Consumers had sought to amend its long-running agreement with National Energy of Lincoln in northeast Michigan, proposing early termination of a previous amendment that had extended the PPA
for the plant’s 18 MW of electricity to 2027. The latest proposed amendment would have resulted in closure of the plant on May 31, 2024.

In June 2023 Consumers applied for a similar early termination of a PPA with Cogeneration Michigan Associates Limited Partnership’s Cadillac Plant. The new exit date would also be May 31, 2024, from July 2028.

In both cases, Consumers Energy had argued the early terminations provide several benefits, such as “an
expected reduction in cost, which will be passed on to PSCR [power supply cost recovery] customers…”.

But commissioners raised concerns about these claimed potential savings since Consumers “would turn to volatile electricity markets to replace some of the energy output and capacity lost with the shutdown of the plants.”

“The Commission found relying on unpredictable markets for replacement supply outside of a comprehensive Integrated Resource Planning process in this manner entailed an unacceptable level of risk,” MPSC said in a statement.

Consumers had proposed replacing the capacity from the Lincoln biomass plant with a 33.6 MW solar facility and the Cadillac Plant with a 67 MW solar facility. However, the utility had itself noted in testimony that given their non-dispatchable profiles, the two solar facilities would not be able to replace all the electric capacity from the biomass plants without supplemental electricity purchases.

Commissioners said that was concerning given the Midwest Independent System Operator (MISO) has warned of tightening supplies.

Regulators greenlight solar and storage projects

The Commission also approved several renewable energy and storage projects called for in the long-range integrated resource plans of two Michigan electric utilities.

Commissioners approved DTE Energy’s application to construct a 220 MW/800 MWh lithium-ion battery storage facility at the site of the former Trenton Channel coal-fired plant in Wayne County. The battery storage project is expected to cost $460 million.

The application to build the battery facility was approved the same day DTE demolished two smokestacks at Trenton Channel.

Retired in 2022, the plant was originally built to address the needs of an expanding economy post World War I and was the fourth major power plant Detroit Edison put into operation during the 1920’s. The coal-fired plant began operating in 1924.

The plant had six turbine generators with 13 coal-fired boilers. The sixth and last turbine generator arrived by 1929. At that time, Trenton Channel was the largest project Detroit Edison had undertaken. At one point, with the expansion of the plant in 1950, the facility generated 1,060 MW of energy.

At its retirement, Trenton Channel generated 535 MW.

Beyond the actions related to the Trenton Channel site, MPSC on Friday approved Consumers Energy’s application for approval of a PPA between the utility and Freshwater Solar Project, a 300 MW solar facility in Montcalm County, with a total lifetime cost of $715.7 million.

The solar and battery storage system will help match the electricity consumed by Google’s forthcoming data center campus in Mesa, Arizona. Energy not needed by the data center will be used to meet other SRP customer needs.

Also supporting Google is the newly developed Storey Energy Center, an 88-MW solar and battery storage system, located in Coolidge, Arizona. Both facilities are operated by subsidiaries of NextEra Energy Resources. SRP and NextEra Energy Resources’ under-development wind facility, Babbitt Ranch Energy Center, will also support Google. This is a 161-MW wind project, on Babbitt Ranches property in Coconino County, north of Flagstaff.

Google is pursuing net-zero emissions across its operations and value chain by 2030, supported by a goal to run its data centers and office campuses on 24/7 carbon-free energy. The Sonoran, Storey, and Babbitt Ranch projects contribute to these commitments by supporting the energy needs of Google’s future data center in Mesa, which the company announced in 2023 with plans to use air-cooled technology.

“We’re aiming for every Google campus to operate on clean electricity every hour of every day by 2030, including in Arizona where we are excited to put down roots with our first data center in the state currently under construction,” said Amanda Peterson Corio, Global Head of Data Center Energy, Google. “The collaboration with Salt River Project and NextEra is accelerating decarbonization in Arizona and our own carbon-free journey in the region.”          

Through its Integrated System Plan, SRP found it will need to at least double the number of power resources on its power system in the next 10 years as it completes the planned retirement of 2,600 MW of coal resources, and amid growing energy demand.

“These renewable energy centers will generate low-cost, homegrown energy and provide millions of dollars in additional revenue to both Maricopa and Pinal counties over the life of the projects,” said Anthony Pedroni, Vice President of Renewables and Storage Development at NextEra Energy Resources. “We are pleased to work with SRP and Google to bring online Arizona’s newest renewable energy centers.”  

Originally published in Renewable Energy World.

The fuel cell power system, which combines Kohler’s power generation control platform and system integration expertise with a fuel cell module from Toyota, can be used as a prime or back-up power source or as part of a distributed network.

Klickitat Valley Health

Klickitat Valley Health (KVH) is a hospital that serves as the principal medical center for over 10,000 people in their district.

The hospital previously announced plans to reinforce their electrical infrastructure including backup and secondary power generation that included a hydrogen fuel cell to ensure uninterrupted operations.

According to Ben Crawford, business development manager, Kohler Energy and Richard Ferguson, new markets manager, business development, Fuel Cell Solutions at Toyota Motor North America, this type of solution was a good fit for KVH.

“For installations such as healthcare facilities, resiliency is critical…The KOHLER Fuel Cell System features a Toyota Solid Polymer Electrolyte Membrane (PEM) fuel cell for high-efficiency energy conversion, and the system has been designed for fast start-up and exceptional transient handling.

“Kohler provides one-source responsibility for the generating system and accessories, with the fuel cell unit being prototype-tested and factory-built within Kohler facilities. This approach results in a highly optimized and scalable solution that is built to last.”

The fuel cell system

Toyota has consolidated various components from a second-generation Toyota Mirai passenger vehicle fuel cell system into a single, compact fuel cell module.

The newly created module includes the second generation’s improved fuel cell stack and the elements responsible for the generation of electricity (air containing oxygen and the gaseous hydrogen fuel), system cooling, and on-board power control.

“Toyota has been exploring various applications of our fuel cell technology and this opportunity with Kohler highlights the decarbonization opportunities that hydrogen as a fuel can provide for customers,” said Chris Yang, Group vice president, Business Development, Toyota. “Our fuel cell technology can be scaled and used to power a wide variety of products beyond transportation, and it does so without any emissions except water.”

Kohler will also complete the system integration and balance of the plant to ensure all supporting components and auxiliary systems needed to deliver energy operate together safely and reliably and within a turnkey package.

“Kohler is committed to investing in new technologies to help our customers achieve their resiliency goals without sacrificing their climate-related objectives, and fuel cells are a hugely promising opportunity – both on their own, and when combined with other complementary technologies for more flexible power strategies, such as microgrids,” said Charles Hunsucker, Kohler Power Systems president.

According to Ben Crawford and Richard Ferguson, on-site or emergency power is becoming more prevalent because every mission-critical facility needs back-up power.

“It is a fundamental building block of resilient energy supply.

“In some cases, highly efficient generators using renewable fuel, such as hydrotreated vegetable oil (HVO), represent the best solution for mission-critical applications. In other cases, it will be hydrogen fuel cell systems.”

Originally published by Power Engineering International.

The project, in Emery County, Utah, was designed as a 400 MW solar PV facility integrated with a battery storage system. This expansion would increase the project’s storage capacity from 400 MWh to 1,600 MWh, making it one of the largest solar-plus-storage projects under development in the U.S.

The project involves capital investment of more than one billion dollars and will commence construction in the second quarter of 2024, rPlus said.

The developer last month announced it secured up to $460 million in investments from Sandbrook Capital. The partnership would include continued support from Gardner Group, the founding investor in rPlus and a leading commercial real estate company in the Mountain West.

rPlus currently has a 15 GW pipeline of solar, wind, battery and pumped storage hydropower projects.

Over the last five years, rPlus has developed over 630 MW of solar and wind projects that are now in service or under construction, including Graphite Solar and Appaloosa Solar, two operational Utah-based solar PV facilities.

rPlus is also currently managing construction on rPlus-developed Pleasant Valley Solar, the largest solar PV facility in the Idaho Power system, while a 152 MW wind project rPlus sold to Clearway Energy Group is also nearing completion.

Prevalon brings experience from the BESS business at Mitsubishi Power – over 30 projects, and three gigawatt hours (GWh) of utility-scale battery energy storage systems (BESS) deployed globally. Mitsubishi Power says Prevalon will operate “with the agility of a startup.”

The new entity retains the current leadership team, technology and service offerings, employees, and other assets from the BESS global business at Mitsubishi Power. Prevalon will continue to offer the integrated end-to-end battery energy storage solution, renamed “Prevalon Battery Energy Storage Platform,” which has an energy management system that will also serve as the foundation for Prevalon’s remote monitoring and diagnostics service business.

“As the speed of the energy transition increases, it is imperative that advanced technology solutions such as battery energy storage keep pace,” said Bill Newsom, President and CEO, Mitsubishi Power Americas. “With the establishment of Prevalon, we are confident its dedicated focus on battery energy storage solutions and services will unlock more value in this business to keep pace with this hyper-growth battery energy storage market. This is an example of Mitsubishi Power’s commitment to aligning and structuring its businesses in a way that brings more value and targeted expertise to the ever-changing energy transition.”

In 2023, New England had nearly 400 dispatchable generators and about 30,700 MW of generating capability, with 99.3% of electricity provided by natural gas, nuclear, hydropower, and imported electricity (mostly in the form of hydropower from Eastern Canada) and renewables. About 40,000 MW of new capacity is proposed to be built, the report said, and more than 7,000 MW of generation have retired since 2013 or may retire in the next few years, composed of mostly coal-fired, oil-fired and nuclear power plants. The region’s remaining two zero-carbon-emitting nuclear facilities, Millstone and Seabrook, supply a quarter of the electricity New England consumes in a year.

New England also had about 3,800 MW of of demand capacity resources (DCRs) and about 350,000 distributed solar power installations totaling 6,500 MW, with most installed behind the meter.

This number was calculated by adding total electricity generation and price-responsive demand reduction within New England to net imports from and exports to neighboring regions. The energy used to operate pumped storage power plants is then subtracted from that sum. Numbers are preliminary, pending the resettlement process.

Output from solar installations increased by 6% from 2022, rising to 3,851 GWh or 3% of the NEL. Wind power was relatively steady from year to year at 3% of NEL.

Oil-fired resources produced less electricity in 2023 than in 2022, accounting for 322 GWh, or 0.32% of the NEL, compared to the previous year’s 1,844 GWh. Production from coal-fired resources decreased from 320 GWh to 182 GWh, accounting for .16% of NEL for 2023.

All six New England states have renewable portfolio standards, which require electricity suppliers to provide customers with increasing percentages of renewable energy, ISO-NE said. Because large-scale renewable resources typically have higher up-front capital costs and different financing opportunities than more conventional resources, they have had difficulty competing in the wholesale markets. Therefore, the New England states are promoting, at varying levels and speed, the development of specific clean-energy resources to meet their public policy goals.

Several states have established public policies that direct electric power companies to enter into ratepayer-funded, long-term contracts for large-scale carbon-free energy that would cover most, if not all, of the resource’s costs.

About 97% of resources currently proposed for the region are grid-scale wind, solar and battery projects. As of January 2024, about 40,000 MW have been proposed in the ISO New England Interconnection Request Queue.

Energy storage represented 46% of the projects in the Interconnection Request Queue as of January 2024, and solar power accounted for 10%. Most solar power in New England is connected behind the meter directly at retail customer sites. Because such projects do not follow the ISO interconnection process, they aren’t reflected in the Interconnection Request Queue numbers.

The region had a total of about 350,000 distributed solar power installations as of December 2023 with a combined nameplate generating capability of approximately 6,500 MW. 

The facility broke ground January 18 and is expected to be operational by April, 2025. It will provide Arizona Public Service (APS) customers with energy, support increased power demand, and will also store energy from solar power plants on its grid to use when it is needed, particularly in the summertime when extreme heat and electricity demand is high in Arizona. In May 2023, Strata forged a 20-year tolling agreement with APS.

“The successful financing for the Scatter Wash battery storage complex marks a significant step forward in our mission to drive the transition to clean energy,” said Markus Wilhelm, Chief Executive Officer of Strata Clean Energy. “This opportunity to collaborate with our financing partners to bring this critical project to fruition will create a lasting, sustainable impact on a region that struggles with grid challenges and extreme heat.”

The development of Scatter Wash is supported by the Investment Tax Credit (ITC) for standalone energy storage created by the Inflation Reduction Act (IRA) of 2022. Last year, Strata was one of the first to take advantage of the tax incentive for energy storage for two projects in Vermont.

Strata has more than 270 solar and storage projects completed, per the company, and it has been involved in the development and construction of 3,000 MW of solar energy and 3,200 MWh of utility-scale energy storage. Its current development pipeline contains 8,400 MW of solar capacity and 31,800 MWh of storage.

J.P. Morgan and Nomura acted as coordinating lead arrangers and joint bookrunners. J.P. Morgan also fulfilled roles as administrative agent, depositary agent, and collateral agent. The financing was further supported by U.S. Bancorp Impact Finance and CoBank as coordinating lead arrangers with the Korea Development Bank and Norddeutsche Landesbank as joint lead arrangers. Furthermore, Siemens and Regions contributed as lenders in this transformative project, and U.S. Bancorp Impact Finance was also the primary tax equity investor.

Originally published in Renewable Energy World.

The site is a public-private partnership with the U.S. Air Force, located on a mixture of private land and land belonging to Edwards Air Force base – making it the largest public-private collaboration in the history of the U.S. Department of Defense. The site supplies power to the city of San Jose, Southern California Edison, Pacific Gas & Electric Co., the Clean Power Alliance, and Starbucks, among others.

The 4,660-acre project, developed by Terra-Gen and constructed by Mortenson, began construction in early 2021, with “substantial completion” reported last year. Construction efforts included installing over 98 miles of MV Wire, over 361 miles of DC Wire, 120,720 LG Chem, Samsung, and BYD batteries, and more than 1.9 million First Solar panels. [Editor’s note: I’m reading this like this meme.]

Last month, NASA’s Landsat 9 satellite captured an image of the project as seen from space.

The Air Force Civil Engineer Center, a primary subordinate unit of the Air Force Installation and Mission Support Center, worked with Edwards AFB to solicit lease proposals for the underutilized parcel of land on the northwest corner of the base using the Air Force Enhanced Use Lease (EUL) program. The Air Force and Terra-Gen signed a 35-year EUL agreement in November 2018.

“Through the program, Air Force installations can lease non-excess, underused land to private sector developers in return for rent or in-kind consideration subject to approval by the Deputy Assistant Secretary of the Air Force for Installations,” said Jeffrey Domm, Director for AFCEC’s Installations Directorate.

The Edwards array is the fifth and largest solar EUL project in the Air Force, with the others located at Luke Air Force Base, Arizona; Eglin Air Force Base, Florida; and two at Joint Base McGuire-Dix-Lakehurst, New Jersey.

Originally published in Renewable Energy World.

The announcement follows the release of initial data from the group which said it found that there were no reported injuries and no harmful levels of toxins detected following fires at battery energy storage systems in Jefferson, Orange, and Suffolk Counties last summer.

15 draft recommendations have been proposed by the working group after completing an examination of the existing FCNYS and other energy storage fire safety standards. They are meant to address preventative and responsive measures as well as best practices. They include proposed requirements related to peer review of project permit application packages, emergency response planning, and local fire department training.

The working group said the recommendations identify ways to further improve the regulatory framework for BESS operation in New York and are intended to apply to lithium-ion BESS exceeding 600 kilowatt-hours (kWh). The recs were developed with a focus on outdoor systems, BESS in dedicated-use buildings, and other grid-scale battery energy storage systems. They will be considered by the New York State Code Council for inclusion in the next edition of the FCNYS an an effort to improve the deployment of safety standards in the state.

The creation of the working group was announced last summer after a fire at an energy storage system in Warwick burned for multiple days in June; the next month, a battery fire at a solar farm in Jefferson County raised concerns of possible air contamination and an energy storage system at an East Hampton substation caught fire.

State agencies began immediate inspections of energy storage sites, and the working group was created with the intent to help prevent fires and ensure emergency responders have the necessary training and information to prepare and deploy resources in the event of a fire.

In 2019, New York state committed to adding 3,000 MW of Energy Storage by 2030, among other energy and climate goals, as part of the Climate Leadership and Community Protection Act.

“The battery energy storage industry is enabling communities across New York to transition to a clean energy future, and it is critical that we have the comprehensive safety standards in place,” Governor Kathy Hochul said. “Adopting the Working Group’s recommendations will ensure New York’s clean energy transition is done safely and responsibly.”

The Working Group includes State agency officials from the New York State Division of Homeland Security and Emergency Services, New York State Office of Fire Prevention and Control, New York State Energy Research and Development Authority (NYSERDA), New York State Department of Environmental Conservation, Department of Public Service and the Department of State, as well as BESS safety industry experts with the objectives of investigating the recent failure events, inspecting current installations and identifying gaps in codes and industry best practices.

Additionally, the working group said it is concluding negotiations with the impacted facilities’ battery manufacturers and utility companies to secure Root Cause Analysis (RCA) reports for the Warwick, East Hampton, and Chaumont fires. Subject matter experts will review and analyze the reports once they are made available.

The Working Group said it has also partnered with subject matter experts to inspect all operational battery systems above 300 kW in New York, which accounts for the majority of commercial battery systems in service across the state. Inspections are currently underway and are expected to be complete by the second quarter of 2024. The goal of these inspections is to revise the current evaluation checklists and best practices available for use by New York State and others prior to energizing battery energy storage systems and to incorporate lessons learned from the battery fires while enhancing emergency response measures.

Originally published in Renewable Energy World.

This “All-Source” RFP eliminates specific technology requirements, opening the application process for full competition of all non-emitting resources that are widely deployed and consistent with Oregon’s energy policy, PGE said.

The utility said this is its largest open application process to date and is the first in the company’s recent history to provide a flexible timeline for the start of operations.

This RFP, which accepts proposals for resources with a start date between 2025 and the end of 2027, is meant to be consistent with the objectives described in PGE’s 2023 Integrated Resource Plan (IRP), which was acknowledged by the Oregon Public Utility Commission (OPUC) on January 25, 2024. PGE will accept and evaluate bids throughout the first quarter of 2024 and present a shortlist of top-performing projects for OPUC acknowledgment later in the year.

Last year, PGE released a new Clean Energy Plan in addition to its IRP, which both focus on the addition of more community-based renewable energy (CBRE). In its IRP, PGE forecasts a significant capacity need of 1136 MW in summer, 1004 MW in winter and a significant energy need of 905 MWa (~2,500 MW nameplate) by 2030. To help meet that need, it plans to add up to 155 MW of CBRE resources by 2030 with plans to pursue at least 66 MW by 2026.

At the time, the utility said it also planned to conduct one or more RFPs for an additional 181 MWa (~520 MW nameplate) of non-emitting generation and sufficient capacity to remain resource-adequate each year.

The Clean Energy Plan includes:

• New utility scale renewable projects like wind and solar installations, both in-state and out-of-state.
• Non-emitting capacity such as batteries.
• CBRE resources, small distributed energy resources that include battery storage and solar, which can make customers more resilient and save them money.
• Customer-sited solutions including energy efficiency and demand response programs.
• Upgrades to local transmission lines and new regional transmission solutions to accommodate growth and bring a greater geographic diversity of resources to PGE’s portfolio.

PGE said 2030 emissions targets can be met with technologies and resources that are currently known and commercially available. The utility said to meet 2040 targets, new technologies not yet commercially available that can replicate thermal generation dispatchable capacity, such as advanced nuclear, hydrogen or carbon capture and storage, will be needed to support decarbonization and resource adequacy.

PGE also said its natural gas-fired plants would continue to play a role in meeting resource adequacy needs during the clean energy transition. The utility said it would “continue to invest in the efficiency, safety and emissions controls of those facilities as appropriate.”