Banning Electric Utility Power Transformer Relocation Project Will Yield A Number Of Key Benefits
August 16, 2021
by Paul Ciampoli
APPA News Director
August 16, 2021
A project by the City of Banning Electric Utility (BEU) in California that involves moving and relocating a power transformer will result in a number of benefits including saving BEU ratepayers an estimated $500,000 compared to the cost of purchasing a new transformer.
The project began with a 10-year study and recommendation in 2004. The study recommended a distribution system voltage upgrade as well as an upgrade and expansion of BEU’s Airport Substation from 3.75 megawatts (MW) to 10 MW of capacity. These system upgrades would still allow for planned residential growth in the northwest side of town as well as industrial growth around the vicinity of the Banning Municipal Airport on Banning’s southeastern border.
There are three main components to this transformer relocation project.
First, in 2019, was the relocation of the Airport substation to a newly acquired property within the vicinity of the Banning Municipal Airport. The new substation was renamed Ivy, as a special tribute to the granddaughter of the project manager who relocated from Iowa. Second, the new substation will exceed the recommended 10 MW of capacity with 25 MW and the ability to expand up to 50 MW of capacity as needed for industrial growth anticipated in the area. The third component is the downsizing of the Sunset substation from 50 MW capacity to 25 MW with the move of one power transformer from Sunset to Ivy.
Project completion is scheduled for September 1, 2021.
BEU noted that its staff is excited to transition from 1950 mechanical/analog technology to digital distribution automation (1950s technology to 2020) and bring new technology to this former stagecoach town.
Along with ratepayer savings, the project helps better utilize existing transformation equipment and balances transformation capacity across load and system, and provides needed transformation capacity in industrial and airport zoned properties.
While this project has been years in the making, the timing has been perfect as Banning was recently labeled by The Sacramento Bee newspaper as the fastest growing city in California.
Renewables Were the Number Two Generation Source in 2020: EIA
August 11, 2021
by Peter Maloney
APPA News
August 11, 2021
Renewable energy surpassed coal and nuclear generation, becoming the number two generation source in 2020, according to the Energy Information Administration (EIA).
Electric power generated by wind, hydroelectric, solar, biomass, and geothermal sources reached a record 834 billion kilowatt hours (kWh), or about 21 percent of the electricity generated in the United States last year, according to the EIA.
Renewable energy’s record level of generation surpassed nuclear energy, which generated 790 billion kWh, and coal-fired power, which generated 774 billion kWh, for the first time on record, according to EIA data. The top generation source in 2020 was natural gas-fired power, which produced 1,617 billion kWh.
The changes in the 2020 generation profile were due mostly to significantly less coal use in the U.S. and the steady increase of wind and solar power, the EIA said.
Coal generation last year declined 20 percent from 2019, while renewables, including small-scale solar, increased 9 percent. Power generated from wind, currently the most prevalent source of renewable energy in the United States, grew 14 percent in 2020 from 2019. Utility-scale solar generation (projects greater than 1 megawatt) increased 26 percent, and small-scale solar, such as grid-connected rooftop solar panels, increased 19 percent.
Nuclear power declined 2 percent from 2019 to 2020 because several nuclear power plants retired and other nuclear plants experienced slightly more maintenance-related outages, the EIA said.
U.S. coal-fired generation peaked at 2,016 billion kWh in 2007. Much of that capacity has been replaced by or converted to natural gas-fired generation since then, the EIA said. Until 2016, coal-fired generation was the largest source of electricity in the United States, Last year was the first year that more electricity was generated by renewables and by nuclear power than by coal, according to EIA’s data, which dates to 1949.
Despite coal’s decline relative to natural gas and other sources of energy, the EIA expects the share of electrical output from coal-fired generation to rise this year because rising natural gas prices will make coal more economically attractive.
The EIA sees natural gas prices rising because consumption and exports of the fuel are outpacing production and imports. The agency forecasts the 2021 Henry Hub natural gas spot price to average $3.07 per million British thermal units (MMBtu), an increase of $1.04/MMBtu from the record lows of 2020.
EIA’s Short-Term Energy Outlook (STEO) forecasts an 18 percent increase in coal-fired generation in 2021, compared with 2020. The agency then sees coal-fired generation falling again, by 2 percent, in 2022.
Meanwhile, the EIA is forecasting a 7 percent rise in renewable generation in 2021 and a 10 percent increase in 2022 and sees nuclear power declining 2 percent in 2021 and 3 percent in 2022 as nuclear plant retirements continue.
NYPA Board Approves Additional Funding To Support Purchase Of Electric Vehicles
August 11, 2021
by Paul Ciampoli
APPA News Director
August 11, 2021
The New York Power Authority (NYPA) Board of Trustees recently approved $1.1 million in additional funding to help New York’s municipal and rural electric cooperative systems bring more hybrid and electric vehicles into their fleets.
The additional financial assistance, available through the Municipal and Rural Cooperative Electric Utilities Electric-Drive Vehicle Program, will expand a long-running clean energy partnership that encourages electric vehicle use and reduces greenhouse gas emissions across New York State, NYPA said in late July.
NYPA began the Municipal and Rural Cooperative Electric Utilities Electric-Drive Vehicle Program in 2003. In total, 86 vehicles have been placed with 25 cities, towns and villages across the state. The additional funding brings the current total allocated for the program to $12 million.
The NYPA funding provides zero-interest loans to NYPA’s municipal and rural electric cooperative system customers for the purchase of electric and hybrid-electric vehicles for use in their fleets, as well as associated battery charging equipment. Purchases often include passenger vehicles, pickup trucks, off-road specialty vehicles and heavy-duty utility bucket trucks. The funds are then recovered from customers over a period of up to three years through a surcharge on their NYPA electric bills.
The 51 municipal electric and rural electric cooperative utility systems have been NYPA customers since the Niagara Power Project began generating power in 1961, when approximately 765 megawatts (MW) of Niagara hydropower were legislatively mandated for their use.
NYPA reserves 54 MW of that hydropower to promote economic development within those municipal and cooperative service territories. Power from the reserve is allocated by the NYPA Board of Trustees to individual systems to meet the increased electric load resulting from eligible new or expanding businesses in their service area.
NYPA provides these communities with an array of energy-efficiency services and has helped install electric vehicle charging infrastructure for the public in support of New York Governor Andrew Cuomo’s Charge NY 2.0 initiative, an effort aimed at installing 10,000 charging stations by the end of the year.
Through NYPA’s EVolve NY program, NYPA is creating a fast-charging network across the state to help accelerate the adoption of electric vehicles. More than 150 chargers, open to the public, are being installed along major interstate corridors, in five major cities and at New York City airports by the end of 2021.
Bureau of Ocean Energy Management To Conduct Review Of N.C. Offshore Wind Project
August 10, 2021
by Paul Ciampoli
APPA News Director
August 10, 2021
The Department of the Interior recently announced that its Bureau of Ocean Energy Management (BOEM) will conduct an environmental review of a proposed wind energy project offshore North Carolina.
BOEM published a Notice of Intent (NOI) to Prepare an Environmental Impact Statement (EIS) in the Federal Register on July 29, which opens a 30-day public comment period.
BOEM will review a construction and operations plan submitted by Kitty Hawk Wind LLC, a wholly owned subsidiary of Avangrid Renewables, for a commercial-scale, offshore wind energy project consisting of up to 69 total wind turbine generators, one offshore substation, inter-array cables, and up to two transmission cables that will make landfall in Virginia Beach.
This is the first project within the Kitty Hawk Wind Energy Area (WEA) of Avangrid Renewables. The project consists of nearly 50,000 acres located over 27 miles off the coast of the Outer Banks, due East of Corolla, N.C., with a capacity of at least 800 megawatts (MW). When the entire 122,405-acre Kitty Hawk WEA is developed, it is expected to support a total generation capacity of up to 2,500 MW.
North Carolina has set goals to develop 2.8 gigawatts (GW) of offshore wind energy off of the state’s coast by 2030 and 8 GW by 2040. Roy Cooper, North Carolina’s governor, recently issued an executive order highlighting the state’s commitment to offshore wind power and setting a target to procure 8 GW of offshore wind energy by 2040.
Virginia enacted the Virginia Clean Economy Act in 2020, which sets a target of to produce its electricity from 100% renewable sources by 2045, with 5.2 GW of offshore wind energy by 2034.
If approved, the Kitty Hawk project will contribute towards each of the state’s offshore wind goals.
As part of BOEM’s environmental review, the agency must first identify what should be considered in the EIS, such as important resources and issues, potential impacts to the environment, reasonable alternatives, and mitigation measures.
During the 30-day public comment period, BOEM will hold three virtual public meetings in August.
Biden Administration approves first major offshore wind project in U.S. waters
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-MW Vineyard Wind energy project 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.
Vineyard Wind is a joint venture between Avangrid Renewables, a subsidiary of AVANGRID, Inc., and Copenhagen Infrastructure Partners.
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.
SPP Board Of Directors Approves Western RTO Expansion Terms And Conditions
August 10, 2021
by Paul Ciampoli
APPA News Director
August 10, 2021
Southwest Power Pool’s (SPP) board of directors and its strategic planning committee approved the submitted policy-level terms and conditions for regional transmission organization (RTO) expansion in the Western Interconnection during its quarterly joint stakeholder meeting in late July.
Arkansas-based SPP manages the electric grid across 17 central and western U.S. states and provides energy services on a contract basis to customers in both the Eastern and Western Interconnections.
Prospective western participants include Basin Electric Power Cooperative, Colorado Springs Utilities, Deseret Power Electric Cooperative, the Municipal Energy Agency of Nebraska, Tri-State Generation and Transmission Association, Wyoming Municipal Power Agency and the Western Area Power Administration (WAPA).
WAPA’s evaluation of full RTO participation in the Western Interconnection includes its Upper Great Plains-West region, Colorado River Storage Project and Rocky Mountain region.
All these organizations except Colorado Springs Utilities joined SPP’s Western Energy Imbalance Service (WEIS) market on its Feb. 1, 2021, launch before announcing their intent to explore full western RTO participation. SPP said that Colorado Springs Utilities anticipates joining the WEIS market in 2022 and is also exploring RTO membership as part of this group of entities.
“WAPA anticipates additional value in increasing energy transfers between the East and West through the SPP RTO, providing benefits and mitigating risk for existing and prospective RTO members along with our customers,” said WAPA Interim Administrator Tracey LeBeau in a statement.
If the utilities join or add additional facilities in SPP, they will become the first members of SPP’s RTO to participate in SPP’s Integrated Marketplace in the Western Interconnection. This would extend the reach and value of SPP’s services — including day-ahead wholesale electricity market administration, transmission planning, consolidated balancing authority, resource adequacy and more — and the synergies they provide when bundled under the RTO structure, SPP said.
A recent SPP Brattle study found that WEIS participants’ membership in the SPP RTO would produce approximately $49 million in savings annually for SPP’s current and new members. The western utilities joining SPP would receive $25 million a year in adjusted production cost savings and revenue from off-system sales, and SPP’s members in the east would benefit from $24 million in savings resulting from the expansion of SPP’s market, transmission network and generation fleet.
In the Eastern Interconnection, SPP formed in 1941, implemented operating reserve sharing in 1991, became a certified reliability coordinator in 1997 and earned its RTO designation from the Federal Energy Regulatory Commission (FERC) in 2004. It launched its first real-time balancing market in 2007 then transitioned to a day-ahead market and became a single, consolidated balancing authority in 2014.
SPP began serving customers in the west in October 2015. SPP subsequently expanded its services in the west in December 2019 when it launched its Western Reliability Coordination service on a contract basis and in February 2021 with the successful launch of the WEIS market.
SPP said that the next step to expand the RTO into the Western Interconnection is resolving the outstanding terms and conditions, including cost allocation for the direct-current ties between the Eastern and Western Interconnections. The remaining terms and conditions are expected to be resolved by the October 2021 SPP board of directors meeting. Prospective participants will also need to complete stakeholder processes.
Once accomplished, prospective participants plan to execute a financial commitment agreement in April 2022 to initiate the western RTO expansion. SPP then plans to file tariff modifications with FERC in October 2022 with approval expected sometime in early 2023.
Once approved, SPP anticipates extending its RTO into the west in early 2024.
Federal Legislation Calls For Nuclear Power Purchase Agreement Program
August 10, 2021
by Paul Ciampoli
APPA News Director
August 10, 2021
Reps. Elaine Luria, D-Va., and Dan Newhouse, R-Wash., introduced legislation that establishes an up to 40-year-long nuclear power purchase agreement program at the Department of Energy (DOE) and directs the Secretary of Energy to enter into one or more agreements to purchase nuclear power from reactors licensed after January 2020.
The bill, H.R.4834, also requires the Secretary of Energy to enter into one national security-related nuclear power purchase agreement prior to 2026 to provide reliable and resilient power in remote off-grid and emergency scenarios.
Luria and Newhouse were joined by Reps. Anthony Gonzalez, R-Ohio, and Scott Peters, D-Calif., in sponsoring the bill, which was introduced in late July.
The Nuclear Power Purchase Agreements Act has been endorsed by the U.S. Chamber of Commerce, Clear Path, the U.S. Nuclear Industry Council, the American Nuclear Society, the Nuclear Energy Institute, NuScale Power and the Nuclear Innovation Alliance.
In May 2021, NuScale Power and Washington State’s Grant County Public Utility District on announced the signing of a memorandum of understanding to evaluate the deployment of NuScale’s small modular reactor (SMR) technology in Central Washington State.
In January, Utah Associated Municipal Power Systems and NuScale Power signed agreements to facilitate the development of the Carbon Free Power Project that would deploy NuScale’s SMR design at the Idaho National Laboratory. Energy Northwest has the option to operate the SMR plant.
California Community Choice Aggregators Form Financing Authority
August 9, 2021
by Paul Ciampoli
APPA News Director
August 9, 2021
Four California community choice aggregators (CCAs) have jointly formed the California Community Choice Financing Authority (CCCFA), a joint powers agency that was created with the goal of reducing the cost of power purchases through a pre-payment structure.
Central Coast Community Energy, East Bay Community Energy, Marin Clean Energy and Silicon Valley Clean Energy are the founding members of CCCFA. CCCFA membership is open to CCAs in California that are interested in utilizing the joint powers agency for prepayment transactions.
Member agencies will be able to save 10% or more on power purchase agreements entered into under this structure, the four CCAs said.
The prepayments will allow CCAs to reduce customer costs, retain the green attributes of the renewable energy contract, and increase funding available for local programs, according to the CCAs.
Formation of CCCFA assists the member CCAs by undertaking the financing or refinancing of energy prepayments with tax-advantaged bonds. The prepay structure enables publicly owned utilities, including CCAs, to effectively leverage the difference between tax-exempt and taxable debt rates to fund the reduction in the cost of power purchases, they noted.
Prepayment transactions have been used in the United States for the last 30 years primarily for natural gas transactions. Over 90 municipal prepayment transactions totaling over $50 billion have been completed in the US, with over 95% of them for natural gas.
Prepayment transactions are codified in U.S. tax law and Congress enacted legislation specifically allowing for such transactions as part of the National Energy Policy Act of 2005. CCCFA will take advantage of this structure to increase the amount, and reduce the cost, of clean energy on the California grid, combating climate change and fulfilling customers’ needs for non-polluting resources, the CCAs said.
Energy prepayment transaction agreements undertaken by CCCFA must be approved by the Board of Directors of the member CCA proposing the prepayment. Then the CCCFA Board will have the opportunity to fully consider the benefits, obligations, and risks of each prepayment transaction prior to approving any bond issuance. CCCFA is governed by a Board of Directors consisting of one director representing each founding CCA.
The creation of CCCFA follows the formation of California Community Power earlier this year as a way to help CCAs across the state reduce costs.
Additional information about CCCFA is available here.
The American Public Power Association has initiated a new category of membership for community choice aggregation programs.
Northwest Power Pool Releases Details Of Proposed Resource Adequacy Program
August 9, 2021
by Peter Maloney
APPA News
August 9, 2021
The Northwest Power Pool (NWPP) and participating member utilities have released a design of a proposed resource adequacy (RA) program.
The report details elements of the program, including a “forward showing” program and an operational program, as well as a proposed governance framework. The report also provides details on how stakeholders affected by the program can participate.
The release of the report clears the way for the next phase of NWPP’s proposed resource adequacy effort. NWPP is preparing to launch the next phase in which a forward showing program will provide informational, non-binding resource adequacy requirements for the winter of 2022. NWPP said it would accept participation agreements for the next stage of the program beginning Aug. 16 and running through Sept. 30, which will serve as a beta test for the proposed program design.
The integrated regional power system is in transition, NWPP said in the report. The impending retirement of several thermal generators within and outside the region, which includes the Western U.S. and Canada, mixed with increasing variable energy resources, has led to questions about whether the region will continue to have an adequate supply of electricity during critical hours, according to the report.
In the past four years, several studies have identified an urgent and immediate challenge to the regional electricity system’s ability to provide reliable electric service during high demand conditions.
“These developments threaten to upset the balance of loads and resources within the region and, if not properly addressed, will increase the risk of supply disruptions during winter and summer, increase financial risk for utility customers, and hinder the ability of the system to meet environmental goals and legal requirements,” the report said.
The resource adequacy effort began early in 2019 when the NWPP and a coalition of NWPP members initiated the program. The contemplated resource adequacy program “seeks to enhance and increase reliability for the footprint while maintaining existing responsibilities for reliable operations and observing existing frameworks for planning, purchasing, and delivering energy,” the report said.
“We believe the resource adequacy program will provide multiple benefits to the region as well as participants, including reliability, cost savings and improved visibility and coordination,” Frank Afranji, NWPP president, said in a statement.
There are many forms of resource adequacy – capacity, energy and flexibility – but NWPP’s program focuses on creating a capacity resource adequacy program. Additional adequacy programs may also be necessary following the implementation of the capacity program, the report said. “If additional programs are desired, a similarly discrete decision and implementation process would need to be undertaken to design and implement such programs,” the report said.
The report also noted that the proposed resource adequacy program does not replace or supplant the resource planning processes used by states or provinces or the regulatory requirements of the Federal Energy Regulatory Commission (FERC), North America Electric Reliability Corporation, or the Western Electricity Coordinating Council, but is designed to supplement and complement those processes and requirements.
The resource adequacy program design and implementation will have two components: a forward showing program and an operational program. The forward showing program is designed to ensure that the NWPP footprint has enough demonstrated capacity, well in advance of required performance, to meet the established reliability metrics. It establishes regional metrics for the NWPP footprint, the qualified capacity contribution and effective load-carrying capability of various resources, as well as deliverability expectations, and determines the periods for demonstrating adequacy.
The operational program seeks to achieve a balance between planning while providing flexibility in order to protect customers from unreasonable costs. It creates a framework to provide participants with pre-arranged access to capacity resources in the program footprint during times when a participant is experiencing an extreme event.
Under the current proposal, NWPP would become a public utility as defined by the Federal Power Act.
NWPP would also need to meet independence requirements established by FERC so that the power pool would have financial independence from individual participants in order to ensure there is no undue discrimination for the NWPP.
NWPP members include a number of public power entities.
Bonneville Power Administration To Decrease Power Rates By An Average Of 2.5 percent
August 4, 2021
by Paul Ciampoli
APPA News Director
August 4, 2021
The Bonneville Power Administration (BPA) will decrease power rates by an average of 2.5% and slashed its proposed transmission rate increase in half to an average of 6.1%, the federal power marketing administration (PMA) said in late July.
The new rates were announced as BPA released the final record of decision for its BP-22 power and transmission rate case as well as a tariff proceeding (TC-22).
The tariff proceeding adopted new language in BPA’s open access transmission tariff that will enable the power marketer to participate in the Western Energy Imbalance Market (EIM) if BPA chooses to do so. The decision of whether to join the Western EIM is a separate process outside of the tariff proceeding and is anticipated to be made by the end of the fiscal year.
In 2019, BPA issued a record of decision that addresses numerous policy issues and topics related to its participation in the EIM. BPA also signed a Western EIM Implementation Agreement with the California Independent System Operator that signaled the beginning of work on projects that need to be completed before BPA could start EIM operations.
Under a settlement adopted by the BP-22 record of decision, firm power tier 1 rates will decrease by 2.5% for fiscal years 2022 and 2023. Looking back over the previous decade, BP-22 will cap a 10-year period during which BPA’s power rate trajectory increased by less than 2% annually, which is in line with historical inflation rates.
“Rates that have matched inflation – not just in a single rate case, but over a sustained period – is proof of BPA’s commitment to bending the cost curve and driving down rate pressures on our power rates,” said BPA Administrator John Hairston in a statement. BPA’s announcement “demonstrates we are financially strong, competitive and responsive to our customers’ needs,” he said.
With respect to transmission, the settlement provided for a 6.1% average effective rate increase across the rate period, a number roughly half of what was proposed in an initial proposal.
“We’ve landed in a spot where BPA will be able to continue to keep its transmission commitments and re-invest in the value of BPA’s transmission infrastructure in a fiscally sound and responsible manner,” Hairston said.
Beyond rates, the BP-22 record of decision also establishes revenue financing for up to $40 million for both the power and transmission business lines. This financing will allow BPA to issue less debt and decrease upward rate pressures in subsequent rate cases.
As part of the settlement, BPA has committed to holding workshops on various topics of interest to customers, including revenue financing, EIM costs and benefits, balancing services, the Eastern Intertie, and transmission losses.
The tariff proceeding updated language in BPA’s tariff, including addressing the terms and conditions that will apply to transmission service if BPA decides to participate in the Western EIM. The adoption of this language enables the potential participation of BPA in the Western EIM without committing BPA to that path.
This proceeding also addressed Southern Intertie studies, transmission planning process, real power loss return, the removal of an exception for designation of Seller’s Choice agreements, ministerial edits to service agreement templates, generator interconnection procedures and requirements, and credit standards.
The changes captured by the final records of decision for BP-22 and TC-22 will be effective October 1. Specific to rates, BPA will file the case with the Federal Energy Regulatory Commission, requesting interim approval to start on that date while awaiting final FERC approval.
The Public Power Council (PPC) said that BPA’s final record of decision in the BP-22 rate proceeding largely advances the proposed approach from members of the PPC.
“The Northwest public power community came together with a unified voice to focus on a core set of high-impact issues with BPA on its upcoming power and transmission rates,” said Scott Simms, PPC’s Executive Director. “To come to agreement in the BPA rate case, we knew we needed a strategy that delivered meaningful savings to public power and was reasonable for BPA to run its operations.”
The PPC, established in 1966, is an association that represents over 100 consumer-owned electric utilities in the Pacific Northwest. PPC’s mission is to preserve and protect the benefits of the Federal Columbia River Power System for consumer-owned utilities. PPC is a key forum to identify, discuss and build consensus around energy and utility issues.
Shrewsbury Electric & Cable Operations Adopts Accelerated CO2 Reduction Goals
August 4, 2021
by Peter Maloney
APPA News
August 4, 2021
Shrewsbury Electric & Cable Operations (SELCO) in Massachusetts has adopted a plan with even more aggressive carbon dioxide (CO2) emission reductions than those set by the state.
Earlier this year, Massachusetts established guidelines for all utilities to reach net-zero emissions by 2050. At its July 26 meeting, the SELCO Commission, which approves budgets and sets rates for the public power utility, voted unanimously to adopt a power supply policy that provides a roadmap to 100 percent CO2 free power by 2032.
SELCO provides electric, cable, telephone, and internet services to residential and commercial customers in the Town of Shrewsbury.
The policy establishes a greenhouse gas emission standard for the utility and provides a framework for future power supply contracts, as well as acquisition and retirement of Renewable Energy Certificates (RECs) in pursuit of net-zero emissions.
“We believe this accelerated schedule is in alignment with customer priorities, meets or exceeds community goals for net-zero emissions, and helps establish SELCO as an industry leader,” Christopher Roy, SELCO’s general manager, said in a statement.
The accelerated emissions reduction timeline positions SELCO to serve as the bedrock for a clean energy transition across all other sectors within the town of Shrewsbury and “balances both fiscal and environmental responsibility, resulting in the average customer seeing a monthly bill impact of around $1 in 2021 and increasing to about $5.60 in 2032,” Roy said.
SELCO’s power supply policy will be reviewed annually by the SELCO Commission to confirm the utility is meeting benchmarks in alignment with established goals. The annual review also aims to ensure market fluctuations, industry trends, changes in regulatory requirements and/or public policy are reflected in the utility’s roadmap to net-zero carbon emissions.
After vetoing climate change legislation in January, Charlie Baker, Massachusetts’ Republic governor, in late March signed comprehensive climate change legislation that commits to reaching net zero emissions in 2050.
The law, Senate Bill 9, An Act Creating a Next Generation Roadmap for Massachusetts Climate Policy, establishes interim goals for emissions reductions, significantly increases protections for environmental justice communities across Massachusetts, authorizes the governor to implement a new, voluntary energy efficient building code for municipalities, and allows the commonwealth to procure an additional 2,400 megawatts of offshore wind energy by 2027.