Additional risks and uncertainties are set forth under Part I, Item 1A, “Risk Factors” in this Annual Report on Form 10-K. 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 Securities and Exchange Commission, or SEC, and we encourage you to consult such disclosures.

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. The following chart depicts our current organizational structure.

Through Renewables, we hadhave a combined wind, solar and thermal installed capacity of 8,4999,206 megawatts, or MW, as of December 31, 2020,2022, including Renewables’ share of joint projects, of which 7,7348,061 MW was installed wind capacity. Renewables targets to contract or hedge above 80% of its capacity under long-term power purchase agreements, or PPAs, and hedges to limit market volatility. As of December 31, 2020,2022, approximately 67%74% of the capacity was contracted with PPAs, for an average period of 9.0approximately 10 years, and 18%an additional 15% of installed capacityproduction was hedged. RenewablesAVANGRID is amongone of the top three

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 iswas expected to merge with and into PNMR, with PNMR surviving the Merger as a direct wholly-owned subsidiary of AVANGRID, or the Merger. 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 mergerMerger 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 S.A. 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 April 15, 2021, AVANGRID entered into a side letter agreement with Iberdrola, which set forth certain terms and conditions relating to the Funding Commitment Letter, or the Side Letter Agreement. The Side Letter Agreement provides that any drawing in the form of indebtedness made by AVANGRID pursuant to the Funding Commitment Letter shall bear interest at an interest rate equal to 3-month London Interbank Offer Rate, or LIBOR, plus 0.75% per annum calculated on the basis of a 360-day year for the actual number of days elapsed and, commencing on the date of the Funding Commitment Letter, AVANGRID 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. On February 12, 2021, the shareholders of PNMR approved the proposed Merger. As of November 1, the Merger had obtained all regulatory approvals other than from the New Mexico Public Regulation Commission, or NMPRC. On November 1, 2021, after public hearing and briefing on the matter, the hearing examiner in the Merger proceeding at the NMPRC issued an unfavorable recommendation related to the amended stipulated agreement entered into by PNMR, AVANGRID and several interveners in the NMPRC proceeding with respect to consideration of the joint Merger application in June 2021. On December 8, 2021, the NMPRC issued an order rejecting the amended stipulated agreement. On January 3, 2022, AVANGRID and PNMR filed a notice of appeal of the December 8, 2021 decision of the NMPRC with the New Mexico Supreme Court. The Statement of Issues was filed on February 2, 2022 and the Brief in Chief was filed on April 7, 2022. On June 14, 2022, the NMPRC filed its Answer Brief. On June 13, 2022, New Energy Economy, an intervener in the Merger proceeding, filed its Answer Brief. AVANGRID's Reply Brief was filed on August 5, 2022. On February 24, 2022, the FCC granted an extension to its approval to transfer operating licenses in connection with the Merger, which was further extended on August 9, 2022. On September 21, 2022, New Energy Economy filed a motion to show cause with the NMPRC alleging that AVANGRID and PNMR have engaged in a misleading joint advertising and sponsorship strategy and requesting an investigation. AVANGRID filed a reply to the motion to show cause on October 11, 2022. We cannot predict the outcome of this proceeding.

In addition, on January 3, 2022, AVANGRID, PNMR and Merger Sub entered into an Amendment to the Merger Agreement, or the Amendment, pursuant to which AVANGRID, PNMR and Merger Sub each agreed to extend the “End Date” for consummation of the Merger until April 20, 2023. The parties acknowledged in the Amendment that the required regulatory approval from the NMPRC had not been obtained and that the parties reasonably determined that such outstanding approval would not be obtained by April 20, 2022. In light of this outstanding approval, the parties determined to approve the Amendment. As amended, the Merger Agreement may be terminated by each of AVANGRID and PNMR under certain circumstances, including if the Merger is expectednot consummated by April 20, 2023 (subject to be consummated ina three-month extension by AVANGRID and PNMR by mutual consent if all of the second halfconditions to the closing, other than the conditions related to obtaining regulatory approvals, have been satisfied or waived). During the pendency of 2021the appeal described above, certain required regulatory approvals and consents may expire and AVANGRID and PNMR will reapply and/or apply for extensions of such approvals, as the case may be. In addition, the Closing of the Merger 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. For additional information, see Note 1 to our consolidated financial statements contained in this Annual Report on Form 10-K.

Further information regarding the amount of revenues from external customers, including revenues by products and services, a measure of profit or loss and total assets for each segment for each of the last three fiscal years is provided in Note 24 to our consolidated financial statements contained in this Annual Report on Form 10-K.

On December 16, 2015, we completed the acquisition of UIL Holdings Corporation, or UIL, and changed our name to Avangrid, Inc. Immediately following the completion of the acquisition, former UIL shareowners owned 18.5% of the outstanding shares of common stock of AVANGRID, and Iberdrola owned the remaining shares.

The following table sets forth certain information relating to the rate base, number of customers and the amount of electricity or natural gas provided by each of Networks’ regulated utilities as of and for the year ended December 31, 2020:2022:

During the last five years, Networks has invested $7.2$8.9 billion enhancing its delivery network with greater capacity and improved reliability, environmental security and sustainability, efficiency and automation. Networks continuously improves its

Networks also holds an approximate 20% ownership interest in the regulated New York TransCo, LLC, or New York TransCo. Through New York TransCo, Networks has formed a partnership with affiliates of Central Hudson Gas and Electric Corporation, Consolidated Edison, Inc., National Grid, plc, and Orange and Rockland Utilities, Inc. to develop a portfolio of interconnected transmission lines and substations to fulfill the objectives of the New York energy highway initiative, a proposal to install up to 3,200 MW of new electric generation and transmission capacity in order to deliver more power generated from upstate New York power plants to downstate New York.

In 2018, the New England Clean Energy Connect, or NECEC, transmission project, a joint bid proposed by CMP and Hydro-Québec, was selected by the Massachusetts electric utilities and the Massachusetts Department of Energy Resources, or DOER, in the Commonwealth of Massachusetts’s 83D clean energy Request for Proposal, or RFP.Proposal. The proposed NECEC transmission project includes a 145-mile transmission line linking the electrical grids in Québec, Canada and New England. The project, which has an estimated cost of approximately $1.0$1.4 billion in total, would add 1,200 MW of transmission capacity to supply Maine and the rest of New England with power from reliable hydroelectric generation. As of December 31, 2020,2022, we have spentcapitalized approximately $180$585 million on the NECEC project. For further discussion of the NECEC project, see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” in this Annual Report.

A significant part of Renewables' growing strategic business is offshore wind. Renewables has accessrights to two federal offshore wind lease areasareas. One is located 20 miles off the coast of Massachusetts including 101,590 acres, which has the eastern United States that itpotential to generate up to 2,600 MW of renewable energy for one or more New England states and the other is developing throughlocated 27 miles off the coast of North Carolina including 122,405 acres, which has the potential to generate up to 3,500 MW of renewable energy for Virginia and North Carolina. In addition, Renewables holds a 50% indirect ownership interest in Vineyard Wind 1 LLC (Vineyard Wind 1), a 50-50 partnershipjoint venture with affiliates of Copenhagen Infrastructure Partners, or CIP, a fund management company based in Denmark. In total, the lease areas have the potentialDenmark, which has rights to generate up to 5,000 MW of renewable energy. Renewables is currently developing two wind projects with CIP in one of the lease areas, which is 166,886 acres. The second lease area, acquired in 2018, is 132,370 acres and located over 16 nautical miles off the coast of Massachusetts.

Vineyard Wind 1 LLC is developing and has started onshore construction of the Vineyard Wind 1 project, an 806 MW utility-scale offshore wind project in Lease Area 501. The Vineyard Wind I1 project is expected to generate clean energy for over 400,000 households and businesses in Massachusetts and reduce carbon emissions by over 1.6 million tons per year. The project has 20-year PPA’sPPAs with the electric distribution companies in Massachusetts with an average price of $88.77/MWh, which represents a price for 50% of the project that starts at $65/MWh and escalates 2.5% annually, and a price for the other 50% of the project that starts at $74/MWh and escalates 2.5% annually. Vineyard Wind LLC

Renewables is also developing the Park City Wind project, an 804 MW project located in the same lease area as the Vineyard Wind I project,on Lease Area 534, that will deliver clean, reliable energy to the residents of Connecticut through contracts with the electric distribution companies in Connecticut. The project has 20-year PPA’sPPAs with the electric distribution companies in Connecticut, including UI, with an average price of $79.83/MWh, which is based on a starting price of $62.50 that escalates at 2.5% annually. With respect to the Park City Wind project, Vineyard WindRenewables has agreed to have good faith negotiations to adjust the price if the project benefits from any improvements to the profitability

RenewablesIn December 2021, the Commonwealth Wind project, which will also has rights to a federalbe located on Lease Area 534 was selected as part of Massachusetts’ third offshore wind lease area located more than 27 miles off the coast of North Carolina, which has the potential to generate up to 2,500competitive procurement process. In April 2022, Commonwealth Wind signed 1200 MW of renewable energycontracts with the Massachusetts electric distribution companies. The project has 20-year PPAs with an average price of $76.06/MWh, which is based on a starting price of $59.60 that escalates at 2.5% annually. Permitting for VirginiaCommonwealth Wind is expected to be substantially completed in 2024. On October 20, 2022, Commonwealth Wind filed a motion with the DPU seeking a one-month suspension in the DPU’s proceeding to review the contracts between Commonwealth Wind and North Carolina. The lease areathe Massachusetts electric distribution companies, or EDCs, in order to provide an opportunity for Commonwealth Wind, the EDCs, state and regulatory officials, and other stakeholders to evaluate the current economic challenges facing Commonwealth Wind and assess measures that would return the project to economic viability including, but not limited to, certain amendments to the contracts. This motion was acquired throughdenied by the DPU on November 4, 2022. In the November 4th order, the DPU directed Commonwealth Wind to indicate whether it wished to move forward with the contracts or file a competitive federal auctionrequest to dismiss the DPU proceedings. On November 14, 2022, Commonwealth Wind responded to the DPU order, indicating that while it strongly believed a pause in 2017the proceedings was in the best interest of all parties, if the DPU did not support a pause, then the appropriate action was for the DPU to continue the proceeding such that the parties could continue ongoing discussions to achieve a financeable and is 122,405 acres.economically viable project. On December 16, 2022, after concluding that the ongoing discussions were unlikely to result in a viable path that would allow the project to move forward under the contracts, Commonwealth Wind filed a motion to dismiss with the DPU, requesting that the DPU’s proceeding be dismissed on the grounds that the contracts did not and could not satisfy the required statutory criteria for approval. Commonwealth Wind’s motion further stated that the best path forward was for the contract capacity to be included in the next Massachusetts offshore wind solicitation, that Commonwealth Wind was committed to continuing development of the project, and that Commonwealth Wind would bid into that solicitation to offer Massachusetts a project with cost-effective pricing, a superior timeline for completion and exceptional development opportunities. On December 30, 2022, notwithstanding Commonwealth Wind’s motion to dismiss, the DPU approved the contracts. On January 19, 2023, Commonwealth Wind filed an appeal of the December 30th DPU order to the Supreme Judicial Court of Massachusetts.

Typically, Renewables enters into long-term lease agreements with property owners who lease their landproperty and other sites for onshore renewable energy projects, and with federal agencies for offshore renewables energy projects. Electricity generated at a wind project is then transmitted to customers through long-term agreements with purchasers. There are a limited number of turbine suppliers in the market. Renewables’ largest turbine suppliers, Siemens-Gamesa in which Iberdrola had an 8.1% ownership interest until that was sold in February 2020, and GE Wind, in the aggregate supplied turbines that accounted for 72%70% of Renewables’ installed wind capacity as of December 31, 2022. Iberdrola had an 8.1% ownership interest in Siemens-Gamesa until it was sold in February 2020.

To monetize the tax benefits resulting from production tax credits, or PTCs and ITCs, and accelerated tax depreciation available to qualifying wind and solar energy projects, Renewables has entered into “tax equity” financing structures with third party investors for a portion of its wind and solar farms. Renewables holds two operating wind and solar farms under these structures through limited liability companies jointly owned by one or more third party investors. These investors generally provide an up-front investment and, in some cases, payments over time for their membership interests in the financing structures. In return, the investors receive specified cash distribution allocations and substantially all of the tax benefits generated by the wind and solar farms, until such benefits achieve a negotiated return on their investment. Upon attainment of this target return, the sharing of the cash flows and tax benefits flip, with Renewables receiving substantially all of these amounts thereafter. We also have an option to repurchase the investor’s interest within a certain timeframe after the target return is met. Renewables maintains operational and management control over the wind and solar farm businesses, subject to investor approval of certain major decisions. See “—Properties—Renewables” for more information regarding Renewables’ wind power generation properties.

Additionally, as part of the Renewables portfolio, Renewables operates two thermal generation facilities, in the United States, with 636 MW of combined capacity as of December 31, 2020.2022. Renewables worked closely with the City of Klamath Falls, Oregon to develop the Klamath Plant, which has a current capacity of 536 MW. The Klamath Plant operates by creating two useful forms of energy, electricity and process steam, from a single fuel source of natural gas. In addition, Renewables operates a highly flexible 100 MW Klamath Peaking Plant adjacent to the Klamath Plant, providing customers of Renewables additional capability to meet their peak summer and winter power needs.

In addition to its wind assets, Renewables operates fourfive solar photovoltaic facilities with an installed capacity of 130324 MW. The solar photovoltaic facilities produced over 242,000317,580 MWh of renewable energy for the year ended December 31, 2020.2022. Solar accounted for 1.5%2.0% of the total renewable energy generation from Renewables in these same periods.2022.

Renewables is pursuing the continued development of a large pipeline of wind and solar energy projects in various regions across the United States. Each site features a range of different atmospheric characteristics that ultimately drive the selection of turbine technology for the proposed project. As part of Renewables’ wind resource assessment investigation, critical atmospheric parameters such as mean wind speed, extreme wind speed, turbulence intensity, and mean air density, and solar energy availability are characterized to represent long-term conditions for over 20 years.conditions. The summary wind and solar characteristics are then combined with a terrain analysis, or orography, and weather pattern analysis to assess siting and placement risks in order to mitigate any future operations and maintenance concerns that may arise due to improper turbine siting.siting or placement.

Renewables maintains close relationships with key turbine suppliers, including Siemens-Gamesa, GE, Vestas and others in order to identify the turbine technology that safely delivers the lowest cost of energy for each candidate project in its portfolio. Renewables has deployed the following mix of turbines under this strategy. See “—Properties—Renewables” for more information regarding Renewables’ turbine technology.

Pursuant to the FPA, electric utilities must maintain tariffs and rate schedules on file with the FERC, which govern the rates, terms and conditions for the provision of the FERC-jurisdictional wholesale power and transmission services. Unless otherwise exempt, any person that owns or operates facilities used for the wholesale sale or transmission of power in interstate commerce is a public utility subject to the FERC’s jurisdiction. The FERC regulates, among other things, the disposition of certain utility property, the issuance of securities by public utilities, the rates, the terms and conditions for the transmission or

With respect to Networks’ regulated electric utilities in Maine, New York and Connecticut, the FERC governs the return on equity, or ROE, on all transmission assets in Maine and Connecticut and certain New York TransCo assets in New York. The FERC also oversees the rates, terms and conditions of the transmission of electric energy in interstate commerce, interconnection service in interstate commerce (which applies to independent power generators, for example) and the rates, terms and conditions of wholesale sales of electric energy in interstate commerce. This includes cost-based rates, market-based rates and the operations of regional capacity and electric energy markets in New England administered by an independent entity, ISO New England, Inc., or ISO-NE, and in New York, administered by the New York Independent System Operator, Inc., or NYISO. The FERC approves CMP's, UI's, MEPCO's and New York TransCo's regulated electric utilities transmission revenue requirements. Wholesale electric transmission revenues are recovered through stated or formula rates that are approved by the FERC. CMP’s, MEPCO’s and UI’s electric transmission revenues are recovered from New England customers through charges that recover costs of transmission and other transmission-related services provided by all regional transmission owners. NYSEG’s and RG&E’s electric transmission revenues are recovered from New York customers through charges that recover the costs of transmission and other transmission-related services provided by all transmission owners in New York. Several of our affiliates have been granted authority to engage in sales at market-based rates and blanket authority to issue securities and have also been granted certain waivers of the FERC reporting and accounting regulations available to non-traditional public utilities; however, we cannot be assured that such authorizations or waivers will not be revoked for these affiliates or will be granted in the future to other affiliates.

Pursuant to a series of orders involving the ROE for regionally planned New England electric transmission projects, the FERC established a base-level transmission ROE of 11.14%, as well as providing a 50-basis point ROE adder on Pool Transmission Facilities for participation in the regional transmission organization, or RTO, for New England and a 100-basis point ROE incentive for projects included in the ISO-NE Regional System Plan that were completed and on line as of December 31, 2008. Certain other transmission projects received authorization for incentives up to 125 basis points.

Since 2011, several parties have filed four separate complaints with the FERC against ISO-NE and several New England transmission owners, or NETOs, including UI, CMP and MEPCO, claiming that the current approved base ROE of 11.14% was not just and reasonable, seeking a reduction of the base ROE and a refund 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). ). For more information on this matter see Note 14 of our consolidated financial statements included in Part II, Item 8, "Financial Statements and Supplementary Data" of this Annual Report on Form 10-K, which information is incorporated herein by reference.

The FERC has the right to review books and records of “holding companies,” as defined in the Public Utility Holding Company Act of 2005, or PUHCA 2005, that are determined by the FERC to be relevant to the companies’ respective FERC-jurisdictional rates. We are a holding company, as defined in PUHCA 2005.

The FERC has civil penalty authority over violations of any provision of Part II of the FPA, as well as any rule or order issued thereunder. FERC is authorized to assess a maximum civil penalty of $1.3$1.39 million per violation for each day that the violation continues. The FPA also provides for the assessment of criminal fines and imprisonment for violations under Part II of the FPA. Pursuant to the Energy Policy Act of 2005, or EPAct 2005, the North American Electric Reliability Corporation, or NERC, has been certified by the FERC as the Electric Reliability Organization for North America responsible for developing and overseeing the enforcement of electric system reliability standards applicable throughout the United States. FERC-approved reliability standards may be enforced by the FERC independently, or, alternatively, by NERC and the regional reliability organizations with frontline responsibility for auditing, investigating and otherwise ensuring compliance with reliability standards, subject to the FERC oversight.

Networks’ regulated distribution utilities deliver electricity and/or natural gas to all customers in their service territory at rates established under cost of service regulation. Under this regulatory structure, Networks’ regulated distribution utilities file rate cases to recover the cost of providing distribution service to their customers based on its costs and earn a return on their capital investment in utility assets. For more information on our regulated utilities’ most recent rate cases and other regulatory matters see Note 5 of our consolidated financial statements included in Part II, Item 8, "Financial Statements and Supplementary Data" of this Annual Report on Form 10-K, which information is incorporated herein by reference.

As a result of a restructuring of the utility industry in New York, Maine, Connecticut and Massachusetts, most of Networks’ distribution utilities’ customers have the opportunity to purchase their electricity or natural gas supplies from third-party energy supply vendors. Most customers in New York, however, continue to purchase such supplies through the distribution utilities under regulated energy rates and tariffs. In Maine, CMP customers can also purchase electric supply from competitive providers, but the majority receive baseline standard offer service that is provided through a MPUC procurement process. Networks’ regulated utilities in New York, Connecticut and Massachusetts and MNG purchase electricity or natural gas from unaffiliated wholesale suppliers and recover the actual approved costs of these supplies on a pass-through basis, as well as certain costs associated with industry restructuring, through reconciling rate mechanisms that are periodically adjusted.

State public utility commissions may also have jurisdiction over certain aspects of Renewables’ competitive generation businesses. For example, in New York, certain Renewables’ generation subsidiaries are electric corporations subject to “lightened” regulation by the NYPSC. As such, the NYPSC exercises its jurisdictional authority over certain non-rate aspects of the facilities, including safety, retirements and the issuance of debt secured by recourse to those generation assets located in New York. In Texas, Renewables’ operations within the Electric Reliability Council of Texas, or ERCOT, footprint are not subject to regulation by FERC, as they are deemed to operate solely within the ERCOT market and not in interstate commerce. These operations are subject to regulation by the Public Utility Commission of Texas, or PUCT. In California, Renewables’ generation subsidiaries are subject to regulation by the California Public Utilities Commission with regard to certain non-rate aspects of the facilities, including health and safety, outage reporting and other aspects of the facilities’ operations.

The RTOs and ISOs are also responsible for transmission planning and operations within their respective regions. Each of Networks’ transmission-owning subsidiaries in New York, Connecticut and Maine has transferred operational control over certain of its electric transmission facilities to its respective ISOs, such as ISO-NE and NYISO.

The National Environmental Policy Act, or NEPA, requires that detailed statements of the environmental effect of Networks’ facilities be prepared in connection with the issuance of various federal permits and licenses. Federal agencies are required by NEPA to make an independent environmental evaluation of the facilities as part of their actions during proceedings with respect to these permits and licenses.

Under the federal Toxic Substances Control Act, the Environmental Protection Agency, or EPA, has issued regulations that control the use and disposal of Polychlorinated Biphenyls, or PCBs. PCBs were widely used as insulating fluids in many electric utility transformers and capacitors manufactured before the federal Toxic Substances Control Act prohibited any further manufacture of such PCB equipment. Fluids with a concentration of PCBs higher than 500 parts per million and materials (such as electrical capacitors) that contain such fluids must be disposed of through burning in high temperature incinerators approved by the EPA. For our gas distribution companies, PCBs are sometimes found in the distribution system. Networks tests any distribution piping being removed or repaired for the presence of PCBs and complies with relevant disposal procedures, as needed.

Under the federal Resource Conservation and Recovery Act, or RCRA, the generation, transportation, treatment, storage and disposal of hazardous wastes are subject to regulations adopted by the EPA. All of Networks’ subsidiaries have complied with the notification and application requirements of present regulations, and the procedures by which the subsidiaries handle, store, treat and dispose of hazardous waste products comply with these regulations.

Many states where Renewables’ projects are located have laws that require state agencies to evaluate the environmental impacts of a proposed project prior to granting state permits or approvals. Generally, state agencies evaluate similar issues as federal agencies, including the project’s impact on wildlife, historic or cultural sites, aesthetics, wetlands and water resources, agricultural operations and scenic areas. States may impose different or additional monitoring or mitigation requirements than federal agencies. Additional approvals may be required for specific aspects of a project, such as stream or wetland crossings,

Renewables’ projects also are subject to local environmental and regulatory requirements, including county and municipal land use, zoning, building and transportation requirements. Permitting at the local municipal or county level often consists of obtaining a special use or conditional use permit under a land use ordinance or code, or, in some cases, rezoning is required for a project. Obtaining a permit usually requires that Renewables demonstrate that the project will conform to certain development standards specified under the ordinance so that the project is compatible with existing land uses and protects natural and human environments. Local or state regulatory agencies may require modeling and measurement of permissible sound levels in connection with the permitting and approval of Renewables’ projects. Local or state agencies also may require Renewables to develop decommissioning plans for dismantling the project at the end of its functional life and establish financial assurances for carrying out the decommissioning plan.

In addition to permits required under state and local laws, Renewables’ projects may be subject to permitting and other regulatory requirements under federal law. For example, if an offshore wind project is sited in federal waters (beyond the 3 nautical mile state jurisdictional line), the project will require approval from the Department of Interior’s Bureau of Ocean Energy Management, or BOEM as well as other federal cooperating agencies such as the National Oceanic and Atmospheric Administration’s National Marine Fisheries Service, the U.S. Army Corps of Engineers, or Army Corps, the Federal Aviation Administration, the Department of Defense, the U.S. Environmental Protection Agency and the U.S. Coast Guard. If an onshore project is located near wetlands, a permit may be required from the Army Corps, with respect to the discharge of dredged or fill material into the waters of the United States. The Army Corps may also require the mitigation of any loss of wetland functions and values that accompanies the project’s activities. Renewables may be required to obtain permits under the federal Clean Water Act for water discharges, such as storm water runoff associated with construction activities, and to follow a variety of best management practices to ensure that water quality is protected and impacts are minimized. Renewables’ projects also may be located, or partially located, on lands administered by the U.S. Bureau of Land Management, or BLM. Therefore, Renewables may be required to obtain and maintain BLM right-of-way grants for access to, or operations on, such lands. To obtain and maintain a grant, there must be environmental reviews conducted, a plan of development implemented and a demonstration that there has been compliance with the plan to protect the environment, including measures to protect biological, archeological and cultural resources encountered on the grant.

Renewables’ projects may be subject to requirements pursuant to the Endangered Species Act, or ESA, and analogous state laws. For example, federal agencies granting permits for Renewables’ projects consider the impact on endangered and threatened species and their habitat under the ESA, which prohibits and imposes stringent penalties for harming endangered or threatened species and their habitats. Renewables’ projects also need to consider the Migratory Bird Treaty Act, or MBTA, and the Bald and Golden Eagle Protection Act, or BGEPA, which protect migratory birds and bald and golden eagles and are administered by the U.S. Fish and Wildlife Service. Criminal liability can result from violations of the MBTA and the BGEPA. For example, the U.S. Department of Justice, or DOJ, has previously enforced substantial penalties and mitigation measures against two large wind farm operators, pursuant to which those operators pled guilty to criminal violations of the MBTA.

In addition to regulations, voluntary wind turbine siting guidelines for onshore wind projects established by the U.S. Fish and Wildlife Service, or USFWS, set forth siting, monitoring and coordination protocols that are designed to support wind development in the United States while also protecting both birds and bats and their habitats. These guidelines include provisions for specific monitoring and study conditions which need to be met in order for projects to be in adherence with these voluntary guidelines. Most states also have similar laws. Because the operation of wind turbines may result in injury or fatalities to birds and bats, federal and state agencies often recommend or require that Renewables conduct avian and bat risk assessments prior to issuing permits for its projects. They may also require ongoing monitoring or mitigation activities as a condition to approving a project.

Similarly, BOEM has established survey guidelines for renewable energy development, including avian surveys in coordination with the USFWS. BOEM will use the data from the offshore marine surveys to evaluate the impacts of construction, installation and operation of meteorological towers, buoys, export and inter-array cables, wind turbine generators and supporting structures on physical, biological, and socioeconomic resources, as well as the seafloor and sub-seafloor conditions. The information will be used by BOEM, other federal agencies and potentially affected states in the preparation of National Environmental Policy Act documents, for consultations and other regulatory requirements.

We are continuously evaluating the regulatory risks and regulatory uncertainty presented by climate change and greenhouse gas emission. Such concerns could potentially lead to additional rules and regulations as well as requirements imposed through the ratemaking process that impact how we operate our business. We generally expect that any of Networks' costs for these rules, regulations and requirements would be recovered from customers.

In August 2016, a partial consent order was issued by the Connecticut Department of Energy and Environmental Protection, or DEEP, related to the investigation and remediation of the English Station site. The consent order 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 is required to remit to the State of Connecticut the difference between such cost and $30 million to be applied to 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. However, UI is obligated to comply with the consent order even if the cost of such compliance exceeds $30 million. The state may 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.

See information on infrastructure protection and cyber security measures in "Properties" in Item 1 of this Annual Report on Form 10-K.

Renewables sells the majority of its energy output to large investor-owned utilities, public utilities and other credit-worthy entities. Additionally, Renewables generates and provides power, among other services, to federal and state agencies, institutional retail and joint action agencies. Offtakers typically purchase renewable energy from Renewables through long-term PPAs, allowing Renewables to limit its exposure to market volatility. Approximately 67%As of Renewables’ windDecember 31, 2022, approximately 74% of the

Renewables has competitive advantages, including a robust development pipeline, a management team with extensive experience, strong relationships with suppliers and clients, expert regulatory knowledge and brand awareness. However, Renewables faces competition throughout the life cycles of its renewable energy facilities, including during the development phase, in the identification and procurement of suitable sites with high wind resource availability, grid connection capacity and land availability. Renewables also competes with other suppliers in securing long-term renewable energy PPAs with power purchasers and participates in competitive bilateral and organized energy markets with other energy sources for power that is not sold under PPAs. Competitive conditions may be substantially affected by various forms of energy legislation and regulation considered from time to time by federal, state and local legislatures and administrative agencies.

The following table sets forth certain operating data relating to the electricity transmission and distribution activities of each of Networks’ regulated utilities as of December 31, 2020:2022:

While we have not had any significant security breaches, a physical security intrusion could potentially lead to theft, damage, interruption of service and the release of critical operating information. In addition to physical security intrusions, a cyber breach could also potentially lead to theft, damage, interruption of service and the release of critical operating information or confidential customer information.

To manage these operational risks, pursuant to the cybersecurity risk policy and corporate security policy approved by the AVANGRID board,Board, we have implemented cyber and physical security measures and continue to strengthen our security posture by improving and expanding our physical and cyber security capabilities to protect critical assets.