FERC on Friday ordered a paper hearing on the PJM transmission owners’ proposed tariff revisions to add network upgrades to their rate base, requesting more information be provided within 45 days (ER21-2282).
The commission accepted and suspended the TOs’ filing for five months, to become effective Feb. 1, subject to refund and to the outcome of the paper hearing procedures.
“We find that the proposed revisions have not been shown to be just and reasonable, and may be unjust, unreasonable, unduly discriminatory or preferential, or otherwise unlawful, and that the record would benefit from further information,” the commission said.
The commission in August had directed the TOs to provide evidence backing up claims that their ability to raise capital is being threatened because they must absorb the risks of increasing transmission upgrades without earning returns on the assets. The TOs responded in September, arguing that PJM’s tariff provides them with the “express authority” to make changes to any of its sections relating to transmission revenue requirements, cost allocation or cost recovery. (See PJM TOs Respond to FERC Questions on Rate-base Network Upgrades.)
The TOs had asked FERC on June 30 to allow them the option to fund network upgrades and add them to their rate bases. Under PJM’s “participant funding” model approved in 2004, generators provide the capital for network upgrades, while the additional infrastructure is added to rate bases at zero cost, allowing TOs to recover only their operations and maintenance expenses from network transmission customers.
According to the TOs, PJM’s 2020 Regional Transmission Expansion Plan (RTEP) showed that the total estimated costs of network upgrades to interconnect new generating resources was about $6.5 billion, which included $1.56 billion of upgrades already constructed and in service and $4.9 billion in active projects in the queue.
The TOs argued that even if a portion of the $4.9 billion of network upgrades in the queue were constructed, it would represent a “significant escalation” of the $1.56 billion of network upgrades they currently own or operate and for which they are currently not earning a return.
“They are concerned that this trend will continue as the number of new generation interconnection requests is expected to increase significantly, if not exponentially, in the coming years as the electric power industry continues to accelerate the development and construction of clean renewable energy resources,” FERC said.
But the commission said a preliminary analysis of the proposed revisions did not show them to be just and reasonable. FERC requested comments on a series of questions in the paper hearing.
The first question posits that the TOs’ proposed revisions are premised on their arguments that owning and operating network upgrades “entails significant risks for which PJM TOs do not earn a return or profit.” FERC asked if the risks TOs’ argue are associated with owning and operating network upgrades are “already incorporated into PJM TOs’ commission-approved ROEs, such that PJM TOs are already compensated for these alleged risks.”
FERC also asked what protections the proposed revisions provide against the “potential for undue discrimination” by the TOs in their choice of which network upgrades will be funded.
Another question asked if the proposed revisions could result in increased costs to interconnection customers “relative to the costs to initially fund network upgrades” if those same customers were able to obtain financing at lower or similar rates than the TOs.
Responses to the questions are due 45 days from the date of the order, and reply comments can be submitted 45 days after the due date of initial comments.
FERC Commissioner James Danly issued a concurring statement, saying that the “voluminous record” on the issue led him to the conclusion that the commission already has “sufficient” evidence to accept the tariff changes, but he recognized that his “colleagues still have questions.”
“While I have previously expressed concerns over improper delay tactics masquerading as requests for additional, unneeded information, the questions set for hearing are such that I do not oppose obtaining additional evidence here,” Danly said.
ISO-NE last week presented to the Planning Advisory Committee its scope of work for the 2050 Transmission Study, which will examine high-level scenarios for incorporating clean energy and distributed energy resources beyond the RTO’s current 10-year planning horizon.
The New England States Committee on Electricity had recommended such a study as part of its vision statement in October 2020. ISO-NE said it developed the study with NESCOE and would also work with the states to draft corresponding tariff changes to enable the study at regular intervals.
The study is the first effort in ISO-NE’s effort to implement a proactive, scenario-based planning process. The study’s objectives include determining transmission needs to serve load while satisfying reliability criteria and transmission upgrade “roadmaps” for 2035, 2040 and 2050. Pradip Vijayan, principal engineer for transmission planning at ISO-NE, said the original proposal was only for 2050 and that the RTO added 2035 and 2040 to the study.
Future load and resource assumptions will be based on the “All Options” pathway in the “Energy Pathways to Deep Decarbonization” report, which is also the basis for part of Phase I of NEPOOL’s Future Grid Reliability Study.
ISO-NE will develop “snapshots” of the worst expected cases — periods with the highest load and lowest renewable energy output:
summer daytime peak: May-September, 9 a.m.-5 p.m.
summer evening peak: May-September, 7-10 p.m.
winter evening peak: January-April, 4-10 p.m.
One stakeholder asked why only peak-load conditions were considered as options when more transmission could be needed during a light-load condition. Vijayan said that the RTO was focused on scenarios where the transmission system serves periods of higher demand.
“I think that as a knock-on effect, you would have transmission for low-load scenarios as well, but as we unlock all the resources that we are evaluating, extended under those conditions, curtailing resources might be an option,” Vijayan said.
The projected peak “All Options” pathway load is significantly higher than that reported in the RTO’s latest annual Capacity, Energy, Loads and Transmission report: 56,000 MW for 2050 and 27,500 MW for 2030. The RTO attributed the load growth to electric vehicle charging and heating. This led it to use two categories of load for the study: EV and non-EV.
The study will assume all oil, coal, diesel and municipal solid waste resources are retired by 2035. Natural gas, nuclear and biomass will be carried at 100% availability for all of the snapshots for the three study years. Assumed hydropower dispatch in the summer peak snapshots will be consistent with the RTO’s current practice in Needs Assessments, while it will be based on 2019 historical outputs for winter peak load conditions for the winter snapshot.
ISO-NE asked stakeholders to provide written comments on the presentation through Dec. 2, and the RTO will finalize the scope of work by the end of the year. It expects to discuss initial results during the first quarter of 2022.
The California Air Resources Board on Friday approved a $1.5 billion clean transportation funding plan that includes $515 million for the Clean Vehicle Rebate Project, the state’s popular electric car incentive program.
The plan also includes $10 million for a new electric bike incentive program and $75 million for Clean Cars 4 All, a program that offers lower-income residents incentives to scrap their old cars and replace them with zero- or near-zero emission vehicles. The program is available in five of the state’s 35 air districts, but an expansion is planned.
On the heavy-duty side, the funding package contains $570 million for the Hybrid and Zero-Emission Truck and Bus Voucher Incentive Project (HVIP). Within that amount, $70 million is set aside for zero-emission transit buses; $130 million for zero-emission school buses; and $75 million for zero-emission drayage trucks.
The spending plan allocates $195 million to the Clean Off-Road Equipment Voucher Incentive Project (CORE), which provides incentives for equipment such as zero-emission tractors and forklifts.
CARB staff said funding for the CORE program had been increased and that the range of eligible equipment was expanded. The program sets aside $30 million in incentives for small business and sole-proprietor landscaping companies.
Record-setting Funding
The CARB board on Friday approved a resolution adopting the fiscal year 2021/22 funding plan. The agency described the funding package as its largest for clean transportation, more than twice the amount of the previous largest investment.
“This unprecedented mix of incentives and funding will continue to support our equitable transition to zero-emission cars and accelerate the commercialization of zero-emission technologies for medium and heavy-duty trucks and buses,” CARB Chairwoman Liane Randolph said in a release.
The state general fund will contribute $838 million of the funding, and $595 million will come from the state’s cap-and-trade program. The Air Pollution Control Fund and the Air Quality Improvement Program account for the remainder.
Other pieces of the plan include $45 million for replacing diesel trucks with trucks that meet a low-nitrogen oxide standard through the state’s Carl Moyer program. There’s also $180 million in incentives for alternatives to agricultural burning in the San Joaquin Valley.
CVRP Changes
CARB announced in April that funding was rapidly running out for its Clean Vehicle Rebate Project (CVRP), as electric-vehicle purchases rebounded more quickly than expected during the COVID-19 pandemic. (See Shortfall Looms for Calif. EV Rebate Program.)
According to CARB, almost 65% of EV owners in the state have received a rebate through CVRP, a program that was launched in 2010 and had issued more than $926 million in rebates as of April.
The $515 million approved on Friday for CVRP is intended to last for three years, CARB staff said. During that time, CARB plans to “ramp down” the program and shift the focus to lower-income car buyers.
A first phase of changes will be implemented after 1 million EVs are sold in California, but not sooner than February 2022. At that point, CARB has proposed lowering the income cap for standard rebates and reducing the cap on manufacturer’s suggested retail price for smaller vehicles.
When EV sales in the state hit 1.25 million, but not sooner than February 2023, the income cap for standard rebates will be further lowered, rebate amounts will be reduced and plug-in hybrids will be dropped from the program.
Some members of the public who commented during Friday’s board meeting objected to the proposed changes to CVRP.
Anthony Bento, director of legal and regulatory affairs at the California New Car Dealers Association, said the incentive program is valuable but is “undermined by its complexity, particularly with respect to eligibility.”
Bento said the group is concerned that the proposed changes would make matters worse.
“In particular, that two-phase reduction in income caps and vehicle eligibility creates needless confusion,” he said.
Eileen Tutt, executive director of the California Electric Transportation Coalition, said in a letter to the CARB board that reducing the CVRP income cap “serves only to confuse and frustrate both middle-class consumers and auto dealers and reduce the market for EVs.”
Tutt described the proposed changes in income caps as arbitrary.
“The phases are proposed even though there is no data indicating these phases are related to consumer response or market viability of EVs,” she said.
CARB board member Daniel Sperling also urged the agency to be cautious in making changes to CVRP. He disagreed with the idea of dropping plug-in hybrids from the program as part of the second phase of changes.
While many people can switch to battery-electric vehicles without much trouble, especially if they own multiple cars, the change may be more difficult for others such as apartment dwellers, said Sperling, who is founding director of the Institute of Transportation Studies at the University of California, Davis.
In addition, Sperling called for using some of the money in the spending package to assess the effectiveness of programs being funded.
“Making sure we’re investing our money wisely and especially looking to the future,” Sperling said. “It can be built into every program, and I think we need to be thinking along those lines more.”
CHARLOTTE, N.C. — Renewable power advocates said last week they remain troubled by the concessions legislators made to utilities in return for the carbon-reduction goals of House Bill 951, saying the law fails to protect low-income residents, undermines competition and excludes renewable technologies other than solar.
The law, enacted in October, directs the North Carolina Utilities Commission to take the “least cost path” to cut electric-sector carbon emissions by 70% from 2005 levels by 2030 and reach carbon neutrality by 2050. The law also requires the state’s utilities — including Duke Energy Progress, Duke Energy Carolinas (NYSE:DUK) and Dominion North Carolina Power (NYSE:D) — to add 2,660 MW of new solar generation, 45% through power purchase agreements and the remainder utility-owned. Utilities will be limited to securitizing only 50% of the remaining book value of coal generators retired early. But it also ensures any other new generation will be utility-owned and subject to cost-of-service rates. (See New Era for Grid Planning in North Carolina?)
The 11-page bill that emerged from the North Carolina Senate was less prescriptive than the initial 50-page House bill, leaving much of the policy decisions to the NCUC.
“But from my perspective, what happened is it got much more prescriptive about the renewable resources that have the opportunity to compete in a marketplace,” Adam Will Foodman, CEO of Solar Operations Solutions and chair of the Carolinas Clean Energy Business Association (CCEBA), said during a panel discussion last week at Infocast’s Southeast Renewable Energy conference. Aside from the 2,660-MW carve out for solar and solar plus storage, “everything else is considered regulatory assets of the utility,” he said.
“Innovation, competition, is the lifeblood of an economy,” he said. “And absent those items, I think it’s difficult to see us charting the most efficient path to an energy transition. … We want a broader opportunity for technologies to compete in the transition that is going to take place with the retirement of coal. There are some opportunities there opened up in the bill. I think it remains to be seen how they will be implemented by the utility commission.”
Consultant Diane Cherry, whose clients include renewable energy developers, the Sierra Club and Carolina Utility Customers Association, a group of manufacturers and other large consumers, said she was disappointed that the law lacked a carve out for stand-alone storage. She also expressed concern that the design of customer programs will be subject to commission rules, making the upcoming dockets — as many as seven of them may be needed to implement the law — a “full employment” guarantee for regulatory attorneys.
Stephen Kalland, executive director of the North Carolina Clean Energy Technology Center at North Carolina State University, said he was disappointed that the final bill did not address distributed generation, community solar, net metering or rooftop solar. But he said the compromises could not obscure the historic nature of the bill’s carbon-reduction goals.
“To see legislated carbon goals … in a bill sponsored by Republicans in both chambers and signed by Democratic governor [is] pretty much unprecedented nationally. I think it was something that was somewhat breathtaking as an example of what states could actually do if they really wanted to drive the train forward in the clean energy space.”
Kalland said the current commission is knowledgeable about the technical issues the law presents. “And so if I had to pick between the legislature writing detailed rules for the energy market, and that utility commission writing those rules, I think it was actually a pretty good outcome,” he said.
“In the decade that I’ve been advocating for clean energy, mostly in front of conservative audiences, we have built the case that clean energy is an economically competitive technology. … And I think having [the perception that] the carbon standard be the driver … for these new clean energy technologies in North Carolina, it kind of takes us back a little bit on advocacy perspective. It’s, ‘Democrats got a carbon standard and, Republicans got things that were good for the vertically integrated monopoly.’ … I think you all know it’s not that simple. But as someone who has to constantly advocate in front of people who don’t look at energy every day of their lives, and they get a sound bite here and there, I’m a little bit concerned.”
“There’s gonna be a lot of work to do at the commission,” she said. “… No doors have truly been closed. We’re just kind of moving the venue.”
Ivan Urlaub, chief of strategy and innovation for the NCSEA, said the NCUC will need to be innovative to overcome the Achilles’ heel of the law: the utility ownership provision.
“The evidence has shown that the utility is not least-cost; it’s just not,” he told the audience. “Your businesses are. … And when your businesses and the customer work together, that’s where we most often see the least-cost options.
“The law is basically inviting the regulator to come up with one integrated solution and innovate in how they do planning,” he continued. “The ball’s in the commission’s court. Are they going to pick it up and play a good hard game with it, and, and really be aggressive [or] are we going to get some status quo?”
Urlaub urged those participating in the upcoming dockets to be suspicious of short-term wins in settlement discussions.
In short term deals, “the carrot … gets dangled to slam the door on the next 12 carrots,” he said.
The Maine Agricultural Solar Stakeholder Group is planning to recommend that the state establish a pilot program for dual-use solar projects as part of a report due to the legislature in January.
A pilot program is one of seven overall recommendations that are in a draft version of the report released by the group for public input.
“The pilot would provide opportunities to conduct necessary research on compatible crops and other dual-use systems to determine best practices for dual use within a defined time frame or capacity limit,” the draft says. In addition, the recommendation suggested that financial incentives or location-based waivers could support projects meeting a set of dual-use criteria.
The Department of Agriculture, Conservation and Forestry (DACF), in cooperation with the Governor’s Energy Office and other state agencies, would develop the pilot program with an eye toward innovation and data collection. Authorization for pilot funding would come from the legislature.
While details of pilot project parameters are not included in the draft recommendation, Nancy McBrady, director of the DACF’s Bureau of Agriculture, Food and Rural Resources, said Thursday that the final report should identify project size and scope.
“The term ‘pilot’ can sometimes infer something small and not particularly aggressive or audacious, and … a pilot specific to dual use needs to be robust enough to prove itself and to be successful,” she said during the group’s latest meeting.
To qualify as dual use, according to the report, a solar installation must enhance agricultural productivity, have a decommissioning plan and support the viability of a farming operation.
As part of its recommendation, the group pointed to New Jersey’s dual-use program as a possible model. The state has a three-year program to develop 200 MW of dual-use solar with projects not to exceed 50 acres, but the program is not “completely defined yet,” said Ellen Griswold, policy and research director at Maine Farmland Trust.
For the final report, McBrady said, the recommendation should convey the group’s interest in the development of a pilot program that would “lead to transformational change.”
Group Insights
The DACF and Energy Office convened the group this year to recommend ways to encourage solar development and protect Maine’s agricultural resources.
In their review of the draft, some group members felt it was cautious in terms of policy considerations.
“I would have liked to see some stronger language,” Griswold said.
The report’s overall tone could focus more on maximizing benefits to agriculture instead of minimizing damage, according to Fortunat Mueller, co-founder of ReVision Energy.
“I would be more inspired by the report if we work a little bit harder to frame it as an affirmatively positive vision for the mutually co-beneficial development of solar and rural economies in Maine,” he said.
Recommendations in the report could be “stronger,” or it should have a “vision statement conclusion about what the next steps should be,” according to Kaitlin Hollinger, policy manager at BlueWave Solar. “I think what’s missing [in the report] is kind of the sense of urgency around what we’re doing.”
In addition to the dual-use pilot program, the report’s other major recommendations include:
creation of a centralized clearinghouse of information related to approved and constructed solar projects, including information on the amount of agricultural land affected by deployed projects;
additional study on the treatment of land enrolled in the farmland current-use taxation program when the land houses a dual-use project;
inclusion of dual-use standards as permitting criteria in future development of processes for activities adjacent to protected natural resources;
development of detailed hosting capacity maps to include data on which areas of the grid have capacity for additional interconnections to minimize land-use stress in any one location;
increased technical assistance capacity and financial support for municipalities to encourage solar development; and
consideration of agricultural siting characteristics in state-sponsored programs that support solar development through long-term contracts or other financial mechanisms.
The group is seeking public input on the draft report through Friday.
Texas regulators continued to explore load-serving entity resource obligations (LSEROs) with an emphasis on dispatchable resources last week in their quest to modify ERCOT’s market design after its near collapse during the February winter storm.
“There’s no silver bullet, no readily apparent solution,” Public Utility Commission Chair Peter Lake said during Friday’s latest ERCOT market work session.
“The first crack we take won’t be the right answer,” he said. “We very much want to capture the good elements of all these proposals and continue to work going forward to the best solution. We’re in the business of vetting ideas and getting closer and closer to the right solution or the right set of solutions.”
One possible solution is the load-serving obligation that Lake has been championing and that still remains atop the list of potential answers. As proposed by NRG Energy (NYSE:NRG) and Exelon (NASDAQ:EXC), the LSERO would directly address resource adequacy concerns by introducing a formal reliability standard and a mechanism to ensure sufficient resources meet this standard. (See Study Suggests Texas LSEs Can Provide Reliability.)
At staff’s request, Brattle Group’s Sam Newell shared his analysis of the LSERO and another alternative to solving ERCOT’s resource-adequacy issues — targeted fuel and backup reserves — to help inform the commission’s decision-making.
He suggested an “LSERO plus” version that would require generators to bid in their capacity at cost to mitigate market power and allow LSEs to procure their obligation just before the season starts. Newell said this would be the most direct way to address resource adequacy, the PUC’s primary concern.
“If you want to look at the fleet and say, ‘Yup, we’re prepared’; if you think you’re able to look at the fleet and say, ‘That’s what we want — we’re prepared for any plausible event’ — this option is the most direct way to express that to the market,” Newell said. “This is the most direct way to export a resource adequacy objective to the market.”
He expressed concern about LSERO plus’s effect on forward bilateral contracts and the likelihood that LSEs wouldn’t know the prices ahead of the auctions and, thus, couldn’t hedge.
And then there’s the not-so-small matter of costs. Newell said Brattle has estimated the proposal would shift about a third of the ERCOT’s market value to LSEROs and cost “roughly” $300 million a year. The high costs stem primarily from staff managing an accreditation process for each resource and awarding reliability credits.
“A lot of administrative judgment goes into this, which will be the subject of ongoing argument,” Newell said. “The money subject to regulatory capture … [is] the biggest downside.”
“This is a major problem,” Stoic Energy consultant Doug Lewin said as he live tweeted the work session. It’s “a step toward an administered market where market participants spend more time working the refs for more money than providing innovation and lower-cost options.”
Alison Silverstein | ACEEE
Independent consultant Alison Silverstein told RTO Insider that large industrial customers might be tempted to opt out of another ERCOT charge and “dump reliability assurance costs onto small customers.”
As an alternative, Newell suggested a targeted fuel and backup reserves option that would require four days of on-site fuel. He said the gas-fired fleet would be the most likely candidate for that requirement, but it would necessitate the units being “satisfactorily winterized” and would only apply to about 25 GW of resources.
The proposal’s increased generation costs would be about half that of LSERO plus, Newell said.
“Holding out a few megawatts from the energy increased the price signals,” Newell told the PUC. “That can attract capital too. It does depend on people believing in [the proposal].”
Brattle’s alternative is similar to a strategic reliability service (SPS) proposed by Commissioner Lori Cobos that she called a “dynamic and flexible reliability tool” that would act as an insurance policy against reliability issues. She said the service would “prospectively target” and meet specific reliability needs not already addressed by ERCOT’s real-time and ancillary services markets.
Under Cobos’ plan, ERCOT would procure SPS through a competitive request-for-proposals process or auction to ensure the selection of the lowest-cost dispatchable resources. Eligible resources would have to meet weatherization requirements, fuel-supply arrangements and other accreditation requirements to ensure availability and firmness. They would also have to be capable of synchronizing to the grid within two hours and run for at least eight hours a day for multiple consecutive days.
Cobos said SPS would be deployed last in the bid stack to minimize its effect on real-time energy prices. Qualifying resources would be paid the market-clearing price, with those failing to perform assessed a “stringent” nonperformance penalty and its participation payment clawed back.
“We want to give ERCOT the flexibility to procure more than peakers. We need to send stronger price signals because we’re moving away from a crisis-based model,” Cobos said, referring to ERCOT’s current dependence on high prices during scarce times to incent new generation.
Newell pointed out that prices are only high during generation shortages.
“It’s not desired,” he said. “We want more supply and more cushion. The only two thematically ways to get that is to increase total demand, either through real-time reserves or through demand for capacity, as with an LSE obligation.”
The other theme?
“Make a side payment, but hold [the resource] out of the market,” he said. “There’s only so much room for supply and only so much demand. You don’t want to expand demand and pay everything that’s reliable. You want to hold some things out of the market.”
The discussion will continue in December, with the PUC committed to releasing a blueprint of its proposed market redesign before the year is up.
Silverstein, who sat in on the work session, questioned the rush for an LSE obligation when real-time co-optimization won’t be added to the market until 2025 at the earliest. The market tool clears energy and ancillary services every five minutes in the real-time market and would simplify a much more complex security-constrained economic dispatch problem when multiple resources and services are juggled over different interdependent time periods.
“I would prefer to see the commission do more, consistent analysis of every new option in the table … before they pick a single option like LSEO to move forward,” Silverstein said. She added that the PUC should analyze the major changes it’s already made to winterization requirements, the operating reserve demand curve and emergency response service, and determine their effect on reliability, market performance and costs.
“This should be the baseline against which they analyze the next set of potential market modifications,” Silverstein said.
Salty Public Comments
The PUC got more than it bargained for when it resumed in-person public comments during its open meeting Thursday. The commission took comments over the phone during the COVID-19 pandemic.
One speaker said she was upset over seats that some stakeholders reserved for others. “There are more suits in this room than the people who were affected” by the winter storm, she said.
A self-described organizer related a story of a person stuck in her home, battling 20-degree temperatures and ice in her sink.
That prompted a response from the woman who followed her: “We didn’t have ice in our sink, but we had ice on our asses.”
During the open meeting’s normal course of action, the commission also:
approved a $41.6 million rate-increase request from Southwestern Electric Power Co. (NASDAQ:AEP) but lowered its return on equity rate from 9.45% to 9.25%. SWEPCO had asked for a $90.2 million increase (51415).
agreed to a certificate of convenience and necessity for CenterPoint Energy’s (NYSE:CNP) 345-kV interconnection project southwest of Houston that will cost at least $22 million. Commissioner Jimmy Glotfelty dissented from the decision. An administrative law judge ruled that CenterPoint should work with a planned solar farm and existing landowners as it links another solar farm to the grid (51568).
learned from Cobos that she has been selected as vice president of Entergy’s Regional State Committee. The E-RSC comprises regulators from Arkansas, Louisiana, Mississippi, Texas and the city of New Orleans and provides input to Entergy about its operations and transmission upgrades.
California Gov. Gavin Newsom on Monday named his senior energy adviser, Alice Reynolds, as the next president of the California Public Utilities Commission, a body under intense pressure to ensure resource adequacy, prevent utilities from igniting wildfires and shepherd the state through its transition to 100% clean energy by 2045.
“As my lead energy policy expert, Alice has been indispensable in our work to move California toward a cleaner, affordable and reliable energy future, navigate the bankruptcy of the state’s largest investor-owned utility [Pacific Gas and Electric] and accelerate the state’s progress toward meeting our clean energy goals, among other critical issues,” Newsom said in a statement. “I look forward to her leadership as President of the California Public Utilities Commission.”
Reynolds will replace outgoing President Marybel Batjer on Dec. 31. Batjer announced in September that she planned to step down at the end of the year with five years left in her seven-year term. (See California PUC President to Step Down.)
“I have had the privilege of serving four California governors and have given my all to public service for many decades,” Batjer wrote in a letter to CPUC staff. “I am now ready for a new challenge and adventure.”
Newsom had named Batjer, then the state’s government operations secretary, to fill out the term of retiring President Michael Picker in July 2019. He reappointed her to a full term last year.
Under Batjer’s leadership, the CPUC oversaw PG&E’s Chapter 11 reorganization and obtained greater oversight of the troubled utility, which has been blamed for starting catastrophic wildfires since 2015. The commission worked to prevent more wildfires through vegetation management and grid-hardening and to rein in the overuse of public safety power shutoffs.
The CPUC came under fire for failing to anticipate the capacity shortfalls that have plagued the state in the past two years and are expected to continue next summer. Commissioners responded by ordering record amounts of procurement, including requiring the state’s three big investor-owned utilities — PG&E, Southern California Edison and San Diego Gas and Electric — to find 11.5 GW of new resources by mid-decade. (See CPUC Orders Additional 11.5 GW but No Gas.)
As adviser to Newsom since early 2019, Reynolds was instrumental in PG&E’s reorganization and in enacting a controversial measure, Assembly Bill 1054, that sought to shore up the IOUs against wildfire liability through a state insurance fund. (See Calif. Wildfire Relief Bill Signed After Quick Passage.)
Reynolds was former Gov. Jerry Brown’s senior adviser for climate, the environment and energy from 2017 to 2019 and served as deputy secretary for law enforcement and general counsel at the California Environmental Protection Agency (CalEPA) from 2011 to 2017.
A lawyer by training, she worked for two law firms from 1998 to 2001 and as a state prosecutor before taking the job with CalEPA.
Industry and environmental groups congratulated Reynolds or offered praise on her appointment after Newsom’s announcement.
“We have worked with Alice Reynolds during her years of service with Governors Brown and Newsom and believe that she is superbly qualified to lead the California PUC at a critical time,” Victoria Rome, director of California government affairs for the Natural Resources Defense Council said in a statement. “She has unmatched expertise on California energy issues. Over the next few years, the PUC will help ensure that California’s clean energy transition is built on a foundation of reliable electric service and equity.”
Others noted the difficult job ahead.
“California has a lot of work to do to make its energy more reliable, affordable, and cleaner, and we look forward to working with the CPUC to make that happen,” Advanced Energy Economy tweeted.
The state Senate must confirm Reynolds’ appointment as CPUC president, a position that pays $229,000 per year.
A panel of conservative electricity market experts on Tuesday argued that markets work better than public policy at encouraging and developing clean energy resources.
“Private capital is foaming at the mouth to get in these markets, and the obstacle is outmoded regulation,” Devin Hartman, director of energy and environmental policy at conservative think tank R Street Institute, said at a webinar hosted by ConservAmerica, a conservative environmental advocacy group. Formerly known as Republicans for Environmental Protection, the group argues that “the most efficient way” of developing clean energy resources “is through policies that encourage competitive markets, private investment and expanded trade.”
The private sector wants to invest in building the infrastructure needed for a clean energy future, said Hartman, former CEO of the Electricity Consumers Resource Council (ELCON). He called for re-evaluating the regulatory structure.
Hartman was joined by current ELCON CEO Travis Fisher.
“A different way to view it is the difference between a state-level mandate versus a corporate goal,” said Fisher, previously economic adviser to former FERC Commissioner Bernard McNamee. A corporate goal can be dropped if things go poorly, there are reliability issues or the cost is too high, he said.
“It doesn’t take an act of state or Congress to drop that,” Fisher said. “The more rigid and the more top-down mandated it is, that’s where you get into problems. [Policy questions] can be borne out through voluntary transactions … instead of saying, ‘We know the answer has to be X, and we have to do it by year Y.’ I don’t think that’s the correct way to go about it.”
The discussion was framed the around a new report by the Energy Choice Coalition (ECC) on the environmental benefits of competition in electricity markets, which found that RTO/ISO regions have reduced their power sector CO2 emissions by about 35% from 2005 levels, while non-RTO regions have reduced theirs by about 27%.
Furthermore, the report found that RTO regions with more competitively owned generation, such as ISO-NE, NYISO and PJM, posted even deeper reductions: 61%, 56% and 41%, respectively, said Joshua Rhodes, research associate at the University of Texas at Austin and a founding partner of energy consultancy IdeaSmiths, which conducted the study.
Clockwise from top left: Robert Dillon, Energy Choice Coalition; Landon Stevens, Conservative Energy Network; Joshua Rhodes, University of Texas Austin; Travis Fisher, ELCON; and Devin Hartman, R Street Institute | ConservAmerica
The study also found that RTO/ISO regions deployed almost 80% of all utility-scale renewable generation capacity, despite accounting for 67% of all existing power plant capacity. In addition, RTO/ISO regions have seen stronger growth in distributed solar PV, increasing by about 214% versus non-ISO regions at 199%.
“You’re never going to get a pure market in this area because there are a lot of different drivers,” said Robert Dillon, executive director of the ECC and a member of the leadership team at ConservAmerica.
The environmental and regulatory aspects of the wholesale level also apply to retail, whether for the large corporations like Google and Microsoft wanting a certain supply of clean energy, or private homeowners that want to install storage or solar, Dillon said.
“Their ability to choose is a market driver; [it’s] a great principle compared to government saying, ‘You’re going to build this traditional huge coal or gas or nuclear plant on the edge of town and running wires through the city,’” Dillon said.
The discussion of the clean energy transition tends to get stuck in a dichotomy of either the Texas model on one hand or vertically integrated markets on the other, said Landon Stevens, director of policy at Conservative Energy Network (CEN), a group of state-based clean energy advocacy organizations.
“There’s actually a lot of different policy decisions that can be made along the way,” said Stevens, who described himself as a “recovering regulator.” He previously served as policy adviser to former Arizona Corporation Commissioner Andy Tobin and his successor, current Commissioner Lea Marquez Peterson.
It’s a big opportunity when about half of the country is trying to consider what the next market designs look like, he said, referring to the West.
The West is considering “an RTO model that we designed in 1995, and I would say there’s probably a lot of changes you can make to that model that would be more tailored to today’s solutions,” Stevens said. “We need to look at those really long and hard, and that’s where we have a lot of research coming down the pipe. … What does an RTO 2.0 look like, or is there a whole new model paradigm that we need to consider to incorporate some of these new technologies and leave room for that innovation?”
A special inspection team sent by the Nuclear Regulatory Commission to the Davis-Besse nuclear power plant in Ohio on July 27 has issued five safety findings that it discovered during an examination of the plant’s steam system following an automatic reactor shutdown July 8.
NRC on Friday issued a 69-page report in which inspectors called the shutdown “complicated” because of the failures of a steam system and electromechanical steam line controls.
The problems started when the plant’s main steam turbine tripped off, causing the reactor to shut down without incident. But engineers had to manually shut valves to fix steam system problems after the electromechanical controls failed to work, according to the report.
The six-member inspection team concluded that Davis-Besse engineers had installed the wrong part in a switch controlling the steam valve system and that overall the plant had inadequate “procedural guidance” for control room operators in such a situation.
The commission is still determining the safety significance of two of the five findings, involving the failure of the plant’s emergency diesel generators (EDGs) five times over 24 months preceding the July shutdown. The failures occurred during routine testing to make sure the EDGs would instantly start and instantly generate electricity.
The inspection team reviewed the efforts by Davis-Besse’s engineers to find the cause of the failures of the large EDGs during routine testing. The inspectors determined that there had been inadequate maintenance in one case and the use of an updated but inappropriate electronic part in another case. The correct, updated parts have been installed since the failures.
NRC is now doing a complicated risk assessment of the failures of the EDGs to start as designed, as failure during an actual emergency involving the reactor could lead to catastrophic consequences.
EDGs must be able to automatically start and immediately generate power when a reactor shuts down and the plant is simultaneously cut off from grid power, making their operability critical during an emergency.
A nuclear power plant requires about 4 MW to run all its operating, safety and control systems. If the generators are inoperable during an emergency, a battery backup system powers certain emergency equipment for a limited number of hours.
Davis-Besse is owned by Energy Harbor, the successor to FirstEnergy Solutions. Davis-Besse is owned by Energy Harbor, the successor to FirstEnergy Solutions. Energy Harbor did not respond to a request for comment.
Municipal utility Seattle City Light wants the same legislative green light to manufacture hydrogen for fuel that Washington’s rural public utility districts (PUDs) have received.
In 2019, Washington’s legislature passed a law that allows the state’s PUDs to produce and distribute hydrogen. The state’s municipal utilities do not have that legal authorization.
“We would like municipal hydrogen authorization,” Mendy Droke, government and legislative affairs advisor for Seattle City Light, said Thursday at a briefing of the Washington House Environment and Energy Committee.
While committee members did not say whether they would tackle such a bill in their 2022 session, Droke’s statement addressed a question from Rep. Alex Ramel (D) about whether municipal utilities should have that authorization. Ramel is active in climate change legislation in Olympia.
Washington has no infrastructure to support fuel cell vehicles (FCEVs) powered by hydrogen.
But the Douglas County PUD plans to start operating a hydrogen manufacturing plant in the first quarter of 2022 along the eastern shore of the Columbia River in central Washington. The $25 million facility is expected to produce two tons of hydrogen per day with plans to expand when more output is needed. (See Wash. PUD Breaks Ground on Hydrogen Plant.)
“We want to make Douglas County a hotbed of hydrogen production,” PUD General Manager Gary Ivory said.
Two hydrogen refueling stations are on the drawing board in Douglas County and in Chehalis, which is south of Olympia. Both are slated to begin operating sometime in 2022. The first hydrogen-fueled vehicles in Washington will be a handful of buses to be operated by Twin Transit in Lewis County — which contains Chehalis — plus a few Douglas County PUD trucks.
By contrast, California has roughly 11,000 hydrogen-fueled vehicles and about 50 refueling stations, Jason Sekhon a senior consultant with Toyota North America, told the committee.
Sekhon said that Washington faces several challenges in bringing hydrogen-fueled vehicles to the state, including the current lack of local hydrogen production.
Sekhon said the state needs to build a hydrogen-refueling network prior to boosting the sales of the vehicles. Government agencies need to coordinate their refueling facilities so all agencies can use them. He added that tax exemptions should be set up for the earliest purchasers of hydrogen-fueled vehicles.
He said co-locating hydrogen refueling stations with gas stations is an easy path to take. A hydrogen-refueling station in California capable of handling 1,400 vehicles a day costs about $3 million to develop, roughly the same cost as an electric-vehicle charging center cable of handling the same volume of vehicles, he said. However, hydrogen refueling takes three to five minutes compared to up to 30 minutes for an electric recharging.
Seattle City Light and Tacoma Power plan to study getting into hydrogen vehicles and possibly production, said officials from those utilities.
