-current debt	8,839		9,184
Non-current debt to affiliate	2,000		800
Total Non-current Liabilities	18,904		18,074
Total Liabilities	26,043		23,313
Commitments and Contingencies
Equity
Stockholders’ Equity:
Common stock, $.01 par value, 500,000,000 shares authorized, 388,008,132 and 387,872,787 shares issued; 386,911,024 and 386,770,915 shares outstanding, respectively	4		4
Additional paid in capital	17,708		17,701
Treasury stock	(47)		(47)
Retained earnings	2,059		2,015
Accumulated other comprehensive income (loss)	31		(25)
Total Stockholders’ Equity	19,755		19,648
Non-controlling interests	935		1,028
Total Equity	20,690		20,676
Total Liabilities and Equity	$	46,733	$	43,989

The accompanying notes are an integral part of our condensed consolidated financial statements.

Avangrid, Inc. and Subsidiaries

Condensed Consolidated Statements of Cash Flows

(unaudited)


	Nine Months Ended September 30,
	2024		2023
(Millions)
Cash Flow from Operating Activities:
Net income	$	622	$	297
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	935		868
Regulatory assets/liabilities amortization and carrying cost	29		(48)
Pension cost	(7)		(11)
Earnings from equity method investments	(15)		(5)
Distributions of earnings received from equity method investments	14		21
Unrealized (gain) loss on marked-to-market derivative contracts	(18)		19
Deferred taxes	31		53
Other non-cash items	(107)		(49)
Changes in operating assets and liabilities:
Current assets	(118)		170
Noncurrent assets	(338)		(107)
Current liabilities	131		(408)
Noncurrent liabilities	(219)		(43)
Net Cash Provided by Operating Activities	940		757
Cash Flow from Investing Activities:
Capital expenditures	(2,854)		(2,078)
Contributions in aid of construction	100		101
Proceeds from sale of assets	6		48

Distributions received from equity method investments	4		4
Other investments and equity method investments, net	(338)		(99)
Net Cash Used in Investing Activities	(3,082)		(2,024)
Cash Flow from Financing Activities:
Non-current debt issuances	655		842
Non-current debt issuance with affiliate	1,200		800
Repayments of non-current debt	(15)		(303)
Receipts of other short-term debt, net	873		390
Repayment of short-term debt with affiliates	(6)		—
Repayments of financing leases	(6)		(3)

Issuance of common stock	(2)		(3)
Distributions to noncontrolling interests	(51)		(13)
Contributions from noncontrolling interests	61		79
Dividends paid	(510)		(510)
Net Cash Provided by Financing Activities	2,199		1,279
Net Increase in Cash, Cash Equivalents and Restricted Cash	57		12
Cash, Cash Equivalents and Restricted Cash, Beginning of Period	94		72
Cash, Cash Equivalents and Restricted Cash, End of Period	$	151	$	84
Supplemental Cash Flow Information
Cash paid for interest, net of amounts capitalized	$	285	$	217
Cash paid for income taxes, net of transferred tax credits (Note 16)	$	20	$	(30)

The accompanying notes are an integral part of our condensed consolidated financial statements.

Avangrid, Inc. and Subsidiaries

Condensed Consolidated Statements of Changes in Equity

(unaudited)



(Millions, except for number of shares )	Number of shares (*)	Common Stock		Additional paid-in capital		Treasury Stock		Retained Earnings		Accumulated Other Comprehensive (Loss) Income		Total Stockholders’ Equity		Noncontrolling Interests		Total
As of June 30, 2023	386,645,258	$	3	$	17,695	$	(47)	$	1,900	$	(74)	$	19,477	$	966	$	20,443

Net income (loss)	—	—		—		—		59		—		59		(28)		31
Other comprehensive income, net of tax of $26	—	—		—		—		—		69		69		—		69
Comprehensive income																100
Dividends declared, $0.44/share	—	—		—		—		(170)		—		(170)		—		(170)

Issuance of common stock	125,657	—		—		—		—		—		—		—		—

Stock-based compensation	—	—		4		—		—		—		4		—		4
Distributions to noncontrolling interests	—	—		—		—		—		—		—		(6)		(6)
Contributions from noncontrolling interests	—	—		—		—		—		—		—		4		4
As of September 30, 2023	386,770,915	$	3	$	17,699	$	(47)	$	1,789	$	(5)	$	19,439	$	936	$	20,375
As of June 30, 2024	386,911,024	$	4	$	17,705	$	(47)	$	2,195	$	28	$	19,885	$	966	$	20,851

Net income (loss)	—	—		—		—		205		—		205		(33)		172
Other comprehensive income, net of tax of $1	—	—		—		—		—		3		3		—		3
Comprehensive income																175
Dividends declared, $0.44/share	—	—		—		—		(341)		—		(341)		—		(341)
Release of common stock held in trust	—	—		—		—		—		—		—		—		—
Issuance of common stock	—	—		—		—		—		—		—		—		—

Stock-based compensation	—	—		3		—		—		—		3		—		3
Distributions to noncontrolling interests	—	—		—		—		—		—		—		(3)		(3)
Contributions from noncontrolling interests	—	—		—		—		—		—		—		5		5
As of September 30, 2024	386,911,024	$	4	$	17,708	$	(47)	$	2,059	$	31	$	19,755	$	935	$	20,690



(Millions, except for number of shares )	Number of shares (*)	Common Stock		Additional paid-in capital		Treasury Stock		Retained Earnings		Accumulated Other Comprehensive (Loss)Income		Total Stockholders’ Equity		Noncontrolling Interests		Total
As of December 31, 2022	386,628,586	$	3	$	17,694	$	(47)	$	1,910	$	(180)	$	19,380	$	962	$	20,342

Net income (loss)	—	—		—		—		389		—		389		(92)		297
Other comprehensive income, net of tax of $63	—	—		—		—		—		175		175		—		175
Comprehensive income																472
Dividends declared, $1.32/share	—	—		—		—		(510)		—		(510)		—		(510)
Release of common stock held in trust	4,299	—		—		—		—		—		—		—		—
Issuance of common stock	138,030	—		(4)		—		—		—		(4)		—		(4)

Stock-based compensation	—	—		9		—		—		—		9		—		9
Distributions to noncontrolling interests	—	—		—		—		—		—		—		(13)		(13)
Contributions from noncontrolling interests	—	—		—		—				—		—		79		79
As of September 30, 2023	386,770,915	$	3	$	17,699	$	(47)	$	1,789	$	(5)	$	19,439	$	936	$	20,375
As of December 31, 2023	386,770,915	$	4	$	17,701	$	(47)	$	2,015	$	(25)	$	19,648	$	1,028	$	20,676

Net income (loss)	—	—		—		—		725		—		725		(103)		622
Other comprehensive income, net of tax of $20	—	—		—		—		—		56		56		—		56
Comprehensive income																678
Dividends declared, $1.32/share	—	—		—		—		(681)		—		(681)		—		(681)
Release of common stock held in trust	4,764	—		—		—		—		—		—		—		—
Issuance of common stock	135,345	—		(2)		—		—		—		(2)		—		(2)

Stock-based compensation	—	—		9		—		—		—		9		—		9
Distributions to noncontrolling interests	—	—		—		—		—		—		—		(51)		(51)
Contributions from noncontrolling interests	—	—		—		—				—		—		61		61
As of September 30, 2024	386,911,024	$	4	$	17,708	$	(47)	$	2,059	$	31	$	19,755	$	935	$	20,690

(*) Par value of share amounts is $0.01

The accompanying notes are an integral part of our condensed consolidated financial statements.

Avangrid, Inc. and Subsidiaries

Notes to Condensed Consolidated Financial Statements

(unaudited)

Note 1. Background and Nature of Operations

Avangrid, Inc. (Avangrid, we or the Company) is an energy services holding company engaged in the regulated energy transmission and distribution business through its principal subsidiary, Avangrid Networks, Inc. (Networks), and in the renewable energy generation business through its principal subsidiary, Avangrid Renewables Holding, Inc. (ARHI). ARHI in turn holds subsidiaries including Avangrid Renewables, LLC (Renewables). Iberdrola, S.A. (Iberdrola), a corporation organized under the laws of the Kingdom of Spain, owns 81.6% of the outstanding common stock of Avangrid. The remaining outstanding shares are owned by various shareholders, with approximately 14.7% of Avangrid's outstanding shares publicly traded on the New York Stock Exchange (NYSE).

Agreement and Plan of Merger

On May 17, 2024, Avangrid entered into an Agreement and Plan of Merger (the Merger Agreement) with Iberdrola and Arizona Merger Sub, Inc (Merger Sub). The Merger Agreement provides that, upon the terms and subject to the satisfaction or waiver of the conditions set forth therein, Merger Sub will merge with and into Avangrid (the Merger), with Avangrid continuing as the surviving corporation and a wholly-owned subsidiary of Iberdrola.

Pursuant to the terms of the Merger Agreement, at the time at which the Merger becomes effective (the Effective Time), as a result of the Merger, each share of common stock of Avangrid issued and outstanding immediately prior to the Effective Time (other than shares of common stock owned by Iberdrola, Merger Sub or any other direct or indirect wholly-owned subsidiary of Iberdrola and shares of common stock owned by Avangrid or any direct or indirect wholly-owned subsidiary of Avangrid, and in each case not held on behalf of third parties will be converted into the right to receive $35.75 in cash per share, without interest. At the Effective Time, all of the shares of common stock of Avangrid will be cancelled and will cease to exist. In addition, under the terms of the Merger Agreement, Avangrid is permitted to continue paying regular quarterly cash dividends not to exceed $0.44 per share through the closing of the Merger, including a pro-rated dividend for any partial quarter prior to the closing of the Merger.

The consummation of the Merger is subject to customary closing conditions, including, among others, requisite shareholder approval and receipt of certain required regulatory approvals (including approvals from the Federal Energy Regulatory Commission (FERC), the Maine Public Utilities Commission (MPUC) and the New York Public Service Commission (NYPSC)). The Merger Agreement contains certain termination rights for each of Avangrid and Iberdrola. In addition, Avangrid, upon the recommendation of the Unaffiliated Committee, and Iberdrola may terminate the Merger Agreement if the Merger is not consummated on or before June 30, 2025, subject to one three-month extension, exercisable by either Iberdrola or Avangrid, upon the recommendation of the Unaffiliated Committee, in the event that all conditions to closing have been satisfied except for those related to the approval of FERC, MPUC and NYPSC.

Avangrid previously announced in the third quarter of 2024 that it had received FERC approval of the Merger, that the MPUC granted Avangrid’s request for exemption from the approval requirements set forth in Maine law and that the Avangrid shareholders voted in favor of the Merger at Avangrid’s 2024 annual meeting of shareholders. The consummation of the Merger remains subject to the satisfaction of other closing conditions, including receipt of the approval of the NYPSC.

In addition, on September 16, 2024, the Connecticut Attorney General and Consumer Counsel filed a petition with the Connecticut Public Utilities Regulatory Authority (PURA) seeking PURA review of the Merger because it constitutes a “change in control”. On October 17, 2024, PURA issued a Notice of Proceeding providing that PURA will consider the petition in two phases. The initial phase will address the threshold question of whether the Merger is subject to PURA review under Connecticut law and, if PURA finds in the affirmative, PURA will conduct further proceedings in a second phase to review the Merger in accordance with applicable Connecticut law. We cannot predict the outcome of this proceeding or any impact it may have on the consummation of the Merger.

Note 2. Basis of Presentation

The accompanying condensed consolidated financial statements should be read in conjunction with the Form 10-K for the fiscal year ended December 31, 2023.

The accompanying unaudited financial statements are prepared on a consolidated basis and include the accounts of Avangrid and its consolidated subsidiaries, Networks and ARHI. All intercompany transactions and accounts have been eliminated in consolidation. The year-end balance sheet data was derived from audited financial statements. The unaudited condensed consolidated financial statements for the interim periods have been prepared in accordance with accounting principles generally

accepted in the United States of America (U.S. GAAP) for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X. Accordingly, the interim condensed consolidated financial statements do not include all the information and note disclosures required by U.S. GAAP for complete financial statements.

In the opinion of management, the accompanying condensed consolidated financial statements contain all adjustments necessary to present fairly our condensed consolidated financial statements for the interim periods described herein. All such adjustments are of a normal and recurring nature, except as otherwise disclosed. The results for the three and nine months ended September 30, 2024, are not necessarily indicative of the results for the entire fiscal year ending December 31, 2024.

Note 3. Significant Accounting Policies and New Accounting Pronouncements

The new accounting pronouncements we have adopted as of January 1, 2024, and reflected in our condensed consolidated financial statements are described below. There have been no other material changes to the significant accounting policies described in our Form 10-K for the fiscal year ended December 31, 2023, except for those described below resulting from the adoption of new authoritative accounting guidance issued by the Financial Accounting Standards Board (FASB).

Adoption of New Accounting Pronouncements

(a) Improvements to Reportable Segment Disclosures

In November 2023, the FASB issued guidance requiring incremental disclosures for reportable segments. These incremental requirements include disclosing significant expenses that are regularly provided to the chief operating decision maker (CODM) and other segment items, including a description of its composition. The other segment items category is the difference between segment revenue less the significant segment expenses, and each reported measure of segment profit or loss. The guidance clarifies that if the CODM reviews multiple measures of a segments total profit or loss, that the entity may under certain conditions report multiple measures in the segment footnote; however, if only one measure is reported, it should be the one that best conforms with U.S. GAAP. The guidance requires disclosure of the title and position of the individual or the name of the group identified as the CODM. Finally, all annual disclosures are required in interim reporting starting in the first quarter of 2025. As the guidance impacts disclosures only, it will not have an impact to the consolidated financial results. These changes in disclosures will initially be reflected in the annual financial statement footnotes for the year ended December 31, 2024.

Accounting Pronouncements Issued but Not Yet Adopted

The following are new significant accounting pronouncements not yet adopted, including those issued since December 31, 2023, that we have evaluated or are evaluating to determine their effect on our condensed consolidated financial statements.

(a) Improvements to Income Tax Disclosures

In December 2023, the FASB issued guidance to enhance income tax disclosures. The standard is required to be adopted by public business entities for annual periods beginning after December 15, 2024. Early adoption is permitted. The two primary enhancements relate to disaggregation of the annual effective tax rate reconciliation and income taxes paid disclosures. For the rate reconciliation, it requires additional disaggregation of information in a tabular format using both percentages and amounts broken out into specific categories (e.g., state and local income tax net of federal income tax effect, foreign tax effects, effect of changes in tax laws, tax credits, changes in valuation allowances, nontaxable or nondeductible items, and changes in unrecognized tax benefits). For income taxes paid, it requires disaggregation by jurisdiction (e.g., federal, state and foreign). We do not expect the new guidance to have a material impact on our consolidated results of operations, financial position and cash flows.

Note 4. Revenue

We recognize revenue when we have satisfied our obligations under the terms of a contract with a customer, which generally occurs when the control of promised goods or services transfers to the customer. We measure revenue as the amount of consideration we expect to receive in exchange for providing those goods or services. Contracts with customers may include multiple performance obligations. For such contracts, we allocate revenue to each performance obligation based on its relative standalone selling price. We generally determine standalone selling prices based on the prices charged to customers. Certain revenues are not within the scope of the FASB issued ASC Topic 606, Revenue from Contracts with Customers (ASC 606), such as revenues from leasing, derivatives, other revenues that are not from contracts with customers and other contractual rights or obligations, and we account for such revenues in accordance with the applicable accounting standards. We exclude from revenue amounts collected on behalf of third parties, including any such taxes collected from customers and remitted to governmental authorities. We do not have any significant payment terms that are material because we receive payment at or shortly after the point of sale.

The following describes the principal activities, by reportable segment, from which we generate revenue. For more detailed information about our reportable segments, refer to Note 13.

Networks Segment

Networks derives its revenue primarily from tariff-based sales of electricity and natural gas service to customers in New York, Connecticut, Maine and Massachusetts with no defined contractual term. For such revenues, we recognize revenues in an amount derived from the commodities delivered to customers. Other major sources of revenue are electricity transmission and wholesale sales of electricity and natural gas.

Tariff-based sales are subject to the corresponding state regulatory authorities, which determine prices and other terms of service through the ratemaking process. The applicable tariffs are based on the cost of providing service. The utilities’ approved base rates are designed to recover their allowable operating costs, including energy costs, finance costs, and the costs of equity, the last of which reflect our capital ratio and a reasonable return on equity. We traditionally invoice our customers by applying approved base rates to usage. Maine state law prohibits the utility from providing the electricity commodity to customers. In New York, Connecticut and Massachusetts, customers have the option to obtain the electricity or natural gas commodity directly from the utility or from another supplier. For customers that receive their commodity from another supplier, the utility acts as an agent and delivers the electricity or natural gas provided by that supplier. Revenue in those cases is only for providing the service of delivery of the commodity. Networks entities calculate revenue earned but not yet billed based on the number of days not billed in the month, the estimated amount of energy delivered during those days and the estimated average price per customer class for that month. Differences between actual and estimated unbilled revenue are immaterial.

Transmission revenue results from others’ use of the utility’s transmission system to transmit electricity and is subject to FERC regulation, which establishes the prices and other terms of service. Long-term wholesale sales of electricity are based on individual bilateral contracts. Short-term wholesale sales of electricity are generally on a daily basis based on market prices and are administered by the Independent System Operator-New England (ISO-NE) and the New York Independent System Operator (NYISO) or PJM Interconnection, L.L.C. (PJM), as applicable. Wholesale sales of natural gas are generally short-term based on market prices through contracts with the specific customer.

The performance obligation in all arrangements is satisfied over time because the customer simultaneously receives and consumes the benefits as Networks delivers or sells the electricity or natural gas or provides the delivery or transmission service. We record revenue for all of such sales based upon the regulatory-approved tariff and the volume delivered or transmitted, which corresponds to the amount that we have a right to invoice. There are no material initial incremental costs of obtaining a contract in any of the arrangements. Networks does not adjust the promised consideration for the effects of a significant financing component if it expects, at contract inception, that the time between the delivery of promised goods or service and customer payment will be one year or less. For its New York and Connecticut utilities, Networks assesses its Deferred Payment Arrangements (DPAs) at each balance sheet date for the existence of significant financing components, but has had no material adjustments as a result.

Certain Networks entities record revenue from Alternative Revenue Programs (ARPs), which is not ASC 606 revenue. Such programs represent contracts between the utilities and their regulators. The Networks ARPs include revenue decoupling mechanisms (RDMs), other ratemaking mechanisms, annual revenue requirement reconciliations and other demand side management programs. The Networks entities recognize and record only the initial recognition of “originating” ARP revenues (when the regulatory-specified conditions for recognition have been met). When they subsequently include those amounts in the price of utility service billed to customers, they record such amounts as a recovery of the associated regulatory asset or liability. When they owe amounts to customers in connection with ARPs, they evaluate those amounts on a quarterly basis and include them in the price of utility service billed to customers and do not reduce ARP revenues.

Networks also has various other sources of revenue including billing, collection, other administrative charges, sundry billings, rent of utility property and miscellaneous revenue. It classifies such revenues as other ASC 606 revenues to the extent they are not related to revenue generating activities from leasing, derivatives or ARPs.

Renewables Segment

Renewables derives its revenue primarily from the sale of energy, transmission, capacity and other related charges from its renewable wind, solar and thermal energy generating sources. For such revenues, we will recognize revenues in an amount derived from the commodities delivered and from services as they are made available. Renewables has bundled power purchase agreements consisting of electric energy, transmission, capacity and/or renewable energy credits (RECs). The related contracts are generally long-term with no stated contract amount, that is, the customer is entitled to all or a percentage of the unit’s output. Renewables also has unbundled sales of electric energy and capacity, RECs and natural gas, which are generally for periods of less than a year. The performance obligations in substantially all of both bundled and unbundled arrangements for

electricity and natural gas are satisfied over time, for which we record revenue based on the amount invoiced to the customer for the actual energy delivered. The performance obligation for stand-alone RECs is satisfied at a point in time, for which we record revenue when the performance obligation is satisfied upon delivery of the REC. There are no significant financing elements in any of the arrangements. We recognize an asset for incremental costs of obtaining a contract with a customer when we expect the benefit of those costs to be longer than one year.

Renewables classifies certain contracts for the sale of electricity as derivatives, in accordance with the applicable accounting standards. Renewables also has revenue from its energy trading operations, which it generally classifies as derivative revenue. However, trading contracts not classified as derivatives are within the scope of ASC 606, with the performance obligation of the delivery of energy (electricity, natural gas) and settlement of the contracts satisfied at a point in time at which time we recognize the revenue. Renewables also has other ASC 606 revenue, which we recognize based on the amount invoiced to the customer.

Certain customers may receive cash credits, which we account for as variable consideration. Renewables estimates those amounts based on the expected amount to be provided to customers and reduces revenues recognized. We believe that there will not be significant changes to our estimates of variable consideration.

Other

Other, which does not represent a segment, includes miscellaneous Corporate revenues and intersegment eliminations.

Contract Cost Assets and Liabilities

We have contract cost assets for costs from development success fees and construction delays, which were paid during solar farm assets development periods. The contract cost assets are amortized ratably into expense over the 16 - 21 year life of the respective power purchase agreements (PPAs). Contract cost assets totaled $19 million and $9 million at September 30, 2024 and December 31, 2023, respectively, and are presented in "Other non-current assets" on our condensed consolidated balance sheets.

We have contract liabilities for revenue from transmission congestion contract (TCC) auctions, for which we receive payment at the beginning of an auction period, and amortize ratably each month into revenue over the applicable auction period. The auction periods range from six months to two years. TCC contract liabilities totaled $5 million and $18 million at September 30, 2024 and December 31, 2023, respectively, and are presented in "Other current liabilities" on our condensed consolidated balance sheets. We recognized $4 million and $18 million as revenue related to contract liabilities for the three and nine months ended September 30, 2024, respectively, and $8 million and $36 million for the three and nine months ended September 30, 2023, respectively.

We apply a practical expedient to expense as incurred costs to obtain a contract when the amortization period is one year or less. We record costs incurred to obtain a contract within operating expenses, including amortization of capitalized costs.

Disaggregated revenues

Revenues disaggregated by major source for our reportable segments for the three and nine months ended September 30, 2024 and 2023 are as follows:


	Three Months Ended September 30, 2024								Nine Months Ended September 30, 2024
	Networks		Renewables		Other (b)		Total		Networks		Renewables		Other (b)		Total
(Millions)
Regulated operations – electricity	$	1,417	$	—	$	—	$	1,417	$	3,968	$	—	$	—	$	3,968
Regulated operations – natural gas	199		—		—		199		1,089		—		—		1,089
Nonregulated operations – wind	—		207		—		207		—		689		—		689
Nonregulated operations – solar	—		18		—		18		—		42		—		42
Nonregulated operations – thermal	—		51		—		51		—		158		—		158
Other(a)	34		1		(1)		34		80		(20)		(3)		57
Revenue from contracts with customers	1,650		277		(1)		1,926		5,137		869		(3)		6,003
Leasing revenue	2		—		—		2		6		—		—		6
Derivative revenue	—		136		—		136		—		270		—		270
Alternative revenue programs	15		—		—		15		111		—		—		111
Other revenue	4		—		—		4		25		8		—		33
Total operating revenues	$	1,671	$	413	$	(1)	$	2,083	$	5,279	$	1,147	$	(3)	$	6,423


	Three Months Ended September 30, 2023								Nine Months Ended September 30, 2023
	Networks		Renewables		Other (b)		Total		Networks		Renewables		Other (b)		Total
(Millions)
Regulated operations – electricity	$	1,341	$	—	$	—	$	1,341	$	3,602	$	—	$	—	$	3,602
Regulated operations – natural gas	185		—		—		185		1,158		—		—		1,158
Nonregulated operations – wind	—		206		—		206		—		638		—		638
Nonregulated operations – solar	—		19		—		19		—		40		—		40
Nonregulated operations – thermal	—		69		—		69		—		125		—		125
Other(a)	27		(27)		—		—		46		(54)		—		(8)
Revenue from contracts with customers	1,553		267		—		1,820		4,806		749		—		5,555
Leasing revenue	4		—		—		4		10		—		—		10
Derivative revenue	—		121		—		121		—		335		—		335
Alternative revenue programs	20		—		—		20		90		—		—		90
Other revenue	10		(1)		—		9		30		8		(1)		37
Total operating revenues	$	1,587	$	387	$	—	$	1,974	$	4,936	$	1,092	$	(1)	$	6,027

(a) Primarily includes certain intra-month trading activities, billing, collection and administrative charges, sundry billings and other miscellaneous revenue.

(b) Does not represent a segment. Includes Corporate and intersegment eliminations.

As of September 30, 2024 and December 31, 2023, accounts receivable balances related to contracts with customers were approximately $1,267 million and $1,441 million, respectively, including unbilled revenues of $278 million and $426 million, which are included in “Accounts receivable and unbilled revenues, net” on our condensed consolidated balance sheets.

As of September 30, 2024, the aggregate amount of the transaction price allocated to performance obligations that are unsatisfied (or partially unsatisfied) were as follows:


As of September 30, 2024	2025		2026		2027		2028		2029		Thereafter		Total
(Millions)

Revenue expected to be recognized on multiyear capacity and carbon-free energy sale contracts	42		22		7		5		5		49		130
Revenue expected to be recognized on multiyear renewable energy credit sale contracts	76		55		33		11		1		1		177
Total operating revenues	$	118	$	77	$	40	$	16	$	6	$	50	$	307

As of September 30, 2024, the aggregate amount of the transaction price allocated to performance obligations that are unsatisfied (or partially unsatisfied) for the remainder of 2024 was $19 million.

We do not disclose information about remaining performance obligations for contracts for which we recognize revenue in the amount to which we have the right to invoice (e.g., usage-based pricing terms).

Note 5. Regulatory Assets and Liabilities

Pursuant to the requirements concerning accounting for regulated operations, our utilities capitalize, as regulatory assets, incurred and accrued costs that are probable of recovery in future electric and natural gas rates. We base our assessment of whether recovery is probable on the existence of regulatory orders that allow for recovery of certain costs over a specific period, or allow for reconciliation or deferral of certain costs. When costs are not treated in a specific regulatory order, we use regulatory precedent to determine if recovery is probable. Our operating utilities also record, as regulatory liabilities, obligations to refund previously collected revenue or to spend revenue collected from customers on future costs. The primary items that are not included in rate base or accruing carrying costs are regulatory assets for qualified pension and other postretirement benefits, which reflect unrecognized actuarial gains and losses; debt premium; environmental remediation costs, which are primarily the offset of accrued liabilities for future spending; unfunded future income taxes, which are the offset to the unfunded future deferred income tax liability recorded; asset retirement obligations; hedge losses; and contracts for differences. As of September 30, 2024, the total net amount of these items is approximately $1,147 million.

CMP Distribution Rate Case

On August 11, 2022, CMP filed a three-year rate plan, with adjustments to the distribution revenue requirement in each year. On June 6, 2023, the MPUC approved a Stipulation resolving all issues in the case providing for a 9.35% ROE, 50% equity ratio, and 50% earnings sharing for annual earnings in excess of 100 basis points of CMP’s allowed ROE. The Stipulation also provides for a two-year forward looking rate plan with increases to occur in four equal levelized amounts every six months beginning on July 1, 2023. An increase occurred on January 1, 2024 and July 1, 2024. The last increase will occur on January 1, 2025. The amount of each increase is $16.75 million. These revenue increases include amounts for operations and maintenance but are primarily driven by increases in capital investment forecasted by CMP to occur during the period covered by the Stipulation. The Stipulation also imposes a service quality indicator incentive mechanism on CMP. The incentive is provided by a penalty mechanism that would impose a maximum of $8.8 million per year for a failure to meet specified service quality indicator targets.

NYSEG and RG&E Rate Plans

On June 14, 2023, NYSEG and RG&E filed a Joint Proposal (2023 JP) settlement for a three-year rate plan with the NYPSC. For purposes of the 2023 JP, the three rate years are defined as the 12 months ending April 30, 2024 (New York Rate Year 1); April 30, 2025 (New York Rate Year 2); and April 30, 2026 (New York Rate Year 3); respectively. On October 12, 2023, the NYPSC approved the 2023 JP, commencing May 1, 2023 and continuing through April 30, 2026. The effective date of new tariffs was November 1, 2023 with a make-whole provision back to May 1, 2023.

The 2023 JP, as approved, includes levelization across the three years of the rate plan for delivery rates for NYSEG's and RG&E’s Electric and Gas businesses with an allowed rate of return on common equity for NYSEG Electric, NYSEG Gas, RG&E Electric and RG&E Gas of 9.20%. The common equity ratio for each business is 48.00%.

The 2023 JP also includes an Earnings Sharing Mechanism (ESM) applicable to each business that varies based on the earned ROE with 100% of the customers’ portion of earnings above the sharing threshold that would otherwise be deferred for the benefit of customers used to reduce NYSEG's and RG&E’s respective outstanding regulatory asset deferral balances. In addition, 50% of NYSEG's and RG&E’s portion will be used to reduce their respective outstanding storm-related regulatory asset deferral balances to the extent such balances exist.

The 2023 JP further enhances distribution vegetation management, maintains gas safety performance measures, establishes threshold performance levels for designated aspects of customer service quality, and includes three Electric Reliability Performance Measures (SAIFI, CAIDI, and Distribution Line Inspection Program Metric for Level II Deficiencies) with a negative revenue adjustment (NRA) beginning with calendar year 2023, if NYSEG fails to meet its annual SAIFI performance metric.

NYSEG and RG&E will continue a RAM to return or collect the remaining Customer Bill Credits established in the prior rate plan and will continue an Electric Revenue Decoupling Mechanism on a total revenue per class basis.

The 2023 JP reflects the recovery of deferred NYSEG Electric and RG&E Electric Major Storm costs of approximately $371 million and $54.6 million, respectively. NYSEG’s remaining super storm regulatory asset of $52.3 million and the non-super storm regulatory asset of $96.6 million from the 2020 Joint Proposal are being amortized over seven years. RG&E’s remaining non-super storm regulatory asset of $19.6 million established prior to the 2020 Joint Proposal is being amortized over two years. All other deferred storm costs at both NYSEG and RG&E are being amortized over 10 years. The 2023 JP gradually increases NYSEG’s and RG&E’s Major Storm rate allowances over the term of the 2023 JP to better align NYSEG’s and RG&E’s actual Major Storm costs with such rate allowances and to support NYSEG’s and RG&E’s credit metrics.

The 2023 JP contains provisions consistent with, supportive of, and in furtherance of the objectives of the Climate Leadership and Community Protection Act (CLCPA) including provisions that will, among other things, increase funding for energy efficiency programs, enhance the electric system in anticipation of increased electrification and increase funding for electric heat pump programs, provide funding for improved electric and gas reliability and resiliency, encourage non-pipe and non-wire alternatives, and replace leak prone pipe. The 2023 JP also includes support for $634 million of capital investment for CLCPA Phase 1 investments projected to be placed in-service beyond the three-year rate plan.

New York CLCPA

On February 16, 2023, the NYPSC issued an order to authorize transmission upgrades solely to support new renewable generation sources pursuant to the implementation of the Accelerated Renewable Growth and Community Benefit Act as part of the CLCPA Phase 2. The order approves an estimated $4.4 billion in transmission upgrades proposed by upstate utilities to help integrate 3,500 MW of clean energy capacity into the grid, of which NYSEG and RG&E are approved for estimated upgrade costs of $2.2 billion, including participation with other upstate utilities on certain projects. On October 17, 2023, NYSEG and RG&E filed a petition requesting approval from the NYPSC to seek authorization from the FERC, to utilize 100 percent construction work in progress (CWIP), in rate base for the local transmission upgrades under the CLCPA Phase 2. On April 18, 2024, the NYPSC approved the petition to allow NYSEG and RG&E to seek FERC approval along with adding other related reporting requirements. On July 5, 2024, FERC conditionally accepted NYSEG and RG&E’s application for CWIP and the 100% Abandoned Plant incentive (Abandoned Plant), subject to further compliance, for projects that are subject to subsequent permitting approval by the NYPSC under Article VII of New York State’s Public Service Law, effective July 8, 2024, and denied the application for CWIP and Abandoned Plant for projects not subject to Article VII permitting approval. On August 2, 2024, NYSEG and RG&E sought clarification, or in the alternative rehearing, of the July 5, 2024 order. Rehearing was denied after 30 days by operation of law, and the order denying rehearing states that the issue will be addressed in a future order. On October 1, FERC ruled on NYSEG and RG&E’s request for clarification/rehearing. FERC confirmed that any projects that receive state siting approval orders that include the required reliability and/or congestion reduction determinations can qualify for incentives, not limited to the projects listed in the July order as Article VII projects. FERC denied clarification and rehearing to include CWIP in rate base prior to FERC’s acceptance of the state siting orders.

UI, CNG, SCG and BGC Rate Plans

Under Connecticut law, The United Illuminating Company’s (UI) retail electricity customers are able to choose their electricity supplier while UI remains their electric distribution company. UI purchases power for those of its customers under standard service rates who do not choose a retail electric supplier and have a maximum demand of less than 500 kilowatts and its customers under supplier of last resort service for those who are not eligible for standard service and who do not choose to purchase electric generation service from a retail electric supplier. The cost of the power is a “pass-through” to those customers through the Generation Service Charge on their bills.

UI has wholesale power supply agreements in place for its entire standard service load for 2024, 80% of the first half of 2025 and 20% of the second half of 2025. Supplier of last resort service is procured on a quarterly basis and UI has a wholesale power supply agreement in place for the first, second, third and fourth quarters of 2024.

On September 9, 2022, UI filed a distribution revenue requirement case proposing a three-year rate plan commencing September 1, 2023 through August 31, 2026. The filing was based on a test year ending December 31, 2021, for the rate years beginning September 1, 2023 (UI Rate Year 1), September 1, 2024 (UI Rate Year 2), and September 1, 2025 (UI Rate Year 3).

On August 25, 2023, PURA issued its Final Decision for a one-year rate plan commencing on September 1, 2023, providing for a rate increase of $23 million based on an allowed ROE of 9.1% that was reduced to 8.63% by certain adjustments. The Final Decision established a capital structure consisting of 50% common equity and 50% debt. The Final Decision results in an average increase in base distribution rates of about 6.6% and an average increase in customer bills of about 2% compared to current levels. On September 18, 2023, UI filed an appeal of the PURA's Final Decision in Connecticut Superior Court, because of factual and legal errors related to the treatment of deferred assets, plant in service, and operating expenses. We cannot predict the outcome of this matter.

In 2017, PURA approved new tariffs for SCG effective January 1, 2018 for a three-year rate plan with annual rate increases. The new tariffs also include an RDM and Distribution Integrity Management Program (DIMP) mechanism, ESM, the amortization of certain regulatory liabilities (most notably accumulated hardship deferral balances and certain accumulated deferred income taxes) and tariff increases based on an ROE of 9.25% and an approximately 52.00% equity ratio. Any dollars due to customers from the ESM are to be first applied against any environmental regulatory asset balance as defined in the settlement agreement (if one exists at that time) or refunded to customers through a bill credit if such environmental regulatory asset balance does not exist.

On September 30, 2024, UI filed a Notice of Intent to file an application between November 1 and 30, 2024, to adjust its rates and charges. The UI Application will propose to amend UI’s existing rate schedules effective November 1, 2025, in order to address a significant deficiency in distribution-related operating revenues. More specifically, the UI Application will propose a change in base distribution rates to be implemented in the rate year beginning November 1, 2025, with proposed rates designed to provide incremental operating revenues of approximately $105 million. UI’s Application is also expected to include several measures to moderate the impact of the proposed rate update for customers, including, a low-income discount rate to provide rate relief to UI’s disadvantaged customers, as well as proposing to continue an economic development rate to support continued commercial growth in UI’s service territory. We cannot predict the outcome of this matter.

In 2018, PURA approved new tariffs for CNG effective January 1, 2019 for a three-year rate plan with annual rate increases. The new tariffs continued the RDM and DIMP mechanism. ESM and tariff increases are based on an ROE of 9.30% and an equity ratio of 54.00% in 2019, 54.50% in 2020 and 55.00% in 2021.

On November 3, 2023, CNG and SCG filed a distribution revenue requirement case proposing a one-year rate plan commencing November 1, 2024 through October 31, 2025, for each company respectively. CNG requested that PURA approve new distribution rates to recover an increase in revenue requirements of approximately $19.8 million, and SCG requested approval of new distribution rates to recover an increase in revenue requirements of approximately $40.6 million. CNG’s and SCG’s rate plans also included several measures to moderate the impact of the proposed rate update for all customers, including, the adoption of a low-income discount rate and each company seeks to maintain their current revenue decoupling and earning sharing mechanisms. Evidentiary hearings commenced on April 22, 2024 and a draft decision was issued by PURA on October 4, 2024, providing for a rate decrease of $38.8 million and $36.6 million, respectively, for CNG and SCG, based on an allowed ROE of 9.2% for both companies. The Company currently is evaluating the draft decision, and expects to respond to PURA within the established timeframe. The final decision is expected in the fourth quarter of 2024 with new rates commencing November 1, 2024. We cannot predict the outcome of this matter.

On June 24, 2022, BGC filed a Settlement Agreement with the Massachusetts Attorney General’s Office (AGO) for DPU approval negotiated between BGC and the AGO in lieu of a fully litigated rate case before the DPU. The Settlement Agreement allowed for agreed-upon adjustments to BGC’s revenue requirement as well as various step increases BGC shall be entitled to on January 1, 2023 and January 1, 2024. It provided for the opportunity to increase BGC’s revenue requirement by as much as $5.6 million over current rates (reflective of a 9.70% ROE and a 54.00% equity ratio as well as other stepped adjustments) through January 1, 2024. The Settlement Agreement was approved in its entirety by the DPU on October 27, 2022, and new rates went into effect January 1, 2023.

Connecticut Energy Legislation

On October 7, 2020, the Governor of Connecticut signed into law an energy bill that, among other things, instructs PURA to revise the rate-making structure in Connecticut to adopt performance-based rates for each electric distribution company, increases the maximum civil penalties assessable for failures in emergency preparedness, and provides for certain penalties and reimbursements to customers after storm outages greater than 96 hours and extends rate case timelines.

Pursuant to the legislation, PURA opened a docket to consider the implementation of the associated customer compensation and reimbursement provisions in emergency events where customers were without power for more than 96 consecutive hours. On June 30, 2021, PURA issued a final decision implementing the legislative mandate to create a program pursuant to which residential customers will receive $25 for each day without power after 96 hours and also receive reimbursement of $250 for

spoiled food and medicine. The decision emphasizes that no costs incurred in connection with this program are recoverable from customers. On June 29, 2023 the Governor of Connecticut signed SB7 into law, which included language that Level 1 storm events were exempt from the waiver. We will continue to review the requirements of the program for the next legislative session.

PURA Investigation of the Preparation for and Response to the Tropical Storm Isaias and Connecticut Storm Reimbursement Legislation

On August 6, 2020, PURA opened a docket to investigate the preparation for and response to Tropical Storm Isaias by the electric distribution companies in Connecticut including UI. Following hearings and the submission of testimony, PURA issued a final decision on April 15, 2021, finding that UI “generally met standards of acceptable performance in its preparation and response to Tropical Storm Isaias," subject to certain exceptions noted in the decision, but ordered a 15-basis point reduction to UI's ROE in its next rate case to incentivize better performance and indicated that penalties could be forthcoming in the penalty phase of the proceedings. On June 11, 2021, UI filed an appeal of PURA’s decision with the Connecticut Superior Court.

On May 6, 2021, in connection with its findings in the Tropical Storm Isaias docket, PURA issued a Notice of Violation to UI for allegedly failing to comply with standards of acceptable performance in emergency preparation or restoration of service in an emergency and with orders of the Authority, and for violations of accident reporting requirements. PURA assessed a civil penalty in the total amount of approximately $2 million. PURA held a hearing on this matter and, in an order dated July 14, 2021, reduced the civil penalty to approximately $1 million. UI filed an appeal of PURA’s decision with the Connecticut Superior Court. This appeal and the appeal of PURA’s decision on the Tropical Storm Isaias docket have been consolidated. Following oral arguments in October 2022, the court denied UI’s appeal and affirmed PURA’s decisions in their entirety. UI filed a notice of appeal to Connecticut's Appellate court on November 7, 2022. This matter has been briefed and oral argument was held December 11, 2023. We cannot predict the outcome of this proceeding.

Regulatory Assets and Liabilities

The regulatory assets and regulatory liabilities shown in the tables below result from various regulatory orders that allow for the deferral and/or reconciliation of specific costs. Regulatory assets and regulatory liabilities are classified as current when recovery or refund in the coming year is allowed or required through a specific order or when the rates related to a specific regulatory asset or regulatory liability are subject to automatic annual adjustment.

Regulatory assets as of September 30, 2024 and December 31, 2023, respectively, consisted of:


	September 30,		December 31,
As of	2024		2023
(Millions)
Pension and other post-retirement benefits	$	450	$	445
Pension and other post-retirement benefits cost deferrals	56		58
Storm costs	1,219		868
Rate adjustment mechanism	28		24
Revenue decoupling mechanism	105		86
Contracts for differences	24		38
Hardship programs	24		23
Deferred purchased gas	14		16
Environmental remediation costs	259		240
Debt premium	53		58
Unamortized losses on reacquired debt	16		17
Unfunded future income taxes	619		578
Federal tax depreciation normalization adjustment	126		130
Asset retirement obligation	20		19
Deferred meter replacement costs	59		59
COVID-19 cost recovery and late payment surcharge	10		12
Low income arrears forgiveness	39		55
Excess generation service charge	42		52
System Expansion	22		22
Non-bypassable charge	142		103
Hedge losses	14		34
Rate change levelization	95		60
Value of distributed energy resources	53		49
Uncollectible reserve	139		104
New York make-whole provision	63		96
Other	373		283
Total regulatory assets	4,064		3,529
Less: current portion	914		718
Total non-current regulatory assets	$	3,150	$	2,811

“Pension and other post-retirement benefits” represent the actuarial losses on the pension and other post-retirement plans that will be reflected in customer rates when they are amortized and recognized in future pension expenses.

“Pension and other post-retirement benefits cost deferrals” include the difference between actual expense for pension and other post-retirement benefits and the amount provided for in rates for certain of our regulated utilities. A portion of this balance is amortized through current rates, the remaining portion will be refunded in future periods through future rate cases.

“Storm costs” for CMP, NYSEG, RG&E and UI are allowed in rates based on an estimate of the routine costs of service restoration. The companies are also allowed to defer unusually high levels of service restoration costs resulting from major storms when they meet certain criteria for severity and duration. A portion of this balance is amortized through current rates, and the remaining portion will be determined through future rate cases.

“Rate adjustment mechanism” represents an interim rate change to return or collect certain defined reconciled revenues and costs for NYSEG and RG&E following the approval of the Joint Proposal by the NYPSC. The RAM, when triggered, is implemented in rates on July 1 of each year for return or collection over a twelve-month period.

"Revenue decoupling mechanism" represents the mechanism established to disassociate the utility's profits from its delivery/commodity sales.

“Contracts for Differences” represent the deferral of unrealized gains and losses on contracts for differences derivative contracts. The balance fluctuates based upon quarterly market analysis performed on the related derivatives. The amounts, which do not earn a return, are fully offset by a corresponding derivative asset/liability.

“Hardship Programs” represent hardship customer accounts deferred for future recovery to the extent they exceed the amount in rates.

“Deferred Purchased Gas” represents the difference between actual gas costs and gas costs collected in rates.

“Environmental remediation costs” includes spending that has occurred and is eligible for future recovery in customer rates. Environmental costs are currently recovered through a reserve mechanism whereby projected spending is included in rates with any variance recorded as a regulatory asset or a regulatory liability. The amortization period will be established in future proceedings and will depend upon the timing of spending for the remediation costs. It also includes the anticipated future rate recovery of costs that are recorded as environmental liabilities since these will be recovered when incurred. Because no funds have yet been expended for the regulatory asset related to future spending, it does not accrue carrying costs and is not included within rate base.

“Debt premium” represents the regulatory asset recorded to offset the fair value adjustment to the regulatory component of the non-current debt of UIL at the acquisition date. This amount is being amortized to interest expense over the remaining term of the related outstanding debt instruments.

“Unamortized losses on reacquired debt” represent deferred losses on debt reacquisitions that will be recovered over the remaining original amortization period of the reacquired debt.

“Unfunded future income taxes” represent unrecovered federal and state income taxes primarily resulting from regulatory flow through accounting treatment and are the offset to the unfunded future deferred income tax liability recorded. The income tax benefits or charges for certain plant related timing differences, such as removal costs, are immediately flowed through to, or collected from, customers. This amount is being amortized as the amounts related to temporary differences that give rise to the deferrals are recovered in rates. These amounts are being collected over a period of 46 years, and the NYPSC staff has initiated an audit, as required, of the unfunded future income taxes and other tax assets to verify the balances.

“Federal tax depreciation normalization adjustment” represents the revenue requirement impact of the difference in the deferred income tax expense required to be recorded under the IRS normalization rules and the amount of deferred income tax expense that was included in cost of service for rate years covering 2011 forward. The recovery period in New York is from 25 to 35 years and for CMP 32.5 years beginning in 2020.

“Asset retirement obligations” represents the differences in timing of the recognition of costs associated with our AROs and the collection of such amounts through rates. This amount is being amortized at the related depreciation and accretion amounts of the underlying liability.

“Deferred meter replacement costs” represent the deferral of the book value of retired meters which were replaced or are planned to be replaced by AMI meters. This amount is being amortized over the initial depreciation period of related retired meters.

"COVID-19 cost recovery and late payment surcharge" represents: a) deferred COVID-19-related costs in the state of Connecticut based on the order issued by PURA on April 29, 2020, requiring utilities to track COVID-19-related expenses and lost revenue and create a regulatory asset, and b) deferred lost late payment revenue in the state of New York based on the order issued by the NYPSC on June 17, 2022, approving a deferral and surcharge/sur-credit mechanism to recover/return deferred balances starting July 1, 2022.

“Low-income arrears forgiveness” represents deferred bill credits in the state of New York based on the order issued by the NYPSC on June 16, 2022, approving deferral of bill credits for low-income customers and recovery of regulatory assets from all customers over five years for RG&E and three years for NYSEG. Surcharge started August 1, 2022.

“Excess generation service charge” represents deferred generation-related costs or revenues for future recovery from or return to customers. The amount fluctuates based upon timing differences between revenues collected from rates and actual costs incurred.

“System expansion” represents expenses not covered by system expansion rates related to expanding the natural gas system and converting customers to natural gas.

“Non-bypassable charges” represent non-bypassable federally mandated congestion costs or revenues for future recovery from or return to customers. The amount fluctuates based upon timing differences between revenues collected from rates and actual costs incurred.

“Hedge losses” represents the deferred fair value losses on electric and gas hedge contracts.

“Rate change levelization" adjusts the New York delivery rate increases across the three-year plan to avoid unnecessary spikes and offsetting dips in customer rates. A portion of this balance is amortized through current rates, the remaining portion will be refunded in future periods through future rate cases.

“Value of distributed energy resources” represents the mechanism to compensate for energy created by distributed energy resources, such as solar.

“Uncollectible reserve” includes the anticipated future rate recovery of costs that are recorded as uncollectible since those will be recovered when incurred. Because no funds have yet been expended for the regulatory asset related to future uncollectible expense, it does not accrue carrying costs and is not included within rate base. It also includes the variance between actual uncollectible expense and uncollectible expense included in rates that is eligible for future recovery in customer rates. The amortization period will be established in future proceedings.

“New York make-whole provision” represents the regulatory asset to recover revenues that would have been received by NYSEG/RGE had Rate Year 1 rates approved in the 22-E-0317 et al. joint proposal gone into effect on the effective date of May 1, 2023. The balance is being recovered through a separately stated make-whole rate, effective November 1, 2022, over 6-30 months.

“Other” includes various items subject to reconciliation including vegetation management, systems benefit charge and transmission reconciliations.

Regulatory liabilities as of September 30, 2024 and December 31, 2023, respectively, consisted of:


	September 30,		December 31,
As of	2024		2023
(Millions)
Energy efficiency portfolio standard	$	23	$	15
Gas supply charge and deferred natural gas cost	1		8
Pension and other post-retirement benefits cost deferrals	96		89
Carrying costs on deferred income tax bonus depreciation	1		3
Carrying costs on deferred income tax - Mixed Services 263(a)	1		2
2017 Tax Act	1,152		1,190
Accrued removal obligations	1,124		1,139
Positive benefit adjustment	4		9
Deferred property tax	23		21
Net plant reconciliation	21		23
Debt rate reconciliation	10		18
Rate refund – FERC ROE proceeding	41		39
Transmission congestion contracts	20		26
Merger-related rate credits	6		8
Accumulated deferred investment tax credits	19		21
Asset retirement obligation	19		19
Middletown/Norwalk local transmission network service collections	15		16
Non-firm margin sharing credits	43		34
Non by-passable charges	5		9
Transmission revenue reconciliation mechanism	4		57
Other	164		209
Total regulatory liabilities	2,792		2,955
Less: current portion	156		261
Total non-current regulatory liabilities	$	2,636	$	2,694

“Energy efficiency portfolio standard” represents the costs of energy efficiency programs deferred for future recovery to the extent they exceed the amount in rates. A portion of this balance is amortized through current rates, the remaining portion will be refunded in future periods through future rate cases.

“Gas supply charge and deferred natural gas cost" reflects the actual costs of purchasing, transporting and storing of natural gas. Gas supply reconciliation is determined by comparing actual gas supply expenses to the monthly gas cost recoveries in rates. Prior rate year balances are collected/returned to customers beginning the next calendar year.

“Pension and other postretirement benefits cost deferrals” include the difference between actual expense for pension and other post-retirement benefits and the amount provided for in rates for certain of our regulated utilities. A portion of this balance is amortized through current rates, the remaining portion will be refunded in future periods through future rate cases.

“Carrying costs on deferred income tax bonus depreciation” represent the carrying costs benefit of increased accumulated deferred income taxes created by the change in tax law allowing bonus depreciation. A portion of this balance is amortized through current rates, the remaining portion will be refunded in future periods through future rate cases.

"Carrying costs on deferred income tax - Mixed Services 263(a)" represent the carrying costs benefit of increased accumulated deferred income taxes created by Section 263 (a) IRC. A portion of this balance is amortized through current rates, the remaining portion will be refunded in future periods through future rate cases.

“2017 Tax Act” represents the impact from remeasurement of deferred income tax balances as a result of the Tax Act enacted by the U.S. federal government on December 22, 2017. Reductions in accumulated deferred income tax balances due to the reduction in the corporate income tax rates from 35% to 21% under the provisions of the Tax Act will result in amounts previously and currently collected from utility customers for these deferred taxes to be refundable to such customers, generally

through reductions in future rates. The NYPSC, MPUC, PURA, DPU and the FERC held separate proceedings in New York, Maine, Connecticut, Massachusetts and the FERC, respectively, and for the majority of our regulated utilities, authorized the amortization periods for the return of regulatory liabilities and the recovery of regulatory assets, including the authorization of sur-credits to return the related benefits to rate payers in certain jurisdictions.

“Accrued removal obligations” represent the differences between asset removal costs recorded and amounts collected in rates for those costs. The amortization period is dependent upon the asset removal costs of underlying assets and the life of the utility plant.

“Positive benefit adjustment” resulted from Iberdrola’s 2008 acquisition of Avangrid (formerly Energy East Corporation). This is being used to moderate increases in rates. A portion of this balance is amortized through current rates, the remaining portion will be refunded in future periods through future rate cases.

“Deferred property tax” represents the difference between actual expense for property taxes recoverable from customers and the amount provided for in rates. A portion of this balance is amortized through current rates, the remaining portion will be refunded in future periods through future rate cases.

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

“Debt rate reconciliation” represents the over/under collection of costs related to debt instruments identified in the rate case. Costs would include interest, commissions and fees versus amounts included in rates.

“Rate refund - FERC ROE proceeding” represents the reserve associated with the FERC proceeding around the base return on equity (ROE) reflected in ISO New England, Inc.’s (ISO-NE) open access transmission tariff (OATT). See Note 8 for more details.

“Transmission congestion contracts” represents deferral of the Nine Mile 2 Nuclear Plant transmission congestion contract at RG&E. A portion of this balance is amortized through current rates, the remaining portion will be refunded in future periods through future rate cases.

“Merger-related rate credits” resulted from the acquisition of UIL. This is being used to moderate increases in rates. During the three and nine months ended September 30, 2024, $1 million and $2 million, respectively, and $1 million and $2 million, respectively, for the three and nine months ended September 30, 2023 of rate credits were applied against customer bills.

“Accumulated deferred investment tax credits” represent investment tax credits related to plant investments that are deferred when earned and amortized over the estimated lives of the related assets.

“Asset retirement obligation” represents the differences in timing of the recognition of costs associated with our AROs and the collection of such amounts through rates. This amount is being amortized at the related depreciation and accretion amounts of the underlying liability.

“Middletown/Norwalk local transmission network service collections” represents allowance for funds used during construction of the Middletown/Norwalk transmission line, which is being amortized over the useful life of the project.

“Non-firm margin sharing credits” represents the portion of interruptible and off-system sales revenue set aside to fund gas expansion projects.

“Other” includes various items subject to reconciliation or being returned through rates, such as service quality metrics.

Note 6. Fair Value of Financial Instruments and Fair Value Measurements

We determine the fair value of our derivative assets and liabilities and non-current equity investments associated with Networks’ activities utilizing market approach valuation techniques:

•Our equity and other investments consist of Rabbi Trusts. Our Rabbi Trusts, which cover certain deferred compensation plans and non-qualified pension plan obligations, consist of equity and other investments. The Rabbi Trusts primarily invest in equity securities, fixed income and money market funds. Certain Rabbi Trusts also invest in trust or company owned life insurance policies. We measure the fair value of our Rabbi Trust portfolio using observable, unadjusted quoted market prices in active markets for identical assets and include the measurements in Level 1. We measure the fair value of the supplemental retirement benefit life insurance trust based on quoted prices in the active markets for the various funds within which the assets are held and include the measurement in Level 2.

•NYSEG and RG&E enter into electric energy derivative contracts to hedge the forecasted purchases required to serve their electric load obligations. They hedge their electric load obligations using derivative contracts that are settled based upon Locational Based Marginal Pricing published by the NYISO. NYSEG and RG&E hedge approximately 70% of their electric load obligations using contracts for a NYISO location where an active market exists. The forward market prices used to value the companies’ open electric energy derivative contracts are based on quoted prices in active markets for identical assets or liabilities with no adjustment required and therefore we include the fair value measurements in Level 1.

•NYSEG and RG&E enter into natural gas derivative contracts to hedge their forecasted purchases required to serve their natural gas load obligations. NYSEG and RG&E hedge up to approximately 55% of their forecasted winter demand through the use of financial transactions and storage withdrawals. The forward market prices used to value open natural gas derivative contracts are exchange-based prices for the identical derivative contracts traded actively on the New York Mercantile Exchange (NYMEX). We include the fair value measurements in Level 1 because we use prices quoted in an active market.

•UI enters into CfDs, which are marked-to-market based on a probability-based expected cash flow analysis that is discounted at risk-free interest rates and an adjustment for non-performance risk using credit default swap rates. We include the fair value measurement for these contracts in Level 3 (See Note 7 for further discussion of CfDs).

We determine the fair value of our derivative assets and liabilities associated with Renewables activities utilizing market approach valuation techniques. Exchange-traded transactions, such as NYMEX futures contracts, that are based on quoted market prices in active markets for identical products with no adjustment are included in fair value Level 1. Contracts with delivery periods of two years or less which are traded in active markets and are valued with or derived from observable market data for identical or similar products such as over-the-counter NYMEX, foreign exchange swaps, and fixed price physical and basis and index trades are included in fair value Level 2. Contracts with delivery periods exceeding two years or that have unobservable inputs or inputs that cannot be corroborated with market data for identical or similar products are included in fair value Level 3. The unobservable inputs include modeled volumes on unit-contingent contracts, extrapolated power curves through May 2032 and scheduling assumptions on California power exports to cover Nevada physical power sales. The valuation for this category is based on our judgments about the assumptions market participants would use in pricing the asset or liability since limited market data exists.

We determine the fair value of our interest rate derivative instruments based on a model whose inputs are observable, such as SOFR, forward interest rate curves or other relevant benchmark. We include the fair value measurement for these contracts in Level 2 (See Note 7 for further discussion of interest rate contracts).

We determine the fair value of our foreign currency exchange derivative instruments based on current exchange rates compared to the rates at inception of the hedge. We include the fair value measurement for these contracts in Level 2.

The carrying amounts for cash and cash equivalents, restricted cash, accounts receivable, accounts payable, notes payable, lease obligations and interest accrued approximate fair value.

Restricted cash was $3 million as of both September 30, 2024 and December 31, 2023, and is included in "Other Assets" on our condensed consolidated balance sheets.

The financial instruments measured at fair value as of September 30, 2024 and December 31, 2023, respectively, consisted of:


As of September 30, 2024	Level 1		Level 2		Level 3		Netting		Total
(Millions)
Equity investments with readily determinable fair values	$	30	$	20	$	—	$	—	$	50
Derivative assets
Derivative financial instruments - power	$	21	$	67	$	98	$	(70)	$	116
Derivative financial instruments - gas	—		5		—		—		5
Contracts for differences	—		—		1		—		1
Derivative financial instruments - Other	—		132		—		—		132
Total	$	21	$	204	$	99	$	(70)	$	254
Derivative liabilities
Derivative financial instruments - power	$	(32)	$	(30)	$	(35)	$	93	$	(4)
Derivative financial instruments - gas	(4)		(18)		(1)		4		(19)
Contracts for differences	—		—		(25)		—		(25)
Derivative financial instruments - Other	—		(72)		—		—		(72)
Total	$	(36)	$	(120)	$	(61)	$	97	$	(120)


As of December 31, 2023	Level 1		Level 2		Level 3		Netting		Total
(Millions)
Equity investments with readily determinable fair values	$	29	$	16	$	—	$	—	$	45
Derivative assets
Derivative financial instruments - power	$	15	$	42	$	114	$	(69)	$	102
Derivative financial instruments - gas	—		17		—		(12)		5
Contracts for differences	—		—		1		—		1
Derivative financial instruments - Other	—		122		—		—		122
Total	$	15	$	181	$	115	$	(81)	$	230
Derivative liabilities
Derivative financial instruments - power	$	(37)	$	(101)	$	(40)	$	135	$	(43)
Derivative financial instruments - gas	(12)		(26)		—		37		(1)
Contracts for differences	—		—		(39)		—		(39)
Derivative financial instruments - Other	—		(92)		—		—		(92)
Total	$	(49)	$	(219)	$	(79)	$	172	$	(175)

The reconciliation of changes in the fair value of financial instruments based on Level 3 inputs for the three and nine months ended September 30, 2024 and 2023, respectively, is as follows:


	Three Months Ended September 30,				Nine Months Ended September 30,
(Millions)	2024		2023		2024		2023
Fair Value Beginning of Period,	$	13	$	23	$	36	$	16
Gains recognized in operating revenues	6		—		12		8
(Losses) recognized in operating revenues	7		—		(3)		(12)
Total losses recognized in operating revenues	13		—		9		(4)
Gains recognized in OCI	—		—		—		8
(Losses) recognized in OCI	8		(9)		(6)		(10)
Total (losses) gains recognized in OCI	8		(9)		(6)		(2)
Net change recognized in regulatory assets and liabilities	5		5		14		13
Purchases	29		(2)		32		29
Settlements	(30)		(39)		(47)		(74)

Fair Value as of September 30,	$	38	$	(22)	$	38	$	(22)
Losses for the period included in operating revenues attributable to the change in unrealized gains relating to financial instruments still held at the reporting date	$	13	$	—	$	9	$	(4)

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 September 30, 2024
Index	Avg.		Max.		Min.
Ameren ($/MWh)	$	42.62	$	90.60	$	19.58
ComEd ($/MWh)	$	38.70	$	85.85	$	15.39
ERCOT S hub ($/MWh)	$	47.03	$	197.00	$	16.17
Mid C ($/MWh)	$	82.57	$	248.45	$	14.30

Our Level 3 valuations primarily consist of a Hydro PPA utilized for balancing services for the Northwest wind fleet, power swaps with delivery periods extending through May 2032 hedging Midwest and Texas wind farms and physical power sales agreements in Nevada.

We considered the measurement uncertainty regarding the Level 3 gas and power positions to changes in the valuation inputs. Given the nature of the transactions in Level 3, the primary input to the valuation is the market price of gas or power for transactions with delivery periods exceeding two years. The fixed price power swaps are economic hedges of future power generation, with decreases in power prices resulting in unrealized gains and increases in power prices resulting in unrealized losses. The hydro PPA is a long capacity/energy position in the Northwest that provides balancing services with increases in power prices resulting in unrealized gains and decreases in power prices resulting in unrealized losses. The gas swaps are economic hedges of fuel purchases for a combined cycle gas plant, with increases in gas prices resulting in unrealized gains and decreases in gas prices resulting in unrealized losses. As all transactions are economic hedges of the underlying position, any changes in the fair value of these transactions will be offset by changes in the anticipated purchase/sales price of the underlying commodity.

Two elements of the analytical infrastructure employed in valuing transactions are the price curves used in the calculation of market value and the modeled volumes on unit-contingent agreements. We maintain and document authorized trading points and associated forward price curves, and we develop and document models used in valuation of the various products.

Transactions are valued in part on the basis of forward prices and estimated volumes. We maintain and document descriptions of these curves and their derivations. Forward price curves used in valuing the transactions are applied to the full duration of the transaction.

The determination of fair value of the CfDs (see Note 7 for further details on CfDs) was based on a probability-based expected cash flow analysis that was discounted at risk-free interest rates, as applicable, and an adjustment for non-performance risk using credit default swap rates. Certain management assumptions were required, including development of pricing that extends over the term of the contracts. We believe this methodology provides the most reasonable estimates of the amount of future discounted cash flows associated with the CfDs. Additionally, on a quarterly basis, we perform analytics to ensure that the fair value of the derivatives is consistent with changes, if any, in the various fair value model inputs. Significant isolated changes in the risk of non-performance, the discount rate or the contract term pricing would result in an inverse change in the fair value of the CfDs. Additional quantitative information about Level 3 fair value measurements of the CfDs is as follows:


						Range at
Unobservable Input						September 30, 2024
Risk of non-performance						0.51% - 0.53%
Discount rate						3.58% - 3.58%
Forward pricing ($ per KW-month)						$2.59 - $2.61

Fair Value of Debt

As of September 30, 2024 and December 31, 2023, debt consisted of first mortgage bonds, unsecured pollution control notes and other various non-current debt securities. The estimated fair value of debt was $12,339 million and $10,266 million as of September 30, 2024 and December 31, 2023, respectively. The estimated fair value was determined, in most cases, by discounting the future cash flows at market interest rates. The interest rates used to make these calculations take into account the credit ratings of the borrowers in each case. The fair value of debt is considered Level 2 within the fair value hierarchy.

Note 7. Derivative Instruments and Hedging

Our operating and financing activities are exposed to certain risks, which are managed by using derivative instruments. All derivative instruments are recognized as either assets or liabilities at fair value on our condensed consolidated balance sheets in accordance with the accounting requirements concerning derivative instruments and hedging activities.

(a) Networks activities

The tables below present Networks' derivative positions as of September 30, 2024 and December 31, 2023, respectively, including those subject to master netting agreements and the location of the net derivative positions on our condensed consolidated balance sheets:


As of September 30, 2024	Current Assets		Noncurrent Assets		Current Liabilities		Noncurrent Liabilities
(Millions)
Not designated as hedging instruments
Derivative assets	$	19	$	2	$	19	$	2
Derivative liabilities	(19)		(2)		(45)		(16)
	—		—		(26)		(14)
Designated as hedging instruments
Derivative assets	—		—		—		—
Derivative liabilities	—		—		—		—
	—		—		—		—
Total derivatives before offset of cash collateral	—		—		(26)		(14)
Cash collateral receivable	—		—		9		5
Total derivatives as presented in the balance sheet	$	—	$	—	$	(17)	$	(9)


As of December 31, 2023	Current Assets		Noncurrent Assets		Current Liabilities		Noncurrent Liabilities
(Millions)
Not designated as hedging instruments
Derivative assets	$	13	$	3	$	12	$	3
Derivative liabilities	(12)		(3)		(57)		(32)
	1		—		(45)		(29)
Designated as hedging instruments
Derivative assets	—		—		—		—
Derivative liabilities	—		—		—		—
	—		—		—		—
Total derivatives before offset of cash collateral	1		—		(45)		(29)
Cash collateral receivable	—		—		27		7
Total derivatives as presented in the balance sheet	$	1	$	—	$	(18)	$	(22)

The net notional volumes of the outstanding derivative instruments associated with Networks' activities as of September 30, 2024 and December 31, 2023, respectively, consisted of:


	September 30,	December 31,
As of	2024	2023
(Millions)
Wholesale electricity purchase contracts (MWh)	5.9	5.6
Natural gas purchase contracts (Dth)	10.7	10.7

Derivatives not designated as hedging instruments

NYSEG and RG&E have an electric commodity charge that passes costs for the market price of electricity through rates. We use electricity contracts, both physical and financial, to manage fluctuations in electricity commodity prices in order to provide price stability to customers. We include the cost or benefit of those contracts in the amount expensed for electricity purchased when the related electricity is sold. We record changes in the fair value of electric hedge contracts to derivative assets and/or liabilities with an offset to regulatory assets and/or regulatory liabilities, in accordance with the accounting requirements concerning regulated operations.

NYSEG and RG&E have purchased gas adjustment clauses that allow us to recover through rates any changes in the market price of purchased natural gas, substantially eliminating our exposure to natural gas price risk. NYSEG and RG&E use natural gas futures and forwards to manage fluctuations in natural gas commodity prices to provide price stability to customers. We include the cost or benefit of natural gas futures and forwards in the commodity cost that is passed on to customers when the related sales commitments are fulfilled. We record changes in the fair value of natural gas hedge contracts to derivative assets and/or liabilities with an offset to regulatory assets and/or regulatory liabilities in accordance with the accounting requirements for regulated operations.

The amounts for electricity hedge contracts and natural gas hedge contracts recognized in regulatory liabilities and assets as of September 30, 2024 and December 31, 2023 and amounts reclassified from regulatory assets and liabilities into income for the three and nine months ended September 30, 2024 and 2023 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						Three Months Ended September 30,				Nine Months Ended September 30,
September 30, 2024	Electricity		Natural Gas		2024	Electricity		Natural Gas		Electricity		Natural Gas
Regulatory assets	$	10	$	4	Purchased power, natural gas and fuel used	$	9	$	—	$	42	$	11
Regulatory liabilities	$	—	$	—
December 31, 2023					2023
Regulatory assets	$	22	$	12	Purchased power, natural gas and fuel used	$	14	$	—	$	85	$	6

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 September 30, 2024, UI has recorded a gross derivative asset of $1 million ($0 of which is related to UI’s portion of the CfD signed by CL&P), a regulatory asset of $24 million, a gross derivative liability of $25 million ($24 million of which is related to UI’s portion of the CfD signed by CL&P) and a regulatory liability of $0. As of December 31, 2023, UI had recorded a gross derivative asset of $1 million ($0 of which is related to UI’s portion of the CfD signed by CL&P), a regulatory asset of $38 million, a gross derivative liability of $39 million ($38 million of which is related to UI’s portion of the CfD signed by CL&P) and a regulatory liability of $0.

The unrealized gains and losses from fair value adjustments to these derivatives, which are recorded in regulatory assets, for the three and nine months ended September 30, 2024 and 2023, respectively, were as follows:


	Three Months Ended September 30,				Nine Months Ended September 30,
	2024		2023		2024		2023
(Millions)

Derivative liabilities	$	5	$	5	$	14	$	13

Derivatives designated as hedging instruments

The effect of derivatives in cash flow hedging relationships on Other Comprehensive Income (OCI) and income for the three and nine months ended September 30, 2024 and 2023, respectively, consisted of:


Three Months Ended September 30,	Gain Recognized in OCI on Derivatives (a)		Location of Loss Reclassified from Accumulated OCI into Income	Loss Reclassified from Accumulated OCI into Income		Total amount per Income Statement
(Millions)
2024
Interest rate contracts	$	—	Interest expense	$	1	$	132


Total	$	—		$	1
2023
Interest rate contracts	$	—	Interest expense	$	1	$	107


Total	$	—		$	1


Nine Months Ended September 30,	Gain (Loss) Recognized in OCI on Derivatives (a)		Location of Loss Reclassified from Accumulated OCI into Income	Loss Reclassified from Accumulated OCI into Income		Total amount per Income Statement
(Millions)
2024
Interest rate contracts	$	—	Interest expense	$	3	$	379


Total	$	—		$	3
2023
Interest rate contracts	$	—	Interest expense	$	3	$	301


Total	$	—		$	3

(a) Changes in accumulated OCI are reported on a pre-tax basis.

As of September 30, 2024 and December 31, 2023, the net loss in accumulated OCI related to previously settled forward starting swaps and accumulated amortization was $36 million and $39 million, respectively. Networks recorded net derivative losses related to discontinued cash flow hedges of $1 million and $3 million, for both the three and nine months ended September 30, 2024 and 2023, respectively. Networks will amortize approximately $4 million of net derivative losses related to discontinued cash flow hedges within the next twelve months.

(b) Renewables activities

Renewables sells fixed-price gas and power forwards to hedge our merchant wind assets from declining commodity prices for our Renewables business. Renewables also purchases fixed-price gas and basis swaps and sells fixed-price power in the forward market to hedge the spark spread or heat rate of our merchant thermal assets and enters into tolling arrangements to sell the output of its thermal generation facilities.

Renewables has proprietary trading operations that enter into fixed-price power and gas forwards in addition to basis swaps. The intent is to speculate on fixed-price commodity and basis volatility in the U.S. commodity markets.

Renewables will periodically designate derivative contracts as cash flow hedges for both its thermal and wind portfolios. The fair value changes are recorded in OCI. For thermal operations, Renewables will periodically designate both fixed-price NYMEX gas contracts and natural gas basis swaps that hedge the fuel requirements of its Klamath Plant in Klamath, Oregon. Renewables will also designate fixed-price power swaps at various locations in the U.S. market to hedge future power sales from its Klamath facility and various wind farms.

The net notional volumes of outstanding derivative instruments associated with Renewables' activities as of September 30, 2024 and December 31, 2023, respectively, consisted of:


	September 30,	December 31,
As of	2024	2023
(MWh/Dth in millions)
Wholesale electricity purchase contracts	—	1
Wholesale electricity sales contracts	4	6
Natural gas and other fuel purchase contracts	20	21
Financial power contracts	4	4
Basis swaps – purchases	23	24
Basis swaps – sales	1	1

The fair values of derivative contracts associated with Renewables' activities as of September 30, 2024 and December 31, 2023, respectively, consisted of:


	September 30,		December 31,
As of	2024		2023
(Millions)
Wholesale electricity purchase contracts	$	4	$	29
Wholesale electricity sales contracts	70		14
Natural gas and other fuel purchase contracts	(6)		4
Financial power contracts	39		17
Basis swaps – purchases	(8)		—

Total	$	99	$	64

Renewables has a forward interest rate swap, with a total notional amount of $956 million, to hedge the issuance of forecasted variable rate debt. The forward interest rate swap is designated and qualifies as a cash flow hedge. As of September 30, 2024 and December 31, 2023, the fair value of the interest rate swap was $131 million and $122 million, respectively, as a current and non-current asset. The gain or loss on the interest rate swap is reported as a component of accumulated OCI and will be reclassified into earnings in the period or periods during which the related interest expense on the debt is incurred.

The tables below present Renewables' derivative positions as of September 30, 2024 and December 31, 2023, respectively, including those subject to master netting agreements and the location of the net derivative position on our condensed consolidated balance sheets:


As of September 30, 2024	Current Assets		Noncurrent Assets		Current Liabilities		Noncurrent Liabilities
(Millions)
Not designated as hedging instruments
Derivative assets	$	66	$	53	$	16	$	—
Derivative liabilities	(1)		(7)		(29)		—
	65		46		(13)		—
Designated as hedging instruments
Derivative assets	37		131		—		—
Derivative liabilities	(17)		(6)		(4)		(22)
	20		125		(4)		(22)
Total derivatives before offset of cash collateral	85		171		(17)		(22)
Cash collateral (payable) receivable	(2)		—		14		1
Total derivatives as presented in the balance sheet	$	83	$	171	$	(3)	$	(21)


As of December 31, 2023	Current Assets		Noncurrent Assets		Current Liabilities		Noncurrent Liabilities
(Millions)
Not designated as hedging instruments
Derivative assets	$	53	$	52	$	53	$	1
Derivative liabilities	—		(3)		(73)		(4)
	53		49		(20)		(3)
Designated as hedging instruments
Derivative assets	15		113		7		1
Derivative liabilities	(1)		—		(47)		(37)
	14		113		(40)		(36)
Total derivatives before offset of cash collateral	67		162		(60)		(39)
Cash collateral receivable	—		—		43		13
Total derivatives as presented in the balance sheet	$	67	$	162	$	(17)	$	(26)

Derivatives not designated as hedging instruments

The effects of trading and non-trading derivatives associated with Renewables' activities for the three and nine months ended September 30, 2024, consisted of:


	Three Months Ended September 30, 2024						Nine Months Ended September 30, 2024
	Trading		Non-trading		Total amount per income statement		Trading		Non-trading		Total amount per income statement
(Millions)
Operating Revenues
Wholesale electricity purchase contracts	$	—	$	—			$	(1)	$	—
Wholesale electricity sales contracts	—		6				1		31
Financial power contracts	3		12				(1)		15
Financial and natural gas contracts	—		(2)				—		(7)
Total (loss) gain included in operating revenues	$	3	$	16	$	2,083	$	(1)	$	39	$	6,423

Purchased power, natural gas and fuel used
Wholesale electricity purchase contracts	$	—	$	(3)			$	—	$	(23)


Financial and natural gas contracts	—		1				—		2
Total loss included in purchased power, natural gas and fuel used	$	—	$	(2)	$	457	$	—	$	(21)	$	1,610

Total (loss) gain	$	3	$	14			$	(1)	$	18

The effects of trading and non-trading derivatives associated with Renewables' activities for the three and nine months ended September 30, 2023, consisted of:


	Three Months Ended September 30, 2023						Nine Months Ended September 30, 2023
	Trading		Non-trading		Total amount per income statement		Trading		Non-trading		Total amount per income statement
(Millions)
Operating Revenues
Wholesale electricity purchase contracts	$	(1)	$	(4)			$	(9)	$	(5)
Wholesale electricity sales contracts	(19)		14				9		57
Financial power contracts	(5)		14				(6)		39
Financial and natural gas contracts	—		(1)				—		5
Total (loss) gain included in operating revenues	$	(25)	$	23	$	1,974	$	(6)	$	96	$	6,027

Purchased power, natural gas and fuel used
Wholesale electricity purchase contracts	$	—	$	(23)			$	—	$	(79)


Financial and natural gas contracts	—		2				—		(30)
Total loss included in purchased power, natural gas and fuel used	$	—	$	(21)	$	482	$	—	$	(109)	$	1,844

Total (loss) gain	$	(25)	$	2			$	(6)	$	(13)

Derivatives designated as hedging instruments

The effect of derivatives in cash flow hedging relationships on accumulated OCI and income for the three and nine months ended September 30, 2024 and 2023, respectively, consisted of:


Three Months Ended September 30,	(Loss) Gain Recognized in OCI on Derivatives (a)		Location of (Gain) Reclassified from Accumulated OCI into Income	Loss Reclassified from Accumulated OCI into Income		Total amount per Income Statement
(Millions)
2024
Interest rate contracts	(42)		Interest Expense	—		$	132
Commodity contracts	23		Operating revenues	18		$	2,083
Total	$	(19)		$	18
2023
Interest rate contracts	58		Interest Expense	—		$	107
Commodity contracts	(17)		Operating revenues	52		$	1,974
Total	$	41		$	52


Nine Months Ended September 30,	(Loss) Gain Recognized in OCI on Derivatives (a)		Location of (Gain) Reclassified from Accumulated OCI into Income	Loss Reclassified from Accumulated OCI into Income		Total amount per Income Statement
(Millions)
2024
Interest rate contracts	9		Interest Expense	—		$	379
Commodity contracts	28		Operating revenues	31		$	6,423
Total	$	37		$	31
2023
Interest rate contracts	182		Interest Expense	—		$	301
Commodity contracts	18		Operating revenues	136		$	6,027
Total	$	200		$	136

(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 $3 million of losses included in accumulated OCI at September 30, 2024, are expected to be reclassified into earnings within the next twelve months. For all of the three and nine months ended September 30, 2024 and 2023, we did not record any net derivative losses related to discontinued cash flow hedges.

Avangrid uses financial derivative instruments from time to time to alter its fixed and floating rate debt balances or to hedge fixed rates in anticipation of future fixed rate issuances.

As of September 30, 2024 and December 31, 2023, the net loss in accumulated OCI related to previously settled interest rate contracts was $22 million and $29 million, respectively. We amortized into income $2 million and $7 million for both the three and nine months ended September 30, 2024 and 2023, respectively, of the loss related to settled interest rate contracts. We will amortize approximately $7 million of the net loss on the interest rate contracts within the next twelve months.

The effect of derivatives in cash flow hedging relationships on accumulated OCI for the three and nine months ended September 30, 2024 and 2023, respectively, consisted of:


Three Months Ended September 30,	(Loss) Recognized in OCI on Derivatives (a)		Location of Loss Reclassified from Accumulated OCI into Income	Loss Reclassified from Accumulated OCI into Income		Total amount per Income Statement
(Millions)
2024
Interest rate contracts	$	—	Interest expense	$	2	$	132

2023
Interest rate contracts	$	—	Interest expense	$	2	$	107


Nine Months Ended September 30,	(Loss) Recognized in OCI on Derivatives (a)		Location of Loss Reclassified from Accumulated OCI into Income	Loss Reclassified from Accumulated OCI into Income		Total amount per Income Statement
(Millions)
2024
Interest rate contracts	$	—	Interest expense	$	7	$	379

2023
Interest rate contracts	$	—	Interest expense	$	7	$	301

(a) Changes in OCI are reported on a pre-tax basis. The amounts in accumulated OCI are being reclassified into earnings over the underlying debt maturity periods which end in 2025 and 2029.

On July 15, 2021, Corporate entered into an interest rate swap to hedge the fair value of $750 million of existing debt included in "Non-current debt" on our consolidated balance sheets. The interest rate swap is designated and qualifies as a fair value hedge. The change in the fair value of the interest rate swap and the offsetting change in the fair value of the underlying debt are reported as components of "Interest expense."

The effects on our consolidated financial statements as of and for the three and nine months ended September 30, 2024 and 2023, respectively, are as follows:


	Fair value of hedge		Location of (Gain) Recognized in Income Statement	Loss Recognized in Income Statement				Total per Income Statement
(Millions)	As of September 30, 2024			Three Months Ended September 30, 2024		Nine Months Ended September 30, 2024		Three Months Ended September 30, 2024		Nine Months Ended September 30, 2024
Current Liabilities	$	(22)	Interest Expense	$	9	$	26	$	132	$	379
Non-current liabilities	$	(48)

	Cumulative effect on hedged debt
Current debt	$	—
Non-current debt	$	70


	Fair value of hedge		Location of Loss Recognized in Income Statement	Loss Recognized in Income Statement				Total per Income Statement
(Millions)	As of December 31, 2023			Three Months Ended September 30, 2023		Nine Months Ended September 30, 2023		Three Months Ended September 30, 2023		Nine Months Ended September 30, 2023
Current Liabilities	$	(26)	Interest Expense	$	9	$	23	$	107	$	301
Non-current liabilities	$	(63)

	Cumulative effect on hedged debt
Current debt	$	—
Non-current debt	$	89

(d) Counterparty credit risk management

NYSEG and RG&E face risks related to counterparty performance on hedging contracts due to counterparty credit default. We have developed a matrix of unsecured credit thresholds that are applicable based on the respective counterparty’s or the counterparty guarantor’s credit rating, as provided by Moody’s or Standard & Poor’s. When our exposure to risk for a counterparty exceeds the unsecured credit threshold, the counterparty is required to post additional collateral or we will no longer transact with the counterparty until the exposure drops below the unsecured credit threshold.

The wholesale power supply agreements of UI contain default provisions that include required performance assurance, including certain collateral obligations, in the event that UI’s credit ratings on senior debt were to fall below investment grade. If such an event had occurred as of September 30, 2024, UI would have had to post an aggregate of approximately $15 million in collateral.

We have various master netting arrangements in the form of multiple contracts with various single counterparties that are subject to contractual agreements that provide for the net settlement of all contracts through a single payment. Those arrangements reduce our exposure to a counterparty in the event of a default on or termination of any single contract. For financial statement presentation purposes, we offset fair value amounts recognized for derivative instruments and fair value amounts recognized for the right to reclaim or the obligation to return cash collateral arising from derivative instruments executed with the same counterparty under a master netting arrangement. As of September 30, 2024 and December 31, 2023, the amount of cash collateral under master netting arrangements that have not been offset against net derivative positions was $26 million and $63 million, respectively. Derivative instruments settlements and collateral payments are included throughout the “Changes in operating assets and liabilities” section of operating activities in our condensed consolidated statements of cash flows.

Certain of our derivative instruments contain provisions that require us to maintain an investment grade credit rating on our debt from each of the major credit rating agencies. If our debt were to fall below investment grade, we would be in violation of those provisions and the counterparties to the derivative instruments could request immediate payment or demand immediate and ongoing full overnight collateralization on derivative instruments in net liability positions. The aggregate fair value of all derivative instruments with credit risk related contingent features that are in a liability position as of September 30, 2024 was $14 million, for which we have posted collateral.

Note 8. Contingencies and Commitments

We are party to various legal disputes arising as part of our normal business activities. We assess our exposure to these matters and record estimated loss contingencies when a loss is probable and can be reasonably estimated. We do not provide for accrual of legal costs expected to be incurred in connection with a loss contingency.

Transmission - ROE Complaint – CMP and UI

On September 30, 2011, the Massachusetts Attorney General, DPU, PURA, New Hampshire Public Utilities Commission, Rhode Island Division of Public Utilities and Carriers, Vermont Department of Public Service, numerous New England consumer advocate agencies and transmission tariff customers collectively filed a joint complaint with the FERC, pursuant to sections 206 and 306 of the Federal Power Act against several NETOs claiming that the approved base ROE of 11.14% used by NETOs in calculating formula rates for transmission service under the ISO-New England Open Access Transmission Tariff (OATT) was not just and reasonable and seeking a reduction of the base ROE of 9.2%. CMP and UI are NETOs with assets and service rates that are governed by the OATT and will thereby be affected by any FERC order resulting from the filed complaint.

On December 26, 2012, a second related complaint for a subsequent rate period was filed requesting the ROE be reduced to 8.7%. On July 31, 2014, a third related complaint was filed for a subsequent rate period requesting the ROE be reduced to 8.84%. On April 29, 2016, a fourth complaint was filed for a rate period subsequent to prior complaints requesting the base ROE be 8.61% and ROE Cap be 11.24%.

On October 16, 2018, the FERC issued an order directing briefs and proposing a new methodology to calculate the NETOs ROE that is contained in NETOs’ transmission formula rate on file at FERC. We cannot predict the final outcome of the proceedings.

Customer Invoice Dispute

On May 4, 2021, Nike USA, Inc. (Nike), the buyer under a virtual PPA with a subsidiary of Renewables, provided notice that it disagreed with the settlement amounts included in certain invoices. The PPA provides for a monthly settlement between the parties based on the metered output of the project based on a stated hub price. The disagreement relates as to the appropriate hub price to use for settlement calculations, most notably during Winter Storm Uri in February of 2021. Nike has requested an adjustment to the invoices that would increase the amount payable by approximately $31 million. Renewables has responded that the invoices have been properly calculated in accordance with the provisions of the PPA, and that Nike is not entitled to any further payments. On June 16, 2023, Nike filed suit against the Company, Renewables and certain subsidiaries of Renewables alleging breach of contract, and seeking more than $31 million in invoice adjustments, fees, and interest. The Company filed a motion to dismiss the complaint, which the Circuit Court of the State of Oregon for the County of Multnomah denied on October 25, 2023 following oral arguments. The case is currently proceeding with an expected trial beginning in February 2025. We cannot predict the outcome of this matter.

Solar Contractor Dispute

Renewables, through certain subsidiaries, has Engineering, Procurement and Construction (EPC) contracts with Sterling and Wilson Solar Solutions, Inc. (SWSS) for the construction of two Solar farms–Lund Hill in Klickitat, WA (Lund Hill), and Pachwáywit Fields in Gillam County, OR (Montague). Renewables believes that SWSS is in default of a number of its obligations under the respective EPC contracts, including construction flaws and failing to pay certain subcontractors. As a result, Renewables drew on Letters of Credit for both Montague and Lund Hill. In response, SWSS filed liens on both projects totaling approximately $105 million claiming that this amount is due under EPC contracts. Renewables has bonded over the liens on both properties. On October 27, 2023, SWSS commenced foreclosure actions in Oregon on the lien at Montague, and added claims for breach of contract and quantum meruit, seeking up to $111.8 million. SWSS has also commenced foreclosure procedures in Washington State against Lund Hill seeking to close on its lien of $59.9 million. On February 26, 2024, SWSS filed a lawsuit against Lund Hill and Renewables in New York State court, all based on the same facts as the previously filed foreclosure matter and seeking $59.9 million in damages. We cannot predict the outcome of these disputes.

Guarantee Commitments to Third Parties

As of September 30, 2024, we had approximately $948 million of standby letters of credit, surety bonds, guarantees and indemnifications outstanding. We also provided a guaranty related to Renewables' commitment to contribute equity to Vineyard Wind and an indemnification of Vineyard Wind tax equity investors as described in Note 19, which are in addition to the amounts above. These instruments provide financial assurance to the business and trading partners of Avangrid, its subsidiaries and equity method investees in their normal course of business. The instruments only represent liabilities if Avangrid or its subsidiaries fail to deliver on contractual obligations. We therefore believe it is unlikely that any material liabilities associated with these instruments will be incurred and, accordingly, as of September 30, 2024, neither we nor our subsidiaries have any liabilities recorded for these instruments.

NECEC Commitments

On January 4, 2021, CMP transferred the NECEC project to NECEC Transmission LLC, a wholly-owned subsidiary of Networks. Among other things, NECEC Transmission LLC and/or CMP committed to approximately $90 million of future payments to support various programs in the state of Maine, of which approximately $12 million was paid through the nine months ended September 30, 2024.

Note 9. Environmental Liabilities

Environmental laws, regulations and compliance programs may occasionally require changes in our operations and facilities and may increase the cost of electric and natural gas service. We do not provide for accruals of legal costs expected to be incurred in connection with loss contingencies.

Waste sites

The Environmental Protection Agency and various state environmental agencies, as appropriate, have notified us that we are among the potentially responsible parties that may be liable for costs incurred to remediate certain hazardous substances at twenty-four waste sites, which do not include sites where gas was manufactured in the past. Sixteen of the twenty-four sites are included in the New York State Registry of Inactive Hazardous Waste Disposal Sites; one site is included in Maine’s Uncontrolled Sites Program; and one site is included on the Massachusetts Non-Priority Confirmed Disposal Site list. The remaining sites are not included in any registry list. Finally, five of the twenty-four sites are also included on the National Priorities list. Any liability may be joint and several for certain sites.

We have recorded an estimated liability of $9 million related to seven of the twenty-four sites. We have paid remediation costs related to the remaining seventeen sites and do not expect to incur additional liabilities. Additionally, we have recorded an estimated liability of $7 million related to another nine sites where we believe it is probable that we will incur remediation and/or monitoring costs, although we have not been notified that we are among the potentially responsible parties or that we are regulated under State Resource Conservation and Recovery Act programs. It is possible the ultimate cost to remediate these sites may be significantly more than the accrued amount. As of September 30, 2024, our estimate for costs to remediate these sites ranges from $15 million to $23 million. Factors affecting the estimated remediation amount include the remedial action plan selected, the extent of site contamination, and the allocation of the clean-up costs.

Manufactured Gas Plants

We have a program to investigate and perform necessary remediation at our fifty-three sites where gas was manufactured in the past (Manufactured Gas Plants, or MGPs). Six sites are included in the New York State Registry; thirty-nine sites are included in the New York State Department of Environmental Conservation (NYSDEC) Multi-Site Order of Consent; one site is with individual NYSDEC Orders of Consent; two sites are under a Brownfield Cleanup Program and two sites are included in Maine Department of Environmental Protection programs (none in the Voluntary Response Action Program, Brownfield Cleanup Program and Uncontrolled Sites Program). The remaining sites are not included in a formal program. We have entered into consent orders with various environmental agencies to investigate and, where necessary, remediate forty-one of the fifty-three sites.

As of September 30, 2024, our estimate for all costs related to investigation and remediation of the fifty-three sites ranges from $114 million to $213 million. Our estimate could change materially based on facts and circumstances derived from site investigations, changes in required remedial actions, changes in technology relating to remedial alternatives and changes to current laws and regulations.

Certain of our Connecticut and Massachusetts regulated gas companies own or have previously owned properties where MGPs had historically operated. MGP operations have led to contamination of soil and groundwater with petroleum hydrocarbons, benzene and metals, among other things, at these properties, the regulation and cleanup of which is regulated by the federal Resource Conservation and Recovery Act as well as other federal and state statutes and regulations. Each of the companies has or had an ownership interest in one or more such properties contaminated as a result of MGP-related activities. Under the existing regulations, the cleanup of such sites requires state and at times, federal, regulators’ involvement and approval before cleanup can commence. In certain cases, such contamination has been evaluated, characterized and remediated. In other cases, the sites have been evaluated and characterized, but not yet remediated. Finally, at some of these sites, the scope of the contamination has not yet been fully characterized; as of September 30, 2024, no liability was recorded related to these sites and no amount of loss, if any, can be reasonably estimated at this time. In the past, the companies have received approval for the recovery of MGP-related remediation expenses from customers through rates and will seek recovery in rates for ongoing MGP-related remediation expenses for all of their MGP sites.

As of September 30, 2024 and December 31, 2023, the liability associated with our MGP sites in Connecticut was $113 million and $112 million, respectively, the remediation costs of which could be significant and will be subject to a review by PURA as to whether these costs are recoverable in rates.

As of September 30, 2024 and December 31, 2023, our total recorded liability to investigate and perform remediation at all known inactive MGP sites discussed above and other sites was $249 million and $250 million, respectively. We recorded a corresponding regulatory asset, net of insurance recoveries and the amount collected from FirstEnergy, as described below, because we expect to recover the net costs in rates. Our environmental liability accruals are recorded on an undiscounted basis and are expected to be paid through the year 2058.

FirstEnergy

NYSEG and RG&E each sued FirstEnergy under the Comprehensive Environmental Response, Compensation, and Liability Act (CERCLA) to recover environmental cleanup costs at certain former MGP sites, which are included in the discussion

above. In 2011, the District Court issued a decision and order in NYSEG’s favor, which was upheld on appeal, requiring FirstEnergy to pay NYSEG for past and future clean-up costs at the sixteen sites in dispute. In 2008, the District Court issued a decision and order in RG&E's favor requiring FirstEnergy to pay RG&E for past and future clean-up costs at the two MGP sites in dispute. FirstEnergy remains liable for a substantial share of clean up expenses at the MGP sites. Based on projections as of September 30, 2024, FirstEnergy’s share of clean-up costs owed to NYSEG & RG&E is estimated at approximately $8 million and $5 million, respectively. These amounts are being treated as contingent assets and have not been recorded as either a receivable or a decrease to the environmental provision. Any recovery will be flowed through to NYSEG and RG&E customers, as applicable.

English Station

On August 4, 2016, DEEP issued a partial consent order (the consent order), that requires UI to investigate and remediate certain environmental conditions within the perimeter of a former generation site on the Mill River in New Haven (English Station) that UI sold to Quinnipiac Energy in 2000. Under the consent order, to the extent that the cost of this investigation and remediation is less than $30 million, UI will remit to the State of Connecticut the difference between such cost and $30 million. UI must comply with the terms of the consent order, but may seek to recover costs above $30 million in consultation with the state. UI continues its activities to investigate and remediate the environmental conditions at the site. In 2023 and 2024, DEEP sent UI a series of letters requesting details on remediation plans and security, which UI has responded to.

On January 25, 2024, DEEP issued a notice of declaratory ruling to determine the “high occupancy standard” necessary “to abate on-site pollution and impacts for industrial/commercial use of the Site … inside the buildings” as referenced in section (B)(1)(e)(4) of the Partial Consent Order. On February 26, 2024, UI was granted intervenor status and it subsequently submitted its written comments objecting to the proceedings on March 11, 2024. On January 29, 2024, DEEP served UI with a Summons and Complaint seeking injunctive relief and enforcement of the consent order from the Connecticut Superior Court. On April 9, 2024, the application to transfer the proceedings to the Complex Litigation Docket of the Connecticut Superior Court was granted. On May 28, 2024, DEEP issued a declaratory ruling that the applicable high occupancy standard inside the building is 1 part per million of PCBs. UI appealed DEEP’s ruling to the Connecticut Superior Court on July 3, 2024. Motions to Strike UI’s Special Defenses and to Dismiss UI’s Counter-claims have been briefed.

As of September 30, 2024 and December 31, 2023, the amount reserved related to English Station was $20 million and $19 million, respectively. Since its inception, we have recorded $35 million to the reserve which has been offset with cash payments over time. We cannot predict the outcome of these proceedings.

Keddy Mill Superfund Site, Windham, ME

On September 30, 2024, CMP received a special notice letter pursuant to Section 122(e) of the Comprehensive Environmental Response, Compensation, and Liability Act of 1980 (CERCLA) from the United States Department of Environmental Protection Agency related to contamination at the Keddy Mill Superfund Site in Windham, Maine that occurred in the 1960s and 1970s. The site had previously been owned by a CMP affiliate between 1941 and 1945. The letter notifies CMP of potential liability with respect to the site, informs CMP of planned remediation activities, and invites CMP to perform or finance those remediation activities. We are evaluating the allegations of liability and cannot predict the outcome of this matter.

Note 10. Post-retirement and Similar Obligations

During the three and nine months ended September 30, 2024, we made $18 million and $23 million of pension contributions, respectively. We expect to make additional contributions of $5 million for the remainder of 2024.

The components of net periodic benefit cost for pension benefits for the three and nine months ended September 30, 2024 and 2023, respectively, consisted of:


	Three Months Ended September 30,				Nine Months Ended September 30,
	2024		2023		2024		2023
(Millions)
Service cost	$	1	$	1	$	4	$	4
Interest cost	27		30		83		91
Expected return on plan assets	(38)		(36)		(119)		(109)
Amortization of:
Prior service costs	—		—		1		1
Actuarial loss	8		1		23		2
Settlement Charge	1		—		1		—

Net Periodic Benefit Credit	$	(1)	$	(4)	$	(7)	$	(11)

The components of net periodic benefit cost for postretirement benefits for the three and nine months ended September 30, 2024 and 2023, respectively, consisted of:


	Three Months Ended September 30,				Nine Months Ended September 30,
	2024		2023		2024		2023
(Millions)
Service cost	$	—	$	—	$	1	$	1
Interest cost	4		3		10		10
Expected return on plan assets	(1)		(1)		(3)		(4)
Amortization of:
Prior service costs	(1)		—		(1)		—
Actuarial gain	(1)		(3)		(4)		(9)
Net Periodic Benefit Credit (Cost)	$	1	$	(1)	$	3	$	(2)

Note 11. Equity

As of September 30, 2024 and December 31, 2023, we had, respectively, 99,125 and 103,889 shares of common stock held in trust and no convertible preferred shares outstanding. During the three and nine months ended September 30, 2024, we released 0 and 4,764 shares of common stock held in trust, respectively. During the three and nine months ended September 30, 2023, we released 0 and 4,299 shares of common stock held in trust, respectively.

We maintain a repurchase agreement with J.P. Morgan Securities, LLC. (JPM), pursuant to which JPM will, from time to time, acquire, on behalf of Avangrid, shares of common stock of Avangrid. The purpose of the stock repurchase program is to allow Avangrid to maintain Iberdrola's relative ownership percentage of approximately 81.5%. The stock repurchase program may be suspended or discontinued at any time upon notice. As of September 30, 2024, a total of 997,983 shares have been repurchased in the open market, all of which are included as Avangrid treasury shares. The total cost of all repurchases, including commissions, was $47 million as of September 30, 2024.

On September 26, 2024, the board of directors of Avangrid declared a quarterly dividend of $0.44 per share on its common stock. This dividend is payable on January 2, 2025 to shareholders of record at the close of business on December 2, 2024.

Accumulated Other Comprehensive Loss

Accumulated Other Comprehensive Loss for the three and nine months ended September 30, 2024 and 2023, respectively, consisted of:


	As of June 30,		Three Months Ended September 30,		As of September 30,		As of June 30,		Three Months Ended September 30,		As of September 30,
	2024		2024		2024		2023		2023		2023
(Millions)

Amortization of pension cost, net of income tax expense of $0 and $0 for 2024 and 2023			—						—
Net (loss) gain on pension plans	(20)		—		(20)		(18)		—		(18)
Unrealized gain (loss) from equity method investment, net of income tax (benefit) expense of $0 for 2024 and $0 for 2023 (a)	16		—		16		18		(1)		17
Unrealized (loss) gain during period on derivatives qualifying as cash flow hedges, net of income tax expense of $(6) for 2024 and $11 for 2023	(132)		(17)		(149)		(163)		30		(133)
Reclassification to net income of losses on cash flow hedges, net of income tax expense of $7 for 2024 and $15 for 2023 (b)	164		20		184		89		40		129
Gain (Loss) on derivatives qualifying as cash flow hedges	32		3		35		(74)		70		(4)
Accumulated Other Comprehensive Income (Loss)	$	28	$	3	$	31	$	(74)	$	69	$	(5)


	As of December 31,		Nine Months Ended September 30,		As of September 30,		As of December 31,		Nine Months Ended September 30,		As of September 30,
	2023		2024		2024		2022		2023		2023
(Millions)

Amortization of pension cost, net of income tax expense of $0 and $1 for 2024 and 2023			$	1					$	2
Net (loss) gain on pension plans	$	(21)	$	1	$	(20)	$	(20)	$	2	$	(18)
Unrealized gain (loss) from equity method investment, net of income tax (benefit) expense of $(1) for 2024 and $1 for 2023 (a)	$	18	$	(2)	$	16	$	13	$	4	$	17
Unrealized (loss ) gain during period on derivatives qualifying as cash flow hedges, net of income tax expense of $11 for 2024 and $22 for 2023	(178)		29		(149)		(195)		62		(133)
Reclassification to net income of losses on cash flow hedges, net of income tax expense of $10 for 2024 and $39 for 2023 (b)	156		28		184		22		107		129
(Loss) Gain on derivatives qualifying as cash flow hedges	(22)		57		35		(173)		169		(4)
Accumulated Other Comprehensive (Loss) Income	$	(25)	$	56	$	31	$	(180)	$	175	$	(5)

(a) Foreign currency and interest rate contracts.

(b) Reclassification is reflected in the operating expenses and interest expense, net of capitalization line items, respectively, in our condensed consolidated statements of income.

Note 12. Earnings Per Share

Basic earnings per share is computed by dividing net income attributable to Avangrid by the weighted-average number of shares of our common stock outstanding. During the three and nine months ended September 30, 2024 and 2023, while we did have securities that were dilutive, these securities did not result in a change in our earnings per share calculations for the both three and nine months ended September 30, 2024 and 2023.

The calculations of basic and diluted earnings per share attributable to Avangrid, for the three and nine months ended September 30, 2024 and 2023, respectively, consisted of:


	Three Months Ended September 30,				Nine Months Ended September 30,
	2024		2023		2024		2023
(Millions, except for number of shares and per share data)
Numerator:
Net income attributable to Avangrid	$	205	$	59	$	725	$	389
Denominator:
Weighted average number of shares outstanding - basic	387,010,149		386,869,341		386,978,958		386,788,279
Weighted average number of shares outstanding - diluted	387,434,841		387,322,281		387,322,300		387,122,498
Earnings per share attributable to Avangrid
Earnings Per Common Share, Basic	$	0.53	$	0.15	$	1.87	$	1.00
Earnings Per Common Share, Diluted	$	0.53	$	0.15	$	1.87	$	1.00

Note 13. Segment Information

Our segment reporting structure uses our management reporting structure as its foundation to reflect how Avangrid manages the business internally and is organized by type of business. We report our financial performance based on the following two reportable segments:

•Networks: includes all of the energy transmission and distribution activities, any other regulated activity originating in New York and Maine and regulated electric distribution, electric transmission and gas distribution activities originating in Connecticut and Massachusetts. The Networks reportable segment includes nine rate regulated operating segments. These operating segments generally offer the same services distributed in similar fashions, have the same types of customers, have similar long-term economic characteristics and are subject to similar regulatory requirements, allowing these operations to be aggregated into one reportable segment.

•Renewables: activities relating to renewable energy, mainly wind energy generation and trading related with such activities.

The chief operating decision maker evaluates segment performance based on segment adjusted net income defined as net income adjusted to exclude mark-to-market earnings from changes in the fair value of derivative instruments, costs incurred related to the merger and other transactions, and accelerated depreciation from the repowering of wind farms and offshore contract provision.

Products and services are sold between reportable segments and affiliate companies at cost. Segment income, expense and assets presented in the accompanying tables include all intercompany transactions that are eliminated in our condensed consolidated financial statements. Refer to Note 4 - Revenue for more detailed information on revenue by segment.

Segment information as of and for the three and nine months ended September 30, 2024, consisted of:


Three Months Ended September 30, 2024	Networks		Renewables		Other (a)		Avangrid Consolidated
(Millions)
Revenue - external	$	1,669	$	413	$	1	$	2,083
Revenue - intersegment	2		—		(2)		—
Depreciation and amortization	189		135		3		327
Operating income (loss)	211		57		(14)		254
Earnings from equity method investments	4		—		—		4
Interest expense, net of capitalization	87		(2)		47		132
Income tax expense (benefit)	34		6		(21)		19
Adjusted net income (loss)	161		87		(37)		211


Nine Months Ended September 30, 2024	Networks		Renewables		Other (a)		Avangrid Consolidated
(Millions)
Revenue - external	$	5,276	$	1,147	$	—	$	6,423
Revenue - intersegment	3		—		(3)		—
Depreciation and amortization	554		374		7		935
Operating income (loss)	764		121		(23)		862
Earnings from equity method investments	12		3		—		15
Interest expense, net of capitalization	253		1		125		379
Income tax expense (benefit)	124		(17)		(55)		52
Adjusted net income (loss)	581		258		(98)		741
Capital expenditures	2,064		783		7		2,854
As of September 30, 2024
Property, plant and equipment	23,212		11,459		12		34,683
Equity method investments	196		864		—		1,060
Total assets	$	32,626	$	14,869	$	(762)	$	46,733

(a) Includes Corporate and intersegment eliminations.

Segment information for the three and nine months ended September 30, 2023 and as of December 31, 2023, consisted of:


Three Months Ended September 30, 2023	Networks		Renewables		Other (a)		Avangrid Consolidated
(Millions)
Revenue - external	$	1,587	$	387	$	—	$	1,974
Revenue - intersegment	—		—		—		—
Depreciation and amortization	175		123		5		303
Operating income (loss)	134		(45)		—		89
Earnings from equity method investments	3		(4)		—		(1)
Interest expense, net of capitalization	76		6		25		107
Income tax expense (benefit)	12		(27)		7		(8)
Adjusted net income (loss)	92		55		(42)		105


Nine Months Ended September 30, 2023	Networks		Renewables		Other (a)		Avangrid Consolidated
(Millions)
Revenue - external	$	4,935	$	1,092	$	—	$	6,027
Revenue - intersegment	1		—		(1)		—
Depreciation and amortization	524		338		6		868
Operating income (loss)	531		(46)		(5)		480
Earnings (losses) from equity method investments	11		(6)		—		5
Interest expense, net of capitalization	215		16		70		301
Income tax expense (benefit)	70		(87)		—		(17)
Adjusted net income (loss)	364		170		(100)		434
Capital expenditures	1,551		505		22		2,078
As of December 31, 2023
Property, plant and equipment	21,692		11,090		12		32,794
Equity method investments	186		532		—		718
Total assets	$	30,413	$	14,538	$	(962)	$	43,989

(a) Includes Corporate and intersegment eliminations.

Reconciliation of Adjusted Net Income to Net Income attributable to Avangrid for the three and nine months ended September 30, 2024 and 2023, respectively, is as follows:


	Three Months Ended September 30,				Nine Months Ended September 30,
	2024		2023		2024		2023
(Millions)
Adjusted Net Income Attributable to Avangrid, Inc.	$	211	$	105	$	741	$	434
Adjustments:
Mark-to-market earnings - Renewables (1)	18		(23)		18		(19)
Accelerated depreciation from repowering (2)	(10)		—		(16)		—
Merger and other transaction costs (3)	(12)		(1)		(18)		(2)
Offshore contract provision (4)	—		(40)		—		(40)
Income tax impact of adjustments	(2)		17		1		16
Net Income Attributable to Avangrid, Inc.	$	205	$	59	$	725	$	389

(1)Mark-to-market earnings relates to earnings impacts from changes in the fair value of Renewables' derivative instruments associated with electricity and natural gas.

(2)Represents the amount of accelerated depreciation derived from the repowering of wind farms in Renewables.

(3)Pre-merger and other transaction costs incurred.

(4)Costs incurred in connection with offshore contract provision.

Note 14. Related Party Transactions

We engage in related party transactions that are generally billed at cost and in accordance with applicable state and federal commission regulations.

Related party transactions for the three and nine months ended September 30, 2024 and 2023, respectively, consisted of:


Three Months Ended September 30,	2024				2023
(Millions)	Sales To		Purchases From		Sales To		Purchases From
Iberdrola, S.A.	$	—	$	(16)	$	—	$	(8)
Iberdrola Renovables Energía, S.L.	$	—	$	—	$	—	$	(2)
Iberdrola Financiación, S.A.	$	—	$	(32)	$	—	$	(12)
Vineyard Wind	$	4	$	—	$	2	$	—

Other	$	—	$	—	$	—	$	(1)


Nine Months Ended September 30,	2024				2023
(Millions)	Sales To		Purchases From		Sales To		Purchases From
Iberdrola, S.A.	$	—	$	(44)	$	—	$	(34)
Iberdrola Renovables Energía, S.L.	$	—	$	(1)	$	—	$	(5)
Iberdrola Financiación, S.A.	$	—	$	(74)	$	—	$	(20)
Vineyard Wind	$	10	$	—	$	6	$	—

Other	$	—	$	(1)	$	—	$	(1)

Related party balances as of September 30, 2024 and December 31, 2023, respectively, consisted of:


As of	September 30, 2024				December 31, 2023
(Millions)	Owed By		Owed To		Owed By		Owed To
Iberdrola	$	—	$	(38)	$	1	$	—
Iberdrola Renovables Energía, S.L.	$	—	$	(7)	$	4	$	—
Iberdrola Financiación, S.A.	$	—	$	(2,006)	$	—	$	(799)
Vineyard Wind	$	6	$	(8)	$	6	$	(8)
Iberdrola Solutions	$	—	$	—	$	—	$	(6)
Other	$	4	$	(5)	$	4	$	—

Transactions with Iberdrola relate predominantly to the provision and allocation of corporate services and management fees, and certain financing arrangements described below. 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.

There have been no guarantees provided or received for any related party receivables or payables. These balances are unsecured and are typically settled in cash. Interest is not charged on regular business transactions but is charged on outstanding loan balances. There have been no impairments or provisions made against any affiliated balances.

Avangrid optimizes its liquidity position as part of the Iberdrola Group and is a party to a liquidity agreement with a financial institution, along with certain members of the Iberdrola Group. Cash surpluses remaining after meeting the liquidity requirements of Avangrid and its subsidiaries may be deposited at the financial institution. Deposits, or credit balances, serve as collateral against the debit balances of other parties to the liquidity agreement. The balance at both September 30, 2024 and December 31, 2023, was $0.

Avangrid has a credit facility with Iberdrola Financiación, S.A.U., a subsidiary of Iberdrola. The facility has a limit of $750 million and matures on June 18, 2028. Avangrid pays a quarterly facility fee of 22.5 basis points (rate per annum) on the facility based on Avangrid’s current Moody’s and S&P ratings for senior unsecured long-term debt. As of both September 30, 2024 and December 31, 2023, there was no outstanding amount under this credit facility, respectively.

On July 19, 2023, we entered into an intra-group green term loan agreement with Iberdrola Financiación, S.A.U., a subsidiary of Iberdrola, with an aggregate principal amount of $800 million maturing on July 13, 2033 at an interest rate of 5.45%.

On June 13, 2024, we entered into an intra-group green loan agreement with Iberdrola Financiación, S.A.U., with an aggregate principal amount of $600 million maturing on September 13, 2027 at an interest rate of 5.48%.

On June 13, 2024, we entered into an additional intra-group green loan agreement with Iberdrola Financiación, S.A.U., with an additional aggregate principal amount of $600 million maturing on June 13, 2030 at an interest rate of 5.53%.

On September 16 2024, we entered into an intra-group green loan agreement with Iberdrola Financiación, S.A.U., with an aggregate principal amount of $600 million maturing on September 16, 2034 with an interest rate of 5.06%. The funding of this intra-group loan was received on October 1, 2024.

We had a bi-lateral demand note agreement with Iberdrola Solutions, LLC, which had notes payable balances of $0 and $6 million as of September 30, 2024 and December 31, 2023, respectively.

See Note 19 - Equity Method Investments for more information on transactions with our equity method investees.

Note 15. Other Financial Statement Items

Accounts receivable and unbilled revenue, net

Accounts receivable and unbilled revenues, net as of September 30, 2024 and December 31, 2023 consisted of:


As of	September 30, 2024		December 31, 2023
(Millions)
Trade receivables and unbilled revenues	$	1,529	$	1,749
Allowance for credit losses	(177)		(161)
Accounts receivable and unbilled revenues, net	$	1,352	$	1,588

The change in the allowance for credit losses for the three and nine months ended September 30, 2024 and 2023 consisted of:


	Three Months Ended September 30,				Nine Months Ended September 30,
(Millions)	2024		2023		2024		2023
As of Beginning of Period,	$	174	$	155	$	161	$	155
Current period provision	48		45		142		95
Write-off as uncollectible	(45)		(37)		(126)		(87)
As of September 30,	$	177	$	163	$	177	$	163

The Deferred Payment Arrangements (DPA) receivable balance was $153 million and $110 million at September 30, 2024 and December 31, 2023, respectively. The allowance for credit losses for DPAs at September 30, 2024 and December 31, 2023 was $73 million and $44 million, respectively. Furthermore, the change in the allowance for credit losses associated with the DPAs for the three and nine months ended September 30, 2024 was $10 million and $29 million, respectively, and for the three and nine months ended September 30, 2023 was $1 million and $6 million, respectively.

Prepayments and other current assets

Included in prepayments and other current assets are $220 million and $165 million of broker margin and collateral accounts as of September 30, 2024 and December 31, 2023, respectively. Also included in prepayments and other current assets are $205 million and $142 million of prepaid other taxes as of September 30, 2024 and December 31, 2023, respectively.

Property, plant and equipment and intangible assets

The accumulated depreciation and amortization as of September 30, 2024 and December 31, 2023, respectively, were as follows:


As of	September 30, 2024		December 31, 2023
(Millions)
Property, plant and equipment
Accumulated depreciation	$	13,273	$	12,479
Intangible assets
Accumulated amortization	$	368	$	351

As of September 30, 2024 and 2023, accrued liabilities for property, plant and equipment additions were $598 million and $469 million, respectively.

Assets held for sale

Included in prepayments and other current assets are $66 million and $63 million assets held for sale, as of September 30, 2024 and December 31, 2023, respectively, related to the sale of Kitty Hawk North, LLC. On July 8, 2024, Avangrid entered into an agreement to sell the Kitty Hawk North, LLC related 40,000-acre federal offshore lease OCS-A 0559 and associated assets for approximately $158 million. This transaction is subject to customary closing conditions and is expected to close in the fourth quarter of 2024.

Debt

Commercial Paper

As of September 30, 2024 and December 31, 2023, there was $1,928 million and $1,332 million of commercial paper outstanding, respectively. As of September 30, 2024 and December 31, 2023, the weighted-average interest rate on commercial paper was 5.10% and 5.65%, respectively.

Supplier Financing Arrangements

We operate a supplier financing arrangement. We arranged for the extension of payment terms with some suppliers, which could elect to be paid by a financial institution earlier than maturity under supplier financing arrangements. Due to the interest cost associated with these arrangements, the balances are classified as "Notes payable" on our consolidated balance sheets. The balance relates to capital expenditures and, therefore, is treated as non-cash activity, and is reported under financing activity of the consolidated statement of cash flows when the balance is paid. As of September 30, 2024 and December 31, 2023, the amount of notes payable under supplier financing arrangements was $5 million and $0, respectively. As of September 30, 2024, the weighted average interest rate on this balance was 6.29%.

Group Cash Pool

We are a party to a liquidity agreement with Bank of America, N.A. along with certain members of the Iberdrola Group. The liquidity agreement aids the Iberdrola Group in efficient cash management and reduces the need for external borrowing by the pool participants. Parties to the agreement, including us, may deposit funds with or borrow from the financial institution, provided that the net balance of funds deposited or borrowed by all pool participants in the aggregate is not less than zero. As of September 30, 2024 and December 31, 2023, the balance was $304 million and $0, respectively. As of September 30, 2024, the weighted average interest rate on the balance was 5.45%. Any deposit amounts would be reflected in our consolidated balance sheets under cash and cash equivalents because our deposited surplus funds under the cash pooling agreement are highly-liquid short-term investments.

Note 16. Income Tax Expense

The effective tax rates, inclusive of federal and state income tax, for the three and nine months ended September 30, 2024, were 9.9% and 7.7%, respectively, and below the federal statutory tax rate of 21%, primarily due to the recognition of production tax credits associated with wind production, the effect of the excess deferred tax amortization resulting from the Tax Act (including an adjustment prompted by recently released IRS private letter rulings (“PLRs”)), the equity component of allowance for funds used during construction, and other property related flow through items, partially offset by the effects of tax equity financing impacts, state taxes, and prior year tax provision to return adjustments.

The effective tax rates, inclusive of federal and state income tax, for the three and nine months ended September 30, 2023, were (34.8)% and (6.1)%, respectively, and below the federal statutory tax rate of 21%, primarily due to the recognition of production tax credits associated with wind production, the effect of the excess deferred tax amortization resulting from the Tax Act, the equity component of allowance for funds used during construction and other property related flow through items.

In the third quarter of 2023, Avangrid executed an agreement to transfer the production tax credits generated in 2023 pursuant to the transferability provisions of the Inflation Reduction Act of 2022. Avangrid received cash of $62 million for the transfer of tax credits in the nine months ended September 30, 2023.

Note 17. Stock-Based Compensation Expense

The Avangrid, Inc. Amended and Restated Omnibus Incentive Plan (the Plan) provides for, among other things, the issuance of performance stock units (PSUs), restricted stock units (RSUs) and phantom share units (Phantom Shares).

Performance Stock Units

In March 2023, a total number of 677,752 PSUs, before applicable taxes, were approved to be earned by participants based on achievement of certain performance and market-based metrics for the 2021 to 2022 performance period and are payable in three

equal installments, net of applicable taxes, in 2023, 2024 and 2025. The remaining unvested PSUs were forfeited. The second installment was paid in March 2024, and 126,311 shares of common stock were issued to settle this installment payment.

During 2023 and 2024, 1,067,500 and 15,296 PSUs, respectively, were granted to certain executives of Avangrid with achievement measured based on certain performance and market-based metrics for the 2023 to 2025 performance period. The PSUs will be payable in three equal installments, net of applicable taxes, in 2026, 2027 and 2028.

Restricted Stock Units

In June 2022, 25,000 RSUs were granted to an officer of Avangrid. The RSUs vest in two equal installments in 2023 and 2024, provided that the grantee remains continuously employed with Avangrid through the applicable vesting dates. The fair value on the grant date was determined based on a price of $47.64 per share. The second and final installment of this RSU grant was settled in January 2024, net of applicable taxes, by issuing 9,034 shares of common stock.

Phantom Share Units

In February 2022, 9,000 Phantom Shares were granted to certain Avangrid executives and employees. These awards vest in four equal installments in 2022 - 2024 and will be settled in a cash amount equal to the number of Phantom Shares multiplied by the closing share price of Avangrid’s common stock on the respective vesting dates, subject to continued employment. The liability of these awards is measured based on the closing share price of Avangrid’s common stock at each reporting date until the date of settlement. In February 2024, $0.1 million was paid to settle the fourth and final installment under this plan.

In February 2023, 81,000 Phantom Shares were granted to certain Avangrid executives and employees. These awards vest in three equal installments in 2024, 2025 and 2026 and will be settled in a cash amount equal to the number of Phantom Shares multiplied by the closing share price of Avangrid’s common stock on the respective vesting dates, subject to continued employment. The liability of these awards is measured based on the closing share price of Avangrid’s common stock at each reporting date until the date of settlement. In February 2024, $1.0 million was paid to settle the first installment under this plan.

As of September 30, 2024 and December 31, 2023, the total liability was $1 million and $2 million, respectively, which is included in other current and non-current liabilities.

The total stock-based compensation expense, which is included in "Operations and maintenance" in our condensed consolidated statements of income, for the three and nine months ended September 30, 2024 was $3 million and $9 million, respectively, and for the three and nine months ended September 30, 2023 was $4 million and $11 million, respectively.

Note 18. Variable Interest Entities

We participate in certain partnership arrangements that qualify as VIEs. These arrangements consist of tax equity financing arrangements (TEFs) and partnerships in which an investor holds a noncontrolling interest and does not have substantive kick-out or participating rights.

The sale of a membership interest in the TEFs represents the sale of an equity interest in a structure that is considered a sale of non-financial assets. Under the sale of non-financial assets, the membership interests in the TEFs we sell to third-party investors are reflected as noncontrolling interest on our condensed consolidated balance sheets valued based on an HLBV model. Earnings from the TEFs are recognized in net income attributable to noncontrolling interests in our condensed consolidated statements of income. We consolidate the entities that have TEFs based on being the primary beneficiary for these VIEs.

The assets and liabilities of the VIEs totaled approximately $2,678 million and $192 million, respectively, at September 30, 2024. As of December 31, 2023, the assets and liabilities of VIEs totaled approximately $2,741 million and $174 million, respectively. At September 30, 2024 and December 31, 2023, the assets and liabilities of the VIEs consisted primarily of property, plant and equipment.

Wind and solar power generation are subject to certain favorable tax treatments in the U.S. In order to monetize the tax benefits, we have entered into these structured institutional partnership investment transactions related to certain wind and solar farms. Under these structures, we contribute certain wind / solar assets, relating both to existing wind farms and wind farms / solar facilities that are being placed into operation at the time of the relevant transaction, and other parties invest in the share equity of the limited liability holding company. As consideration for their investment, the third parties make either an upfront cash payment or a combination of upfront cash and payments over time. We retain a class of membership interest and day-to-day operational and management control, subject to investor approval of certain major decisions. The third-party investors do not receive a lien on any assets and have no recourse against us for their upfront cash payments.

The partnerships generally involve disproportionate allocations of profit or loss, cash distributions and tax benefits resulting from the wind farm energy generation between the investor and sponsor until the investor recovers its investment and achieves

a targeted cumulative annual after-tax return. Once this target return is met, the relative sharing of profit or loss, cash distributions and taxable income or loss between the Company and the third party investor flips, with the sponsor generally receiving higher percentages thereafter. We also have a call option to acquire the third party investors’ membership interest within a defined time period after this target return is met.

At September 30, 2024, El Cabo Wind, LLC (El Cabo), Patriot Wind Farm LLC (Patriot), Aeolus Wind Power VII, LLC (Aeolus VII), Aeolus VIII, and Solis I are our consolidated VIEs.

Our El Cabo, Patriot, Aeolus VII, Aeolus VIII, and Solis I interests are not subject to any rights of investors that may restrict our ability to access or use the assets or to settle any existing liabilities associated with the interests.

See Note 19 - Equity Method Investments for information on our VIE that we do not consolidate.

Note 19. Equity Method Investments

Renewables holds a 50% indirect ownership interest in Vineyard Wind 1, LLC (Vineyard Wind 1), a joint venture with Copenhagen Infrastructure Partners (CIP). Prior to a restructuring transaction that took place on January 10, 2022 (Restructuring Transaction), Renewables held a 50% ownership interest in Vineyard Wind, LLC (Vineyard Wind) which held rights to two easements from the U.S. Bureau of Ocean Energy Management (BOEM) for the development of offshore wind generation, Lease Area 501 which contained 166,886 acres and Lease Area 522 which contained 132,370 acres, both located southeast of Martha’s Vineyard. Lease Area 501 was subdivided in 2021, creating Lease Area 534. On September 15, 2021, Vineyard Wind closed on construction financing for the Vineyard Wind 1 project. Among other items, the Vineyard Wind 1 project was transferred into a separate joint venture, Vineyard Wind 1. Following the Restructuring Transaction, Vineyard Wind 1 remained a 50-50 joint venture and kept the rights to develop Lease Area 501, and Vineyard Wind was effectively dissolved where Renewables received rights to the Lease Area 534 and CIP received rights to Lease Area 522 as liquidating distributions. In contemplation of the liquidating distributions, Renewables also made an incremental payment of approximately $168 million to CIP in 2022.

Concurrently with the closing on the construction financing for the Vineyard Wind 1 project, Renewables entered into a credit agreement with certain banks to provide future term loans and letters of credit up to a maximum of approximately $1.2 billion to finance a portion of its share of the cost of Vineyard Wind 1 at the maturity of the Vineyard Wind 1 project construction loan. Any term loans mature by October 15, 2031, subject to certain extension provisions. Renewables also entered into an Equity Contribution Agreement in which Renewables agreed to, among other things, make certain equity contributions to fund certain costs of developing and constructing the Vineyard Wind 1 project in accordance with the credit agreement. In addition, we issued a guaranty up to $827 million for Renewables' equity contributions under the Equity Contribution Agreement. As part of the Vineyard Wind 1 financial close, $152 million of Renewables prior contributions for the Vineyard Wind 1 project were returned in 2021.

On October 24, 2023, Vineyard Wind 1 closed on a TEF agreement, pursuant to which Vineyard Wind 1 is expected to receive approximately $1.2 billion from tax equity investors in installments based on the number of turbines reaching or about to reach mechanical completion each month until the entire project reaches commercial operation date. Vineyard Wind 1 received the initial funding of $85 million from tax equity investors in 2023. On May 29, 2024, Vineyard Wind 1 received the second funding of $22 million from tax equity investors. The remaining $1.1 billion is expected to be received in 2024 and 2025. In conjunction with the equity installments received since the closing of the TEF agreement, we have issued an indemnification of our joint share of the investor contributions. As of September 30, 2024 and December 31, 2023, our total indemnified amount was $54 million and $43 million, respectively.

Vineyard Wind 1 is considered a VIE because it cannot finance its activities without additional support from its owners or third parties. Renewables is not the primary beneficiary of the entity since it does not have a controlling financial interest, and therefore we do not consolidate this entity. During 2024, Renewables made a capital contribution of $328 million to Vineyard Wind 1. As of September 30, 2024 and December 31, 2023, the carrying amount of Renewables' investments in Vineyard Wind 1, LLC and Vineyard Wind 1 Pledgor LLC was $643 million and $297 million, respectively.

Note 20. Subsequent Event

On October 23, 2024, Avangrid entered into a sale-leaseback financing transaction for the Daybreak Solar project, pursuant to which Avangrid received approximately $200 million of net proceeds.

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

You should read the following discussion of our financial condition and results of operations in conjunction with the condensed consolidated financial statements and the notes thereto included elsewhere in this Quarterly Report on Form 10-Q and with our audited consolidated financial statements as of December 31, 2023 and 2022, and for the three years ended December 31, 2023, included in our Annual Report on Form 10-K for the year ended December 31, 2023, filed with the Securities and Exchange Commission, or the SEC, on February 22, 2024 and amended by Amendment No. 1 to our Annual Report on Form 10-K for the year ended December 31, 2023, filed with the SEC on April 26, 2024, which we refer to as our “Form 10-K.” In addition to historical condensed consolidated financial information, the following discussion contains forward-looking statements that reflect our plans, estimates and beliefs. Our actual results could differ materially from those discussed in the forward-looking statements. The foregoing and other factors are discussed and should be reviewed in our Form 10-K and other subsequent filings with the SEC.

Overview

Avangrid aspires to be the leading sustainable energy company in the United States. Our purpose is to work every day to deliver a more accessible clean energy model that promotes healthier, more sustainable communities. A commitment to sustainability is firmly entrenched in the values and principles that guide Avangrid, with environmental, social, governance and financial sustainability key priorities driving our business strategy.

Avangrid has approximately $47 billion in assets and operations in 24 states concentrated in our two primary lines of business - Avangrid Networks and Avangrid Renewables. Avangrid Networks owns eight electric and natural gas utilities, serving approximately 3.3 million customers in New York and New England. Avangrid Renewables owns and operates 10.0 gigawatts of electricity capacity, primarily through wind and solar power, with a presence in 22 states across the United States. Avangrid supports the achievement of the Sustainable Development Goals approved by the member states of the United Nations, was named among the World’s Most Ethical companies in 2024 for the sixth consecutive year by the Ethisphere Institute and recognized by Just Capital as one of the 2024 Just 100, an annual ranking of the most just U.S. public companies for the fourth time. Avangrid employs approximately 8,000 people. Iberdrola S.A., or Iberdrola, a corporation (sociedad anónima) organized under the laws of the Kingdom of Spain, a worldwide leader in the energy industry, directly owns 81.6% of the outstanding shares of Avangrid common stock. The remaining outstanding shares are owned by various shareholders with approximately 14.7% of Avangrid's outstanding shares publicly-traded on the New York Stock Exchange (NYSE). Avangrid's primary businesses are described below.

Our direct, wholly-owned subsidiaries include Avangrid Networks, Inc., or Networks, and Avangrid Renewables Holdings, Inc., or ARHI. ARHI in turn holds subsidiaries including Avangrid Renewables, LLC, or Renewables. Networks owns and operates our regulated utility businesses through its subsidiaries, including electric transmission and distribution and natural gas distribution, transportation and sales. Renewables operates a portfolio of renewable energy generation facilities primarily using onshore wind power and also solar, biomass and thermal power.

Through Networks, we own electric distribution, transmission and generation companies and natural gas distribution, transportation and sales companies in New York, Maine, Connecticut and Massachusetts, delivering electricity to approximately 2.3 million electric utility customers and delivering natural gas to approximately 1.0 million natural gas utility customers as of September 30, 2024.

Networks, a Maine corporation, holds regulated utility businesses, including electric transmission and distribution and natural gas distribution, transportation and sales. Networks serves as a super-regional energy services and delivery company through the eight regulated utilities it owns directly:

•New York State Electric & Gas Corporation, or NYSEG, which serves electric and natural gas customers across more than 40% of the upstate New York geographic area;

•Rochester Gas and Electric Corporation, or RG&E, which serves electric and natural gas customers within a nine-county region in western New York, centered around Rochester;

•The United Illuminating Company, or UI, which serves electric customers in southwestern Connecticut;

•Central Maine Power Company, or CMP, which serves electric customers in central and southern Maine;

•The Southern Connecticut Gas Company, or SCG, which serves natural gas customers in Connecticut;

•Connecticut Natural Gas Corporation, or CNG, which serves natural gas customers in Connecticut;

•The Berkshire Gas Company, or BGC, which serves natural gas customers in western Massachusetts; and

•Maine Natural Gas Corporation, or MNG, which serves natural gas customers in several communities in central and southern Maine.

Renewables has a combined wind, solar and thermal installed capacity of 10,037 megawatts, or MW, as of September 30, 2024, including Renewables’ share of joint projects, of which 8,045 MW was installed onshore wind capacity, 1,201 MW of installed solar capacity and 156 MW of offshore. Renewables targets to contract or hedge above 80% of its capacity under long-term PPAs and hedges to limit market volatility. As of September 30, 2024, approximately 77% of the capacity was contracted with PPAs for an average period of approximately 10 years and an additional 9% of production was hedged. Avangrid is one of the three largest wind operators in the United States based on installed capacity as of December 31, 2023, and strives to lead the transformation of the U.S. energy industry to a sustainable, competitive, clean energy future. Renewables installed capacity includes 68 onshore wind farms and seven solar facilities operational and one offshore wind facility in 21 states across the United States.

Agreement and Plan of Merger

Business Environment

The impact of extraordinary external events such as global pandemics and geopolitical instability continue to cause global economic and supply chain disruption and volatility in financial markets and the United States economy. We continue to experience changes in inflation levels resulting from various supply chain disruptions, increased business and labor costs, increased financing costs from changes in the Federal Reserve's monetary policy and other disruptions caused by global economic conditions. We continue to take steps intended to mitigate the potential risks from continued conflict, including without limitation, communication with suppliers to ensure that the supply chains are free from sanctioned materials and efforts to diversify sourcing and capacity planning to help avoid supply chain disruptions. To date, there has been no material impact on our operations or financial performance as a result of ongoing extraordinary events including, without limitation, the conflicts in Eastern Europe and the Middle East; however, we cannot predict the extent of these effects, given the evolving nature of the geopolitical situation, on our business, results of operations or financial condition.

For more information, see the risk factors in Item 1A. Risk Factors in our Form 10-K for the year ended December 31, 2023 and in this Quarterly Report on Form 10-Q.

Summary of Results of Operations

Our operating revenues increased by $109 million from $1,974 million for the three months ended September 30, 2023 to $2,083 million for the three months ended September 30, 2024.

Networks business revenues increased mainly due to rate increases in New York effective October 12, 2023. Renewables revenues increased mainly due to increases in merchant prices driven by higher average prices and favorable MtM changes on energy derivative transactions entered for economic hedging purposes in the current period.

Net income attributable to Avangrid increased by $146 million from $59 million for the three months ended September 30, 2023 to $205 million for the three months ended September 30, 2024, primarily driven by rate increases in New York and lower operating expenses in Renewables in the period, driven mainly by offshore contract provisions recorded in the same period of 2023.

Adjusted net income (a non-GAAP financial measure) increased by $106 million from $105 million for the three months ended September 30, 2023 to $211 million for the three months ended September 30, 2024. The increase is primarily due to a $68 million increase in Networks driven primarily by rate increases in New York effective October 12, 2023, a $32 million increase in Renewables primarily driven by favorable impact in power and gas purchases due to lower average prices in the period and a $5 million increase in Corporate mainly driven by favorable taxes from applying the annual consolidated estimated tax rate, offset by higher interest expenses in the period.

For additional information and reconciliation of the non-GAAP adjusted net income to net income attributable to Avangrid, see “—Non-GAAP Financial Measures”.

See “—Results of Operations” for further analysis of our operating results for the quarter.

Legislative and Regulatory Update

We are subject to complex and stringent energy, environmental and other laws and regulations at the federal, state and local levels as well as rules within the independent system operator, or ISO, markets in which we participate. Federal and state legislative and regulatory actions continue to change how our business is regulated. We actively participate in the regulatory process at the federal, regional, state and ISO levels. Significant updates are discussed below. For a further discussion of the environmental and other governmental regulations that affect us, see our Form 10-K for the year ended December 31, 2023.

New England Clean Energy Connect

In 2018, the New England Clean Energy Connect, or NECEC, transmission project, proposed in a joint bid by CMP and Hydro-Québec, was selected by the Massachusetts electric distribution utilities, or EDCs, and the DOER in the Commonwealth of Massachusetts’s 83D clean energy Request for Proposal. The NECEC transmission project includes a 145-mile transmission line linking the electrical grids in Québec, Canada and New England. The project, which has estimated construction costs of approximately $1.5 billion in total, would add 1,200 MW of transmission capacity to supply Maine and the rest of New England with power from reliable hydroelectric generation.

On June 13, 2018, CMP entered into transmission service agreements, or TSAs, with the Massachusetts EDCs, and H.Q. Energy Services (U.S.) Inc., or HQUS, an affiliate of Hydro-Québec, which govern the terms of service and revenue recovery for the NECEC transmission project. Simultaneous with the execution of the TSAs with CMP, the EDCs executed certain PPAs with HQUS for sales of electricity and environmental attributes to the EDCs. On October 19, 2018, FERC issued an order accepting the TSAs for filing as CMP rate schedules effective as of October 20, 2018. On June 25, 2019, the Massachusetts DPU issued an Order approving the NECEC project long term PPAs and the cost recovery by the EDCs of the TSA charges. This Order was subsequently appealed by NextEra Energy Resources. On September 3, 2020, the Massachusetts Supreme Judicial Court denied NextEra Energy Resources’ appeal of the DPU Order.

The NECEC project requires a Certificate of Public Convenience and Necessity, or CPCN, from the MPUC. On May 3, 2019, the MPUC issued an Order granting the CPCN for the NECEC project. This Order was subsequently appealed by NextEra Energy Resources. On March 17, 2020, the Maine Law Court denied NextEra Energy Resources’ appeal of the CPCN.

On January 4, 2021, CMP transferred the NECEC project to NECEC Transmission LLC, a wholly-owned subsidiary of Networks, pursuant to the terms of a transfer agreement dated November 3, 2020.

The NECEC project requires certain permits, including environmental, from multiple state and federal agencies and a presidential permit from the U.S. Department of Energy, or DOE, authorizing the construction, operation, maintenance and connection of facilities for the transmission of electric energy at the international border between the United States and Canada. On January 8, 2020, the Maine Land Use Planning Commission, or LUPC, granted the LUPC Certification for the NECEC. The Maine Department of Environmental Protection, or MDEP, granted Site Location of Development Act, Natural Resources Protection Act, and Water Quality Certification permits for the NECEC by an Order dated May 11, 2020. The MDEP Order was appealed by certain intervenors. Through an Order dated July 21, 2022, the Maine Board of Environmental Protection, or MBEP, denied the appeals of the MDEP Order, as well as the appeal of MDEP’s December 4, 2020 Order approving the partial transfer of the permits for the project to NECEC Transmission LLC. In August 2022, the intervenors that had appealed the MDEP Order appealed the MBEP Order, and these appeals have all been dismissed.

On November 6, 2020, the project received the required approvals from the U.S. Army Corps of Engineers, or Army Corps, pursuant to Section 10 of the Rivers and Harbor Act of 1899 and Section 404 of the Clean Water Act. A complaint for declaratory and injunctive relief asking the court to, among other things, vacate or remand the Section 404 Clean Water Act permit for the NECEC project filed by three environmental groups is currently pending before the District Court in Maine. We cannot predict the outcome of this proceeding.

ISO-NE issued the final System Impact Study (SIS) for NECEC on May 13, 2020, determining the upgrades required to permit the interconnection of NECEC to the ISO-NE system. On July 9, 2020, the project received the formal I.3.9 approval associated with this interconnection request. CMP, NECEC Transmission LLC and ISO-NE executed an interconnection agreement. With respect to the upgrade required at the Seabrook Nuclear Generation Station, or Seabrook Station, on February 1, 2023, FERC issued an order granting in part Avangrid and NECEC Transmission LLC’s complaint against NextEra Energy Resources, LLC and NextEra Energy Seabrook, LLC, or Seabrook, denying in part Avangrid and NECEC Transmission LLC’s complaint, and dismissing Seabrook’s petition for declaratory order. Among other things, FERC directed Seabrook to replace the breaker at Seabrook Station pursuant to its obligations under Seabrook Station’s large generator interconnection agreement and good utility practice. Furthermore, FERC determined that Seabrook should not recover opportunity or legal costs in connection with the breaker replacement. NextEra sought reconsideration of FERC’s decision, which was denied in April 2023 and by further FERC order in June 2023. NextEra appealed that decision to the U.S. Court of Appeals for the D.C. Circuit and on October 4, the Court affirmed FERC's decision and denied NextEra's petition.

On January 14, 2021, the DOE issued a Presidential Permit granting permission to NECEC Transmission LLC to construct, operate, maintain and connect electric transmission facilities at the international border of the United States and Canada. On March 26, 2021, the plaintiffs challenging the Army Corps permit filed a motion for leave before the District Court in Maine to supplement their complaint to add claims against DOE in connection with the Presidential Permit. On April 20, 2021, the District Court granted the plaintiffs motion to amend the complaint. On April 22, 2021, the plaintiffs filed their amended complaint asking the Court, among other things, to vacate, set aside, remand or stay the Presidential Permit. This challenge to the Presidential Permit is currently pending before the District Court in Maine. We cannot predict the outcome of this proceeding.

On November 2, 2021, Maine voters approved, by virtue of a referendum, L.D. 1295 (I.B. 1) (130th Legis. 2021), “An Act To Require Legislative Approval of Certain Transmission Lines, Require Legislative Approval of Certain Transmission Lines and Facilities and Other Projects on Public Reserved Lands and Prohibit the Construction of Certain Transmission Lines in the Upper Kennebec Region” (the “Initiative”), which per its terms would retroactively apply to the NECEC project.

On November 3, 2021, Networks and NECEC Transmission LLC filed a lawsuit challenging the constitutionality of the Initiative and requesting injunctive relief preventing retroactive enforcement of the Initiative to the NECEC transmission project. Networks and NECEC Transmission LLC also requested a preliminary injunction preventing such retroactive enforcement during the pendency of the lawsuit, which was ultimately denied. The Initiative took effect on December 19, 2021.

On December 22, 2021, Networks and NECEC Transmission LLC moved that the Business & Consumer Court report its decision to the Maine Law Court for an interlocutory appeal under the applicable rule of appellate procedure. The Business & Consumer Court granted this motion, thereby sending its decision to the Law Court for review. On August 30, 2022, the Law Court ruled that certain Initiative provisions would infringe on NECEC’s constitutionally protected vested rights if NECEC Transmission LLC can demonstrate that it engaged in substantial construction of the NECEC project in good-faith reliance of the authority under the CPCN granted by the MPUC before Maine voters approved the Initiative. The Maine Law Court remanded the matter to the Business & Consumer Court for a trial to determine that question. The trial began on April 10, 2023 and concluded on April 20, 2023, when the jury reached a unanimous decision finding that NECEC had constructed substantial construction in good faith. The Court subsequently entered an Order that NECEC had obtained vested rights to continue work on the project, and that retroactively applying the Initiative to the NECEC project would violate the Maine Constitution. No party appealed that decision.

In connection with the lease granted by BPL over a small area of Maine public lands to house a 0.9-mile section of the NECEC, on November 29, 2022, the Law Court vacated the trial court’s prior decision to reverse BPL’s decision to grant the lease.

On August 3, 2023, NECEC resumed limited construction and is continuing to evaluate the construction schedule for the NECEC project, related commercial operation date, and total project cost, including potential impacts from increased construction costs, disputes with third party vendors regarding contracts and certain change orders, and a decrease in expected returns. As of September 30, 2024, we have capitalized approximately $1,294 million for the NECEC project, which includes capitalized interest costs and other additional payments related to the project along with construction costs.

At the municipal level, the project has obtained all approvals.

PURA Investigation of the Preparation for and Response to the Tropical Storm Isaias and Connecticut Storm Reimbursement Legislation

Power Tax Audits

Previously, CMP, NYSEG and RG&E implemented Power Tax software to track and measure their respective deferred tax amounts. In connection with this change, we identified historical updates needed with deferred taxes recognized by CMP, NYSEG and RG&E and increased our deferred tax liabilities, with a corresponding increase to regulatory assets, to reflect the updated amounts calculated by the Power Tax software. Since 2015, the NYPSC and MPUC accepted certain adjustments to deferred taxes and associated regulatory assets for this item in recent distribution rate cases, resulting in regulatory asset balances of approximately $126 million and $130 million, respectively, for this item at September 30, 2024 and December 31, 2023.

CMP began recovering its regulatory asset in 2020. In 2017, the NYPSC commenced an audit of the power tax regulatory assets. On January 11, 2018, the NYPSC issued an order opening an operations audit of NYSEG and RG&E and certain other New York utilities regarding tax accounting. In September 2023, NYSEG and RG&E received the NYPSC final audit report and in October 2023 we responded with comments and a request for certain clarifications. The report includes recommendations that are primarily intended to enhance existing practices. The NYPSC audit process was completed and the final audit report issued by the Commission on November 21, 2023 with no impacts to the recorded regulatory assets.

SEC's Climate Disclosure Rule

On March 6, 2024, the SEC issued a final rule that requires registrants to provide climate-related disclosures in their annual reports and registration statements, beginning with annual reports for the year ending December 31, 2025, for calendar-year-end large accelerated filers. On April 4, 2024, the SEC announced to voluntarily delay the implementation of climate disclosure regulations while going through certain legal challenges filed to vacate the proposed rules.

The new rules include disclosures relating to climate-related risks and risk management as well as the board and management’s governance of such risks. In addition, the rules include requirements to disclose the financial effects of severe weather events and other natural conditions in the audited financial statements. Larger registrants will also be required to disclose information about greenhouse gas emissions, which will be subject to a phased-in assurance requirement. We are

currently evaluating the new rules and their impact to our systems, processes, and controls for gathering and reporting of these incremental disclosures.

Anti-Circumvention Petition

We are monitoring the Department of Commerce's, or DOC, anti-circumvention determination made on August 18, 2023 finding that producers shipping solar panels and cells from Vietnam, Thailand, Malaysia and Cambodia may have circumvented tariffs imposed on Chinese solar panels and cells. Anti-dumping and countervailing duties began being applied to producers found to be circumventing on June 6, 2024 after the end of the Biden Administration’s 24-month tariff exemption. Panels imported before June 6, 2024, that entered under the moratorium must be “used or installed” by December 3, 2024. On April 24, 2024, several solar manufacturers filed a new petition to launch an anti-dumping and countervailing duties (CVD) investigation applicable to manufacturers of solar cells and modules operating in the same four Southeast Asian countries (Cambodia, Malaysia, Thailand and Vietnam). On October 1, 2024, the DOC announced its preliminary affirmative determinations in the CVD investigations of crystalline photovoltaic cells whether or not assembled into modules (solar cells) from these companies. The DOC is conducting concurrent anti-dumping duty investigations of solar cells from Cambodia, Malaysia, Thailand and Vietnam. A final determination from the DOC on anti-dumping is expected before year end. To date, there has been no material impact on Renewables' operations or financial performance as a result of either the anti-circumvention determination or the new investigation. Despite mitigation actions, there is uncertainty around related long-term effects to the solar panel supply chain and we cannot predict if there will be materially adverse impacts to our business, results of operations or financial condition.

201 Tariff bifacial exclusion

The bifacial exclusion from 201 tariffs on imported solar panels was ended via Presidential proclamation on June 21, 2024. Beginning September 24, 2024, bifacial panels entering the US will face a tariff rate of 14.25% until February 2025 and 14.00% until February 2026, with certain exceptions granted to a subset of developing countries of origin. To date, there has been no material impact on Renewables' operations or financial performance as a result of this tariff. Currently, mitigation actions are being taken however there is uncertainty around related long-term impacts, and we cannot predict if there will be materially adverse impacts to our business, results of operations or financial condition.

New York Climate Leadership and Community Protection Act

On February 16, 2023, the NYPSC issued an order to authorize transmission upgrades solely to support new renewable generation sources pursuant to the implementation of the Accelerated Renewable Growth and Community Benefit Act as part of the Climate Leadership and Community Protection Act (CLCPA) Phase 2. The order approves an estimated $4.4 billion in transmission upgrades proposed by upstate utilities to help integrate 3,500 MW of clean energy capacity into the grid, of which NYSEG and RG&E are approved for estimated upgrade costs of $2.2 billion, including participation with other upstate utilities on certain projects. On October 17, 2023, NYSEG and RG&E filed a petition requesting approval from the NYPSC to seek authorization from the Federal Energy Regulatory Commission, or FERC, to utilize 100 percent construction work in progress, or CWIP, in rate base for the local transmission upgrades under the CLCPA Phase 2. On April 18, 2024, the NYPSC approved the petition to allow NYSEG and RG&E to seek FERC approval along with adding other related reporting requirements. On July 5, 2024, FERC conditionally accepted NYSEG and RG&E’s application for CWIP and the 100% Abandoned Plant incentive (Abandoned Plant), subject to further compliance, for projects that are subject to subsequent permitting approval by the NYPSC under Article VII of New York State’s Public Service Law, effective July 8, 2024, and denied the application for CWIP and Abandoned Plant for projects not subject to Article VII permitting approval. On August 2, 2024, NYSEG and RG&E sought clarification, or in the alternative rehearing, of the July 5, 2024 order. Rehearing was denied after 30 days by operation of law, and the order denying rehearing states that the issue will be addressed in a future order. On October 1, FERC ruled on NYSEG and RG&E’s request for clarification/rehearing. FERC confirmed that any projects that receive state siting approval orders that include the required reliability and/or congestion reduction determinations can qualify for incentives, not limited to the projects listed in the July order as Article VII projects. FERC denied clarification and rehearing to include CWIP in rate base prior to FERC’s acceptance of the state siting orders.

UI RAM Proceeding

On March 1, 2024, UI submitted its 2023 comprehensive rate adjustment mechanism, or RAM, filing detailing the UI’s calculated over- or under-recoveries for the RAM components for the period of January 1, 2023, through December 31, 2023 (RAM Application) to PURA. The RAM Application detailed the UI’s proposed weighted-average rate adjustments associated with such over- or under-recoveries of the RAM components.

PURA held a noticed public hearing on this matter on March 11, 2024, and on March 28, 2024, a proposed interim decision was issued in this proceeding to provide an opportunity for the parties and intervenors to file written exceptions and to present oral arguments, which were heard on April 4, 2024. On April 17, 2024, PURA conditionally approved rates for UI's

RAM components effective July 1, 2024, through April 30, 2025, subject to its final prudency review of UI's 2023 reported RAM costs. On September 26, UI appealed PURA's decision.

Stipulation Agreement for 2022 CMP Incremental Storm Costs

On June 11, 2024, the MPUC issued an order approving a stipulation filed by CMP on May 30, 2024, to resolve the Office of the Public Advocate’s complaint regarding 2022 storm costs and to include a provision that it will not challenge 2023 storm costs recovery. As a result of the stipulation agreement, CMP will reduce carrying costs on the unamortized balance of the 2022 incremental storm costs by $0.85 million for the period of July 1, 2024 to June 30, 2025. The stipulation also recognizes that there is no disallowance or finding of imprudence by CMP, with no other modification on incurred storm costs recovery aside from the aforementioned carrying cost adjustment.

IRS Normalization Rulings

In June 2024, the Internal Revenue Service, or IRS, released private letter rulings that clarified how the normalization rules apply to situations where customer rates are reduced for certain tax benefits realized through affiliate rather than stand-alone activity. As part of these rulings, the IRS concluded that certain utility Net Operating Loss deferred tax assets as of December 31, 2017 and subject to 2017 Tax Act remeasurement, need to be determined on a separate company basis without regard to any affiliate losses. As a result, in September 2024, Avangrid recorded a $14 million tax expense reduction for the required pre-gross up decrease to its 2017 Tax Act related regulatory liability.

IRS Release of CAMT regulations

In September 2024, the IRS issued proposed regulations to provide guidance on the Corporate Alternative Minimum Tax, or CAMT, which Congress enacted in August 2022, and effective 2023, as part of the Inflation Reduction Act of 2022, or IRA. The proposed CAMT regulations clarify some but not all significant requirements of the law and are subject to a 90 day comment period. Avangrid's 2023 US federal tax return reflects a $16 million CAMT and we estimate a liability of $12 million for the first nine months of 2024. The IRS has granted corporate taxpayers relief from underpayment risk associated with 2023 and 2024 liabilities through various notices including Notice 2024-66 issued in August 2024. We do not expect the proposed regulations to have a significant impact on our earnings or cash flows.

U.S. DOE capacity contract award

On October 3, 2024, the U.S. Department of Energy, or DOE, selected Avangrid for a $425 million capacity contract for its Aroostook Renewable Project.

New England Wind 1 development project

On September 6, 2024, Renewables' New England Wind 1 offshore wind development project was selected by the Commonwealth of Massachusetts to provide 791 MW of offshore wind power to Massachusetts with an expected commercial operation date of 2029. Renewables is in the process of negotiating PPAs with the Massachusetts EDCs.

Results of Operations

The following tables set forth financial information by segment for each of the periods indicated:


	Three Months Ended								Three Months Ended
	September 30, 2024								September 30, 2023
	Total		Networks		Renewables		Other(1)		Total		Networks		Renewables		Other(1)
	(in millions)
Operating Revenues	$	2,083	$	1,671	$	413	$	(1)	$	1,974	$	1,587	$	387	$	—
Operating Expenses
Purchased power, natural gas and fuel used	457		386		71		—		482		377		105		—
Operations and maintenance	866		725		132		9		924		748		183		(7)
Depreciation and amortization	327		189		135		3		303		175		123		5
Taxes other than income taxes	179		160		18		1		176		153		21		2
Total Operating Expenses	1,829		1,460		356		13		1,885		1,453		432		—
Operating Income	254		211		57		(14)		89		134		(45)		—
Other Income (Expense)
Other income (expense)	65		68		6		(9)		42		45		8		(11)
Earnings (losses) from equity method investments	4		4		—		—		(1)		3		(4)		—
Interest expense, net of capitalization	(132)		(87)		2		(47)		(107)		(76)		(6)		(25)
Income (Loss) Before Income Tax	191		196		65		(70)		23		106		(47)		(36)
Income tax expense (benefit)	19		34		6		(21)		(8)		12		(27)		7
Net Income (Loss)	172		162		59		(49)		31		94		(20)		(43)
Net (income) loss attributable to noncontrolling interests	33		(1)		34		—		28		(1)		29		—
Net Income (Loss) Attributable to Avangrid, Inc.	$	205	$	161	$	93	$	(49)	$	59	$	93	$	9	$	(43)


	Nine Months Ended								Nine Months Ended
	September 30, 2024								September 30, 2023
	Total		Networks		Renewables		Other(1)		Total		Networks		Renewables		Other(1)
	(in millions)
Operating Revenues	$	6,423	$	5,279	$	1,147	$	(3)	$	6,027	$	4,936	$	1,092	$	(1)
Operating Expenses
Purchased power, natural gas and fuel used	1,610		1,390		220		—		1,844		1,514		330		—
Operations and maintenance	2,477		2,095		373		9		2,319		1,910		414		(5)
Depreciation and amortization	935		554		374		7		868		524		338		6
Taxes other than income taxes	539		476		59		4		516		457		56		3
Total Operating Expenses	5,561		4,515		1,026		20		5,547		4,405		1,138		4
Operating Income	862		764		121		(23)		480		531		(46)		(5)
Other Income (Expense)
Other income (expense)	176		185		12		(21)		96		110		13		(27)
Earnings (losses) from equity method investments	15		12		3		—		5		11		(6)		—
Interest expense, net of capitalization	(379)		(253)		(1)		(125)		(301)		(215)		(16)		(70)
Income (Loss) Before Income Tax	674		708		135		(169)		280		437		(55)		(102)
Income tax expense (benefit)	52		124		(17)		(55)		(17)		70		(87)		—
Net Income (Loss)	622		584		152		(114)		297		367		32		(102)
Net loss (income) attributable to noncontrolling interests	103		(3)		106		—		92		(3)		95		—
Net Income (Loss) Attributable to Avangrid, Inc.	$	725	$	581	$	258	$	(114)	$	389	$	364	$	127	$	(102)

(1)"Other" represents Corporate and intersegment eliminations.

Comparison of Period to Period Results of Operations

Three Months Ended September 30, 2024 Compared to Three Months Ended September 30, 2023

Operating Revenues

Our operating revenues increased by $109 million from $1,974 million for the three months ended September 30, 2023 to $2,083 million for the three months ended September 30, 2024, as detailed by segment below:

Networks

Operating revenues increased by $84 million from $1,587 million for the three months ended September 30, 2023 to $1,671 million for the three months ended September 30, 2024. Electricity and gas revenues increased by $138 million, primarily due to rate increases in New York effective October 12, 2023, offset by $32 million unfavorable impact from deferrals mainly driven by the regulatory mechanism established in the same period of 2023 in anticipation of the amortization periods to be established in the rate case in New York in 2023. Additionally, electricity and gas revenues changed due to the following items that have offsets within the income statement: an increase of $9 million in purchased power and purchased gas (offset in purchased power) driven by higher average units and pricing in commodities in the period, offset by a decrease of $31 million in flow through amortizations (offset in operating expenses).

Renewables

Operating revenues increased by $26 million from $387 million for the three months ended September 30, 2023 to $413 million for the three months ended September 30, 2024. The increase in operating revenues was primarily due to an increase of $26 million in merchant prices driven by higher average prices and favorable MtM changes of $21 million on energy derivative transactions entered for economic hedging purposes in the current period, offset by a $21 million decrease in production in the current period.

Purchased Power, Natural Gas and Fuel Used

Our purchased power, natural gas and fuel used decreased by $25 million from $482 million for the three months ended September 30, 2023 to $457 million for the three months ended September 30, 2024, as detailed by segment below:

Networks

Purchased power, natural gas and fuel used increased by $9 million from $377 million for the three months ended September 30, 2023 to $386 million for the three months ended September 30, 2024. The increase is primarily driven by a $9 million increase in average commodity prices and an overall increase in electricity and gas units procured due to higher degree days in the period.

Renewables

Purchased power, natural gas and fuel used decreased by $34 million from $105 million for the three months ended September 30, 2023 to $71 million for the three months ended September 30, 2024. The decrease is primarily due to favorable MtM changes on derivatives of $19 million driven by market price changes and a decrease of $15 million in power and gas purchases due to lower average prices in the current period.

Operations and Maintenance

Operations and maintenance expenses decreased by $58 million from $924 million for the three months ended September 30, 2023 to $866 million for the three months ended September 30, 2024, as detailed by segment below:

Networks

Operations and maintenance expenses decreased by $23 million from $748 million for the three months ended September 30, 2023 to $725 million for the three months ended September 30, 2024. The decrease is driven by $31 million decrease in flow-through items and amortizations (which is offset in revenue), offset by a $8 million increase in personnel expenses primarily driven by higher headcount in the current period.

Renewables

Operations and maintenance expenses decreased by $51 million from $183 million for the three months ended September 30, 2023 to $132 million for the three months ended September 30, 2024. The decrease is primarily driven by a $40 million offshore contract provision and $5 million write-off of certain development projects, both recorded in the same period of 2023, and $6 million decrease driven by lower operating costs in the current period.

Depreciation and Amortization

Depreciation and amortization for the three months ended September 30, 2024 was $327 million compared to $303 million for the three months ended September 30, 2023, representing an increase of $24 million. The increase is primarily driven by $14 million from plant additions mainly in Networks and Renewables, and $10 million impact of accelerated depreciation from the repowering of wind farms in the current period.

Other Income (Expense) and Earnings (Losses) from Equity Method Investments

Other income (expense) and equity earnings (losses) increased by $28 million from $41 million for the three months ended September 30, 2023 to $69 million for the three months ended September 30, 2024. The increase is primarily due to a $12 million increase in allowance for funds used during construction in Networks primarily driven by the NECEC project construction, a $11 million increase in carrying costs on regulatory deferrals and $5 million of favorable equity earnings in the current period.

Interest Expense, Net of Capitalization

Interest expense for the three months ended September 30, 2024 and 2023 was $132 million and $107 million, respectively. The change is primarily due to a $16 million increase in interest expense mainly driven by increased debt in the period at Networks and a $32 million increase in Other mainly driven by increased outstanding balances on commercial paper and the intragroup loan in the current period, offset by $23 million of capitalized interest driven by higher interest rates in the period.

Income Tax

The effective tax rate, inclusive of federal and state income tax, for the three months ended September 30, 2024 was 9.9%, which is below the federal statutory tax rate of 21%, primarily due to the recognition of production tax credits, the effect of the excess deferred tax amortization resulting from the Tax Act (including an adjustment prompted by recently released IRS private letter rulings (“PLRs”)), the equity component of allowance for funds used during construction, and other property related flow through items, partially offset by the effects of tax equity financing impacts, state taxes, and prior year tax provision to return adjustments. The effective tax rate, inclusive of federal and state income tax, for the three months ended September 30, 2023 was (34.8)%, which is below the federal statutory tax rate of 21%, primarily due to the recognition of production tax credits associated with wind production, the effect of the excess deferred tax amortization resulting from the Tax Act, the equity component of allowance for funds used during construction and other property related flow through items.

Nine Months Ended September 30, 2024 Compared to Nine Months Ended September 30, 2023

Operating Revenues

Our operating revenues increased by $396 million from $6,027 million for the nine months ended September 30, 2023 to $6,423 million for the nine months ended September 30, 2024, as detailed by segment below:

Networks

Operating revenues increased by $343 million from $4,936 million for the nine months ended September 30, 2023 to $5,279 million for the nine months ended September 30, 2024. Electricity and gas revenues increased by $320 million, primarily due to rate increases in New York effective October 12, 2023, and a $46 million favorable impact from deferrals mainly driven by new regulatory mechanisms established by the rate case in New York. Additionally, electricity and gas revenues changed due to the following items that have offsets within the income statement: a decrease of $124 million in purchased power and purchased gas (offset in purchased power) driven by lower average pricing in commodities in the period, offset by an increase of $101 million in flow through items and amortizations (offset in operating expenses).

Renewables

Operating revenues increased by $55 million from $1,092 million for the nine months ended September 30, 2023, to $1,147 million for the nine months ended September 30, 2024. The increase in operating revenues was primarily due to an increase of $56 million in favorable thermal and power trading due to wider spark spreads in the period primarily driven by weather, and a $65 million increase in merchant prices driven by higher average prices in the current period, offset by unfavorable MtM changes of $51 million on energy derivative transactions entered for economic hedging purposes and a $15 million decrease from production in the current period.

Purchased Power, Natural Gas and Fuel Used

Purchased power, natural gas and fuel used decreased by $234 million from $1,844 million for the nine months ended September 30, 2023 to $1,610 million for the nine months ended September 30, 2024, as detailed by segment below:

Networks

Purchased power, natural gas and fuel used decreased by $124 million from $1,514 million for the nine months ended September 30, 2023 to $1,390 million for the nine months ended September 30, 2024. The decrease is primarily driven by a $124 million decrease in average commodity prices and an overall decrease in electricity and gas units procured due to lower degree days in the period.

Renewables

Purchased power, natural gas and fuel used decreased by $110 million from $330 million for the nine months ended September 30, 2023 to $220 million for the nine months ended September 30, 2024. The decrease is primarily due to favorable MtM changes on derivatives of $87 million driven by market price changes in the period and a decrease of $23 million in power and gas purchases due to lower average prices in the current period driven by weather.

Operations and Maintenance

Operations and maintenance expenses increased by $158 million from $2,319 million for the nine months ended September 30, 2023 to $2,477 million for the nine months ended September 30, 2024, as detailed by segment below:

Networks

Operations and maintenance expenses increased by $185 million from $1,910 million for the nine months ended September 30, 2023 to $2,095 million for the nine months ended September 30, 2024. The increase is driven by increased business and corporate costs of $24 million, and a $60 million increase in personnel expenses primarily driven by higher headcount. In addition, there were increases of $101 million in flow-through items and amortizations (which is offset in revenue).

Renewables

Operations and maintenance expenses decreased by $41 million from $414 million for the nine months ended September 30, 2023 to $373 million for the nine months ended September 30, 2024. The decrease is primarily driven by a $40 million offshore contract provision and $5 million write-off of certain development projects, both recorded in the same period of 2023, and $5 million decrease driven by lower operating costs in the current period, offset by a $9 million bad debt provision reversal recorded in the same period of 2023 arising from the 2022 weather event in the PJM market.

Depreciation and Amortization

Depreciation and amortization for the nine months ended September 30, 2024 was $935 million compared to $868 million for the nine months ended September 30, 2023, an increase of $67 million. The increase is primarily driven by $51 million from plant additions mainly in Networks and Renewables, and $16 million impact of accelerated depreciation from the repowering of wind farms in the current period.

Other Income (Expense) and Earnings (Losses) from Equity Method Investments

Other income (expense) and equity earnings (losses) increased by $90 million from $101 million for the nine months ended September 30, 2023 to $191 million for the nine months ended September 30, 2024. The increase is primarily due to a $48 million increase in allowance for funds used during construction in Networks primarily driven by the NECEC project construction, a $32 million increase in carrying costs on regulatory deferrals and $10 million of favorable equity earnings in the current period.

Interest Expense, Net of Capitalization

Interest expense for the nine months ended September 30, 2024 and 2023 was $379 million and $301 million, respectively. The change is primarily due to a $48 million increase in interest expense mainly driven by increased debt in the period at Networks and a $89 million increase in Other mainly driven by increased outstanding balances on commercial paper and the intragroup loan and unfavorable changes in the fair value hedges in the current period, offset by $59 million of capitalized interest driven by higher interest rates in the period.

Income Tax

The effective tax rate, inclusive of federal and state income tax, for the nine months ended September 30, 2024 was 7.7%, which is below the federal statutory tax rate of 21%, primarily due to the recognition of production tax credits, the effect of the excess deferred tax amortization resulting from the Tax Act, (including an adjustment prompted by recently released IRS private letter rulings (“PLRs”)), the equity component of allowance for funds used during construction, and other property related flow through items, partially offset by the effects of tax equity financing impacts, state taxes, and prior year tax provision to return adjustments. The effective tax rate, inclusive of federal and state income tax, for the nine months ended September 30, 2023 was (6.1)%, which is below the federal statutory tax rate of 21%, primarily due to the recognition of

production tax credits associated with wind production, the effect of the excess deferred tax amortization resulting from the Tax Act, the equity component of allowance for funds used during construction and other property related flow through items.

Non-GAAP Financial Measures

To supplement our consolidated financial statements presented in accordance with U.S. GAAP, we consider adjusted net income and adjusted earnings per share, adjusted EBITDA and adjusted EBITDA with Tax Credits as financial measures that are not prepared in accordance with U.S. GAAP. The non-GAAP financial measures we use are specific to Avangrid and the non-GAAP financial measures of other companies may not be calculated in the same manner. We use these non-GAAP financial measures, in addition to U.S. GAAP measures, to establish operating budgets and operational goals to manage and monitor our business, evaluate our operating and financial performance and to compare such performance to prior periods and to the performance of our competitors. We believe that presenting such non-GAAP financial measures is useful because such measures can be used to analyze and compare profitability between companies and industries by eliminating the impact of certain non-cash charges. In addition, we present non-GAAP financial measures because we believe that they and other similar measures are widely used by certain investors, securities analysts and other interested parties as supplemental measures of performance.

We define adjusted net income as net income adjusted to exclude mark-to-market earnings from changes in the fair value of derivative instruments, costs incurred related to the merger and other transactions, accelerated depreciation from the repowering of wind farms and costs incurred in connection with offshore contract provision. We believe adjusted net income is more useful in understanding and evaluating actual and projected financial performance and contribution of Avangrid core lines of business and to more fully compare and explain our results. The most directly comparable U.S. GAAP measure to adjusted net income is net income. We also define adjusted earnings per share, or adjusted EPS, as adjusted net income converted to an earnings per share amount.

We define adjusted EBITDA as adjusted net income adjusted to fully exclude the effects of net (loss) income attributable to noncontrolling interests, income tax expense (benefit), depreciation and amortization, interest expense, net of capitalization, other (income) expense and (earnings) losses from equity method investments. We further define adjusted EBITDA with tax credits as adjusted EBITDA adding back the pre-tax effect of retained Production Tax Credits (PTCs) and Investment Tax Credits (ITCs) and PTCs allocated to tax equity investors. The most directly comparable U.S. GAAP measure to adjusted EBITDA and adjusted EBITDA with tax credits is net income.

The use of non-GAAP financial measures is not intended to be considered in isolation or as a substitute for, or superior to, Avangrid’s U.S. GAAP financial information, and investors are cautioned that the non-GAAP financial measures are limited in their usefulness, may be unique to Avangrid, and should be considered only as a supplement to Avangrid’s U.S. GAAP financial measures. The non-GAAP financial measures may not be comparable to other similarly titled measures of other companies and have limitations as analytical tools.

Non-GAAP financial measures are not primary measurements of our performance under U.S. GAAP and should not be considered as alternatives to operating income, net income or any other performance measures determined in accordance with U.S. GAAP.

The following tables provide a reconciliation between Net Income attributable to Avangrid and non-GAAP measures Adjusted Net Income, Adjusted EBITDA and Adjusted EBITDA with Tax Credits by segment for the three and nine months ended September 30, 2024 and 2023, respectively:


	Three Months Ended September 30, 2024								Nine Months Ended September 30, 2024
	Total		Networks		Renewables		Corporate*		Total		Networks		Renewables		Corporate*
	(in millions)								(in millions)
Net Income Attributable to Avangrid, Inc.	$	205	$	161	$	93	$	(48)	$	725	$	581	$	258	$	(114)
Adjustments:
Mark-to-market earnings – Renewables	(18)		—		(18)		—		(18)		—		(18)		—
Accelerated depreciation from repowering	10		—		10		—		16		—		16		—
Merger and other transaction costs	12		—		1		11		18		—		2		17
Income tax impact of adjustments (1)	2		—		2		1		(1)		—		—		(1)
Adjusted Net Income (2)	$	211	$	161	$	87	$	(37)	$	741	$	581	$	258	$	(98)

Net (loss) income attributable to noncontrolling interests	(33)		1		(34)		—		(103)		3		(106)		—
Income tax expense (benefit)	17		34		4		(22)		53		124		(17)		(54)
Depreciation and amortization	327		189		135		3		935		554		374		7
Interest expense, net of capitalization	132		87		(2)		47		379		253		1		125
Other (income) expense	(65)		(68)		(6)		9		(176)		(185)		(12)		21
(Earnings) losses from equity method investments	(4)		(4)		—		—		(15)		(12)		(3)		—
Adjusted EBITDA (3)	$	585	$	400	$	184	$	1	$	1,814	$	1,318	$	495	$	1

Retained PTCs and ITCs	42		—		42		—		134		—		134		—
PTCs allocated to tax equity investors	40		—		40		—		123		—		123		—
Adjusted EBITDA with Tax Credits (3)	$	666	$	400	$	266	$	1	$	2,070	$	1,318	$	752	$	1


	Three Months Ended September 30, 2023								Nine Months Ended September 30, 2023
	Total		Networks		Renewables		Corporate*		Total		Networks		Renewables		Corporate*
	(in millions)								(in millions)
Net Income Attributable to Avangrid, Inc.	$	59	$	92	$	9	$	(43)	$	389	$	364	$	127	$	(102)
Adjustments:
Mark-to-market earnings – Renewables	23		—		23		—		19		—		19		—
Merger and other transaction costs	1		—		—		1		2		—		—		2
Offshore contract provision	40		—		40		—		40		—		40		—
Income tax impact of adjustments (1)	(17)		—		(17)		—		(16)		—		(16)		(1)
Adjusted Net Income (2)	$	105	$	92	$	55	$	(42)	$	434	$	364	$	170	$	(100)

Net (loss) income attributable to noncontrolling interests	(28)		1		(29)		—		(92)		3		(95)		—
Income tax expense (benefit)	9		12		(10)		7		(1)		70		(71)		1
Depreciation and amortization	303		175		123		5		868		524		338		6
Interest expense, net of capitalization	107		76		6		25		301		215		16		70
Other (income) expense	(42)		(45)		(8)		11		(96)		(110)		(13)		27
(Earnings) losses from equity method investments	1		(3)		4		—		(5)		(11)		6		—
Adjusted EBITDA (3)	$	455	$	308	$	141	$	6	$	1,409	$	1,055	$	351	$	3

Retained PTCs and ITCs	35		—		35		—		125		—		125		—
PTCs allocated to tax equity investors	34		—		34		—		113		—		113		—
Adjusted EBITDA with Tax Credits (3)	$	524	$	308	$	210	$	6	$	1,647	$	1,055	$	589	$	3

(1)Income tax impact of adjustments: 2024 - $3 million and $4 million from MtM earnings, $(2) million and $(4) million from repowering, and $1 and $(1) from merger and other transaction costs for the three and nine months ended September 30, 2024, respectively; 2023 - $(6) million and $(5) million from MtM earnings, $(1) million and $(1) million from merger costs, and $(10) million and $(10) million from offshore contract provision for the three and nine months ended September 30, 2023, respectively.

(2)Adjusted Net Income is a non-GAAP financial measure and is presented after excluding MtM activities in Renewables, costs incurred related to the merger and other transactions, accelerated depreciation from the repowering of wind farms and offshore contract provision.

(3)Adjusted EBITDA is a non-GAAP financial measure defined as adjusted net income adjusted to fully exclude the effects of net (loss) income attributable to noncontrolling interests, income tax expense (benefit), depreciation and amortization, interest expense, net of capitalization, other (income) expense and (earnings) losses from equity method investments. We further define adjusted EBITDA with tax credits as adjusted EBITDA adding back the pre-tax effect of retained PTCs and ITCs and PTCs allocated to tax equity investors.

* Includes corporate and other non-regulated entities as well as intersegment eliminations.

Three Months Ended September 30, 2024 Compared to Three Months Ended September 30, 2023

Adjusted net income

Our adjusted net income increased by $106 million from $105 million for the three months ended September 30, 2023 to $211 million for the three months ended September 30, 2024. The increase is primarily due to a $68 million increase in Networks driven primarily by rate increases in New York effective October 12, 2023, a $32 million increase in Renewables primarily driven by favorable impact in power and gas purchases due to lower average prices in the period and a $5 million increase in Corporate mainly driven by favorable taxes from applying the annual consolidated estimated tax rate, offset by higher interest expenses in the period.

Nine Months Ended September 30, 2024 Compared to Nine Months Ended September 30, 2023

Adjusted net income

Our adjusted net income increased by $307 million from $434 million for the nine months ended September 30, 2023 to $741 million for the nine months ended September 30, 2024. The increase is primarily due to a $217 million increase in Networks driven primarily by rate increases in New York effective October 12, 2023, a $88 million increase in Renewables primarily driven by favorable thermal and power trading due to higher average prices in the period primarily due to weather and a $2 million increase in Corporate mainly driven by favorable taxes from applying the annual consolidated estimated tax rate, offset by higher interest expenses in the period.

The following tables reconcile Net Income attributable to Avangrid to Adjusted Net Income (non-GAAP), and EPS attributable to Avangrid to adjusted EPS (non-GAAP) for the three and nine months ended September 30, 2024 and 2023, respectively:


	Three Months Ended				Nine Months Ended
	September 30,				September 30,
(Millions)	2024		2023		2024		2023
Networks	$	161	$	92	$	581	$	364
Renewables	93		9		258		127
Corporate (1)	(48)		(43)		(114)		(102)
Net Income	$	205	$	59	$	725	$	389
Adjustments:
Mark-to-market earnings - Renewables (2)	(18)		23		(18)		19
Accelerated depreciation from repowering (3)	10		—		16		—
Merger and other transaction costs (4)	12		1		18		2
Offshore contract provision (5)	—		40		—		40
Income tax impact of adjustments	2		(17)		(1)		(16)
Adjusted Net Income (6)	$	211	$	105	$	741	$	434


	Three Months Ended				Nine Months Ended
	September 30,				September 30,
(Millions)	2024		2023		2024		2023
Networks	$	0.41	$	0.24	$	1.50	$	0.94
Renewables	0.24		0.02		0.67		0.33
Corporate (1)	(0.12)		(0.11)		(0.29)		(0.26)
Earnings Per Share	$	0.53	$	0.15	$	1.87	$	1.00
Adjustments:
Mark-to-market earnings - Renewables (2)	(0.05)		0.06		(0.05)		0.05
Accelerated depreciation from repowering (3)	0.03		—		0.04		—
Merger and other transaction costs (4)	0.03		—		0.05		0.01
Offshore contract provision (5)	—		0.10		—		0.10
Income tax impact of adjustments	0.01		(0.04)		—		(0.04)
Adjusted Earnings Per Share (6)	$	0.55	$	0.27	$	1.91	$	1.12

(1)Includes corporate and other non-regulated entities as well as intersegment eliminations.

(2)Mark-to-market earnings relates to earnings impacts from changes in the fair value of Renewables' derivative instruments associated with electricity and natural gas.

(3)Represents the amount of accelerated depreciation derived from the repowering of wind farms in Renewables.

(4)Pre-merger and other transaction costs incurred.

(5)Costs incurred in connection with offshore contract provision.

(6)Adjusted net income and adjusted earnings per share are non-GAAP financial measures and are presented after excluding MtM activities in Renewables, costs incurred related to the merger and other transactions, accelerated depreciation from the repowering of wind farms and offshore contract provision.

Liquidity and Capital Resources

Our operations, capital investment and business development require significant short-term liquidity and long-term capital resources. Historically, we have used cash from operations and borrowings under our credit facilities and commercial paper program as our primary sources of liquidity. Our long-term capital requirements have been met primarily through retention of earnings, equity issuances and borrowings in the investment grade debt capital markets. Continued access to these sources of liquidity and capital are critical to us. Risks may increase due to circumstances beyond our control, such as a general disruption of the financial markets and adverse economic conditions.

We and our subsidiaries are required to comply with certain covenants in connection with our respective loan agreements. The covenants are standard and customary in financing agreements, and we and our subsidiaries were in compliance with such covenants as of and throughout the nine months ended September 30, 2024.

Liquidity Position

We optimize our liquidity within the United States through a series of arms-length intercompany lending arrangements with our subsidiaries and among our regulated utilities to provide for lending of surplus cash to subsidiaries with liquidity needs, subject to the limitation that the regulated utilities may not lend to unregulated affiliates. These arrangements minimize overall short-term funding costs and maximize returns on the temporary cash investments of the subsidiaries. We have the capacity to borrow up to $3,575 million from the lenders committed to the Avangrid Credit Facility described below.

The following table provides the components of our liquidity position as of September 30, 2024 and December 31, 2023, respectively:


	As of September 30,		As of December 31,
	2024		2023
	(in millions)
Cash and cash equivalents	$	148	$	91
Avangrid Credit Facility	3,575		3,575
Iberdrola Group Credit Facility	750		750
Less: borrowings	(2,232)		(1,332)
Total	$	2,241	$	3,084

Avangrid Commercial Paper Program

Avangrid has a commercial paper program with a limit of $2 billion that is backstopped by the Avangrid Credit Facility (described below). As of September 30, 2024 and October 22, 2024, there was $1,928 million and $1,892 million, respectively, of commercial paper outstanding, presented net of discounts on the balance sheet.

Avangrid Credit Facility

Avangrid and its subsidiaries, NYSEG, RG&E, CMP, UI, CNG, SCG and BGC, each of which are joint borrowers, have a revolving credit facility with a syndicate of banks, or the Avangrid Credit Facility, that provides for maximum borrowings of up to $3,575 million in the aggregate, which was executed on November 23, 2021.

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. On November 23, 2021, the executed Avangrid Credit Facility increased Avangrid's maximum sublimit from $1,500 million to $2,500 million. The Avangrid Credit Facility contains pricing that is sensitive to Avangrid’s consolidated greenhouse gas emissions intensity. The Credit Facility also contains negative covenants, including one that sets the ratio of maximum allowed consolidated debt to consolidated total capitalization at 0.65 to 1.00, for each borrower. Under the Avangrid Credit Facility, each of the borrowers will pay an annual facility fee that is dependent on their credit rating. The initial facility fees will range from 10 to 22.5 basis points. The maturity date for the Avangrid Credit Facility is November 22, 2026. On July 17, 2023, the Avangrid Credit Facility was amended and restated to, among other things, provide for the replacement of LIBOR-based rates with SOFR-based rates.

As of both September 30, 2024 and October 22, 2024, we had no borrowings outstanding under this credit facility.

Since the Avangrid credit facility is also a backstop to the Avangrid commercial paper program, the total amount available under the facility as of September 30, 2024 and October 22, 2024, was $1,637 million and $1,675 million, respectively.

Iberdrola Group Credit Facility

Avangrid has a credit facility with Iberdrola Financiación, S.A.U., a subsidiary of Iberdrola. The facility has a limit of $750 million and matures on June 18, 2028. Avangrid pays a quarterly facility fee of 22.5 basis points (rate per annum) on the facility based on Avangrid’s current Moody’s and S&P ratings for senior unsecured long-term debt. As of both September 30, 2024 and October 22, 2024, we had $0 of borrowings outstanding under this credit facility.

Intragroup Green Loans

On June 13, 2024, we entered into an additional intra-group green loan agreement with Iberdrola Financiación, S.A.U., with an aggregate principal amount of $600 million maturing on June 13, 2030 at an interest rate of 5.53%.

On September 16, 2024, we entered into an intra-group green loan agreement with Iberdrola Financiación, S.A.U., with an aggregate principal amount of $600 million maturing on September 16, 2034 with an interest rate of 5.06%. The funding of this intra-group loan was received on October 1, 2024.

Group Cash Pool

We are a party to a liquidity agreement with Bank of America, N.A. along with certain members of the Iberdrola Group. The liquidity agreement aids the Iberdrola Group in efficient cash management and reduces the need for external borrowing by the pool participants. Parties to the agreement, including us, may deposit funds with or borrow from the financial institution, provided that the net balance of funds deposited or borrowed by all pool participants in the aggregate is not less than zero. As of September 30, 2024 and October 22, 2024, the balance was $304 million and $50 million, respectively. As of both September 30, 2024 and October 22, 2024, the weighted average interest rate on the balance was 5.45%. Any deposit amounts would be reflected in our consolidated balance sheets under cash and cash equivalents because our deposited surplus funds under the cash pooling agreement are highly-liquid short-term investments.

Capital Requirements

We expect to fund our capital requirements, including, without limitation, any quarterly shareholder dividends and capital investments primarily from the cash provided by operations of our businesses and through the access to the capital markets in the future. We have revolving credit facilities, as described above, to fund short-term liquidity needs and we believe that we will continue to have access to the capital markets as long-term growth capital is needed. While taking into consideration the current economic environment, management expects that we will continue to have sufficient liquidity and financial flexibility to meet our business requirements.

We expect to incur approximately $1.3 billion in capital expenditures through the remainder of 2024. This estimate is subject to continuing review and actual capital expenditures may vary significantly. As a result, the timing and ultimate cost associated with solar panels and cells and related project capital expenditures may vary from our current expectations.

Cash Flows

Our cash flows depend on many factors, including general economic conditions, regulatory decisions, weather, commodity price movements and operating expense and capital spending control.

The following is a summary of the cash flows by activity for the nine months ended September 30, 2024 and 2023, respectively:


	Nine Months Ended
	September 30,
	2024		2023
	(in millions)
Net cash provided by operating activities	$	940	$	757
Net cash used in investing activities	(3,082)		(2,024)
Net cash provided by financing activities	2,199		1,279
Net increase in cash, cash equivalents and restricted cash	$	57	$	12

Operating Activities

The cash provided by operating activities for the nine months ended September 30, 2024 compared to the nine months ended September 30, 2023 increased by $183 million, primarily attributable to higher operating revenues offset by increased interest payments during the period.

Investing Activities

For the nine months ended September 30, 2024, net cash used in investing activities was $3,082 million, which was comprised of $2,854 million of capital expenditures and $338 million of capital contributions to the equity method investments, partially offset by $100 million of contributions in aid of construction.

For the nine months ended September 30, 2023, net cash used in investing activities was $2,024 million, which was comprised of $2,078 million of capital expenditures and $99 million of capital contributions to the equity method investments, partially offset by $101 million of contributions in aid of construction.

Financing Activities

For the nine months ended September 30, 2024, financing activities provided $2,199 million in cash reflecting primarily a net increase in non-current debt and current notes payable of $2,707 million, contribution from non-controlling interests of $61 million, offset by distributions to non-controlling interests of $51 million and dividends of $510 million in the period.

For the nine months ended September 30, 2023, financing activities provided $1,279 million in cash reflecting primarily a net increase in non-current debt and current notes payable of $1,729 million, contribution from non-controlling interests of $79 million, offset by distributions to non-controlling interests of $13 million and dividends of $510 million in the period.

Off-Balance Sheet Arrangements

There have been no material changes in our off-balance sheet arrangements during the nine months ended September 30, 2024 as compared to those reported for the fiscal year ended December 31, 2023 in our Form 10-K.

Contractual Obligations

There have been no material changes in contractual and contingent obligations during the nine months ended September 30, 2024 as compared to those reported for the fiscal year ended December 31, 2023 in our Form 10-K.

Critical Accounting Policies and Estimates

We have prepared the accompanying condensed consolidated financial statements provided herein in accordance with U.S. GAAP. In preparing the accompanying condensed consolidated financial statements, our management has made certain estimates and assumptions that affect the reported amounts of assets, liabilities, stockholders’ equity, revenues and expenses and the disclosures thereof. While we believe that these policies and estimates used are appropriate, actual future events can and often do result in outcomes that can be materially different from these estimates. As of September 30, 2024, the only notable changes to the significant accounting policies described in our Form 10-K for the fiscal year ended December 31, 2023, are with respect to our adoption of the new accounting pronouncements described in Note 3 of our condensed consolidated financial statements for the nine months ended September 30, 2024.

New Accounting Standards

We review new accounting standards to determine the expected financial effect, if any, that the adoption of each such standard will have. The new accounting pronouncements we have adopted as of January 1, 2024, and reflected in our condensed consolidated financial statements are described in Note 3 of our condensed consolidated financial statements for the nine months ended September 30, 2024.

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

This Quarterly Report on Form 10-Q contains a number of forward-looking statements. Forward-looking statements may be identified by the use of forward-looking terms such as “may,” “will,” “should,” “would,” “could,” “can,” “expect(s),” “believe(s),” “anticipate(s),” “intend(s),” “plan(s),” “estimate(s),” “project(s),” “assume(s),” “guide(s),” “target(s),” “forecast(s),” “are (is) confident that” and “seek(s)” or the negative of such terms or other variations on such terms or comparable terminology. Such forward-looking statements include, but are not limited to, statements about our plans, objectives and intentions, outlooks or expectations for earnings, revenues, expenses or other future financial or business performance, strategies or expectations, or the impact of legal or regulatory matters on business, results of operations or financial condition of the business and other statements that are not historical facts. Such statements are based upon the current reasonable beliefs, expectations, and assumptions of our management and are subject to significant risks and uncertainties that could cause actual outcomes and results to differ materially. Important factors are discussed and should be reviewed in our Form 10-K and other subsequent filings with the SEC. Specifically, forward-looking statements include, without limitation:

•any statements regarding the Merger with Iberdrola including expected timing and likelihood of completion of the Merger, including the timing, receipt and terms and conditions of any required shareholder, governmental and regulatory approvals of the Merger that could reduce the anticipated benefits of, or cause the parties to abandon, the transaction, risks related to the disruption to ongoing business operations due to the proposed transaction, our status as a SEC registrant and NYSE-listed company, and litigation or administrative proceedings that may arise in connection with the Merger;

•actions or inactions of local, state or federal regulatory agencies;

•the ability of our regulated utility operations to recover costs in a timely manner or at all or obtain a return on certain assets or invested capital through base rates, cost recovery clauses and other regulatory mechanisms;

•potentially material adverse effect on our business, and financial condition due to the purchase and sales of energy commodities and related transportation and services by our operating subsidiaries;

•the impact of any change to applicable laws and regulations, including those subject to referendums affecting the ownership and operations of electric and gas utilities and renewable energy generation facilities, respectively, including, without limitation, those relating to the environment and climate change, taxes, price controls, regulatory approval and permitting;

•efforts to maintain a responsive sustainability program;

•new tariffs imposed on imported goods;

•potential restrictions by interconnecting utility and/or RTO rules, policies, procedures and FERC tariffs and market conditions on renewable project operations and ability to generate revenue;

•our rights, and the rights of our subsidiaries to sites that projects are located at may be subordinate to the rights of lienholders and leaseholders;

•strikes, work stoppages or an inability to negotiate future collective bargaining agreements on commercially reasonable terms;

•technological developments;

•geopolitical instability could exacerbate existing risk factors;

•future financial performance, anticipated liquidity and capital expenditures;

•weather conditions are unfavorable or below production forecasts;

•customary business and market related risks including warranty limitation and expiration as well as PPA expiration or early termination;

•impact of Iberdrola’s influence over stock as well as the future sale or issuance of common stock by Iberdrola;

•the “controlled company” exemption to the corporate governance rules for NYSE-listed companies could make shares of our common stock less attractive to some investors or otherwise harm our stock price;

•our dividend policy is subject to the discretion of our board of directors and may be limited by our debt agreements and limitations under New York law;

•ability to meet our financial obligations and to pay dividends on our common stock if our subsidiaries are unable to pay dividends or repay loans from us;

•the ability to maintain effective internal control over financial reporting;

•our investments and cash balances are subject to the risk of loss;

•the cost and availability of capital to finance our business is inherently uncertain;

•litigation or administrative proceedings;

•inability to insure against all potential risks;

•the ability to recruit and retain a highly qualified and diverse workforce in the competitive labor market;

•changes in amount, timing or ability to complete capital projects;

•adverse developments in general market, business, economic, labor, regulatory and political conditions including, without limitation, the impacts of inflation, deflation, supply-chain interruptions and changing prices and labor costs, including the Department of Commerce's anti-circumvention petition that could adversely impact renewable solar energy projects;

•the impacts of climate change, fluctuations in weather patterns and extreme weather events;

•the impact of extraordinary external events, such as any cyber breaches or other incidents, grid disturbances, acts of war or terrorism, civil or social unrest, natural disasters, pandemic health events or other similar occurrences, including the ongoing geopolitical conflict with Russia and Ukraine;

•the impact of a catastrophic or geopolitical event on business and economic conditions;

•the implementation of changes in accounting standards;

•adverse publicity or other reputational harm; and

•other presently unknown unforeseen factors.

Should one or more of these risks or uncertainties materialize, or should any of the underlying assumptions prove incorrect, actual results may vary in material respects from those expressed or implied by these forward-looking statements. You should not place undue reliance on these forward-looking statements. We do not undertake any obligation to update or revise any forward-looking statements to reflect events or circumstances after the date of this report, whether as a result of new information, future events or otherwise, except as may be required under applicable securities laws. Other risk factors are detailed from time to time in our reports filed with the SEC, and we encourage you to consult such disclosures.

Item 3. Quantitative and Qualitative Disclosures about Market Risk

There have been no material changes in our market risk during the nine months ended September 30, 2024, as compared to those reported for the fiscal year ended December 31, 2023 in our Form 10-K.

Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

Our management, with the participation of our Chief Executive Officer, or CEO, and our Chief Financial Officer, or CFO, has evaluated the effectiveness of our disclosure controls and procedures (as defined in Rules 13a- 15(e) and 15d- 15(e) under the Securities Exchange Act of 1934, as amended (Exchange Act)), as of the end of the period covered by this Quarterly Report on Form 10-Q. Based on such evaluation, our CEO and CFO have concluded that as of such date, our disclosure controls and procedures were effective.

Changes in Internal Control

There has been no change in our internal control over financial reporting identified in management’s evaluation pursuant to Rules 13a-15(d) or 15d-15(d) of the Exchange Act during the period covered by this Quarterly Report on Form 10-Q that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Limitations on Effectiveness of Controls and Procedures

In designing and evaluating the disclosure controls and procedures, management recognizes that any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving the desired control objectives. In addition, the design of disclosure controls and procedures must reflect the fact that there are resource constraints and that management is required to apply judgment in evaluating the benefits of possible controls and procedures relative to their costs.

PART II. OTHER INFORMATION

Item 1. Legal Proceedings

Please read “Note 8—Contingencies and Commitments” and “Note 9—Environmental Liabilities” to the accompanying unaudited condensed consolidated financial statements under Part I, Item 1 of this report for a discussion of legal proceedings that we believe could be material to us.

Item 1A. Risk Factors

Shareholders and prospective investors should carefully consider the risk factors disclosed in our Form 10-K for the fiscal year ended December 31, 2023 and Form 10-Q for the period ended June 30, 2024.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

None.

Item 3. Defaults Upon Senior Securities

None.

Item 4. Mine Safety Disclosures

Not applicable.

Item 5. Other Information

None.

Item 6. Exhibits

The following documents are included as exhibits to this Form 10-Q:


Exhibit Number						Description

2.1						Agreement and Plan of Merger, dated May 17, 2024, by and among Avangrid, Inc., Iberdrola S.A. and Arizona Merger Sub, Inc. (incorporated herein by reference to Exhibit 2.1 to Form 8-K filed with the Securities and Exchange Commission on May 17, 2024).

10.1						Ten-Year Intra-Group Green Loan Agreement, dated September 16, 2024, between Avangrid, Inc. and Iberdrola Financiación, S.A.U.*

10.2						Separation Agreement, dated September 4, 2024, between Avangrid Management Company, LLC and Catherine Stempien.*†

31.1						Chief Executive Officer Certification pursuant to Rule 13a-14(a) and 15d-14(a), as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.*

31.2						Chief Financial Officer Certification pursuant to Rule 13a-14(a) and 15d-14(a), as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.*

32						Certification pursuant to 18 United States Code Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.*

101.INS						XBRL Instance Document.*

101.SCH						XBRL Taxonomy Extension Schema Document.*

101.CAL						XBRL Taxonomy Extension Calculation Linkbase Document.*

101.DEF						XBRL Taxonomy Extension Definition Linkbase Document.*

101.LAB						XBRL Taxonomy Extension Label Linkbase Document.*

101.PRE						XBRL Taxonomy Extension Presentation Linkbase Document.*

*Filed herewith.

†Compensatory plan or agreement.

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.


		Avangrid, Inc.

Date: October 23, 2024	By:	/s/ Pedro Azagra Blázquez
		Pedro Azagra Blázquez
		Director and Chief Executive Officer


Date: October 23, 2024	By:	/s/ Justin B. Lagasse
		Justin B. Lagasse
		Senior Vice President - Chief Financial Officer and Controller