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October 30, 2024

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California PUC to Delay Net Metering Decision for a Year

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.”

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NJ to Invest $10.8M in EV Chargers, School Buses

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.

NEVI (NJ DOT, NJ BPU, NJ EDA, NJ DEP) Content.jpgNew 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.

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SPP Continues to Build on Markets+ Offering

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 2022-08-09 (RTO Insider LLC) Content.jpgPowerex’s Mark Holman listens to a discussion. | © RTO Insider LLC

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.

Steve Bruce 2022-08-09 (RTO Insider LLC).jpgSPP’s Steve Johnson (left) and Bruce Rew listen to Markets+ attendees. | © RTO Insider LLC

 

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.

Sarah Edmonds 2022-08-10 (RTO Insider LLC) FI.jpgSarah Edmonds, Western Power Pool | © RTO Insider LLC

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.”

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Infrastructure Law’s 2022 Funds to Double US Clean Bus Fleet

The U.S. Department of Transportation’s Federal Transit Administration (FTA) announced Tuesday that it’s releasing $1.66 billion in grants to nearly double the number of non-emission buses on the nation’s roads with just one year of funding.

The FTA’s awards will fund the purchase of 1,800 low- and no-emissions buses and construction of related facilities for 150 bus fleets in 48 states and territories.  

More than 1,100 of the buses will be zero emissions, helping to meet President Biden’s goal of net-zero emissions by 2050, the FTA said.

The DOT estimates that every zero-emission bus eliminates 1,690 tons of CO2 over an average 12-year lifespan, equivalent to removing 27 cars from the nation’s roads.  

During a briefing Monday preceding the announcement, FTA Administrator Nuria Fernandez said the funds will help cash-strapped transportation authorities modernize fleets while making the switch to more sustainable fuels.

“When a transit door opens, whether it is a bus, train or ferry, it is a great equalizer for everyone in our nation,” Fernandez said in a press release.

The bus grant awards are funded through last year’s Bipartisan Infrastructure Law and will be doled out under the FTA’s Buses and Bus Facilities and Low or No Emission Vehicle programs. Applicants were subjected to competitive grant selections. The FTA received 530 eligible applications requesting $7.7 billion in funding.

The Low or No Emission Grant Program allows transit agencies to buy or lease American-made vehicles, while the Grants for Buses and Bus Facilities Program encourages such agencies to purchase and rehab buses and vans and build maintenance facilities. The programs will receive $5.5 billion and $2 billion in infrastructure funding, respectively, over the next five years. For fiscal year 2022, $1.1 billion in grants were available under the Low or No Emission Grant Program, with the remaining $550 million available under the Buses and Bus Facilities Program. The amounts are approximately six times the previous five years of funding, the FTA said.

Examples of this year’s recipients include the New York Metropolitan Transportation Authority’s (MTA) $116 million purchase of about 230 battery-electric buses to replace diesel buses; the Los Angeles County MTA’s $104 million purchase of 160 battery-electric buses; the Memphis Area Transit Authority’s $54 million project to build an operations and maintenance facility; and the Colorado Department of Transportation’s $34.7 million electric charging bus depot for Summit Stage, a rural transit agency.

The administration’s distribution will also fund smaller ticket projects, like the $402,257 needed by the Metlakatla Indian Community in Alaska to buy a battery-electric bus and charging equipment to service a route to and from a ferry. The City of Midland, Mich.’s Dial-A-Ride service will receive $167,257 to buy electric vans to replace older gas buses. 

For the first time, funding will be earmarked to train transit workers on how to operate and maintain clean buses, the FTA said. The administration allocated 5% of this year’s funds to develop transit workforces.

Mitch Landrieu, White House infrastructure coordinator, said the country’s full transition to electric vehicles will continue with the newly passed Inflation Reduction Act, which focuses on substituting the country’s passenger and heavy-duty vehicle fleet with clean fuels. (See What’s in the Inflation Reduction Act, Parts 1 and 2.)

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Biden Signs Inflation Reduction Act

President Biden signed the $740 billion Inflation Reduction Act (H.R. 5376) into law Tuesday, kicking off an aggressive pre-midterm election campaign that, an executive memo said, “will use all the tools of the White House” to promote the law and its benefits to voters across the country.

Returning early from a family vacation in South Carolina, Biden put his signature to the new law surrounded by some of the key lawmakers who helped push it to passage, including Sen. Joe Manchin (D-W.Va.) Senate Majority Leader Chuck Schumer (D-N.Y.), and Reps. Jim Clyburn (D-S.C.), Frank Pallone (D-N.J.) and Kathy Castor (D-Fla.).

And he made immediate use of the White House bully pulpit with a passionate speech about the IRA and what it represents for the country, laying out the Democratic talking points for the November midterms.

Pointing to other recently passed legislation such as the Infrastructure Investment and Jobs Act and the CHIPS and Science Act ― which aims to boost semiconductor manufacturing in the United States ― Biden said, “We are in a season of substance. … We’re delivering results for the American people. We didn’t tear down; we build up. We didn’t look back; we look forward; and today offers further proof that the soul of America is vibrant; the future of America is bright; and the promise of America is real and just beginning.”

The IRA’s $369.75 billion in energy funding will, Biden said, “allow us to boldly take additional steps toward meeting all my climate goals,” which include decarbonizing the U.S. electric grid by 2035 and creating a net-zero economy by 2050. “It’s going to offer working families thousands of dollars in savings by providing them rebates to buy new and efficient appliances, weatherize their homes, [and] get tax credits for purchasing heat pumps and rooftop solar, electric stoves, ovens [and] dryers.” (See What’s in the Inflation Reduction Act, Part 1.)

A White House fact sheet released Monday parsed out the savings, including $1,000/year from clean energy and electric vehicle tax credits and $350/year from rebates on heat pumps and other energy-efficient appliances.

Biden also stressed the new law’s potential for creating “clean energy opportunities in frontline and fenceline communities that have been smothered by the legacy of pollution and [fighting] environmental injustice.”

The bill signing ends a three-week marathon by congressional Democrats to get the slimmed-down budget reconciliation package — originally the $2.2 trillion Build Back Better Act — to Biden before beginning their August recess and midterm campaigns. After behind-closed-doors negotiations, Schumer and Manchin unveiled the draft of the bill on July 27. The Senate passed it on a straight party-line vote on Aug. 7, followed by a similar vote in the House of Representatives on Aug. 12.

On Tuesday, Biden handed the pen he used to sign the bill to Manchin, signaling his thanks for the West Virginian’s role in drafting and passing the IRA.

“This important legislation will give energy companies the certainty they need to increase domestic energy production while also lowering energy and health care costs and pay down our national debt without raising costs for working Americans,” Manchin said in a statement. “I look forward to following this momentum by passing comprehensive permitting reform next month to ensure these investments become the energy projects we need to decarbonize and boost energy security.”

Reaction

Clean energy organizations quickly offered statements of thanks and praise but, like Manchin, also called for further action.

The IRA’s clean energy funding “is not a cure-all but rather an overdue federal component to combat the climate crisis,” said Stephen Smith, executive director of the Southern Alliance for Clean Energy. “This federal investment is a necessary cornerstone for climate action and clean energy commitments that must accelerate in all sectors of the economy on all levels — including state and local governments, the utilities that generate and deliver our electricity, corporations, and the collective actions of citizens.”

“Small businesses across the nation stand ready to deliver on the promise of this historic clean energy and climate legislation,” said Lynn Abramson, president of the Clean Energy Business Network. “The Inflation Reduction Act marks the start of a new era for deploying cleantech at unprecedented scale to drive down energy costs, cut emissions and boost our energy security.”

Abigail Ross Hopper, president and CEO of the Solar Energy Industries Association, said the new law provides “a long-term framework … for the solar and storage industry to drive economic growth in every zip code across the country.”

“It features long-term investments in clean energy and new incentives for energy storage, which give solar and storage businesses a stable policy environment and the certainty they need to deploy clean energy,” Hopper said.

Daniel Bresette, executive director of the Environmental and Energy Study Institute, said the new law will also send a message to other countries that the U.S. is serious about cutting its carbon emissions as they prepare for the next U.N. Climate Conference of the Parties in Egypt in November. “I hope this law will encourage world leaders to make more ambitious climate commitments, followed by their own transformative investments, and provide adequate support for decarbonization and climate adaptation efforts by developing countries.”

Judi Greenwald, executive director of the Nuclear Innovation Alliance, welcomed the law’s funding for advanced nuclear development, in particular its $700 million “to help make high-assay low-enriched uranium available for advanced reactor demonstration and commercialization through public and private partnerships and actions.”

But, echoing others, Greenwald said, “enactment of the IRA is just the beginning: Swift and effective implementation of this law will be crucial to ensuring it meets the goals intended by Congress and supported by the president with his signature today.”

‘Biden Backlash’?

Biden’s speech at the signing provided a preview of the Biden administration’s talking points for its “Building a Better America” campaign, in which “cabinet members will travel to 23 states on over 35 trips touting the Inflation Reduction Act and the administration’s accomplishments,” according to the White House memo first published by POLITICO.

For example, on Wednesday, Agriculture Secretary Tom Vilsack will be in Colorado for a roundtable discussion on the law’s benefits for agricultural stakeholders, while Interior Secretary Deb Haaland will be in California to talk about funding to tackle drought resilience. Digital strategy will include a “new, interactive website on climate incentives, including information for families, homeowners, small businesses and more on access to tax credits.”

The campaign will also develop “essential collateral”: talking points, graphics and state-by-state fact sheets to be distributed to state, local, tribal and territorial leaders.

Written by White House Deputy Chief of Staff Jen O’Malley Dillon and Senior Adviser Anita Dunn, the memo notes that “our internal polling shows that messages touting the cost-lowering features of the Inflation Reduction Act — lowering health costs, prescription drug costs and utility bills — are among the highest testing messages ever.”

Another core message of the campaign will emphasize how “the president and congressional Democrats defeated special interests,” while Republicans sided with special interests.

But industry analysts ClearView Partners argue that the new law could trigger “a new wave of ‘Biden backlash’ ― a GOP-led defense of legacy economic franchises against energy transition technologies and environmental, social and governance (ESG) standards.”

With Democrats seen as the party of green energy and Republicans the party of fossil fuels, ClearView predicts a 2023 Biden backlash in state legislatures, focused on four types of energy initiatives:

  • restrictions on the closure of existing gas- or coal-fired plants;
  • imposition of production taxes — as opposed to production tax credits — on renewable energy generation;
  • siting restrictions on new solar and wind; and
  • bans on local restrictions or prohibitions on natural gas hook-ups.

Republican leaders Tuesday similarly provided a preview of the party’s messaging ahead of the midterms.

“Democrats robbed Americans last year by spending our economy into record inflation,” Senate Minority Leader Mitch McConnell (R-Ky.) tweeted. “This year, their solution is to do it a second time. The partisan bill President Biden signed into law today means higher taxes, higher energy bills and aggressive IRS audits.”

“Biden just signed a bill to raise taxes during a recession, send the IRS after the middle class and give rich liberals tax credits to buy luxury electric vehicles,” tweeted Ronna McDaniel, chair of the Republican National Committee.

But ClearView also sees a longer-term shift in which “party-line energy policy cleavages could fade due to fundamentals. Green power (wind energy especially) already contributes significantly to red-state generation mixes. As renewables proliferate on GOP-represented grids, their economic and political relevance to state (and federal) government officials seems likely to increase too.”

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ISO-NE Wants to Hike its Budget by 10% in 2023

ISO-NE is proposing a roughly 10% increase in its operating budget for 2023 and the addition of more than 50 employees over the next two years as it looks to reshape the region’s electricity markets.

According to a presentation by ISO-NE CFO Robert Ludlow to NEPOOL’s Budget and Finance Subcommittee on Thursday, the grid operator’s proposed operating budget of $209 million is a more than $20 million boost (before depreciation) over that of 2022 and would require $9.475 million more in revenue.

Part of that budget bump is that the grid operator plans to add 52 full-time equivalent positions by 2024, 32 in 2023 and 20 the next year. The largest group of new jobs would be nine additions in market development, as the RTO continues to try to move forward on complex work to update the Forward Capacity Market, including with resource capacity accreditation and new day-ahead ancillary services.

ISO-NE is also proposing to add eight positions to its information and cybersecurity office, five for system planning, and two each in participant relations, advanced technology solutions, system operations and market administration, external affairs and HR.

And it’s budgeting more — $8.4 million in total — for employee raises and benefit increases, plus recruiting, retention and succession planning.

The grid operator’s 2023 capital budget is $33.5 million, a $7 million increase over those of the last few years, driven by the next generation markets project, other market and reliability initiatives, cybersecurity enhancements, and information technology and infrastructure replacements.

The budget finds $3.4 million in savings, including lower salary rates from turnover and retirements, less building maintenance, fewer software licensing costs and more.

Because ISO-NE is funded by fees from market participants and ratepayers, the budget is scrutinized closely by consumer advocates and state officials. The RTO is currently in the process of running the budget by state agencies and planning to ask for a NEPOOL Participants Committee vote in October, shortly followed by a Board of Directors vote and FERC filing.

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FERC Rejects PJM’s Reserve Deployment Proposal

FERC on Monday rejected PJM’s proposal to change how it handles synchronized reserve events, saying it would likely result in higher prices and lead the RTO to procuring more energy than the system actually needs during emergencies (ER22-1200).

Called Intelligent Reserve Deployment (IRD), PJM’s proposed construct would have it use a real-time security-constrained economic dispatch (RT SCED) case that simulates the loss of the largest generation unit on its grid during a synchronized reserve event. Such events can be caused by the loss of generation, loss of transmission or sudden increase in load.

Currently, PJM responds to these emergencies by issuing an “all-call” message to all market participants to deploy their available resources. The RTO argued that IRD would be more efficient and that, by using RT SCED, it would better align prices with actual grid conditions and trigger resource-specific responses.

But FERC was unpersuaded, ruling 4-1 that IRD “fails to model actual system conditions.

“It therefore is likely to result in artificially inflated prices and thus prevent PJM from achieving a least-cost dispatch solution to address synchronized reserve events, which could in turn produce a misalignment between prices and actual system conditions.”

IRD would simulate the loss of the generator by effectively increasing the load forecast by the equivalent capacity. Thus, FERC found, it would not lead to accurate dispatch, as most reserve events are likely to be smaller in nature.

“IRD would result in PJM setting prices as though the largest contingency had occurred, and then immediately procure additional reserves accordingly, without regard for the size and location of the actual system event,” the commission said. Even if the emergency were the result of the largest contingency, “the IRD SCED case might not be representative of actual system conditions if the contingency event occurs near a constraint or within a reserve sub-zone … because IRD would model an RTO-level increase in load,” FERC said.

PJM filed its proposal in March under Section 205 of the Federal Power Act, after it received final stakeholder approval in January, though with 18 objections. (See “Consent Agenda,” PJM MRC/MC Briefs: Jan. 26, 2022.) FERC acknowledged that the current all-call approach could be improved upon, but the RTO “must show that any such proposed methodology produces just and reasonable rates.”

FERC agreed with arguments by the RTO’s Independent Market Monitor and the PJM Industrial Customer Coalition that the proposal would result in unjustly higher prices. But it also noted that, in response to their protests, PJM had acknowledged that the price resulting from IRD cases “is not perfect,” though it emphasized that it would be more accurate than under the all-call approach.

“Even if that characterization were true, that does not render this particular proposal to use the largest contingency in the IRD case just and reasonable,” the commission said.

Danly Dissent

Commissioner James Danly dissented, arguing that PJM “easily met its Section 205 burden” and rejecting the majority’s conclusion that IRD would “artificially inflate prices.”

“I see nothing wrong with modeling the single largest reliability contingency during a reserve shortage, for example, when the system is dangerously exposed to a subsequent reliability event,” Danly said.

Danly argued that IRD would clearly be an improvement over the all-call approach, which he said “is essentially an email blast” that “apparently is routinely ignored by resources not subject to nonperformance penalties. It does not take an engineer to identify a legitimate reliability risk here.”

“I would not reject a clear reliability enhancement merely because it results in potentially higher (albeit more efficient) prices,” he said. “FPA Section 205 contemplates broad discretion for utilities to grapple with challenges and opportunities as they see fit. This filing easily fits within the range of acceptable filings.”

He concluded that, despite rejecting the proposal, “we at the commission will enthusiastically join the throngs blaming PJM if, down the road, it suffers a blackout caused by back-to-back reliability events.”

The majority responded to Danly’s dissent by noting that PJM acknowledged that the system would remain reliable without IRD. It also argued that part of Danly’s argument was apparently based on the fact that Tier 1 synchronized reserve resources are not subject to nonperformance penalties, but it noted that the commission had already approved PJM consolidating Tier 1 and 2 resources into a single product, which will be subject to penalties and go into effect Oct. 1. (See FERC Approves PJM Reserve Market Overhaul.)

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ERCOT Names NiSource’s Vegas as New CEO

AUSTIN, Texas — ERCOT announced Tuesday that it has selected Pablo Vegas, a senior executive with Indiana-based utility NiSource, as its next CEO.

Vegas, currently an executive vice president with the company and group president of NiSource Utilities, will join the Texas grid operator on Oct. 1. He will replace interim CEO Brad Jones, whose 90-day temporary gig has stretched into a 16-month assignment.

The announcement came during the Board of Directors’ bimonthly meeting and was quickly ratified by the Texas Public Utility Commission.

Vegas will be expected to guide ERCOT as it continues to make changes following the February 2021 winter storm that nearly brought the Texas Interconnection to its knees. A massive loss of generation led to dayslong outages that resulted in hundreds of deaths and billions of dollars in damages.

Pablo Vegas (NiSource) FI.jpgPablo Vegas, NiSource | NiSource

“With Pablo, we’re getting the leader we’ve been looking for: extensive experience with regulated utilities; a demonstrated record of managing a system of diverse energy resources; and most importantly, unwavering commitment to reliability,” board Chair Paul Foster said after breaking the news. “With this unanimous vote, it is clear that this board believes we have found an exceptional executive who can successfully lead this organization.”

The board approved Vegas’ selection and compensation package during an executive session Monday. The announcement was made at the start of the board meeting Tuesday as it became apparent to the directors that the news had been leaking out and represented “a risk to the [employment] agreement.” One market insider said they had first heard Vegas’ name last Thursday.

NiSource is one of the largest fully regulated utility companies in the U.S., serving approximately 3.2 million natural gas customers and 500,000 electric customers across six states through its Columbia Gas and Northern Indiana Public Service Co. brands.

Vegas, who was only promoted to his present position on July 1, signed his contract Monday. He was not in Austin on Tuesday or available for comment. ERCOT directors and staff declined to comment.

“I’m excited to return to Texas both personally and professionally,” Vegas said in a statement. “This is a once-in-a-lifetime opportunity to lead an exceptional organization of people and make a positive impact on millions of Texans.”

Before joining NiSource in 2016, Vegas spent 11 years with American Electric Power. He served as president and COO of both AEP Texas, for two years, and AEP Ohio. Vegas has a bachelor’s degree in mechanical engineering from the University of Michigan and held senior leadership positions with Andersen Consulting and other firms before joining the utility industry.

Judith Talavera, who currently holds Vegas’ titles for AEP Texas, said his time in the state “gives him a unique understanding” about the ERCOT system’s strengths and weaknesses.

“His experience in Texas and his leadership positions at AEP Ohio and NiSource will serve him well in his new role as ERCOT CEO. We look forward to working with him,” Talavera said in an email to RTO Insider.

“It doesn’t hurt that this isn’t his first rodeo in Texas,” Foster told the board. “Pablo knows our current market; he knows the incredible progress we’ve made in the last year implementing landmark reforms; and he knows how to turn the challenges we face into opportunities to strengthen the competitive market in Texas.”

“He has been an invaluable member of our leadership team, and I along with the entire NiSource community will miss working with Pablo, and we wish him the best in his new role at ERCOT,” NiSource CEO Lloyd Yates said in a press release.

Vegas’ hiring comes after several sources told a Texas newspaper that Gov. Greg Abbott stepped in to reject an earlier selection of former CAISO CEO Steve Berberich. (See ERCOT Could Name New CEO this Week.)

According to his employment contract, Vegas will earn a base salary of $990,000 and a one-time lump sum payment of $247,500 on or before Dec. 31. He will also receive make-whole payments of $6.68 million through 2027, when his contract ends. Beginning next year, Vegas will be eligible for incentive payments that could equal his base salary, assuming he meets key performance indicators.

Former ERCOT CEO Bill Magness, who was fired in March 2021 following the winter storm, disclosed during testimony before the Texas Legislature last year that his annual salary was $803,000. Jones’ annual salary is $500,000, and he is a due a one-time lump sum of $169,640 when he receives his final paycheck.

South Texas Electric Cooperative’s Clif Lange, chair of ERCOT’s Technical Advisory Committee, said the group looks forward to working closely with Vegas when he takes over.

“He faces some very big challenges as he transitions into the role, with a number of initiatives already started but with many still ahead,” he said, referring to the second phase of ERCOT’s market design. “I’m optimistic that he’ll be able to lead ERCOT successfully in implementing those.”

Director Bill Flores led the selection committee in what was termed an “exhaustive” nationwide search. He said the group identified 107 candidates and interviewed 21.

The directors, ERCOT staff and stakeholders saluted Jones with a standing ovation after the announcement was made.

“Twenty-six million Texans owe you a real debt of gratitude for everything you and the team have done to persevere through the challenges faced with record heat and cold winters,” Flores said.

A smiling Jones pointed to his grin as he greeted well-wishers during the meeting’s first break. He will spend October helping Vegas transition into his new position before resuming a retirement that was interrupted by the winter storm.

“Brad stepped in as our interim CEO during a very challenging time and was unquestionably the leader ERCOT needed at a most difficult time,” Foster said. “He’s also stayed much longer than originally anticipated.”

“Hopefully, his next endeavor includes an enjoyable and relaxing retirement, although I will bet that he will remain engaged in the electric industry. It’s in his blood,” Lange said. “He’s faced a monumental task in overseeing a significant overhaul of ERCOT’s priorities, and while it’s not always been popular, he’s been very successful in navigating those changes.”

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Diablo Canyon Extension Effort Gears up

The movement to keep California’s last nuclear plant operating beyond its impending retirement has gained new momentum with the prospect of billions of dollars in state and federal funding, support from Gov. Gavin Newsom, and the clearest indication yet that plant owner Pacific Gas and Electric (NYSE:PCG) could go along with the plan.

PG&E has been planning to shut down its 2.2-GW Diablo Canyon nuclear power plant by 2025, a move sought by anti-nuclear activists concerned with seismic safety and by PG&E, largely for economic reasons. In 2016, the state’s largest utility signed an agreement with environmental, labor and anti-nuclear groups to close the plant on California’s Central Coast rather than invest billions of dollars in environmental and safety upgrades.

Now, however, proponents see the continued operation of Diablo Canyon — the state’s largest generator producing about 8.5% of total capacity — as vital to ensuring grid reliability during the state’s transition to 100% clean energy by 2045. Energy emergencies during the past two summers and the likelihood of continued shortfalls caused by wildfires, drought and extreme heat have prompted some who supported the closure to reconsider, including the governor.

Newsom’s office circulated draft legislation Thursday that would lend PG&E up to $1.4 billion in a forgivable loan to keep Diablo Canyon open for an additional five to 10 years beyond its planned retirement date.

“It is a very difficult decision, and it’s a last resort,” Ana Matosantos, Newsom’s cabinet secretary, said in a workshop Friday hosted by the California Energy Commission and CAISO. Supply-and-demand forecasts based on historical data “are not necessarily reflecting our real-term reality and the speed at which the impacts of climate change are being experienced by our people and by our energy system,” she said.

In extreme scenarios, cumulative disruptions from weather and fire could leave the state 7,000 MW short this summer and up to 10,000 MW short by 2025, CEC analysts said in May. The gap could be as little as 1,700 MW this summer and 1,800 MW in 2025 without cumulative crises, they said. (See Heat, Fire and Supply Chain Woes Threaten Calif. Reliability.)

In addition, peak summer demand has shifted later in the day, after solar ramps down on hot evenings, resulting in shortfalls, and demand is expected to increase as millions of electrical vehicles replace gas-powered cars and trucks in coming years.

“The net of all of these pieces is that we are behind where we need to be in bringing our clean resources online to ensure that we can retire these [other] resources,” Matosantos said. “And so, we are meeting to have the very difficult conversation around an extension [of Diablo Canyon], the terms and the conditions under which an extension would be done, and the duration of any extension to make it as short as possible.”

Funding Possible

The availability of billions of dollars in federal aid could make an extension more feasible.

Matosantos wrote to U.S. Energy Secretary Jennifer Granholm in May, asking that the Department of Energy amend its eligibility criteria for the Biden administration’s $6 billion Civil Nuclear Credit Program (CNC), funded under November’s Infrastructure Investment and Jobs Act. The program is meant to assist nuclear plants at risk of closure for economic reasons.

In an April guidance, DOE had said CNC funding is for nuclear plants that participate in competitive energy markets and do not recover more than 50% of their costs from cost-of-service ratemaking. PG&E recovers its Diablo Canyon costs from customers under rate cases approved by the California Public Utilities Commission and would not qualify for CNC funding under that interpretation.

Matosantos requested that DOE’s guidance be changed to exclude the cost-of-service requirement. The department approved the change on June 30 and extended the application deadline for the first round of CNC funding to Sept. 6.

PG&E has said it will apply for the funding. Company CEO Patti Poppe said in a July 28 earnings call that the company was looking to keep Diablo Canyon open — the strongest company statement of its kind — but warned parties that the “clock is ticking” on the time needed to switch from decommissioning the plant by 2025 to operating it through 2035.

State and federal entities, including the U.S. Nuclear Regulatory Commission and the California State Legislature, will need to weigh in to make that happen in an accelerated time frame.

State Sen. John Laird, who represents the district containing Diablo Canyon, said at Friday’s workshop that the speed at which the plant might reverse course would contrast sharply with the effort to close the plant, which took years.

“Endless hours and millions of dollars have been used to plan for the plant’s closure and coordinate with local state and regulatory bodies on the decommissioning effort,” Laird said.

Questions about cost, safety and environmental impacts, including nuclear waste storage, remain unanswered, he said. Laird also questioned the potential effects of keeping the plant open on offshore wind development. Floating wind turbines off the coast near Diablo Canyon, in the planned Morro Bay wind energy area, are expected to connect to CAISO’s grid using transmission lines that now serve the plant.

“I don’t see a pathway to Diablo Canyon’s continued operation unless each of these elements is addressed,” Laird said. “No proposal can be complete without that.”

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Members Near Vote Over PJM, IMM Black Start Fuel Requirements

VALLEY FORGE, Pa. — Capping four years of discussions and analysis, PJM held a first read of proposed fuel assurance rules for black start resources (BSRs) at the Market Implementation and Operating committee meetings Wednesday and Thursday.

PJM has considered fuel supply capabilities along with other technical, operational and cost factors in awarding black start contracts in the past. In 2017, the RTO increased the weighting of fuel assurance in its evaluation of responses to requests for proposals. But current rules have no fuel assurance requirement other than an existing tariff provision requiring black start units to maintain enough fuel for 16 hours of run time.

PJM’s Janell Fabiano said work on the black start proposals — which included a two-year “hiatus” in stakeholder discussions while PJM conducted analyses of restoration times, costs and benefits, and gas supply risks — was an “epic process.”

In the 2018 problem statement launching the effort, PJM said only about half of the units in its black start fleet were fuel assured “through dual-fuel capability, on-site fuel storage or multiple gas pipeline connections.”

The committees heard presentations on two competing proposals, one from the Independent Market Monitor and a second cosponsored by PJM, Brookfield Renewable and the D.C. Office of the People’s Counsel.

Only 23% of stakeholders supported the Monitor’s proposal in polling in June. Nearly three-quarters of stakeholders said they supported PJM’s proposal before it was combined with one from Brookfield and the OPC, which had received 37% support.

PJM Package

The PJM package would select black start sites based on their fuel assurance, giving top preference to units with on-site fuel storage (e.g., dual fuel), followed by those connected to multiple pipelines and then gas-only sites connected to a single source fed directly from a gas supply basin or gathering system ahead of an interstate pipeline.

After that, PJM ranks fuel-assured hydro units (pump storage and run-of-river), followed by fuel-assured intermittent or hybrid sites. The last choice would be at least two gas-only sites in a transmission owner’s zone connected to two separate interstate gas pipelines.

Additional black start units would be solicited for eight “high-impact” sites in which incremental restoration time would be 10 hours or longer with the loss of a non-fuel-assured black start site.

Mitigation of the eight sites in five TO zones would add $28.2 million to the current annual black start cost of $68.2 million, a 41% jump, according to PJM.

IMM Package

The IMM said existing BSRs lacking fuel assurance should correct the problem or have their black start status terminated, with penalties for nonperformance.

The Monitor also would require predefined emission and effluent waivers to accommodate operations during restoration rather than PJM’s proposal that generators use their “best efforts” to obtain permit modifications or waivers.

For dual-fuel resources, the Monitor would require testing of both fuels annually, including a demonstration of the ability to switch between fuels. PJM proposes separate testing for each fuel in the same year. The IMM also would require concurrent annual tests of all BSRs connected to the same fuel source. PJM would not.

PJM would increase the “Z factor” incentive from 10% to 20% for fuel-assured resources selected via the RFP. PJM said the change would cost $436,000 annually.

The IMM would keep the base formula rate incentive factor for such units at 10%. The incentive is multiplied by the sum of fixed and variable black start service costs plus training and fuel storage costs.

The Monitor would also end PJM’s current practice of allowing transmission owners to provide black start service under a “backstop” process following two failed RFPs. “TOs should not own generation,” the Monitor said.

The IMM also opposed PJM’s proposal to allow intermittent resources to seek black start contracts. The Monitor said intermittent resources, other than run-of-river hydro, should not be considered BSRs because they cannot be assured of being available when needed.

PJM’s Tom Hauske said the RTO wanted to allow intermittent resources with storage to offer as black start and to anticipate future technologies. “It’s not going to be easy” for renewables to qualify, he acknowledged.

In a presentation of the IMM’s proposal, Monitoring Analytics President Joe Bowring took exception to the fact that PJM had decided not to impose penalties on intermittent resources that registered as fuel-assured BSRs but failed to meet the new rules, saying that this was “discriminatory” and “doesn’t make any sense.”

PJM said the penalties would be unfair to intermittent resources because the RTO would be responsible for calculating confidence levels for such generators.

Generators are responsible for their own performance, regardless of whether PJM defines the performance standard, Bowring said.

Zonal vs. Regional Plan

Bowring also challenged PJM’s plan to award black start sites, and allocate their costs, by TO zone.

“From a PJM perspective, the zonal approach is the correct approach,” said Dan Bennett, who presented PJM’s proposal. “No one knows a zone more than the transmission operator. They are the right people to be managing this.”

Bowring said TO zones are anachronisms under PJM’s regional management of the grid and that the RTO should take advantage of cross-zonal benefits.

“The fact that TOs can do it is irrelevant,” Bowring said. “There is no magic to zones. Zones are arbitrary. PJM has unfortunately taken the position that TOs are more capable than itself. It’s PJM’s responsibility to do it.”

Greg Poulos, executive director of the Consumer Advocates of the PJM States, said some advocates are not convinced there is a need for black start units in every TO zone. “We are interconnected, unlike ERCOT,” Poulos said. “We do have the ability to have other resources help us.”

Impact on Existing Resources

Stakeholders voiced confusion and concern over the proposed changes, asking for clarification on how they would impact current BSRs that do not register as being fuel assured.

Paul Sotkiewicz of E-Cubed Policy Associates summarized many of these concerns when asking whether the process would be “voluntary” and whether it “would negatively impact BSRs that do not officially register as being fuel-assured.”

PJM responded that the new rules would not impact existing BSRs and were a voluntary process that sought to give additional compensation to eligible generators. Bennett encouraged stakeholders to continue providing feedback or suggestions that would make the packages “stronger because of teamwork.”

The BSR discussions exceeded the allotted time in both the MIC and OC meetings. PJM has scheduled a special meeting for Aug. 25 on the issue. PJM is targeting a filing to FERC in December and an RFP in April 2023.

Dual Votes

Because both the MIC and OC took part in discussions, both will be involved in voting on the two proposals, PJM’s Fabiano said. Voting will open after the Sept. 8 OC meeting and close at 5 p.m. ET on Sept. 15. Only one representative per voting member may participate; if different representatives vote at the MIC and OC, PJM will consolidate the responses and validate one response per member.

Poulos thanked PJM for its work helping the advocates understand the cost-benefit of the fuel incentives. PJM used a range of probabilities of a coincident blackout and fuel delivery failure and a range of values of lost load to calculate the increase in the expected cost that could result if a black start site were unavailable because of fuel failure.

“I don’t think they’re all going to be for it, but I certainly think there’s going to be more support … than there would have been without PJM’s work,” Poulos said of his members.