MISO is refreshing its longstanding “parking lot” of improvement ideas submitted to the grid operator, some of which have been in a holding pattern for the better part of a decade.
The RTO has conducted an internal review on how it handles issues relegated to the parking lot until MISO stakeholder committees deem it’s time to reexamine them. Some stakeholders have said topics they’ve brought forward can languish on the list.
Alison Lane, stakeholder relations lead, said during a Steering Committee teleconference Wednesday that MISO will now refer to inactive recommendations and will commit to their biannual reviews, beginning in 2024.
Staff will go before its large stakeholder committee meetings with a review and cleanup of the suggested improvements, Lane said. MISO will keep the issues that advance its imperative reliability work or that can be handled within the next three years and are supported by “the state of the industry’s” policies and technologies.
MISO currently has 36 issues in the parking lot, some of which are more than seven years old. Staff said some of the proposals have already been addressed with FERC rulemakings, as is the case with Order 2222 and allowing aggregators of distributed resources into the wholesale energy markets.
“We have every intention of being much more diligent on parking lot items” Lane promised earlier this year.
The parking lot designations were used under the RTO’s Integrated Roadmap process, where stakeholder input was used to annually prioritize a list of market tasks and improvements. MISO ended the practice last year. (See MISO Keeps Reduced Schedule for Rest of 2022.)
The grid operator is also encouraging a more standardized method for stakeholders to submit new issues that they think deserve MISO’s attention. After the roadmap process was scrapped, stakeholders said in public meetings they were left wondering how to broach ideas for improvements.
Staff stressed that stakeholders who want their ideas discussed in public meetings should complete its issues submission form. From there, the item is either directly considered by a stakeholder group or, when the assignment is less clear, the Steering Committee determines which stakeholder groups will take up the issues for consideration.
A measure that asks CAISO to report to California lawmakers on Western regionalization efforts and the potential benefits of greater interstate collaboration cleared the State Legislature last week, with some saying it could renew discussions of an RTO developed by the ISO.
“There is considerable potential for additional benefits for California consumers through further regional collaboration,” and the state should “collaborate, coordinate on policy, and share systems and resources with our neighboring Western states when opportunities for mutual benefit exist,” Assembly Concurrent Resolution 188 says.
“The legislature should have current and comprehensive information on the impacts to California of expanding the existing independent system operator into a regional organization that manages wholesale electricity markets, transmission planning and other services across a broader Western region.”
Introduced by Assemblymember Chris Holden and co-authored by 75 lawmakers, ACR 188 passed the Senate and Assembly without opposition on Aug. 8 and 11 respectively. It asks CAISO to produce a report by Feb. 28, 2023, that summarizes recent studies on the impacts of expanded regional cooperation and identifies features that could advance the state’s energy and environmental goals while “reflect[ing] the impact of regionalization on transmission costs and reliability for California ratepayers.”
Transmission and resources needed to fulfill the 100% clean energy goal of 2018’s Senate Bill 100 should be covered, as should mandates by Colorado and Nevada requiring transmission owners to join an RTO by 2030, it said.
CAISO said the request signaled a growing interest in regional efforts.
“We’re encouraged that compiling the many existing studies on this, as well as highlighting the other market efforts in the West, will foster a better understanding of the issues and how we might move forward collaboratively,” Stacey Crowley, CAISO’s vice president of external affairs, said in a statement.
Potential Benefits
In the resolution, lawmakers cited a study published last year that found an RTO covering the entire U.S. portion of the Western Interconnection could save the region $2 billion in annual electricity costs by 2030 and cut carbon dioxide emissions by 191 million metric tons. A group of Western states led the study, financed by the U.S. Department of Energy.
A subsequent study released in July by Advanced Energy Economy (AEE) looked at regional economic effects. It concluded an 11-state Western RTO could generate roughly $19 billion to $79 billion in additional gross regional product by 2030 and could help create 159,000 to 657,000 permanent jobs at an average total compensation, including benefits, of $73,000 a year. (See Study Tallies Economy-wide Benefits of Western RTO.)
AEE said the resolution “kickstarts discussions about California’s role in improving the Western power grid in collaboration with other states in the region.”
“ACR 188 sets the stage for California to engage substantively with its neighbors, and it’s great to see the legislature recognize the importance of regional collaboration when it comes to our energy grid and achieving state goals,” AEE Managing Director Amisha Rai said in a news release.
Prior regionalization efforts involving CAISO fizzled in 2016, 2017 and 2018, as California lawmakers balked at making changes to the ISO’s governance that could open its Board of Governors to out-of-state members. CAISO is a public benefit corporation created by the legislature and led by five gubernatorial appointees from California.
Even as California has been unwilling to share CAISO leadership, many parties in other Western states are unwilling to participate in a California-dominated RTO.
Acknowledging the standoff, the resolution said CAISO’s report should examine “collaboration between states on energy policies to maximize consumer savings while respecting state policy autonomy.”
Western Resource Advocates said the resolution “sends an important signal that regional electric grid collaboration should respect individual states’ autonomy and include governance provisions that allow significant engagement by states across the West.”
Speaking for CAISO, Crowley said, “Perhaps today there’s more general understanding of how a regional market would benefit ratepayers and the overall reliability, while at the same time respecting the policies set by each state in the West.”
Regional Cooperation Efforts
CAISO’s multistate Western Energy Imbalance Market has shown the economic benefits of regional cooperation by securing more than $2 billion in benefits for its members since it began in 2014, the resolution notes. Members from California and other Western states make up WEIM’s Governing Body.
The ISO is engaged in a stakeholder process to expand the real-time WEIM to a day-ahead market with the potential to increase resource exchanges across the West. On Tuesday it posted a revised straw proposal on the extended day-ahead market (EDAM) initiative and has scheduled stakeholder meetings for Aug. 28 and Sept. 7-8. (See CAISO Issues EDAM Straw Proposal for the West.)
“The extended day-ahead market is expected to achieve cost savings through a more efficient day-ahead commitment of generating units, including the displacement of resource commitments within one balancing authority area when more economic resources can be committed in other balancing authority areas instead,” the resolution says.
CAISO is facing competition from other entities that are moving to increase regional planning or form a Western RTO.
SPP has been promoting its Markets+ offering in the Western Interconnection, attracting interest from utilities seeking a range of market services that stop short of a full RTO. (See related story, BPA Commits to Funding Markets+ Development.) It is planning to establish a Western version of its eastern RTO, called RTO West, with Markets+ participants as likely members.
Spanning much of the Western Interconnection, the Western Resource Adequacy Program (WRAP) promises to be another significant player in regionalization efforts. Started by the Northwest Power Pool — which recently changed its name to the Western Power Pool (WPP) to reflect its wider reach — the program is meant to address reliability concerns in the Western Interconnection. It has already attracted participants in an area spanning from British Columbia to Arizona and east to South Dakota.
WPP has not signaled intentions to expand the WRAP’s offerings beyond resource adequacy, but it appears increasingly as a possible platform for incrementally developing a Western RTO that could compete with SPP and CAISO.
The Department of Energy issued a $45 million challenge Wednesday for the development and commercialization of tools and technologies to protect U.S. electric, oil and natural gas production and delivery systems from cyberattacks.
The goal is to build on grid upgrades funded through the Infrastructure Investment and Jobs Act and the recently signed Inflation Reduction Act by integrating “greater cyber defenses into our energy sector,” DOE said in a press release. Up to 15 projects could be funded, with a focus on research, development and demonstration of new cybersecurity technologies, the press release said.
Eligible proposals must apply to electricity generation, transmission, or distribution (including energy management systems and electric vehicles) or oil and natural gas production, refining, storage or distribution.
“As DOE builds out America’s clean energy infrastructure, this funding will provide the tools for a strong, resilient and secure electricity grid that can withstand modern cyberthreats and deliver energy to every pocket of America,” Energy Secretary Jennifer Granholm said.
The $45 million from the DOE Office of Cybersecurity, Energy Security and Emergency Response will be targeted at “tools and technologies that enable energy systems to autonomously recognize a cyberattack, attempt to prevent it and automatically isolate and eradicate it with no disruption to energy delivery,” the press release said.
Other areas of focus for the funding include:
building cybersecurity and resilience into technologies through a “cybersecurity by design” approach, which identifies “key cybersecurity features and risk considerations from the start;”
protecting systems through the broad-scale adoption and standardization of encryption;
developing tools and technologies to detect and prevent ransomware attacks at the hardware, firmware and software levels; and
developing software to serve project owners and operators that can be tested “across a full range of attacks in both testbed and real environments.”
Funding will also be provided for two demonstration projects in which developers will team up with asset owners and operators to field test technologies “purpose built for the operational technology environment, capable of adapting to and surviving a cyberattack and have been made available to the energy sector.”
‘Interoperable, Scalable, Readily Manageable’
Both the Infrastructure Investment and Jobs Act and the Inflation Reduction Act provide funding for grid upgrades and building and transportation electrification that will likely accelerate digitization of the U.S. electricity system, which will make the grid smarter and more efficient while also providing more targets for cyberattacks.
The IIJA’s $7.5 billion in funding for EV chargers is aimed at putting 500,000 chargers along U.S. highways, potentially making them a huge target for cyberattacks. The IRA provides funds to help low-income families buy electric home appliances, again opening millions of points of entry for cyber criminals.
The DOE funding opportunity announcement (FOA) is structured to promote both technical innovation to prevent and mitigate cyberattacks, and commercialization and integration strategies to get the new tools and technologies adopted by utilities, grid operators and other energy stakeholders.
The FOA lays out a two-step structure for applicants: a research and development phase focused on innovation, and a demonstration phase, which requires applicants to provide a plan for commercialization and the buildout of domestic supply chains and jobs.
Individual grants will range from $1.5 million to $3 million, and applicants will be required to supply matching funds equal to 29% of project costs, except for the demonstration projects, where the funding split will be 50% each for DOE and the applicants.
Commercialization plans must include “U.S. manufacturing commitments as well as plans for technology maturation and technology licensing,” the FOA says. “Invention and copyright licensing to commercialize technology” developed under the FOA is also required.
DOE will be looking for “interoperable, scalable, readily manageable advanced tools and technologies [that] are compatible with common methods and best practices,” the FOA says.
Applicants will also have to develop diversity, equity, inclusion and accessibility plans aimed at ensuring benefits and jobs for “underrepresented groups in STEM [science, technology, engineering and math]” and their communities.
Concept papers are due by Sept. 12, with a full application due Dec. 5. Winners will be notified in February and funding awards made in June 2023.
Wednesday’s funding opportunity follows on the DOE’s April announcement of $12 million in awards to six university-led teams researching the use of “anomaly detection, artificial intelligence and machine learning, and physics-based analytics to strengthen the security of next-generation energy systems.” According to the announcement, these next-gen systems “include components placed in substations to detect cyber intrusions more quickly and automatically block access to control functions.”
Minnesota-based Andersen Corp. and California startup Ubiquitous Energy have signed an agreement to develop and manufacture windows that double as solar power modules.
The companies pledged windows “without aesthetic compromises”; in other words, visible light will pass through the windows, which, judging by early versions developed entirely by Ubiquitous, will not visibly reveal their photovoltaic abilities.
The two companies announced their agreement the day after President Biden signed the Inflation Reduction Act, which will provide more funding to technologies aimed at fighting climate change with electrification replacing fossil-based technologies.
The breakthrough Ubiquitous claims to have made is based on patented technology pioneered by researchers at Michigan State University and the Massachusetts Institute of Technology. MSU has already installed glass produced by Ubiquitous.
In January, Ubiquitous revealed that Andersen was a leading investor in a $30 million funding round it concluded at the end of 2021, taking the total of investor research and development funding to $70 million.
The company’s technology produces power from ultraviolet and infrared light, allowing visible light to pass through the window. The two companies intend to manufacture the solar glass in the U.S.
“With our patented technology, Ubiquitous Energy has expanded what’s possible in photovoltaic technology. We’ve engineered our solar cells to selectively transmit visible light, what we see, while absorbing and converting invisible ultraviolet and infrared light into electricity,” the company announced on its website. “This makes our technology the first truly transparent solar technology, allowing windows to convert ambient light into useful electricity without impacting aesthetics or performance.”
Ubiquitous in April announced it had demonstrated the technical ability to uniformly coat glass as wide as 1.5 meters, the first step toward its production line target to manufacture high volumes of 1.5-by-3-meter floor-to-ceiling solar windows.
The company also said its technology does not use hazardous materials, but “earth-abundant materials” instead. Its coating technology follows “standard industry coating practices, and its windows will meet ‘Low E thermal performance’ standards,” it said.
Brandon Berg, senior vice president of research and development at Andersen, described the agreement with Ubiquitous as “a powerful opportunity to leverage our industry leadership, product development expertise and manufacturing capabilities.”
Newly elected Ubiquitous CEO Susan Stone said the two companies “have a shared goal of changing the way the world uses solar power and positively impacting the environment in a big way without compromising aesthetics or function.”
Entergy on Wednesday announced that chairman and CEO Leo Denault will step down early next year after a decade at the utility’s helm.
The Entergy Board of Directors has elected current CFO Drew Marsh to succeed Denault as CEO, effective Nov. 1, in an overlapping transfer of power. Denault will continue to lead the board as chairman until his retirement.
Entergy said the move is part of an “orderly and planned leadership succession process.”
Denault, 62, has spent 23 years with Entergy, becoming an executive vice president and CFO in short order a few years after his arrival. He has served as chairman and CEO since 2013, when he took over for J. Wayne Leonard as Entergy transitioned into MISO membership. Denault and Leonard are Entergy’s only two CEOs in the last 24 years; Leonard, who died in 2018, became CEO in 1998.
In a press release, Entergy’s lead independent director Stuart Levenick said Denault has “strengthened the business and positioned Entergy well for the future.” Levenick also said he’s “confident that Drew will carry the torch and continue serving all of Entergy’s stakeholders well by creating sustainable value today and for future generations.”
Marsh, 50, joined Entergy in 1998, serving in several financial planning and strategy roles before becoming CFO in 2013. Kimberly Fontan will become Entergy’s CFO; she has served as a senior vice president and chief accounting officer since 2019.
“I am both grateful and honored by the confidence the board has placed in me, and I’m honored to follow in my colleague and friend Leo Denault’s footsteps,” Marsh said. “I will uphold Entergy’s values and the strategy that he has instilled in our leadership team.”
Denault said his transition comes at a “logical time,” pointing out that Entergy recently successfully pulled off its “planned, multi-year strategy” to exit the merchant nuclear power business.
Entergy owned six merchant nuclear power plants when Denault began managing the company: FitzPatrick and two Indian Point units in New York; Vermont Yankee in Vermont; Pilgrim in Massachusetts; and Palisades in Michigan. All are now closed except for FitzPatrick, which Exelon now owns.
Entergy said Denault played a critical role during and after Hurricane Katrina’s 2005 destruction, making sure the company’s headquarters remained in New Orleans — where it is the city’s only Fortune 500 company — and guiding Entergy New Orleans through bankruptcy proceedings after it lost nearly all of its customers in the storm’s aftermath.
The utility also praised Denault for spearheading an accelerated goal to reach net-zero emissions by 2050 and “advancing climate resilience initiatives throughout communities in the Entergy region.”
For years, Entergy has had a goal to invest about $1 billion annually in transmission capital projects for economic and system resilience reasons. In June, Entergy committed to a $25 billion, five-year capital plan to ramp up decarbonization efforts and to accelerate reinforcements to its Gulf Coast infrastructure to better protect it against future hurricane strikes. The plan includes adding more renewable energy and burying some distribution lines.
After Hurricane Ida darkened the coastal Louisiana grid for weeks last year, Entergy faced calls from climate change activists to harden its transmission and distribution system and make more investments in renewable energy. (See Entergy Fends Off Calls for Tx, Solar, Microgrid Investment.)
Entergy announced other leadership changes Wednesday.
Chris Bakken, currently executive vice president and chief nuclear officer, was named executive vice president of Entergy infrastructure. Entergy said Bakken will have oversight responsibility for both utility operations and nuclear operations.
Senior Vice President of Nuclear Corporate Services Kimberly Cook-Nelson was appointed executive vice president of nuclear operations and chief nuclear officer. The company said Cook-Nelson will be responsible for operations at Entergy’s four remaining nuclear plants in in Arkansas, Louisiana and Mississippi. She will report to Bakken.
VANCOUVER, Canada — At the first in-person meetings of NERC’s Board of Trustees and Member Representatives Committee (MRC) since the start of the COVID-19 pandemic, attendees reflected on the changes that the organization has experienced in the years since they last saw each other.
“I think the last time we met in person, Jennifer Sterling was the chair, and then Paul [Choudhury] took over as chair … and now I’ve taken over,” MRC Chair Roy Jones said on Wednesday. “So Paul now has the honor of being the only MRC chair to never hold a meeting in person.”
The meetings, held Wednesday and Thursday, were NERC’s second attempt at returning to in-person gatherings after the second-quarter meetings, intended to be held in D.C., were converted to virtual sessions after an attendee tested positive for COVID-19 at the meeting site. (See “Positive COVID-19 Test Prompts Return to Virtual Sessions,” NERC Board of Trustees/MRC Briefs: May 11-12, 2022.)
Ahead of the third-quarter meetings, NERC put new policies in place to prevent a repeat of the incident and its disruptions to attendees’ travel plans. These rules, requiring isolation and virtual attendance after a positive test, were put into practice when NERC CEO Jim Robb tested positive on-site the day before the MRC meeting. While Robb remained in Vancouver and listened to the events via webcast, Manny Cancel, president of the Electricity Information Sharing and Analysis Center, delivered the President’s Report in his place.
The final meeting of the board and MRC in 2022 is scheduled for Nov. 15-16 in New Orleans. According to the 2023 schedule shared this week, NERC plans to hold its first- and third-quarter meetings in person in California and Canada, respectively. Gatherings for the second and fourth quarter will be held in D.C. and Atlanta, following a hybrid model in which trustees and members meet in person while all other attendees join virtually.
Board Approves ERO Budgets
The board approved relatively few actions at its meeting Thursday. Only the Finance and Audit Committee (FAC) submitted any items for approval, primarily the final business plans and budgets for NERC and the regional entities, approved at its meeting the day before. (See related story, NERC FAC Approves Final 2023 ERO Budgets.) With the board’s approval, the ERO will file the budgets with FERC by Aug. 25.
The FAC also asked trustees to approve an extension of NERC’s $4 million line of credit, which the organization maintains for emergency working capital needs and unforeseen contingencies. NERC has renewed the line annually since 2007; last year the board authorized management to execute the renewal without its approval.
However, the board must still give its assent “if the terms and conditions [of the line of credit] materially change.” In the next renewal period, the interest rate index for the line will change from the London Interbank Offered Rate to the Secure Overnight Financing Rate, which qualifies as a material change. As a result, management decided to take the question of approval back to the FAC and board. The trustees agreed to the change and renewal without objection.
Updates on Standards Projects
Howard Gugel, NERC’s vice president of engineering and standards, updated the board on the progress of some ongoing standards projects. First was Project 2021-07 (Extreme cold weather grid operations, preparedness and coordination), which NERC started last year in response to the mass outages caused by the February 2021 winter storm.
The project has produced two draft standards, EOP-011-3 (Emergency operations) and EOP-012-1 (Extreme cold weather preparedness and operations). Both standards were posted for comment in May; EOP-011-3 passed on the first ballot, but EOP-012-1 failed and was returned to the standard drafting team for revision along with industry comment. Gugel said EOP-011-3 is currently “in a holding pattern until we get EOP-012 across the board.”
Gugel also discussed the ongoing efforts to revise NERC’s Critical Infrastructure Protection (CIP) standards, including the proposed changes to CIP-003-8 (Cybersecurity — security management controls) that are currently out for a formal comment and ballot period that will close on Friday. If the standard passes this ballot — for which Gugel said NERC has “good expectations” — additional revisions are likely to follow based on the work of Project 2016-02 (Modifications to CIP standards), which on Wednesday entered a ballot period that is expected to wrap up by Sept. 21.
The Bonneville Power Administration has said it will become the first Western utility to formally commit to funding further development of SPP’s Markets+ offering in the Western Interconnection.
In an Aug. 12 letter to the Public Power Council’s (PPC) Executive Committee, BPA Administrator and CEO John Hairston said that while the agency has not made a decision to join Markets+ as a market participant, it expects to fund its share of the market’s development phase in late 2022 and to participate in drafting a tariff and market protocols next year.
“By supporting and participating in SPP’s process, Bonneville and our customers can help shape the market design in a way that ensures it could work with our statutory obligations and support Bonneville’s customers’ needs and interests,” Hairston said.
He said BPA’s goal is to ensure the utility has a fully developed option “that could work for Bonneville” and that can be evaluated alongside CAISO’s Extended Day-Ahead Market (EDAM) proposal. The agency will continue to take part in the EDAM development process as well.
“Bonneville recognizes that independent governance is an essential aspect of any potential future market to ensure neutrality in market development, implementation and operation,” Hairston wrote. “While some aspects of the Markets+ governance proposal can be improved upon, Bonneville is encouraged by the representative nature of SPP’s existing governing structure and its participant-driven process.”
He said BPA supports the Markets+ governance proposal that includes independent, West-wide participation.
“Bonneville is also encouraged by SPP’s track record of accommodating the unique characteristics and statutory requirements of the Western Area Power Administration in its other markets and SPP’s long history of working with public power in its Eastern region,” Hairston said.
The letter was in response to an earlier letter from the PPC, which represents the Pacific Northwest’s public utilities in the region and in D.C. The PPC encouraged BPA to commit to a “fully informed decision” on meeting customers’ “evolving needs in the context of a rapidly changing Western electric grid.”
“This was welcome news as we look to evaluate all options on the table,” PPC Executive Director Scott Simms said in an email to RTO Insider. “Specifically, we in Northwest public power will continue to evaluate CAISO’s EDAM approach along with SPP Markets+ approach, with an eye to the governance structure and overall market design path that can create the greatest value to BPA and its customers in the Pacific Northwest.”
BPA’s decision is significant, as it is the region’s 800-pound gorilla with 15,000 circuit miles of transmission that serve the region. Its footprint’s size has been compared to France, and it serves nearly 3 million people.
The PPC’s members are among the largest purchaser of the utility’s transmission products and services. It said it is closely watching BPA to determine whether it will continue to provide “reliable, affordable and clean resources.”
Lauren Tenney Denison, PPC’s director of market policy and grid strategy, said BPA’s transmission and connectivity “will be critical” for enabling a successful organized market in the Northwest.
“BPA is adjacent to over a dozen other balancing authority areas, which are all also considering potential participation in Markets+ and other market opportunities,” she told RTO Insider. “Their access to those market opportunities will be impacted by the availability of BPA’s transmission to be utilized in that market.”
Denison said BPA’s 31 dams, with a nameplate capacity of 22 GW, could provide “considerable” value for any centralized market, but that its commitment to continue develop day-ahead options “signals an assurance from BPA and public power that they will work collaboratively with other entities in the region to find an integrated market option that will work for the region.”
“This is particularly important given the Northwest’s previous struggles with establishing organized markets,” Denison said. “BPA’s role as a federal power administration with statutory commitments can create challenges to the agency participating in organized markets. This statement … demonstrates a commitment to work through these issues.”
SPP welcomed the news.
“Over the last several months, SPP has been encouraged by the level of engagement among utilities like Bonneville Power Administration, plus public interest groups, state commissions and others interested in seeing Markets+ become a reality,” CEO Barbara Sugg said in a statement. “With their input on the challenges and opportunities of ensuring electric reliability in the West, and our experience designing, building and administering electricity markets, we’re confident we can deliver a market that brings tremendous value to a new part of the country.”
SPP is preparing to publish in November a service offering for Markets+, a conceptual bundle of services that would centralize day-ahead and real-time unit commitment and dispatch and provide hurdle-free transmission service. Staff say that the offering would provide a voluntary, incremental opportunity to realize “significant” benefits for those utilities that aren’t ready to pursue full RTO membership.
The California Public Utilities Commission is poised to delay enacting controversial changes to net energy metering (NEM) for another year, saying it needs more time to consider revisions to how the state compensates owners of rooftop solar for electricity sent to the grid.
The current Aug. 27 deadline in the proceeding does not give the CPUC or the public enough time to review the mass of comments it has received on the changes or to vet alternatives, the commission said in a proposed decision Monday.
“Accordingly, it is necessary to extend the deadline by one year to allow adequate time to address the remaining issues of this proceeding,” Administrative Law Judge Kelly Hymes wrote in the proposed order, which the CPUC will likely take up at its next voting meeting on Aug. 25.
The one-year delay, to Aug. 27, 2023, is the latest postponement of California’s efforts to reduce the generous credits it gives to rooftop solar owners who export surplus electricity. Currently, those customers receive bill offsets at full retail electricity rates, which are far more than the current costs of utility-scale solar.
A proposed decision in December set off a storm of public criticism by recommending up to an 80% credit reduction while adding an $8/kW monthly grid participation charge (GPC) to customers’ bills. (See California PUC Proposes New Net Metering Plan.)
Opponents, led by the solar industry, have argued such a plan would decimate rooftop solar adoption. The NEM credits have made California the nation’s rooftop solar leader, with more than 1.3 million installations, they contend.
Proponents of change, including the state’s large investor-owned utilities, argue utility-scale solar is more cost-effective and can serve far more consumers.
The CPUC said in its proposed decision in December that the current scheme unfairly shifts costs from homeowners who can afford rooftop solar to those who cannot.
It “negatively impacts nonparticipating customers, is not cost-effective and disproportionately harms low-income ratepayers,” Hymes wrote.
Utilities estimated that $4 billion in costs would be shifted this year from ratepayers with rooftop solar to those without it.
The outpouring of criticism over the December proposal led the CPUC to postpone an expected decision in January, as the commission’s new president, Alice Reynolds, took the lead on the proceeding.
In May, Hymes asked parties to comment on questions she posed regarding possible alternatives.
The judge’s questions focused on a “glide path” to gradually transition rooftop solar owners from the generous benefits they now receive, and non-bypassable charges for solar owners based on their gross energy consumption, including use of the solar energy they generate.
A voluminous response to the judge’s questions came from industry groups and environmental advocates, among others.
In comments Monday, ClearView Energy Partners said it believed the latest delay signals the likelihood that the CPUC will eventually issue a scaled-back proposal next year.
“We continue to think final reforms are likely to be more modest than those offered in the [December proposed decision],” the firm said. “We think the glide path and the GPC are most susceptible to changes.”
New Jersey will spend $10.8 million to fund the purchase of heavy-duty electric vehicles, including 10 electric school buses, and install 62 fast-charging stations that will enhance the charger coverage outlined in the state’s recently filed National Electric Vehicle Infrastructure (NEVI) deployment plan.
The state investment, announced by Gov. Phil Murphy last week, will put charging stations at 31 locations around the state, funded with $3.9 million from New Jersey’s share of the nationwide Volkswagen settlement. Another $6.9 million, drawn from funds awarded to the state under the Regional Greenhouse Gas Initiative (RGGI), will pay for the buses, as well as for seven electric garbage trucks and two buses for non-school use.
The announcement follows the submission just before the Aug. 1 deadline of the state’s NEVI plan to the Federal Highway Administration (FHWA). The plan outlined a three-pronged strategy to “install fast chargers every 50 miles” along certain designated traffic corridors using $104.4 million in FHWA funds awarded to the state.
The state expenditures are designed in part to increase the number of electric trucks and buses that pass through communities overburdened by air pollution, said Shawn LaTourette, commissioner of the New Jersey Department of Environmental Protection (DEP).
“While medium- and heavy-duty vehicles are fewer in number than passenger cars, they contribute a much larger share of emissions per vehicle, so there is a major benefit to the environment when we electrify them,” he said.
The state investment on charging stations — with two chargers per site at 16 locations to be installed by government entities and 15 by private entities — are designed to expand the number of “community fast-charging” stations, LaTourette said. The charging locations were picked on criteria that included locations where people live and work — such as town centers, commercial areas, retail centers and concentrations of multiunit dwellings (MUDs) — and had to be accessible to the public, open 24/7 and able to accept payment from all credit cards.
The list of charger locations picked to be funded are spread across the state, including at municipal halls, retail stores such as 7-Eleven, car dealerships and a church. The grants ranged from a maximum of $75,000 for a 50-kW charger, to $200,000 for a charger of 150 kW or greater.
In a release outlining the $10.8 million expenditure, Murphy’s office said that locations that were considered for state funding but were eventually rejected will now be considered for funding under the NEVI plan.
Charging Stations Every 25 to 50 Miles
States were required to submit their NEVI plans by Aug. 1, detailing how they would site a charging station every 50 miles on major interstate routes in order to receive federal funds. The FHWA now has until Sept. 30 to review and approve the plans.
New Jersey’s DC fast chargers and L2 chargers currently within one mile of the state’s designated alternative fuel corridors. | New Jersey Department of Transportation
The rules also required fast chargers to be available 24/7, operating 97% of the time and able to accept any debit or credit card. The program also requires states to contribute 20% of the cost of building out the charging stations on highways designated Alternative Fueling Corridors (AFCs). (See States File Plans on Deadline for Federal EV Charging Funds.)
Pamela Frank, CEO of ChargEVC, a trade and research organization that promotes EV use, said New Jersey had done a “reasonably decent” job on the NEVI submission and in keeping a strong focus on ensuring that the key arteries through the state have EV charger coverage.
“This plan does not dot every ‘i’ and cross every ‘t,’ but I think it hits on” the key points, she said. That was assisted by the fact that New Jersey’s 2020 EV law addressed much of the same ground but with some more stringent measures, requiring a charging station every 25 miles on certain highways instead of the 50 miles under the federal program.
“New Jersey’s law says ensure coverage so that nobody ever has to go anywhere without bumping into one of these fast-charging opportunities every 25 miles,” Frank said. “Every 50 miles doesn’t cut the mustard,” but “the good news is federal dollars are going to help us get to our buildout that was mandated under New Jersey law faster. So it’s like they’re feeding each other. It’s more money to help New Jersey get to the very ambitious goals it has.”
Aiming for Statewide Coverage
Under the first phase of the state’s NEVI plan, from 2022 to 2024, New Jersey officials would designate 12 highways in the state as AFCs, among them the New Jersey Turnpike and Garden State Parkway. The state would also use the funds to install four 150-kW chargers at least every 50 miles at locations less than a mile from the highway exit.
The second phase, from 2023 to 2025, would focus on adding to those charger stations with a goal of installing chargers every 25 miles. In some cases, the state would look to increase funding efficiency by placing a charger at an intersection that serves two corridors, according to the plan.
The final phase, through 2026, would involve the installation of chargers that address other charging needs in the state. These would include placement in certain “community-centric” locations, putting chargers near MUDs and locating sites in overburdened and disadvantaged communities where they can serve ride-sharing and ride-hailing programs. The New Jersey Board of Public Utilities (BPU) recently identified this as key to helping speed the uptake of EVs in disadvantaged areas where economic circumstances and obstacles to owning an EV would otherwise hinder the adoption of the vehicles. (See NJ Study Looks at Getting EVs into Overburdened Communities.)
The effort to cover the state with EV chargers is part of a portfolio of programs aimed at helping the state meet the goals set out in the Energy Master Plan for the state to deploy 330,000 light-duty EVs on the road by 2025. The NEVI plan said the state had 126 DCFC sites in 2022, and it would need 1,600 to 5,600 in 2035 to meet the goal of plug-in EVs accounting for all vehicle sales in the state.
PORTLAND, Ore. — SPP and Western entities interested in the RTO’s Markets+ “RTO light” offering continued to inch toward one another other last week during another development session.
During a discussion on further defining base schedules into various types and their effect on the market, one Western stakeholder cracked, “You even make base schedules fun!”
Those in the know greeted the comment with laughter.
For the uninitiated, base schedules are financial accounting records created by tagging and scheduling bilateral transactions. Should the Markets+ dispatch create an interchange between balancing authorities — there are 38 in the Western Interconnection — the design structure’s dynamic tags will be updated to reflect that dispatch.
Mark Holman, managing director of Canadian power marketer Powerex, spoke up frequently during the two-day session, peppering SPP staff and the stakeholder-led design teams with questions of market designs and products.
A conversation on allocating day-ahead congestion rents that left many non-technical attendees lost in the weeds led Holman to remark that the two sides are “down to the final details.”
“I just think this is one of the most complex topics we’re going to tackle,” he said. “We’re trying to allocate congestion rights on top of a multi-[transmission service provider] framework with point-to-point network customers. So, I think we’re in excellent shape on this topic, and I’m really happy how far we’ve gotten in four or five discussions.”
Given a day to think, Holman said the two days were a “tremendous success.”
“Not only was there a great turnout from so many entities across the West, it is now becoming clear that we have general alignment amongst stakeholders on several of the key market design topics. We are already getting down to discussing the finer details,” he said in an email to RTO Insider.
Holman acknowledged there is still work to do but said he is optimistic that SPP staff and those interested in Markets+ will soon have a draft governance and market design proposal with “sufficient detail to support moving to the next phase.”
That would be drawing up a tariff and market protocols, a task that is scheduled to begin next year.
“We’re still talking internally about what that looks like,” Bruce Rew, SPP’s senior vice president of operations, told attendees when the meeting adjourned Wednesday.
Until then, the RTO and interested Markets+ participants will develop a draft service offering by the end of September. SPP expects a final service offering to be available in mid-November for what it says is a “conceptual bundle” of services (centralized day-ahead and real-time unit commitment and dispatch, and hurdle-free transmission service across the footprint) for utilities that see value in the services but aren’t ready to pursue full RTO membership.
Eventually, entities interested in membership will be asked to make a financially binding commitment during the first quarter of 2023.
The two sides will gather again in Phoenix in November.
“We’ve learned a lot from those out here, and they’ve learned a lot from us,” SPP General Counsel Paul Suskie said. “I think we’re driving to a strong consensus. I think structurally we’ve got a sound straw proposal, and we’re really just tweaking it.”
Asked what SPP has learned from its potential new members, Suskie said, “What I’ve really learned is there’s a lot of history in the West and because they haven’t had many long-term, successful, regionwide organizations, things are still getting a feel for how to cooperate and work together.”
SPP has said Markets+ will eventually replace the Western Energy Imbalance Service (WEIS) market it currently operates. When three new members join the WEIS next year, it will be regionally balancing 13.5 GW of load generation. Rew has said an imbalance market is a great introduction to markets but is only a short-term solution for participants.
Recent years have seen CAISO also offer RTO services with its Western Energy Imbalance Market (WEIM), and then build on that with its proposed extended day-ahead market (EDAM). Suskie pointed to those advances and that of the Western Power Pool’s Western Resource Adequacy Program (WRAP) as changing attitudes toward regional markets.
WPP President Sarah Edmonds framed the WRAP as an industry-driven regional approach to help ensure resource adequacy, given the changing resource mix and its increased resource uncertainty. Participation is voluntary, with members facing mandatory resource requirements. The WRAP’s bilateral transactions under an existing framework is expected to meet estimated peak winter and summer loads of about 66 GW.
SPP is the initiative’s technical services provider, Edmonds said. “They run the studies. They do a lot of the kind of operational facilitation that we’re contemplating for WRAP.”
The program is the West’s take on resource adequacy, she said, which is “part and parcel” of what RTOs do.
“Out here, we’re maybe pivoting towards a slightly different model,” she said. “If WRAP is successful — and so far, we have tremendous momentum and a lot of trust from our members and customers — then there could be a new construct where you’ve got different market operators. There’s more than one in this space right now and a kind of a complementary provider of the resource adequacy program.
“Now, it would necessitate some kind of interplay or coordination between WRAP and these market programs, and the details of that is just something that we haven’t gotten to yet.”
There are also plenty of details to work out with the governance strawman. SPP’s proposal that one of its independent directors be included on the Markets+ Independent Panel (MIP), which would manage the markets and report to the RTO’s Board of Directors, was met with the most pushback. SPP staff have recommended the director have Western experience, but it doesn’t necessarily see that person as the MIP chair.
“Our board picks [its] own chair. I don’t know why MIP can’t pick [its] own chair,” SPP CEO Barbara Sugg said.
“That was just our starting point,” Suskie said.
“If a board member is on the MIP, how is it independent?” asked Western Resource Advocates’ Vijay Satyal. “If you want autonomy, no directors on the MIP is autonomy to me. The director should be ex officio and non voting.”
Staff assured attendees that the MIP’s eventual makeup is up to them. “We’re spending more time discussing this than we ever will in 10 years of Markets+,” Suskie said.
SPP’s takeaways from the governance discussion also included concerns over the $5,000 annual membership fee for non-member participants. Suskie asked for feedback from attendees, noting a waiver might make sense.
“The questions they have today won’t exist two years from now. It takes time to get comfortable with each other in a very diverse stakeholder process,” Suskie told RTO Insider after the meeting adjourned. “You’ve got to have trust, and that takes time to build. I think we’re getting there.”
