Rhode Island’s Pascoag Utility District turns to batteries to avoid a transmission upgrade
May 18, 2021
by Peter Maloney
APPA News
May 18, 2021
The Pascoag Utility District in Rhode Island plans to use an energy storage project as an alternative to upgrading transmission lines.
The 3-megawatt (MW), 9-megawatt hour (MWh) lithium-ion battery array is being developed by Agilitas Energy, which is beginning the pre-construction phase of the project. The battery system is expected to enter service in the second quarter of 2022.
Pascoag Utility District is contracting for all the battery system’s capacity, both storage and generation. The contract also includes a sharing arrangement on the lowering of the public power utility’s capacity and transmission costs, which vary depending on the utility’s load at times of peak demand on the ISO-New England system.
The batteries will cycle on Pascoag Utility District’s system, charging and discharging and shifting load between peak and off-peak periods and will provide peak shaving services to the utility and ancillary services to ISO-New England.
“The battery storage system will allow us to modernize our infrastructure and avoid the more costly re-construction of existing transmission lines,” Mike Kirkwood, general manager of Pascoag Utility District, said in a statement. “The battery energy storage systems help fulfill our goal to control costs while we assure reliable power.”
The battery storage project was attractive to the Pascoag Utility District because the utility was starting to reach the thermal limits on its existing connection to the grid. The project “avoids $6 million to $12 million in costs that would have been needed to completely rebuild the two National Grid 5-mile, 13.8-kilovolt (kV) feeder lines that connect us to the outside world,” Kirkwood said via email. “Some work is still needed on those lines, but much less than was initially anticipated because of our substation work and the battery project.”
National Grid’s system impact study put “the cost of rebuilding the transmission lines at $6 million with a confidence level of -50%/+200%, meaning the actual costs could have escalated to twice the original estimate,” Kirkwood said. “We had to rebuild our substation no matter what alternative we chose,” he said, “so the battery part of the project is helping us avoid the $6-12 million in the complete rebuilding of the lines.”
Pascoag Utility District is paying about $200,000 in interconnection costs associated with the storage project with funds from a grant allocated by the Rhode Island Office of Energy Resources for unique energy efficiency projects.
Pascoag Utility District qualified for the grant because the battery project, together with the work it is doing on the substation connecting the utility’s system to the New England grid, qualifies as a non-wires alternative. The utility also received $1.4 million in financing for the substation project through Rhode Island’s Efficient Building Funds program, which allowed Pascoag Utility District to receive low cost financing from the Rhode Island Infrastructure Bank, a quasi-state agency that finances public infrastructure.
“The operation of this system will obviate the need for adding costly transmission infrastructure and create a win-win for all parties including Pascoag’s customers,” Barrett Bilotta, president of Agilitas Energy, said in a statement.
Last year, then-Governor Gina Raimondo signed an executive order that committed Rhode Island to meeting 100 percent of its electricity demand with renewable and non-fossil fuel resources by 2030. Many energy experts see energy storage playing a key role in that transition with its ability to store electricity generated by renewable energy resources and discharge it at times when demand is high or renewable resources are not available.
The American Public Power Association offers a Public Power Energy Storage Tracker for association members that summarizes energy storage projects undertaken by members that are currently online.
Groups press for access to direct payment refundable energy tax credits
May 17, 2021
by Paul Ciampoli
APPA News Director
May 17, 2021
Public power utilities and rural electric cooperatives should be allowed to receive direct payment refundable energy tax credits, leaders of the American Public Power Association (APPA), National Rural Electric Cooperative Association (NRECA) and Large Public Power Council (LPPC) told congressional leaders in a May 14 letter.
While refundable credits have for several years been one option under consideration for providing comparable incentives to energy tax credits, the letter is the first joint statement specifically citing them as the preferred approach.
The letter, which was sent to House Speaker Nancy Pelosi, D-Calif., Minority Leader Kevin McCarthy, R-Calif., Senate Majority Leader Charles Schumer, D-N.Y., and Senate Minority Leader Mitch McConnell. R-Kentucky, was signed by APPA President and CEO Joy Ditto, NRECA CEO Jim Matheson and LPPC President John Di Stasio.
The letter notes that earlier this year, President Biden set ambitious targets for reducing greenhouse gas emissions from power generation, transportation, and other sources. “Reaching these goals will be a daunting challenge, but our members have been and continue to be committed to reduce greenhouse gas emissions,” wrote Ditto, Matheson and Di Stasio.
“However, for community-owned electric utilities, all the increased costs associated with drastically reshaping our generation profile will be borne by our customers and consumer-owners. As such, we cannot afford inefficient or ineffective policies. If the goal is to move toward a cleaner energy grid by providing tax incentives for developing clean energy generation, storage, transmission, and electric vehicle (EV) recharging infrastructure, federal incentives must be made available to all electricity providers,” the three association leaders said.
They argued that one of the most significant shortcomings of federal energy tax policy is that not-for-profit and tax-exempt community-owned electric utilities have been excluded from being able to directly claim these credits. “The result is that our utilities only indirectly benefit from energy-related tax incentives.”
This is typically done through long-term power purchase agreements (PPAs) with taxable project developers and their tax equity partners, which claim these credits. “PPAs are complex and expensive, and much of the value of the credits flow to the project developers and their investors rather than to the not-for-profit utilities and their customers,” wrote Ditto, Matheson and Di Stasio.
“Further, to qualify for the credit, the project developer and tax-equity investors must retain ownership of the facility and our utilities may only later purchase the facilities by paying the owner the fair market value of the facility. This increases the cost and inefficiency of the present system and means that the purchasing utility is denied the substantial operational benefits that flow from direct ownership.”
Allowing public power utilities and rural electric cooperatives to receive these tax credits in the form of direct payments for building clean energy infrastructure “would ensure that all utilities serving all Americans would have equal access to these federal resources. The direct payments would be used to help offset project costs — increasing the incentive for further investments — and would enable public power utilities and rural electric cooperatives to own these facilities directly. It would also mean more local projects, with local jobs, under local control. Having direct ownership as an option will help our members develop a generation mix that best suits the needs of the customers.”
The President and Congress “have ambitious climate goals that cannot be met by leaving nearly 30 percent of the nation’s electric utility customers without access to incentives and support,” the letter said. To that end, Ditto, Matheson and Di Stasio urged Congress to provide direct pay for credits to public power utilities and rural electric cooperatives.
City Water, Light and Power plant chosen as site for carbon capture technology pilot testing
May 13, 2021
by Peter Maloney
APPA News
May 13, 2021
The U.S. Department of Energy’s (DOE) National Energy Technology Laboratory (NETL) has chosen the University of Illinois’ Prairie Research Institute (PRI) to conduct large-scale pilot testing of a carbon dioxide (CO2) capture technology at Springfield, Ill., public power utility City Water, Light and Power’s (CWLP) Dallman Unit 4.
The DOE has allocated $47 million for the final phase of the project that will see the construction of a 10-megawatt (MW) Linde-BASF advanced post-combustion CO2 capture system to process the power plant’s flue gas. Illinois committed an additional $20 million to cost of the final phase of the project.
Dallman 4 is a 200-MW pulverized coal power plant.
In making the award, the DOE said the successful construction and operation of the Dallman Unit 4 plant would demonstrate economic carbon capture technology and help enable commercialization of the technology.
The PRI projects the construction and operation of the Dallman Unit 4 carbon capture facility will have a regional economic impact of $47.1 million and generate tax revenue of $5.6 million.
“As a publicly-owned utility, this new construction and innovative initiative will be a boost to our local economy while the energy industry as a whole will also be watching CWLP to see how this technology performs,” Springfield Mayor Jim Langfelder said in a statement.
The third phase of the Dallman carbon capture test project, final design and construction, is scheduled to begin in June and includes finalizing a detailed engineering plan and acquiring equipment and modules needed for the new system. Building the system is slated to begin in June 2022 with testing expected to take place from March 2024 through to May 2026.
“The success of this project would be a model and foundation for more accessible, attainable carbon capture systems at facilities around the world,” Kevin OBrien, principal investigator for the project and director of the PRI’s Illinois Sustainable Technology Center (ISTC), said in a statement.
In addition to the carbon capture project at the Dallman plant, CWLP is working with ISTC on projects involving the use CO2 as feedstock for algae; scrubber wastewater treatment technology; beneficial reuse of coal fly ash in plastics, and a project advancing the design of a hybrid power plant and energy storage system.
“A proven and cost-effective carbon capture solution is what plants need to be able to demonstrate and transition to if a balanced, resilient and reliable energy grid is the goal,” Doug Brown, CWLP’s chief utility engineer, said in a statement. “Further, I’m pleased the University is planning spinoff projects from this work,” he added.
California community choice aggregator’s board approves 15-year geothermal energy contract
May 13, 2021
by Paul Ciampoli
APPA News Director
May 13, 2021
The Board of Directors for California’s Clean Power Alliance (CPA) recently approved a 15-year contract with Ormat Technologies Inc.’s Heber South Geothermal facility located in Imperial Valley, Calif.
Once the long-term contract takes effect January 1, 2022, the facility will add 14 megawatts of renewable energy to CPA’s energy portfolio. With an expected average annual generation of 116,508 MWh, the project will also allow CPA to further comply with the state of California’s aggressive renewable energy mandates.
CPA will pay for the output of the geothermal generation of the project at a fixed-price rate per megawatt hour for the full term of the 15-year contract. Under the contract, CPA will receive all product attributes from the facility, including energy and renewable energy credits (RECs).
In addition, the contract brings CPA closer to meeting its regulatory obligations under California’s SB 100 and SB 350, which require that 65% of Renewables Portfolio Standard (RPS) compliance related renewable energy supply be sourced from long-term contracts beginning in the 2021-2024 compliance period.
The Heber South project has a firm transmission agreement with California public power utility Imperial Irrigation District to deliver power to the California Independent System Operator at the Coachella Valley substation.
CPA, a community choice aggregator (CCA), serves approximately three million customers and one million customer accounts across 32 communities throughout Southern California.
According to CAISO’s website, geothermal energy accounts for 1,389 MW of the ISO’s grid as of April 11, 2021.
In January 2020, Ormat Technologies announced the signing of two power purchase agreements with Silicon Valley Clean Energy and Monterey Bay Community Power, two California CCAs.
The American Public Power Association has a category of membership for community choice aggregation programs.
Platte River Power Authority begins permitting for 150-MW solar project
May 13, 2021
by Peter Maloney
APPA News
May 13, 2021
Platte River Power Authority has initiated permitting for a 150 megawatt (MW) solar power project in Weld County, Colo.
Platte River Power Authority is undertaking the Black Hollow Solar project with BHS Solar, a subsidiary 174 Power Global. The public power utility intends to use the electrical output from the solar project to replace its share of the output from the coal-fired Craig Unit 1, which is scheduled to retire in 2025.
The solar project, if approved by Weld County planners and commissioners, would be located northeast of Black Hollow Reservoir and span between 1,000 and 1,400 acres, with the final location and layout determined through a review of physical, environmental and land-use constraints and feedback from numerous stakeholders, including neighbors, state agencies, and county leaders.
The solar project would provide work for an estimated 320 full-time workers during construction and up to 450 workers during the peak of construction and then require eight to 10 permanent positions to manage the solar farm after it enters service.
Under the agreement with Platte River, 174 Power Global will build, own and operate the Black Hollow Solar project and sell the electricity under a long-term power purchase agreement to Platte River beginning in 2023. Energy would be delivered to Platte River’s owner communities in Colorado’s north Front Range through a substation to be built adjacent to existing Platte River transmission lines.
Platte River Power Authority serves Estes Park, Fort Collins, Longmont and Loveland, Colo.
“The addition of the Black Hollow Solar project will take us approximately halfway toward our goal of providing 100% noncarbon energy,” Jason Frisbie, general manager and CEO of Platte River Authority, said in a statement. “This is one of many significant steps we’re taking to achieve our Resource Diversification Policy, and we’re excited to move forward with construction.”
When the Black Sparrow Solar project is completed, it will give Platte River Power Authority more than 200 MW of solar capacity when combined with its 30-MW Rawhide Flats solar project, which entered service in 2016, and its 22-MW Rawhide Prairie Solar installation, which began operation – along with 2 megawatt hours of battery storage –in March.
Platte River also receives about 230 MW of wind energy under long-term power contracts.
Ditto, Sargent named to GridWise Alliance advisory council formed to support call for investments in power system
May 12, 2021
by Paul Ciampoli
APPA News Director
May 12, 2021
Joy Ditto, President and CEO of the American Public Power Association (APPA), and Jackie Sargent, general manager of Texas public power utility Austin Energy, have been named to a GridWise Alliance Grid Infrastructure Advisory Council (GIAC) to support the alliance’s call for at least $50 billion in federal spending to modernize the nation’s electric power transmission and distribution systems.
Formation of the 30-member council was announced by GridWise Alliance Board Chair Gil Quiniones on April 26. Quiniones, who is President and CEO of the New York Power Authority, will lead the GIAC.
After the announcement regarding the formation of the GIAC, the White House recognized the launch of the council in a Fact Sheet on the Biden Administration’s plan to advance the expansion and modernization of the electric grid.
“GridWise Alliance’s new Advisory Council will be a vital asset as we work to build support in Congress and throughout the country for grid modernization and for President Biden’s ambitious and potentially historic infrastructure plan—the ‘American Jobs Plan,’” Quiniones said in a statement.
He noted that the council includes leaders from the electric utility industry, environmental groups, labor unions and other interested parties in the public and private sectors. “It is diverse, but also united in its firm belief that the power grid must be significantly upgraded,” Quiniones said.
The GridWise Alliance praised the Biden Administration on the infrastructure plan’s proposed $100 billion investment in upgrading the electricity grid and promoting clean energy and $50 billion for resilient infrastructure, Quiniones said.
He noted that this complements the Alliance’s Grid Investments for Economic Recovery initiative, launched earlier this year, which focuses more specifically on urging a $50 billion federal investment in modernizing and upgrading the transmission and distribution networks.
The purpose of Ditto’s participation is to ensure public power is well represented on the group.
“A reliable power supply depends upon having a robust and modern transmission and distribution system,” said Ditto. “I am honored to be able to serve as a voice for public power on GridWise Alliance’s Advisory Council, and I look forward to working with my fellow council members,” she said.
“I am honored to have been asked to serve on the Grid Infrastructure Advisory Council,” said Jackie Sargent, Austin Energy General Manager. “This is an important and exciting challenge and I am looking forward to working with this diverse group to reimagine our electric grid.”
The GIAC and GridWise Alliance will work collaboratively with the Biden Administration to define areas where investment in the electric grid would be most beneficial to the economy and the communities in most need, a GridWise Alliance news release noted. The council will amplify the best practices of alliance members, put a spotlight on key policy and appropriations recommendations and utilize its utility executives, grid equipment manufacturers, and vendor members to advocate funding for grid modernization.
The GridWise Alliance represents stakeholders that design, build, and operate the electric grid.
Colorado Springs Utilities to join Southwest Power Pool’s Western Energy Imbalance Service Market
May 12, 2021
by Paul Ciampoli
APPA News Director
May 12, 2021
Public power utility Colorado Springs Utilities on May 12 said it will join Southwest Power Pool’s (SPP) Western Energy Imbalance Service (WEIS) Market in April 2022 and join other western utilities in evaluating membership in SPP’s regional transmission organization (RTO).
“Our current portfolio of solar compliments SPP well,” said Colorado Springs Utilities CEO Aram Benyamin in a statement. “We expect to save customers money by optimizing the dispatch of different utilities’ generating resources within each hour of the day. Our employees will also benefit from increased market intelligence, better integration of our new solar projects and being one step closer to meeting our clean energy goals.”
In June 2020, the Colorado Springs Utilities Board approved a new sustainable energy plan, which calls for Colorado Springs Utilities to reduce carbon emissions at least 80% by 2030 and 90% by 2050. Additionally, the plan increases renewable energy and incorporates storage resources. It benefits customers by maintaining competitive and affordable rates and advances energy efficiency, the utility notes.
SPP launched its WEIS market Feb. 1, 2021. The wholesale electricity market balances regional supply and demand of electricity in real-time. Colorado Springs Utilities will join eight other western utilities already participating in the WEIS.
SPP is already coordinating an effort by several western utilities — all current participants in the WEIS market — that are evaluating membership in its RTO, and Colorado Springs Utilities will join this effort too.
While SPP administers the WEIS market on a contract basis to non-members, it provides RTO members an entire suite of valuable services including market administration, transmission planning, reliability coordination and more. A recent SPP-Brattle study estimated the WEIS participants’ move to RTO membership would produce $49 million in benefits and those would grow with additional western members.
Colorado Springs Utilities plans to work with the Western Area Power Administration (WAPA), a current SPP WEIS participant, to act as its balancing authority.
A balancing authority is required to enter WEIS as they are responsible for operating a transmission control area. They match generation with load and maintain consistent electric frequency to the grid, even during extreme weather conditions or natural disasters.
The evaluation of membership is expected to conclude in early 2022, with the terms and start dates of any interested parties’ membership agreement to be announced then.
WAPA’s Colorado River Storage Project to explore membership in SPP
SPP recently received a letter from WAPA’s Colorado River Storage Project (CRSP) expressing interest in evaluating membership in the organization.
In November 2020, Basin Electric Power Cooperative, Deseret Power Electric Cooperative, the Municipal Energy Agency of Nebraska, Tri-State Generation and Transmission Association, and WAPA’s Upper Great Plains-West and Loveland Area Projects notified SPP of their intent to evaluate membership in the RTO.
The entities’ letters indicate they will work with SPP to evaluate the terms, costs and benefits of putting western facilities under the RTO’s tariff.
Glenwood Springs and Aspen in Colorado ramp up plans for EV charging stations
May 11, 2021
by Peter Maloney
APPA News
May 11, 2021
The Colorado communities of Glenwood Springs and Aspen are collaborating to increase the number of charging stations needed in their region to support the growth of light and heavy duty electric vehicles.
The collaboration includes a focused effort to be more strategic in advancing EV charging infrastructure in their communities.
“Being a local hub for the Western Slope [of the Rocky Mountains], we feel it’s important to be able to provide appropriate numbers of charging stations along with the private stations that are available to the public,” Matt Langhorst, public works director for Glenwood Springs, said in a statement. “We see the future of electric vehicles coming and plan to be prepared for it.”
Last year, Glenwood Springs added three dual cord, Level-2 ChargePoint stations and a similar unit in a downtown parking garage. There are also several publicly available private charging stations such as Tesla stations close to Interstate 70.
In the near future, Glenwood Springs intends to increase its level of collaboration with Aspen, which is in the process of developing an electric vehicle infrastructure masterplan that would serve as a blueprint for Aspen’s public charging stations over the next five years. The plan would provide recommendations on where, when and how Aspen should install public charging stations and how it should manage its existing stations. The plan would address policy issues such as when to begin paid charging and how rates might compare across the regional charging network.
Aspen currently owns and operates eight publicly available electric vehicle charging stations, six of which are dual cord, Level-2 ChargePoint stations and two are direct current fast charging stations that serve one vehicle at a time. The city also operates several Level 2 charging stations for its administrative fleet of light duty electric vehicles.
There are also eight electric buses that operate within Aspen and in the 70-mile stretch between Aspen and Glenwood Springs as part of the Roaring Fork Transportation Authority’s (RFTA) Battery Electric Bus (BEB) Pilot Project.
RFTA, based in Aspen and Glenwood Springs, integrated electric buses into its fleet of 120 buses in 2019. The buses use Level 2 chargers to replenish their batteries overnight to take advantage of lower off-peak rates. Overall charging time for the buses is approximately three to four hours.
Langhorst said he hopes Aspen’s EV Infrastructure Masterplan will serve as a guide and a tool for other regional stakeholders with electrification plans.
Aspen and Glenwood Springs were among the first communities in the United States to achieve their individual 100 percent renewable energy goals. Aspen reached that goal in 2015, Glenwood Springs in 2019.
Aspen and Glenwood Springs are members of NMPP Energy and the Municipal Energy Agency of Nebraska, the wholesale power supply organization of NMPP Energy, based in Lincoln, Neb.
The Nebraska Municipal Power Pool (NMPP), part of NMPP Energy, provides a variety of energy and management services to nearly 200 member municipalities in six Midwest and Rocky Mountain states.
TVA, Kairos Power to collaborate on low-power demonstration reactor
May 11, 2021
by Paul Ciampoli
APPA News Director
May 11, 2021
The Tennessee Valley Authority and Kairos Power recently announced plans to collaborate on deploying a low-power demonstration reactor at the East Tennessee Technology Park in Oak Ridge, Tenn.
As part of this agreement, TVA will provide engineering, operations, and licensing support to help Kairos Power deploy its low-power demonstration reactor, named Hermes, TVA noted on May 6.
California-based Kairos Power states on its website that its fluoride salt-cooled high temperature reactor is a novel advanced reactor technology that aims to be cost competitive with natural gas in the U.S. electricity market and to provide a long-term reduction in cost.
Kairos Power has chosen Albuquerque, N.M., as its home for a new engineering center to support the development of its advanced reactor technology. The facility will be located in Albuquerque’s Mesa del Sol master-planned community in an existing building on 32 acres of land for future expansion.
Jeff Lyash, President and CEO of TVA, discusses the Kairos Power news in an upcoming episode of the American Public Power Association’s Public Power Now podcast. Click here on Monday, May 17 to access the podcast episode.
TVA generates more than 40% of its electricity from nuclear power and has the third largest nuclear fleet in the U.S.
In April 2020 it was disclosed that the University of Tennessee and the Tennessee Valley Authority had signed a memorandum of understanding to evaluate the development of a new generation of cost-effective, advanced nuclear reactors, such as small modular reactors, at TVA’s 935-acre Clinch River Nuclear Site in Roane County.
TVA signed a similar agreement with Oak Ridge National Laboratory in February 2020 to explore advanced reactor designs as a next-generation nuclear technology with potential for improved safety and increased flexibility.
Biden Administration approves first major offshore wind project in U.S. waters
May 11, 2021
by Paul Ciampoli
APPA News Director
May 11, 2021
Secretary of the Interior Deb Haaland and Secretary of Commerce Gina Raimondo on May 11 announced the approval of the construction and operation of the Vineyard Wind project, the first large-scale, offshore wind project in the U.S.
The 800-megawatt Vineyard Wind energy project, which will contribute to the Biden Administration’s goal of generating 30 gigawatts of energy from offshore wind by 2030, will be located approximately 12 nautical miles offshore Martha’s Vineyard and 12 nautical miles offshore Nantucket in the northern portion of Vineyard Wind’s lease area.
The May 11 Record of Decision (ROD) grants Vineyard Wind final federal approval to install 84 or fewer turbines off Massachusetts as part of an offshore wind energy facility.
According to the ROD for the project, the project would deliver power to the New England energy grid to contribute to Massachusetts’s renewable energy requirements—particularly, the Commonwealth’s mandate that distribution companies (IOUs) jointly and competitively solicit proposals for offshore wind energy generation.
The ROD is jointly signed by and addresses permitting decisions by the Bureau of Ocean Energy Management, U.S. Army Corps of Engineers, and the National Marine Fisheries Service within the National Oceanic and Atmospheric Administration.
Prior to construction, Vineyard Wind must submit a facility design report and a fabrication and installation report. These engineering and technical reports provide specific details for how the facility will be fabricated and installed in accordance with the approved construction and operations plan.
In addition to the May 11 announcement, since January 20, the Department has initiated the environmental review of two other offshore wind projects, and pursued additional leasing opportunities in the New York Bight.
The Departments of Interior, Energy and Commerce on March 29 announced a shared goal to deploy 30 GW of offshore wind in the U.S. by 2030.
At a White House forum, Interior announced the final Wind Energy Areas (WEA) in the New York Bight, an area of shallow waters between Long Island and the New Jersey coast.
The goal of the Department’s area identification process is to identify the offshore locations that appear most suitable for wind energy development, taking into consideration coexistence with ocean users, Interior noted.
The WEAs are adjacent to the greater metropolitan Tri-State area of New York, New Jersey, and Connecticut.
Interior’s BOEM has identified nearly 800,000 acres as WEAs in the New York Bight. The BOEM will initiate an environmental review, with public input, on these areas in federal waters for potential offshore wind leasing.
In addition, Interior in March 2021 said it was initiating an environmental review of the third commercial scale offshore wind project by announcing a notice of intent to prepare an environmental impact statement (EIS) for Ocean Wind LLC’s proposed project offshore New Jersey.
Ocean Wind has proposed an offshore wind project with a total capacity of 1,100 MW.
N.Y. stakeholders, including LIPA, adopt plan for power line for offshore wind farm
A group composed of the New York State Public Service Commission and more than a dozen stakeholders, including the Long Island Power Authority (LIPA), recently agreed to and adopted a plan to build a transmission line that would link a proposed offshore wind farm to the state’s power grid.
In a recent episode of Public Power Now, Tom Falcone, CEO of LIPA, discussed offshore wind.
In August 2019, the New York Power Authority shared key results from a study of European offshore wind transmission models that will help guide New York State as it moves aggressively towards its offshore wind goal by and inform regional and national offshore wind development.