- 19M-0670E – Distribution System Planning (filing comments on Monday, 2/3)
- 19M-0661EG – Investigation of Performance-Based Ratemaking (awaiting the second phase)
- 19R-0608E – NOPR for Amendments to Community Solar Gardens Rules
- 19R-0654E – Amendments to Electric Rules Relating to Interconnection
- 19A-0471E – Investment in EV Fleet Infrastructure
We’re also awaiting a decision on the following:
2020 Outlook: New state action on customer empowering rate designs and business models
Regulators, utilities and stakeholders will pilot simple price signals and work toward agreement on a performance-based framework, but California may be in for a surprise.
Herman K. Trabish, Utility Dive, Jan. 23, 2020
In 2020, the way utilities charge customers and the business models they use could change electricity users’ role in the energy transition and support the enhanced adoption of new technologies.
Only about 6% of U.S. electricity customers now pay through rates that give them a role in the types of energy they use and when they use it. The rest use a rate that discourages customer interest, encourages no change in the power mix and gives utilities no motive to evolve, according to advocates for more dynamic rates. But 2020 promises major advances by state regulators in rate design and power provider incentives.
Efforts by state regulators and legislators in 2020 will show “the power of the states over the future of the electricity system in the absence of federal action,” Energy Innovation (EI) Director of Electricity Policy Michael O’Boyle told Utility Dive. “States can and will move on their own and they are creating a framework and a foundation for change.”
Utilities can now use new technologies, like smart meters and solar+storage, and new power system dynamics, like the shifting time of peak energy demand, to benefit their customers and their systems. In 2020, advanced rates with price signals to direct electricity use and business model reforms to align customer and provider needs could begin delivering big benefits. But one of 2020’s biggest steps forward, to be taken by California, may be a misstep, a leading rate design authority said.
Complexity versus simplicity in 2020
In Q3 2019, “28 states plus D.C. took actions to reform rate designs, regulatory structures or utility business models,” the newest quarterly policy update from the North Carolina Clean Energy Technology Center (NCCETC) reported. Rate design reforms were considered in 21 states and utility business model or ratemaking adjustments were undertaken in D.C. and 22 states.
Decisions and implementations of time of use (TOU) and other time-varying rates, including critical peak pricing, peak time rebates, and demand charges, and of simple subscription rates are coming in 2020, NCCETC Senior Policy Research Manager and quarterly lead author Autumn Proudlove told Utility Dive. These rates’ price signals discourage customer electricity usage during peak demand periods.
Critical peak pricing imposes significantly higher prices during critically high demand events, when system costs are highest or when the power grid is severely stressed. Demand charges add an extra cost to the monthly bill based on the customer’s single highest period of electricity consumption. And peak time rebates reward customers for load reductions during forecast critical periods.
“Providing more customer-friendly [rate] options also increases a utility’s ability to address the complexities in an electricity system with more renewables, more extreme weather events, and more customer-owned resources.”
VP for Rate Design and Strategic Solutions, Duke Energy
With subscription agreements, tiered price contracts would be based on the amount of monthly consumption and the amount of peak consumption. Customers could save money by choosing lower consumption. And electricity providers’ greater load certainty would allow them to more cost-effectively and reliably manage their systems.
In 2020, debates will continue on how to balance complexity and simplicity in rate designs, but regulators’ inclinations will begin to be clarified, Proudlove said.
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Subscription pricing proposals may be decided in Arizona, Nevada, and Vermont in the coming year, according to NCCETC. Proposed pilots of more complex time varying rates will likely be ruled on for the Hawaiian Electric Companies (HECO) and Michigan’s DTE Energy.
This movement toward more advanced rate designs has largely been limited simply to TOU rates with more than the typical on-peak and off-peak time periods, Proudlove said. Newer ones, expected to see regulatory rulings in 2020, include critical peak periods or peak time rebates.
Hawaii’s Advanced Rate Design Strategy includes “time-varying rates, critical peak incentives, multi-part time-varying rates, and electric vehicle rates,” NCCETC reported. Michigan’s Advanced Customer Pricing pilot includes “two time-varying rates, two demand rates, and two rates combining time-varying and demand elements.” A National Grid pilot in New York includes both a TOU rate and a subscription rate.
These multi-faceted rate designs reflect an increased demand from customers for options, Duke Energy VP for Rate Design and Strategic Solutions Lon Huber told Utility Dive. “Providing more customer-friendly options also increases a utility’s ability to address the complexities in an electricity system with more renewables, more extreme weather events, and more customer-owned resources.”
There is a tendency for regulators and policymakers to be too prescriptive, Huber said. By being more flexible, they can identify better rate designs and modify them based on what they learn as they are implemented. Duke’s new fixed bill product in Florida, which attracted over 55,000 customers in its first year, “has built-in flexibility as well as the certainty that reduces worry and stress about the bill.”
Utilities seem inclined “more toward complexity than simplicity,” Proudlove said. But it is provoking pushback from stakeholders “concerned that customers cannot understand and respond without automated, set-it-and-forget-it type technologies.”
The trend toward greater complexity will continue, but utilities and policymakers will “start looking at the bigger picture in 2020,” she said. They will give “more attention to providing customers with the tools and education to respond to the price signals built into the complex time varying rates.”
There will also be more transportation electrification proposals in 2020 and many will likely include EV-specific TOU rates, she added. Rulings are expected in 2020 on Southern California Edison (SCE) and Pacific Gas and Electric (PG&E) solutions to the impediment that demand charges present to charger deployment.
Key results on time varying rate design implementations are expected in Maryland and California in 2020, Brattle Group Principal Ahmad Faruqui, who has advocated for such rates since the 1980s, told Utility Dive.
“Baltimore Gas and Electric, Delmarva, and Pepco did separate PC 44 pilots of time varying rates for low-income customers and other customers in Maryland,” Faruqui said. Results, expected in Spring 2020, will show more clearly than other trials of advanced rates “whether the impacts are different on low-income customers, which is one of the biggest objections to advanced rates.”
In California, SCE and PG&E will join the transition San Diego Gas and Electric (SDG&E) began this year of over 20 million residential customers to default TOU rates by 2021. It is the biggest U.S. implementation of default TOU rates ever. But that is not the big news about California’s rollouts, Faruqui said.
“High penetrations of renewable and distributed energy will require more real-time pricing and automated prices-to-devices technology.”
Principal, Brattle Group
The California reveal
Many customers have successfully adapted to advanced rate designs, Faruqui said. His analysis of 349 TOU rates around the world shows that the higher the on-peak price to off-peak price ratio is, the more customers reduce peak electricity usage, he said. “And if the price signal is accompanied by enabling technology, they reduce their peak electricity usage even more.”
But progress on new electricity rates has been impeded by regulators’ and utilities’ “fears of political pushback” if advanced rates cause higher bills or complications that customers refuse to accept, he said. And those fears may cause that very pushback in California, he said.
Data shows TOU rates will provide a change in usage of about 3% to 4% “if the on-peak to off-peak ratio is 2 to 1, but the California TOU rates have an anemic ratio of less than 1.5 to 1,” Faruqui said. “That price discount is too small to give customers a reason to change their behavior, which means the rate transition will not impact peak demand, accelerate renewables or deliver customer savings.”
California’s on-peak to off-peak ratio is little more than “paying lip service” to the idea of advanced rates and may result in another “Puget Sound Energy fiasco,” he added. Puget Sound’s planned 2001-2002 transition of 300,000 customers to a default TOU rate with only a 1.3 to 1 ratio led to customer revolt and a program shut down when it became clear promised bill savings would not materialize.
“Hawaii is expected to solidify its position as the national leader through phase two of its PBR proceeding in 2020 and everyone is watching.”
Director of Electricity Policy, Energy Innovation
“California customers may revolt for the same reason,” Faruqui said. “They will return to putting solar on their roofs to lower their bills, which will make the state’s solar over-generation issue worse and do nothing to address peak demand. It seems to me California has not learned the lesson in the Puget Sound experience.”
The consolation is that “TOU rates are not the solution to the problems the system will face in the coming years,” he added. “High penetrations of renewable and distributed energy will require more real-time pricing and automated prices-to-devices technology.”
California will make substantive progress on understanding how customers respond to those more dynamic rates in 2020, California Solar+Storage Association (CalSSA) Senior Advisor for Regulatory Affairs Scott Murtishaw told Utility Dive. It will come from a TOU pilot for large C&I solar+storage owners implemented in 2019.
The pilot offers a 3-to-1 or higher price ratio from peak to super-off-peak, a demand charge that targets the system peak, and “the first daily peak demand rate in California,” Murtishaw said. All three reward customers for reducing peak load.
Current rates reward midday storage discharge, which “only adds to the over-generation challenge,” and does not “align with system benefits by reducing peak demand,” Murtishaw said. “The 2020 enrollment data will show if customers respond to the new rate.”
PBR matures in 2020
Performance-based regulation (PBR), long pushed by utility business model reform advocates in the U.S., would align utility earnings strategies with customer demand by awarding performance incentives for achieving policy goals. It has had only partial implementations, but “Hawaii is expected to solidify its position as the national leader through phase two of its PBR proceeding in 2020 and everyone is watching,” EI’s O’Boyle said.
Phase two workshops started in August, Dan Cross-Call, Electricity Practice Manager for workshop facilitator Rocky Mountain Institute, told Utility Dive. They will address “performance incentives and other details of how revenue determinations will work.”
In 2020, Hawaii’s regulators are “committed to making sure the utility is able to recover its costs and make a fair return,” Cross-Call said. “But how much that return is would be determined by the utility’s performance against the PBR structures that will be established in this proceeding.”
In phase one of Hawaii’s PBR proceeding, completed in May, stakeholder groups established “goals” and “outcomes related to the goals,” Commissioner Jennifer Potter, who is leading the proceeding, had told Utility Dive.
HECO rate cases completed by the end of 2020 will further “lay the foundation for PBR” and, over the following five years, lead to a” performance-based regulatory framework.” Potter added in December.
But important new PBR efforts are also emerging across the U.S., EI’s O’Boyle said.
In Minnesota, Xcel Energy, the state’s dominant electricity supplier, will begin to work with performance metrics in 2020 and report on their impacts in early 2021, O’Boyle said. In New York, regulators will evaluate how well performance incentives approved for Consolidated Edison in 2017 have worked and “what needs to change in the approach they adopted three years ago.”
Michigan may be furthest along among a “new wave of states in earlier stages of PBR development,” O’Boyle said. A stakeholder PBR process will open in 2020 and lead to “concrete” performance incentives and mechanisms.
Nevada’s legislatively-mandated investigatory PBR proceeding will, during 2020, “build a record that would then support something more substantive,” he said. And Colorado will undertake an investigation to determine if transitioning to PBR, “based on performance metrics and incentives, would be ‘net beneficial.’”
Rhode Island regulators will refine and potentially apply new performance incentive mechanism design principles in 2020 intended to provide guidance on PBR’s net benefit, he added. And Oregon regulators have indicated they “may consider PBR in 2020.”
In 2020, “we may see a complete spectrum of PBR initiatives that includes a possible proposal, a new study, interim proceedings, a deeper look at incentives, and Hawaii’s detailed PBR construct,” O’Boyle said. “It reflects the maturing of the PBR idea as utilities, regulators, and stakeholders search for a new framework that puts the customer and decarbonization at the center of the utility business model.”
Xcel assesses non-wires alternatives to distribution upgrade as it enters new proceedings in Colorado, Minnesota
Jan. 30, 2020
- Xcel Energy recently worked with the Electric Power Research Institute (EPRI) to assess the use of demand side management (DSM) and energy storage compared to a conventional upgrade for a feeder on its distribution system, Xcel and EPRI officials said at DTECH on Tuesday.
- The analysis found DSM resources more cost effective than energy storage. “So it makes sense to first utilize the DSM resources as much as you can,” Jouni Peppanen, a technical leader in EPRI’s power system studies group, told conference attendees. But the net benefits from scenarios that included storage were higher than those with DSM only, he noted.
- Xcel now wants to have its own modeling tools to conduct such an analysis and help understand the details of its DSM program and how to apply it.
Xcel is entering into distribution planning regulatory proceedings in Colorado and Minnesota and teamed up with EPRI to conduct a non-wires alternative analysis to verify some of the assumptions it was making regarding the potential need for upgrades.
“These proceedings really are more about transparency on our distribution planning process and one of the things that our stakeholders are interested in is non wires alternative,” said Beth Chacon, director of grid storage and emerging technology at Xcel Energy. The company is assessing the use of distributed energy resources (DER) to serve as alternatives to traditional upgrades.
The project in question was a small part of Xcel’s distribution system eligible for an upgrade in terms of increased capacity and distribution. “And we took an approach, primarily with our demand side management or energy efficiency and demand response programs, to look at non wires,” Chacon said.
Xcel also looked at the option of adding energy storage, which can also help reduce distribution constraints, while examining other energy storage capabilities like energy arbitrage and reserve capacity, she noted.
The wires alternative Xcel and EPRI examined was to add a new substation transformer base at a cost of about $10 million. There’s no more capability to add another feeder to this existing transformer, she noted.
“Our goal was to really look first at DSM but also compare that against the cost of energy storage,” she said, adding that Xcel didn’t have a lot of PV participation in the particular area of its distribution system being studied, so it didn’t look much at that.
The modeling confirmed the company’s initial assumptions that energy efficiency and demand response “are a good way to do this particular non-wires alternative, and also there’s a possibility for storage,” Chacon said.
But “early on in the analysis, it was clear that the demand side management resources are more cost effective than energy storage. So it makes sense to first utilize the DSM resources as much as you can … and then, as needed, complement the DSM with energy storage,” Peppanen noted.
Xcel and EPRI looked at five scenarios — a conventional, wires-based upgrade and four alternative scenarios with different combinations of DSM along with utility owned and operated storage that’s close to the substation.
For the analysis, DSM resources were put into two categories: fixed resources, such as air conditioner retrofits and home insulation, which result in a constant load reduction throughout the year, whenever they are needed; and flexible DSM resources, such as smart thermostats, that result in load reductions subject to certain limitations. The analysis assumed some expansion of these resources from 2018 to 2025, but no expansion after 2025.
In addition to understanding the potential power capacity from the DSM resources, there was also a need to understand the limitations to their use, which are not always hard limits, Peppanen said. For example, if a customer is involved too frequently in a DSM program, they might opt out of it. The analysis assumed certain limits on the use of the resources.
The question then became how far into the future could Xcel defer the distribution upgrade if it used the existing and expanded DSM resources and how much storage would it need.
The storage was sized based on the load peaks not being addressed with the demand side management, as well as how Xcel would dispatch the DSM resources along with the storage — about 1.7 MW, 2.4 hours when paired with existing DSM resources, somewhat smaller with expanded DSM resources, according to Peppanen.
Looking at the results of the analysis, the existing DSM allowed Xcel to defer the distribution upgrade until 2025. “If we expand the DSM resources, we get through 2026,” Peppanen said.
With no DSM or storage, Xcel would need the distribution upgrade in 2021. With the storage, Xcel could defer the upgrade through 2027, though that was simply the end of the time horizon for the analysis.
Peppanen said that while all four alternatives to the conventional upgrade break even, “expanding the DSM resources also makes sense because it essentially results in higher net benefits compared to using just the existing resources.”
In addition, the cost of the storage assets was smaller than the value of the deferral, so that “the net benefit from the scenarios with storage [were] higher than the net benefits from the scenarios with DSM only,” he said.
But what do these results potentially mean for Xcel in practical terms, beyond the specifics of whether to upgrade a particular feeder?
“It was nice that we had the modeling tool to really understand … all the details of our DSM program,” Chacon said.
“Should we do extra marketing in this area? Should we really work with builders who are building new homes in the area to target higher efficiency in those models?” she said, adding that it was very helpful to learn how energy storage plays a role and can also be brought in later, if needed.
She also noted that Xcel recently did some screening on other feeders and in most cases, “you really need a situation where you’re looking to defer an upgrade of a transformer because otherwise it’s usually more economical to make the wires upgrade.
The analysis is complex and can’t be done on every feeder, but Xcel has a screening process to help with that. And now, Xcel wants to have its own modeling capabilities and is “waiting on some great tools to evolve,” Chacon said.
Coal plants increasingly operate as cyclical, load-following power, leading to inefficiencies, costs: NARUC
Jan. 29, 2020
- Coal plants are increasingly operating as cyclical or load-following generation units, as the power market becomes more saturated with intermittent resources, according to a Jan. 24 whitepaper from the National Association of Regulatory Utility Commissioners (NARUC).
- Particularly in states with a high renewables penetration, such as wind-heavy Kansas, Oklahoma and Iowa, coal-fired power plant operations have changed dramatically, which poses physical and financial risks to the facilities, according to the paper. Overall coal capacity factors, or how much actual power the plants generate versus how much they’re capable of generating, dropped to 54% in 2018, down from 74% in 2008.
- “There’s a lot of talk going on about how coal plants are operating or what’s happening with the coal fleet,” Wyoming Public Service Commission Chair Kara Fornstrom, who moderated a webinar on the topic, told Utility Dive. “To be able to look at those charts and see the significant change in this in the last 10 years in terms of [coal plant] capacity factors and what they’re operating at, compared to what they were designed to operate at … those numbers are just pretty startling.”
Coal plants are becoming increasingly less economic to operate as a baseload resource, according to the Union of Concerned Scientists, and more utilities across the Southwest Power Pool and in the Midwest are cycling or load-following as their power prices are unable to compete. Though the report is consistent with findings of noneconomic coal dispatches from UCS and Sierra Club, environmental groups split off from the report authors when it comes to how markets should respond.
The power system needs flexible, backup resources paired with intermittent renewables, and proper methods to compensate those resources, which don’t currently exist, according to Energy Ventures Analysis Energy and Environmental Markets Manager and lead author of the report Phillip Graeter.
“[T]here does not exist a proper compensation mechanism that adequately pays backup flexible power generation, be it from natural gas, coal, or energy storage, to provide the needed backup during times of generation loss from these renewable resources,” he told Utility Dive in an email, adding generation loss “can account for more than 60% of generation in any given hour in power markets like [the Southwest Power Pool (SPP)] at this time.”
The Midcontinent ISO and PJM Interconnection are both in the process of developing new market mechanisms to support these changes, including a day-ahead market forecast and pricing tools to mitigate overnight financial losses, respectively. Meanwhile, the Electric Reliability Council of Texas and SPP have “acknowledged” such mechanisms are necessary, the report finds.
“What I think is important is that the markets understand that this is what’s going on [and] this report helps them to do that and that they will start down the path of at least considering compensation for certain attributes that these kind of facilities provide to the grid,” said Fornstrom.
Though environmental groups agree flexible resources are needed to be paired with renewables, what this report should really tell states and market operators is that high startup and shutdown costs should be included in tariffs, and incentives should not encourage coal operators to run their plants outside of merit order, Sierra Club Senior Strategy and Technical Advisor Jeremy Fisher told Utility Dive.
And although the report makes the argument that higher operation costs warrant better compensation in states and markets, Fisher said the report is just evidence that fewer plants are economic than they had initially thought.
“I don’t see this report as necessarily antithetical to anything that we’ve said about coal being non economically dispatched,” he said. “It lends a little bit of color, [but] I think some of the directions it has taken are missing the point to a large extent.”
Plants only operated at their highest efficiency capacity, 80%, 37% of the time in 2018, down from 55% in 2008, and plants spent more than 18% of the time operating below 60%, down from 12% ten years earlier.
In response to changing conditions, coal plants are left with two main operating options: to shut down completely or change their electric output.
Coal plants in general were not built to operate cyclically, and lack the flexibility and natural load-following capabilities of simple and combined cycle natural gas plants. Operating coal units in this way can lead to efficiency losses and high ramp rates are becoming more common.
All this can lead to physical issues for the units including thermal fatigue, corrosion and other strains on the facility, which can further ramp up operation and maintenance costs, as well as lead to increased plant outages, the report notes.
The paper “really makes it clear that we’re asking coal plants to do things that they weren’t constructed to do, and that there are costs associated with that,” said Fornstrom.
And because plants are making less money to fund the upgrades that would be necessary to finance some of this maintenance, operators “find themselves in a vicious cycle,” according to the report.
Fisher said groups like Sierra Club have asked utilities about these impacts in resource planning proceedings they’ve been involved in, but never received a “firm assessment” from utilities that these higher costs exist.
“I appreciate that we get better transparency into the clunkiness and potential impacts,” he said. But although the report largely credits high ramp rates to an increase in wind power on the grid, Fisher said the report fails to note that coal’s marginal economics are what is leading it to operate less and hit high ramp rates.
“The reason that coal is increasingly ramping on our electricity system today is because it is increasingly non economic to continue operating on an hour by hour basis,” he said.
Efficiency improvements and more guided operations could all help, according to the report but so could greater dispatches of resources such as energy storage and demand-side management, as well as better curtailment of wind and solar resources during times of high generation or low demand.
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New Jersey outlines sweeping plans to achieve 100% clean energy by 2050
Jan. 28, 2020
- New Jersey Gov. Phil Murphy released on Monday a wide-ranging plan with details on how the state could achieve 100% clean energy by 2050, a goal adopted by governors of both Massachusetts and Washington in the past month.
- The governor’s “Energy Master Plan” admits that New Jersey’s efforts to reduce greenhouse gas emissions thus far are insufficient to achieve the target of 80% reduction from 2006 levels set by the state’s Global Warming Response Act, passed last summer.
- Major proposals in the plan include additional steps to ensure that 7.5 GW of offshore wind is part of New Jersey’s energy mix by 2035. Murphy also announced proposals to have state regulators require utilities to explore “non-wire solutions” like storage and distributed energy resources (DERs) and establishing an electric vehicle “ecosystem” to build up EV charging infrastructure.
Murphy’s plan provides more specifics on how the state could meet its goals related to clean energy adoption based around seven areas: the transportation sector, renewable energy and DERs, energy efficiency, the building sector, the use of “integrated distribution plans,” incentivizing clean energy in underserved communities and attracting supply chain businesses to create clean energy “clusters.”
The Murphy administration had announced two major initiatives related to these areas: a November 2019 executive order set the goal of 7,500 MW of offshore wind by 2035, the second-largest such goal in the nation, and 2018 legislation aimed for 2,000 MW of energy storage by 2030.
On offshore wind, the plan calls for the New Jersey Board of Public Utilities to “develop a consistent and transparent solicitation schedule through 2035 that supports a steady, long-term Mid-Atlantic project pipeline. This procurement approach will enable long-term industry investment in core infrastructure and manufacturing facilities.”
The plan is a “promising boost” for New Jersey’s offshore wind power industry, the National Wildlife Federation (NWF) said in a press release.
Beyond utility-scale projects like offshore wind, the plan also calls for a focus on distributed energy resources like rooftop solar. It calls upon state utilities to establish “integrated distribution plans” that will “allow for the anticipated growth of DER and EV charging on the electric distribution system,” including changes in rate structures to encourage DERs.
Another strategy outlined by the governor looks at the state’s building sector, which accounts for 62% of New Jersey’s total end-use energy consumption, according to the plan. The document calls for New Jersey to “electrify its state facilities, partner with private industry to establish electrified building demonstration projects [and] expand and accelerate the current statewide net zero carbon homes incentive programs for both new construction and existing homes,” among other measures.
The Consumer Energy Alliance, a group that represents business interests as well as large energy companies like ExxonMobil, criticized the plan for failing to present its costs. “While we support greater inclusion of renewable energy sources in New Jersey’s energy mix, it is highly worrisome that the state was unwilling to make the cost of this plan on ratepayers public,” Consumer Energy Alliance Mid-Atlantic Director Mike Butler said in a statement.
The master plan recommendations are based on a report developed by the New Jersey Board of Public Utilities and the New Jersey Department of Environmental Protection along with contractors the Rocky Mountain Institute and Evolved Energy Research. The Integrated Energy Plan “identifies the optimal, least-cost approach to reach 100% clean energy by 2050 based on today’s most cost-effective technologies,” according to the master plan.
- STATE OF NEW JERSEY 2019 New Jersey Energy Master Plan
Electric Vehicle Adoption in California Could Increase Gross State Product by More Than $140 Billion: Report
Electrification of light-duty vehicles in California could be a potent catalyst for economic growth over the next 10 years. That’s according to a new study by Next 10 on the impact on the California economy if the state achieves electric vehicle (EV) adoption that is consistent with its climate goals.
The report, “Clean Transportation: An Economic Assessment of More Inclusive Vehicle Electrification in California,” was prepared by Berkeley Economic Advising and Research and assesses the economic implications of the projected increase in electric vehicle use with a long-term economic forecasting model — focusing on the policy milestone years of 2030 and 2050. Even under a relatively conservative baseline scenario that assumes no improvement in EV costs in the coming 10 years, EV adoption could result in significant economic benefits by stimulating the overall economy, reducing harmful pollution, and improving public health outcomes, the report notes. Other scenarios that consider anticipated drops in price and increase in innovation show even greater gains.
Key findings include:
- Successfully hitting California’s 2030 GHG reduction goals with the scale of increased EV adoption modeled in this study would create more than 390,000 new jobs under a relatively conservative scenario — and more than half a million new jobs in the scenarios that account for steeper declining costs and increasing model choices.
- By 2030, the Gross State Product would increase between $82 to $142 billion, depending on the scenario analyzed.
- Real income (income adjusted for inflation) is projected to increase substantially, ranging between $311 billion to $357 billion in 2030.
- This overall economic expansion has significant fiscal benefits – generating billions in additional revenue per year from existing tax instruments.
- Looking out to 2050,the economic benefits increase by up to seven to eight times over those in 2030, depending on the scenario. Even under a relatively conservative estimate, California’s GSP stands to increase by about 5% by 2050. Under scenarios that reflect more likely vehicle cost reductions — the gains are almost twice as large.
The report notes that the manufacturing of fuel-efficient vehicles is already associated with 14,776 jobs in California — and more indirect employment could be generated through increased demand for charging infrastructure and utility load. The projected job growth and economic benefits noted in the study come from avoided fuel costs alone.
Other findings include:
- Employment and income benefits are proportionately higher among Disadvantaged Communities (DAC) even though they represent only 25% of the state’s population. This is because the dollars spent from fuel savings will go primarily to goods and services industries — sectors that disproportionately employ DAC workers.
- By 2050, the Innovation scenario—which assumes greater cost savings through improved technology costs — creates 1.182 million additional jobs across the state, with more than 36% benefiting DAC households.
- The study focused on Los Angeles County and the Central Valley as 75% of the state’s DACs are in these regions. By 2050, under the Innovation scenario, DACs in both regions would see substantial incremental employment benefits (192 jobs created per DAC in LA County and 216 per DAC in the Central Valley).
- Air pollution reductions from large-scale electric vehicle adoption also benefit DAC households more than higher-income groups. The study found that in an equity scenario, the economic value of health benefits from the reduction in pollution would amount to $2 billion by 2030 — including $800 million from avoided mortality and $1.2 billion from averted medical costs.
“The benefits to GSP and income are much larger than some other climate policies, including California’s cap-and-trade program and far exceed the funds committed thus far to clean vehicle incentive programs,” noted David Roland-Holst, BEAR Managing Director and Economics professor at UC Berkeley, and lead author of the report. “Studies have shown that incentives are successful in helping car buyers opt for cleaner alternatives, and what we see here is that increased EV adoption, especially in lower-income communities, can have a measurable and lucrative payback.”
Currently, the state is planning to significantly curtail budgeting for electric car and light-duty SUV incentives.