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October 10, 2024

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NOLA Mayor Calls for Changes in Entergy Grid Planning

New Orleans Mayor LaToya Cantrell appears to be in lockstep with the city council’s desire for a more resilient electric grid following Hurricane Ida’s destruction.

Cantrell, a speaker during Wednesday’s virtual session of North America Smart Energy Week, used the opportunity to call for grid reinforcements, new transmission lines, microgrids and renewable energy. The event was originally slated to be held in New Orleans but was forced into a virtual format by Hurricane Ida.

Cantrell’s comments follow the New Orleans City Council’s recent ask for regulatory investigations into Entergy’s transmission planning and commission of a study of a new utility structure for the city. (See New Orleans Seeks FERC Inquiry into Entergy Planning Practices; Facing City Council Inquiry, Entergy Says it Could Sell New Orleans Utility Arm.)

Cantrell refrained from using Entergy’s name, but she said the 12 hours Ida spent over the city made clear that the grid needs work to prevent future storm-driven outages. She said while the city’s levees and sewerage authority “held the line,” the city’s energy infrastructure did not fare well.

“We saw that our investments in our levees and infrastructure protected the city from flooding,” she said. “At the same time, though, with the entire city losing power, we saw that our electric grid is in need of much, much investment.”

Cantrell called for a transmission buildout and localized renewable resources.

“Our power infrastructure should definitely include a mix of regional transmission and planning and local generation … That’s what we saw and learned firsthand,” she said. “And we must include … renewable energy in the planning so that New Orleans truly can be more resilient and sustainable.”

Cantrell said the city is focused on turning vacant lots into utility-scale solar installations.  She also said the city is installing new, more efficient turbines to serve the city’s Sewerage and Water Board.

She said her administration is focused on establishing a series of microgrids with renewable energy sources across hubs that the city used as disaster shelters.

“I’m looking for power lines to be underground,” she added.

New Orleans has a plan to halve its carbon emissions by 2035 and become carbon neutral by 2050. Entergy has said it wants to achieve net-zero emissions by 2050.

Cantrell’s comments run counter to those of Entergy Louisiana CEO Phillip May. He said transmission reinforcements, solar generation and microgrids would not have withstood Ida any better, nor would they have made for a swifter restoration in New Orleans. (See Entergy Fends Off Calls for Tx, Solar, Microgrid Investment.)

Entergy is also defending itself against accusations that it’s resisting MISO’s efforts to approve billions of dollars in new transmission that could bring competing energy suppliers into its service territory. (See Tensions Boil over MISO South Attitudes on Long-range Transmission Planning.)

Prolonged power outages aside, Cantrell said storm-hardening of other city infrastructure worked as designed during Ida.

“When I think about where we were 16 years ago, we’re nowhere where we were before, so that’s a good thing,” she said, referencing Hurricane Katrina’s 2005 strike.

Cantrell recalled that soon after Katrina, city planners recommended that her Broadmoor neighborhood not be restored and instead be converted into one of several new drainage areas. A neighborhood organization president at the time, she said those plans deepened her community involvement.

“All hell broke loose,” she said. “We absolutely moved into activation, proclaiming that Broadmoor would live and we would not become a drainage park. But we would adapt ourselves to mitigating flooding, embracing green infrastructure, and that’s what we did.”

New Orleans is interested in all forms of innovation to address climate change and achieve a carbon-free future, Cantrell said. She said the city welcomes new ideas in water management, battery development and electric vehicles.

“Come to New Orleans,” she said. “We’re a place to build and test your solutions.”

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Mass. to Test Solar in Highway Built Environment

The Massachusetts Department of Transportation (MassDOT) has received $1.23 million in grant funding from the state to develop five solar projects, including a pilot to install solar panels on highway sound barrier walls in Lexington.

“It’s an opportunity to see if it’s a means to develop existing infrastructure and combine it with solar,” Donald Pettey, program manager with MassDOT, told NetZero Insider.

If the setup works, the panels will generate 800 MWh/year, Pettey said.

Solar panels will be mounted on 160 sound barrier wall sections along I-95. According to state officials, the pilot will be the first of its kind in the country.

The funding for pilot comes from the Massachusetts Department of Energy Resource’s Leading by Example program, which provides grants for state entities that help increase the installation of solar photovoltaic systems at state facilities, particularly solar canopies and innovative solar technologies.

“The efforts by the Leading by Example team, MassDOT and other state institutions have resulted in greater solar and EV adoption,” Gov. Charlie Baker said in a statement. The pilot project from MassDOT is assisting the state in its “efforts to meet ambitious net-zero emissions requirements set forth by legislation signed earlier this year.”

The section along I-95 in Lexington was selected for the pilot because the sound barrier was built recently and won’t require an upgrade during the solar project’s lifetime, Pettey said.

Wall sections for the project are also high up with little plant growth in front of them, and they receive a lot of sunlight.

“We don’t want to be cutting down any trees,” Pettey said.

Some conservation groups and farmers in Massachusetts oppose large-scale solar farms planned for forested lands, open space and agricultural fields, but Pettey said it has been cheaper to build ground-mounted solar installations on previously undeveloped land.

However, the state’s Solar Massachusetts Renewable Target incentive program is steering away from ground-mounted solar and providing more credits for projects in underutilized spaces that are already developed, like carports or highways.

With the costs of steel increasing, Pettey said some projects in the built environment would not be possible without grants from the state.

“The cost per watt to install solar canopies is still pretty high,” Pettey said.

Lexington is also a designated environmental justice community. About half of the town’s population falls under that category, according to state data. If effective, the project is a way to bring clean energy to the grid in a town overburdened by pollution, Pettey said.

The agency received $365,000 to build solar canopies at park-and-ride sites in Plymouth, Harwich and New Bedford, and a $520,000 grant for a 773-kW solar canopy at the new Central Massachusetts Transportation Center in Worcester.

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FERC Deadlock Allows Revised PJM MOPR

PJM’s narrowed minimum offer price rule (MOPR) took effect Wednesday after FERC deadlocked 2-2 on the RTO’s proposal to apply it only to resources connected to the exercise of buyer-side market power or those receiving state subsidies conditioned on clearing the capacity auction.

The proposal, filed by the Board of Managers on July 30, became effective “by operation of law” under Section 205 of the Federal Power Act when the commission failed to act on it within 60 days.

“The commission did not act on PJM’s filing because the commissioners are divided two against two as to the lawfulness of the change,” the commission said in a notice (ER21-2582).

Chairman Richard Glick and Commissioner Allison Clements, Democrats who said PJM’s “expanded” MOPR (MOPR-Ex) was undermining renewable growth, are believed to have supported the PJM filing, with Republicans James Danly and Mark Christie apparently opposed. The commissioners are expected to file statements explaining their positions.

The PJM board backed the “focused MOPR” proposal that was approved by almost 84% of stakeholders in June — the only one of nine proposals voted on to receive majority support. Chair Mark Takahashi said it “accommodates state policy and self-supply business models,” addresses “attempted exercises of buyer-side market power” and creates a “sustainable market design” by “keeping clearing prices consistent with supply and demand fundamentals.”

The vote concluded an 18-month saga that whipsawed PJM and caused the cancellation of the 2020 Base Residual Auction (BRA).

PJM adopted the extended MOPR in response to FERC’s 2-1 ruling in December 2019 saying it should apply to all new state-subsidized resources to combat price suppression in the capacity market (EL16-49, EL18-178). Then-Chair Neil Chatterjee and fellow Republican Bernard McNamee formed the majority, with Glick angrily dissenting. Glick asked PJM to undo the rule after he was named chairman by President Biden in January.



PJM’s proposed procedure for determining whether a market participant is exercising buyer-side market power | PJM

Market participants will be asked to sign attestations declaring they are not exercising market power or receiving state funds tied to clearing in the auction. PJM and the Independent Market Monitor will conduct “fact-specific, case-by-case reviews” if market power is suspected, and referrals will be made to FERC for a final determination.

PJM’s filing was opposed by gas-fired merchant generators as well as some electric cooperatives and state utility regulators. (See Mixed Stakeholder Reception to PJM MOPR Replacement.)

The new rules — which will eliminate both the expanded MOPR and PJM’s prior MOPR, which was limited to new natural gas resources — will be effective for the 2023/24 delivery year BRA scheduled to begin Dec. 1.

PJM has asked FERC to delay the auction by nearly two months to give it time to respond to a commission order on unit-specific offer review thresholds (ER21-2877). (See PJM Proposing 2-Month Capacity Auction Delay.) The Monitor reminded market participants Wednesday that the deadline for submitting market seller offer cap (MSOC) requests and must-offer exception requests for the auction is Oct. 1.

Reaction

Renewable advocates on Wednesday expressed relief over the approval of the new MOPR but regret that they came without an explicit imprimatur from FERC.

“It is disappointing that a majority of the commissioners could not agree on these important principles of federal and state comity and send a strong signal that it is not the place of federal regulators or wholesale market rules to ‘mitigate’ state clean energy policies,” said Jeff Dennis, general counsel of Advanced Energy Economy.

Sean Gallagher, vice president of state and regulatory affairs at the Solar Energy Industries Association, said the focused MOPR is “a vast improvement for the PJM market.”

“As proposed, the MOPR would have undermined PJM’s competitive market and punished states and independent power producers for providing affordable clean energy during annual capacity market auctions. The focused MOPR clears a path forward for IPPs that want to bid into PJM’s Base Residual Auction and acknowledges the right for states to choose affordable and reliable clean energy,” he said. “The focused MOPR also removes unnecessary administrative burdens and project assumptions that favor incumbent generators. The end result is a more efficient capacity market that protects market participants and customers alike.”

“Today is a great day for millions of ratepayers in PJM, America’s largest electricity market, who will be saved from paying more money than they should for clean power,” said Greg Wetstone, CEO of the American Council on Renewable Energy. “The MOPR, as previously designed, was a poorly disguised effort to undermine the success that low-cost renewables have enjoyed in competitive electricity markets nationwide by financially bolstering uneconomic fossil fuel generators. We commend PJM for working to reverse a destructive policy that distorted the market and directly conflicted with state efforts to accelerate the transition to pollution-free renewable power.”

“We’re considering all our options, including requesting rehearing,” said Todd Snitchler, CEO of the Electric Power Supply Association. “Given our strong protest in response to the PJM filing, we will continue to pursue what we think is the better path forward, which would be to reject the as-filed MOPR and allow sufficient time to pursue a more holistic approach to respond to the concerns raised by FERC and the states.”

Fears not Realized

Although MOPR-Ex was in place for the RTO’s 2022/23 BRA in May, predictions that it would inflate prices and block renewables’ entry did not materialize. Rest-of-RTO prices dropped by nearly two-thirds to $50/MW-day, and prices in the Eastern and Southwest Mid-Atlantic Area Council regions fell to their lowest on record. Nuclear generators, natural gas, renewables and energy efficiency increased their market share, while coal saw its contribution shrink. (See Capacity Prices Drop Sharply in PJM Auction.)

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NJ Proposes Cutting EV Incentives Amid Big Demand

New Jersey Board of Public Utilities (BPU) wants to halve the size of incentives available to consumers who buy electric vehicles, after the popular program barreled through its second-year budget of $30 million in two months.

The BPU opened the program, known as Charge Up New Jersey on July 6, and then suspended it on Sept. 15 due to the exhaustion of the funds, saying that it would look for new funding to continue offering subsidies. The agency announced on Thursday it would shift $20 million from another fund to continue the program with a new, lower incentive structure, which will be discussed at a public hearing Sept. 30.

The program had been offering incentives of up to $5,000 for EVs with a manufacturer’s suggested retail price of up to $45,000, and up to $2,000 for EVs prices between $45,000 and $55,000. The new incentives will be $2,500 for EVs priced up to $45,000, and $1,000 for those prices between $45,000 and $55,000.

An agency explanation of the revised program rules said that “due to high interest in EVs, staff recommends reducing incentive levels to better allocate the budgeted funds and to increase the longevity of the program.” By cutting the incentives, the program would “ensure equitable access to funding for vehicles accessible to more New Jersey residents and to stretch available funds further,” the document said.

The program awards a $25 incentive for each mile of range that a vehicle can drive solely powered by electricity. Plug-in hybrid electric vehicles (PHEVs) would also be eligible for the $25 incentive for each mile of range, to a maximum of $1,000 under the proposed rules. There was no limit on incentive size at the start of the second phase, although incentives were expected to be relatively small due to the short range of the current crop of PHEVs.

A review of vehicles by NetZero Insider earlier in the year found that that the range of 16 eligible PHEVs listed on the program website was between 17 and 47 miles, which would result in incentives between $425 and $1,175.

By the time it was suspended, the second phase of the program had subsidized the purchase of 9,000 vehicles, the BPU said in a Sept. 14 statement announcing the suspension. It added that “drivers looking to make the switch to electric have enthusiastically embraced” it.

Jim Appleton, president of the New Jersey Coalition of Automotive Retailers (NJCAR), a trade association that represents about 500 car and truck dealers, said Friday the organization supports the program. But he questioned whether now is the right time to put more money into it, given the chip shortage that has hindered car manufacturing, and the possibility of federal money for EVs “on the horizon.”

He said that going “strictly by the numbers,” Charge Up New Jersey has probably been a success. But he said the agency should take time before restarting the program again.

“We really should be looking past the top-line numbers and ask, after two years, was the Charge Up New Jersey program a $60-million success that incentivized consumers to buy EVs they wouldn’t have purchased otherwise,” he said. “Or was it a $60-million give-away” to people who were going to buy an EV anyway?

“NJCAR thinks this would be a really good time to do a thorough analysis of where the money went, how we can better serve consumers that did not participate, and for the BPU and EV stakeholders to review program criteria and administrative functions to improve performance moving forward,” he said.

Searching For “Incentive-essential” Buyers

The Charge Up New Jersey program is part of New Jersey’s effort to get 330,000 registered light-duty EVs in the state by 2025, in line with its goal of using 100% clean energy by 2050. The plan also calls for at least 85% of all new light-duty vehicles sold or leased in New Jersey to be EVs by December 31, 2040.

The first phase of the program, also funded with $30 million, ran from January to December 2020, offering incentives of up to $5,000 for EVs priced up to $55,000. It subsidized the purchase of 7,000 vehicles, which along with the 9,000 subsidized thus far this year, accounts for about 5% of the 330,000 target total.

At the end of 2020, there were 28,869 EVs registered in New Jersey, along with 12,227 PHEVs, for a total of 41,096 vehicles — or about 12.5% of the 2025 target — according to figures from the New Jersey Department of Environmental Protection.

In the first year of the Charge Up program, 93% of recipients received the maximum incentive of $5,000, and 83% of the vehicles purchased were Teslas, according to BPU figures. In response, the BPU revised the structure in the second phase so that the maximum incentive of $5,000 would be available only to vehicles priced $45,000 or below. (See: NJ EV Incentives Target Cheaper Vehicles, Middle-income Buyers.)

BPU officials outlining the reasoning behind the price cap said it was an effort make the incentives “more accessible to middle-income families” and to prioritize “incentive-essential” buyers, or those who would likely not buy an EV without the incentive. Only one Tesla model, the Model 3 — which sells for $39,990, according to the company website — is priced below the $45,000 cut off.

Asked about the impact of the decision to focus the maximum incentives on lower-priced vehicles, and how many Teslas were sold under the second-year incentive structure, Peter Peretzman, spokesman for the BPU, said that at a later date the agency would “fully review Year Two of the program which will give us a complete picture of which vehicles were purchased.”

‘Filtering off’ the Teslas

Speaking before the BPU announced its plan to cut the incentive size, Stanislav Jaracz, president of Central Jersey Electric Auto Association, who spoke at a hearing on the proposed rules in the spring, urged the agency to shrink the incentives.

Jaracz, in a Sept. 16 email to NetZero Insider, said he found it “very surprising” that the fund was exhausted so quickly. He urged the BPU to do a thorough, transparent evaluation of who bought the cars. The rapid exhaustion of the funds reinforced his belief that the incentives should have been smaller, he said.

Incentives of $4,000 for EVs priced up to $40,000, and $2,000 for vehicles in the $40,000 to $50,000 price range would “filter off all Teslas from the $4,000 rebate tier to $2,000 tier,” enabling twice as many drivers to buy an EV, he said.

“With my proposal, the funding would still not last until the end of June 2022, but it would not be exhausted after less than 3 months,” he said.

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EVs Reshaping Transportation Landscape

The growing adoption of electric vehicles is changing how consumers look at transportation and forcing automakers and policymakers to think about a multitude of disciplines beyond automotive design, from mining and recycling to emissions and urban planning.

In persuading people to buy an EV, product execution may play a bigger role than whether it’s an electric car or not, so the responsibility is on manufacturers “to surprise customers with the execution,” Ford Motor Company CEO Jim Farley said Thursday. “That seems to be driving the demand, not just electrification.”

Farley made his remarks during a webinar hosted by Columbia University’s Center on Global Energy Policy, appearing with the CGEP’s Director Jason Bordoff and distinguished visiting fellow Mary Nichols, former chairwoman of the California Air Resources Board.

Tipping Point

The moment when the EV market is going to take off is finally here it seems, Farley said.

“The Mustang Mach-E is sold out in the U.S., Europe and China — not just a little sold out, like a year sold out,” Farley said. “Enthusiasm for the product is very high.”

The F-150 is probably the model he watched the closest, he said, being America’s bestselling vehicle overall for 40 years.

“We have 150,000 orders, so it’s actually quite overwhelming right now to see the adoption,” Farley said. “Our market share is 50% of the light duty commercial vehicles in the U.S., so if you’re doing work with a vehicle in the U.S., 50% of them are a Ford. And we are the first one to have an electric van and an electric pickup, and we’re number one in both segments.”

Bi-directional charging has been of interest to Nichols since the Fukushima disaster, when the Japanese used their EVs to keep factories — and their own homes — powered, she said.

Clockwise from top left: Ford Motor Company CEO Jim Farley; CGEP Director Jason Bordoff; and Mary Nichols, CGEP | CGEP

Ford designed its vehicles to be power stations, and the company saw a big increase in demand for that functionality after the blackouts in Texas last winter, Farley said.

“Right now, basically, the vehicle will be able to power your home,” Farley said. “Selling electrons back to the grid could be a big solution to our energy issues and the grid issues for peak demand … but we haven’t worked that out. The solar industry has done it, but it was a really painful process about how to sell electrons back to the grid from personal solar systems. We are just starting that discussion with the Edison Institute and some forward-leaning utilities, like the ones in California.”

States regulate the utility industry, “maybe not as much as some of my fellow regulators would like, but, still, [utilities] don’t make a move without knowing that they’re going to be able to get cost recovery from it, so it doesn’t feel like [net metering for EVs] is at the top of the agenda where it probably needs to be at this point,” Nichols said.

Global Issues

Most global carmakers are investing heavily in the transition to EV production, but some are worried that the switch could hit workers as well as their bottom line.

Trade journal Inside EVs in mid-September reported Toyota CEO Akio Toyoda saying “that going all-EV could cost Japan 5.5 million jobs and 8 million units of lost vehicle output by 2030.”

General Motors announced in June that it will invest $35 billion in EVs and automated driving systems through 2025, and in July, CNBC reported that Stellantis — the merged Fiat Chrysler/PSA Groupe — plans to invest at least $35.5 billion in EVs and supporting technologies over the same time frame.

Farley and Nichols serve as co-chairs of the Commission on the Future of Mobility, which is trying to grapple with some of these questions and includes representatives from groups and businesses interested in mobility.

“We still are having a hard time, even as a group of people with experience and some claims to leadership, framing some of the really big airy questions,” Nichols said. Topics include “the whole freight sector, which also has a big stake — but that puts you in the business of urban planning.”

Automakers currently make money on the after-sales business, but that will go away as EVs require much less maintenance than internal combustion vehicles, Farley said.

“I think the electric vehicle is going to really challenge that assumption that the value is in the vehicle itself, and maybe the after-sales is not a profit endeavor like it has been for us,” Farley said.

Workforce “risk is something I think about every day with this transition,” Nichols said.

The American industry needs creative solutions to bring the supply chain back to the U.S., from batteries to silicon to mining, Farley said. “No one wants a mine in their neighborhood, but we have to mine or else we’re going to be shipping these materials halfway around the world.”

Today in Europe, 90% of vans are diesel and 20% of passenger cars have a plug, so the transition is going a lot slower for commercial vehicles, Farley said. “Commercial vehicles in China are really different, with three-wheelers and that kind of thing. They are actually going to EVs very quickly in China, but I’d say in general commercial vehicles are 10 years behind passenger vehicles.”

Asked what he wants from the government, Farley said, “Customers are really smart; they do the math, so we have to continue to get support from government leaders to put their foot on the scale of the economics and make this work for more customers.”

“That’s exactly what we’ve been hoping for in the state of California,” Nichols said. “We … try to make the case and educate people about electric vehicles and learned that, first of all, the people weren’t aware that they even existed, or that there were any vehicles out there that would meet their particular needs, and I think we’ve finally begun to turn that around.”

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PPL Acquires Portion of SOO Green Project

PPL (NYSE:PPL) has acquired a portion of the SOO Green HVDC Link, giving the Pennsylvania-based energy company a role in the controversial transmission project aimed at delivering wind generation from MISO to the PJM market.

Details of the deal announced Monday were limited, but PPL will partner with Direct Connect Development, a Minneapolis-based company developing the $2.5 billion project, which consists a 350-mile, 2,100-MW, 525-kV underground transmission line sited along existing Canadian Pacific rail lines and designed to deliver renewable energy from upper MISO to Illinois and the PJM grid.

SOO Green’s other owners are Copenhagen Infrastructure Partners, Siemens Energy and Jingoli Power. Construction is currently planned to begin in 2023 and take three years to complete.

“SOO Green is very pleased to welcome PPL to the SOO Green team,” said project founder Trey Ward. “As a diversified utility with deep transmission development expertise, PPL will bring unique capabilities to help advance this landmark project.”

Project officials have touted the model of using underground cables co-located with existing rights of way to avoid using eminent domain to advance the transmission route. Officials said installing underground cables will enable faster state permitting by avoiding environmental and visual impacts tied to traditional overhead transmission lines.

PPL COO Gregory Dudkin said his company wanted to “gain insight” into SOO Green’s approach to the project as it ramps up its own clean energy transition. It is “excited to lend” its own experience in transmission development on the project.

“PPL is pleased to support a project focused on transforming how major transmission line projects are built in the U.S.,” Durkin said. “SOO Green’s innovative approach aims to remove key barriers to interregional transmission line construction that will be essential to connecting more largescale renewable energy to the grid.”

Project Challenges

SOO Green has been jostling with PJM over the project, asking FERC to eliminate capacity rules that it says are blocking its project from competing in the market. (See related story, SOO Green Seeks Relief from PJM Rule on External Capacity.)

PJM stakeholders originally approved an issue charge in June 2020 to consider integrating HVDC converters as a new type of capacity resource in the RTO. (See HVDC Initiative Endorsed by PJM Stakeholders.) Work at the HVDC Senior Task Force failed to reach a consensus on the issue. (See “HVDC Senior Task Force Update,” PJM MRC/MC Briefs: March 29, 2021.)

Direct Connect filed a complaint with the commission in June, arguing that PJM’s tariff and Operating Agreement are unjust and unreasonable because the RTO requires merchant transmission facilities to complete a “profoundly delayed generation interconnection process” for studies and integration into the grid (EL21-85). (See SOO Green Seeks Participation in PJM RTEP Process.)

Karl Miller, CEO of Jingoli Power, said SOO Green is a “critical link” in the development of the grid of the future.

“We’re thrilled PPL has recognized the project’s revolutionary model to ease constraints for other regional wind and solar developments that will help make the U.S.’ ambitious clean energy goals possible,” Miller said. “We’re eager to get to work with our new partners.”

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Glick, Panel Discuss Critical Role of Tx in Decarbonizing NE

FERC Chair Richard Glick said that when he looks at the interconnection queues across the U.S., it amazes him how clear the direction is in terms of the resource mix: More than 90% of generation are renewable projects, “and that says a lot.”

“I think people realize that if you’re going to have that much intermittent renewable resources, there are some issues that need to be addressed,” Glick said in delivering a keynote at Raab Associates’ 171st New England Electricity Restructuring Roundtable.

Glick said the U.S. needs “a significant build out” of the transmission grid to access renewable resources far from load centers. “It’s an enormous task, not just in terms of finding companies that are willing to invest in these projects and providing the right incentives.” Between siting, permitting, construction and operation, it takes a lot of time. “We need to take that into account.”

Glick acknowledged that FERC has “significant” but not “complete” authority of the grid. However, in dealing with public policy transmission projects, Glick said the current paradigm is not “sufficient.”

In July, FERC announced an Advanced Notice of Proposed Rulemaking (RM21-17) to reconsider its rules on transmission planning, cost allocation and generator interconnection, acknowledging that Order 1000 has failed to provide interregional expansions to deliver increased renewables and meet the challenge of climate change. (See FERC Goes Back to the Drawing Board on Tx Planning, Cost Allocation.)

Glick said cost allocation is “a huge impediment” toward greater investment and development. He also surmised that tens, if not hundreds, of billions of dollars, are needed for transmission, “and people that invest that money are going to want to recover it.”

“That means consumers are going to have to pay for it somewhere, and I think that’s one of the areas from a FERC perspective that I’d like to focus on a little bit more,” Glick said. “How can we make sure that the transmission that is needed — that the investments that are made are truly the most efficient investments — that consumers get the biggest bang for their buck? That’s going to be the dominant issue as we move forward, whether it be at the state level or the federal level.”

Improving Tx Planning, Investment and Siting

Following Glick’s keynote, four panelists from the RTO, state, utility and consultant spaces drilled down deeper on improving transmission planning, investment and siting in New England.

“We are pivoting from a time when we really wanted to use transmission to support markets and economic efficiency — as well as reliability, of course — toward a … new objective function of decarbonization targets,” said Sue Tierney, senior adviser at Analysis Group. “We need robust scenario planning approaches. The states’ energy and electricity requirements need to be at the center of these scenarios. We need to look at multiple pathways [to decarbonization] and analyze transmission needs that come out robustly to support a variety of different scenario pathways.”

Clockwise from top left: Judy Chang, Massachusetts Executive Office of Energy and Environmental Affairs; Bill Quinlan, Eversource Energy; ISO-NE CEO Gordon van Welie; and Sue Tierney, Analysis Group | Raab Associates

The existing planning process needs improvement, conceded Bill Quinlan, president of transmission and offshore wind projects for Eversource Energy. Still, it did produce “a very reliable, efficient grid for New England.”

“Whether it’s eliminating congestion down in southwest Connecticut, opening up interstate power flows, allowing fossil plants to retire, there’s a lot of goodness that has come out of the reliability-based planning that has taken place over a decade,” Quinlan said. “We do need to open up the planning process and create a new planning framework that allows the region to achieve its clean energy goals.”

Judy Chang, undersecretary of Energy and Climate Solutions in the Massachusetts Executive Office of Energy and Environmental Affairs, said that any new planning processes are not going to be perfect “the first time.”

“It takes several iterations to get it right, not that there is a final answer or anything,” Chang said. “But I think we improve as we do this, so we have to do this quickly, the first time acknowledging that we may not get every scenario right, and every assumption right, or even the stories behind each scenario quite right; or might not have satisfied everybody’s curiosity and input. This is difficult for the [RTO], but we have to strike a balance. We have to take into account the input, but we also have to do it quickly, knowing that we’ll have another chance to come back and refine.”

ISO-NE CEO Gordon van Welie said there is plenty of renewable energy potential in New England, “more than enough to support what we need for decarbonization.”

“I think there are limits to how much consensus we can expect in the stakeholder process. We have to recognize transmission investments tilt the playing field, and so that’s going to limit how much consensus can be achieved in the stakeholder process,” van Welie said. “The most important consensus we need is amongst the New England states because if we don’t get consensus amongst the states, we won’t make progress. I think our history shows that, and so that’s really the vital ingredient to this.”

Historically, when the states are aligned, Quinlan said, “solutions become a reality.”

“Stakeholder engagement, I think that’s key; everyone really does need to have a voice in this, but directionally, I don’t think there’s a big difference of opinion as to what the future should look like,” Quinlan said.

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NERC Board Approves Atlanta Office Move

At an abbreviated open meeting on Tuesday, NERC’s Board of Trustees approved a request from management that will allow the organization to go forward with plans to move its Atlanta headquarters.

The meeting had a single agenda item, split into two parts. First, the board authorized NERC management to execute the lease for the new Atlanta office that they have negotiated with the future landlord. Next, the trustees approved an amendment to NERC’s 2022 Business Plan and Budget allowing the organization to draw about $773,000 from its reserves in 2022 to pay for moving to the new office.

NERC’s current lease is set to expire in 2025, but an early termination clause would allow the organization to exit the lease by October of next year. That clause must be exercised by Oct. 31 and will require a payment of up to $2 million this year; earlier this month the organization requested permission from FERC to pay the early termination charge from its Operating Contingency Reserve (OCR). (See NERC Seeks FERC Approval to Fund Office Move.)

CFO Andy Sharp explained that NERC’s moving costs are also to be partly funded from the OCR, with about $64,000 to be spent in 2022 on top of the earlier charge. Another $709,000 will be paid from the Future Obligations Reserve, a fund that Sharp said was set aside by NERC to “subsidize the remaining term of the Atlanta lease.”

The use of the reserves means NERC will not have to change the assessments on regional entities in its 2022 budget, while the ending balance of the OCR in 2022, even with the new expenditures, is projected to be 5.5% of the revised budget. This is well within the policy target range of 3.5 to 7.5%.

NERC has shared few details about its new lease because of ongoing negotiations, but during Tuesday’s board meeting and the open meeting of the Finance and Audit Committee that preceded it, Sharp provided more information about the “attractive financial offer” that the organization received from the new landlord.

In addition to saving $900,000 per year on lease and facility costs, the new landlord has agreed to pay a majority of NERC’s construction, furnishing and move costs. These benefits “will result in a reasonable payback” of the early termination charge and the moving costs.

Along with the financial savings, Sharp highlighted several other advantages of the new location, such as a 40% smaller footprint that will accommodate a reduced staff presence in the office as NERC continues the hybrid work posture it began last year because of the COVID-19 pandemic. The new space also offers amenities such as free employee parking that are not available at NERC’s current office.

With the board having approved both proposals, NERC plans to submit the amended budget to FERC by Thursday. Board Chair Kenneth DeFontes thanked management for working quickly to finalize the new lease and take advantage of the early termination opportunity, saying the deal was “excellent timing.”

“It really coincides extremely well with the plans we’re making for a return to work, post-COVID world, not only in terms of saving costs, but also in terms of how we’re going to restructure the way in which we will use our offices,” DeFontes said. “So it really has been remarkable, and I want to thank the team for their creativity and their opportunistic approach that will [allow] a 30 to 40% reduction in our fixed costs going forward.”

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Bonneville Commits to Joining Western EIM

The Western Energy Imbalance Market is poised to make its largest expansion ever next spring after the Bonneville Power Administration said Monday that it will join the market in March.

With 15,000 miles of high-voltage transmission and 31 hydroelectric projects under its control, BPA will be the largest transmission- and hydro-provider in a market that currently includes 14 members with territories spanning much of the Western Interconnection.

“This decision aligns with Bonneville’s strategic plan and opens up an opportunity to increase revenues through additional sales of surplus power and to reduce costs through greater efficiencies,” BPA Administrator John Hairston said in a statement. “As the West moves rapidly to decarbonize the grid, Western EIM participation will help us navigate future challenges and leverage opportunities to benefit our customers and the Northwest.”

BPA’s decision comes three years after the federal power marketing agency began exploring membership in the CAISO-operated WEIM and two years after it signed a nonbinding implementation agreement to begin integrating the ISO’s systems into its operations. (See Bonneville Power Signs Agreement with EIM.)   The agency said Monday that its internal preparations are “on track” and that it has already begun testing with the ISO.

“Bonneville and its public power customers are highly valued partners for the ISO, and we look forward to further strengthening our working relationships,” CAISO Chief Operating Officer Mark Rothleder said.

BPA’s decision, though not a surprise, marks CAISO’s second victory this month in its competition with SPP, which earlier this year launched the Western Energy Imbalance Service (WEIS). A competing real-time market that has already attracted members in the Rocky Mountain region, the WEIS could provide a foothold for a full RTO in the West. In June, Xcel Energy postponed its effort to join the WEIM in order to consider its alternatives with SPP. (See Xcel Delays Joining EIM to Weigh Options.)

But two weeks ago, the Western Area Power Administration’s Desert Southwest Region signed its own implementation agreement with the WEIM, putting the agency on track to join in 2023. (See WAPA Desert Southwest Region to Join Western EIM.) By that time, the WEIM will consist of 22 members representing 84% of the West’s load, CAISO estimates.  

The ISO has taken key steps to seal the deal for BPA’s membership, including revising its tariff to create a new category of default energy bid — a “hydro DEB” — that estimates the opportunity costs for hydro in the WEIM to avoid forcing those resources to make unprofitable trades under certain conditions. (See CAISO Goes 2 for 3 on EIM Hydro Rule Changes.) 

And last month, CAISO’s Board of Governors and the WEIM’s Governing Body both unanimously approved a plan that would delegate more authority to the Governing Body over issues affecting the WEIM, a move widely popular among Northwest utilities and power producers. (See CAISO Agrees to Share More Power with EIM.)

Hairston said Monday that BPA’s WEIM membership could be a steppingstone to other forays into regional markets.

“Western EIM participation is a great introduction to emerging markets in the West. We hope to build on this experience to assess future market-based opportunities,” he said.

BPA is already heading in that direction, having last month proposed to participate in the next non-binding phase of Northwest Power Pool’s Western Resource Adequacy Program (WRAP). Interest in the WRAP has expanded to include utilities currently outside the NWPP’s current coverage area. (See RA Program will Require Restructuring of NWPP.)

And BPA signaled that it would also consider developments taking shape farther east.

“In addition to participating in the Western Resource Adequacy Program, BPA is closely monitoring the potential formation of day-ahead markets in the West,” the agency said. “Both the California ISO and Southwest Power Pool have presented initial concepts that could provide additional opportunities and benefits for BPA and its customers.”

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Conn. Regulator Nudges ISO-NE to Share Tx Data to Support OSW

States in New England are relying on offshore wind (OSW) to cut greenhouse gas emissions, but they need to hear from ISO-NE on where transmission upgrades are most needed before they can start harnessing the energy.

“I think [ISO-NE] is best-positioned to be able to provide the states with that kind of planning analysis,” Connecticut Department of Energy and Environmental Protection (DEEP) Commissioner Katie Dykes said at the Environmental Business Council of New England’s Connecticut Offshore Wind Webinar on Friday.

Other onshore renewable energy resources, Dykes said, need to be considered in the transmission planning process for OSW to avoid unintended consequences of congestion or curtailment between resources.

“The [ISO-NE] planning process for transmission has been pretty reactive,” Dykes said, and states are calling for a more proactive approach to building out the grid.

But New England states also need to work with ISO-NE in providing information on what their transmission and climate goals are so the system operator can include them in its planning efforts.

Since 2012, for example, Connecticut’s Integrated Resource Plan (IRP) has assessed supply and demand to formulate recommendations for the state’s electricity needs. The final version of the latest IRP is due later this month, Dykes said. And in Massachusetts, Gov. Charlie Baker’s administration developed a Decarbonization Roadmap to model how the state will reduce emissions at least 85% by 2050, including plans for electrification that require significant transmission updates.

Connecticut and Massachusetts want to plug the IRP and roadmap into ISO-NE’s scenario planning process, Dykes said.

Last year, all six New England states, through their representatives to the New England States Committee on Electricity, signed a vision statement that calls for ISO-NE to make the changes necessary to cost-effectively build the transmission needed to integrate OSW and other renewables.

In July, FERC opened a rulemaking to reconsider its rules on transmission planning, cost allocation and generator interconnection, acknowledging that Order 1000 has failed to provide interregional expansions to deliver increased renewables and meet the challenge of climate change. (See FERC Goes Back to the Drawing Board on Tx Planning, Cost Allocation.)

FERC’s review is important, Dykes said, because New England is “long delayed in reforms to the transmission procurement process.”

To unlock the transmission investment needed to integrate future offshore wind and other renewables, it is “critical that we’ll be able to participate in the process,” Dykes said.

Connecticut currently has about 90% of its electricity load under contract with renewable and zero-carbon resources, including the 704-MW Revolution Wind project between Eversource Energy (NYSE: ES) and Ørsted off the coast of both Connecticut and Rhode Island. The developers expect to place the project in commercial operation by 2025.

In addition, Vineyard Wind’s 804-MW Park City Wind project is located 23 miles off the coast of Massachusetts but will bring renewable energy to the residents of Connecticut.

Prices for OSW are steadily declining, Dykes said. The contract prices for Connecticut’s projects declined 20% from $99.50/MWh to $79.83/MWh, she said.

“These [prices] are a testament to the success of the competitive procurement mechanism Connecticut has been using to invest in OSW, as we provide certainty and finance stability for these projects going forward,” Dykes said. “The next challenge we have to tackle is transmission.”