Sunnova Seeks Approval To Build Solar-Storage ‘Micro Utilities’ in California
September 7, 2022
by Peter Maloney
APPA News
September 7, 2022
Sunnova Energy International has applied to the California Public Utilities Commission (CPUC) to develop solar-and-storage “micro-utilities” in California.
Sunnova’s wholly owned subsidiary Sunnova Community Microgrids California (SCMC) said it plans to target newly constructed homes where it can work with developers to design and implement mostly self-sustaining micro-utilities equipped with solar and storage facilities.
The company said the installations would be “largely self-sustaining micro-utilities by equipping new home communities with solar and storage to provide consumers with a better energy service that allows them to live in a more resilient home and community with latest-generation energy infrastructure.”
In its filing with the California commission, SCMC asked the CPUC to qualify it as a “micro-utility” and to request a certificate to construct and operate microgrids under California’s public utilities code.
The company hopes to build multi-property microgrids for residential and commercial customers in California and be the first solar and storage focused micro-utility company in the state able to own and operate behind-the-meter nanogrids, community assets, and front-of-the-meter distribution infrastructure.
SCMC community assets would include complete distribution infrastructure and energy assets including solar, battery storage, and emergency generation, the company said.
California’s first 100 percent renewable energy, front-of-the-meter, multi-customer microgrid, in Humboldt County, came online in June, providing energy resilience for a regional airport and a U.S. Coast Guard Air Station.
Maine And Rhode Island Join New York-led Clean Hydrogen Hub Coalition
September 7, 2022
by Peter Maloney
APPA News
September 7, 2022
Maine and Rhode Island have joined a multi-state clean hydrogen hub in the New England-MidAtlantic region, New York Governor Kathy Hochul announced late in August.
The newest members of the New York-led coalition join Connecticut, Massachusetts and New Jersey in the effort to develop a proposal to become one of at least four regional clean hydrogen hubs designated through the federal Regional Clean Hydrogen Hubs program included in the bipartisan Infrastructure Investment and Jobs Act.
In addition to the six states, the coalition includes 14 private sector companies, 12 utilities, 20 hydrogen original equipment manufacturers, 10 universities, seven non-profits, two transportation companies, and three state agencies.
Hochul’s office said New York would continue to engage with states and entities interested in joining the coalition.
The coalition members have agreed to work together to lay the groundwork for a proposal for the Department of Energy (DOE) funding opportunity expected to be announced in September or October with up to $8 billion in total funding available for regional clean hydrogen hubs.
They have also committed to collaborate with the New York State Energy Research and Development Authority (NYSERDA), New York Power Authority (NYPA), and Empire State Development (ESD) to develop a clean hydrogen hub proposal.
Partner states will also coordinate with their respective state entities to help align the consortium’s efforts with each state’s climate and clean energy goals. These include Connecticut’s Global Warming Solutions Act goal of reducing greenhouse gas emissions 80 percent by 2050, Massachusetts’ goal of reaching net-zero carbon emissions by 2050, New Jersey’s Global Warming Response Act goal of reducing greenhouse gas emissions 80 percent by 2050, Maine’s statutory goals to achieve carbon neutrality by 2045 and reduce gross greenhouse gas emissions by at least 80 percent by 2050, and Rhode Island’s commitment to achieving 100 percent renewable electricity by 2033.
The coalition also plans to continue to focus on the integration of renewables, such as onshore and offshore wind, hydropower, solar power, and nuclear power, into clean hydrogen production, and the evaluation of clean hydrogen for use in transportation, heavy industry, and power generation.
“This expanded collaboration with Maine, Rhode Island and other like-minded partners will significantly boost the value of our clean hydrogen hub proposal and make the Northeast a stronger, more multi-faceted contender for funding through the U.S. Department of Energy. Innovative technologies are showing the potential of green hydrogen as a fossil fuel alternative and the time is right to take a deeper dive into the many opportunities that will reduce greenhouse gas emissions, benefit the workforce and help build a clean energy economy,” Justin E. Driscoll, interim president and CEO of NYPA, said in a statement.
In February, the Department of Energy (DOE) released two requests for information (RFI) to collect feedback from stakeholders to inform the implementation and design of two of the DOE’s clean hydrogen programs, which in total call for investments of up to $9.5 billion.
In March, the governors of Colorado, New Mexico, Utah and Wyoming signed a memorandum of understanding to develop a proposal to vie for DOE’s regional clean hydrogen hub funding opportunity.
Pascoag Utility District, Agilitas Energy Bring R.I.’s First Utility Scale Battery Online
September 7, 2022
by Peter Maloney
APPA News
September 7, 2022
Pascoag Utility District (PUD), in partnership with Agilitas Energy, in July brought Rhode Island’s first utility scale a battery storage project online.
For Pascoag Utility District, the 3-megawatt (MW), 9-megawatt hour (MWh) battery installation helps it shave peak demand and deferred transmission costs. The public power utility entered the project as a non-wires alternative solution to upgrading or installing new transmission lines, which would have cost Pascoag between $6 million and $12 million.
“This project allowed us to save up to $12 million dollars for our customers by avoiding a costly rebuilding of transmission infrastructure,” Mike Kirkwood, general manager of Pascoag Utility District, said in a statement.
There was no cost associated with the project for Pascoag, however, the utility did complete work on a substation that was required for the battery project.
PUD received a grant of $250,000 from Rhode Island’s Office of Energy Resources (OER) for the substation project, which was also funded by an $1.4 million loan from the Rhode Island Infrastructure Bank and approved by OER through the state’s Efficient Building Fund program.
For its part, “Agilitas invested the necessary capital for construction, completed the engineering, procurement and construction for the battery project, and worked with PUD to commission this project,” Barrett Bilotta, president of Agilitas Energy, said via email. As part of the deal, Agilitas will split the transmission and capacity savings with the utility district. The savings come from avoided regional network service charges and installed capacity (ICAP) charges assessed by ISO-New England based on PUD’s peak load.
Agilitas, which owns and operates the battery project, uses it to provide energy to ISO New England grid when wholesale electric prices are high and charges the batteries from the grid when electric prices are low.
“As demand grows due to increased electrification and extreme weather conditions, we want to ensure Pascoag and Harrisville residents experience the same service and value they’ve come to expect,” Kirkwood said. “This project from Agilitas Energy was an easy, no-risk way to keep our operating costs down and deliver cleaner energy in the most cost-effective manner.”
Agilitas, based in Wakefield, Mass., acquired the Ocean State battery project in Rhode Island in April 2021 as part of its acquisition of New England Battery Storage, which added 25 MWh of energy storage capacity to its portfolio.
Planning Meeting For Next Light Up Navajo Scheduled For Sept. 14
September 7, 2022
by Paul Ciampoli
APPA News Director
September 7, 2022
A virtual planning meeting for the next Light Up Navajo mutual aid initiative will take place on Sept. 14, 2022.
The meeting for Light Up Navajo IV is scheduled to start at 1 p.m. EST and will include remarks from Joy Ditto, President and CEO of the American Public Power Association (APPA), Walter Haase, General Manager, Navajo Tribal Utility Authority (NTUA), Srinivasa Venigalla, Deputy General Manager, NTUA, Shannon Burnette, Assistant Manager, NTUA, and Deenise Becenti, Public Affairs Manager, NTUA.
For more Information, contact Burnette at: shannonb@ntua.com, (928) 729-6248, Paulette Wauneka, paulettew@ntua.com; (928)-729-6560 or Chelsea Zahne, chelseaz@ntua.com (928) 729-6452.
APPA worked with NTUA on Light Up Navajo III to help volunteers continue to bring electricity to families in need.
During April-June 2022, 69 volunteers from 14 utilities in 10 different states worked to electrify 137 Navajo Nation homes.
NREL Outlines Paths And Challenges Of Reaching 100% Clean Electric Grid By 2035
September 6, 2022
by Peter Maloney
APPA News
September 6, 2022
There are several pathways to accomplish the decarbonizing of the U.S. electric grid by 2035, but they all come with their own sets of challenges, according to a new report from the National Renewable Energy Laboratory (NREL).
The report, Examining Supply-Side Options to Achieve 100% Clean Electricity by 2035, examines the types of supply side clean energy technologies and the scale and pace of deployment needed to achieve 100 percent clean – defined as zero net greenhouse gas emissions – power grid by 2035, which NREL says could put the United States on a path to economy wide decarbonization by 2050.
The authors noted that the report comes on the heels of the enactment of the Inflation Reduction Act (IRA), which, with the Bipartisan Infrastructure Law (BIL), aims to reduce economy wide greenhouse gas emissions in the United States to 40 percent below 2005 levels by 2030. The reductions are expected to be more pronounced within the electric power sector with initial estimates of declines of 68 to 78 percent below 2005 levels by 2030. Nonetheless, the authors say the laws are likely not sufficient to bring the country all the way to 100 percent carbon dioxide free electricity by 2035.
In the study, which as done in partnership with the Department of Energy (DOE) with funding support from the DOE’s Office of Energy Efficiency and Renewable Energy, the authors evaluated four core scenarios that were each compared with two reference scenarios, one with current policy electricity demand and the other with higher load growth as a result of accelerated electrification.
The authors noted that the most cost effective pathway to large-scale decarbonization likely involves electrification of buildings and much of the transportation and industrial sectors, as well as “aggressive” energy efficiency and demand management measures. However, they also noted that electrification “will dramatically increase demand, which in turn makes it more difficult to decarbonize the electricity system due to the rate of deployment needed.”
The four core scenarios used in the study are:
- All Options, in which all technologies continue to decline in cost while reaching higher levels of performance, including development and deployment of direct air capture (DAC) technology, which removes carbon dioxide directly from the atmosphere. (The other three scenarios assume DAC does not achieve cost and performance targets needed to be deployed at scale.)
- Infrastructure Renaissance, which assumes improved transmission technologies as well as new permitting and siting approaches that allow greater levels of transmission deployment with higher capacity.
- Constrained, in which additional constraints to deployment of new generation and transmission capacity increases costs and limits deployment of certain technologies.
- No CCS, in which carbon capture and storage (CCS) technologies do not achieve needed cost and performance targets for cost-competitive deployment.
Beyond the four core scenarios, NREL also analyzed 142 additional sensitivities in the study in order to capture future uncertainties related to technology cost, performance, and availability.
None of the scenarios in the study include the IRA and BIL energy provisions, but NREL said their inclusion is not expected to significantly alter the 100 percent systems explored.
In all the core scenarios, the 100 percent requirement is met on a net basis, meaning gross emissions can be offset through negative emissions technologies, such as DAC, that can capture carbon dioxide from the air.
In all scenarios, as much as 5 percent of 2035 generation is from fossil fuel technologies. The All Options scenario includes about 660 gigawatts (GW) of fossil capacity of all types in 2035.
Only the No CCS scenario precludes the use of fossil fuel generation; it also has the greatest use of seasonal storage. In the other three scenarios, fossil generators continue to contribute through 2035, but their emissions must be offset by technologies including DAC and bioenergy with carbon capture and storage. Fossil plants with carbon capture and storage would have to have emissions offsets because their capture rates are assumed to be 90 percent and upstream methane leakage from natural gas production must also be offset.
In all the modeled scenarios, NREL said new clean energy technologies would be deployed at an “unprecedented scale and rate” to achieve 100 percent clean electricity by 2035.
The models call for wind and solar energy to provide between 60 and 80 percent of generation in the least-cost electricity mix in 2035, with overall generation capacity growing to roughly three times the 2020 level by 2035. That would require the installation of between 40 and 90 GW of solar on the grid per year and 70 to 150 GW of wind power per year by the end of the decade. That growth in renewable generation would represent a fourfold increase in the current annual deployment levels of wind and solar power, NREL noted.
Across the four scenarios, 5 to 8 GW of new hydropower and 3 to 5 GW of new geothermal capacity would also need to be deployed by 2035, as well as 120 to 350 GW of diurnal storage, that is, storage capable of discharging from to 2 to up to 12 hours.
Seasonal storage would also have to play an important role in reaching 100 percent clean energy by 2035, NREL said, because there would be a multiday-to-seasonal mismatch of variable renewable supply and demand if clean electricity comprises 80 to 95 percent of generation. Across the scenarios, seasonal storage capacity in 2035 would need to range from 100 to 680 GW, which would require “substantial development” of infrastructure such as fuel storage, transportation and pipeline networks.
In the Constrained scenario, nuclear capacity more than doubles, reaching 27 percent of generation, while limited growth in the other three core scenarios results in a contribution of 9 to 12 percent, largely from the existing nuclear fleet, NREL said.
Differences in energy contribution among the four core scenarios are largely driven by constraints in transmission and renewable siting, NREL said. In all scenarios, a “significant” amount of new transmission would be needed to deliver energy from wind-rich regions to load centers in the eastern United States. Total transmission capacity in 2035 would need to be 1.3 to 2.9 times current capacity, requiring 1,400 to 10,100 miles of new high-capacity transmission lines per year, NREL said.
Technologies being deployed today “can provide most of U.S. electricity by 2035 in a deeply decarbonized power sector,” but achieving a net-zero electricity sector at the lowest cost will take advances in research and development into emerging technologies, including the “potentially important role of several technologies that have not yet been deployed at scale, including seasonal storage and several CCS-related technologies,” NREL said in the study.
In addition, a growing body of research has demonstrated that the cost of transitioning to 100 percent carbon dioxide free electricity increases steeply as the 100 percent mark is approached. The higher costs of the so-called “last 10% challenge” are driven largely by the seasonal mismatch between variable renewable energy generation and consumption, NREL said.
NREL said it has been studying how to solve the last 10 percent challenge, including outlining key unresolved technical and economic considerations and modeling possible pathways and system costs.
“There is no one single solution to transitioning the power sector to renewable and clean energy technologies,” Paul Denholm, principal investigator and lead author of the study, said in a statement. “There are several key challenges that we still need to understand and will need to be addressed over the next decade to enable the speed and scale of deployment necessary to achieve the 2035 goal.”
Public Power Utilities Express Interest In Participating In SPP Market Development
September 3, 2022
by Paul Ciampoli
APPA News Director
September 3, 2022
The Southwest Power Pool (SPP) recently announced that six additional entities including a number of public power utilities have expressed interest in participating in the next phase of the development of a western market.
Avista Corp., Washington State’s Chelan County Public Utility District and Grant County Public Utility District, along with Powerex Corp., Puget Sound Energy and Washington State’s Tacoma Power join Bonneville Power Administration (BPA).
In a letter Aug. 19, the six Pacific Northwest entities declared their intent to work with SPP to develop a western market that “supports reliability and delivers value to our customers.”
Since December 2021, SPP has been working with western stakeholders to learn what they’d like to see out of its proposed day-ahead and real-time market. Based on its potential customers’ input, SPP will develop the Markets+ draft service offering, which will explain how the proposed service will address things like governance structure, market design and transmission availability.
In August, BPA was the first western utility to formally commit to funding further development of SPP’s “Markets+.”
This group of seven entities represents a well-connected footprint with extensive transmission capability, a large fleet of clean flexible hydro resources, and a peak load over 30,000 MW, which is already 50% larger than the smallest RTO, ISO-New England, SPP said.
Markets+ is a conceptual bundle of services proposed by SPP that would centralize day-ahead and real-time unit commitment and dispatch, “provide hurdle-free transmission service across its footprint and pave the way for the reliable integration of a rapidly growing fleet of renewable generation,” SPP said.
For utilities that see value in these services but who aren’t ready to pursue full membership in a regional transmission organization (RTO) at this time, Markets+ provides a voluntary, incremental opportunity to realize significant benefits, according to SPP.
SPP staff met with western stakeholders Aug. 9-10 in Portland, Oregon to review work done on the service offering and discuss outstanding items and next steps. The draft service offering will be distributed Sept. 30, followed by a public comment period, with the final service offering distributed November 18. Interested parties will make a commitment to fund further market development in early 2023.
SPP is a RTO that manages the electric grid across 17 central and western U.S. states and provides energy services on a contract basis to customers in both the Eastern and Western Interconnections.
APPA’s Delia Patterson Reappointed To Serve On DOE Electricity Advisory Committee
September 3, 2022
by Paul Ciampoli
APPA News Director
September 3, 2022
Delia Patterson, Senior Vice President of Advocacy and Communications and General Counsel at the American Public Power Association, has been reappointed to serve another term on the Department of Energy’s (DOE) Electricity Advisory Committee (EAC).
Each member of the EAC is appointed by the U.S. Secretary of Energy for a two-year term. The group reports to the DOE’s Assistant Secretary for Electricity and meets three times a year to advise DOE on a variety of electricity issues.
The 37 members of the EAC come from across the energy community, including state and regional entities, utilities, cybersecurity and national security firms, the natural gas sector, equipment manufacturers, construction and architectural companies, non-governmental organizations, and other electricity-related organizations.
During their two-year term, the EAC members advise DOE on current and future electric grid reliability, resilience, security, sector interdependence, and policy issues.
They periodically review and make recommendations on DOE electric grid-related programs and initiatives, including electricity-related research and development programs and modeling efforts.
Members also identify emerging issues related to electricity production and delivery and advise on federal coordination with utility industry authorities in the event of supply disruptions and other emergencies.
She was first appointed to the EAC by then-Secretary of Energy Rick Perry, who served in the administration of President Trump.
Patterson recently joined the advisory board of E Source, a research, consulting and data science firm for the utility sector.
She was also elected president of the board of directors of the Energy Bar Association this year.
Patterson is also a member of the Lawrence Berkeley National Laboratory Future Electric Utility Regulation Advisory Group, and an associate member of the Commodity Futures Trading Commission Energy and Environmental Markets Advisory Committee.
In addition, she is on the board of the Women’s Energy Resource Council and is the member of APPA’s executive leadership team who leads energy policy formulation and advocacy before federal agencies, federal courts, and various energy policy forum.
Groups Argue For Flexibility In Revision Of Reliability Standard To Address Extreme Weather Events
September 2, 2022
by Paul Ciampoli
APPA News Director
September 2, 2022
The North American Electric Reliability Corp. (NERC) must be given flexibility for any revisions made to an existing reliability standard to address reliability concerns related to transmission system planning for extreme heat and cold weather events impacting the reliable operations of the bulk electric system, the American Public Power Association (APPA) and several other trade groups said in recent comments submitted to the Federal Energy Regulatory Commission (FERC).
The Aug. 26 comments were filed in response to a pending FERC notice of proposed rulemaking (NOPR) proposing to direct NERC to revise mandatory reliability standard TPL-001-5.1 (Transmission System Planning Performance Requirements) to address reliability concerns related to transmission planning for extreme heat and cold weather events.
APPA was joined in the comments by the Edison Electric Institute, Large Public Power Council, National Rural Electric Cooperative Association, and Transmission Access Policy Study Group.
While the groups support addressing the planning for extreme heat and cold weather events in NERC reliability standards, “the variation in extreme weather events between regions and the highly varied system topologies of registered entities call for the Commission to vest NERC and the standard drafting team with flexibility in determining how to address the issues identified by the Commission, including potential corrective actions,” APPA and the others said.
The groups noted that they share the Commission’s desire to better address and respond to extreme heat and cold weather events and therefore support efforts to improve system planning specifically for these extreme heat and cold weather events.
“The manner and process required to achieve these goals is complex, requiring flexibility and multiple tools, if this effort is to be fully effective,” they said.
APPA and the other groups said that the purpose of the TPL standard is to establish transmission system planning performance requirements over a broad spectrum of system conditions, including extreme events, based upon operating experience that may result in wide-area disturbances and following a wide range of probable contingencies.
“Including extreme heat and cold weather as described by the Commission potentially could require adding numerous elements and specifics to a planning analysis,” they told FERC.
Given the wide set of issues and corresponding circumstances that a new or modified standard must entail, the groups recommended that the Commission “defer to the technical competence of the subject matter experts on a standard drafting team in order to develop a risk-based approach to the myriad issues raised in the NOPR.”
The groups also said that addressing challenges to electric system reliability posed by extreme heat and cold weather should be informed by the highly varied nature of risks and potential consequences to the electric system posed by these events.
“Different parts of the country face different risks, in terms of both type and severity of weather events. The risks faced by, and appropriate measures for, an entity in Florida may look very different from those of an entity in Texas, Wisconsin, or California; the risks may, moreover, change over time,” APPA and the other groups pointed out.
“Entities also vary in terms of the scope of their facilities. For example, some NERC-registered transmission owners own only one or two bulk electric system transmission lines, while others own extensive transmission systems covering a wide range of varying topography. The flexible approach proposed by the NOPR is thus imperative to help ensure that threats are assessed accurately and that selected corrective actions are suited to the region, system topography, and affected entities.”
Further emphasizing the need for flexibility in the approach to new or modified standards, many of the associations’ members currently assess risk to their systems due to extreme heat and cold weather effects in varying ways.
“Some already have developed studies and implemented plans to maintain system performance in light of extreme weather. Electric utilities constantly evaluate and update these risks depending on their particular location and system topology,” the groups said.
Moreover, NERC registered entities have obligations under TPL-001-4 to include events that are expected to produce more severe system impacts on the bulk electric system in planning assessments.
“While NERC develops reliability standards that apply on a continent-wide basis, in some instances a regional variance may be developed if a standard cannot be met or complied with because of a physical difference in the Bulk-Power System or because of an operational difference,” APPA and the other groups said.
In the case of extreme heat and cold weather, “regional differences require some flexibility or customization because systems vary widely in their topology and electrical characteristics, as well as in the weather impacts they face.”
The standard drafting team “should determine the best possible approach for addressing a continent-wide extreme heat and cold weather planning standard that accounts for geographic, system topology, and other variations, as well as the best approach to accommodating such variations or determining if regional variances are necessary.”
Report Highlights Regulators’ Role In Assuring Nuclear Power’s Continued Contribution
September 1, 2022
by Peter Maloney
APPA News
September 1, 2022
The National Association of Regulatory Utility Commissioners (NARUC) has released a white paper detailing the key role nuclear power can play as a clean energy resource and the role state regulators can play to support the continued viability of nuclear generation.
The paper, Nuclear Energy as a Keystone Clean Energy Resource, was written by Energy Ventures Analysis under subcontract to the NARUC Center for Partnerships and Innovation. It explores nuclear energy’s role in providing carbon-free electricity and highlights key considerations for regulators to keep in mind as decarbonization efforts continue across many states and utilities.
“Retaining the current nuclear fleet will be vital to meet current state decarbonization goals,” the authors of the paper conclude. They noted that 30 states have renewable portfolio standards (RPS), but only 13 of those states have established a clean energy standard (CES) that allows generation from other zero-carbon resources, such as nuclear energy, to count toward the requirement. And, of those 13 states, only four – New York, Illinois, New Jersey, and Connecticut – provide direct financial support for their in-state nuclear plants through zero-emission credits or other financial subsidies.
States should expand existing RPS rules to include nuclear energy as a qualifying resource, and states with CES regimes should establish financial support that could enable struggling nuclear plants to continue operation, the paper said.
Since 2013, 13 nuclear reactors totaling almost 11,000 megawatts (MW) have retired and two more reactors are scheduled to retire within the next three years. The retirements are mostly due to economic factors, particularly competition from relatively cheap natural gas brought about by rising shale gas supplies, the paper said.
There are still 92 nuclear reactors in operation in the United States with a total of 97,400 MW of capacity, which in aggregate account for approximately 20 percent of total electric generation and almost 50 percent of carbon-free electricity.
And as states continue to move toward higher levels of intermittent generation to meet greenhouse gas reduction targets, the reliable, zero emission energy of nuclear power will become more crucial, the paper said.
Nuclear reactors have the lowest forced outage rates among major fuel and technology types, the authors noted, citing data from the North American Electric Reliability Corporation (NERC). And because of their low cost of fuel, they are also one of the cheapest non-renewable generating resources operating in the United States, the paper said. Nuclear power plants are also a major employer and taxpayer, the paper noted.
Nonetheless, six states currently do not allow for the construction of new nuclear power plants until a federal solution has been found to provide safe long-term storage for spent nuclear fuel.
The paper’s authors recommend that the Nuclear Regulatory Commission (NRC) and the federal government should finalize a decision on the safe long-term storage of spent nuclear fuel at a consolidated interim storage facility (CISF) to enable states like Connecticut, Illinois, or Oregon to consider new nuclear plants as part of their future resource mix.
They also recommend enacting federal tax incentives that could provide additional financial opportunities for developers and investors to consider building new nuclear plants.
The paper also noted that current NRC regulations and guidance were developed and optimized for the licensing of conventional light water reactor technology. Updating those regulations to be risk-informed, performance- based, and technology inclusive would enable the more effective and efficient licensing of advanced reactor technologies, the paper said.
“Reducing unnecessary regulatory barriers to advanced reactor licensing is one of the keys to helping reduce the prohibitive costs of current conventional and advanced nuclear reactor designs,” the authors said.
The paper’s authors also said that state utility regulators should “ensure that utilities have fully considered the value of retaining their existing nuclear fleet through timely application for subsequent license renewal (SLRs) while also considering new nuclear power plants as viable resource options during their long-term resource planning procedures.”
In states with deregulated electricity markets, state utility regulators could work with state legislatures and other state regulatory agencies to provide financial incentives for utilities to retain and possibly expand nuclear generation within the state, the authors added.
“States play a vital role in moving the ball forward on advanced nuclear technology deployment. Ensuring that state energy regulators understand the opportunities that nuclear can help to unlock, as well as the challenges in deploying this technology effectively, is essential to ensure that nuclear continues to support grid reliability and carbon reduction goals,” Anthony O’Donnell, a Maryland commissioner and co-chair of the Department of Energy-NARUC Nuclear Energy Partnership and chair of the NARUC Subcommittee on Nuclear Issues–Waste Disposal, said in a statement.
Machine Learning Can Help Speed EV Charging, Idaho Lab Researchers Say
September 1, 2022
by Peter Maloney
APPA News
September 1, 2022
Machine learning has the potential to help bring an electric vehicle battery to a nearly fully charge in 10 minutes, according to researchers at the Department of Energy’s Idaho National Laboratory (INL).
“Currently, we’re seeing batteries charge to over 90 percent in 10 minutes without lithium plating or cathode cracking,” Eric Dufek. manager for INL’s energy storage and electric transportation department, said in a statement. At best, current protocols can fully charge an electric vehicle battery in about half an hour, he said.
When charging, lithium ions migrate from a battery’s cathode to its anode. Fast charging causes the ions to migrate more quickly, but sometimes the lithium ions do not fully move into the anode, which can cause lithium metal to build up and trigger early battery failure. Fast charging can also cause the cathode to wear and crack. Both conditions will reduce battery life and the effective range of an electric vehicle.
To charge a battery with optimal speed and minimum damage requires a huge amount of data about how different charging methods can affect a wide variety of batteries of varying designs and conditions, as well as the feasibility of applying a given charging protocol with the current electric grid infrastructure.
By inputting information about the condition of many lithium-ion batteries during their charging and discharging cycles, Idaho National Laboratory scientists say there were able to train machine learning analysis to predict battery lifetimes and the ways that different battery designs would eventually fail. The INL researchers fed that data back into the analysis to identify and optimize new protocols they then tested on real batteries.
“We’ve significantly increased the amount of energy that can go into a battery cell in a short amount of time,” Dufek said. One advantage of INL’s machine learning model is that it ties the protocols to the physics of what is actually happening in a battery, he said.
The researchers plan to use their model to develop even better methods and to help design new lithium-ion batteries that are optimized to undergo fast charging. The ultimate goal is for electric vehicles to be able to “tell” charging stations how to power up their specific batteries quickly and safely, Dufek said.
The INL scientists presented the results of their research at an Aug. 22 meeting of the American Chemical Society.