[USA] New York regulators reject proposed NRG and Danskammer Energy natural gas plants

The New York Department of Environmental Conservation (DEC) announced on October 27, 2021, that it has rejected Title V air permit applications for NRG Energy’s proposed Astoria Replacement Project and Danskammer Energy LLC's planned Danskammer Energy Center.[1] [2] The DEC rejected the two proposed natural gas-fired plants because their project emissions are inconsistent with achieving the goals set out in New York’s 2019 Climate Leadership and Community Protection Act (CLCPA). New York’s 2019 climate law requires the state to reduce statewide greenhouse gas emissions 40% below 1990 levels by 2030 and 85% below 1990 levels by 2050. The law also requires the state's electricity to be emissions-free by 2040.

Danskammer Energy submitted its air permit application on December 3, 2019, for a 536 MW plant in Newburgh, New York. Astoria Gas Turbine Power, a wholly-owned subsidiary of NRG Energy, submitted its application on April 27, 2020, for a proposed 437 MW facility in Astoria, New York. Both companies put forth several arguments for why the proposed projects meet the requirements of the climate law, including that the projects have lower emissions than the plants they would be replacing. The companies also cited the potential future use of renewable natural gas and hydrogen, which would lower the plants’ environmental impact. NRG and Danskammer Energy have 30 days to appeal the DEC's decision and request an administrative adjudicatory hearing.

[1] https://www.dec.ny.gov/press/124069.html

[2] https://www.dec.ny.gov/press/124070.html

[USA] DOE announces $20 million in funding for four regional CCUS projects

On October 15, 2021, the Department of Energy (DOE) announced that $20 million in funding was awarded to four projects working to accelerate the regional deployment of carbon capture, utilization, and storage (CCUS).[1] According to the news release, expanding the deployment of CCUS will reduce CO2 emissions from industrial sources and help the U.S. achieve net-zero emissions by 2050. The projects, referred to as Regional Initiatives to Accelerate CCUS Deployment, represent all four corners of the country and will each receive $5 million in funding. The Regional Initiatives are university-led partnerships with academia, non-governmental organizations, industry leaders, and local and state governments. They include:

• Battelle Memorial Institute in Columbus, OH: the Regional Initiative to Accelerate CCUS Deployment in the Midwestern and Northeastern USA project will consist of 20 Midwestern and Northwestern states to review regional infrastructure and technical challenges to deploying CCUS in three sedimentary basins and the Arches province.

• New Mexico Institute of Mining and Technology in Socorro, NM: the Carbon Utilization and Storage Partnership of the Western United States project will be in 15 Western states and focus on compiling geologic datasets in the region for storage resource analyses and identifying lapses in data.

• Southern States Energy Board in Peachtree Corners, GA: the Southeast Regional Carbon Utilization and Storage Partnership project will extend across 15 Southeast states in an effort to identify at least 50 potential regional sites to evaluate storage resource potential and infrastructure needs.

• University of North Dakota Energy and Environmental Research Center in Grand Forks, ND: the Plains CO2 Reduction project consists of 13 Northwest states and four Canadian provinces to identify and address onshore regional storage and transport challenges facing the commercial deployment of CCUS.

The initiatives will work to identify and promote CCUS projects by addressing technical challenges to deployment; facilitating the collection, sharing, and analysis of data; evaluating regional storage and transport infrastructure; and promoting regional transfer of technologies.

[1] https://www.energy.gov/articles/doe-awards-20-million-help-states-deploy-carbon-capture-and-storage

[USA] Dominion reaches tentative settlement in Virginia rate case

On October 18, 2021, Dominion Energy Virginia, the state’s largest electric utility, announced that it had reached a tentative settlement agreement in its pending base rate case with staff at the Virginia State Corporation Commission (SCC), the Office of the Attorney General, and other parties[1].[2] The SCC staff and the state attorney general had alleged that the utility had garnered nearly $1 billion in excess profits between 2017 and 2020. The allegations spurred regulators to start a rate review in March 2021 to examine Dominion’s earnings over the last four years and whether adjustments to customers' base rates are necessary.

Under the proposed agreement, Dominion’s customers will receive a total of $330 million in one-time refunds and a $50 million rate reduction. The one-time refunds would be made up of $255 million over a six-month period and $75 million over three years, which would equal a refund of about $67 for a typical residential customer. According to Dominion, the $50 million rate reduction is the maximum amount permitted by law under the 2018 Grid Transformation and Security Act and would result in a proposed monthly bill reduction of about $0.90 for each residential customer. The settlement agreement also includes the use of $309 million in revenue to offset the costs of developing the Coastal Virginia Offshore Wind pilot project, the deployment of smart meters, and a customer information platform. If approved by the SCC, Dominion would also receive a higher return for its shareholders, rising from the current 9.2% rate to a 9.35% return on equity.

[1] The settlement agreement is also joined by the Apartment and Office Building Association of Metropolitan Washington, Costco, Direct Energy, Department of the Navy on behalf of the Federal Executive Agencies, Kroger and Harris Teeter, Virginia Committee for Fair Utility Rates, and Walmart

[2] https://news.dominionenergy.com/2021-10-18-Dominion-Energy-Virginia,-State-Corporation-Commission-Staff,-Office-of-Attorney-General,-and-Other-Parties-File-Comprehensive-Rate-Settlement-Agreement-That-Provides-Significant-Customer-Benefits

[USA] PJM releases Phase 1 of its Offshore Wind Transmission Study

On October 19, 2021, PJM Interconnection[1], the largest regional transmission organization (RTO) in the U.S., published the Phase 1 results of its Offshore Wind Transmission Study.[2] In the study, PJM partnered with state agencies in Delaware, Maryland, New Jersey, North Carolina, and Virginia to identify transmission solutions across the RTO’s footprint to deliver offshore wind generation. Current offshore wind policy targets among PJM’s member states total 14,268 MW. In addition, within PJM, ten states and the District of Columbia have mandatory Renewable Portfolio Standard (RPS) targets.

In the study, PJM analyzed offshore wind injection totals ranging from 6,416 MW to 17,016 MW, as well as modeling state RPS targets. Of the five scenarios analyzed in Phase 1, one scenario was short-term, modeling out to 2027, while the remaining four scenarios were long-term, modeling out to 2035. The estimated cost to upgrade existing onshore transmission ranged from $627.34 million in the short-term scenario to $2.16 billion to $3.21 billion in the long-term scenarios. While the states in PJM’s footprint each have different offshore wind goals and policies, the report determined that coordinated planning among states could be a more efficient path to achieving these objectives than each state working independently.

[1] PJM serves all or parts of Delaware, Illinois, Indiana, Kentucky, Maryland, Michigan, New Jersey, North Carolina, Ohio, Pennsylvania, Tennessee, Virginia, West Virginia, and the District of Columbia.

[2] https://www.pjm.com/-/media/library/reports-notices/special-reports/2021/20211019-offshore-wind-transmission-study-phase-1-results.ashx

[USA] House Democrats request more details from LUMA Energy regarding its handling of Puerto Rico's grid

On October 8, 2021, Representatives Katie Porter (D-CA) and Raúl Grijalva (D-AZ)[1] sent a letter to the head of LUMA Energy, Puerto Rico's electric utility, asking for additional details on staffing levels, expenditures, executive compensation, and a stretch of power outages.[2] In June 2021, LUMA took over operating the island's distribution and transmission infrastructure from the Puerto Rico Electric Power Authority (PREPA) as part of an agreement with Puerto Rico's Public-Private Partnership Agreement. The takeover is an effort to overcome PREPA's bankruptcy and is intended to help Puerto Rico rebuild its grid after Hurricane Maria destroyed it in 2017.

The letter from the congressmen follows an oversight hearing of the House Natural Resources Committee on October 6, 2021, during which LUMA President and CEO Wayne Stensby failed to answer some of the committee's questions completely. The letter claims that since LUMA's take over, "conditions have worsened." The House Democrats highlight several issues, including a fire at LUMA's Monacillo substation in June 2021 that knocked out power to 800,000 customers. In addition, service complaints have more than doubling since the takeover. Despite these issues, LUMA has already tried to increase rates despite promises to keep them constant for the first three years of operation. The Puerto Rico Energy Bureau recently rejected the utility's request to recover $52 million in additional fuel and other costs in June and July 2021.

Rep. Porter and Rep. Grijalva argue that "One potential reason for these issues has been the size and experience of LUMA's workforce." According to the letter, over 3,000 of the 4,200 PREPA employees eligible to be transitioned "did not move to LUMA and instead transferred to other departments in the Puerto Rican government," despite LUMA's contract requiring qualified PREPA employees to be prioritized in the hiring process. Among other requests, the letter asks LUMA for a detailed breakdown of the number of employees and their experience levels across a variety of positions.

[1] Representative Porter is chair of the House Subcommittee on Oversight and Investigations and Representative Grijalva is chair of the House Committee on Natural Resources.

[2] https://naturalresources.house.gov/imo/media/doc/HNRC%20Document%20Request%20-%20LUMA%20Energy%20-%2010.8.2021.pdf

[Japan] Eneos announces deal to acquire Japan Renewable Energy for $1.78 billion

On October 11, 2021, Eneos Holdings Inc., Japan's largest oil refiner, announced it had reached a deal to acquire Japan Renewable Energy (JRE), a renewables developer and operator, for about 200 billion yen ($1.78 billion/EUR 1.55 billion) to expand its low-carbon business.[1] Under the deal, JPE will be a wholly-owned subsidiary of Eneos in late January 2022. Eneos will buy JRE from the infrastructure arm of U.S. investment bank Goldman Sachs and Singaporean sovereign wealth fund GIC. The agreement is the first big purchase of a renewables firm by a top Japanese oil company.

Founded by Goldman Sachs in 2012, JRE has 708 MW in renewable energy assets, including those under construction on an equity basis. Most of JRE's portfolio consists of solar, onshore wind, and biomass, with some offshore wind projects under development. After the agreement, Eneos' renewable assets will reach 1,220 MW. The deal will enable Eneos to meets its target of having over 1,000 MW of renewables in Japan and abroad by March 2023. The deal will also help Eneos reach its goal to achieve carbon neutrality by 2040.

[1] https://www.reuters.com/business/energy/eneos-says-buy-japan-renewable-energy-177-bln-2021-10-11/

https://www.japantimes.co.jp/news/2021/10/12/business/corporate-business/eneos-japan-renewable-energy/

[USA] SEEM goes into effect following FERC deadlock

The Southeast Energy Exchange Market (SEEM), a proposed trading platform for 15 utilities[1] in the Southeast, became operational on October 12, 2021, after the Federal Energy Regulatory Commission deadlocked 2-2 on whether to approve it.[2] The proposal was enacted by default because the four-member commission didn't act within the 60-day limit set by section 205 of the Federal Power Act (FPA). The commission could not agree on the lawfulness of the change, according to FERC’s notice. The proposal was initially filed with FERC in February 2021 and has since been amended twice. According to the utilities backing the plan, SEEM will set up an automated trading platform to buy and sell excess wholesale energy every 15 minutes, with the aim to reduce costs to customers and boost renewable energy resources. The platform is expected to produce up to $50 million in annual savings in the near term. SEEM expects to be operational in 11 states by mid-2022. Rehearing requests for the FERC decision are due in 30 days and the commission will have another 30 days to respond to them. FERC's commissioners will explain their views on the SEEM proposal in upcoming filings.

[1] The full list of expected members is: Associated Electric Cooperative, Dalton Utilities, Dominion Energy South Carolina, Duke Energy Carolinas, Duke Energy Progress, Georgia System Operations Corporation, Georgia Transmission Corporation, LG&E and KU Energy, MEAG Power, NCEMC, Oglethorpe Power Corp., PowerSouth, Santee Cooper, Southern Company and TVA.

[2] https://southeastenergymarket.com/wp-content/uploads/Notice-re-SEEM-Effective-by-OOL-10.13.2021-ER21-1111.pdf

https://southeastenergymarket.com/wp-content/uploads/NR-SEEM-FERC-Approval-2-2-vote-FINAL-101321.pdf

[USA] ESS and SB Energy sign agreement to deploy 2 GWh of iron flow storage through 2026

On September 30, 2021, Oregon-based long-duration battery manufacturer ESS announced that it had reached an agreement with SB Energy, a U.S. renewable energy firm that is a subsidiary of Japan’s SoftBank Group, to deploy 2 GWh of iron flow storage through 2026.[1] ESS produces flow batteries built with only iron, salt, and water that can provide up to 12 hours of output. The manufacturer has also developed a large-scale battery system starting at 3 MW with durations of between 6 and 16 hours for power providers and large manufacturers. According to the press release, ESS systems can help customers enhance grid resiliency and eliminate the risk of systems catching fire, especially in wildfire-prone areas likes those in California.

Under the agreement, SB Energy will deploy iron flow battery systems to complement its solar power projects in Texas and California. SB Energy has five utility-scale solar projects totaling 1.7 GW under construction or operation and is developing other solar and storage projects to be built in the near term. The first system has already arrived at a solar generation site in Davis, California, and will be installed later in October 2021.

[1] https://essinc.com/wp-content/uploads/2021/09/ESS_SBEnergyFramework_release_FINAL.pdf

[USA] Spire asks Supreme Court to pause Missouri pipeline shut down

On October 4, 2021, Spire STL Pipeline LLC requested the Supreme Court stay an order from the U.S. Court of Appeals for the District of Columbia Circuit shutting down the Spire STL pipeline.[1] The 65-mile pipeline runs from Illinois to the St. Louis, Missouri area to serve Spire Missouri customers. The pipeline has been operational since 2019 and is a rare case of federal courts vacating a pipeline’s service after it is operational. In June 2021, the D.C. Circuit vacated the pipeline’s certificate of public convenience and necessity, which was issued by the Federal Energy Regulatory Commission (FERC) in 2018. The court ruled that FERC had failed to adequately assess the need for the Spire pipeline. Following this, Spire obtained a temporary certificate from FERC in September 2021 to operate the pipeline until December 13, 2021, while regulators consider the next steps for the pipeline. On October 1, 2021, the D.C. Circuit declined Spire's request to delay its issue of a formal shutdown mandate on Oct. 8.

In its application for an emergency stay from the Supreme Court, Spire warned that shutting off the pipeline will lead to 400,000 St. Louis area customers experiencing extended loss of service when FERC's temporary permission expires this winter. Spire argued that there is no guarantee that FERC will keep the temporary certificate in place or offer an extension. The company’s application comes as it prepares for a broader Supreme Court challenge of the D.C. Circuit’s decision.

[1] https://www.supremecourt.gov/Search.aspx?FileName=/docket/docketfiles/html/public%5C21a56.html

[USA] Coalition of energy companies urge FERC to overturn revised PJM MOPR

The PJM Power Providers Group (P3)[1], a non-profit organization focused on promoting well-designed competitive markets, filed an emergency challenge on October 5, 2021, to a recent overhaul of the minimum offer price rule (MOPR) adopted by PJM Interconnection LLC, the Grid operator for 13 states and the District of Columbia.[2] P3 is a coalition of independent power producers that operate across the Mid-Atlantic and Midwest. Some members mostly own coal- or gas-fired power plants, while others also manage renewable energy projects.

In December 2019, the Federal Regulatory Commission (FERC), under then-Chairman Neil Chatterjee, issued the MOPR expansion rule, which raised the bid price for all state-subsidized resources, such as renewables and nuclear.[3] In response to concerns from states and Biden-appointed Chairman Richard Glick, PJM filed a plan with FERC in July 2021 to remove the application of the MOPR from state-subsidized resources and effectively make it easier for these resources to compete in capacity auctions.[4] However, P3 claims that FERC’s notice on September 29, 2021[5], allowing the revised MOPR to go into effect violates the Federal Power Act (FPA)[6] and the Administrative Procedure Act (APA)[7].

In its rehearing request, P3 argued that the notice conflicts with “the remedial rate fixed by the Commission under FPA section 206 in its recent expanded MOPR Orders,” which established protections against market power and discrimination. The notice also does not satisfy the provisions of the APA because it is arbitrary and capricious. The coalition also argued that the revised MOPR is in itself unlawful because it goes against more than a decade of Commission decisions that asserted that "uneconomic entry" of state-subsidized resources in regional power markets weakens market confidence and harms consumers. P3 said FERC should grant P3's request for rehearing, reject PJM's proposal, and direct PJM to develop a new policy to address state-subsidized resources.

[1] Members include: Advanced Power, Caithness Energy, L.L.C., Calpine Corporation, Cogentrix, Competitive Power Ventures, Eastern Generation, LLC, J-POWER USA Development Co., Ltd, LS Power Development LLC, NRG Energy

Talen Energy, Tenaska, Inc., and Vistra Energy

[2] https://www.p3powergroup.com/siteFiles/News/6CD08DA3CE06DFBADBA97398F79C0D2B.pdf

[3] https://www.powermag.com/the-significance-of-fercs-recent-pjm-mopr-order-explained/

[4] https://www.jdsupra.com/legalnews/pjm-s-focused-minimum-offer-price-rule-3396405/

[5] https://elibrary.ferc.gov/eLibrary/filelist?accession_number=20210929-3009&optimized=false

[6] The Federal Power Act created the Federal Power Commission (FPC) (now the Federal Energy Regulatory Commission) as the regulatory body of transmission and wholesale sale of electricity and natural gas.

[7] The Administrative Procedure Act governs the way in which administrative agencies of the federal government may propose and establish regulations. Under the APA, administrative agencies must abide by certain regulations when rulemaking.

[USA] FERC and NERC release new report on February 2021 extreme weather event

On September 23, 2021, the Federal Energy Regulatory Commission (FERC) and the North American Electric Reliability Corporation (NERC) released a joint report on the February 2021 cold weather event, which left millions in Texas and the Midwest without power.[1] According to the report, stronger weatherization standards for the gas and electric sectors are necessary for maintaining reliability and avoiding a repeat of the February outages. FERC and NERC’s report found that a large cause of the grid failure was due to the natural gas system, although other generators were also affected. The report found that 1,045 individual generating units were affected by the cold weather, "of which 604 were natural-gas fired generators." The preliminary report makes 28 recommendations, including nine key recommendations. The key recommendations include revising reliability standards to require generator owners to better prepare for extreme weather and allowing generators to recover the costs of weatherization.

The report found that this was the fourth time in the last decade that cold weather "jeopardized bulk-power system reliability due to unplanned cold weather-related generation outages;” there were similar events in 2011, 2014, and 2018. After the 2011 cold weather event, FERC and NERC released a report that recommended the development of winterization standards, but NERC ultimately decided not to act on that recommendation. During FERC’s open meeting to present the 2021 report, Chairman Richard Glick committed to stricter requirements and said new rules would cast a wide net.

[1] https://ferc.gov/february-2021-cold-weather-grid-operations-preliminary-findings-and-recommendations

[USA] Ford announces it will build two new campuses in Tennessee and Kentucky; plans to invest $11.4 B

Ford Motor Company announced plans on September 27, 2021, to build two new environmentally and technologically advanced campuses in Tennessee and Kentucky to produce the next generation of electric F-Series trucks and batteries to power future Ford and Lincoln electric vehicles (EVs).[1] Ford and its partner SK Innovation, a South Korean energy developer, plan to invest $11.4 billion—the largest investment in EVs at one time by an automotive manufacturer in the U.S—and create nearly 11,000 new jobs at the Tennessee and Kentucky “mega-sites.”

The new $5.6 billion campus in Stanton, Tennessee, called Blue Oval City, will create approximately 6,000 new jobs and cover almost 6 square miles. The campus will build next-generation electric F-Series pickups and will include a BlueOvalSK battery plant, key suppliers, and recycling. The Tennessee plant will be carbon neutral with zero waste to landfills once fully operational. In Glendale, Kentucky, Ford will work with SK Innovation to build two battery plants, the $5.8 billion BlueOvalSK Battery Park. The plants will create 5,000 jobs and are intended to supply Ford’s North American assembly plants with locally assembled batteries. The three new battery plants will enable 129 GWh a year of U.S. production capacity for Ford. Investments in the new battery plants are planned to be made via BlueOvalSK, a new joint venture to be formed by Ford and SK Innovation.

[1] https://media.ford.com/content/fordmedia/fna/us/en/news/2021/09/27/ford-to-lead-americas-shift-to-electric-vehicles.html

[Japan] Japan’s largest power generator to invest $1.58 billion in Philippine’s Aboitiz Power

On September 27, 2021, JERA, Japan’s largest power generator, announced that it is acquiring approximately 27% of the outstanding shares of Aboitiz Power Corporation, the leading utility in the Philippines, for approximately $1.58 billion, which is the largest investment by JERA to date.[1] JERA, a joint venture between Tokyo Electric Power Company and Chubu Electric Power Company, has signed a share purchase agreement with Aboitiz Power’s parent company Aboitiz Equity Ventures and Aboitiz & Company. The Japanese power generator hopes to benefit from growing energy demand in the Philippines while also significantly advancing the expansion of clean and renewable energy in the country. Power demand in the Philippines is expected to grow at an annual average rate of 4.2% through 2030, making the development of electric power infrastructure an urgent priority. JERA’s statement noted that the Philippines, like Japan, has limited energy resources and is subsequently reliant on imports.

JERA and Aboitiz will explore many areas of collaboration, including operation and maintenance, development of power projects, fuel procurement, and the use of cleaner fuels such as ammonia and hydrogen. Aboitiz Power aims to increase power generation capacity from 4.6 GW (including facilities under construction) to 9.2 GW by 2030. The utility also hopes to achieve a 50:50 clean energy and thermal capacity mix by 2030. JERA also has goals to reduce its emissions and is working to eliminate CO2 emissions from its domestic and overseas businesses by 2050 under its “JERA Zero CO2 Emissions 2050” objective.

[1] https://www.jera.co.jp/english/information/20210927_765

[USA] Dominion Energy Virginia proposes more than 1,000 MW of new solar and energy storage

In its second annual clean energy filing with the Virginia State Corporation Commission (SCC) on September 16, 2021, Dominion Energy Virginia proposed more than 1,000 MW of new solar and energy storage projects, the largest clean energy expansion from the utility to date.[1] Dominion proposed 15 projects in total, including 11 utility-scale solar projects ranging from 18 MW to 150 MW, two small-scale distributed solar projects at 2 MW and 1.6 MW, one solar plus storage project (100 MW plus 50 MW stored), and one 20 MW stand-alone energy storage project. In addition, the proposal includes 32 competitively selected solar and energy storage project power purchase agreements (PPAs) that third-party providers will operate. Together, these projects will provide more than 1,000 MW of electricity, enough power to run more than 250,000 homes at peak output.

The proposed utility-owned projects will require SCC approval as well as local and state permits before construction can begin. If approved, the proposed projects will add about $1.13 to the average residential customer’s bill. The distributed solar projects and the stand-alone storage project are expected to be completed in 2022. The remaining projects are set to be completed in 2023. The proposed projects would advance the goals of the Virginia Clean Economy Act (VCEA), which requires all electricity sales in-state to come from clean energy sources by 2045. According to the utility, the construction of the 15 utility-owned projects is also expected to generate more than $880 million in economic benefits across the state and support nearly 4,200 jobs.

[1] https://news.dominionenergy.com/2021-09-16-Dominion-Energy-Proposes-Largest-Expansion-of-Solar-and-Energy-Storage-for-Benefit-of-Customers

[USA] New York governor launches major green energy infrastructure projects

New York Governor Kathy Hochul, D, introduced two major green energy infrastructure projects on September 20, 2021, that will power New York City with wind, solar, and hydropower from upstate New York and Canada.[1] The two new projects, known as the Clean Path New York (CPNY) and Champlain Hudson Power Express (CHPE), were selected through a competitive process. The 174-mile CPNY will be developed jointly by Forward Power and the New York Power Authority and will primarily transfer wind and solar power generated in upstate New York into the downstate area. The 339-mile CHPE will be advanced by Transmission Developers, Inc., and Hydro-Quebec and will mostly move hydropower down from Quebec, Canada.

Together, the projects seek to produce roughly 18 million MWh of renewable energy annually. They will also both reduce greenhouse gas emissions by 77 million metric tons and reduce exposure to harmful pollutants resulting in $2.9 billion in public health benefits over the next 15 years. The projects will create approximately 10,000 jobs statewide and bring $8.2 billion in economic development investments, including developer-committed investment to support disadvantaged communities. Both projects will advance New York’s goal of achieving 70% renewable-sourced electricity by 2030. The projects will cost over $13 billion to build, according to developers. If approved, CHPE and CPNY are expected to begin providing power to New York City in 2025 and 2027, respectively.

[1] https://www.governor.ny.gov/news/during-climate-week-governor-hochul-announces-major-green-energy-infrastructure-projects-power

[USA] AMPLY Power and Volvo Trucks partner on charge management programs for electric trucks fleets

On September 22, 2021, AMPLY Power, an electric vehicle (EV) charging and energy management provider, announced that it is partnering with Volvo Trucks North America on customer programs to maximize uptime and cost savings for electric Class 8[1] heavy-duty electric trucks.[2] AMPLY Power joined the Volvo Group’s Connected Solutions Innovation Lab in Silicon Valley, CA, in 2019 as a founding member. The two companies collaborate on charging solutions to support the transition to electric power for fleets.  Through this partnership, the two companies are now working on projects on the West Coast and East Coast with two heavy-duty electric truck fleets. Notably, the companies are working with Manhattan Beer Distributors, a New York City-based company that is one of the largest beverage distributors in the country. The Manhattan Beer Distributors fleet includes five Class 8 Volvo VNR Electric models that have a range of 150 miles and a battery capacity of 264 kWh, needing approximately 70 minutes to reach an 80% charge. Other collaborations are in the works.

AMPLY uses its full-scale charge management system to help fleet operators like Manhattan Beer Distributors manage their energy infrastructure and charging needs for their operations. The company handles everything from site design to software and hardware to enable optimal energy charging. To manage charging operations, AMPLY uses its OMEGA software platform to charge vehicles based on the fleet’s priorities. The software also provides real-time alerts to help guarantee road time and deliver detailed emissions reporting.

[1] A Class 8 truck is a vehicle with a gross vehicle weight rating (GVWR) exceeding 33000 lb (14969 kg). This category include all semi-trailer trucks, single-unit dump trucks of a GVWR over 33,000, and non-commercial chassis fire trucks.

[2] https://amplypower.com/volvo-trucks-north-america-and-amply-power-collaborate-on-charge-management-programs-for-electric-truck-fleets/

[USA] PSEG and NJEDA sign lease for New Jersey Wind Port

On September 14, 2021, the New Jersey Economic Development Authority (NJEDA) and PSEG signed a lease for up to 78 years on land that will be the site of the New Jersey Wind Port in Salem County, New Jersey.[1] The Wind Port will provide a place for staging, assembly, and manufacturing activities related to offshore wind along the East Coast. The location of the port is adjacent to PSEG’s nuclear generating site, which currently provides more than 90% of the state’s carbon-free electricity. The site of the Wind Port itself is an artificial island on the eastern shores of the Delaware River, southwest of the City of Salem. Due to its large footprint, lack of height restrictions, and easy access to wind farm lease areas, the Wind Port is one of only a few ports on the East Coast that can house offshore wind turbine marshaling and manufacturing.

New Jersey and federal officials broke ground on the Wind Port on September 9, 2021.[2] Major construction is set to begin in December 2021, and the port should be completed by the end of 2023. The estimated cost of the project is between $300 million and $400 million. According to NJEDA, the Wind Port could potentially create more than 1,500 manufacturing, assembly, and operations jobs, as well as hundreds of construction jobs. Offshore wind is part of Governor Phil Murphy’s (D) Energy Master Plan to achieve 100% percent clean energy by 2050. Under the Energy Master Plan, the state has set a target to produce 7,500 MW of offshore wind energy by 2035.

[1] https://www.njeda.com/njeda-and-pseg-sign-78-year-lease-for-the-new-jersey-wind-port-establishing-new-jersey-as-a-hub-for-the-clean-energy-economy/

[2] https://subscriber.politicopro.com/article/eenews/2021/09/10/officials-break-ground-on-nj-wind-energy-construction-port-280415

[USA] Illinois passes landmark clean energy bill, Byron and Dresden nuclear plants to begin refueling

On September 13, 2021, the Illinois State Senate voted 37-17 to approve Senate Bill 2408, called the Climate and Equitable Jobs Act,[1] and Governor JB Pritzker (D) subsequently signed the bill into law on September 15, 2021.[2] The bill aims to prevent the premature closure of nuclear plants and will provide $700 million in subsidies for struggling nuclear power plants. In response to the provisions in S.B. 2408, on September 13, 2021, Exelon Generation said it plans to begin refueling its Byron and Dresden nuclear power plants.[3] The Byron and Dresden plants were previously set to shut down on September 13, 2021, and in November 2021, respectively.

In addition to the nuclear subsidies, the bill provides $340 million in subsidies for renewable energy and $180 million in subsidies for communities where fossil fuel plants will eventually be shutting down. S.B. 2408 also calls for the municipally-owned Prairie State coal plant, the largest carbon-emitting power plant in Illinois and one of the largest in the nation, CWLP Dallman, another municipally-owned coal-fired power plant, to cut carbon emissions 45% by 2038. In addition, the legislation raises Illinois’ renewable standard to 40% by 2030 and 50% by 2040, compared to its current renewable requirement of 25% of electricity by 2025.

[1]https://www.ilga.gov/legislation/BillStatus.asp?DocNum=2408&GAID=16&DocTypeID=SB&LegId=135062&SessionID=110&GA=102#actions

[2] https://www.nbcchicago.com/news/local/pritzker-signs-transformative-energy-plan-aimed-at-bringing-state-to-100-clean-energy-by-2050/2612986/

[3] https://www.exeloncorp.com/newsroom/passage-of-illinois-energy-legislation-preserves-nuclear-plants-and-strengthens-states-clean-energy-leadership

[USA] Report: Solar energy prices increase across all markets in Q2 2021

According to a report released on September 14, 2021, by Wood Mackenzie and the Solar Energy Industries Association (SEIA), the price of solar energy increased in every market in the second quarter of 2021.[1] This is the first time solar prices have increased quarter-over-quarter and year-over-year since SEIA and Wood Mackenzie began tracking this data in 2014. Prices for utility-scale solar energy have increased the most, rising 6% in the second quarter of 2021 compared to the second quarter of 2020. The report found that major drivers of the increase include supply chain constraints, increased shipping costs, and rising prices for commodities like steel. The report said that recent enforcement actions on Xinjiang metallurgical grade silicon and two new tariff petitions could significantly exacerbate supply chain constraints and increase solar system prices. The report forecasts that prices will likely remain elevated throughout 2021 but should decrease sometime in 2022.

Despite rising prices, the solar industry accounted for 56% of all new U.S. electric capacity additions in the first half of 2021. The U.S. officially surpassed 3 million solar installations in the second quarter of 2021, which was driven by a strong recovery in the residential sector after it was impacted by the COVID-19 pandemic. Wood Mackenzie forecasts that the U.S. will average just over 29 GW of new annual solar capacity additions through 2026 but noted that this falls short of the pace necessary to reach President Biden’s 2035 clean energy targets.

[1] https://www.seia.org/news/solar-prices-increase-across-every-market-segment-first-time-seven-years

[USA] Duke Energy Florida proposes plan to offset rate increases by 33%

On September 3, 2021, Duke Energy Florida announced that it had developed a plan to reduce the impact of new rates that go into effect in January 2022 by 33%.[1] Under this plan, Duke Energy Florida will spread the recovery of roughly $247 million of unrecovered fuel costs over two years and forgo immediate recovery of costs from recent storms, as well as other actions. These proposed actions would reduce a residential 1,000 kWh customer bill by an average of $4.67 per month. Under the plan, the typical residential customer's 1,000 kWh bill will increase by $9.24 per month, on average, for 2022. Commercial and industrial customer bills will increase by 1% to 8%.

The utility also recently proposed modifications to demonstrate its commitment to implementing energy efficiency and demand-side management programs. Proposed actions include increasing the Neighborhood Energy Savers targeted customers by 5% and making temporary changes to the approved Florida Energy Efficiency and Conservation Act (FEECA) programs for lower-income customers. In addition, customers enrolled in the utility's approved Residential Demand Response Program will receive a $30 "assistance incentive" in the form of a gift card that can be used toward their energy bill. Further, a second modification to FEECA programs will offer 20,000 assistance kits to provide energy efficiency savings to customers in need.

[1] https://news.duke-energy.com/releases/duke-energy-florida-seeks-to-reduce-2022-bill-impacts-by-33