EDP Renewables is expanding its presence within the Latin American and global clean energy market with two separate deals reached with Atacama Energy and Lader Energy in Chile.
The two deals have a total consideration of $38 million for the acquisition of 628 MW of solar and wind energy projects in Chile.
Commenting on the development, Miguel Stilwell de Andrade, the CEO of EDP Renewables, said: “We are committed to playing an active role in the energy transition and in the Latin American markets, where Chile offers world-class renewable energy generation potential. The entry into this market confirms the importance of the region for EDPR’s ambitious international growth strategy. This move reinforces our global leadership and we are confident of Chile’s growth potential for the renewable energy sector.”
The acquisition marks the presence of EDP Renewables in 16 international markets and the company’s 21st country of operation. Today, EDP Renewables touts to be the fourth largest producer of renewable energy globally.
The acquired 628 MW are expected to be operational between 2023 and 2025. They comprise a 77-MW wind farm which has a 20-year power purchase agreement and set for operation in 2023 and 551 MW of solar and wind farms, which are currently under development. The solar and wind projects under development are expected to be live by 2025 to participate in upcoming regulated tenders and private power purchase deals.
EDP Renewables plans to further strengthen its footprint in Latin America by pursuing green hydrogen opportunities. The company currently owns 400 MW of renewable energy projects in operation in the region, as well as 1.1 GW and 500 MW of secured capacity in Brazil and Colombia, respectively.Energy transition in Chile
EDP Renewables is hoping that its entry into Chile will help accelerate the energy transition in the country through increased deployment of green projects. Although Chile has massive potential for renewable energy generation, today the country is still heavily reliant on thermal power generation which is accounting for 50% of the country’s total energy mix.
However, the country’s regulation is supporting increased adoption of renewables evidenced by announced tenders and an increasingly growing portfolio of private power purchase deals.
Chile plans to expand the share of renewables excluding hydro within its energy mix to 20% by 2025 and 70% by 2050.
A partial solar eclipse last Thursday was expected to reduce solar energy production for a time. It underlines the importance of photovoltaic operators and utilities having backups, whether in the form of energy storage or alternative ways of getting energy to customers during an outage.
According to Astronomy, last week’s annular, or ring-shaped eclipse, was caused by the Earth, Moon and Sun getting in a straight line relative to each other. The Moon would be too far from Earth for a total eclipse, but would block out about 92 percent of the Sun. The eclipse lasted for five hours, starting at 4:12 am EDT June 10. The area most affected by the eclipse was sparsely populated parts of northern Canada and Greenland and eastern Russia, according to NASA, but people in other parts of the northern hemisphere were still able watch.
German grid operator Amprion warned that the celestial event would cause a drop in solar power output of about one gigawatt, Reuters reported. Under peak conditions Germany can produce 40 GW of solar power, so the eclipse loss is significant. However, it only lasted about two hours.
Previous eclipses strained solar power systems in the past. A partial eclipse in March of 2015 reduced output by 15 GW in Germany, according to Reuters, and a 2017 total eclipse in the United States reduced output at utility-scale PV installations across the country, according to the United States Energy Information Administration. Despite not being where the eclipse was at its most intense, California experienced a drop of four GW from its 8.8 GW capacity. An upcoming paper by researchers in India found that eclipses reduced output by 37 percent versus an ordinary sunny day.
Although solar eclipses can be predicted years in advance, the drops in production they cause — as well as reductions from other, unpredictable sources, such as dense cloud cover or extreme weather events like hurricanes or extreme cold — make securing storage and alternatives important for grid operators.
Storage solutions for solar energy are varied, but lithium-ion batteries similar to those used in electronics and electric vehicles are the most popular, according to the Solar Energy Industries Association. Battery prices of these systems dropped recently because growing demand is leading to production increases. The SEIA reported that 34 percent of future PV installations will include energy storage systems.
Even subtracting the need for reserves when production drops, utilities should encourage producers to invest in storage, or invest in storage capacity themselves, in order to maintain an even price for electricity throughout the day. Peak solar production usually occurs around noon, while peak demand is in the late afternoon. This can be important for when residential systems are feeding the grid during the day, but in the evenings and nights, they may need power back. The utility could share out the cost of storage for many residential solar installations, allowing it to store power both for customers during peak demand and in the event of an unforeseen drop in output. Such an arrangement would also reduce the cost of installing solar panels by the homeowner, potentially spurring more to do so.
Other forms of storage include pumped hydropower, thermal and flywheel, according to the United States Department of Energy. However, these are less efficient and more limited in storage capacity than batteries, so they may be more expensive and only suitable for certain niche operations.
The other way utilities can protect themselves from outages is by purchasing power from non-solar producers, however, this can cut into decarbonizing efforts, depending on available sources, so offsets may be needed.
Efficiency Maine last week announced seven awards to place new high-speed electric vehicle (EV) chargers at strategic locations on Interstate 95 to serve communities in central and eastern Maine.
With these additions, Maine’s universally accessible, high-speed EV charger network will connect Bangor, mid-coast Maine, and Acadia to drivers traveling to and from southern New England and the State’s western border.
Installation of high-speed EV chargers at these locations will fully commit the balance of the $3.15 million in Volkswagen (VW) settlement funds that Maine dedicated to EV infrastructure. In 2018, the Maine Department of Transportation selected Efficiency Maine to administer the EV infrastructure initiative with the settlement funds resulting from a successful lawsuit against VW for violation of environmental protection laws. Further expansion of the high-speed network, including to Northern Maine and further Downeast, is planned over the next several years.
Under the terms of the awards, two high-speed chargers, each at least 50 kW in capacity and universally accessible (offering both CHAdeMO and CCS plugs), will be installed over the next year at each of the following supermarkets and gas stations in the state.
“Over the last three years, Efficiency Maine has used Volkswagen settlement funds to install electric vehicle chargers in communities across Maine, expanding cleaner transportation options for Maine people, reducing greenhouse gas emissions, and fighting climate change,” said Governor Janet Mills.
“As electric vehicles become more common, Maine must continue to expand its charging network, which is why I am proposing $8 million through the Maine Jobs & Recovery Plan for EV charging infrastructure. By making it easier to charge an EV anywhere in Maine, we will strengthen our economy and reduce harmful carbon emissions. I applaud Efficiency Maine for reaching this milestone and for its many contributions toward energy efficiency and climate action in Maine.”
“It’s significant that we were able to attract these high quality, well-trafficked locations within 30 miles of other fast chargers, and that some of the major gas stations are diversifying their business strategies by adding EV charging,” said Michael Stoddard, executive director of the Efficiency Maine Trust. “When we get gas stations and grocery stores playing host to EV chargers, we know that the sites are strategically located, the owners know how to cater to drivers, and the transition to electric is getting serious.”
This initiative has been developed by Efficiency Maine in collaboration with the governor’s office and the Maine Department of Transportation to align on the state’s progress toward EV adoption.
In addition to installing these publicly accessible fast chargers, Efficiency Maine also is supporting the expansion of lower-cost, public Level 2 chargers in other strategic locations across the state. Level 2 chargers are most commonly installed in homes, as well as at workplaces and public spaces. These units can provide between 14 and 35 miles of range per hour and are often used when a car can be left plugged in for longer periods of time. All Level 2 chargers have a universal “J” plug and connect to all electric vehicle models.
Adding publicly available Level 2 chargers improves local access and destination charging across the state. These charger plugs serve commuters, local drivers, business people driving to and from meetings and appointments, and overnight guests. To date, Efficiency Maine has helped fund more than 140 new level 2 plugs in Maine’s public EV charging network, which has now grown to a total of 120 DC high-speed charging plugs and 375 Level 2 “community” plugs.
GE Renewable Energy and LafargeHolcim have signed a memorandum of understanding (MoU) to explore circular economy solutions using materials from decommissioned wind turbines.
The companies are exploring new ways of recycling wind blades, as well as how wind turbine blades can be turned into sustainable construction materials to build new wind farms.
This research builds on LafargeHolcim’s work, under its Geocycle brand, to recover energy from GE’s decommissioned turbine blades after they have been removed from the turbine and shredded. Geocycle offers co-processing solutions for wind blades in Germany and will evaluate the possibility of extending this solution to other parts of Europe.
“This is a truly exciting next step in our journey to introduce new circular lifecycle improvements for the wind industry,” said Jérôme Pécresse, chief executive officer of GE Renewable Energy. “We are delighted to work with LafargeHolcim on these critical projects, which will help to improve the sustainability of wind power now and well into the future.”
This next phase of collaboration between these two companies follows the 2020 announcement to co-develop wind turbine towers at record heights using concrete three-dimensional printing together with COBOD, the Danish 3D printing start-up.
“With sustainability at the core of our strategy, accelerating renewable energy and the circular economy are top priorities for our business. I’m very excited about this collaboration with GE Renewable Energy because it meets both goals at once,” said Edelio Bermejo, head of LafargeHolcim’s Global Innovation Center.
This announcement is the next step in both partners’ focus on circular solutions. The European Commission has adopted a new Circular Economy Action Plan, one of the main blocks of the European Green Deal, and nearly 10 GW of ageing turbines in Europe are expected to be repowered or decommissioned by 2025, according to GE.
The New York Power Authority (NYPA) announced this week that it will launch a project with the Electric Power Research Institute (EPRI) to explore the use of crushed rock thermal energy storage to provide reliable and effective energy storage in a market with significant renewable energy resources. The project will be led by EPRI and funded by a $200,000 U.S. Department of Energy (DOE) grant. It will investigate the feasibility of a thermal energy storage (TES) technology developed by Brenmiller Energy, an Israeli developer and manufacturer of thermal energy storage systems. If determined to be feasible, the investigation team will pilot the technology and evaluate its ability to provide effective and economical energy storage at NYPA’s Eugene W. Zeltmann Power Project in Astoria.
In addition to the DOE’s funding, the project participants will contribute another $50,000.
“Investing in research and development to improve energy storage is critical at this moment in time,” said Neva Espinoza, EPRI vice president of Energy Supply and Low-Carbon Resources. “Innovations in energy storage will contribute to a grid that is both reliable and resilient. This is essential to reaching a cleaner energy future, and we look forward to working with NYPA on this feasibility study.”
“Integrating energy storage is key if we want to make the most of the increasing use of renewable energy resources such as solar and wind,” said Alan Ettlinger, NYPA’s senior director of Research, Technology Development and Innovation. “This collaboration with EPRI could potentially perfect an environmentally friendly solution that would provide large-scale, longer-duration energy storage that would ultimately help renewable energy compete with fossil fuels.”
This new storage technology holds potential to help transition New York State from fossil fuels to at least 70 percent renewable electricity by 2030, which is part of the state’s Vision2030 strategic plan. Part of NYPA’s Vision 2030 strategy includes investigating in potential low- to zero-carbon technologies at several of its facilities to transition from fossil fuel and stabilize the grid as it integrates cleaner energy sources.
Brenmiller, has patented a high-temperature crushed-rock TES system, which is being tested in three generations of demonstration units at separate sites globally. As with other energy storage technologies, the system stores excess energy, in this case thermal energy, so it can be used later during peak demand periods.
The first phase of the NYPA project will be a feasibility study on the integration of the crushed-rock thermal energy storage into a range of fossil generation assets, which is expected to be complete in early 2022. A project plan will then be developed for a second phase to evaluate real world operating conditions and demonstrate the technology’s ability to provide effective and economical energy storage at a natural gas combined cycle plant.
The plan will evaluate the cost and performance of Brenmiller’s TES technology, to support commercial-scale deployment by 2030. United E&C, an engineering and construction firm, is supporting the project through a techno-economic study.
NYPA is also partnering with Brenmiller on a separate project to develop and demonstrate a TES-based combined heat and power (CHP) system at Purchase College (State University of New York) in Harrison, NY, to increase energy efficiency and reduce greenhouse gas emissions. That unit is expected to be operational later in the summer of 2021.
by Alison Wiley
The electric bus world is growing rapidly, with more purchase orders being placed for them weekly, massive federal funding for them being proposed, and Lion’s announcement of going public and building a huge e-bus manufacturing plant in Illinois with capacity to produce 20,000 electric school buses per year.
If you are working to keep up in this complex field, and also to learn to be an anti-racist ally, so am I. If only one of those describes you, I hope you keep reading regardless! Bus passengers are disproportionately people of color. They get the sickest from diesel exhaust while having the least access to health care. As a white person, I’ve learned I tend to center myself and my privileges unconsciously. I can do better. Other white leaders in this field have expressed similar determination. Some of you have been following my personal anti-racism project that last week reached a joyful result; if you’d like to know about that, just reply to this email.
I am Alison Wiley here in Oregon, writing this newsletter (archives here) primarily for bus fleets, though people from government, nonprofits, consulting firms and the clean tech industry read it as well. Why do I do this? I love buses, the people who ride and operate them, and our shared climate. And because e-buses improve the health of all the above. Most bus fleets are new to electric, and my aim is to support those fleets in moving forward.
My last article named the first five things that I suggest bus fleets need in order to start electrifying. Completing that list:
6.) Solid education/exposure to electric buses and charging infrastructure. I estimate that less than 7% of the United States’ 13,500 school districts and a slightly larger percentage of the nation’s public transit agencies have received solid education at this point (public transit started electrifying about seven years earlier than pupil transportation). Glancing exposure to e-buses at conferences is what most bus fleets have available to them so far. Working to address this need, the Electric Bus Learning Project* I lead here in Oregon with Neil Baunsgard just partnered with Lion Electric on a week-long series of hands-on Ride and Drive events (see photo below).Oregon’s first ever Electric School Bus Tour last week reached ten school districts and about 150 people in rural, urban and suburban areas, including a Public Utility Commissioner. Malinda Sandhu, left, Director of Business Development for Lion Electric, is describing the Lion Type C electric bus to staff at Redmond School District.
7.) A relationship with your bus fleet’s utility. When you get your first electric bus, your fleet’s electric utility suddenly becomes a fuel source. But a year ahead of your e-bus’s arrival you should know if you have enough amps to fuel it. Funding applications will pose that question. Start chatting with your utility today if you haven’t already. Have them visit your bus yard. They love advance notice of changes (who doesn’t? see Inclusiveness below). Have a designated person build your fleet’s relationship with your utility. Charging infrastructure is the hardest part of electrifying, and the easiest part to avoid since the buses, even with their novel electric drivetrains, feel more familiar than charging units that will be about the size and shape of refrigerators in your bus yard. Why are you still reading this and not talking with the Electrification Planner from your utility?!
8.) Local support for electric buses. This could be grassroots support, as from Chispa or a passionate middle-school science student like Holly Thorpe in Florida, who convinced her district to get its first e-bus. Or local support could come from leaders, i.e., mayor, county commissioner, District Superintendent or Chief Financial Officer. Funding agencies usually expect letters of support. If the bus fleet’s Transportation Director or General Manager or Fleet Manager does not yet want to get their first electric bus, that is a major barrier. Find out their objections and what they need to feel supported. They are correct that electrifying is a disruption to their existing operations, and that it will make their jobs harder. It may also make their jobs more interesting and rewarding. Which leads to the following.
9.) Inclusiveness. Change is hard. The people impacted by the changes that e-buses bring need to be included from the beginning. I’m thinking, for example, of bus drivers and mechanics, many of whom checked out the e-bus on our tour last week. Some were skeptical at first, then more positive after driving it. “It’s so quiet!” Note that driver skill extends your e-bus’s range, and lack of skill (like a heavy brake-foot that blocks regenerative braking) shaves miles off the bus’s range, leading to loss of promised savings on fuel. Skill level is connected to motivation. Being included increases motivation, which then improves skill.
10.) Funding. I put this last because funding is crucial, but not sufficient for success. You could land your funding for your pilot project and then have it fail for lack of planning and education, as happened in Massachusetts in 2016 (I’m told the bus is running now, but still, it was an early black eye). Utilities and Volkswagen mitigation funds are the prime funding sources for electric school buses.
In Oregon, Volkswagen funds are opening up for electric school buses June 30, closing date for applications August 31. My Electric Bus Learning Project will offer at least one training to prepare bus fleets to apply. Background: electric school buses cost 3x or more their diesel equivalents, and electric public transit buses about 50% more. Fuel and maintenance savings may mean that total cost of ownership compensates for the higher purchase price. The more you drive your e-bus, the more savings you generate from it.
I know I said ten things, but I lied.
11.) Fleet transition plan to scale up beyond the onesie-twosie nature of pilots. We’ve got to think big, as the World Resources Institute is helping us do with its initiative (more on this in future newsletters). Some bus fleets, such as Corvallis Transit System, develop transition plans even before receiving their first electric bus. They hired Center for Transportation and the Environment (CTE) to do this. CTE is also part of my Electric Bus Learning Project team.
Finally, this list is incomplete! You surely know things I don’t. Feel free to reply and tell me what else bus fleets need in order to electrify.
*The Electric Bus Learning Project receives funding from the Oregon Clean Fuels Program and Pacific Power.About the Author:
I’m Alison Wiley here in Portland Oregon, on an advocacy mission of electric school buses, equity and inclusion. I’ve been in the transportation field since 2006, specializing in electric buses since 2016. I’m a writer, relationship-builder and advocate, creating the newsletters on this website as a public service. Why?
Find me running the forested hills of Mt Tabor, practicing hospitality with my husband Thor Hinckley and serving on the leadership team of EcoFaith Recovery, which blends faith with activism. Visit my website to find how to contact me.
SMC Global Power Holdings Corp. (SMC), a major supplier of power to the national grid in the Philippines, has partnered with ABB to install battery energy storage systems (BESS) as part of its BESS Project.
In countries such as the Philippines, several challenges negatively impact grid performance, such as the length of power lines required to connect the diverse archipelago, as well as intermittent energy supply from wind and solar, which needs storage to act as a frequency regulator. The BESS solution, the largest of its kind in the region according to ABB, is designed to avoid large frequency deviations, which can result in costly equipment damage and disruptive power system failure.
Not only will the system increase grid reliability, it will also support the Philippines’ ambitious plans to decarbonize energy generation, ensuring that 54% of its energy mix comes from renewables by 2040.
“Battery energy storage systems are transforming the market, driving wider adoption of renewable energy solutions, and helping to improve grid performance across the globe,” said Alessandro Palin, president of ABB’s Distribution Solutions Division. “In support of ABB’s 2030 sustainability commitments, pioneering solutions like the one in the Philippines will ensure that grids are more stable and will satisfy the reliability challenges associated with moving to a stronger mix of renewables.”
The contract with ABB, won in 2019, will support two 20-MW sites and a further 40-MW site, to be commissioned in 2021. The remaining sites will be commissioned in 2022.
One system will support the local grid on Luzon, the largest and most populous island in the archipelago, as well as the island of Visayas. Both these fast-developing regions will benefit from BESS as part of the government’s “Build, build, build” program that aims to establish a “golden age of infrastructure” to boost industry and tourism.
The Philippines project uses ABB’s proprietary software platform ABB Ability Zenon to act as the intuitive interface to the BESS, allowing users to make real-time decisions based on grid parameters to ensure performance stability.
The scalable and modular building block design includes an integrated combination of energy storage modules and power distribution equipment, that can be increased or reduced in capacity to suit specific site location requirements.
The BESS includes the provision of battery enclosures, ABB EcoFlex eHouse, UniGear ZS1 medium-voltage switchgear, integrated skid units, transformers and inverters in one single skid, with a connection to the grid.
By Robert MacDonald, Smarter Grid Solutions
As individual states across the U.S. work towards increasingly ambitious net zero emissions targets, the logistics of how these targets can be achieved and where investment should be made is at the forefront of decision-makers’ minds. To date, considerable efforts have been made to look at solutions that implement more renewables and clean energy into a modern and sustainable electricity system – and electric vehicles (EVs) have an important role to play.
EV adoption has been accelerating in the United States – by 2030 an estimated 18.7 million EVs will be on U.S. roads, up from 2 million in 2020. An increasing portion of EVs will be composed of full battery electric vehicles (BEVs), leading to significant increases in electricity consumption – estimated to grow from 6 to 53 billion kilowatt-hours (kWh) per year by 2030. At the same time, EV charging infrastructure remains limited, with an estimated 9.6 million EV charging stations needed to meet the growing demand.
The slow rollout of EV charging infrastructure can be attributed to a combination of investment certainty, finance and incentives but also physical system limits around today’s grid infrastructure and a lack of interoperable technologies to understand and manage charging. Today’s electrical grid has limited capacity to supply significant new EV charging demand without requiring extensive equipment upgrades, such as power transformers and circuits.
Paradoxically, existing grid infrastructure experiences overall low utilization rates, or load factor, from EV charging due to short-duration, high-demand usage patterns. For EV supply equipment (EVSE) developers, EV consumers, and utility customers the potential over-build and underutilization of grid assets can result in high costs that prevent or delay expansion of charging infrastructure.
Managed EV charging could address both these issues.
Three essential elements are needed to allow the rapid build-out of EV charging infrastructure:
Meeting the Challenge
Distributed energy resource management system (DERMS) software can help accelerate the build-out of EV charging infrastructure, by enabling managed charging solutions.
A DERMS platform acts as the central coordinating entity that manages, automates, and optimizes EV charging across the grid. To start, DERMS enables end-to-end connectivity between the operator and the EVSEs by communicating with private charging network operators as well as disparate, stand-alone EVSE installations. Not only must DERMS have the flexibility to interface through various telecommunications pathways – such as broadband, cellular or private networks and proprietary or standard communications interfaces — they must also manage many different monitoring and control signals in order to aggregate EVSEs into potential demand reduction resources.
Once EVSEs are linked, DERMS can be used to implement a variety of intelligent charging programs across the entire connected fleet. These include basic programs such as scheduled charging (e.g. target charging from 12am to 6am), shared charging (e.g. demand shared across multiple charging stations), and coordinated charging (e.g. charging during periods of excess on-site solar production). But they also entail more sophisticated programs which employ elements of forecasting and optimization, such as real-time management against grid constraints or price signals.
A managed EV charging strategy using DERMS can bring significant benefits for grid infrastructure. DERMS can be integrated with operational systems such as Energy Management Systems (EMS), Distribution Management Systems (DMS), and utility SCADA to obtain real-time grid telemetry, identify potential grid constraints, and take actions to manage EV charging levels. A properly implemented DERMS system should be able to monitor EV charging demand, calculate potential for demand reduction, and coordinate the reduction in line with the grid’s physical limits.
At the same time, DERMS can also manage the complexities of coordinating and dispatching a large number of EVSE with different control points; this may involve requesting demand reduction of a fleet of EVSE from a charging network operator, directly controlling individual EVSEs, or a combination of the two. Grid operators at distribution and transmission levels with increased visibility and control of EV charging will allow for expanded grid hosting capacity for new charging stations, increased utilization of existing grid infrastructure, and minimized grid upgrade costs – all while maintaining system safety and reliability. This creates benefits for EVSE developers in more grid hosting capacity and quicker interconnections, at lower cost.
For the broader energy system, DERMS can be integrated to manage reduction in demand and utilize market pricing signals to coordinate optimal EV charging times. The benefits include supply/demand alignment, reduced resource requirements, and lower energy prices. As the system incorporates more renewable generation, DERMS can also incorporate weather forecasts that anticipate times of high renewables availability in coordination with EV charging needs, providing benefits of lower charging costs while maximizing the use of low carbon electricity.
A well-coordinated EV charging strategy ultimately benefits EV consumers through lower charging costs, accelerated deployment of EV charging stations, and increased environmental benefits enabled by DERMS technology.
Making EVs mainstream
If governments are to achieve net zero targets, investment in EVs is critical. While progress has been made to encourage the uptake of EVs, more can still be done.
To create a sustainable EV charging infrastructure, increasingly intelligent operational systems such as DERMS must be put in place that are flexible and adaptable to the needs of the fleet operators, grid operators and EV users. By implementing managed charging solutions, not only will EVSE operators be able to collect valuable data to inform future solutions, but by pairing this with renewables, they can create new flexible tariffs and implement a variety of new incentives. In turn, this will boost the market and make EVs and the necessary smart charging infrastructure a more attractive investment.About the Author Picture Copyright Chris Watt.
Robert MacDonald is the global lead for the Planning and Analysis practice at Smarter Grid Solutions.
Work is under way at Glacier Bay National Park and Preserve in Alaska to tie into a hydropower network to provide renewable power to the headquarters complex.
More than 20 years in the making, this project – known as the intertie – will connect the park’s existing power system with the 800-kW Falls Creek Hydroelectric Project, which powers much of the southeast Alaska community of Gustavus. This effort is a public-private renewable energy partnership between the National Park Service and Alaska Power and Telephone. Sharing an interconnected grid will provide power reliability and redundancy for both the park and Gustavus.
The park is powered by diesel-fired generators located in a central powerhouse in Bartlett Cove. Access to clean, renewable power will eliminate the need to ship more than 38,000 gallons of diesel fuel annually through the sensitive marine environment of southeast Alaska. The project will also reduce the park’s greenhouse gas emissions by an estimated 600 tons of carbon dioxide per year. Carbon dioxide emissions generated by human activity are a primary driver of global climate change, which is significantly impacting park resources, including its glaciers.
The intertie project requires laying buried electrical line and fiber optic cable from the park’s “Depot” and recycling area about 8.5 miles to the Falls Creek plant following a route along existing roadways. Trenching outside the park will take place within the State of Alaska’s Department of Transportation right-of-way. The trench will typically be 18 to 24 inches wide and 4 feet deep and situated 6 to 10 feet from the road pavement edge.
This renewable energy partnership between the park and AP&T has its roots in a 1998 land exchange that made way for a run-of-river hydro system installed at Falls Creek, a stream flowing out of the Chilkat Range. Operating since 2009, the Falls Creek Hydroelectric Project eliminates the need to import an estimated 300,000 gallons of diesel fuel annually to Gustavus.
A 2013 feasibility study conducted by the NPS — followed by additional studies and stakeholder engagement, including with city officials and Gustavus community members — determined that integrating existing park electrical facilities with the community electrical grid would be positive for the park and community. In addition to the environmental benefits, the project will reduce infrastructure costs and is expected to result in lower power rates for the community.
The intertie will be owned, operated and maintained under a contract between the park and AP&T, which will also maintain the park’s generators to work along with existing AP&T generators in Gustavus for use as backup in case of drought or emergency. The fiber optic cable laid with the power cable will allow AP&T to monitor and control connections with the park. The construction contract and related maintenance agreement are being managed by the Denver Service Center, the central planning, design and construction management office for the NPS.
The intertie connection is expected to be complete by Dec. 31, 2021.
Two new Michigan solar projects are now operational and delivering up to 40 MW of carbon free power to the region.
National Grid Renewables announced work was completed at Bingham Solar and Temperance Solar, both part of the company’s MiSolar Portfolio. National Grid Renewables owns both projects, which will generate under power purchase agreements with utility Consumers Energy.
The developer kept the construction work as local as possible. Michigan-based contractor J. Ranck Electric handled engineering, procurement and construction duties, employing about 160 workers, most of which came from within 100 miles of each site.
“Our company has a long history in Michigan, and we are proud to support the state and local economies through the creation of new tax revenue and jobs that result from these projects,” stated David Reamer, Head of Development, US Onshore Renewables for National Grid Renewables. “Thank you to the residents of Clinton and Monroe Counties for welcoming us into your communities.”
Subcontractors included Michigan-based The Hydaker-Wheatlake Company, based out of Reed City.
“The Hydaker-Wheatlake Company was proud to help construct the MiSolar Portfolio,” stated Neil Wallerstrom, General Foreman, The Hydaker-Wheatlake Company. “Solar projects like the MiSolar Portfolio provide economic benefits for Michigan residents at the local and state level. Throughout the construction process of both project substations, we were able to hire Michigan residents and were pleased to support local hardware stores, hotels, and restaurants.”
Now operational, three full-time operations and maintenance staff work at the MiSolar project sites. During the first 20 years of operation, MiSolar is projected to further benefit the community through the creation of approximately $6 million in new tax revenue, based on current Michigan law.
Throughout that same time period, using the United States Environmental Protection Agency’s (EPA) greenhouse gas equivalencies calculator, the combined projects are estimated to offset carbon dioxide emissions by more than 50,000 metric tons annually.
Michigan-based Consumers Energy is accelerating the electric vehicle (EV) transformation with a new program to help businesses statewide transition to carbon-free EVs. The utility’s PowerMIFleet program will focus on Michigan businesses, offering expertise and $3 million in rebates for charging locations throughout the state.
“Michigan was the birthplace of the American auto industry. Now, we are the center of the industry’s clean energy revolution,” said Lauren Youngdahl Snyder, Consumers Energy’s vice president for customer experience. “With PowerMIFleet, we at Consumers Energy are taking our success with EVs to the next level, making it easier for other businesses to join us on this Clean Energy journey.”
Through PowerMIFleet, Consumers Energy will provide expertise and consultation services to Michigan businesses, governments and school systems that are looking to electrify their vehicle fleets and charge overnight through cost-saving use rates. Consumers Energy is launching PowerMIFleet to build on its existing EV program, PowerMIDrive, which makes EV cost savings simple by providing time of use rates for EV drivers, and more than 800 rebates for home, business and public charging stations in the last two years.
“Consumers Energy will connect Michigan businesses, local governments and school bus fleets with the planning resources, expert guidance and financial incentives to easily and cost-effectively transition to electric vehicles,” Youngdahl Snyder said.
Through all of Consumers Energy’s vehicle programs, Michigan’s largest energy provider plans to help power 200 fast charging locations, along with more than 2,000 chargers at homes and businesses, over the next three years in Michigan.
Those vehicles will be powered by an electric grid that is moving toward being carbon neutral. Consumers Energy’s Clean Energy Plan calls for eliminating coal, eliminating energy waste and adding more renewable energy sources.
Consumers Energy, Michigan’s largest energy provider, is the principal subsidiary of CMS Energy, providing natural gas and/or electricity to 6.8 million of the state’s 10 million residents in all 68 Lower Peninsula counties.
Florida Power & Light Co. (FPL) achieved a major milestone by surpassing 40% completion of its “30-by-30” plan to install 30 million solar panels by 2030. To date, FPL has installed more than 12 million solar panels in Florida, putting the company well on its way to achieving its “30-by-30” plan. FPL says this is one of the largest solar expansions in the U.S.
By the end of this month, FPL is on track to have 42 solar energy centers in Florida, including its Discovery Solar Energy Center at Kennedy Space Center, which just became operational. The solar panels installed across the company’s sites are expected to save customers about $421 million over the lifetime of the assets, while making Florida third in the nation for solar generation, with a trajectory to be a world leader in solar capacity by the end of the decade, according to FPL.
“Reaching this milestone is an important step in our commitment to increase zero-emissions energy as FPL builds a more resilient and sustainable energy future all of us can depend on, including future generations,” said Eric Silagy, FPL’s president and chief executive officer. “Despite the pandemic, our team has stayed laser-focused on executing our ’30-by-30′ plan. Eight new solar energy centers have begun powering customers with clean energy so far this year, and three more are scheduled to come online before the end of this year.
“Nobody in the country is building more solar than FPL,” Silagy continued. “We’re dedicated to providing our customers with clean, affordable and reliable energy, while keeping bills among the nation’s lowest – and our rapid solar expansion helps us consistently deliver on this promise.”
By the end of this month, the company will have more than 3,000 MW of solar capacity in operation, which, according to FPL, is more than any other utility in the U.S. Nearly every solar energy center that becomes operational in 2021 will also support FPL SolarTogether™ – the company’s community solar program, which is the nation’s largest.
By the end of 2030, FPL plans to have more than 11,700 MW of universal solar capacity. To support its solar buildout, the company recently began installing the first components of the world’s largest integrated solar-powered battery system, the 400-MW FPL Manatee Energy Storage Center. In addition, later this month, the company will demolish its last coal-fired plant in Florida, with plans to replace it with more clean, emissions-free solar energy power facilities.
“Since FPL first pioneered large-scale solar development in 2009, our industry has seen a transformation of what was once considered niche technology to solar becoming a dominant source of energy,” Silagy said. “Solar helps us reliably power our millions of customers, fuels our economy with jobs and benefits our environment.”
NextEra Energy Inc., FPL’s parent company, is the world’s largest generator of renewable energy from the wind and sun and a world leader in battery storage.
Last week, RWE Renewables said it has started commercial operation on its 250-MW onshore Scioto Ridge Wind Farm, located in Hardin and Logan Counties in Ohio.
The project uses 75 Siemens Gamesa turbines and represents RWE’s first wind project in Ohio.
“The ongoing transition to lower carbon technologies and a more diverse energy portfolio represents a significant economic development opportunity for our state,” said Stephanie Kromer, Director of Energy and Environmental Policy at the Ohio Chamber of Commerce. “We are excited for RWE’s successful completion of their first Ohio-based project of over $300 million and look forward to their continued cooperation.”
Ohio has enormous potential for future projects, as wind power provides less than two percent of the total electricity generation in the state. In addition Ohio has a long history of industrial manufacturing, including approximately 52 wind-related factories — the most of any single state in the U.S., according to RWE.
The U.S. accounts for more than one third of the RWE Group’s renewables capacity playing a key role in the company’s strategy to grow its renewables business and get to net zero by 2040. RWE constructs, owns and operates wind, solar and energy storage projects in the U.S.
In related news, RWE said it recently entered into a joint venture, New England Aqua Ventus, focused on floating offshore wind in the state of Maine.
Silvia Ortin, COO Onshore Wind and Solar PV Americas, RWE Renewables: “Scioto Ridge marks our successful entry in the Ohio market. The state’s location in the heartland of the U.S. offers ideal conditions for renewable energy and we are happy to bring this project online as part of our focus on the U.S. market.”
“We’re proud to be a member of the local community, contributing more than $75 million in new payments over the next 25 years to the local governments, school districts and landowners,” added Ortin. “We created approximately 250 construction jobs and will hire up to 10 full-time, long-term operations and maintenance people who will live and work in the area.”
Enel Green Power has published an article noting the use of 3D printing in their flagship Geyser project at Santa Barbara metallurgy labs in Cavriglia, Italy.
The idea to use 3D printing to repair essential components was spawned at a roundtable discussion organized by the project Geyser team. A group of technicians and experts from the geothermal, thermal and hydroelectric sectors gathered to discuss how to optimize the management of geothermal plants.
“It all started from our curiosity and desire to use the 3D printer that we had in-house,” says Nicoletta Mazzuca, Enel Green Power’s project manager for Geyser. “We wanted to repair parts that were going to end up in landfills because they couldn’t be fixed with conventional forging techniques.”
The 3D printing machine is located in the Santa Barbara labs, at the headquarters of Engineering and Technical Support for Enel Production, where an additive manufacturing machine with laser metal deposition (or direct energy deposition) technology has been available since 2019. This tool can reproduce and repair various metal parts by depositing the necessary material one layer at a time.
The pilot project began when the printer was used to repair an impeller, which is an essential component of the centrifugal compressor of a geothermal plant.
The team purchased a powdered form of the material used to make the impellers (a type of stainless steel called 17-4 PH), followed by laser scans and the creation of the 3D model. The work concluded with the first historic repair of a worn part using this technology.
According to Enel, this sustainable innovation will make it possible to set in motion a cycle of reuse of materials: until now, worn impellers were replaced with new ones and ended up in landfills, so repairing them will also save about €70,000 ($85,000) per year.
“After a year of work, we were able to use additive manufacturing processes to repair our impellers for the first time. Not only does it give our impellers a second life, it also saves us money while respecting the environment thanks to a circularity of 100%,” added Mazzuca.
Matteo Niccolai, workshop maintenance and technical services leader – O&M Geo Italy of Enel Green Power said: “The idea of using additive manufacturing to solve one of Geo’s supply chain issues is a concrete example of the effectiveness of sharing problems and best practices transversally within the company, solving critical issues with the help of previously unseen perspectives.”
On June 5, the last of 72 turbines was installed at the Kriegers Flak wind farm, 15 km to 40 km off the east coast of Denmark. The next steps will be to finalize testing and certification of the farm so that it can be inaugurated after summer.
According to Swedish energy company Vattenfall, the farm is Denmark’s largest and will have a capacity of 604 MW. It will cover the electricity consumption of about 600,000 Danish households and increase Danish wind production by about 16%.
“We are pleased to see that the installation of the turbines has been successfully completed. Despite COVID-19, we have been able to deliver according to plan – actually a little ahead of schedule – which shows that our general strategy to prepare for the unforeseen has proved to be robust. We are very satisfied with the cooperation with our partners and proud of the contribution that the farm will make to enabling a fossil-free future,” says Catrin Jung, head of offshore wind at Vattenfall.
The first turbine was installed in February 2021, and installation of the remaining Siemens Gamesa offshore wind turbines has continued smoothly. The 72 wind turbines each have a total height of 188 m, and each foundation weighs up to 800 tonnes.
During the installation phase, the turbines were preassembled and shipped out of the Port of Roenne on the Baltic Sea island of Bornholm. The wind farm will be serviced out of Vattenfall’s new service facility at the Port of Klintholm about 100 km south of the Danish capital Copenhagen.
“It’s extremely rewarding that we – in the middle of these challenging COVID times – have safely installed all 72 wind turbines ahead of schedule. The close collaboration between Siemens Gamesa employees, Vattenfall, and the Port of Roenne has been outstanding. We look forward to continuing the great joint efforts on the Danish Kriegers Flak project with all,” says Marc Becker, chief executive offshore of offshore at Siemens Gamesa.
European renewable energy generator Statkraft, in collaboration with Norwegian supplier Ocean Sun, has started commercial operations at the first unit of its floating solar project in Albania.
The project is placed at the Banja reservoir in Albania, where Statkraft is operating its 72-MW Banja hydropower plant. After the successful completion of the first floating solar unit and connection to the grid, the plant is now generating renewable energy and injecting the power into the Albanian national electricity grid.Image credit: Statkraft
The first unit, comprising 1536 solar panels, has an installed capacity of 0.5 MWp and covers almost 4,000 square meters. In addition, 160 equal panels have been placed on land for comparison and documentation of the cooling effect on the floating panels.
The project is unique as it uses Ocean Sun’s patented membrane technology. The solar modules are mounted on hydro-elastic membranes and offers cost and performance benefits not seen in many other floating PV systems.
The project is expected to continue its second implementation phase during the second half of 2021, whereby additional three floating units will be installed, with a combined additional capacity of 1.5MWp.
“After the start of commercial operations of our Banja and Moglice hydropower plants, we are looking into further optimising these renewable assets. The Banja Floating Solar Plant is a concrete example for further integration of different resources of renewable energy,” says Rigela Gegprifti, Statkraft’s country head in Albania.
Floating solar power involves installing solar panels on floating structures on a body of water, such as a lake, fjord or ocean, or in a hydropower reservoir. Each unit consists of a floating ring and a thin membrane. Combined with the cooling of the panels from the water below, it is this membrane and the large area that makes this concept unique. The technology is developed by Ocean Sun and although the membrane is only a few millimeters thick, it can easily withstand the weight of the solar panels and of personnel carrying out installation or maintenance tasks.
“We are very pleased to start commercial operations of the new Ocean Sun flagship floater at Statkraft’s Banja reservoir. This demonstrates the safe, simple and fast construction methodology. We were able to install the solar panels at record breaking speed… We look forward to the second stage of the project and to demonstrate the high performance of our solution,” says CEO of Ocean Sun, Børge Bjørneklett.
According to Statkraft, Albania has one of the highest shares of renewable energy in Southeast Europe. Hydropower accounts for the largest share of Albania’s electricity generation, representing around 95% of its installed power capacity. In addition, Albania has some of Europe’s highest number of sunshine hours per year, presenting significant potential for the development of solar power and a good fit with existing hydropower capacity.
Tracking SDG7: The Energy Progress Report says that during the past decade, a greater share of the global population gained access to electricity than ever before, but the number of people without electricity in Sub-Saharan Africa increased. Unless efforts are scaled up significantly in countries with the largest deficits, the world will still fall short of ensuring universal access to affordable, reliable, sustainable and modern energy by 2030.
The report was released by the International Energy Agency (IEA), International Renewable Energy Agency (IRENA), UN Department of Economic and Social Affairs (UN DESA), World Bank, and World Health Organization (WHO).
According to the report, significant progress has been made since 2010 on various aspects of the Sustainable Development Goal (SDG) 7, but progress has been unequal across regions. More than 1 billion people gained access to electricity globally over the past decade, but COVID’s financial impact has made basic electricity services unaffordable for 30 million more people, the majority located in Africa. Nigeria, the Democratic Republic of Congo, and Ethiopia had the biggest electricity access deficits, with Ethiopia replacing India in the Top 3.
Globally, the number of people without access to electricity declined from 1.2 billion in 2010 to 759 million in 2019. Electrification through decentralized renewable-based solutions in particular gained momentum. The number of people connected to mini grids more than doubled between 2010 and 2019, growing from 5 million to 11 million. However, an estimated 660 million people would still lack access in 2030, most of them in Sub-Saharan Africa.
The report examines ways to bridge the gaps to reach SDG7, chief among them the goal of significantly scaling up renewables. While renewable energy has seen unprecedented growth over the past decade, its share of total final energy consumption remained steady as global energy consumption grew at a similar rate. Renewables are most dynamic in the electricity sector, reaching around 25% in 2018, while progress in the heat and transport sectors has been much slower.
More than one third of the increase in renewable energy generation in 2018 can be attributed to East Asia, driven by large uptakes of solar and wind energy in China. The largest country-level advances in renewable energy in 2018 were in Spain, owing to higher hydropower generation, followed by Indonesia, with a rapid uptake of bioenergy.
Accelerating the pace of progress across all regions and indicators will require stronger political commitment, long-term energy planning, and adequate policy and scale incentives to spur faster uptake of sustainable energy solutions. Although clean energy investments continue to be sourced primarily from the private sector, the public sector remains a major source of financing and is central in leveraging private capital, particularly in developing countries and in a post-COVID context. One of the newest indicators in the report, international public financial flows to developing countries, shows that international financial support continues to be concentrated in a few countries and failing to reach many of those most in need. Flows to developing countries in support of clean and renewable energy reached $14 billion in 2018, with a mere 20% going to the least-developed countries. An increased emphasis on “leaving no one behind” is required in the years ahead.
The COVID-19 crisis resulted in an estimated 7% year-on-year expansion of renewable electricity generation, supported by long-term contracts, low marginal costs, priority access to grids and installation of new renewable capacity. In contrast, renewable energy share for transport and heat declined in 2020. Renewable electricity accounts for almost half of global renewable energy consumption and three-quarters of its year-on-year increase, with hydropower being the largest renewable source of electricity globally and for each region. Heat had only a 1.2% absolute increase when it came to renewable sources. Coal, gas and oil still meet three-quarters of global heat demand. Transport has the lowest renewable energy penetration of all sectors, with only 3.4% in 2018 being supplied by renewables. While Sub-Saharan Africa has the largest share of renewable sources in its energy supply, it is not modern – 85% is traditional uses of biomass. Latin America and the Caribbean have the largest share of modern renewable energy uses, thanks to hydropower for electricity, bioenergy for industrial processes and biofuels for transport.
“On a global path to achieving net-zero emissions by 2050, we can reach key sustainable energy targets by 2030 as we expand renewables in all sectors and increase energy efficiency,” said Fatih Birol, executive director of IEA. “Greater efforts to mobilize and scale up investment are essential to ensure that energy access progress continues in developing economies. Providing electricity access and clean cooking solutions to those people who are deprived of them today costs around $40 billion a year, equal to around 1% of average annual energy sector investment on a path to net zero by 2050. This fairer and cleaner energy future is achievable if governments work together to step up actions.”
“Renewable energy has proven itself to be reliable, cost-effective, and resilient during the pandemic, revealing its significant value at the forefront of the energy transition. But progress towards the achievement of climate objectives and SDG7 needs to move at an accelerated pace and equitable manner,” said Francesco La Camera, director-general of IRENA. “Efforts, including international public financial flows to renewables, must be scaled up to support countries that need the most improvement in clean, affordable, and sustainable energy access, healthcare, and welfare.”
This is the seventh edition of this report, formerly known as the Global Tracking Framework (GTF). This year’s edition was chaired by the United Nations Statistics Division. Funding for the report was provided by the World Bank’s Energy Sector Management.
Kenya Electricity Generating Company PLC (KenGen) has begun drilling the first geothermal well at the Aluto site for Ethiopia Electric Power (EEP) company.
This sets into motion Phase II of the $70.4 million contract. KenGen’s managing director and chief executive officer, Rebecca Miano, through a statement, said the works began over the last weekend in May. “The exercise started on Saturday, 29 May 2021, whereby the first hole section was drilled to 29 metres within eight hours. So far, drilling operations are running smoothly as the team moves to the next hole section. Drilling a single well takes about two months to complete. We however hope to shorten this period despite the prevailing circumstances brought about by Coronavirus Disease (COVID-19),” she said.
According to Miano, within the next three weeks the company will mobilize specialized drilling services crew including aerated drillers, directional drillers, and reservoir engineers to ensure the project is a success.
Former EEP CEO Abraham Belay said they were optimistic KenGen would be able to drill the projected number of wells. “What is more exciting is the fact that KenGen is also building the capacity of our people and eventually, we will also be able to manage geothermal equipment and run the power plants after the company exits the sites,” said Belay.
He revealed that Ethiopia’s quest for geothermal energy spans over four decades as the country had tried to venture into geothermal development as far back as 1981. With KenGen’s entry into the country, Ethiopia is now staring at a geothermal generation breakthrough.
The move by KenGen to commence Phase II of the project follows the completion of Phase I of the contract by the consortium partners under which two rigs were delivered to the site. Phase I entailed the purchase of drilling rigs, while Phase II entails the provision of drilling services. KenGen is supplying about 30% of the components of Phase II, which translates to about $6.2 million.
Under this project, which is financed by the World Bank through a loan to the Ethiopian government, a total of eight wells will be drilled in Lot 1 using two rigs with expected revenue of $6.2 million. Each rig is expected to drill four wells within a period of one year.
Depending on the outcome of Lot 1 wells, an additional 12 wells may be drilled under Lot 2, bringing the total to 20 wells.
by Elizabeth McGowan, Energy News Network
An ambitious measure to convert Virginia’s fleet of 17,000 diesel-powered school buses to quieter and cleaner electric models over a decade was praised by health and environmental advocates when it passed the General Assembly at the end of February.
But transitioning from yellow to green is expensive. And that hefty price tag became more daunting when House Bill 2118, signed into law by Democratic Gov. Ralph Northam, was left unfunded.
Still, proponents of a bill that drew bipartisan support are optimistic that they can figure out how to tap into state, federal or even private dollars to ensure that fleet turnover is executed in a speedy and equitable fashion.
The bill that became law was stripped of its original funding source, a tax on dyed diesel fuel, which is used in farm machinery and other non-highway vehicles. The substitute version creates a grant fund and directs the state Department of Environmental Quality to lead a workgroup to figure out the details.
While that’s being hashed out, supporters point to other options. For example, $10 million in grants are now available from the DEQ via the Volkswagen Environmental Mitigation Trust. Observers are also abuzz with the potential of a private-public partnership that their Maryland neighbor to the north, Montgomery County Public Schools, signed in February with Massachusetts-based Highland Electric Transportation.
Federal money also could be on the table, depending on how Congress shapes the Biden administration’s new $2.3 trillion infrastructure package, the American Jobs Plan, into legislation.
Many Virginians find any of those options far more palatable than a continued, but thus far unsuccessful, legislative effort by Dominion Energy to fold electric school buses into the utility’s expansive vehicle-to-grid plans.
Blair St. Ledger-Olson leads transportation-related policy initiatives at Generation 180, founded in 2016 as a nationwide organization to equip individuals and communities to play a role in the country’s transition to 100% clean energy.
The Charlottesville-based nonprofit was disappointed that legislators, then Northam, declined to fund HB 2118.
“Helping kids breathe cleaner air should be a no-brainer,” she said. “The General Assembly just doesn’t have the appetite to spend money on transportation electrification.”
HB 2118 was the handiwork of Del. Mark Keam, a Fairfax County Democrat who had sponsored similar legislation that failed during the 2020 session.
In a nutshell, this year’s version calls for setting up a grant fund to help school districts cover expenses for electric buses and related charging infrastructure. It is designed to prioritize grant requests from districts in regions with high asthma rates and poor air quality. Diesel fumes contain particulate matter that causes asthma.
A child riding on a diesel school bus may be exposed to as much as four times the level of pollution from exhaust as someone riding in a car, according to a study released in 2001 by the Natural Resources Defense Council. That exposure puts them at a higher risk of developing cancer.
The advocacy organization Mothers Out Front has maintained that swapping combustion engines for electric ones is essential to combating climate change because nationwide the transportation sector is the largest emitter of heat-trapping gases. In Virginia, tailpipe pollution accounts for roughly 48% of all greenhouse gas emissions.
Fairfax County resident Bobby Monacella, who co-leads her county’s Mothers Out Front chapter, began delving into the issue a few years ago and garnering Keam’s support.
As this year’s legislative session went down to the wire, she and her two daughters, ages 18 and 14, sat glued to a livestream. They were also plugged into a group chat with other advocates so nobody missed anything.
“When it passed, we completely wigged out,” she recalled. “But like it is with any project, you take the time to be excited, then realize how much work you have ahead.”
The labor to set up a grant fund involves regular gatherings of people with all levels of expertise about electric school buses.
“This is a whole new learning curve,” Monacella said. “We need to define the program and make sure all stakeholders have input.”Volkswagen funds now up for grabs
When Virginia was allotted $93.6 million from the Volkswagen Environmental Mitigation Trust, it designated $20 million of that to clean school buses. Through June 25, the state DEQ is accepting applications from school districts for the first round of $10 million. A total of $9.25 million is available for battery electric buses and associated chargers, while the remainder is set aside for propane buses.
The money covers the price difference between diesel and cleaner buses — up to $265,000 per electric bus or up to $20,000 per propane bus, said Angela Conroy, senior planner with DEQ’s Air and Renewable Energy Division.
While each school district can apply to cover that differential for up to 10 buses, the state agency is giving preference to districts that have old buses with high mileage and that enroll large numbers of students in free and reduced meal programs.
Balancing such criteria allows DEQ to address equity issues while also removing the dirtiest buses from fleets, Conroy said. She noted that Virginia has no law outlining when a school bus should be retired. Buses built in and before 2006 are the biggest polluters because the U.S. Environmental Protection Agency didn’t institute standards until model year 2007.
“Each bus is scored and ranked individually,” she said. “It’s highly unlikely a district will receive funding for 10 buses even if it applies for 10. Our objective is to get old buses off the road and give everybody a fair shot.”
DEQ officials will notify school districts in July whether or not they’ve been selected. A new funding round of $10 million will likely be rolled out this fall.
Conroy knows $20 million is a drop in the bucket, but “it has to start somewhere.” The VW settlement money is one of several funding options with the potential to generate momentum to move the electric bus market.
“This is the right time and the right place to move people forward, to have that conversation,” she said. “That’s what we’re looking at doing.”Fairfax County moves ahead — cautiously
Since late May, students in Fairfax County Public Schools have been riding eight electric buses that are part of a pilot program Dominion announced in August 2019.
Vehicle maintenance coordinator Joseph Welborn said he gave drivers plenty of time to familiarize themselves with the new technology after the buses arrived between January and March.
“Our fingers are crossed that we will be successful with these buses,” Welborn said. “Then we can slowly transition to an electric fleet.”
Dominion’s starter plan invited schools within its service territory to apply for a share of 50 electric buses. Initially, the utility selected 16 localities based on the value of batteries to the local grid. The idea was to grow the program so the bus batteries can serve as energy storage to support the integration of distributed renewable energy.
However, this year and last, lawmakers repeatedly rejected Dominion’s attempts to move beyond phase one and add at least another 1,000 electric buses in its service area. Program costs would have been recoverable through the utility’s base rates. Opponents criticized most of the bills as monopoly overreach that would have raised customers’ bills and handcuffed public schools to the utility’s profit incentives.
Phase one was narrowed to 15 localities because of shifting budget priorities at some school districts caused by impacts of COVID-19, Dominion spokeswoman Samantha Moore said. Despite that, the utility expected to have the 50 electric school buses deployed by the end of May.
“We are continuing to explore ways to expand this innovative program,” she said when asked how Dominion could add enough buses to create a viable vehicle-to-grid operation.
Dominion selected Thomas Built Buses as the vendor for the electric buses, which cost at least three times as much as a diesel model. Under the pilot, school districts pay the cost of a diesel bus — roughly $109,000 — and Dominion covers the difference.
In Fairfax County, charging infrastructure was installed at the Stonecroft Transportation Facility near Westfield High School because it met Dominion’s grid-access requirements. Routes of the buses are in adjacent neighborhoods.
The price of each electric bus in Fairfax, with mandated upgrades, rang in at $376,000. The schools paid $130,000 of that total, with Dominion also covering the charging equipment. The utility owns the bus batteries and propulsion systems.
Typically, the district replaces about 100 buses annually in its fleet of 1,625, Welborn said. He urges climate activists to exercise patience in their push for electric buses because school authorities have to consider the budget, rapid advances in technology and how to install charging infrastructure for buses parked at 130 lots throughout the sprawling district.
“I know this is all about the environment and clean air for students, but we’re trying to be real here,” he said. “I can’t say we’re going to jump in with both feet and only buy electric buses. We can’t do that on our own with our budget.”
Those concerns have prompted him to apply to the DEQ program and explore other opportunities.Is Maryland county a model for Virginia?
A local model on everyone’s radar is the deal the nearby Montgomery County School Board in Maryland sealed with Highland Electric Transportation, founded in 2018 by renewable energy industry veteran Duncan McIntyre.
The district will pay an annual fee to lease the buses from the vendor. In turn, Highland will invest in the upfront costs of buying the buses and recoup that investment over time via decreasing bus prices, cheaper fuel and savings on maintenance.
Montgomery County plans to replace its current fleet of 1,400-plus buses over the next 14 years. The county expects to cover the cost of the contract with funds that would have paid for purchasing and operating diesel buses, according to a news release.
Touted as the largest single-district project of its type nationwide, it mimics the power purchase agreements that have helped schools obtain access to solar energy without being burdened by the steep upfront costs of arrays.
St. Ledger-Olson, of Generation 180, said such an arrangement is intriguing but wonders how it would work in Virginia because every state has different laws.
“In theory, it’s fantastic,” she said. “In practice, we have to figure it out.”
Virginia is open and prepared to accept federal dollars for school bus conversions, St. Ledger Olson said, but the devil is always in the details of what Congress might actually approve.
When President Biden unveiled the American Jobs Plan, it included $20 billion to electrify one-fifth of the nation’s 480,000 school buses — the country’s largest mass transit system. About 17,000 of those are in Virginia. However, that $20 billion isn’t set in stone because at least three federal bills outlining transportation electrification are also part of the mix.
No matter what Virginia’s funding stream is, Monacella, the Fairfax County advocate, is confident the state can create a fair program that meets each school district’s needs.
“Some people whine about the fact that this is expensive,” she said. “Electric buses matter to us moms who worked on it because we’re talking about our kids and their health. It just seems like we have to make this happen.”
Power plant engineering and construction giant Bechtel is partnering with a renewable energies company to explore the potential of bioenergy production sites combined with carbon capture and storage.
The EPC firm announced its strategic agreement with Drax to create Bioenergy with Carbon Capture and Storage (BECCS) plants around the world. The focus for both companies working together is identify design optimization for engineering and building BECCS plants
Drax already has undertaken what it calls the largest decarbonization project in Europe—converting its power station in North Yorkshire, England, to use biomass instead of coal.
Jason Shipstone, Drax Group Chief Innovation Officer, said: “Negative emissions technologies such as BECCS are crucial in tackling the global climate crisis and at Drax we’re planning to retrofit this to our UK power station, demonstrating global climate leadership in the transformation of a former coal-fired power station.”
Bechtel will focus its study on strategically important regions for new build BECCS plants, including North America and Western Europe, as well as reviewing how to optimize the design of a BECCS plant using state-of-the-art engineering to maximize efficiency, performance and cost.
“Technological advancements have created new opportunities to improve how we bring power to communities worldwide,” Jamie Cochrane, Bechtel Manager of Energy Transition, said in a statement. “We are resolved to work with our customers on projects that deliver effective ways to contribute to a clean energy future. Tackling the big global challenges related to climate change is key to meeting aggressive environmental targets and we are proud to partner with Drax to optimize design and explore locations for the new generation of BECCS facilities.”
Carbon capture and decarbonization focus of this month’s POWERGEN+ online series
Drax owns and operates a portfolio of renewable electricity generation assets in England and Scotland. The assets include the UK’s largest power station, based at Selby, North Yorkshire, which supplies five percent of the country’s electricity needs.
Drax also owns and has interests in 17 pellet mills in the southern U.S. and western Canada which have the capacity to manufacture 4.9 million tonnes of compressed wood pellets (biomass) a year. The pellets are produced using materials sourced from sustainably managed working forests and are supplied to third party customers in Europe and Asia for the generation of renewable power.
Bechtel, meanwhile, also has built more than 40 carbon capture plants for LNG facilities, refineries and gas processing plants.