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.
California Lawmakers Approve Legislation That Allows For Nuclear Plant’s Continued Operation
September 1, 2022
by Paul Ciampoli
APPA News Director
September 1, 2022
California lawmakers voted to approve legislation that allows for the possible extension of the operation of the Diablo Canyon Power Plant (DCPP), California’s only remaining operating nuclear power plant.
The vote to approve the measure followed on the heels of a recent California Senate Committee hearing related to the possible extension of the operation of the DCPP. Additional details on the bill are available here.
In June 2016, California investor-owned utility PG&E said it planned to retire Diablo Canyon nuclear power plant in California under a joint proposal with labor and environmental groups. The California Public Utilities Commission in 2018 signed off on a request by PG&E that it be allowed to retire the Diablo Canyon nuclear plant by 2025. The two units at Diablo Canyon together produce approximately 2,300 net megawatts of power.
Ana Matosantos, cabinet secretary to Newsom, said at the California Senate hearing that the DCPP proposal creates the conditions for an extension of Diablo Canyon “for the shortest amount of time necessary to be able to maintain the goal of reliability and continuing to move forward on our transition.” She said that proposed extension is for a five-year period with the possibility of revisiting that duration.
At the Senate hearing, Maureen Zawalick, Vice President of Decommissioning and Technical Services at Pacific Gas and Electric Company (PG&E), said at the hearing that an extension of the nuclear plant would require a number of federal and state regulatory approvals.
“There are also some critical near-term activities we would have to quickly undertake to make a viable option for the state including funding, fuel purchasing and used fuel management,” she said. “The fuel purchasing and used fuel management take about an 18 month to two-year lead time. And we also need to be ramping up a project team to support the NRC license renewal application.”
The bill, SB-846, now goes to the desk of California Gov. Gavin Newsom, who is expected to sign the bill, according to various media reports.
Missouri River Energy Services to Introduce TOU Rates for Members Next Year
August 29, 2022
by Peter Maloney
APPA News
August 29, 2022
Missouri River Energy Services (MRES) plans to introduce wholesale time-of-use (TOU) energy rates for its member public power utilities in 2023.
The new rates would be higher when everyone is using power at the same time during periods of peak demand, typically from 12:00 to 8:00 p.m. during the summer, and cheapest overnight when few people are using power. Rates in the mornings are going to be mid-priced, Joni Livingston, vice president of member services and communications at MRES, said during a Pella, Iowa, city council presentation earlier this month.
Pella is one of the 61 member public power utilities in Iowa, Minnesota, North Dakota, and South Dakota for which MRES provides wholesale power and other energy services.
The change should be revenue neutral for MRES with “very little change for most of our members,” Livingston said. For Pella, she said, the rates would be about a 0.1 percent increase based on your previous usage. So, you should see very little change.”
“We did that purposely because we wanted to get people use to seeing what a time-of-use bill looks like and how time-of-use works,” Livingston said. “We didn’t want that to make any impact on your costs at first.”
The joint action agency has been letting its members know about the pending change for years, Livingston told the city council.
“If you want to bill your customers on time-of-use rates, you have to be sure your billing program will do it. It takes some time on the retail side of things.”
Livingston said the city, as well as other members, should think about passing on those rates to customers because it would give them the opportunity to save money. “If they can shift some of their usage off of your peak time” – typically 4 in the afternoon to 8 at night in both summer and winter – “they would actually save money with these rates.”
“Larger industrial and commercial customers, depending on their processes and how they can change things around or shift things to later time periods, it might make a big difference to them as well,” Livingston added.
Demand is somewhere between 40 and 50 percent of Pella’s total energy costs, “so anything the city can do to shave its peak load can have a significant savings for our community,” Mike Nardini, Pella city administrator, said during the meeting.
For a lot of MRES members, their current billing systems do not work with time-of-use rates, Livingston said, noting, however, that MRES has entered into a partnership with Tyler Technologies and is now offering member utilities a discount when they upgrade to Tyler’s TOU-compatible billing software.
Advanced metering infrastructure (AMI) – something Pella has been considering for years – also “needs to be in place for TOU rates, but there are also a ton of other benefits,” Livingston said.
AMI allows a utility to offer customer different metering intervals, not just monthly meter reads. That can give them and you more insight into how much electricity they use and when it is being used, and they can better manage use and costs.
The technology also reduces meter misreads and gives a utility the ability to do remote connections and disconnections, as well as quicker outage restoration and notifications, Livingston said. AMI also provides more accurate metering for charging electric vehicles, which are growing in popularity, she said.
Lansing, Michigan Utility Brings Gas Plant Online to Replace Retired Coal Plant
August 29, 2022
by Peter Maloney
APPA News
August 29, 2022
The Lansing Board of Water & Light (BWL) in Michigan has brought online a 250-megawatt (MW) natural gas-fired combined-cycle plant, replacing a retired coal-fired plant.
The $500 million Delta Energy Park replaces BWL’s 350-MW coal-fired Eckert Power Station which retired in 2020, and supports the utility’s increased renewable portfolio. The new plant, at the Erickson Power station in Delta Township, is BWL’s second natural gas plant.
The 162-MW coal-fired Erickson Power Station, which was commissioned in 1973, is scheduled to retire by December 2022. BWL said the retirement will make it the largest utility in Michigan to generate coal-free power by 2022, reducing its carbon emissions by 80 percent.
“Delta Energy Park marks a milestone in BWL history for being able to generate safe, affordable power to the greater Lansing region,” Dick Peffley, BWL’s general manager said in a statement.
“Along with moving us closer to our clean energy goals, this plant has opened the door for tremendous regional economic growth opportunities, such as BWL being the catalyst for the State of Michigan and General Motors to locate GM’s $2.6 billion electric vehicle battery plant just a few miles down the road. DEP has also resulted in ongoing conversations with new, large industrial customers looking to build in Lansing.”
The Delta Energy Park plant entered service in March and was built by a combination of local and national firms, including Lansing Power Constructors, a joint venture of Lansing’s Clark Construction and Barton Malow, as construction manager; Black & Veatch as design engineer; Sergeant & Lundy as owner’s engineer; and Michigan’s Consumers Energy as transmission line contractor.
BWL has around 100,000 electric customers, 58,000 water customers, 155 steam customers and 19 chilled water customers.
Power Generated by Natural Gas Set a New Record in July, EIA Says
August 29, 2022
by Peter Maloney
APPA News
August 29, 2022
Electric power generated by natural gas-fired plants hit a record in July, beating the record set in July 2020, according to the Energy Information Administration (EIA).
Gas-fired generation in the lower 48 states hit 6.37 million megawatt hours (MWh) on July 21, 2022, despite relatively high natural gas prices, according to the EIA’s Hourly Electric Grid Monitor.
The previous record, set on July 27, 2020, was reached when natural gas prices were historically low.
Demand for natural gas for electricity generation has been strong throughout July as a result of above-normal temperatures, reduced coal-fired electricity generation, and recent natural gas-fired capacity additions, the EIA said.
Electricity demand usually peaks in the summer because of demand for air conditioning, and this July was especially hot, ranking as the third hottest on record in the United States.
Despite higher prices, electric sector demand for natural gas remains high. This July, the Henry Hub natural gas price averaged $7.28 per million British thermal units (MMBtu). In July 2020, the natural gas at Henry Hub price averaged $1.77/MMBtu.
In June, the EIA said natural gas spot prices would remain high throughout 2022 with a forecast of the Henry Hub price to average $8.71/MMBtu through August.
Higher gas prices usually push electric generators to turn to other fuels, such a coal, but this summer coal-fired plants have not been used as much as in prior summers because of continued retirements of coal-fired plants, relatively high coal prices, and lower-than-average coal stocks at power plants.
In May, coal inventories at power plants averaged 20 percent lower than prior year levels, the EIA said. In December the EIA said coal stockpiles at electric power plants reached their lowest levels since 1978.
Earlier this month, the EIA said increased economic activity and hot summer weather would increase electricity consumption this year by 2.4 percent over 2021 levels, according to the agency’s Short-Term Energy Outlook (STEO).
Possible Extension Of California Nuclear Power Plant’s Operation Gets Closer Look
August 29, 2022
by Paul Ciampoli
APPA News Director
August 29, 2022
A California Senate Committee on Aug. 25 held a hearing on the possible extension of the operation of the Diablo Canyon Power Plant (DCPP), California’s only remaining operating nuclear power plant.
The hearing was held by the California Senate’s Committee on Energy, Utilities and Communications.
In June 2016, California investor-owned utility PG&E said it planned to retire Diablo Canyon nuclear power plant in California under a joint proposal with labor and environmental groups. The California Public Utilities Commission in 2018 signed off on a request by PG&E that it be allowed to retire the Diablo Canyon nuclear plant by 2025. The two units at Diablo Canyon together produce approximately 2,300 net megawatts of power.
A background memo prepared for the hearing by the California Senate Committee noted that in late April of this year, California Governor Gavin Newsom commented on the possibility of extending operations of the DCPP, as well as natural gas plants that like DCPP are subject to retirement due to State Water Board regulations regarding once-through-cooling facilities that impacts ocean water and marine life.
“Since then, there have been a number of news reports and a Joint Agency Workshop as recent as two weeks ago to discuss the need, option, and hurdles to extending operation of DCPP,” the memo noted. “The Newsom Administration has noted the opportunity to secure federal funding from the U.S. Department of Energy’s implementation of the Infrastructure Investment and Jobs Act, specifically a pending September 6th application deadline for currently operating nuclear facilities.”
Newsom recently proposed to extend operations of the DCPP.
In a presentation at the hearing, Ana Matosantos, cabinet secretary to Newsom, said that the DCPP proposal creates the conditions for an extension of Diablo Canyon “for the shortest amount of time necessary to be able to maintain the goal of reliability and continuing to move forward on our transition.” She said that proposed extension is for a five-year period with the possibility of revisiting that duration.
Maureen Zawalick, Vice President of Decommissioning and Technical Services at Pacific Gas and Electric Company (PG&E), said at the hearing that an extension of the nuclear plant would require a number of federal and state regulatory approvals.
“There are also some critical near-term activities we would have to quickly undertake to make a viable option for the state including funding, fuel purchasing and used fuel management,” she said. “The fuel purchasing and used fuel management take about an 18 month to two-year lead time. And we also need to be ramping up a project team to support the NRC license renewal application.”
Other witnesses at the hearing included Hunter Stern, Business Representative, International Brotherhood of Electrical Workers, Local 1245; Ralph Cavanagh, energy Program Co-Director, Natural Resources Defense Council; Bruce Gibson, Supervisor, Chair of the Board, County of San Luis Obispo; Kim Delfino, Representative, Defenders of Wildlife and the California Coastal Protection Network and Mark Toney, Executive Director, The Utility Reform Network.
Meanwhile, a group of California lawmakers this month unveiled a proposal that “would reject Gov. Gavin Newsom’s plan to extend the lifespan of the state’s last operating nuclear power plant — and instead spend over $1 billion to speed up the development of renewable energy, new transmission lines and storage to maintain reliable power in the climate change era,” the Associated Press reported.
California mayors send letter to Newsom
Also this month, the mayors representing nine cities on California’s Central Coast sent a joint letter to Newsom on Monday sharing policies that they are requesting Newsom include in any legislation that explores the extension of Diablo Canyon Power Plant’s operations.
Officials said that the goal of the letter is to help shape the legislation with a set of guiding principles that include, among other things, ensuring the safe operation of the power plant, limiting the term of the extension and tying it to making sure the state has enough renewable energy and battery storage to replace the power plant when the license extension expires and finding a safe solution for the long-term storage of the spent fuel that is currently being stored at DCPP.
The letter is available here.
Ariz. Public Power And Cooperative Groups Urge PG&E To Extend Nuclear Plant’s Operating Life
In a June 2022 letter to Patricia Poppe, CEO of PG&E, officials with the Irrigation & Electrical Districts’ Association of Arizona (IEDA), the Arizona Municipal Power Users’ Association (AMPUA) and the Grand Canyon State Electric Cooperative Association (GCSECA) made the case for extending the life of the California nuclear power plant Diablo Canyon Power Plant past its existing license.
The letter was signed by Ed Gerak, executive director of IEDA, AMPUA’s Russell Smoldon, and Dave Lock, CEO of GCSECA.
“While we understand that the history of the plant is long and complicated, we hope that you will agree that the benefits of extending the operating license outweighs the cons,” they wrote.
California Approves Rules Requiring All New Cars To Be Zero Emission By 2035
August 28, 2022
by Peter Maloney
APPA News
August 28, 2022
The California Air Resources Board last week approved a rule that requires all new cars and light trucks sold in California will be zero-emission vehicles (ZEVs), including plug-in hybrid electric vehicles, by 2035.
The Advanced Clean Cars II (ACCII) rule establishes a year-by-year roadmap that codifies the light-duty vehicle goals set out in Governor Gavin Newsom’s Executive Order N-79-20.
The ACC II rule is the second phase of California’s Advanced Clean Cars Program adopted by CARB in 2012 that was designed to bring together CARB’s passenger vehicle requirements to meet federal air quality standards and to support AB 32, the law that called for greenhouse gas emissions to be reduced to 1990 levels by 2020, which was achieved in 2016. ACC II is also “a major tool” in the effort to reach the SB 32 target of reducing greenhouse gases an additional 40% below 1990 levels by 2030. SB 32, ratified in 2016, amended the goals of AB 32, which was passed in 2006.
ACC II applies to automakers, not dealers, and covers only new vehicle sales. It does not affect existing vehicles on the road, which will still be legal to own and drive.
The rule accelerates requirements that automakers deliver an increasing number of zero-emission light-duty vehicles each year beginning in model year 2026. Sales of new ZEVs and plug-in hybrid electric vehicles will start with 35 percent that year, build to 68 percent in 2030, and reach 100 percent in 2035.
ACC II specifies that plug-in hybrid, full battery-electric, and hydrogen fuel cell vehicles count toward an automaker’s requirement under the rule, but further specifies that plug-in hybrid electric vehicles must have an all-electric range of at least 50 miles under real-world driving conditions. Automakers will be allowed to meet no more than 20 percent of their overall ZEV requirement with plug-in hybrid electric vehicles.
Battery-electric and fuel cell vehicles will need a minimum range of 150 miles to qualify under the ACC II rules, as well as fast-charging ability and must come equipped with a charging cord to facilitate charging and meet new warranty and durability requirements.
By model year 2030, the rules require vehicles to maintain at least 80 percent of electric range for 10 years or 150,000 miles. That goal is phased in from 70 percent for 2026 through 2029 model year vehicles.
By model year 2031, individual vehicle battery packs must be warranted to maintain 75 percent of their energy for eight years or 100,000 miles with a phase-in schedule of 70 percent for 2026 through 2030 model years.
The rule also calls for ZEV powertrain components to be warranted for at least three years or 50,000 miles.
ACC II also updates regulations for light- and medium-duty internal combustion engine vehicles with lower emission standards that CARB says will “complement more significant emission reductions gained by wider ZEV deployment” and help to “prevent potential emission backsliding by removing ZEVs from the emissions baseline used to calculate new vehicle fleet-average emissions.”
California’s budget includes $2.7 billion in fiscal year 2022-23 and $3.9 billion over three years, for investment in ZEV adoption.
The ZEV budget includes $400 million over three years for the statewide expansion of Clean Cars 4 All, which provides up to $9,500 to low-income drivers who scrap older vehicles to purchase cleaner running vehicles.
The budget also includes $525 million for the Clean Vehicles Rebate Project, which provides up to $7,000 for income-qualified drivers to buy or lease a ZEV.
And the ZEV budget provides $300 million for more charging infrastructure, especially for consumers who do not have a garage.
CARB says its analysis indicates that battery-electric vehicles are likely to reach cost parity with conventional vehicles by 2030 and that by 2035 consumers are likely to realize as much as $7,900 in maintenance and operational savings over the first 10 years of ownership.
CARB said that states that follow California’s vehicle rules are expected to adopt similar regulations. Those states constitute about 40 percent of the nation’s new car sales, CARB said.
Those states are Colorado, Connecticut, Delaware, Maine, Maryland, Massachusetts, Minnesota, New Jersey, New York, Oregon, Pennsylvania, Rhode Island, Vermont, Washington.
APPA Weighs In On National Electric Vehicle Infrastructure Formula Program
August 23, 2022
by Paul Ciampoli
APPA News Director
August 23, 2022
The American Public Power Association (APPA) recently responded to a request for comments from the Federal Highway Administration (FHA) on a notice of proposed rulemaking for the National Electric Vehicle Infrastructure (NEVI) Formula Program. Among other things, APPA commented on the need for flexibility on the number of ports and charging capacity for Electric Vehicle Supply Equipment (EVSE).
A section of the proposed rule includes requirements for the installation, operation, and maintenance of NEVI Formula Program funded chargers. Specifically, this section proposes to require four Combined Charging System charging ports capable of simultaneously charging four electric vehicles, with each port being capable of charging at least 150 kW. This means a NEVI-compliant charging station would be required to serve at least 600 kW at any given time.
APPA noted in its Aug. 22 comments that public power utilities are already actively working with their communities to advance transportation electrification. However, “this level of new load could be a challenge depending on the unique circumstances of the local utility and grid. For some APPA members this additional load could double their current overall load and, even for utilities serving a larger load, charging stations at this capacity level will still require significant and costly utility upgrades to support.”
To address this challenge, APPA offered two recommendations.
First, APPA recommended providing the maximum possible flexibility in implementing the requirement that NEVI-compliant charging stations include four, 150 kW minimum, charging ports.
It noted that in certain areas with low utilization levels, EV drivers may be fully served by two 150 kW ports in the near-term and additional ports could be added subsequently during the five-year NEVI program. “Additionally, states should be strongly encouraged to include the cost of necessary electric infrastructure upgrades when providing grants to fund NEVI stations.”
Additionally, grant recipients should also be able to futureproof stations and upsize design (lot sizes, transformers, conduit, wire/cable/etc.) to enable rapid deployments of additional chargers at the sites as demand grows, APPA said.
APPA also recommended that stakeholders, including NEVI station owners, operators, and site hosts, talk to utilities early about connecting to the grid. “This engagement will allow public power utilities to plan for future load and any upgrades as well as provide crucial advice on how to deploy this infrastructure.”
The program also that “states must ensure that EVSE is maintained in compliance with NEVI standards for a period of not less than 5 years from the date of installation.”
APPA “encourages states to require clear, comprehensive, and detailed contractual agreements for any maintenance and operation requirements. For example, contracts should specify turnaround timeframes for maintenance and describe if the scope includes maintenance for operational issues due to theft and vandalism. This is vital to ensuring a positive customer experience, but ongoing and proactive maintenance is also needed to support charger reliability.”
The FHA also proposes requirements for the workforce installing, maintaining, and operating NEVI-funded EV charging stations, including requirements that all electricians be either certified through the Electric Vehicle Infrastructure Training Program or a graduate from a Registered Apprenticeship Program that includes EVSE-specific training and is developed as part of a national guideline standard approved by the Department of Labor in consultation with the Department of Transportation.
APPA voiced concerns about this requirement, particularly given the size and scope of the NEVI Formula Program, which aims to deploy 500,000 EV chargers around the country. “This effort will absolutely require an appropriately trained and qualified workforce; however, additional flexibility regarding training specifics will allow more workers to qualify in a timely manner.”
Meanwhile, APPA also expressed concerns about the program’s proposal that NEVI-funding charging stations be required to display and base the price for charging in $/kWh.
“APPA has concerns with this requirement, particularly that it will limit innovation in pricing from site hosts and other stakeholders. For example, public power utilities have already utilized a variety of billing techniques including price per kWh, price per minute, subscription fees, and connection or idling fees that may be in combination with other fee types.”
APPA noted that an idling fee would encourage responsible EV charging practices and allow for the most efficient use of chargers by the most consumers. Some public power utilities are using time-of-use structures within these billing techniques. “This can help incentivize off-peak charging as well as provide drivers with a more accurate price signal for the cost to charge their vehicle. As not-for-profit entities, the main goal of public power utility rate design is to recover the cost of providing service. It is important that pricing structures for charging infrastructure allow flexibility for owners to recover costs such as installation, maintenance, and make-ready infrastructure upgrades.”
APPA also addressed the question of whether there are factors that could be considered to avoid an instance of charging the consumer too high a price for electric vehicle charging, particularly when demand is high, and supply is low.
“APPA strongly believes that electric rate design is a state and local decision. Ratemaking at public power utilities is conducted in an open and transparent manner and is subject to approval by the utility’s governing body.”
Supply Chain And The Need For Flexibility
APPA also used its comments to highlight ongoing supply chain challenges facing the electric utility sector.
If supply chain issues persist into the long-term, “they could impact the ability for electric utilities to deploy the infrastructure necessary for the EV charging network envisioned by the NEVI program, as well as many of the other electric infrastructure projects that will be supported by the Infrastructure Investment and Jobs Act (IIJA).”
Implementing federal and state agencies “should consider what tools they can deploy to help the electric industry ensure the supplies and materials, as well as the necessary workforce, are in place to efficiently and effectively make this significant and needed infrastructure investment.”
APPA also said that NEVI grant programs should be designed with flexibility in mind, noting that every community is different and project needs will vary. “Technology is evolving and EV and charging infrastructure usage will change with higher adoption. One-size-fits-all programs will be inaccessible or unworkable for many public power utilities.”