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AGR Avangrid

Filed: 4 May 21, 4:03pm

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, DC 20549
FORM 10-Q
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended March 31, 2021
Or
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from                  to                  i
Commission File No. 001-37660
agr-20210331_g1.jpg
Avangrid, Inc.
(Exact Name of Registrant as Specified in its Charter)
New York14-1798693
(State or other jurisdiction of incorporation or organization)(I.R.S. Employer Identification No.)
180 Marsh Hill Road
Orange,Connecticut06477
(Address of principal executive offices)(Zip Code)
Registrant’s telephone number, including area code: (207) 629-1190
Securities registered pursuant to Section 12(b) of the Act:
Title of each classTrading SymbolName of exchange on which registered
Common Stock, par value $0.01 per shareAGRNew York Stock Exchange
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes      No  
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).    Yes      No  
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.  
Large Accelerated FilerAccelerated Filer
Non-accelerated FilerSmaller Reporting Company
Emerging Growth Company  
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. 
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes      No  
As of April 30, 2021, the registrant had 309,369,894 shares of common stock, par value $0.01, outstanding.



Avangrid, Inc.
REPORT ON FORM 10-Q
For the Quarter Ended March 31, 2021
INDEX
 
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GLOSSARY OF TERMS AND ABBREVIATIONS
Unless the context indicates otherwise, the terms “we,” “our” and the “Company” are used to refer to Avangrid, Inc. and its subsidiaries.
2020 Joint ProposalJoint proposal of NYSEG and RG&E and certain other signatory parties approved by the NYPSC on November 19, 2020, for a three-year rate plan for electric and gas service commencing December 1, 2020.
AOCI Accumulated other comprehensive income
ARHI Avangrid Renewables Holdings, Inc.
ARP Alternative Revenue Programs
ASC Accounting Standards Codification
AVANGRID Avangrid, Inc.
BGC The Berkshire Gas Company
CfDs Contracts for Differences
CFIUSCommittee on Foreign Investment in the United States
CL&P The Connecticut Light and Power Company
CMP Central Maine Power Company
CNG Connecticut Natural Gas Corporation
DEEP Connecticut Department of Energy and Environmental Protection
DIMP Distribution Integrity Management Program
DPA Deferred Payment Arrangements
DPUMassachusetts Department of Public Utilities
EBITDA Earnings before interest, taxes, depreciation and amortization
ESM Earnings sharing mechanism
Evergreen Power Evergreen Power, LLC
English StationThe former generation site on the Mill River in New Haven, Connecticut
Exchange Act The Securities Exchange Act of 1934, as amended
FASB Financial Accounting Standards Board
FCCFederal Communications Commission
FERC Federal Energy Regulatory Commission
FirstEnergy FirstEnergy Corp.
Form 10-KAvangrid, Inc.’s Annual Report on Form 10-K for the year ended December 31, 2020, filed with the Securities and Exchange Commission on March 1, 2021.
HLBV Hypothetical Liquidation at Book Value
IberdrolaIberdrola, S.A., which owns 81.5% of the outstanding shares of Avangrid, Inc.
Iberdrola GroupThe group of companies controlled by Iberdrola, S.A.
Installed capacityThe production capacity of a power plant or wind farm based either on its rated (nameplate) capacity or actual capacity.
ISO Independent system operator
Klamath PlantKlamath gas-fired cogeneration facility located in the city of Klamath, Oregon.
KWKilowatts
LIBOR The London Interbank Offered Rate
MergerThe merger of PNMR with and into Merger Sub on the terms and subject to the conditions set forth in the Merger Agreement, with PNMR continuing as the surviving corporation and as a wholly-owned subsidiary of AVANGRID.
Merger AgreementAgreement and Plan of Merger, dated as of October 20, 2020, among AVANGRID, PNMR and Merger Sub.
Merger SubNM Green Holdings, Inc., a New Mexico corporation and wholly-owned subsidiary of AVANGRID.
MNG Maine Natural Gas Corporation
MPUC Maine Public Utility Commission
MtM Mark-to-market
MW Megawatts
MWh Megawatt-hours
Networks Avangrid Networks, Inc.
New York TransCo New York TransCo, LLC.
NMPRCNew Mexico Public Regulation Commission
Non-GAAPFinancial measures that are not prepared in accordance with U.S. GAAP, including adjusted net income, adjusted earnings per share, adjusted EBITDA and adjusted EBITDA with tax credits.
NRCNuclear Regulatory Commission
NYPSC New York State Public Service Commission
NYSEG New York State Electric & Gas Corporation
NYSERDA New York State Energy Research and Development Authority
OCI Other comprehensive income
PJM PJM Interconnection, L.L.C.
PNMRPNM Resources, Inc.
PUCTPublic Utility Commission of Texas
PURA Connecticut Public Utilities Regulatory Authority
Renewables Avangrid Renewables, LLC
RDM Revenue Decoupling Mechanism
RG&E Rochester Gas and Electric Corporation
ROE Return on equity
SCG The Southern Connecticut Gas Company
SEC United States Securities and Exchange Commission
Tax Act Tax Cuts and Jobs Act of 2017 enacted by the U.S. federal government on December 22, 2017
TEF Tax equity financing arrangements
UI The United Illuminating Company
UIL UIL Holdings Corporation
U.S. GAAP Generally accepted accounting principles for financial reporting in the United States.
VIEs Variable interest entities
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PART I. FINANCIAL INFORMATION

Item 1. Financial Statements
Avangrid, Inc. and Subsidiaries
Condensed Consolidated Statements of Income
(unaudited)
 
Three Months Ended March 31,
 20212020
(Millions, except for number of shares and per share data)  
Operating Revenues$1,966 $1,789 
Operating Expenses
Purchased power, natural gas and fuel used501 475 
Operations and maintenance642 570 
Depreciation and amortization247 251 
Taxes other than income taxes170 166 
Total Operating Expenses1,560 1,462 
Operating Income406 327 
Other Income and (Expense)  
Other income (expense)(3)
Earnings (losses) from equity method investments(6)
Interest expense, net of capitalization(73)(76)
Income Before Income Tax335 242 
Income tax expense14 12 
Net Income321 230 
Net loss attributable to noncontrolling interests13 10 
Net Income Attributable to Avangrid, Inc.$334 $240 
Earnings Per Common Share, Basic$1.08 $0.78 
Earnings Per Common Share, Diluted$1.08 $0.78 
Weighted-average Number of Common Shares Outstanding:  
Basic309,495,250 309,491,082 
Diluted309,736,266 309,623,573 
The accompanying notes are an integral part of our condensed consolidated financial statements.
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Avangrid, Inc. and Subsidiaries
Condensed Consolidated Statements of Comprehensive Income
(unaudited)
 
Three Months Ended March 31,
 20212020
(Millions)  
Net Income$321 $230 
Other Comprehensive Income (Loss)
Unrealized loss during the period on derivatives qualifying as cash flow hedges, net of income tax of $(5) and $(8), respectively(27)(23)
Reclassification to net income of loss on cash flow hedges, net of income taxes $(1) and $0, respectively
Other Comprehensive Income (Loss)(26)(21)
Comprehensive Income295 209 
Net loss attributable to noncontrolling interests13 10 
Comprehensive Income Attributable to Avangrid, Inc.$308 $219 
The accompanying notes are an integral part of our condensed consolidated financial statements.
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Avangrid, Inc. and Subsidiaries
Condensed Consolidated Balance Sheets
(unaudited)
 
 March 31,December 31,
As of20212020
(Millions)  
Assets  
Current Assets  
Cash and cash equivalents$813 $1,463 
Accounts receivable and unbilled revenues, net1,283 1,187 
Accounts receivable from affiliates15 12 
Derivative assets23 18 
Fuel and gas in storage83 93 
Materials and supplies171 169 
Prepayments and other current assets534 525 
Regulatory assets317 310 
Total Current Assets3,239 3,777 
Total Property, Plant and Equipment ($1,637 related to VIEs)27,168 26,751 
Operating lease right-of-use assets177 153 
Equity method investments695 668 
Other investments61 68 
Regulatory assets2,583 2,572 
Other Assets
Goodwill3,119 3,119 
Intangible assets302 305 
Derivative assets74 79 
Other350 331 
Total Other Assets3,845 3,834 
Total Assets$37,768 $37,823 
The accompanying notes are an integral part of our condensed consolidated financial statements.
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Avangrid, Inc. and Subsidiaries
Condensed Consolidated Balance Sheets
(unaudited)
 March 31,December 31,
As of20212020
(Millions, except share information)  
Liabilities  
Current Liabilities  
Current portion of debt$387 $313 
Notes payable307 
Notes payable to affiliates
Interest accrued81 70 
Accounts payable and accrued liabilities1,416 1,453 
Accounts payable to affiliates16 50 
Dividends payable136 136 
Taxes accrued60 73 
Operating lease liabilities16 
Derivative liabilities32 17 
Other current liabilities348 368 
Regulatory liabilities292 274 
Total Current Liabilities2,792 3,069 
Regulatory liabilities3,150 3,137 
Other Non-current Liabilities
Deferred income taxes1,924 1,919 
Deferred income1,181 1,204 
Pension and other postretirement979 1,007 
Operating lease liabilities172 154 
Derivative liabilities85 79 
Asset retirement obligations217 210 
Environmental remediation costs284 292 
Other591 448 
Total Other Non-current Liabilities5,433 5,313 
Non-current debt7,401 7,478 
Non-current debt to affiliate3,000 3,000 
Total Non-current Liabilities18,984 18,928 
Total Liabilities21,776 21,997 
Commitments and Contingencies00
Equity  
Stockholders’ Equity:  
Common stock, $.01 par value, 500,000,000 shares authorized, 309,848,228 and 309,794,917 shares issued; 309,369,894 and 309,077,300 shares outstanding, respectively
Additional paid in capital13,667 13,665 
Treasury stock(16)(14)
Retained earnings1,864 1,666 
Accumulated other comprehensive loss(137)(111)
Total Stockholders’ Equity15,381 15,209 
Non-controlling interests611 617 
Total Equity15,992 15,826 
Total Liabilities and Equity$37,768 $37,823 
The accompanying notes are an integral part of our condensed consolidated financial statements.
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Avangrid, Inc. and Subsidiaries
Condensed Consolidated Statements of Cash Flows
(unaudited)
Three Months Ended March 31,
 20212020
(Millions)
Cash Flow from Operating Activities:
Net income$321 $230 
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization247 251 
Regulatory assets/liabilities amortization and carrying cost21 18 
Pension cost17 20 
(Earnings) losses from equity method investments(1)
Distributions of earnings received from equity method investments
Unrealized loss (gain) on marked-to-market derivative contracts53 (18)
Deferred taxes(13)10 
Other non-cash items(5)
Changes in operating assets and liabilities:
Current assets(169)(16)
Noncurrent assets(93)(55)
Current liabilities39 (117)
Noncurrent liabilities(26)
Net Cash Provided by Operating Activities425 307 
Cash Flow from Investing Activities:
Capital expenditures(623)(742)
Contributions in aid of construction
Proceeds from sale of assets
Proceeds from notes receivable from affiliates
Distributions received from equity method investments
Other investments and equity method investments, net(39)(23)
Net Cash Used in Investing Activities(639)(749)
Cash Flow from Financing Activities:
Repayments of non-current debt(2)(3)
(Repayments) receipts of other short-term debt, net(301)187 
Repayments of financing leases(1)(1)
Repurchase of common stock(2)
Issuance of common stock(1)
Distributions to noncontrolling interests(3)(1)
Contributions from noncontrolling interests10 244 
Dividends paid(136)(136)
Net Cash (Used in) Provided by Financing Activities(436)290 
Net Decrease in Cash, Cash Equivalents and Restricted Cash(650)(152)
Cash, Cash Equivalents and Restricted Cash, Beginning of Period1,467 184 
Cash, Cash Equivalents and Restricted Cash, End of Period$817 $32 
Supplemental Cash Flow Information
Cash paid for interest, net of amounts capitalized$51 $70 
Cash paid for income taxes$$
The accompanying notes are an integral part of our condensed consolidated financial statements.
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Avangrid, Inc. and Subsidiaries
Condensed Consolidated Statements of Changes in Equity
(unaudited)

Avangrid, Inc. Stockholders
(Millions, except for number of shares )Number of shares (*)Common StockAdditional paid-in capitalTreasury StockRetained EarningsAccumulated Other Comprehensive LossTotal Stockholders’ EquityNoncontrolling InterestsTotal
As of December 31, 2019309,005,272 $3 $13,660 $(12)$1,634 $(95)$15,190 $349 $15,539 
Adoption of accounting standards— — — — (1)— (1)— (1)
Net income (loss)— — — — 240 — 240 (10)230 
Other comprehensive loss, net of tax of $(8)— — — — — (21)(21)— (21)
Comprehensive income209 
Dividends declared, $0.44/share— — — — (136)— (136)— (136)
Release of common stock held in trust213 — — — — — — — — 
Stock-based compensation— — — — — — 
Distributions to noncontrolling interests— — — — — — — (1)(1)
Contributions from noncontrolling interests— — — — — — — 244 244 
As of March 31, 2020309,005,485 $3 $13,667 $(12)$1,737 $(116)$15,279 $582 $15,861 
As of December 31, 2020309,077,300 $3 $13,665 $(14)$1,666 $(111)$15,209 $617 $15,826 
Net income (loss)— — — — 334 — 334 (13)321 
Other comprehensive loss, net of tax of $(6)— — — — — (26)(26)— (26)
Comprehensive income295 
Dividends declared, $0.44/share— — — — (136)— (136)— (136)
Release of common stock held in trust292,594 — — — — — — — — 
Issuance of common stock53,311 — (1)— — — (1)— (1)
Repurchase of common stock(53,311)— — (2)— — (2)— (2)
Stock-based compensation— — — — — — 
Distributions to noncontrolling interests— — — — — — — (3)(3)
Contributions from noncontrolling interests— — — — — — — 10 10 
As of March 31, 2021309,369,894 $3 $13,667 $(16)$1,864 $(137)$15,381 $611 $15,992 
(*) Par value of share amounts is $0.01
The accompanying notes are an integral part of our condensed consolidated financial statements.
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Avangrid, Inc. and Subsidiaries
Notes to Condensed Consolidated Financial Statements
(unaudited)
Note 1. Background and Nature of Operations
Avangrid, Inc. (AVANGRID, we or the Company), is an energy services holding company engaged in the regulated energy transmission and distribution business through its principal subsidiary, Avangrid Networks, Inc. (Networks), and in the renewable energy generation business through its principal subsidiary, Avangrid Renewables Holding, Inc. (ARHI). ARHI in turn holds subsidiaries including Avangrid Renewables, LLC (Renewables). Iberdrola, S.A. (Iberdrola), a corporation organized under the laws of the Kingdom of Spain, owns 81.5% of the outstanding common stock of AVANGRID. The remaining outstanding shares are publicly traded on the New York Stock Exchange and owned by various shareholders. 
Proposed Merger with PNMR
On October 20, 2020, AVANGRID, PNM Resources, Inc., a New Mexico corporation (PNMR) and NM Green Holdings, Inc., a New Mexico corporation and wholly-owned subsidiary of AVANGRID (Merger Sub), entered into an Agreement and Plan of Merger (Merger Agreement), pursuant to which Merger Sub is expected to merge with and into PNMR, with PNMR surviving the Merger as a direct wholly-owned subsidiary of AVANGRID (Merger). Pursuant to the Merger Agreement, each issued and outstanding share of the common stock of PNMR (PNMR common stock) (other than (i) the issued shares of PNMR common stock that are owned by AVANGRID, Merger Sub, PNMR or any wholly-owned subsidiary of AVANGRID or PNMR, which will be automatically cancelled at the time the Merger is consummated and (ii) shares of PNMR common stock held by a holder who has not voted in favor of, or consented in writing to, the Merger who is entitled to, and who has demanded, payment for fair value of such shares) will be converted, at the time the Merger is consummated, into the right to receive $50.30 in cash (Merger Consideration).
Consummation of the Merger (Closing) is subject to the satisfaction or waiver of certain customary closing conditions, including, without limitation, the approval of the Merger Agreement by the holders of at least a majority of the outstanding shares of PNMR common stock entitled to vote thereon, the absence of any material adverse effect on PNMR, the receipt of certain required regulatory approvals (including approvals from the Public Utility Commission of Texas (PUCT), the New Mexico Public Regulation Commission (NMPRC), the Federal Energy Regulatory Commission (FERC), the Federal Communications Commission (FCC), the Committee on Foreign Investment in the United States (CFIUS), the Nuclear Regulatory Commission (NRC) and approval under the Hart-Scott-Rodino Antitrust Improvements Act of 1976), the Four Corners Divestiture Agreements (as defined below) being in full force and effect and all applicable regulatory filings associated therewith being made, as well as holders of no more than 15% of the outstanding shares of PNMR common stock validly exercising their dissenters’ rights. On February 12, 2021, the shareholders of PNMR approved the proposed Merger. During the period ended March 31, 2021, the Merger obtained regulatory approval under the the Hart-Scott-Rodino Antitrust Improvements Act of 1976 and approvals from the CFIUS and the FCC. During April 2021, the Merger received approval from the FERC. The Merger is currently expected to close in the second half of 2021.
The Merger Agreement also contains representations, warranties and covenants of PNMR, AVANGRID and Merger Sub, which are customary for transactions of this type. In addition, among other things, the Merger Agreement contains a covenant requiring PNMR to, prior to the Closing, enter into agreements (Four Corners Divestiture Agreements) providing for, and to make filings required to, exit from all ownership interests in the Four Corners Power Plant, all with the objective of having the closing date for such exit be no later than December 31, 2024.
In connection with the Merger, Iberdrola has provided AVANGRID a commitment letter (Iberdrola Funding Commitment Letter), pursuant to which Iberdrola has unilaterally agreed to provide to AVANGRID, or arrange the provision to AVANGRID of, funds to the extent necessary for AVANGRID to consummate the Merger, including the payment of the aggregate Merger Consideration. To the extent AVANGRID wishes to effect a funding transaction under the Iberdrola Funding Commitment Letter in order to pay the Merger Consideration, the specific terms of any such transaction will be negotiated between Iberdrola and AVANGRID on an arm’s length basis and must be approved by both (i) a majority of the members of the unaffiliated committee of the board of directors of AVANGRID, and (ii) a majority of the board of directors of AVANGRID. Under the terms of such commitment letter, Iberdrola has agreed to negotiate with AVANGRID the specific terms of any transaction effecting such funding commitment promptly and in good faith, with the objective that such terms shall be commercially reasonable and approved by AVANGRID. AVANGRID’s and Merger Sub’s obligations under the Merger Agreement are not conditioned upon AVANGRID obtaining financing.
On April 15, 2021, AVANGRID entered into a side letter agreement with Iberdrola, which sets forth certain terms and conditions relating to the funding commitment letter (the Side Letter Agreement). The Side Letter Agreement provides that any drawing in the form of indebtedness made by the Corporation pursuant to the Funding Commitment Letter shall bear interest at
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an interest rate equal to 3-month LIBOR plus 0.75% per annum calculated on the basis 360-day year for the actual number of days elapsed and, commencing on the date of the Funding Commitment Letter, we shall pay Iberdrola a facility fee equal to 0.12% per annum on the undrawn portion of the funding commitment set forth in the Funding Commitment Letter.
The Merger Agreement provides for certain customary termination rights including the right of either party to terminate the Merger Agreement if the Merger is not completed on or before January 20, 2022 (subject to a three-month extension by either party if all of the conditions to the closing, other than the conditions related to obtaining regulatory approvals, have been satisfied or waived). The Merger Agreement further provides that, upon termination of the Merger Agreement under certain specified circumstances (including if AVANGRID terminates the Merger Agreement due to a change in recommendation of the board of directors of PNMR or if PNMR terminates the Merger Agreement to accept a superior proposal (as defined in the Merger Agreement)), PNMR will be required to pay AVANGRID a termination fee of $130 million. In addition, the Merger Agreement provides that (i) if the Merger Agreement is terminated by either party due to a failure of a regulatory closing condition and such failure is the result of AVANGRID’s breach of its regulatory covenants, or (ii) AVANGRID fails to effect the Closing when all closing conditions have been satisfied and it is otherwise obligated to do so under the Merger Agreement, then, in either such case, upon termination of the Merger Agreement, AVANGRID will be required to pay PNMR a termination fee of $184 million as the sole and exclusive remedy. Upon the termination of the Merger Agreement under certain specified circumstances involving a breach of the Merger Agreement, either PNMR or AVANGRID will be required to reimburse the other party’s reasonable and documented out-of-pocket fees and expenses up to $10 million (which amount will be credited toward, and offset against, the payment of any applicable termination fee).
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, 2020.
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.
Preparation of the accompanying unaudited financial statements requires management to make estimates and assumptions that affect the amounts reported during the periods covered by the related financial statements and accompanying disclosures. We continue to utilize information reasonably available to us; however, the business and economic uncertainty resulting from the global pandemic of the novel coronavirus (COVID-19) has made such estimates and assumptions more difficult to assess and calculate. Impacted estimates include, but are not limited to, evaluations of certain long-lived assets and goodwill for impairment, expected credit losses and potential regulatory deferral or recovery of certain costs. While there have been no material impacts from COVID-19 on financial results, actual results could differ from those estimates, which could result in material impacts to our consolidated financial statements in future reporting periods.
In the opinion of management, the accompanying condensed consolidated financial statements contain all adjustments necessary to present fairly our condensed consolidated financial statements for the interim periods described herein. All such adjustments are of a normal and recurring nature, except as otherwise disclosed. The results for the three months ended March 31, 2021, are not necessarily indicative of the results for the entire fiscal year ending December 31, 2021.
Note 3. Significant Accounting Policies and New Accounting Pronouncements
The new accounting pronouncements we have adopted as of January 1, 2021, 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, 2020, 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) Simplifying the accounting for income taxes
In December 2019, the FASB issued an accounting standards update that is intended to reduce complexity in accounting for income taxes. The amendments remove specific exceptions to the general principles in ASC 740, Income Taxes, eliminating the need for an entity to analyze whether the following apply in a given period: (1) exception to the incremental approach for intra-period tax allocation; (2) exceptions to accounting for basis differences in equity method investments when there are ownership
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changes in foreign investments; and (3) exception in interim period income tax accounting for year-to-date losses that exceed anticipated losses. The amendments also improve financial statement preparers’ application of income-tax related guidance and simplify U. S. GAAP for: (1) franchise taxes that are partially based on income; (2) transactions with a government that result in a step up in the tax basis of goodwill; (3) separate financial statements of legal entities that are not subject to tax; and (4) enacted changes in tax laws in interim periods. We adopted the amendments effective January 1, 2021, with no material effect to our condensed consolidated results of operations, financial position, cash flows and disclosures. We are applying the amendments on a retrospective and/or modified retrospective basis, or a prospective basis, depending on the amendment requirement.
Accounting Pronouncements Issued but Not Yet Adopted
The following are new accounting pronouncements not yet adopted, including those issued since December 31, 2020, that we have evaluated or are evaluating to determine their effect on our condensed consolidated financial statements.
(a) Facilitation of the effects of reference rate reform on financial reporting, and subsequent scope clarification
In March 2020, the FASB issued amendments and created ASC 848 to provide temporary optional guidance to entities to ease the potential burden in accounting for, or recognizing the effects of, reference rate reform on financial reporting. The amendments respond to concerns about structural risks of interbank offered rates, and particularly, the risk of cessation of the London Interbank Offered Rate (LIBOR). The guidance is elective and applies to all entities, subject to meeting certain criteria, that have contracts, hedging relationships, and other transactions that reference LIBOR or another reference rate expected to be discontinued due to reference rate reform, around the end of 2021. The guidance applies to contracts that have modified terms that affect, or have the potential to affect, the amount or timing of contractual cash flows resulting from the discontinuance of the reference rate reform. The amendments are effective for all entities as of March 12, 2020, through December 31, 2022, although the FASB has indicated it will monitor developments in the marketplace and consider whether developments warrant an extension.
In January 2021, the FASB issued amendments to clarify the scope of ASC 848 and respond to questions from stakeholders about whether ASC 848 can be applied to derivative instruments that do not reference a rate that is expected to be discontinued but that use an interest rate for margining, discounting, or contract price alignment that is modified because of reference rate reform. The modification, commonly referred to as the “discounting transition,” may have accounting implications, raising concerns about the need to reassess previous accounting determinations related to those derivatives and about the possible hedge accounting consequences of the discounting transition. The amendments clarify that certain optional expedients and exceptions in ASC 848 for contract modifications and hedge accounting apply to derivatives that are affected by the discounting transition, capture the incremental consequences of the scope clarification and tailor the existing guidance to derivative instruments affected by the discounting transition. The amendments are effective immediately, and may be elected retrospectively to eligible modifications as of any date from the beginning of the interim period that includes March 12, 2020, or prospectively to new modifications made on or after any date within the interim period that includes January 7, 2021.
We expect our adoption of reference rate reform and the subsequent scope clarification will not materially affect 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 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
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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. They traditionally invoice their 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.
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.
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.
Networks also has various other sources of revenue including billing, collection, other administrative charges, sundry billings, rent of utility property and miscellaneous revenue. It classifies such revenues as other ASC 606 revenues to the extent they are not related to revenue generating activities from leasing, derivatives or ARPs.
Renewables Segment
Renewables derives its revenue primarily from the sale of energy, transmission, capacity and other related charges from its renewable wind, solar and thermal energy generating sources. For such revenues, we will recognize revenues in an amount derived from the commodities delivered and from services as they are made available. Renewables has bundled power purchase agreements consisting of electric energy, transmission, capacity and/or renewable energy credits (RECs). The related contracts are generally long-term with no stated contract amount, that is, the customer is entitled to all of the unit’s output. Renewables also has unbundled sales of electric energy and capacity, RECs and natural gas, which are generally for periods of less than a year. The performance obligations in substantially all of both bundled and unbundled arrangements for electricity and natural gas are satisfied over time, for which we record revenue based on the amount invoiced to the customer for the actual energy delivered. The performance obligation for stand-alone RECs is satisfied at a point in time, for which we record revenue when the performance obligation is satisfied upon delivery of the REC.
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.
Other
Other, which does not represent a segment, includes miscellaneous Corporate revenues and intersegment eliminations.
Contract Costs and Contract Liabilities
We recognize an asset for incremental costs of obtaining a contract with a customer when we expect the benefit of those costs to be longer than one year. We have contract assets for costs from development success fees, which we paid during the solar asset development period in 2018, and will amortize ratably into expense over the 15-year life of the power purchase agreement
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(PPA), expected to commence in December 2021 upon commercial operation. Contract assets totaled $9 million at both March 31, 2021 and December 31, 2020, 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 $9 million at March 31, 2021 and December 31, 2020, respectively, and are presented in "Other current liabilities" on our condensed consolidated balance sheets. We recognized $4 million and $5 million as revenue during the three months ended March 31, 2021 and 2020, respectively.
Revenues disaggregated by major source for our reportable segments for the three months ended March 31, 2021 and 2020 are as follows:
Three Months Ended March 31, 2021
 NetworksRenewablesOther (b)Total
(Millions)
Regulated operations – electricity$942 $$$942 
Regulated operations – natural gas564 564 
Nonregulated operations – wind371 371 
Nonregulated operations – solar
Nonregulated operations – thermal12 12 
Other(a)10 32 42 
Revenue from contracts with customers1,516 419 0 1,935 
Leasing revenue
Derivative revenue(31)(31)
Alternative revenue programs47 47 
Other revenue13 
Total operating revenues$1,573 $393 $0 $1,966 
Three Months Ended March 31, 2020
NetworksRenewablesOther (b)Total
(Millions)
Regulated operations – electricity$873 $$$873 
Regulated operations – natural gas507 507 
Nonregulated operations – wind211 211 
Nonregulated operations – solar
Nonregulated operations – thermal10 10 
Other(a)19 28 47 
Revenue from contracts with customers1,399 253 0 1,652 
Leasing revenue
Derivative revenue70 70 
Alternative revenue programs56 56 
Other revenue10 
Total operating revenues$1,461 $328 $0 $1,789 
(a) Primarily includes certain intra-month trading activities, billing, collection and administrative charges, sundry billings and other miscellaneous revenue.
(b) Does not represent a segment. Includes Corporate and intersegment eliminations.
As of March 31, 2021 and December 31, 2020, accounts receivable balances related to contracts with customers were approximately $1,222 million and $1,151 million, respectively, including unbilled revenues of $292 million and $341 million, which are included in “Accounts receivable and unbilled revenues, net” on our condensed consolidated balance sheets.
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As of March 31, 2021, the aggregate amount of the transaction price allocated to performance obligations that are unsatisfied (or partially unsatisfied) were as follows:
As of March 31, 202120222023202420252026ThereafterTotal
(Millions)       
Revenue expected to be recognized on multiyear retail energy sales contracts in place$$$$$$$
Revenue expected to be recognized on multiyear capacity and carbon-free energy sale contracts24 16 14 12 68 141 
Revenue expected to be recognized on multiyear renewable energy credit sale contracts30 18 62 
Total operating revenues$60 $35 $21 $15 $10 $70 $211 
As of March 31, 2021, the aggregate amount of the transaction price allocated to performance obligations that are unsatisfied (or partially unsatisfied) for the remainder of 2021 was $69 million.
Note 5. Regulatory Assets and Liabilities
Pursuant to the requirements concerning accounting for regulated operations, our utilities capitalize, as regulatory assets, incurred and accrued costs that are probable of recovery in future electric and natural gas rates. We base our assessment of whether recovery is probable on the existence of regulatory orders that allow for recovery of certain costs over a specific period, or allow for reconciliation or deferral of certain costs. When costs are not treated in a specific regulatory order, we use regulatory precedent to determine if recovery is probable. Our operating utilities also record, as regulatory liabilities, obligations to refund previously collected revenue or to spend revenue collected from customers on future costs. The primary items that are not included in rate base or accruing carrying costs are regulatory assets for qualified pension and other postretirement benefits, which reflect unrecognized actuarial gains and losses; debt premium; environmental remediation costs, which are primarily the offset of accrued liabilities for future spending; unfunded future income taxes, which are the offset to the unfunded future deferred income tax liability recorded; asset retirement obligations; hedge losses; and contracts for differences. As of March 31, 2021, the total net amount of these items is approximately $1,473 million.
CMP Distribution Rate Case
In an order issued on February 19, 2020, the MPUC authorized an increase in CMP's distribution revenue requirement of $17 million, or approximately 7.00%, based on an allowed ROE of 9.25% and a 50.00% equity ratio. The rate increase was effective March 1, 2020. The MPUC also imposed a 1.00% ROE reduction (to 8.25%) for management efficiency associated with CMP’s customer service performance following the implementation of its new billing system in 2017. The management efficiency adjustment will remain in effect until CMP has demonstrated satisfactory customer service performance on four specified service quality measures for a rolling average period of 18 months, which commenced on March 1, 2020. CMP is meeting the required rolling average benchmarks for all four of these quality measures and expects to file with the MPUC in the third quarter of 2021 to remove the management efficiency adjustment.
The order provided additional funding for staffing increases, vegetation management programs and storm restoration costs, while retaining the basic tiered structure for storm cost recovery implemented in the 2014 stipulation. The MPUC order also retained the RDM implemented in 2014. The order denied CMP’s request to increase rates for higher costs associated with services provided by its affiliates and ordered the initiation of a management audit to evaluate whether CMP's current management structure, and the management and other services from its affiliates, are appropriate and in the interest of Maine customers. The management audit was commenced in July 2020 by the MPUC’s consultants and is expected to conclude in 2021.
NYSEG and RG&E Rate Plans
On November 19, 2020, the NYPSC approved a new three-year rate plan for NYSEG & RG&E (2020 Joint Proposal), with modifications to the rate increases at the two electric businesses. The effective date of new tariffs was December 1, 2020 with a make-whole provision back to April 17, 2020. The proposed rates facilitate the companies’ transition to a cleaner energy future while allowing for important initiatives such as COVID-19 relief for customers and additional funding for vegetation management, hardening/resiliency and emergency preparedness. The rate plans continue the RAM designed to return or collect certain defined reconciled revenues and costs, have new depreciation rates and continue existing RDMs for each business. The 2020 Joint Proposal bases delivery revenues on an 8.80% ROE and 48.00% equity ratio; however, for the proposed earnings sharing mechanism, the equity ratio is the lower of the actual equity ratio or 50.00%. The below table provides a summary of
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the approved delivery rate increases and delivery rate percentages, including rate levelization and excluding energy efficiency, which is a pass-through, for all four businesses:
Year 1Year 2Year 3
Rate IncreaseDelivery Rate %Rate IncreaseDelivery Rate %Rate IncreaseDelivery Rate %
Utility(Millions)Increase(Millions)Increase(Millions)Increase
NYSEG Electric$344.6 %$46 5.9 %$36 4.2 %
NYSEG Gas$0%$0.8 %$1.6 %
RG&E Electric$173.8 %$14 3.2 %$16 3.3 %
RG&E Gas$0%$%$1.3 %
UI, CNG, SCG and BGC Rate Plans
In 2016, the Connecticut Public Utilities Regulatory Authority (PURA) approved new distribution rate schedules for The United Illuminating Company (UI) for three years, which became effective January 1, 2017 and, among other things, provide for annual tariff increases and an ROE of 9.10% based on a 50.00% equity ratio, continued UI’s existing earnings sharing mechanism (ESM) pursuant to which UI and its customers share on a 50/50 basis all distribution earnings above the allowed ROE in a calendar year, continued the existing decoupling mechanism and approved the continuation of the requested storm reserve. Any dollars due to customers from the ESM continue to be first applied against any storm regulatory asset balance (if one exists at that time) or refunded to customers through a bill credit if such storm regulatory asset balance does not exist.
In 2017, PURA approved new tariffs for the Southern Connecticut Gas Company (SCG) effective January 1, 2018. The new tariffs also include an RDM and Distribution Integrity Management Program (DIMP) mechanism, ESM, the amortization of certain regulatory liabilities (most notably accumulated hardship deferral balances and certain accumulated deferred income taxes) and tariff increases based on an ROE of 9.25% and an equity ratio of approximately 52.00%. Any dollars due to customers from the ESM will be first applied against any environmental regulatory asset balance as defined in the settlement agreement (if one exists at that time) or refunded to customers through a bill credit if such environmental regulatory asset balance does not exist.
In 2018, PURA approved new tariffs for Connecticut Natural Gas Corporation (CNG) effective January 1, 2019 for a three-year rate plan with annual rate increases. The new tariffs continued the RDM and DIMP mechanism. ESM and tariff increases are based on an ROE of 9.30% and an equity ratio of 54.00% in 2019, 54.50% in 2020 and 55.00% in 2021.
In 2019, the Massachusetts Department of Public Utilities (DPU) approved new distribution rates for BGC. The distribution rate increase is based on a 9.70% ROE and 54.00% equity ratio. The new tariffs provide for the implementation of an RDM and pension expense tracker and also provide that BGC will not file to change base distribution rates to become effective before November 1, 2021.
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 certain penalties and reimbursements to customers after storm outages greater than 96 hours and extends rate case timelines.
Pursuant to the legislation, on October 30, 2020, PURA reopened a docket related to new rate design and review, expanding the scope to consider the implementation of an (a) interim rate decrease; (b) low income rates; and (c) economic development rates. Seperately, UI was due to make its annual rate adjustment mechanism (RAM) filing on March 8, 2021 for the approval of its RAM Rate Components reconciliations: Generation Services Charges, By-passable Federally Mandated Congestion Costs, System Benefits Charge, Transmission Adjustment Charge and RDM. PURA had previously delayed implementation of those rates for a year in 2020.
On March 9, 2021, UI, jointly with the Office of the CT Attorney General, the Office of CT Consumer Counsel, DEEP and PURA’s Office of Education, Outreach, and Enforcement entered into a settlement agreement and filed a motion to approve the settlement agreement which addressed issues in both dockets.
On April 14, 2021, PURA issued a draft decision which declined to approve the settlement agreement. UI filed written exceptions and held oral arguments. As a result, on April 26, 2021, PURA issued an order suspending the procedural schedule for a period up to and including July 2, 2021, so that the parties to the Settlement could address certain issues PURA identified
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in the order. A revised procedural schedule will be issued at a later date. We cannot predict the outcome of these proceedings, including the potential impact on the recovery of UI’s RAM components or the interim rate reduction proceeding.
PURA Investigation of the Preparation for and Response to the Tropical Storm Isaias and Connecticut Storm Reimbursement Legislation
On August 6, 2020, the PURA opened a docket to investigate the preparation for and response to Tropical Storm Isaias by the electric distribution companies in Connecticut including UI. Following hearings and the submission of testimony, PURA issued a final decision on April 15, 2021, finding that UI “generally met standards of acceptable performance in its preparation and response to Tropical Storm Isaias," subject to certain exceptions noted in the decision, but ordered a 15 basis point 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. We cannot predict the final outcome of this investigation or potential penalties that may be assessed.
Regulatory Assets and Liabilities
The regulatory assets and regulatory liabilities shown in the tables below result from various regulatory orders that allow for the deferral and/or reconciliation of specific costs. Regulatory assets and regulatory liabilities are classified as current when recovery or refund in the coming year is allowed or required through a specific order or when the rates related to a specific regulatory asset or regulatory liability are subject to automatic annual adjustment.
Regulatory assets as of March 31, 2021 and December 31, 2020, respectively, consisted of:
March 31,December 31,
As of20212020
(Millions)
Pension and other post-retirement benefits cost deferrals$99 $105 
Pension and other post-retirement benefits902 927 
Storm costs460 451 
Rate adjustment mechanism50 33 
Revenue decoupling mechanism71 58 
Transmission revenue reconciliation mechanism36 31 
Contracts for differences85 86 
Hardship programs15 20 
Plant decommissioning
Deferred purchased gas30 
Deferred transmission expense26 26 
Environmental remediation costs247 247 
Debt premium80 83 
Unamortized losses on reacquired debt25 26 
Unfunded future income taxes382 373 
Federal tax depreciation normalization adjustment146 148 
Asset retirement obligation21 21 
Deferred meter replacement costs36 33 
COVID-19 cost recovery11
Other212 180 
Total regulatory assets2,900 2,882 
Less: current portion317 310 
Total non-current regulatory assets$2,583 $2,572 
“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.
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“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.
“Reliability support services” represents the difference between actual expenses for reliability support services and the amount provided in rates.
"Revenue decoupling mechanism" represents the mechanism established to disassociate the utility's profits from its delivery/commodity sales.
"Transmission revenue reconciliation mechanism" reflects differences in actual costs in the rate year from those used to set rates. This mechanism contains the Annual Transmission True up (ATU), which is recovered over the subsequent June to May period.
“Contracts for Differences” represent the deferral of unrealized gains and losses on contracts for differences derivative contracts. The balance fluctuates based upon quarterly market analysis performed on the related derivatives. The amounts, which do not earn a return, are fully offset by a corresponding derivative asset/liability.
“Hardship Programs” represent hardship customer accounts deferred for future recovery to the extent they exceed the amount in rates.
“Deferred Purchased Gas” represents the difference between actual gas costs and gas costs collected in rates.
“Deferred Transmission Expense” represents deferred transmission income or expense and fluctuates based upon actual revenues and revenue requirements.
“Environmental remediation costs” includes spending that has occurred and is eligible for future recovery in customer rates. Environmental costs are currently recovered through a reserve mechanism whereby projected spending is included in rates with any variance recorded as a regulatory asset or a regulatory liability. The amortization period will be established in future proceedings and will depend upon the timing of spending for the remediation costs. It also includes the anticipated future rate recovery of costs that are recorded as environmental liabilities since these will be recovered when incurred. Because no funds have yet been expended for the regulatory asset related to future spending, it does not accrue carrying costs and is not included within rate base.
“Debt premium” represents the regulatory asset recorded to offset the fair value adjustment to the regulatory component of the non-current debt of UIL at the acquisition date. This amount is being amortized to interest expense over the remaining term of the related outstanding debt instruments.
“Unamortized losses on reacquired debt” represent deferred losses on debt reacquisitions that will be recovered over the remaining original amortization period of the reacquired debt.
“Unfunded future income taxes” represent unrecovered federal and state income taxes primarily resulting from regulatory flow through accounting treatment and are the offset to the unfunded future deferred income tax liability recorded. The income tax benefits or charges for certain plant related timing differences, such as removal costs, are immediately flowed through to, or collected from, customers. This amount is being amortized as the amounts related to temporary differences that give rise to the deferrals are recovered in rates. These amounts are being collected over a period of forty-six years, and the NYPSC staff has initiated an audit, as required, of the unfunded future income taxes and other tax assets to verify the balances.
“Federal tax depreciation normalization adjustment” represents the revenue requirement impact of the difference in the deferred income tax expense required to be recorded under the IRS normalization rules and the amount of deferred income tax expense that was included in cost of service for rate years covering 2011 forward. The recovery period in New York is from 25 to 35 years and for CMP 32.5 years beginning in 2020.
“Asset retirement obligations” (ARO) represents the differences in timing of the recognition of costs associated with our AROs and the collection of such amounts through rates. This amount is being amortized at the related depreciation and accretion amounts of the underlying liability.
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“Deferred meter replacement costs” represent the deferral of the book value of retired meters which were replaced or are planned to be replaced by advanced metering infrastructure meters. This amount is being amortized over the initial depreciation period of related retired meters.
"COVID-19 cost recovery" represents 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.
“Other” includes post-term amortization deferrals and various items subject to reconciliation including excess generation service charge, hedge losses and deferred property tax.
Regulatory liabilities as of March 31, 2021 and December 31, 2020, respectively, consisted of:
March 31,December 31,
As of20212020
(Millions)
Energy efficiency portfolio standard$51 $58 
Gas supply charge and deferred natural gas cost
Pension and other post-retirement benefits cost deferrals57 59 
Carrying costs on deferred income tax bonus depreciation32 34 
Carrying costs on deferred income tax - Mixed Services 263(a)10 11 
2017 Tax Act1,417 1,435 
Rate Change Levelization82 55 
Revenue decoupling mechanism
Accrued removal obligations1,190 1,184 
Asset sale gain account
Economic development28 28 
Positive benefit adjustment28 30 
Theoretical reserve flow thru impact10 
Deferred property tax29 31 
Net plant reconciliation19 20 
Debt rate reconciliation60 63 
Rate refund – FERC ROE proceeding33 33 
Transmission congestion contracts23 22 
Merger-related rate credits13 14 
Accumulated deferred investment tax credits24 25 
Asset retirement obligation18 18 
Earning sharing provisions16 17 
Middletown/Norwalk local transmission network service collections18 18 
Low income programs31 28 
Non-firm margin sharing credits17 14 
New York 2018 winter storm settlement
Other207 176 
Total regulatory liabilities3,442 3,411 
Less: current portion292 274 
Total non-current regulatory liabilities$3,150 $3,137 
“Energy efficiency portfolio standard” represents the costs of energy efficiency programs deferred for future recovery to the extent they exceed the amount in rates. A portion of this balance is amortized through current rates, the remaining portion will be refunded in future periods through future rate cases. The amortization period in current rates is three years and began in 2020.
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"Gas supply charge and deferred natural gas cost" reflects the actual costs of purchasing, transporting and storing of natural gas. Gas supply reconciliation is determined by comparing actual gas supply expenses to the monthly gas cost recoveries in rates. Prior rate year balances are collected/returned to customers beginning the next calendar year.
“Pension and other postretirement benefits cost deferrals” include the difference between actual expense for pension and other post-retirement benefits and the amount provided for in rates for certain of our regulated utilities. A portion of this balance is amortized through current rates, the remaining portion will be refunded in future periods through future rate cases.
“Carrying costs on deferred income tax bonus depreciation” represent the carrying costs benefit of increased accumulated deferred income taxes created by the change in tax law allowing bonus depreciation. A portion of this balance is amortized through current rates, the remaining portion will be refunded in future periods through future rate cases. The amortization period in current rates is three years and began in 2020.
"Carrying costs on deferred income tax - Mixed Services 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. The amortization period in current rates is three years and began in 2020.
“2017 Tax Act” represents the impact from remeasurement of deferred income tax balances as a result of the Tax Act enacted by the U.S. federal government on December 22, 2017. Reductions in accumulated deferred income tax balances due to the reduction in the corporate income tax rates from 35% to 21% under the provisions of the Tax Act will result in amounts previously and currently collected from utility customers for these deferred taxes to be refundable to such customers, generally through reductions in future rates. The NYPSC, MPUC, PURA and DPU have instituted separate proceedings in New York, Maine, Connecticut and Massachusetts, respectively, to review and address the implications associated with the Tax Act on the utilities providing service in such states.
"Rate change levelization" adjusts the New York delivery rate increases across the three-year plan to avoid unnecessary spikes and offsetting dips in customer rates. A portion of this balance is amortized through current rates, the remaining portion will be refunded in future periods through future rate cases. The amortization period in current rates is five years and began in 2020.
"Revenue decoupling mechanism" represents the mechanism established to disassociate the utility's profits from its delivery/commodity sales.
“Accrued removal obligations” represent the differences between asset removal costs recorded and amounts collected in rates for those costs. The amortization period is dependent upon the asset removal costs of underlying assets and the life of the utility plant.
“Asset sale gain account” represents the net gain on the sale of certain assets that will be used for the future benefit of customers. The amortization period in current rates is three years for NYSEG and two years for RG&E and began in 2020.
“Economic development” represents the economic development program, which enables NYSEG and RG&E to foster economic development through attraction, expansion and retention of businesses within its service territory. If the level of actual expenditures for economic development allocated to NYSEG and RG&E varies in any rate year from the level provided for in rates, the difference is refunded to customers. A portion of this balance is amortized through current rates, the remaining portion will be refunded in future periods through future rate cases. The amortization period in current rates is three years and began in 2020.
“Positive benefit adjustment” resulted from Iberdrola’s 2008 acquisition of AVANGRID (formerly Energy East Corporation). This is being used to moderate increases in rates. A portion of this balance is amortized through current rates, the remaining portion will be refunded in future periods through future rate cases. The amortization period in current rates is three years and began in 2020.
“Theoretical reserve flow thru impact” represents the differences from the rate allowance for applicable federal and state flow through impacts related to the excess depreciation reserve amortization. It also represents the carrying cost on the differences. A portion of this balance is amortized through current rates, the remaining portion will be refunded in future periods through future rate cases. The amortization period in current rates is three to five years and began in 2020.
"Deferred property tax" represents the difference between actual expense for property taxes recoverable from customers and the amount provided 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. The amortization period in current rates is five years and began in 2020.
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"Net plant reconciliation" represents the reconciliation of the actual electric and gas net plant and book depreciation to the targets set forth in the 2020 Joint Proposal. A portion of this balance is amortized through current rates, the remaining portion will be refunded in future periods through future rate cases. The amortization period in current rates is five years and began in 2020.
"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. The amortization period in current rates is five years and began in 2020.
“Merger-related rate credits” resulted from the acquisition of UIL. This is being used to moderate increases in rates. During both the three months ended March 31, 2021 and 2020, $1 million of rate credits were applied against customer bills.
"Asset retirement obligation" represents the differences in timing of the recognition of costs associated with our AROs and the collection of such amounts through rates. This amount is being amortized at the related depreciation and accretion amounts of the underlying liability.
"Earning sharing provisions" represents the annual earnings over the earnings sharing threshold. A portion of this balance is amortized through current rates, the remaining portion will be refunded in future periods through future rate cases.
"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.
“Low income programs” represent various hardship and payment plan programs approved for recovery.
"New York 2018 winter storm settlement" represents the settlement amount with the NYPSC following the comprehensive investigation of New York’s major utility companies’ preparation and response to March 2018 storms. The balance is being amortized through current rates over an amortization period of three years, beginning in 2020.
“Other” includes cost of removal being amortized through rates and various items subject to reconciliation.
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 for deferred compensation plans and a supplemental retirement benefit life insurance trust. The Rabbi Trusts primarily include equity securities, fixed income and money market funds. We measure the fair value of our Rabbi Trust portfolio using observable, unadjusted quoted market prices in active markets for identical assets and include the measurements in Level 1. We measure the fair value of the supplemental retirement benefit life insurance trust based on quoted prices in the active markets for the various funds within which the assets are held and include the measurement in Level 2.
NYSEG and RG&E enter into electric energy derivative contracts to hedge the forecasted purchases required to serve their electric load obligations. They hedge their electric load obligations using derivative contracts that are settled based upon Locational Based Marginal Pricing published by the NYISO. NYSEG and RG&E hedge approximately 70% of their electric load obligations using contracts for a NYISO location where an active market exists. The forward market prices used to value the companies’ open electric energy derivative contracts are based on quoted prices in active markets for identical assets or liabilities with no adjustment required and therefore we include the fair value measurements in Level 1.
NYSEG and RG&E enter into natural gas derivative contracts to hedge their forecasted purchases required to serve their natural gas load obligations. The forward market prices used to value open natural gas derivative contracts are exchange-based prices for the identical derivative contracts traded actively on the New York Mercantile Exchange (NYMEX). Because we use prices quoted in an active market we include the fair value measurements in Level 1.
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NYSEG, RG&E and CMP enter into fuel derivative contracts to hedge their unleaded and diesel fuel requirements for their fleet vehicles. Exchange-based forward market prices are used, but because an unobservable basis adjustment is added to the forward prices, we include the fair value measurement for these contracts in Level 3.
UI enters into CfDs, which are marked-to-market based on a probability-based expected cash flow analysis that is discounted at risk-free interest rates and an adjustment for non-performance risk using credit default swap rates. We include the fair value measurement for these contracts in Level 3 (See Note 7 for further discussion of CfDs).
We determine the fair value of our derivative assets and liabilities associated with Renewables activities utilizing market approach valuation techniques. Exchange-traded transactions, such as NYMEX futures contracts, that are based on quoted market prices in active markets for identical products with no adjustment are included in fair value Level 1. Contracts with delivery periods of two years or less which are traded in active markets and are valued with or derived from observable market data for identical or similar products such as over-the-counter NYMEX, foreign exchange swaps, and fixed price physical and basis and index trades are included in fair value Level 2. Contracts with delivery periods exceeding two years or that have unobservable inputs or inputs that cannot be corroborated with market data for identical or similar products are included in fair value Level 3. The unobservable inputs include historical volatilities and correlations for tolling arrangements and extrapolated values for certain power swaps. The valuation for this category is based on our judgments about the assumptions market participants would use in pricing the asset or liability since limited market data exists.
We determine the fair value of our 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, the short-term investment from the proceeds of the Iberdrola Loan, restricted cash, accounts receivable, accounts payable, notes payable, lease obligations and interest accrued approximate their estimated fair values and are considered Level 1.
Restricted cash was $4 million as of both March 31, 2021 and December 31, 2020, and is included in "Other Assets" on our condensed consolidated balance sheets.
The financial instruments measured at fair value as of March 31, 2021 and December 31, 2020, respectively, consisted of:
As of March 31, 2021Level 1Level 2Level 3NettingTotal
(Millions)     
Equity investments with readily determinable fair values$43 $14 $0 $ $57 
Derivative assets
Derivative financial instruments - power$$27 $101 $(53)$82 
Derivative financial instruments - gas23 17 (27)13 
Contracts for differences
Total$7 $50 $120 $(80)$97 
Derivative liabilities
Derivative financial instruments - power$(20)$(66)$(31)$93 $(24)
Derivative financial instruments - gas(1)(5)(1)(1)
Contracts for differences(87)(87)
Derivative financial instruments – Other(5)(5)
Total$(21)$(76)$(119)$99 $(117)
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As of December 31, 2020Level 1Level 2Level 3NettingTotal
(Millions)     
Equity investments with readily determinable fair values$49 $14 $0 $ $63 
Derivative assets
Derivative financial instruments - power$$31 $105 $(54)$87 
Derivative financial instruments - gas24 19 (35)
Contracts for differences
Total$5 $55 $126 $(89)$97 
Derivative liabilities
Derivative financial instruments - power$(23)$(31)$(23)$72 $(5)
Derivative financial instruments - gas(1)(9)(2)(3)
Contracts for differences(88)(88)
Total$(24)$(40)$(113)$81 $(96)
The reconciliation of changes in the fair value of financial instruments based on Level 3 inputs for the three months ended March 31, 2021 and 2020, respectively, is as follows:
Three Months Ended March 31,
(Millions)20212020
Fair Value Beginning of Period,$13 $25 
Gains recognized in operating revenues11 13 
(Losses) recognized in operating revenues(4)(10)
Total gains recognized in operating revenues
Gains recognized in OCI
(Losses) recognized in OCI(17)(5)
Total gains (losses) recognized in OCI(16)(4)
Net change recognized in regulatory assets and liabilities(3)
Settlements(4)(6)
Fair Value as of March 31,$$15 
Gains for the period included in operating revenues attributable to the change in unrealized gains relating to financial instruments still held at the reporting date$$
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 March 31, 2021  
IndexAvg.Max.Min.
NYMEX ($/MMBtu)$2.59 $3.47 $1.48 
AECO ($/MMBtu)$1.58 $3.24 $(0.17)
Ameren ($/MWh)$26.21 $40.53 $14.73 
COB ($/MWh)$33.68 $120.68 $8.20 
ComEd ($/MWh)$24.14 $39.26 $12.65 
ERCOT N hub ($/MWh)$32.00 $196.95 $11.25 
ERCOT S hub ($/MWh)$32.26 $203.37 $11.41 
Indiana hub ($/MWh)$28.24 $43.58 $16.36 
Mid C ($/MWh)$29.96 $95.00 $4.00 
Minn hub ($/MWh)$22.79 $37.78 $11.52 
NoIL hub ($/MWh)$24.02 $39.01 $12.70 
PJM W hub ($/MWh)$28.19 $59.53 $14.28 
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Our Level 3 valuations primarily consist of NYMEX gas and fixed price power swaps with delivery periods extending through 2024 and 2032, respectively. The gas swaps are used to hedge merchant wind positions. The power swaps are used to hedge merchant wind production in the West and Midwest.
We considered the measurement uncertainty regarding Level 3 gas and power positions to changes in the valuation inputs. Given the nature of the transactions in Level 3, the only material input to the valuation is the market price of gas or power for transactions with delivery periods exceeding two years. The fixed price power swaps are economic hedges of future power generation, with decreases in power prices resulting in unrealized gains and increases in power prices resulting in unrealized losses. The gas swaps are economic hedges of merchant generation, with decreases in gas prices resulting in unrealized gains and increases in gas prices resulting in unrealized losses. As all transactions are economic hedges of the underlying position, any changes in the fair value of these transactions will be offset by changes in the anticipated purchase/sales price of the underlying commodity.
Two elements of the analytical infrastructure employed in valuing transactions are the price curves used in the calculation of market value and the models themselves. We maintain and document authorized trading points and associated forward price curves, and we develop and document models used in valuation of the various products.
Transactions are valued in part on the basis of forward price, correlation and volatility curves. We maintain and document descriptions of these curves and their derivations. Forward price curves used in valuing the transactions are applied to the full duration of the transaction.
The determination of fair value of the CfDs (see Note 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 InputMarch 31, 2021
Risk of non-performance0.39% - 0.54%
Discount rate0.35% - 0.92%
Forward pricing ($ per KW-month)$2.00 - $5.30
Fair Value of Debt
As of March 31, 2021 and December 31, 2020, debt consisted of the Iberdrola Loan (see Note 14), first mortgage bonds, unsecured pollution control notes and other various non-current debt securities. The estimated fair value of debt was $11,607 million and $12,166 million as of March 31, 2021 and December 31, 2020, 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. All 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.
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(a) Networks activities
The tables below present Networks' derivative positions as of March 31, 2021 and December 31, 2020, respectively, including those subject to master netting agreements and the location of the net derivative positions on our condensed consolidated balance sheets:
As of March 31, 2021Current AssetsNoncurrent AssetsCurrent LiabilitiesNoncurrent Liabilities
(Millions)    
Not designated as hedging instruments    
Derivative assets$$$$
Derivative liabilities(6)(2)(30)(78)
(24)(76)
Designated as hedging instruments
Derivative assets
Derivative liabilities(4)(1)
(4)(1)
Total derivatives before offset of cash collateral(28)(77)
Cash collateral receivable11 
Total derivatives as presented in the balance sheet$$$(17)$(75)
As of December 31, 2020Current AssetsNoncurrent AssetsCurrent LiabilitiesNoncurrent Liabilities
(Millions)    
Not designated as hedging instruments    
Derivative assets$$$$
Derivative liabilities(3)(4)(34)(78)
(31)(75)
Designated as hedging instruments
Derivative assets
Derivative liabilities(1)
(1)
Total derivatives before offset of cash collateral(32)(75)
Cash collateral receivable18 
Total derivatives as presented in the balance sheet$$$(14)$(74)
The net notional volumes of the outstanding derivative instruments associated with Networks' activities as of March 31, 2021 and December 31, 2020, respectively, consisted of:
 March 31,December 31,
As of20212020
(Millions)  
Wholesale electricity purchase contracts (MWh)5.2 5.6 
Natural gas purchase contracts (Dth)8.2 9.5 
Fleet fuel purchase contracts (Gallons)2.6 2.5 
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.
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NYSEG and RG&E have purchased gas adjustment clauses that allow us to recover through rates any changes in the market price of purchased natural gas, substantially eliminating our exposure to natural gas price risk. NYSEG and RG&E use natural gas futures and forwards to manage fluctuations in natural gas commodity prices to provide price stability to customers. We include the cost or benefit of natural gas futures and forwards in the commodity cost that is passed on to customers when the related sales commitments are fulfilled. We record changes in the fair value of natural gas hedge contracts to derivative assets and/or liabilities with an offset to regulatory assets and/or regulatory liabilities in accordance with the accounting requirements for regulated operations.
The amounts for electricity hedge contracts and natural gas hedge contracts recognized in regulatory liabilities and assets as of March 31, 2021 and December 31, 2020 and amounts reclassified from regulatory assets and liabilities into income for the three months ended March 31, 2021 and 2020 are as follows:
(Millions)Loss or Gain Recognized in Regulatory Assets/LiabilitiesLocation of Loss (Gain) Reclassified from Regulatory Assets/Liabilities into IncomeLoss (Gain) Reclassified from Regulatory Assets/Liabilities into Income
As ofThree Months Ended March 31,
March 31, 2021ElectricityNatural Gas2021 ElectricityNatural Gas
Regulatory assets$13 $Purchased power, natural gas and fuel used$$(1)
December 31, 20202020 
Regulatory assets$17 $Purchased power, natural gas and fuel used$21 $
Pursuant to a PURA order, UI and Connecticut’s other electric utility, The Connecticut Light and Power Company (CL&P), each executed 2 long-term CfDs with certain incremental capacity resources, each of which specifies a capacity quantity and a monthly settlement that reflects the difference between a forward market price and the contract price. The costs or benefits of each contract will be paid by or allocated to customers and will be subject to a cost-sharing agreement between UI and CL&P pursuant to which approximately 20% of the cost or benefit is borne by or allocated to UI customers and approximately 80% is borne by or allocated to CL&P customers.
PURA has determined that costs associated with these CfDs will be fully recoverable by UI and CL&P through electric rates, and UI has deferred recognition of costs (a regulatory asset) or obligations (a regulatory liability), including carrying costs. For those CfDs signed by CL&P, UI records its approximate 20% portion pursuant to the cost-sharing agreement noted above. As of March 31, 2021, UI has recorded a gross derivative asset of $2 million ($0 of which is related to UI’s portion of the CfD signed by CL&P), a regulatory asset of $85 million, a gross derivative liability of $87 million ($84 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, 2020, UI had recorded a gross derivative asset of $2 million ($0 of which is related to UI’s portion of the CfD signed by CL&P), a regulatory asset of $86 million, a gross derivative liability of $88 million ($85 million of which is related to UI’s portion of the CfD signed by CL&P) and a regulatory liability of $0.
The unrealized gains and losses from fair value adjustments to these derivatives, which are recorded in regulatory assets, for the three months ended March 31, 2021 and 2020, respectively, were as follows:
Three Months Ended March 31,
 20212020
(Millions)  
Derivative assets$$
Derivative liabilities$$(3)
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Derivatives designated as hedging instruments
The effect of derivatives in cash flow hedging relationships on Other Comprehensive Income (OCI) and income for the three months ended March 31, 2021 and 2020, respectively, consisted of:
Three Months Ended March 31,Gain (Loss) Recognized in OCI on Derivatives (a)Location of Loss Reclassified from Accumulated OCI into IncomeLoss Reclassified from Accumulated OCI into IncomeTotal amount per Income Statement
(Millions)
2021
Interest rate contracts$Interest expense$$73 
Commodity contractsPurchased power, natural gas and fuel used501 
Foreign currency exchange contracts(4)
Total$(3)$1 
2020
Interest rate contracts$Interest expense$$76 
Commodity contracts(2)Purchased power, natural gas and fuel used475 
Foreign currency exchange contracts(6)
Total$(8)$1 
(a) Changes in accumulated OCI are reported on a pre-tax basis.
The net loss in accumulated OCI related to previously settled forward starting swaps and accumulated amortization is $50 million and $51 million as of March 31, 2021 and December 31, 2020, respectively. For both the three months ended March 31, 2021 and 2020, Networks recorded net derivative losses related to discontinued cash flow hedges of $1 million. Networks will amortize approximately $3 million of discontinued cash flow hedges for the remainder of 2021.
Unrealized losses of $4 million on hedge derivatives are reported in OCI because the forecasted transactions are considered to be probable as of March 31, 2021. Networks expects $0 of those losses will be reclassified into earnings within the next twelve months. The maximum length of time over which Networks hedges its exposure to the variability in future cash flows for forecasted fleet fuel transactions is 12 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.
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The net notional volumes of outstanding derivative instruments associated with Renewables' activities as of March 31, 2021 and December 31, 2020, respectively, consisted of:
March 31,December 31,
As of20212020
(MWh/Dth in millions)  
Wholesale electricity purchase contracts
Wholesale electricity sales contracts
Natural gas and other fuel purchase contracts24 24 
Financial power contracts12 12 
Basis swaps – purchases32 35 
Basis swaps – sales
The fair values of derivative contracts associated with Renewables' activities as of March 31, 2021 and December 31, 2020, respectively, consisted of:
March 31,December 31,
As of20212020
(Millions)  
Wholesale electricity purchase contracts$21 $
Wholesale electricity sales contracts(30)11 
Natural gas and other fuel purchase contracts13 
Financial power contracts67 66 
Basis swaps – purchases
Total$71 $88 
The tables below present Renewables' derivative positions as of March 31, 2021 and December 31, 2020, respectively, including those subject to master netting agreements and the location of the net derivative position on our condensed consolidated balance sheets:
As of March 31, 2021Current AssetsNoncurrent AssetsCurrent LiabilitiesNoncurrent Liabilities
(Millions)
Not designated as hedging instruments
Derivative assets$37 $82 $19 $10 
Derivative liabilities(5)(2)(39)(14)
32 80 (20)(4)
Designated as hedging instruments
Derivative assets14 
Derivative liabilities(6)(1)(12)(23)
(4)(10)(9)
Total derivatives before offset of cash collateral28 80 (30)(13)
Cash collateral (payable) receivable(5)(8)16 
Total derivatives as presented in the balance sheet$23 $72 $(14)$(10)
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As of December 31, 2020Current AssetsNoncurrent AssetsCurrent LiabilitiesNoncurrent Liabilities
(Millions)
Not designated as hedging instruments
Derivative assets$47 $89 $$
Derivative liabilities(23)(2)(4)(11)
24 87 (2)(2)
Designated as hedging instruments
Derivative assets15 
Derivative liabilities(5)(6)(3)(10)
(1)(3)
Total derivatives before offset of cash collateral27 96 (3)(5)
Cash collateral payable(9)(18)
Total derivatives as presented in the balance sheet$18 $78 $(3)$(5)
Derivatives not designated as hedging instruments
The effects of trading and non-trading derivatives associated with Renewables' activities for the three months ended March 31, 2021, consisted of:
Three Months Ended March 31, 2021
TradingNon-tradingTotal amount per income statement
(Millions)
Operating Revenues
Wholesale electricity purchase contracts$$
Wholesale electricity sales contracts(17)
Financial power contracts(5)(16)
Financial and natural gas contracts(4)
Total gain (loss) included in operating revenues$$(37)$1,966 
Purchased power, natural gas and fuel used
Wholesale electricity purchase contracts$$10 
Financial power contracts
Financial and natural gas contracts
Total gain included in purchased power, natural gas and fuel used$$15 $501 
Total Gain (Loss)$$(22)
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The effects of trading and non-trading derivatives associated with Renewables' activities for the three months ended March 31, 2020, consisted of:
Three Months Ended March 31, 2020
TradingNon-tradingTotal amount per income statement
(Millions)
Operating Revenues
Wholesale electricity purchase contracts$(1)$
Wholesale electricity sales contracts11 
Financial power contracts22 
Total gain included in operating revenues$$33 $1,789 
Purchased power, natural gas and fuel used
Wholesale electricity purchase contracts$$(11)
Financial power contracts(6)
Financial and natural gas contracts(2)
Total loss included in purchased power, natural gas and fuel used$$(19)$475 
Total Gain$$14 
Derivatives designated as hedging instruments
The effect of derivatives in cash flow hedging relationships on accumulated OCI and income for the three months ended March 31, 2021 and 2020, respectively, consisted of:
Three Months Ended March 31,(Loss) Gain Recognized in OCI on Derivatives (a)Location of (Gain) Reclassified from Accumulated OCI into Income(Gain) Reclassified from Accumulated OCI into IncomeTotal amount per Income Statement
(Millions)
2021
Commodity contracts$(28)Operating revenues$(3)$1,966 
2020
Commodity contracts$Operating revenues$$1,789 
(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 $13 million of losses included in accumulated OCI at March 31, 2021, are expected to be reclassified into earnings within the next twelve months. We did not record any net derivative losses related to discontinued cash flow hedges for both the three months ended March 31, 2021 and 2020.
(c) Interest rate contracts
AVANGRID uses financial derivative instruments from time to time to alter its fixed and floating rate debt balances or to hedge fixed rates in anticipation of future fixed rate issuances.
As of March 31, 2021 and December 31, 2020, the net loss in accumulated OCI related to previously settled interest rate contracts was $55 million and $57 million, respectively. For the three months ended March 31, 2021 and 2020, we amortized into income $2 million and $1 million, respectively, of the loss related to settled interest rate contracts. We will amortize approximately $7 million of the net loss on the interest rate contracts for the remainder of 2021.
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The effect of derivatives in cash flow hedging relationships on accumulated OCI for the three months ended March 31, 2021 and 2020, respectively, consisted of:
Three Months Ended March 31,(Loss) Recognized in OCI on Derivatives (a)Location of Loss Reclassified from Accumulated OCI into IncomeLoss Reclassified from Accumulated OCI into IncomeTotal amount per Income Statement
(Millions)
2021
Interest rate contracts$Interest expense$$73 
2020
Interest rate contracts$(31)Interest expense$$76 
(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.
(d) Counterparty credit risk management
NYSEG and RG&E face risks related to counterparty performance on hedging contracts due to counterparty credit default. We have developed a matrix of unsecured credit thresholds that are applicable based on the respective counterparty’s or the counterparty guarantor’s credit rating, as provided by Moody’s or Standard & Poor’s. When our exposure to risk for a counterparty exceeds the unsecured credit threshold, the counterparty is required to post additional collateral or we will no longer transact with the counterparty until the exposure drops below the unsecured credit threshold.
The wholesale power supply agreements of UI contain default provisions that include required performance assurance, including certain collateral obligations, in the event that UI’s credit rating on senior debt were to fall below investment grade. If such an event had occurred as of March 31, 2021, UI would have had to post an aggregate of approximately $16 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 March 31, 2021 and December 31, 2020, the amount of cash collateral under master netting arrangements that have not been offset against net derivative positions was $24 million and $18 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 March 31, 2021 was $13 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 New England Transmission Owners (NETOs) claiming that the approved base ROE of 11.14% used by NETOs in calculating formula rates for transmission service under the ISO-New England Open Access Transmission Tariff (OATT) was not just and reasonable and seeking a reduction of the base ROE with refunds to customers for the 15-month refund periods beginning October 1, 2011 (Complaint I), December 27, 2012 (Complaint II), July 31, 2014 (Complaint III) and April 29, 2016 (Complaint IV).
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On October 16, 2014, the FERC issued its decision in Complaint I, setting the base ROE at 10.57% and a maximum total ROE of 11.74% (base plus incentive ROEs) for the October 2011 – December 2012 period as well as prospectively from October 16, 2014. On March 3, 2015, the FERC upheld its decision and further clarified that the 11.74% ROE cap will be applied on a project specific basis and not on a transmission owner’s total average transmission return. The complaints were consolidated and the administrative law judge issued an initial decision on March 22, 2016. The initial decision determined that, (1) for the fifteen month refund period in Complaint II, the base ROE should be 9.59% and that the ROE Cap (base ROE plus incentive ROEs) should be 10.42% and (2) for the fifteen month refund period in Complaint III and prospectively, the base ROE should be 10.90% and that the ROE Cap should be 12.19%. The initial decision in Complaints II and III is the administrative law judge’s recommendation to the FERC Commissioners.
CMP and UI reserved for refunds for Complaints I, II and III consistent with the FERC’s March 3, 2015 decision in Complaint I. Refunds were provided to customers for Complaint I. The CMP and UI total reserve associated with Complaints II and III is $26 million and $7 million, respectively, as of March 31, 2021, which has not changed since December 31, 2020, except for the accrual of carrying costs. If adopted as final by the FERC, the impact of the initial decision by the FERC administrative law judge would be an additional aggregate reserve for Complaints II and III of $17 million, which is based upon currently available information for these proceedings.
Following various intermediate hearings, orders and appellate decisions, on October 16, 2018, the FERC issued an order directing briefs and proposing a new methodology to calculate the NETOs ROE that is contained in NETOs’ transmission formula rate on file at the FERC (the October 2018 Order). Pursuant to the October 2018 Order, the NETOs filed initial briefs on the proposed methodology in all 4 Complaints on January 11, 2019 and replied to the initial briefs on March 8, 2019.
On November 21, 2019, the FERC issued rulings on 2 complaints challenging the base return on equity for Midcontinent Independent System Operator, or MISO transmission owners. These rulings established a new zone of reasonableness based on equal weighting of the DCF and capital-asset pricing model for establishing the base return on equity. This resulted in a base return on equity of 9.88% as the midpoint of the zone of reasonableness. Various parties have requested rehearing on this decision, which was granted. On May 21, 2020, FERC issued a ruling, which, among other things, adjusted the methodology to determine the MISO transmission owners’ ROE, resulting in an increase in ROE from 9.88% to 10.02% by utilizing the risk premium model in addition to the DCF model and capital-asset pricing model under both prongs of Section 206 of the FPA, and calculated the zone of reasonableness into equal thirds rather than employing the quartile approach. On November 19, 2020, FERC issued an order addressing arguments raised on rehearing of its May 21, 2020 order making minor adjustments to certain typographical errors with regard to some of the case inputs it included in its Risk Premium model analysis. However, those minor adjustments did not affect the outcome of the case, leaving the 10.02% ROE established by the May 21, 2020 order in place. Parties to these orders affecting the MISO transmission owners’ base ROE petitioned for their review at the D.C. Circuit Court of Appeals in January 2021. The NETO’s submitted an amici curia brief in support of the MISO transmission owners’ on March 17, 2021. We cannot predict the outcome of these proceedings, including the potential impact the MISO transmission owners' ROE proceeding may have in establishing a precedent for our pending 4 Complaints.
On April 15, 2021, the FERC issued a supplemental Notice of Proposed Rulemaking (NOPR) that proposes to eliminate the 50 basis point ROE incentive for utilities who join Regional Transmission Organizations after 3 years of membership. Comments on the NOPR are due on May 26, 2021 and reply comments are due on June 10, 2021.
California Energy Crisis Litigation
NaN California agencies brought a complaint in 2001 against a long-term power purchase agreement entered into by Renewables, as seller, to the California Department of Water Resources, as purchaser, alleging that the terms and conditions of the power purchase agreement were unjust and unreasonable. The FERC dismissed Renewables from the proceedings; however, the Ninth Circuit Court of Appeals reversed the FERC's dismissal of Renewables from the proceeding.
Joining with two other parties, Renewables filed a petition for certiorari in the United States Supreme Court on May 3, 2007. In an order entered on June 27, 2008, the Supreme Court granted Renewables’ petition for certiorari, vacated the appellate court's judgment, and remanded the case to the appellate court for further consideration in light of the Supreme Court’s decision in a similar case. In light of the Supreme Court's order, on December 4, 2008, the Ninth Circuit Court of Appeals vacated its prior opinion and remanded the complaint proceedings to the FERC for further proceedings consistent with the Supreme Court's rulings. In 2014, the FERC assigned an administrative law judge to conduct evidentiary hearings. Following discovery, the FERC trial staff recommended that the complaint against Renewables be dismissed.
A hearing was held before a FERC administrative law judge in November and early December 2015. A preliminary proposed ruling by the administrative law judge was issued on April 12, 2016. The proposed ruling found no evidence that Renewables had engaged in any unlawful market conduct that would justify finding the Renewables power purchase agreements unjust and unreasonable. However, the proposed ruling did conclude that the price of the power purchase agreements imposed an
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excessive burden on customers in the amount of $259 million. Renewables position, as presented at hearings and agreed by the FERC trial staff, is that Renewables entered into bilateral power purchase contracts appropriately and complied with all applicable legal standards and requirements. The parties have submitted briefs on exceptions to the administrative law judge’s proposed ruling to the FERC. There is no specific timetable for the FERC's ruling. In April 2018, Renewables requested, based on the nearly two years of delay from the preliminary proposed ruling and the Supreme Court precedent, that the FERC issue a final decision expeditiously. We cannot predict the outcome of this proceeding.
New York State Public Service Commission Show Cause Order Regarding Greenlight Pole Attachments
On November 20, 2020, the NYPSC issued an Order Instituting Proceeding and to Show Cause (the Show Cause Order) regarding alleged violations of the NYPSC’s 2004 Order Adopting Policy Statement on Pole Attachments, dated August 6, 2004 (the 2004 Pole Order) by RG&E, Greenlight Networks, Inc, (Greenlight), and Frontier Communications (Frontier). The alleged violations detailed in the Show Cause Order arise from Greenlight’s installation of unauthorized and substandard communications attachments throughout RG&E’s and Frontier’s service territories. The Show Cause Order directs RG&E to show cause within 30 days why the NYPSC should not pursue civil and/or administrative penalties or initiate a prudency proceeding or civil action for injunctive relief for more than 11,000 alleged violations of the 2004 Pole Order. Under NY Public Service Law Section 25-a, each alleged violation carries a potential penalty of up to $100,000 where it can be shown that the violator failed to “reasonably comply” with a statute or NYPSC order.
RG&E, Greenlight and Frontier filed respective notices to initiate settlement negotiations with respect to the alleged violations and to extend the deadline for filing a response to the Show Cause Order. The NYPSC granted the extension requests initiating settlement discussions. We cannot predict the outcome of this matter.
Beatrice Corwin Living Irrevocable Trust, by and through Its Authorized Trustee, Robert Corwin v. Iberdrola, S.A., et. al.
On January 8, 2021, the Beatrice Corwin Living Irrevocable Trust, by and through its Authorized Trustee, Robert Corwin filed a complaint in the Supreme Court of the State of New York Westchester County against Iberdrola and the members of the Company’s Board of Directors, as defendants, and the Company, as a nominal defendant with respect to certain counts contained in the complaint. The complaint alleges certain violations of fiduciary duties by Iberdrola and the members of the Company’s Board of Directors related to the existence of certain pre-emptive rights provided to Iberdrola in the Shareholder Agreement between the Company and Iberdrola, dated December 16, 2015, and the binding nature of such rights. On March 29, 2021, the parties stipulated to and requested, and the Supreme Court of the State of New York Westchester County issued an Order providing for, the transfer of the venue of the complaint to the Supreme Court, County of New York. We cannot predict the outcome of this matter.
Guarantee Commitments to Third Parties
As of March 31, 2021, we had approximately $612 million of standby letters of credit, surety bonds, guarantees and indemnifications outstanding, including $95 million related to Vineyard Wind. These instruments provide financial assurance to the business and trading partners of AVANGRID and its subsidiaries in their normal course of business. The instruments only represent liabilities if AVANGRID or its subsidiaries fail to deliver on contractual obligations. We therefore believe it is unlikely that any material liabilities associated with these instruments will be incurred and, accordingly, as of March 31, 2021, 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, pursuant to the terms of a transfer agreement dated November 3, 2020. 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.
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-six waste sites, which do not include sites where gas was manufactured in the past. NaN of the NaN sites are
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included in the New York State Registry of Inactive Hazardous Waste Disposal Sites; 5 sites are included in Maine’s Uncontrolled Sites Program; 1 site is included in the Brownfield Cleanup Program and 1 site is included on the Massachusetts Non-Priority Confirmed Disposal Site list. The remaining sites are not included in any registry list. Finally, 6 of the NaN sites are also included on the National Priorities list. Any liability may be joint and several for certain sites.
We have recorded an estimated liability of $6 million related to 11 of the NaN sites. We have paid remediation costs related to the remaining 15 sites and do not expect to incur additional liabilities. Additionally, we have recorded an estimated liability of $9 million related to another 12 sites where we believe it is probable that we will incur remediation and/or monitoring costs, although we have not been notified that we are among the potentially responsible parties or that we are regulated under State Resource Conservation and Recovery Act programs. It is possible the ultimate cost to remediate these sites may be significantly more than the accrued amount. Our estimate for costs to remediate these sites ranges from $13 million to $21 million as of March 31, 2021. 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 NaN sites where gas was manufactured in the past (Manufactured Gas Plants, or MGPs). NaN sites are included in the New York State Registry; 3 sites are included in the New York State Department of Environmental Conservation Multi-Site Order on Consent; 3 sites are part of Maine’s Voluntary Response Action Program with 2 such sites part of Maine’s Uncontrolled Sites Program and one site is pending application into the Brownfield Cleanup Program. The remaining sites are not included in any registry list. We have entered into consent orders with various environmental agencies to investigate and, where necessary, remediate NaN of the NaN sites.
Our estimate for all costs related to investigation and remediation of the NaN sites ranges from $179 million to $291 million as of March 31, 2021. 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; 0 liability was recorded related to these sites as of March 31, 2021 and no amount of loss, if any, can be reasonably estimated at this time. In the past, the companies have received approval for the recovery of MGP-related remediation expenses from customers through rates and will seek recovery in rates for ongoing MGP-related remediation expenses for all of their MGP sites.
As of both March 31, 2021 and December 31, 2020, the liability associated with our MGP sites in Connecticut was $96 million, the remediation costs of which could be significant and will be subject to a review by PURA as to whether these costs are recoverable in rates.
Our total recorded liability to investigate and perform remediation at all known inactive MGP sites discussed above and other sites was $301 million and $300 million as of March 31, 2021 and December 31, 2020, 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 2055.
FirstEnergy
NYSEG and RG&E each sued FirstEnergy under the Comprehensive Environmental Response, Compensation, and Liability Act to recover environmental cleanup costs at certain former MGP sites, which are included in the discussion above. In 2011, the District Court issued a decision and order in NYSEG’s favor, which was upheld on appeal, requiring FirstEnergy to pay NYSEG for past and future clean-up costs at the 16 sites in dispute. In 2008, the District Court issued a decision and order in RG&E favor requiring FirstEnergy to pay RG&E for past and future clean-up costs at the 2 MGP sites in dispute. FirstEnergy remains liable for a substantial share of clean up expenses at the MGP sites. Based on projections as of March 31, 2021, FirstEnergy’s share of clean-up costs owed to NYSEG & RG&E is estimated at approximately $21 million and
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$7 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
In January 2012, Evergreen Power, LLC (Evergreen Power) and Asnat Realty LLC (Asnat), then owners of a former generation site on the Mill River in New Haven (English Station) that UI sold to Quinnipiac Energy in 2000, filed a lawsuit in federal district court in Connecticut related to environmental remediation at the English Station site. This proceeding was stayed in 2014 pending resolutions of other proceedings before the Connecticut Department of Energy and Environmental Protection (DEEP) concerning the English Station site. In December 2016, the court administratively closed the file without prejudice to reopen upon the filing of a motion to reopen by any party.
In December 2013, Evergreen Power and Asnat filed a subsequent lawsuit related to the English Station site. On April 16, 2018, the plaintiffs filed a revised complaint alleging fraud and unjust enrichment against UIL and UI and adding former UIL officers as named defendants alleging fraud. On February 21, 2019, the court granted our Motion to Strike with respect to all counts except for the count against UI for unjust enrichment. The counts stricken include all counts against the individual defendants as well as against UIL. The plaintiffs have appealed the court's decision to strike, and oral arguments have taken place. On May 4, 2021, the Appeals Court affirmed the court's decision striking the counts. We cannot predict the outcome of this matter.
On April 8, 2013, DEEP issued an administrative order addressed to UI, Evergreen Power, Asnat and others, ordering the parties to take certain actions related to investigating and remediating the English Station site. This proceeding was stayed while DEEP and UI continue to work through the remediation process pursuant to the consent order described below. Status reports are periodically filed with DEEP.
On August 4, 2016, DEEP issued a partial consent order (the consent order), that, subject to its terms and conditions, requires UI to investigate and remediate certain environmental conditions within the perimeter of the English Station site. Under the consent order, to the extent that the cost of this investigation and remediation is less than $30 million, UI will remit to the State of Connecticut the difference between such cost and $30 million to be used for a public purpose as determined in the discretion of the Governor of the State of Connecticut, the Attorney General of the State of Connecticut and the Commissioner of DEEP. UI is obligated to comply with the terms of the consent order even if the cost of such compliance exceeds $30 million. Under the terms of the consent order, the state will discuss options with UI on recovering or funding any cost above $30 million such as through public funding or recovery from third parties; however, it is not bound to agree to or support any means of recovery or funding. UI has initiated its process to investigate and remediate the environmental conditions within the perimeter of the English Station site pursuant to the consent order.
As of both March 31, 2021 and December 31, 2020, the amount reserved related to English Station was $22 million. We cannot predict the outcome of this matter.
On April 24, 2020, ACV Environmental Services Company (ACV) filed a lawsuit in Connecticut Superior Court against UI arising out of a contract dispute for services rendered by ACV in the demolition of the Station B at the English Station site. The complaint seeks damages in the amount of $5 million on claims of breach of contract, breach of the covenant of good faith and fair dealing, quantum merit, and unjust enrichment. The claims arise from the alleged non-payment of certain change order requests. The parties have agreed to attempt to mediate this matter during the first half of 2021. We cannot predict the outcome of this matter.
Note 10. Post-retirement and Similar Obligations
We made $13 million of pension contributions for the three months ended March 31, 2021. We expect to make additional contributions of $61 million for the remainder of 2021.
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The components of net periodic benefit cost for pension benefits for the three months ended March 31, 2021 and 2020, respectively, consisted of:
Three Months Ended March 31,
 20212020
(Millions)  
Service cost$10 $12 
Interest cost22 27 
Expected return on plan assets(50)(50)
Amortization of:
Actuarial loss35 31 
Net Periodic Benefit Cost$17 $20 
The components of net periodic benefit cost for postretirement benefits for the three months ended March 31, 2021 and 2020, respectively, consisted of: 
Three Months Ended March 31,
 20212020
(Millions)  
Service cost$$
Interest cost
Expected return on plan assets(2)(2)
Amortization of:
Prior service costs(2)(2)
Actuarial loss
Net Periodic Benefit Cost$0 $0 
Note 11. Equity
As of March 31, 2021 and December 31, 2020, we had 121,188 and 413,782 shares of common stock held in trust, respectively, and 0 convertible preferred shares outstanding. During the three months ended March 31, 2021 and 2020, we released 292,594 and 0 shares of common stock held in trust, respectively.
We maintain a repurchase agreement with J.P. Morgan Securities, LLC. (JPM), pursuant to which JPM will, from time to time, acquire, on behalf of AVANGRID, shares of common stock of AVANGRID. The purpose of the stock repurchase program is to allow AVANGRID to maintain Iberdrola's relative ownership percentage at 81.5%. The stock repurchase program may be suspended or discontinued at any time upon notice. In March 2021, 53,311 shares were repurchased pursuant to the stock repurchase program. As of March 31, 2021, a total of 357,146 shares have been repurchased in the open market, all of which are included as AVANGRID treasury shares. The total cost of all repurchases, including commissions, was $16 million as of March 31, 2021.
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Accumulated Other Comprehensive Loss 
Accumulated Other Comprehensive Loss for the three months ended March 31, 2021 and 2020, respectively, consisted of:
As of December 31,Three Months Ended March 31,As of March 31,As of December 31,Three Months Ended March 31,As of March 31,
202020212021201920202020
(Millions)      
Change in revaluation of defined benefit plans$(12)$$(12)$(12)$$(12)
Loss on nonqualified pension plans(20)(20)(7)(7)
Unrealized loss during period on derivatives qualifying as cash flow hedges, net of income tax benefit of $(5) for 2021 and $(8) 2020(35)(27)(62)(13)(23)(36)
Reclassification to net income of losses on cash flow hedges, net of income tax expense of $(1) for 2021 and $0 for 2020(a)(44)(43)(63)(61)
Loss on derivatives qualifying as cash flow hedges(79)(26)(105)(76)(21)(97)
Accumulated Other Comprehensive Loss$(111)$(26)$(137)$(95)$(21)$(116)
(a)Reclassification is reflected in the operating expenses and interest expense, net of capitalization and line items 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 months ended March 31, 2021 and 2020, while we did have securities that were dilutive, these securities did not result in a change in our earnings per share calculations.
The calculations of basic and diluted earnings per share attributable to AVANGRID, for the three months ended March 31, 2021 and 2020, respectively, consisted of:
Three Months Ended March 31,
 20212020
(Millions, except for number of shares and per share data)  
Numerator:  
Net income attributable to AVANGRID$334 $240 
Denominator:
Weighted average number of shares outstanding - basic309,495,250 309,491,082 
Weighted average number of shares outstanding - diluted309,736,266 309,623,573 
Earnings per share attributable to AVANGRID
Earnings Per Common Share, Basic$1.08 $0.78 
Earnings Per Common Share, Diluted$1.08 $0.78 
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 2 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 8 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 1 reportable segment.
Renewables: activities relating to renewable energy, mainly wind energy generation and trading related with such activities.
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The chief operating decision maker evaluates segment performance based on segment adjusted net income defined as net income adjusted to exclude restructuring charges, mark-to-market earnings from changes in the fair value of derivative instruments and costs incurred in connection with the COVID-19 pandemic.
Products and services are sold between reportable segments and affiliate companies at cost. Segment income, expense and assets presented in the accompanying tables include all intercompany transactions that are eliminated in our condensed consolidated financial statements. Refer to Note 4 - Revenue for more detailed information on revenue by segment.
Segment information as of and for the three months ended March 31, 2021, consisted of:
Three Months Ended March 31, 2021NetworksRenewablesOther (a)AVANGRID Consolidated
(Millions)    
Revenue - external$1,573 $393 $$1,966 
Depreciation and amortization156 91 247 
Operating income313 92 406 
Earnings (losses) from equity method investments(1)
Interest expense, net of capitalization53 20 73 
Income tax expense (benefit)42 (9)(19)14 
Adjusted net income229 123 354 
Capital expenditures531 92 623 
As of March 31, 2021
Property, plant and equipment17,493 9,666 27,168 
Equity method investments134 561 695 
Total assets$25,103 $11,817 $848 $37,768 
(a) Includes Corporate and intersegment eliminations.
Segment information for the three months ended March 31, 2020 and as of December 31, 2020, consisted of:
Three Months Ended March 31, 2020NetworksRenewablesOther (a)AVANGRID
Consolidated
(Millions)    
Revenue - external$1,461 $328 $$1,789 
Depreciation and amortization148 103 251 
Operating income309 13 327 
Earnings (losses) from equity method investments(8)(6)
Interest expense, net of capitalization68 76 
Income tax expense (benefit)43 (30)(1)12 
Adjusted net income198 46 (8)236 
Capital expenditures437 305 742 
As of December 31, 2020    
Property, plant and equipment17,079 9,662 10 26,751 
Equity method investments134 534 668 
Total assets$24,592 $12,867 $364 $37,823 
(a) Includes Corporate and intersegment eliminations.
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Reconciliation of Adjusted Net Income to Net Income attributable to AVANGRID for the three months ended March 31, 2021 and 2020, respectively, is as follows:
Three Months Ended March 31,
 20212020
(Millions)  
Adjusted Net Income Attributable to Avangrid, Inc.$354 $236 
Adjustments:
Mark-to-market earnings - Renewables (1)(20)18 
Restructuring charges (2)(3)
Impact of COVID-19 (3)(6)(10)
Income tax impact of adjustments(2)
Net Income Attributable to Avangrid, Inc.$334 $240 
(1)Mark-to-market earnings relates to earnings impacts from changes in the fair value of Renewables' derivative instruments associated with electricity and natural gas.
(2)Restructuring and severance related charges relate to costs to implement an initiative to mitigate costs and achieve sustainable growth.
(3)Represents costs incurred in connection with the COVID-19 pandemic.
Note 14. Related Party Transactions
We engage in related party transactions that are generally billed at cost and in accordance with applicable state and federal commission regulations.
Related party transactions for the three months ended March 31, 2021 and 2020, respectively, consisted of:
Three Months Ended March 31,20212020
(Millions)Sales ToPurchases FromSales ToPurchases From
Iberdrola Renovables Energía, S.L.$— $(2)$— $(2)
Iberdrola Financiación, S.A.$— $(2)$— $(1)
Iberdrola$— $(13)$— $(10)
Vineyard Wind$$— $$— 
Iberdrola Solutions$$(38)$— $— 
Other$$(1)$$
Related party balances as of March 31, 2021 and December 31, 2020, respectively, consisted of:
As ofMarch 31, 2021December 31, 2020
(Millions)Owed ByOwed ToOwed ByOwed To
Iberdrola$$(11)$$(43)
Iberdrola Renovables Energía, S.L.$— $(2)$— $
Iberdrola Financiación, S.A.$— $(3)$— $(6)
Vineyard Wind$$— $$— 
Iberdrola Solutions$$(8)$$— 
Other$$$$(1)
On December 14, 2020, AVANGRID and Iberdrola, our majority shareholder, entered into an intra-group loan agreement which provided AVANGRID with an unsecured subordinated loan in an aggregate principal amount of $3,000 million (the Iberdrola Loan).
The Iberdrola Loan bears interest (i) from December 16, 2020 until June 15, 2021, at an interest rate of 0.20%, which increases 1 basis point each month following the first month of the term of the Iberdrola Loan up to a maximum interest rate of 0.25%, and (ii) from June 16, 2021 until the Iberdrola Loan and any accrued and unpaid interest is repaid in its entirety, at AVANGRID’s equity cost of capital as published by Bloomberg. Interest is payable on a monthly basis in arrears.
AVANGRID is required to repay the Iberdrola Loan in full upon certain equity issuances by AVANGRID in which Iberdrola participates or a change of control of AVANGRID. In addition, on or after June 15, 2021, upon five business days’ notice to Iberdrola, AVANGRID may voluntarily repay the Iberdrola Loan and any accrued and unpaid interest, in whole or in part,
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without prepayment premium or penalty if there is a change in AVANGRID’s business plan and AVANGRID determines that the Iberdrola Loan is no longer required. The intra-group loan agreement contains certain customary affirmative and negative covenants and events of default.
As of March 31, 2021 and December 31, 2020, the Iberdrola Loan had no current maturities and is included in "Non-current debt with affiliate" on our condensed consolidated balance sheets as we do not intend on repaying the Iberdrola Loan with current assets.
Other transactions with Iberdrola relate predominantly to the provision and allocation of corporate services and management fees. All costs that can be specifically allocated, to the extent possible, are charged directly to the company receiving such services. In situations when Iberdrola corporate services are provided to two or more companies of AVANGRID, any costs remaining after direct charges are allocated using agreed upon cost allocation methods designed to allocate such costs. We believe that the allocation method used is reasonable.
See Note 1 for information on the Side Letter Agreement we entered into with Iberdrola.
We have a bi-lateral demand note agreement with Iberdrola Solutions, LLC, which had notes payable and notes receivable balances of $8 million and $5 million, respectively, as of March 31, 2021 and December 31, 2020. Renewables also has financial forward power contracts with Iberdrola Solutions to hedge Renewables' merchant wind exposure in Texas.
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 0 impairments or provisions made against any affiliated balances.
AVANGRID manages its overall liquidity position as part of the Iberdrola Group and is a party to a liquidity agreement with a financial institution, along with certain members of the Iberdrola Group. Cash surpluses remaining after meeting the liquidity requirements of AVANGRID and its subsidiaries may be deposited at the financial institution. Deposits, or credit balances, serve as collateral against the debit balances of other parties to the liquidity agreement. The balance at both March 31, 2021 and December 31, 2020, was 0.
AVANGRID has a credit facility with Iberdrola Financiacion, S.A.U., a company of the Iberdrola Group. The facility has a limit of $500 million and matures on June 18, 2023. AVANGRID pays a facility fee of 10.5 basis points annually on the facility. As of March 31, 2021 and December 31, 2020, there was 0 outstanding amount under this credit facility.
See Note 19 - Equity Method Investments for more information on Vineyard Wind, LLC (Vineyard Wind).
Note 15. Other Financial Statement Items
Accounts receivable and unbilled revenue, net
Accounts receivable and unbilled revenues, net as of March 31, 2021 and December 31, 2020 consisted of:
As ofMarch 31, 2021December 31, 2020
(Millions)
Trade receivables and unbilled revenues$1,418 $1,295 
Allowance for credit losses(135)(108)
Accounts receivable and unbilled revenues, net$1,283 $1,187 
The change in the allowance for credit losses for the three months ended March 31, 2021 and 2020 consisted of:
Three Months Ended March 31,
(Millions)20212020
As of Beginning of Period,$108 $69 
Current period provision39 19 
Write-off as uncollectible(12)(15)
As of March 31,$135 $73 
The Deferred Payment Arrangements (DPA) receivable balance was $80 million and $78 million at March 31, 2021 and December 31, 2020, respectively. The allowance for credit losses for DPAs at March 31, 2021 and December 31, 2020 was $53 million and $48 million respectively. Furthermore, the change in the allowance for credit losses associated with the DPAs for the three months ended March 31, 2021 and 2020, was $5 million and $0, respectively.
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Prepayments and other current assets
Included in prepayments and other current assets are $145 million and $135 million of prepaid other taxes as of March 31, 2021 and December 31, 2020, respectively.
Property, plant and equipment and intangible assets
The accumulated depreciation and amortization as of March 31, 2021 and December 31, 2020, respectively, were as follows:
 March 31,December 31,
As of20212020
(Millions)  
Property, plant and equipment  
Accumulated depreciation$10,028 $9,799 
Intangible assets  
Accumulated amortization$322 $319 
Debt
As of March 31, 2021 and December 31, 2020, "Notes Payable" consisted of $0 and $309 million, respectively, of commercial paper outstanding, presented net of discounts on our condensed consolidated balance sheets.
Our $500 million credit facility was scheduled to mature on June 28, 2021. We terminated this facility on April 28, 2021.
Note 16. Income Tax Expense
The effective tax rate, inclusive of federal and state income tax, for the three months ended March 31, 2021, was 4.2%, which is below the federal statutory tax rate of 21%, primarily due to the recognition of production tax credits associated with wind production and the effect of the excess deferred tax amortization resulting from the Tax Act.
The effective tax rate, inclusive of federal and state income tax, for the three months ended March 31, 2020, was 5.0%, which is below the federal statutory tax rate of 21%, primarily due to the recognition of production tax credits associated with wind production and the effect of the excess deferred tax amortization resulting from the Tax Act.
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 February 2020, a total number of 208,268 PSUs, before applicable taxes, were approved to be earned by participants based on achievement of certain performance metrics related to the 2016 through 2019 plan and are payable in 3 equal installments, net of applicable taxes. In March 2021, 45,661 shares of common stock were issued to settle the second installment payment. The final payment will occur in 2022.
On February 15, 2021 and March 15, 2021, 1,181,031 and 75,000 PSUs, respectively, were granted to certain officers and employees of AVANGRID with achievement measured based on certain performance and market-based metrics for the 2021 to 2022 performance period. The PSUs will be payable in 3 equal installments, net of applicable taxes, in 2023, 2024 and 2025. The fair value of the PSUs on the grant date was $36.46 per share. The fair value of the PSUs was determined using valuation techniques to forecast possible future stock prices, applying a weighted average historical stock price volatility of AVANGRID and industry companies, a risk-free rate of interest that is equal, as of the grant date, to the yield of the zero-coupon U.S. Treasury bill and a reduction for the respective dividend yield calculated based on the most recently quarterly dividend payment and the stock price as of the grant date. The expense is recognized on a straight-line basis over the requisite service period of approximately four years based on expected achievement.
Restricted Stock Units
In October 2018, 8,000 RSUs were granted to an officer of AVANGRID. The RSUs vested in full in December 2020. The fair value on the grant date was determined based on a price of $47.59 per share. In March 2021, the RSU grant was settled, net of applicable taxes, by issuing 5,953 shares of common stock.
In August 2020, 5,000 RSUs were granted to an officer of AVANGRID. The RSUs vest in 3 equal installments in 2021, 2022 and 2023, provided that the grantee remains continuously employed with AVANGRID through the applicable vesting
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dates. The fair value on the grant date was determined based on a price of $48.99 per share. In February 2021, the first installment of the RSU grant was settled by issuing 1,697 shares of common stock.
Phantom Share Units
In March 2020, 167,060 Phantom Shares were granted to certain AVANGRID executives and employees. These awards vest in 3 equal installments in 2020, 2021 and 2022 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 March 2021, $2 million was paid to settle the second installment under this plan. As of March 31, 2021 and December 31, 2020, the total liability was $1 million and $2 million, respectively, which is included in other current liabilities.
Total stock-based compensation expense, which is included in "Operations and maintenance" in our condensed consolidated statements of income, for the three months ended March 31, 2021 and 2020, was $4 million and $7 million, respectively.
Note 18. Variable Interest Entities
We participate in certain partnership arrangements that qualify as variable interest entities (VIEs). Consolidated VIE's 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.
On February 5, 2021, we closed on the final TEF agreement for Aeolus Wind Power VII, LLC (Aeolus VII) in a non-cash transaction. The 4 Aeolus VII wind farms total 688 MW of wind power.
The assets and liabilities of the VIEs totaled approximately $1,708 million and $81 million, respectively, at March 31, 2021. As of December 31, 2020, the assets and liabilities of VIEs totaled approximately $1,713 million and $107 million, respectively. At March 31, 2021 and December 31, 2020, the assets and liabilities of the VIEs consisted primarily of property, plant and equipment.
At March 31, 2021, El Cabo Wind, LLC (El Cabo), Patriot Wind Farm LLC (Patriot) and Aeolus VII are our consolidated VIEs.
Wind power generation is subject to certain favorable tax treatments in the U.S. In order to monetize the tax benefits, we have entered into these structured institutional partnership investment transactions related to certain wind farms. Under these structures, we contribute certain wind assets, relating both to existing wind farms and wind farms that are being placed into operation at the time of the relevant transaction, and other parties invest in the share equity of the limited liability holding company. As consideration for their investment, the third parties make either an upfront cash payment or a combination of upfront cash and payments over time. We retain a class of membership interest and day-to-day operational and management control, subject to investor approval of certain major decisions. The third-party investors do not receive a lien on any assets and have no recourse against us for their upfront cash payments.
The partnerships generally involve disproportionate allocations of profit or loss, cash distributions and tax benefits resulting from the wind farm energy generation between the investor and sponsor until the investor recovers its investment and achieves a cumulative annual after-tax return. Once this target return is met, the relative sharing of profit or loss, cash distributions and taxable income or loss between the Company and the third-party investor flips, with the sponsor generally receiving higher percentages thereafter. We also have a call option to acquire the third-party investors’ membership interest within a defined time period after this target return is met.
Our El Cabo, Patriot and Aeolus VII interests are not subject to any rights of investors that may restrict our ability to access or use the assets or to settle any existing liabilities associated with the interests.
See Note 19 - Equity Method Investments for information on our VIE we do not consolidate.
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Note 19. Equity Method Investments
Renewables holds a 50% voting interest in Vineyard Wind, LLC (Vineyard Wind), a joint venture with Copenhagen Infrastructure Partners (CIP). Vineyard Wind has acquired 2 easements from the U.S. Bureau of Ocean Energy Management (BOEM) containing the rights to develop offshore wind generation. In total, the 2 lease areas have the potential to generate up to 5,000 MW of renewable energy. The first easement area is 166,886 acres located southeast of Martha's Vineyard. In 2018, Vineyard Wind was selected by the Massachusetts Electric Distribution Companies (EDCs) to construct and operate Vineyard Wind’s proposed 800 MW wind farm and electricity transmission project pursuant to the Massachusetts Green Communities Act Section 83C RFP for offshore wind energy projects. In December 2019, DEEP selected Vineyard Wind to provide 804 MW of offshore wind through the development of its Park City Wind Project.
Vineyard Wind acquired a second offshore easement contract from BOEM. Renewables initially contributed $100 million to Vineyard Wind to acquire the easement contract, which was proportionally more than CIP's contribution. Pursuant to a joint bidding agreement between Renewables and CIP, CIP had the option to reimburse Renewables an amount, plus interest, to restore its 50% interest in the easement contract. In December 2020, CIP exercised this option and will reimburse Renewables $33 million, plus interest.
As of March 31, 2021, under the provisions of the LLC agreement, Renewables has contributed $281 million to Vineyard Wind, net of reimbursement by CIP. We expect to provide additional capital contributions.
Vineyard Wind 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 since it does not have a controlling interest in Vineyard Wind, and therefore we do not consolidate Vineyard Wind. As of March 31, 2021 and December 31, 2020, the carrying amount of Renewables' investment in Vineyard Wind was $274 million and $245 million.
Note 20. Subsequent Event
On April 13, 2021, the board of directors of AVANGRID declared a quarterly dividend of $0.44 per share on its common stock. This dividend is payable on July 1, 2021 to shareholders of record at the close of business on June 4, 2021.
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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, 2020 and 2019, and for the three years ended December 31, 2020, included in our Annual Report on Form 10-K for the year ended December 31, 2020, filed with the Securities and Exchange Commission, or the SEC, on March 1, 2021, 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 is one of the leading sustainable energy companies 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 $38 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 8.6 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 2021 for the third consecutive year by the Ethisphere Institute and is listed by Forbes and Just Capital as one of the 2021 Just 100, an annual ranking of the most just U.S. public companies. AVANGRID employs approximately 7,000 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 81.5% of the outstanding shares of AVANGRID common stock. 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 generation, transmission and distribution 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 March 31, 2021.
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 8,568 megawatts, or MW, as of March 31, 2021, including Renewables’ share of joint projects, of which 7,746 MW was installed wind capacity. As of March 31, 2021, approximately 65% of the capacity was contracted for an average period of 9.4 years, and 14% of production was hedged.
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Being among the top three largest wind operators in the United States based on installed capacity as of March 31, 2021, Renewables strives to lead the transformation of the U.S. energy industry to a sustainable, competitive, clean energy future. Renewables installed capacity includes 65 wind farms and four solar facilities in 21 states across the United States.
Texas Weather Event
During February 2021, Texas and the surrounding region experienced unprecedented extreme cold weather, resulting in outages impacting millions in the state. Avangrid Renewables safely operated our Texas wind generation facilities during this event meeting all of our delivery obligations in Texas and producing excess energy that was sold based on the rules established at the time by the Energy Reliability Council of Texas, or ERCOT. If the received payments are subject to adjustments by ERCOT, it could adversely affect our results of operations.
Proposed Merger with PNMR
On October 20, 2020, AVANGRID, PNM Resources, Inc., a New Mexico corporation, or PNMR, and NM Green Holdings, Inc., a New Mexico corporation and wholly-owned subsidiary of AVANGRID, or Merger Sub, entered into an Agreement and Plan of Merger, or Merger Agreement, pursuant to which Merger Sub is expected to merge with and into PNMR, with PNMR surviving the Merger as a direct wholly-owned subsidiary of AVANGRID, or the Merger. PNMR is a publicly-owned holding company with two regulated utilities providing electricity and electric services in New Mexico and Texas. PNMR's electric utilities are the Public Service Company of New Mexico and the Texas-New Mexico Power Company. Following consummation of the Merger, AVANGRID will expand its geographic and regulatory diversity with ten regulated electric and gas companies in six states to help expand our growing leadership position in transforming the U.S. energy industry.
Pursuant to the Merger Agreement, each issued and outstanding share of the common stock of PNMR (other than (i) the issued shares of PNMR common stock that are owned by AVANGRID, Merger Sub, PNMR or any wholly-owned subsidiary of AVANGRID or PNMR, which will be automatically cancelled at the time the Merger is consummated and (ii) shares of PNMR common stock held by a holder who has not voted in favor of, or consented in writing to, the Merger who is entitled to, and who has demanded, payment for fair value of such shares) will be converted, at the time the Merger is consummated, into the right to receive $50.30 in cash, or Merger Consideration, or approximately $4.3 billion in aggregate consideration. In connection with the Merger, Iberdrola has provided the Iberdrola Funding Commitment Letter, pursuant to which Iberdrola has unilaterally agreed to provide to AVANGRID, or arrange the provision to AVANGRID of, funds to the extent necessary for AVANGRID to consummate the Merger, including the payment of the aggregate Merger Consideration. On February 12, 2021, the shareholders of PNMR approved the proposed Merger. The Merger is expected to close in the second half of 2021 and is subject to certain conditions including certain regulatory approvals and entry into agreements providing for, and to making filings required to, exit from all ownership interests in the Four Corners Power Plant and certain other customary closing conditions. During the period ended March 31, 2021, the Merger obtained regulatory approval under the the Hart-Scott-Rodino Antitrust Improvements Act of 1976 and approvals from the Committee on Foreign Investment in the United States and the Federal Communications Commission. During April 2021, the Merger received approval from the Federal Energy Regulatory Commission.
In connection with the Merger, purported shareholders of PNMR have filed lawsuits against PNMR and the members of the PNMR board of directors under the federal securities laws, challenging the adequacy of the disclosures made in PNMR’s proxy statement in connection with the Merger or otherwise. We cannot predict the outcome of these lawsuits.
COVID-19
The COVID-19 pandemic has led to global economic disruption and volatility in financial markets and the United States economy. AVANGRID is one of the many companies providing essential services during this national emergency and we communicate regularly with federal and state authorities and industry resources to ensure a coordinated response. We have implemented business continuity and emergency response plans to continue to provide safe and reliable service to our customers and support our operational needs while managing the impacts of the COVID-19 pandemic. We have deployed COVID-19 safety protocols for our front-line essential workers and, where possible, moved employees to remote work. We continue to monitor developments affecting both our workforce and our customers and will take precautions that we determine are necessary or appropriate. We regularly communicate with our customers regarding the tools and resources available and to help our customers stay informed during this public health crisis. In addition to measures to protect our workforce and critical operations, we have established a cross-functional task force to plan for a safe and effective return to office. AVANGRID continues to actively monitor potential supply chain and transportation disruptions that could impact the Company’s operations and will implement plans to address any such impacts on our business.
This is a rapidly evolving situation that could continue to lead to extended disruption of economic activity in our markets, which could adversely affect our business. We will continue to actively monitor the situation and may take further
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actions that may be required by federal, state or local authorities or that we determine are in the best interests of our employees, customers, suppliers and shareholders. We have not yet experienced a materially adverse impact to our business, results of operations or financial condition, however, given the uncertain scope and duration of the COVID-19 outbreak and its potential effects on our business, we currently cannot predict if there will be materially adverse impacts to our business, results of operations or financial condition in the future.
Summary of Results of Operations
Our operating revenues increased by 10%, from $1,789 million for the three months ended March 31, 2020 to $1,966 million for the three months ended March 31, 2021.
Networks business revenues increased mainly due to an increase in New York rates, which was approved November 19, 2020. Renewables revenues increased mainly due to higher merchant pricing driven by the Texas weather event during the period.
Net income attributable to AVANGRID increased by 39% from $240 million for the three months ended March 31, 2020 to $334 million for the three months ended March 31, 2021, primarily due to higher Networks revenues from the New York rate case activity and higher Renewables merchant pricing driven primarily by the Texas weather event.
Adjusted net income (a non-GAAP financial measure) increased by 50% from $236 million for the three months ended March 31, 2020 to $354 million for the three months ended March 31, 2021. The increase is primarily due to a $77 million increase in Renewables driven by higher merchant pricing from the Texas weather event, a $31 million increase in Networks driven primarily by the New York rate case and a $10 million increase in Corporate mainly driven by decreased income tax expense.
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, 2020.
Customer Disconnections
Due to the COVID-19 pandemic, all of our regulated utilities suspended customer disconnections during March 2020. In New York, we had voluntarily suspended disconnections for non-payment. The New York state legislature passed a bill stating moratoriums on residential customer disconnections shall remain in place until 180 days after the COVID-19 state of emergency in New York is lifted or December 31, 2021, whichever comes first.
In Connecticut and Maine, regulatory orders for COVID-19 disconnection moratoriums ceased on November 1, 2020; however, disconnections could not resume until the winter disconnection moratorium period ended in April 2021.
CMP Metering and Billing Investigation
On February 19, 2020, the MPUC issued an order in CMP’s distribution rate case proceeding and on February 24, 2020 issued an order in the metering and billing investigation. Each order reflected the MPUC’s conclusion that CMP’s Metering and Billing system is accurately reporting data, there is no systemic root cause for high usage complaints and errors related to CMP’s metering and billing system are localized and random, not systemic. However, the MPUC orders imposed a reduction of 100 basis points in ROE, as a management efficiency adjustment, to address the MPUC Commissioners’ concerns with CMP’s customer service implementation and performance following the launch of its new billing system in 2017. The management efficiency adjustment will remain in effect until CMP has demonstrated satisfactory customer service performance on four specified service quality measures for a rolling average period of 18 months, which commenced on March 1, 2020. CMP is meeting the required rolling average benchmarks for all four of these quality measures and expects to file with the MPUC in the third quarter of 2021 to remove the management efficiency adjustment.
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CMP Standard Offer Uncollectible Adder Investigation
On August 19, 2020, the MPUC issued a Notice of Investigation to open an investigation into whether the uncollectible adder to CMP’s standard offer retainage account for the residential and small non-residential standard offer customer class should be increased for standard offer electricity-supply rates that will go into effect January 1, 2022. The investigation will also include a review of CMP’s credit and collection practices. A technical conference was held on October 8, 2020.
On December 4, 2020, the MPUC Staff issued a Bench Analysis setting forth the staff’s position that CMP’s imprudence in its implementation of its SmartCare billing system and certain of its credit and collections activities beginning in 2016 led to larger write-offs than otherwise would have occurred, which has decreased the standard offer retainage account and increased the size of the uncollectible adder needed to recover those amounts. The MPUC Staff proposes an imprudent disallowance adjustment of approximately $5 million to the uncollectible adder retainage account. CMP filed testimony in response to the Bench Analysis on February 5, 2021. The litigation schedule has been suspended while parties and MPUC Staff engage in settlement negotiation. We cannot predict the outcome of this matter.
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 $146 million and $148 million, respectively, for this item at March 31, 2021 and December 31, 2020.
In 2017, the NYPSC and MPUC commenced audits of the power tax regulatory assets. On January 11, 2018, the NYPSC issued an order opening an operations audit on NYSEG and RG&E and certain other New York utilities regarding tax accounting. The NYPSC audit report is expected to be completed during 2021. In January 2018, the MPUC published the Power Tax audit report with respect to CMP, which indicated the auditor was unable to verify the asset “acquisition value” used to calculate the Power Tax regulatory asset. CMP responded to the audit report in its rate case filing by providing additional acquisition value support and, therefore, requested full recovery of the Power Tax regulatory asset. The MPUC had an outside firm conduct an audit of CMP's filing and acquisition values, and the auditor found CMP's information was reasonable. In September 2019, CMP filed a report in response to the audit report and addressed MPUC staff concerns. On December 17, 2019, CMP filed a stipulation with the MPUC providing for recovery of the Power Tax regulatory asset and adjusting the carrying costs values for the period of July 1, 2017 through June 30, 2019. The MPUC approved the stipulation on January 21, 2020 and CMP began collecting the Power Tax Regulatory asset in July 2020 over 32.5 years.
New England Clean Energy Connect
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. Among other things, on that date, CMP assigned the TSAs to NECEC Transmission LLC.
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, deliberated and 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 has been appealed by certain intervenors. The appeals are currently pending before the Maine Board of Environmental Protection and the Maine Superior Court. Certain parties to the MDEP proceedings requested the stay of the MDEP permits during the pendency of the appeals. The motions to stay were denied by the MDEP Commissioner in August 2020. On November 2, 2020, a motion to stay the MDEP permits was filed before the Maine Superior Court by certain parties. In January 2021, the Maine Superior Court denied the motion for a stay. We cannot predict the outcome of these proceedings.
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 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. A related request for preliminary injunction seeking to enjoin construction of the NECEC was denied by the District Court on December 16, 2020. That denial was appealed to the First Circuit Court of Appeals. On December 21, 2020, plaintiffs filed a motion for emergency injunction pending appeal in the District Court. The District Court denied that motion on December 23, 2020. On December 30,
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2020, plaintiffs filed an emergency motion for injunction with the First Circuit Court seeking to enjoin construction in Segment 1 of the project pending their appeal of the District Court's denial of a preliminary injunction. On January 15, 2021, the First Circuit Court granted the motion temporarily enjoining construction in Segment 1 of the NECEC project. Briefing before the First Circuit Court on the preliminary injunction concluded in February 2021 and oral arguments were on March 30, 2021. We cannot predict the outcome of these proceedings.
ISO-NE issued the final System Impact Study (SIS) for NECEC on May 13, 2020, determining the network 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 system upgrade required at the Seabrook Station, on October 13, 2020, AVANGRID and NECEC Transmission LLC filed a complaint with the FERC and an amended complaint on March 26, 2021. On October 5, 2020, NextEra Energy Seabrook, LLC filed a Petition for Declaratory Order. Both proceedings are currently pending before FERC. We cannot predict the outcome of these proceedings.
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 27, 2021 the plaintiffs filed their amended complaint asking the court, among other things, to vacate, set aside, remand or stay the Presidential Permit. We cannot predict the outcome of these proceedings.
A complaint challenging the validity of NECEC Transmission LLC's leasehold interest in public land that will host a section of the NECEC project, granted by Maine's Bureau of Parks and Lands, is currently pending before the Maine Superior Court. We cannot predict the outcome of this proceeding.
In 2019, certain opponents of the NECEC began an effort to have a referendum ballot question to enact legislation (i.e., a Maine citizen initiative) entitled “Resolve, To Reject the New England Clean Energy Transmission Project,” which, if passed by Maine voters, would have required the MPUC to amend its May 3, 2019 Order granting a Certificate of Public Convenience and Necessity, or CPCN, for the project and deny the CPCN. On August 13, 2020, the Maine Supreme Judicial Court vacated a June 29, 2020 Maine Superior Court decision, held that the referendum is unconstitutional and remanded the case to the Maine Superior Court to enter a declaratory judgment. On August 21, 2020, the Maine Superior Court issued a declaratory judgment that the referendum fails to meet the constitutional requirements for inclusion on the ballot.
On September 16, 2020, a group of Maine voters submitted an application for a citizen referendum (i.e., a Maine citizen initiative) to enact legislation that, if enacted into law and found to be constitutional, would require the vote of 2/3 of all members elected to each House of the Maine Legislature to approve construction of a high-impact electric transmission line crossing or utilizing public lands, prohibit construction of a high impact electric transmission line in the Upper Kennebec Region and require the vote of 2/3 of all members elected to each House of the Maine Legislature for the lease by Maine's Bureau of Parks and Lands of public reserved lands for transmission lines and similar linear projects. The citizen initiative states that these provisions would apply retroactively. On February 22, 2021, the Maine Secretary of State issued a decision finding that proponents of the initiative have gathered the constitutionally required number of signatures and that the referendum is valid for placement on the November 2021 ballot. We cannot predict the outcome of this citizen initiative.
At the municipal level, the project plans to apply for and obtain local approvals from organized towns gradually, based on the project’s construction sequence and schedule. Eleven towns have granted municipal approvals to date. Construction of the NECEC project started in January 2021 and commercial operation is expected in the second quarter of 2023. As of March 31, 2021, we have capitalized approximately $268 million for the NECEC project.
PURA Investigation of the Preparation for and Response to the Tropical Storm Isaias
On August 6, 2020, the PURA opened a docket to investigate the preparation for and response to Tropical Storm Isaias by the electric distribution companies in Connecticut including UI. Following hearings and the submission of testimony, PURA issued a final decision on April 15, 2021, finding that UI “generally met standards of acceptable performance in its preparation and response to Tropical Storm Isaias," subject to certain exceptions noted in the decision, but ordered a 15 basis point 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. We cannot predict the final outcome of this investigation or potential penalties that may be assessed.
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
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company, increases the maximum civil penalties assessable for failures in emergency preparedness, and provides certain penalties and reimbursements to customers after storm outages greater than 96 hours and extends rate case timelines.
Pursuant to the legislation, on October 30, 2020, PURA re-opened a docket related to new rate designs and review, expanding the scope to consider the implementation of an (a) interim rate decrease; (b) low income rates; and (c) economic development rates. Separately, UI was due to make its annual rate adjustment mechanism, or RAM, filing on March 8, 2021 for the approval of its RAM Rate Components reconciliations: Generation Services Charges, By-passable Federally Mandated Congestion Costs, System Benefits Charge, Transmission Adjustment Charge and Revenue Decoupling Mechanism. PURA had previously delayed implementation of those rates for a year in 2020.
On March 9, 2021, UI, jointly with the Office of the CT Attorney General, the Office of CT Consumer Counsel, DEEP and PURA’s Office of Education, Outreach, and Enforcement entered into a settlement agreement and filed a motion to approve the settlement agreement.
On April 14, 2021, PURA issued a draft decision which declined to approve the settlement agreement. UI filed written exceptions and held oral arguments. As a result, on April 26, 2021, PURA issued an order suspending the procedural schedule for a period up to and including July 2, 2021, so that the parties to the Settlement could address certain issues PURA identified in the order. A revised procedural schedule will be issued at a later date. We cannot predict the outcome of these proceedings, including the potential impact on the recovery of UI’s RAM components or the interim rate reduction proceeding.
NYDPS Investigation of the Preparation for and Response to the Tropical Storm Isaias
In August 2020, following Tropical Storm Isaias, the NYDPS commenced a comprehensive investigation of the preparation and response this event by New York's major electric utility companies. In addition, on August 20, 2020, the New York State Senate and Assembly held a joint hearing to examine the response of various utility companies during the aftermath of Tropical Storm Isaias. On December 31, 2020, NYSEG and NYDPS Staff entered into a settlement agreement regarding three alleged violations by NYSEG of its emergency response plan pursuant to which NYSEG agreed to payment of a penalty of approximately $2 million dollars. The settlement was approved on January 21, 2021.
Proposed New York Legislation in Response to the Tropical Storm Isaias
Proposed legislation has been introduced that would amend the public service law to, among other things, increase potential penalties and give greater discretion to the NYPSC to assess penalties for violations of the Public Service Law, Regulations, or Orders of the NYPSC. We cannot predict the outcome of this proposed legislation.
CMP Generator Interconnection Investigation
On February 10, 2021, two solar developer associations petitioned the MPUC to open an investigation into CMP’s generator interconnection practices and the estimates CMP provided to developers related to expected interconnection costs. On April 6, 2021, the MPUC issued a Notice of Formal Investigation related to the prudency and reasonableness of CMP’s actions with respect to the interconnection of generation to its distribution system. We cannot predict the outcome of this investigation or any potential penalties that may be assessed.
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Results of Operations
The following tables set forth financial information by segment for each of the periods indicated:
Three Months EndedThree Months Ended
March 31, 2021March 31, 2020
TotalNetworksRenewablesOther(1)TotalNetworksRenewablesOther(1)
(in millions)
Operating Revenues$1,966 $1,573 $393 $ $1,789 $1,461 $328 $ 
Operating Expenses
Purchased power, natural gas and fuel used501 449 52 — 475 394 81 — 
Operations and maintenance642 506 139 (3)570 466 109 (5)
Depreciation and amortization247 156 91 — 251 148 103 — 
Taxes other than income taxes170 149 19 166 144 22 — 
Total Operating Expenses1,560 1,260 301 (1)1,462 1,152 315 (5)
Operating Income406 313 92 1 327 309 13 5 
Other Income (Expense)
Other income (expense)(6)(3)(2)(7)
Earnings (losses) from equity method investments(1)— (6)(8)— 
Interest expense, net of capitalization(73)(53)— (20)(76)(68)(1)(7)
Income (Loss) Before Income Tax335 268 85 (18)242 241 10 (9)
Income tax expense (benefit)14 42 (9)(19)12 43 (30)(1)
Net Income (Loss)321 226 94 1 230 198 40 (8)
Net loss (income) attributable to noncontrolling interests13 (1)14 — 10 (1)11 — 
Net Income (Loss) Attributable to Avangrid, Inc.$334 $225 $108 $1 $240 $197 $51 $(8)
(1)"Other" represents Corporate and intersegment eliminations.
Comparison of Period to Period Results of Operations
Three Months Ended March 31, 2021 Compared to Three Months Ended March 31, 2020
Operating Revenues
Our operating revenues increased by $177 million, or 10%, from $1,789 million for the three months ended March 31, 2020 to $1,966 million for the three months ended March 31, 2021, as detailed by segment below:
Networks
Operating revenues increased by $112 million, or 8%, from $1,461 million for the three months ended March 31, 2020 to $1,573 million for the three months ended March 31, 2021. Electricity and gas revenues increased by $26 million, primarily due to new rate case activity in New York which was approved November 19, 2020, a $6 million favorable impact from a pension deferral write-off recorded in the same period of 2020, and $4 million of other. Electricity and gas revenues changed due to the following items that have offsets within the income statement: an increase of $55 million in purchased power and purchased gas (offset in purchased power), an increase of $44 million in flow through amortizations ($39 million offset in operating expenses and $5 million offset in taxes other than income taxes), offset by a decrease of $23 million in flow through amortizations ($13 million offset in income tax expense and $10 million offset in interest expense).
Renewables
Operating revenues increased by $65 million, or 20%, from $328 million for the three months ended March 31, 2020, to $393 million for the three months ended March 31, 2021. The increase in operating revenues was primarily due to a $134 million increase in merchant prices driven mainly by higher demand during the Texas storm in the first quarter of 2021, $15 million in power trading driven by higher average prices in the period, $9 million from curtailment payments and $3 million from other, offset by unfavorable MtM changes of $73 million on energy derivative transactions entered for economic hedging purposes, and a decrease of $23 million driven by 397 GWh lower wind generation output in the current period.
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Purchased Power, Natural Gas and Fuel Used
Purchased power, natural gas and fuel used increased by $26 million, or 5%, from $475 million for the three months ended March 31, 2020 to $501 million for the three months ended March 31, 2021, as detailed by segment below:
Networks
Purchased power, natural gas and fuel used increased by $55 million, or 14%, from $394 million for the three months ended March 31, 2020 to $449 million for the three months ended March 31, 2021. The increase is primarily driven by a $48 million increase in average commodity prices and an overall increase in electricity and gas units procured due to higher degree days along with a $5 million increase in other power supply purchases in the period.
Renewables
Purchased power, natural gas and fuel used decreased by $29 million, or 36%, from $81 million for the three months ended March 31, 2020 to $52 million for the three months ended March 31, 2021. The decrease is primarily due to favorable MtM changes on derivatives of $34 million due to market price changes in the period, offset by an increase of $5 million in power purchases in the period.
Operations and Maintenance
Operations and maintenance expenses increased by $72 million, or 13%, from $570 million for the three months ended March 31, 2020 to $642 million for the three months ended March 31, 2021, as detailed by segment below:
Networks
Operations and maintenance expenses increased by $40 million, or 9%, from $466 million for the three months ended March 31, 2020 to $506 million for the three months ended March 31, 2021. The increase is driven by a $5 million increase in uncollectible expenses and an increase of $39 million in flow through amortizations (which is offset in revenue) offset by $6 million favorable personnel expenses.
Renewables
Operations and maintenance expenses increased by $30 million, or 28%, from $109 million for the three months ended March 31, 2020 to $139 million for the three months ended March 31, 2021. The increase is primarily due to a $16 million increase in bad debt provision driven by an increase in uncollectibles billed during the Texas storm in the first quarter of 2021, $9 million of higher land rents driven by new sites, $4 million of increased costs resulting from higher maintenance costs in the period and $1 million of other increases.
Depreciation and Amortization
Depreciation and amortization for the three months ended March 31, 2021 was $247 million compared to $251 million for the three months ended March 31, 2020, a decrease of $4 million. The increase is driven by $12 million from plant additions in Networks and Renewables in the period, offset by a $10 million decrease of accelerated depreciation from the repowering of wind farms and $6 million decrease driven by amortization of a deferred gain.
Other Income (Expense) and Earnings (Losses) from Equity Method Investments
Other income (expense) and equity earnings (losses) increased by $11 million from $(9) million for the three months ended March 31, 2020 to $2 million for the three months ended March 31, 2021. The change is primarily due to a $5 million favorable increase in allowance for funds used during construction, a $4 million favorable change in non-service component pension and other post-retirement expense driven by revised actuarial studies in Networks, $7 million of favorable equity earnings in the period, and $1 million of other increases offset by a $6 million decrease due to the write-off of certain development projects in Renewables in the period.
Interest Expense, Net of Capitalization
Interest expense for the three months ended March 31, 2021 and 2020 was $73 million and $76 million, respectively. The change is primarily due to a decrease of $15 million of interest expense at Networks ($4 million of favorable carrying charges and $10 million favorable amortizations (offset in revenue)) offset by a $13 million increase in Other due to increased debt.
Income Tax
The effective tax rate, inclusive of federal and state income tax, for the three months ended March 31, 2021 was 4.2%, which is below the federal statutory tax rate of 21%, primarily due to the recognition of production tax credits associated with wind production and the effect of the excess deferred tax amortization resulting from the Tax Act. The effective tax rate,
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inclusive of federal and state income tax, for the three months ended March 31, 2020 was 5.0%, which was below the federal statutory tax rate of 21%, primarily due to the recognition of production tax credits associated with wind production and the effect of the excess deferred tax amortization resulting from the Tax Act.
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 restructuring charges, mark-to-market earnings from changes in the fair value of derivative instruments used by AVANGRID to economically hedge market price fluctuations in related underlying physical transactions for the purchase and sale of electricity, accelerated depreciation derived from repowering of wind farms and costs incurred in connection with the COVID-19 pandemic. 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.
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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 months ended March 31, 2021 and 2020, respectively:
 Three Months Ended March 31, 2021
 TotalNetworksRenewablesCorporate*
 (in millions)
Net Income Attributable to Avangrid, Inc.$334 $225 $108 $1 
Adjustments:
Mark-to-market earnings – Renewables20 — 20 — 
Impact of COVID-19— — 
Income tax impact of adjustments (1)(7)(2)(5)— 
Adjusted Net Income (2)$354 $229 $123 $2 
Net (loss) income attributable to noncontrolling interests(13)(14)— 
Income tax expense (benefit)21 44 (4)(19)
Depreciation and amortization247 156 91 — 
Interest expense, net of capitalization73 53 — 20 
Other (income) expense(1)(6)(1)
(Earnings) losses from equity method investments(1)(2)— 
Adjusted EBITDA (3)$680 $474 $204 $2 
Retained PTCs and ITCs50 — 50 — 
PTCs allocated to tax equity investors22 — 22 — 
Adjusted EBITDA with Tax Credits (3)$752 $474 $276 $2 
 Three Months Ended March 31, 2020
 TotalNetworksRenewablesCorporate*
 (in millions)
Net Income (Loss) Attributable to Avangrid, Inc.$240 $197 $52 $(8)
Adjustments:
Mark-to-market earnings - Renewables(18)— (18)— 
Restructuring charges— 
Accelerated depreciation from repowering10 — 10 — 
Income tax impact of adjustments (1)— — 
Adjusted Net Income (2)$236 $198 $46 $(8)
Net (loss) income attributable to noncontrolling interests(10)(11)— 
Income tax expense (benefit)10 43 (32)(1)
Depreciation and amortization241 148 93 — 
Interest expense, net of capitalization76 68 
Other (income) expense(6)
(Earnings) losses from equity method investments(2)— 
Adjusted EBITDA (3)$563 $458 $100 $5 
Retained PTCs and ITCs44 — 44 — 
PTCs allocated to tax equity investors16 — 16 — 
Adjusted EBITDA with Tax Credits (3)$623 $458 $160 $5 
(1)Income tax impact of adjustments: 2021 - $(5) million from MtM earnings and $(2) million from impact of COVID-19 for the three months ended March 31, 2021, respectively; 2020 - $5 million from MtM earnings, $(1) million from restructuring charges, and $(2) million from accelerated depreciation from repowering for the three months ended March 31, 2020, respectively.
(2)Adjusted Net Income is a non-GAAP financial measure and is presented after excluding restructuring charges, accelerated depreciation derived from repowering of wind farms, costs incurred in connection with the COVID-19 pandemic and the impact from mark-to-market activities in Renewables.
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(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 March 31, 2021 Compared to Three Months Ended March 31, 2020
Adjusted net income
Our adjusted net income increased by $118 million, or 50%, from $236 million for the three months ended March 31, 2020 to $354 million for the three months ended March 31, 2021. The increase is primarily due to a $77 million increase in Renewables driven by higher merchant pricing mainly from the Texas weather event, a $31 million increase in Networks driven primarily by new rate case activity in New York which was approved November 19, 2020 and $10 million increase in Corporate mainly driven by favorable tax expense 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 months ended March 31, 2021 and 2020, respectively:
Three Months Ended
March 31,
(Millions)20212020
Networks$225 $197 
Renewables108 52 
Corporate (1)(8)
Net Income$334 $240 
Adjustments:
Mark-to-market earnings - Renewables (2)20 (18)
Restructuring charges (3)— 
Accelerated depreciation from repowering (4)— 10 
Impact of COVID-19 (5)— 
Income tax impact of adjustments(7)
Adjusted Net Income (6)$354 $236 
Three Months Ended
March 31,
 20212020
Networks$0.73 $0.64 
Renewables0.35 0.17 
Corporate (1)— (0.03)
Net Income$1.08 $0.78 
Adjustments:
Mark-to-market earnings - Renewables (2)0.07 (0.06)
Restructuring charges (3)— 0.01 
Accelerated depreciation from repowering (4)— 0.03 
Impact of COVID-19 (5)0.02 — 
Income tax impact of adjustments(0.02)— 
Adjusted Earnings Per Share (6)$1.14 $0.76 
(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)Restructuring and severance related charges relate to costs to implement an initiative to mitigate costs and achieve sustainable growth.
(4)Represents the amount of accelerated depreciation derived from repowering of wind farms in Renewables.
(5)Represents costs incurred in connection with the COVID-19 pandemic.
(6)Adjusted net income and adjusted earnings per share are non-GAAP financial measures and are presented after excluding restructuring charges, accelerated depreciation derived from repowering of wind farms, costs incurred in connection with the COVID-19 pandemic and the impact from mark-to-market activities in Renewables.
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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 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 March 31, 2021.
Liquidity Position
We manage our overall liquidity position as part of the group of companies controlled by Iberdrola, or the Iberdrola Group, and 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. The balance was $0 at both March 31, 2021 and December 31, 2020. Any deposit amounts would be reflected on our condensed consolidated balance sheets under cash and cash equivalents because our deposited surplus funds under the cash pooling agreement are highly-liquid short-term investments.
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 $2.5 billion from the lenders committed to the AVANGRID Credit Facility, $500 million from the lenders committed to the 2020 Credit Facility and $500 million from an Iberdrola Group Credit Facility, each of which are described below.
The following table provides the components of our liquidity position as of March 31, 2021 and December 31, 2020, respectively:
As of March 31,As of December 31,
20212020
 (in millions)
Cash and cash equivalents$813 $1,463 
AVANGRID Credit Facility2,500 2,500 
2020 Credit Facility500 500 
Iberdrola Group Credit Facility500 500 
Less: borrowings— (309)
Total$4,313 $4,654 
AVANGRID Commercial Paper Program
AVANGRID has a commercial paper program with a limit of $2 billion that is backstopped by the AVANGRID Credit Facility and the 2020 Credit Facility (described below). As of both March 31, 2021 and April 30, 2021, there was $0 of commercial paper outstanding.
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 $2.5 billion in the aggregate.
Under the terms of the AVANGRID Credit Facility, each joint borrower has a maximum borrowing entitlement, or sublimit, which can be periodically adjusted to address specific short-term capital funding needs, subject to the maximum limit contained in the agreement. On June 29, 2020, we entered into an amendment to the AVANGRID Credit Facility, which reduced AVANGRID's maximum sublimit from $2.0 billion to $1.5 billion and added minimum sublimits for each joint
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borrower other than AVANGRID. Under the AVANGRID Credit Facility, each of the borrowers will pay an annual facility fee that is dependent on their credit rating. As of March 31, 2021, the facility fees ranged from 10.0 to 17.5 basis points. The AVANGRID Credit Facility matures on June 29, 2024. As of both March 31, 2021 and April 30, 2021, we had no borrowings outstanding under this credit facility.
2020 Credit Facility
During 2020, we entered into a revolving credit agreement with several lenders, or the 2020 Credit Facility, that provides maximum borrowings up to $500 million. We are required to pay an annual facility fee, which ranges from 15 to 30 basis points, dependent on AVANGRID’s credit rating. As of March 31, 2021, the facility fee was 20 basis points and we had no borrowings outstanding. The 2020 Credit Facility was scheduled to mature on June 28, 2021. We terminated this facility on April 28, 2021.
Since our credit facilities are also a backstop to the AVANGRID commercial paper program, the total amounts available under the facilities as of March 31, 2021 and April 30, 2021, were $3,000 million and $2,500 million, respectively.
Iberdrola Group Credit Facility
AVANGRID has a credit facility with Iberdrola Financiacion, S.A.U., a company of the Iberdrola Group. The facility has a limit of $500 million and matures on June 18, 2023. AVANGRID pays a facility fee of 10.5 basis points annually. As of both March 31, 2021 and April 30, 2021, we had no borrowings outstanding under this credit facility.
Capital Resources
We have not issued any new debt during the first quarter of 2021.
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. To date, the Company has not experienced limitations in our ability to access these sources of liquidity in connection with the economic recession triggered by the COVID-19 pandemic. 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 $2.3 billion in capital expenditures through the remainder of 2021.
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 three months ended March 31, 2021 and 2020, respectively:
Three Months Ended
March 31,
 20212020
 (in millions)
Net cash provided by operating activities$425 $307 
Net cash used in investing activities(639)(749)
Net cash (used in) provided by financing activities(436)290 
Net decrease in cash, cash equivalents and restricted cash$(650)$(152)
Operating Activities
The cash from operating activities for the three months ended March 31, 2021 compared to the three months ended March 31, 2020 increased by $118 million, primarily attributable to higher revenues in the period.
Investing Activities
For the three months ended March 31, 2021, net cash used in investing activities was $639 million, which was comprised of $623 million of capital expenditures and $39 million of other investments and equity method investments, partially offset by
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$9 million of contributions in aid of construction and $13 million of proceeds from the sale of assets and notes receivable from affiliates.
For the three months ended March 31, 2020, net cash used in investing activities was $749 million, which was comprised of $742 million of capital expenditures and $23 million of other investments and equity method investments, partially offset by $7 million of contributions in aid of construction and $6 million of proceeds from the sale of assets.
Financing Activities
For the three months ended March 31, 2021, financing activities used $436 million in cash reflecting primarily a net decrease in non-current debt and current notes payable of $303 million, distributions to non-controlling interests of $3 million and dividends of $136 million, offset by contribution from non-controlling interests of $10 million in the period.
For the three months ended March 31, 2020, financing activities provided $290 million in cash reflecting primarily contributions from non-controlling interests of $244 million and a net decrease in non-current debt and current notes payable of $184 million, offset by distributions to non-controlling interests of $1 million, payments on finance leases of $1 million and dividends of $136 million.
Off-Balance Sheet Arrangements
There have been no material changes in our off-balance sheet arrangements during the three months ended March 31, 2021 as compared to those reported for the fiscal year ended December 31, 2020 in our Form 10-K.
Contractual Obligations
As part of the NECEC project, NECEC Transmission LLC and/or CMP committed to approximately $90 million of future payments to support various programs in the state of Maine. There have been no other material changes in contractual and contingent obligations during the three months ended March 31, 2021 as compared to those reported for the fiscal year ended December 31, 2020 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. The accounting policies and related risks described in our Form 10-K are those that depend most heavily on these judgments and estimates. We continue to utilize information reasonably available to us; however, the business and economic uncertainty resulting from COVID-19 has made such estimates and assumptions more difficult to assess and calculate. Impacted estimates include, but are not limited to, evaluations of certain long-lived assets and goodwill for impairment, expected credit losses and potential regulatory deferral or recovery of certain costs. While there were no material impacts from COVID-19 on financial results, actual results could differ from those estimates, which could result in material impacts to our consolidated financial statements in future reporting periods. The other notable changes to the significant accounting policies described in our Form 10-K for the fiscal year ending December 31, 2020, are with respect to our adoption of the new accounting pronouncements described in the Note 3 of our condensed consolidated financial statements for the three months ended March 31, 2021.
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, 2021, and reflected in our condensed consolidated financial statements are described in Note 3 of our condensed consolidated financial statements for the three months ended March 31, 2021.
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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:
the future financial performance, anticipated liquidity and capital expenditures;
actions or inactions of local, state or federal regulatory agencies;
success in retaining or recruiting our officers, key employees or directors;
changes in amount, timing or ability to complete capital projects;
adverse developments in general market, business, economic, labor, regulatory and political conditions;
fluctuations in weather patterns and extreme weather events;
technological developments;
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;
the impact of any change to applicable laws and regulations affecting operations, including those relating to the environment and climate change, taxes, price controls, regulatory approval and permitting;
our ability to close the proposed Merger, the anticipated timing and terms of the proposed Merger, our ability to realize the anticipated benefits of the proposed Merger and our ability to manage the risks of the proposed Merger;
the COVID-19 pandemic, its impact on business and economic conditions and the pace of recovery from the pandemic;
the implementation of changes in accounting standards; 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 three months ended March 31, 2021, as compared to those reported for the fiscal year ended December 31, 2020 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.
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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.
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PART II. OTHER INFORMATION

Item 1. Legal Proceedings
Please read “Note 8—Contingencies” 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, 2020. There have been no material changes to such risk factors.
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
10.1
31.1
31.2
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101.INSXBRL Instance Document.*
101.SCHXBRL Taxonomy Extension Schema Document.*
101.CALXBRL Taxonomy Extension Calculation Linkbase Document.*
101.DEFXBRL Taxonomy Extension Definition Linkbase Document.*
101.LABXBRL Taxonomy Extension Label Linkbase Document.*
101.PREXBRL Taxonomy Extension Presentation Linkbase Document.*
*Filed herewith.
†Compensatory plan or agreement.
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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: May 4, 2021By:/s/ Dennis V. Arriola
  Dennis V. Arriola
  Director and Chief Executive Officer
Date: May 4, 2021By:/s/ Douglas K. Stuver
  Douglas K. Stuver
  Senior Vice President - Chief Financial Officer
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