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.

This is the key message of a new report, Hydropower Investment Landscape, developed by the National Renewable Energy Laboratory with support from Deloitte.

Globally, hydropower is the third largest source of electricity after coal and natural gas. As the world continues to transition away from fossil fuels, low-carbon sources of firm power will be increasingly critical to maintain the electric grid’s reliability. Hydropower already serves as a force multiplier for other renewable energy sources, and the value of this reliability and flexibility will continue to increase.

With the Bipartisan Infrastructure Law and Inflation Reduction Act offering financial support for clean energy projects, new hydropower and pumped storage projects could offer increasingly attractive investment opportunities.

The new report provides a comprehensive analysis of the risks and opportunities for investing in small- to medium-sized hydropower and pumped storage projects. Key findings from the study, which was funded by the U.S. Department of Energy’s (DOE’s) Water Power Technologies Office (WPTO), include:

Medium-sized projects offer significant opportunities for low-impact hydropower development. The medium-sized project pipeline includes projects that would constitute a total capacity of more than 1 GW and involves capacity additions, non-powered dam retrofits, hydropower generation in conduits, pumped storage, new stream-reach development and hybrid projects that combine multiple renewable technologies.

New technology innovations and the variety of sites at which hydropower could be developed present potential opportunities for future investment. Top areas of interest include modular conduit hydropower, non-powered dam resources, hybrid plant confirmation and closed-loop pumped storage innovation.

In the past decade, developers have begun designing and deploying small modular conduit systems, which can be manufactured offsite and assembled onsite. This approach can decrease construction costs, reduce project timelines and increase flexibility to expand the size of a hydropower system in the future. One example highlighted in the report of a company pursuing modular conduit hydropower is Emrgy, which raised several million dollars in private investment.

Because about 97% of U.S. dams do not have power-generating infrastructure, non-powered dams represent an attractive development opportunity with a potential capacity of 2 GW or more within the medium-sized range.

Using hydropower in a hybrid configuration with other renewables and battery storage can unlock new revenue streams by providing power during peak demand or ancillary services, such as the ability to adjust quickly to ensure grid reliability.

Closed-loop pumped storage systems feature two reservoirs that are not connected to a naturally flowing water feature like a river. These projects, which can offer siting flexibility, account for the majority of pumped storage projects in the pipeline. These projects would be the first closed-loop facilities in the U.S.

Investors surveyed for this study generally expressed the greatest level of interest in supporting capacity additions at existing facilities. With a connection to the grid already established, these facilities offer critical opportunities to increase clean energy production.

Overall, innovations in hydropower are driving the industry toward smaller, more modular and flexible solutions that can be more easily scaled and replicated.

Of course, there are challenges associated with hydropower projects, which are generally well known in the industry. Risks like financing for early-stage development, long permitting and licensing timelines, supply chain constraints, and more are important considerations but can also be addressed. The report includes several suggestions for addressing challenges in the industry to help increase investment. They are:

• Provide financing, funding and support for early-stage development
• Support improved market-based incentive signals for hydropower and pumped storage
• Support transparent and efficient permitting and licensing processes
• Support new, innovative research on reducing deployment time and costs
• Clarify new legislation and regulations and conduct outreach with developers and industry
• Increase awareness of new opportunities in hydropower and pumped storage

Published on Hydro Review.

The round was led by Prelude Ventures and Safar Partners. Mitsubishi Corporation and Standard Investments were among several new participating investors.

Quaise says a deep geothermal power plant can create 10x more energy than conventional geothermal and provide 24/7 baseload power on a small land footprint.

“The world needs, more than ever before, game-changing technologies that can deliver abundant carbon-free heat and power to become carbon neutral by 2050,” said Toshiaki Nobuhara, General Manager, International Utility Dept. of Mitsubishi Corporation. “We believe deep geothermal has great potential to become one of these technologies.”

The company says it has advanced a novel technique to vaporize rock using high-power microwaves in the millimeter range, based on more than a decade of research at MIT and recent testing at Oak Ridge National Laboratory. The original MIT experiments have been scaled up 100x, with field demonstrations commencing this year, Quaise said.

With the new funding, Quaise will conduct magnetic and seismic surveys, among other tests, to identify the most advantageous areas for initial drilling. The data will inform the company where to place the first commercial pilots.

Quaise also wants to strengthen the supply chain for the company’s drilling technology. Due to international limitations and custom needs, Quaise is entering joint development and licensing agreements with manufacturers to ensure future equipment will meet design and capacity requirements.

A central focal point for Quaise is repurposing existing fossil-fired industrial assets by drilling onsite at functional power plants to utilize the existing infrastructure and workforce.

Another company has recently secured funding in the geothermal space: Fervo Energy. Last month, Fervo announced it had raised $244 million in new funding led by Devon Energy, meant to enable Fervo’s next phase of growth, deploying technology adapted from the oil and gas industry at scale.

Since its last fundraise, Fervo has brought its first commercial project online and began drilling at Cape Station, a 400 MW project in Beaver County, Utah. Fervo says early drilling results show reduced drilling times and lower costs that exceed Department of Energy expectations for enhanced geothermal systems (EGS).

The fundraising will support Fervo’s continued operations at Cape Station, which is expected to begin delivering electricity to the grid in 2026.

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.

Vineyard Wind 1

Vineyard Wind 1, the first large-scale offshore wind project in the United States, is now providing approximately 68 MW to the New England grid. Once fully operational, Vineyard Wind 1 will deliver 806 MW.

In early January, Vineyard Wind delivered approximately 5 MW of power from one turbine to the grid. Following that milestone, the project has provided power from each of the first five turbines intermittently, as it ramped up its initial operations. Currently, the project has installed nine turbines and is in the process of installing the 10th, with preparations underway to transport the 11th turbine to the offshore project site. Additional power will be delivered to the grid sequentially, with each turbine starting production once it completes the commissioning process.

The power from the project interconnects to the New England grid in Barnstable, transmitted by underground cables that connect to a substation further inland on Cape Cod. Once completed, the project will consist of 62 wind turbines.

Empire Wind 1

With the permitting action by BOEM secured, 810 MW Empire Wind 1 is on track to begin construction in its federal lease area off the southern coast of Long Island later this year and could deliver first power to New Yorkers by 2026. In addition, construction to transform the South Brooklyn Marine Terminal into a hub for offshore wind could begin as early as this spring.

Empire Wind has recently received several federal approvals. Last week, it received its Clean Air Act permit from the Environmental Protection Agency. Earlier this week, it received approval from the NOAA National Marine Fisheries Service in accordance with the Marine Mammal Protection Act. Empire Wind 1 is currently bidding into New York’s fourth offshore wind solicitation.

In January, Equinor and BP decided to terminate the Empire Wind 2 project, citing inflation, interest rates, and supply chain disruptions. The Northeastern U.S. offshore project promised a potential generative capacity of 1,260 MW.

The project was already on the chopping block after the New York State Public Service Commission denied petitions filed by a group of developers and a state renewable energy trade association seeking billions of dollars in additional funding from consumers for four proposed offshore wind projects and 86 land-based renewable projects.

In October, developers who filed the petition, including subsidiaries of Orsted, Equinor, and BP, said that they were reviewing the Commission’s decision before reassessing their offshore projects, like Orsted’s 924 MW Sunrise Wind, Equinor/bp’s 816 MW Empire Wind 1, 1,260 MW Empire Wind 2 and 1,230 MW Beacon Wind.

Originally published by Renewable Energy World.

This funding — made possible by the Bipartisan Infrastructure Law — will support community-driven energy projects in rural and remote regions, such as building microgrids for health centers or constructing a new hydroelectric facility on Tribal lands. The announcement underscores the Biden-Harris Administration’s commitment to building an inclusive and equitable clean energy future that creates safer, more resilient communities, enhances Tribal energy sovereignty, strengthens energy security, and delivers new economic opportunities, according to a release.

“President Biden firmly believes that every community should benefit from the nation’s historic transition to a clean energy future, especially those in rural and remote areas,” said U.S. Secretary of Energy Jennifer M. Granholm. “DOE is helping revitalize communities across America — ensuring thriving businesses, reliable access to clean energy, and exciting new economic opportunities, now and for generations to come.”

In line with President Biden’s Justice40 Initiative to advance energy and environmental justice, all 17 projects are located in or adjacent to disadvantaged communities that are disproportionally overburdened by pollution and historically underserved. The projects are part of DOE’s Energy Improvements in Rural or Remote Areas (ERA) program, which is managed by the Office of Clean Energy Demonstrations (OCED). The ERA program leverages DOE’s expertise in resilient energy solutions while recognizing the unique environmental, cultural and economic landscapes of rural and remote communities. At least 12 projects will support Tribal communities.

Each ERA selectee is required to develop and implement a comprehensive Community Benefits Plan (CBP) — which will be informed by early and meaningful community engagements in each region. As part of the department’s commitment to transparency, OCED will hold a series of national and regional virtual briefings to provide information on the selected projects, OCED’s approach to clean energy demonstrations, and opportunities for community engagement.

Before funding is issued, DOE and the selectees will undergo a negotiation process, and DOE may cancel negotiations and rescind the selection for any reason during that time. Lead applicants also may change during the award negotiations process. If awarded, OCED will evaluate these projects through a phased approach to project management that includes “go/no-go” decision points between each phase.    

Below are details on the four hydroelectric projects chosen:

Chignik Hydroelectric Dam and Water Source Project in Chignik Bay, Alaska, will receive a federal cost share of $7,270,000. The lead applicant is The Lake and Peninsula Borough. This project involves constructing a new run-of-the-river hydroelectric facility, replacing a 70+ year-old wooden dam that is at risk of failure. It aims to improve energy and water security as the current dam leaks frequently, also jeopardizing the community’s only stable source of clean water. The proposed 2.1 MWh hydroelectric facility aims to replace 100% of the community’s diesel consumption. It also plans to provide excess power for heating, electric vehicle charging, and expansion of local economic activities like tourism and fish processing. The Chignik Bay Tribal Council will own the facility and plans to sell power to local utilities for 80% of the avoided cost of fuel, reducing total electricity rates by an estimated 7%.

Old Harbor Hydroelectric Project in Old Harbor, Alaska, will receive a federal cost share of $10,000,000. The lead applicant is the Alutiiq Tribe of Old Harbor. This project plans to construct a run-of-river hydroelectric facility with a diversion structure, pipeline, powerhouse and electric transmission line. It is anticipated that the project will be capable of generating about 3,470 MWh of energy annually and offset diesel fuel use at the local power plant by 95%. Old Harbor is a remote Alutiiq Tribal village on Kodiak Island, about 50 air miles from the nearest social services in the City of Kodiak. There are nearly 200 residents and 83% are Native Alaskans who rely on a subsistence diet. According to the Denali Commission, 88% of residents live below the federal poverty line, with a median household income of $13,181, and experience disproportionally higher cost energy bills.

Thayer Creek Hydroelectric Project in Angoon, Alaska, will receive a federal cost share of $26,920,000. The lead applicant is Kootznoowoo Inc. (KI). This project encompasses an 850-kW, run-of-river hydroelectric project that has the potential to supply three times the community’s electricity needs, providing additional power for heating, fish processing, electric vehicle charging and tourism. KI is the Alaska Native Village Corporation for the community of Angoon, the ancient home of the Tlingit Xóotsnoowe’di people, with a population of 357. In 1980, as part of the Alaska National Interest Lands Conservation Act (P.L. 96-487), KI and Angoon gave up rights to their ancestral land to establish the Admiralty Island National Monument. As compensation, KI was granted the right to develop Thayer Creek Hydroelectric. However, the initial agreement did not include funding, and the Tlingit people are still entirely reliant on imported diesel, which leads to energy costs that are 4.5 times the national average. This project aims to provide an avenue to address historical oversight and support access to reliable and affordable energy for the Tlingit people.

Yakama Tribal Solar Canal & Hydro Project on the Yakama Indian Reservation, Wash., will receive federal cost share of $32,000,000. The lead applicant is The Confederated Tribes and Bands of the Yakama Nation. This project aims to convert inefficient, open-water irrigation canals into a solar and micro-hydropower irrigation system. This system could conserve up to 20% more water and help energy-burdened residents save up to 15% on their utility bills. Additionally, the project team plans to build solar panels on land the Tribe knows does not risk disturbing cultural resources. It is anticipated that deploying solar technologies will increase the Yakama Nation’s renewable power supply, while improving its energy resilience and reliability. Improvements in irrigation efficiency could also benefit grazing and irrigated agriculture, the area’s key economic drivers.

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. 

Solar would account for the largest share of new capacity in 2024, at 58%. A record 36.4 GW are scheduled to join the grid this year, which would almost double the 18.4 GW increase in 2023.

More than half of the new utility-scale solar capacity is planned for Texas (35%), California (10%) and Florida (6%). Outside of these states, other notable projects include the Gemini solar facility in Nevada, which plans to begin operating in 2024. Gemini comprises 690 MW of solar PV installments and 380 MW of battery storage. It is expected to be the largest solar project in the United States when fully operational.

As the effects of supply chain challenges and trade restrictions ease, EIA expects solar to continue outpacing capacity additions from other generating resources.

EIA expects battery storage to set a record for annual capacity additions in 2024. The agency projects U.S. capacity to nearly double in 2024 as developers report plans to add 14.3 GW of battery storage to the existing 15.5 GW.

Texas (6.4 GW) and California (5.2 GW) are expected to account for 82% of the new U.S. battery storage capacity additions. Notable projects scheduled to come on line in 2024 include Menifee Power Bank (460 MW), which is being built at the site of the former Inland Empire Energy Center natural gas-fired power plant in Riverside, California.

With the rise of solar and wind capacity in the United States, EIA says the demand for battery storage continues to increase. The Inflation Reduction Act (IRA) has also accelerated the development of energy storage by introducing investment tax credits (ITCs) for stand-alone storage.

Another 8.2 GW of wind capacity is scheduled to come on line in 2024. Following the record additions of more than 14 GW in both 2020 and 2021, wind capacity additions have slowed in the last two years.

However, two large offshore wind plants are scheduled to come on line this year — the 800 MW Vineyard Wind 1 off the coast of Massachusetts and the 130 MW South Fork Wind off the coast of New York.

Simple cycle gas turbine additions to overtake combined cycle in 2024

Developers are reporting 2.5 GW in planned natural gas-fired capacity additions in 2024, according to EIA. This is the least new natural gas capacity in 25 years.

Notably, 79% of the new capacity planned for 2024 is to come plants with simple cycle gas turbines. This will be the first year since 2001 that combined-cycle capacity was not the predominant natural gas-fired technology. 

Simple cycle gas turbines provide effective grid support to balance renewables because they can start up, ramp up and ramp down relatively quickly.

The utility is seeking wind resources that are within the MISO Local Resource Zone 1 with direct interconnections to the transmission system and the ability to enter commercial production in 2026 or 2027.

Minnesota Power will consider both build-own-transfer and power purchase agreement projects, with a preference for projects between 100 and 200 MW in both categories. An independent third-party evaluator will help Minnesota Power screen and review proposals.

The procurement of wind through this RFP would increase Minnesota Power’s wind portfolio by nearly 50%; it currently has about 870 MW of owned and contracted capacity. The company currently delivers more than 50% renewable energy to its 150,000 retail customers.

This RFP follows Minnesota Power’s 2021 Integrated Resource Plan, approved by the Minnesota Public Utilities Commission, which calls for the company to acquire up to 300 MW of solar energy (which is being evaluated in a separate RFP) and 400 MW of wind generation.

“The carbon-free future must be sustainable for the climate, customers, and communities for everyone to thrive, so we seek projects that will create local jobs, local economic benefits and train people in renewable technologies,” said Minnesota Power COO Josh Skelton. “New wind generation in the Upper Midwest can tap into an excellent wind resource and maximize use of regional transmission assets to deliver renewable energy to our customers and fits well with our portfolio of other energy supply resources to reliably meet customer demands around the clock.”

Proposals will be accepted through April 11, 2024.

The joint funding opportunity between the United States and Denmark aims to advance the global floating offshore wind industry by encouraging collaboration and increasing the impact of research and development in each country.

This proposed funding opportunity will focus on research to improve mooring technologies and methods, which are used to secure floating platforms to the sea floor.

WETO and Innovation Fund Denmark will each contribute approximately $2 million and performing teams must include both U.S. and Danish entities collaborating on each awarded project.

“About two-thirds of U.S. offshore wind energy potential exists over waters too deep for today’s fixed-bottom wind turbine foundations, and instead require floating platforms. This partnership between DOE and Innovation Fund Denmark will advance floating offshore wind R&D to further each nation’s respective climate goals. This effort supports the Floating Offshore Wind Shot, a target to reduce the cost of floating offshore wind in the U.S. 70% by 2035,” said DOE Under Secretary for Science & Innovation Geri Richmond.

“The climate challenge cannot be solved by one good idea or one company—or in one country. It requires many new initiatives and collaborations in different areas that point in the same direction,” said Innovation Fund Denmark chairperson Anders Eldrup.

DOE and Innovation Fund Denmark are seeking proposals addressing five topic areas:

• Compatibility strategies for mooring, cabling, and coexistence
• Mass-producible, high-reliability moorings
• Novel station-keeping systems and components
• Monitoring and inspection technologies for moorings
• Open Topic: Research and development that more broadly support mooring systems for industry-scale deployment of floating offshore wind energy.

This opportunity is expected to be released this spring.

The announcement builds on a previous collaboration between DOE, the Denmark Ministry of Higher Education and Science, the Denmark Ministry of Climate, Energy and Utilities, and Innovation Fund Denmark signed in 2021.

Originally published by Power Engineering International.