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December 1, 2020

New CAISO CEO Vows Urgency on Resource Adequacy

Elliot Mainzer paid close attention from his home in Oregon as CAISO ordered rolling blackouts in August. He said he was not totally surprised because the ISO had warned of possible summer shortfalls for months.

Now that he’s in charge, CAISO’s new CEO said he is addressing California’s resource adequacy problems, in collaboration with leaders at the state Public Utilities Commission (CPUC) and Energy Commission (CEC), with a “tremendous sense of urgency” to prevent more blackouts next summer.

“Without question, resource adequacy is job No. 1 for California,” Mainzer told RTO Insider. “We need to make sure we adapt to stay ahead of that reliability curve.”

The world’s fifth largest economy is switching from fossil fuels to wind and solar as mandated by landmark state laws, but the transition has proven problematic, in part because of insufficient storage for renewables. Massive wildfires attributed to climate change plagued the state the past four years, and unprecedented heat waves strained resources across the West in August and September. (See WECC Findings Show Complexity of Heat Wave Event.)

“When I saw what happened back in August, it was not something that had been entirely unanticipated,” Mainzer said. “We know that the resource base is changing dramatically. We know that the climate is changing. California clearly has significant co-dependencies with other regions of the West. And as the resource base has changed, we need to make sure that our planning and procurement and our operations adapt sufficiently rapidly to stay ahead of the reliability curve.

“California has placed itself on the absolute leading edge of energy policy in this country, if not the world,” he said. “In order to achieve the ambitious goals, we all recognize that we need to have a planning and procurement and an operational framework that is up to the task of those public policy goals.”

Roundtrip to California

Mainzer’s move from the Bonneville Power Administration in Portland, Ore., to CAISO headquarters in Folsom, Calif., in late September was a return home of sorts.

He grew up in San Francisco and attended the University of California, Berkeley, as an undergraduate, before traveling for school and work to India, New England, South Africa, Houston and the Pacific Northwest.

Mainzer said he first grew interested in energy, particularly sustainable energy, when he spent a semester abroad in India and saw the massive Sardar Sarovar Dam being built.

CAISO Resource Adequacy — Elliot Mainzer became CAISO’s CEO on Sept. 30. | *CAISO*

Graduate work in business and environmental studies at Yale University led him to South Africa, where he helped the government of President Nelson Mandela understand how the U.S. regulated its electric utilities, lessons South African leaders hoped to apply at home.

At Yale, Mainzer came across a company called Enron, which was buying wind and solar generation in the West. He went to work for the Enron, first in Houston and then in Portland, where he founded its renewables trading desk. He lost his job in late 2001, when the company collapsed after gaming California’s energy market.

Mainzer said he was not involved in Enron’s malfeasance, but the experience left a sour taste.

“I said, ‘That’s about enough private sector for me for a while,’ and I went across the river to BPA,” he said. “Eighteen years later, this opportunity at CAISO opened up. It’s been a great journey.”

Training Ground

Mainzer took over as BPA administrator in 2013. The energy market was changing. Electricity prices were falling fast with fracking and renewables entering the mix. At the same time, the cost of maintaining BPA’s aging infrastructure, including hydroelectric dams dating to the Great Depression, was growing.

BPA’s rates had been rising too, and buyers, particularly the public power entities that the administration supplied, were not happy.

“Our customers were saying to us, ‘Hey, if you guys don’t get your cost structure under control, and you don’t get your rates under control, we’re not sure we’re going to be there for that next round of long-term contracts,’” Mainzer said. “And so I put a tremendous amount of energy, with my staff and my leadership team and in partnership with customers, to really bend our cost curve to get our rates flattened out to a much more sustainable trajectory and to really maintain that role as the long-term provider of choice for those public power customers.”

Their goal was that BPA would “still be a good deal” in a competitive energy market, he said.

Employee safety was another top priority after a series of injuries and fatalities, Mainzer said. “We transformed the safety culture of BPA in deep ways.” In addition, BPA’s 15,000 circuit miles of transmission lines required upgrades for “efficiency and agility.”

The set of challenges was good training for the job at CAISO, he said.

“I’ve always tried in my career to prepare myself and position myself to work in organizations that are highly impactful and, if staffed correctly and oriented correctly, can have a really positive influence,” Mainzer said. “Bonneville was that for the Northwest, and down here in California, the ISO is such a pivotal organization.”

Moving Forward

When former CAISO CEO Steve Berberich reacted testily to the August blackouts, Mainzer said he understood his frustration. California has a complex system in which the CEC forecasts long-term demand, the CPUC orders year-ahead procurement and CAISO allocates the capacity it is given, with limited backstop procurement authority.

Mainzer said he is approaching his new job by listening to others and working closely with the state commissions, while also acknowledging the hard realities ahead.

“My focus has been on coming in and trying to build collaborative and effective working relationships with the leadership of the CPUC and the CEC, getting to know some of their key staff and offering the hand of partnership,” he said.

“For me, just coming in with fresh eyes — given my experience in the Northwest [with] multi-stakeholder challenges — I think it’s just clear California will not succeed and will not have an effective resource adequacy framework if the ISO and the CPUC and the CEC do not have that shared sense of tremendous urgency and focus and collaboration,” he said. “We have to work well together.

“You can’t have a world where you have two or three analytical frameworks for resource adequacy at different stages of the chain,” Mainzer said. “We need to be looking at issues through roughly the same analytical lens.”

Like leaders at the CPUC and CEC, Mainzer said he wants to see the state’s leading-edge resources thrive, including behind-the-meter solar generation, distributed energy resources, demand response and battery storage. But “for those resources to play important roles in the reliability solution, we have to be really objective and rational … about the different behavioral characteristics of those resources and what it takes to enable them to perform [optimally].”

The new CEO said he’s keenly interested in sharing resources across the West through CAISO’s Energy Imbalance Market, including its extended day-ahead market now under development, and perhaps eventually talking about a Western RTO. For now, however, Mainzer said he is focused on the state’s internal needs.

“Failure is not an option,” Mainzer said. “We have got to continue making progress and working effectively together.”

December 1, 2020

Overheard at NECA’s 19th Power Markets Conference

The Northeast Energy and Commerce Association (NECA) held its 19th Power Markets Conference virtually Nov. 19, featuring three panels discussing the impact of renewable energy integration on reliability, transmission and market rules.

The event also boasted two keynote speakers. The first, a longtime energy journalist, touched on the recent election results and their potential impact on power markets. The second was FERC Commissioner Richard Glick, who could rise to the chair position under the Biden administration.

Here are highlights of what we heard.

Do not Say ‘Chairman Glick’

Glick started his keynote by making one thing clear: He does not know who the next FERC chair will be, though he did not deny that he wanted the position. Glick said he has been in Washington long enough to know that “those decisions are made for a variety of different reasons, and they’re certainly out of my hands.”

Glick also does not control what he called “the dispute” between FERC and the states over federal regulation of wholesale markets. He said he disagrees with FERC’s endorsement of a minimum offer price rule (MOPR) in RTOs, which has the effect of raising prices and is “troubling for a variety of reasons.”

NECA Power Markets Conference — FERC Commissioner Richard Glick | *NECA*

MOPRs have caused states to re-evaluate their participation in wholesale markets, especially in New England, Glick said. If states continue to grow suspicious of the RTO markets with a MOPR regime, “they’re going to go their own way, or they’re going figure something else out,” he said.

“I think that we’re really at an important point here in time, and I certainly think the RTOs get it,” Glick said. “I think ISO New England certainly gets it, and PJM and New York as well. They realized they need to do something different.”

Glick said that at some point, he hopes to convince current — and future — colleagues to design capacity markets that better accommodate state policies and not antagonize them.

“One of the concerns I have is that I think we spend too much time worrying about capacity based on resources and not enough time worrying about flexibility,” Glick said. “How do we encourage — whether it’s gas or storage — those assets to be available when we need them for flexible purposes? It requires some broader thought. … It would probably take the commission a while to modify these markets, but if we don’t do that, I do think that we’re headed for a situation that no one’s going to like.”

Is it possible to design one-size-fits-all standard capacity markets for RTOs? Glick said Congress put an end to talk about that in the early 2000s after backlash from various stakeholders around the country.

“The concept of creating one format for all the RTOs is probably not in the cards,” Glick said. But he admitted that he’s “not a big believer in the mandatory capacity market concept or construct.”

“I came in thinking that we had competitive markets,” Glick said. “Instead, we have markets that have administrative constructs,” in which the market monitor or FERC tells participants what they can bid into the capacity market “or even the ancillary services markets,” he said. That means FERC spends “way too much time litigating these issues” because there are “hundreds of millions of dollars at stake.”

“To me, it’s way too complicated; I’d like to simplify it a little bit and go back to real competitive markets if we can.”

Renewable Integration, Market Rules, Reliability and Tx

Clyde Loutan, principal of renewable energy integration at CAISO, said California has more than 20 GW of renewables on the grid. On some days, peak load is about 20 GW, which creates some “unique challenges.”

“A bigger challenge is calculating or trying to figure out what that net load forecast is,” Loutan said. “Remember, we have one variable, which was load was temperature-dependent, and if you could forecast the temperature, you could pretty much know what that load was going to be in California.”

Lorenzo Kristov, retired principal of market and infrastructure policy at CAISO, added that the grid is no longer the only way to get electricity.

“For 100 years, if you wanted electricity, you got it from the power system,” Kristov said. “Now, just about any customer can install on-site equipment, and the behind-the-meter market becomes a competitor for grid kilowatt-hours.”

Kristov said large California-based companies like Google and Apple are starting to create resources at their facilities to manage some of their energy needs, which is likely to accelerate because associated technology costs “keep going down while the capabilities keep going up.”

FirstLight Power CEO Alicia Barton added that one of the challenges is balancing future renewables with a grid maintenance. “Just because we’ve kept the lights on doesn’t mean we’re not facing some critical junctures ahead,” she said.

Paul Wattles, senior analyst for market design at ERCOT, said more than $6 billion is planned to be spent on transmission upgrades expected to be in service by 2025. Renewable integration is a significant driver of capital investment, but load growth is as well.

“We’ve just had just unprecedented load growth in the Permian Basin [oil fields], and a lot of that fracking and drilling out there is being done with portable generation because we didn’t have the transmission system to get the power to the oil fields,” Wattles said. “It also happens to be an area where there’s tremendous solar irradiance capacity … so that’s a weird dichotomy, but they’re going actually to help each other.”

Eli Massey, senior adviser on policy studies for MISO, said large corporate users as well as states demand clean energy.

“The problem that we have from a planning [perspective] is we don’t know how fast it’s coming, and we’re trying to get a much better idea of what are the operational impacts and how does our transmission system need to evolve to facilitate all this prospective generator interconnection,” Massey said.

He said a MISO Renewable Integration Impact Assessment found that “we start getting into some pretty tricky operating circumstances” when the RTO’s renewable penetration levels reach 40 to 50% of load.

“We’re going to need a significant amount of transmission investment,” Massey said.

Carissa Sedlacek, director of planning services at ISO-NE, said “our issues are not market design issues but rather transmission integration issues.” She said the RTO has determined that the Cape Cod area will require 345-kV upgrades to accommodate offshore wind.

“There’s going to be some serious siting concerns, especially in southern New England because it is congested from a population perspective, and finding the right of way to site the new transmission lines to integrate all of the proposed offshore wind will be a challenge for us over the next several years,” Sedlacek said. “This will take time. It’s not going to be a quick process.”

Clockwise from top left: Julia Frayer, London Economics International; Paul Wattles, ERCOT; Vandan Divatia, Eversource; Eli Massey, MISO; and Carissa Sedlacek, ISO-NE. | *NECA*

Vandan Divatia, director of ISO policy and interconnections at Eversource Energy, agreed that there is “some major work to do.”

“We have to integrate a ton of clean energy resources, over 10 GW just in this decade, and we will look to optimize clean energy and reliability needs in some cases to ensure cost-effectiveness and reliability for our customers,” Divatia said.

RENEW Northeast Executive Director Francis Pullaro said he recognizes “that a megawatt of nameplate wind is not an equivalent of a megawatt of nameplate gas in the ISO markets.”

“You know [wind and solar resources] are discounted because of the variability of wind and the limited amount of sunshine. Still, if developers could count on some level of revenue from that, it certainly would be reflected in the [competitive solicitation] bids that these resources are submitting,” Pullaro said. “I think that’s kind of how we see that issue: It’s above all a consumer issue, and I think that’s why the states are particularly concerned about it.”

NYISO Executive Vice President Emilie Nelson said MOPR is a “challenging issue that I think we’re trying to work through as an industry, and all of the Eastern RTOs are trying to figure out the right course.”

Nelson added that what is interesting about carbon pricing “is the design values that clean energy attribute, which is driving much of the policy that we’re trying to work through the energy market.”

ISO-NE Vice President of Market Development and Settlements Mark Karl said the RTO favors carbon pricing as a potential solution, though there are “certainly challenges with it.”

“It’s one thing to have carbon pricing in a single-state ISO versus trying to get six states to agree,” Karl said. “The advantage of carbon pricing is that we know how it works, and we have a model for it.”

Election Impact

Veteran energy journalist Peter Howe, now senior adviser and energy practice lead at Boston public relations firm Denterlein, said he does not have a crystal ball, nor “perfect clarity and vision into what’s going to come next” following the recent election results. But Howe does seem sure that the incoming Biden administration will undoubtedly be different on a host of energy and environmental issues than the outgoing Trump administration.

Some of President-elect Joe Biden’s policy proposals: net-zero emissions from the electric sector by 2035; a net-zero economy by 2050; rejoining the Paris Agreement on climate change; mass reversal and revocation of executive orders and lawsuits; clean energy jobs; and “electric vehicles galore,” Howe said. Some of them depend on the outcome of the runoff elections in Georgia for the final two U.S. Senate seats. Democratic wins would mean a 50-50 tie in the Senate, with Vice President-elect Kamala Harris as the tiebreaking vote. Just one Republican win would maintain the GOP’s slim majority and make it harder for the Biden administration to push through the most progressive part of any energy and environmental agenda, Howe said.

When it comes to oil and gas and fracking, Howe said many “symbolic and meaningful things” could be done, including how tightly leases on federal land are regulated and how aggressively the Justice Department enforces environmental violations.

“I think that Joe Biden will get to a point where he can make a case that maybe [he] didn’t ban all fracking everywhere … but has done a lot to keep up the pressure on this industry to be as clean as it can be,” Howe said. “And frankly [Biden] wouldn’t say it out loud, but [he needs] to just move the scales as best [he] can away from fossil fuels and toward renewables by making the production of fossil fuels incrementally more expensive by closer regulation.”

At the state and regional level, Howe said offshore wind projects like Vineyard Wind could clear remaining regulatory and permitting hurdles with the Bureau of Ocean Energy Management “led by people who are very enthusiastic about offshore wind.”

Howe also referenced the five New England governors, excluding New Hampshire’s, who recently advocated “very forcefully for changes” to ISO-NE governance, market design and transmission planning. (See New England Governors Call for RTO Reform.)

Howe said the states and the RTO are in the same boat but “not rowing in the same direction” on renewables growth and 80% carbon reduction by 2050 or net-zero emissions. He said an expanded Regional Greenhouse Gas Initiative (RGGI) could bridge the divide.

“I certainly would love something like a supersize RGGI to bake in carbon pricing or some form of carbon pricing, rather than the complexity of blending [the public policies of] six states of into the market.”

States like Connecticut have openly talked about the idea of “actually departing” the ISO-NE wholesale market, though Howe thinks that is “quite a long shot, both physically and politically.”

December 1, 2020

Report: FERC Enforcement Actions down Sharply in FY20

FERC’s Office of Enforcement opened only six new investigations in fiscal year 2020 and managed to get just $550,000 in civil penalties and disgorgements from the three settlements it closed, according to its annual report, released Nov. 19.

The three settlements came early in the fiscal year, in November 2019 and January 2020, suggesting the COVID-19 pandemic may have played a part in the downturn. The report notes that “while Enforcement continued its typical investigations, audits and surveillance activities in FY 2020, it also took steps to help regulated entities manage their potential enforcement and compliance-related obligations in response to the unprecedented COVID-19 pandemic.” This included suspending new audits until July 31 and “postponing contacting entities regarding surveillance inquiries, except those involving market behavior that could result in significant risk of harm to the market.” (See FERC Loosens Requirements in Pandemic.)

This fiscal year continued a trend from last year, with the office opening half the number of new investigations as the previous year, and the amount of money the office collected in penalties and disgorgements was a pittance compared to other years. In fiscal years 2017 and 2018, it collected $51 million and $83 million, respectively. Even in FY19, considered a slow year for the office, it brought in $14.4 million. (See Slow Year for FERC Enforcement, Report Shows.)

The report does note that four cases, in which Enforcement is seeking more than $89 million in penalties and disgorgement, are pending in U.S. district courts.

FERC Office of Enforcement — | *Shutterstock*

The largest penalty assessed by the commission came at the very beginning of the fiscal year, Nov. 1, 2019, and involved Calpine (IN17-1). The company agreed to pay $400,000 because Enforcement found that eight of its plants failed to properly maintain or even falsified records of battery tests, resulting in more than 200 violations of NERC reliability standard PRC-005-1 R2.

Several mitigating factors lowered the settlement amount: plant operators at Calpine’s Gilroy plant in California self-reported several violations in 2015, leading to a wider internal investigation; Calpine fully cooperated with Enforcement’s own investigation; and the office found that the company had not centrally directed any of the violations, with each plant having different circumstances. The company also agreed to a mitigation plan in the settlement.

This year’s penalties also included FERC’s settlement in January with Exelon, which agreed to disgorge more than $100,000 because of an error that resulted in its Mystic Unit 7 in Massachusetts being overcompensated. (See “Fuel Cost Violation,” FERC Rejects Mystic Cost-of-service Amendment.)

After Enforcement staff’s presentation of the report during FERC’s open meeting this month, Commissioner Richard Glick praised them as the commission’s “unsung heroes.” But he expressed concern that the commission itself had “gone AWOL at this point” in enforcing rules against market manipulation based on the low quantity of penalties this year.

“I recognize that you can’t always make a finite judgment based on a single year’s statistic, but I think it’s at least worth asking whether the commission remains committed to its enforcement responsibilities, and I’ve had my doubts,” he said.

November 29, 2020

PG&E Faces ‘Enhanced Oversight’ by CPUC

The California Public Utilities Commission might implement, for the first time, the strict regimen of oversight and enforcement that Pacific Gas and Electric agreed to last year as part of its bankruptcy plan, the commission’s president told the utility last week.

The commission is concerned about alleged lapses in PG&E’s vegetation and line maintenance. The oversight process includes mechanisms that could eventually place PG&E into receivership or allow a public takeover of the utility.

PG&E oversight — CPUC President Marybel Batjer | *CPUC*

“As you are aware, as a condition of approval of Pacific Gas and Electric Co.’s plan of reorganization, the California Public Utilities Commission instituted a six-step enhanced oversight and enforcement process to ensure PG&E is held accountable for delivering on its safety responsibilities,” CPUC President Marybel Batjer wrote to interim CEO William Smith on Tuesday. “By this letter, I am writing to inform you that I have directed CPUC staff to conduct fact-finding to determine whether a recommendation to place PG&E into the enhanced oversight and enforcement process is warranted. These fact-finding activities are well underway and are being undertaken expeditiously.

“My concerns arose from what appears to be a pattern of vegetation and asset management deficiencies that implicate PG&E’s ability to provide safe, reliable service to customers,” she continued. The CPUC’s Wildfire Safety Division “identified a volume and rate of defects in PG&E’s vegetation management that is notably higher than those observed” for the state’s other large investor-owned utilities. “In addition, CPUC staff are reviewing recent filings made by PG&E in its federal criminal proceeding regarding deficiencies and inconsistencies in its vegetation management practices and recordkeeping.”

PG&E did not immediately respond to a request for comment. It acknowledged in a federal court filing earlier this month that it needs to improve its vegetation maintenance practices.

‘Offender PG&E’

Gov. Gavin Newsom signed a bill in July that put the CPUC’s increased oversight-and-enforcement protocol into state law. (See Governor Signs PG&E ‘Plan B’ Takeover Bill.)

The rules require PG&E to submit to greater scrutiny and potential state control for repeated and uncorrected safety problems. Under the terms of the law, the CPUC can appoint a third-party monitor, followed by a receiver, and eventually rescind PG&E’s license to operate as the monopoly utility for most of Northern and Central California.

PG&E equipment caused catastrophic wildfires in 2017 and 2018 that killed more than 100 people and destroyed thousands of homes, resulting in its bankruptcy and stricter scrutiny by state and federal authorities.

The utility remains on probation for felonies related to the San Bruno gas pipeline explosion in 2010. U.S. District Judge William Alsup, who oversees the probation, has repeatedly required PG&E to account for its fire-prevention activities and, in some cases, its role in starting new fires. In October, Alsup questioned PG&E about its possible part in starting the Zogg Fire, which swept through rural Shasta and Tehama counties in late September, killing four residents and destroying more than 200 structures. (See PG&E Line Was Active when Zogg Fire Started.)

A federal monitor reporting to Alsup criticized PG&E’s vegetation management practices in an Oct. 16 letter.

“On a per-mile basis, the monitor team is finding more missed trees … in 2020 than we did in the later part of 2019,” it said. One reason could be that PG&E trimmed trees in areas with low fire risk in 2019 to meet its CPUC-approved targets, rather than trimming trees in the high-fire-risk areas, the monitor said.

Alsup ordered PG&E to explain its shortcomings, which the monitor attributed to “human error, lack of oversight, miscommunications and failure to appropriately escalate matters.” Those were the “same problems that offender PG&E has long had,” the judge said.

PG&E’s wildfire prevention efforts include enhanced vegetation and line maintenance. | *PG&E*

PG&E responded Nov. 3 that it “did not programmatically target low-risk line miles for work in its Enhanced Vegetation Management (EVM) program during 2019” but instead used a risk model along with other factors, including weather conditions, to schedule maintenance.

“By the end of 2019, approximately 40% of the miles completed and more than 50% of the trees worked (removed or trimmed) as a result of the EVM program were in the top 100 highest-risk circuits as identified by the risk model in use at the time.

“While those figures reflect a significant reduction in wildfire risk, PG&E also accepts and agrees with the monitor’s view that in making operational decisions, PG&E must give greater weight to working the riskiest areas first and must do so in a more rigorous, consistent and measurable way,” it said.

November 29, 2020February 12, 2025

Overheard at New England Energy Summit

The New England Energy Summit kicked off the second of three virtual sessions last week with a U.S. senator touting carbon pricing and finished with a panel of energy experts from the public and private sectors.

Here is some of what we heard at the summit, organized by the New England Power Generators Association (NEPGA) and The Dupont Group.

Whitehouse Touts Carbon Pricing, Slams Big Tech

U.S. Sen. Sheldon Whitehouse (D-R.I.) has delivered hundreds of speeches from the Senate floor on climate change since 2012. He wasted little time in his keynote delving into an issue that has become a cause célèbre in New England: carbon pricing.

“I think carbon pricing is a pretty essential component of any rational analysis in the energy sector, and it has particular importance when you consider the climate peril that we face, particularly along the coastlines. Representing the Ocean State, I’m keenly aware of that,” Whitehouse said.

Whitehouse — who was campaigning in Georgia ahead of the Jan. 5 twin runoff races that will determine which party controls the Senate next year — said there is an “imbalance in the energy sector” in the form of a massive subsidy for fossil fuels. Whitehouse cited the International Monetary Fund reporting the yearly subsidy for fossil fuels in the U.S. is $600 billion.

“If you have one fuel that has a $600 billion annual advantage over its competitors, you have baked in a very bad distortion into the marketplace, and the obvious way to fix that is with a carbon price that counterbalances some, or all, of that subsidy until the market can work.”

From left to right, beginning with top left: Matthew Nelson, Massachusetts DPU; Tom Rumsey, Competitive Power Ventures; Dan Dolan, NEPGA; Jennifer Benson, Alliance for Business Leadership; Jim Monahan, The Dupont Group; Paul Hibbard, Analysis Group; and Melissa Hoffer, Massachusetts Attorney General’s Office. | NEPGA

Whitehouse said a carbon price is “far from dead” in Congress. He said it is the “leading strategy” on the Republican side, and there are four separate Democratic carbon pricing bills, “so this is not some fringe idea.”

Whitehouse added that Big Tech companies, such as Google, Apple, Microsoft and Facebook, “are not showing up in Congress to ask for climate legislation.” Instead, TechNet, the lobbying group for the companies, came to Capitol Hill with a 13-page list of legislative priorities and no mention of climate change or green energy, he said.

“There has to be a general awareness that American corporations are a wall in Congress,” Whitehouse said. He said that President-elect Joe Biden would rally corporate support and “call out those faint hearts that say one thing but do something very different in Congress, which is basically everybody.”

Closer to home, Whitehouse addressed a question about the pushback from some states about increasing prices in the Regional Greenhouse Gas Initiative (RGGI) and expanding its use as a carbon-reduction tool. He said governors and state legislators face an interesting choice on RGGI.

“At the moment, RGGI has been run in a very comfortable way for everybody … and it may be that the pressure from the inevitability of some real climate damage empowers some of the states that are leaning forward a little bit more on this to really press the states that are expressing skepticism to either get on board or get out,” Whitehouse said. “The stakes are so high, [but] I think a certain amount of that depends on what the signals from Washington look like. If it seems like Washington is coming together and starting to agree on a significant climate bill, that will take the pressure off RGGI, and in fact, the main question [then] becomes, ‘How does RGGI fit into this?’

“So [to be determined] is the way I would answer that question. But should we fail in Washington, and let’s say we don’t succeed in Georgia, Democrats [would] have a minority in the Senate, [and Senate Majority Leader] Mitch McConnell [R-Ky.] blocks any and all serious carbon legislation. But I think the pressure grows in RGGI to actually do something meaningful and not to be held back by the least ambitious member.”

‘Enormous Strides’ Toward Decarbonization

Whereas Whitehouse touted carbon pricing as a “pretty essential component,” Matthew Nelson, chair of the Massachusetts Department of Public Utilities, said his state has already embraced it through adopting RGGI — a cap-and-trade program — and now pushing the Transportation Climate Initiative (TCI).

“It’s not that we’re speaking from a place where we’re not for carbon pricing,” Nelson said. “But I think the key here is, what type of carbon pricing? FERC-jurisdictional, electric-sector-only carbon pricing has its drawbacks.”

Melissa Hoffer, energy and environment bureau chief in the Massachusetts Attorney General’s Office, said there have been “enormous strides in the decarbonization world.”

“What’s unique about what has occurred this year is you see it now being driven more by fiduciary concerns about the long-term viability of fossil fuel investments,” Hoffer said. “So while we still hear the moral argument motivating those decisions, we are also now hearing, ‘This is just not a good and stable investment for our assets over the long term.’”

Hoffer cited a report by Goldman Sachs that renewables will be the largest area of spending in the energy industry overall in 2021, surpassing upstream oil and gas for the first time in history. Goldman turned this into an implied carbon price of about $40 to $80/ton for new hydrocarbon developments.

Paul Hibbard, principal at Analysis Group, said the “real risk” is that the resource-specific policies and investments made in the present “could look outdated in a relatively short time, and it affects everyone in the economy.”

“Ultimately, all of our energy infrastructure has potential reliability implications, and you only need to think about a declining use of the natural gas infrastructure in the region and the impact that might have on the reliability,” Hibbard said.

Jennifer Benson, president of the Alliance for Business Leadership and a former Massachusetts state representative, said that she was committed to “writing and fighting for a revenue-positive carbon pricing bill.”

“My bill would raise hundreds of millions of dollars per year to fund resiliency and infrastructure by putting 30% of the carbon fees collected into a green infrastructure fund that could range from $300 million at $20/ton of carbon to $600 million at a $40/ton price,” Benson said. Massachusetts is “borrowing billions to pay for resiliency and renewable energy infrastructure, and that is straining our finances.”

“Imagine if the funding mechanism for these critical projects was built into our energy systems and tied directly to the cause of these problems,” Benson said. “Carbon pricing is a simple, elegant, market-based solution that has been proven to work in countries and regions with comparable demographics and economies to ours here in Massachusetts.”

November 29, 2020

Researchers Seek Ways to Jump Start Fleet Electrification

Despite representing only 4% of U.S. vehicles, diesel-powered trucks and buses are responsible for a disproportionate share of pollution and carbon emissions, making them a prime target for electrification efforts. Now, the Environmental Defense Fund is offering a “toolkit” to help fleet owners overcome obstacles to making the switch from internal combustion engines.

EDF’s report, “Financing the Transition: Unlocking Capital to Electrify Truck and Bus Fleets,” goes beyond traditional total cost of ownership (TCO) calculations to consider “soft” costs and other risks that present barriers to change. The report introduces a new framework, total cost of electrification (TCE), which it says can help policymakers, fleet owners, utilities and investors account for, and overcome, the challenges.

“The medium- and heavy-duty vehicle (MHDV) market — which includes everything from semi-trucks and delivery vans, to city buses and garbage trucks — is on the cusp of an electric transformation,” the report says. “To ensure and accelerate the transition, we must move beyond the set of traditional mechanisms that have been used to assist one-to-one replacements of trucks and buses, such as grant programs providing basic buy-down payments. … These solutions must deploy limited public monies in a manner that will unlock private capital at an unprecedented scale.”

The product of interviews with 32 stakeholders, including fleet operators, finance professionals and public policy experts, the report was authored by EDF with M.J. Bradley & Associates and Vivid Economics. It allows fleet operators to identify their obstacles and match them with potential solutions, such as green bonds to help with financing or battery guarantees to address technology risks.

Signs of Change

The U.S. has 14 million buses and large trucks, most fueled by diesel, which EDF says “are among the dirtiest vehicles on the road and will be the leading source of growth in transportation climate pollution over the next 30 years.”

Signs of change are apparent: Daimler, the No. 1 freight truck producer in the U.S., has pledged to stop selling internal combustion trucks in its main markets by 2039. Amazon ordered 100,000 electric trucks from electric vehicle startup Rivian last year, and companies including PepsiCo, Anheuser-Busch and J.B. Hunt Transport Services are piloting emission-free trucks.

In June, 15 U.S. states committed to have 30% of their truck, bus and van sales be zero-emission by 2030. In September, California Gov. Gavin Newsom issued an executive order requiring a transition to zero-emission trucks by 2045. These 16 states represent more than a third of the total U.S. MHDV fleet. (See Calif. to Halt Gas-powered Auto Sales by 2035.)

Officials in New York, Los Angeles, Houston and Honolulu are also planning to go all-electric for fleets such as garbage trucks and transit and school buses.

Fleet Electrification — Andy Darrell, Environmental Defense Fund | *EDF*

“Several different factors are coming together to make the time right to electrify trucks and buses at larger scale, especially in the transit bus and medium-duty sector,” said Andy Darrell, EDF’s chief of strategy, global energy and finance said in an interview with RTO Insider. “We’re seeing that the technology is reaching a tipping point; that policymakers are beginning to set ambitious goals and targets to help stimulate demand. There’s a rise in interest [by] the investment community in socially responsible investments. And then, of course, from a climate and public health perspective, there is an urgent need to reduce pollution from trucks and buses.”

Yet the transition hasn’t moved as quickly as it could, Darrell said.

“What we heard back [from the interviews] was that capital is ready to help. There is interest in the fleet owners to move forward, but there are a few key … pain points that we need to solve to get past that first transition.”

‘Soft’ Costs

The researchers put a priority on deploying public money where it’s needed the most and where it will have the most impact, as well as enabling private investment and financing options.

EV and battery costs have declined, and studies show electric MHDVs have a lower TCO than ICEs. But zero-emission vehicles are still much more expensive to purchase, “a powerful deterrent,” the report said.

While traditional TCO calculations focus on upfront purchase costs and lifetime operating costs, TCE was designed to target all the barriers, including “soft costs,” such as changes to business operations (e.g., routes and schedules) and permitting approvals. TCE also considers “uncertainties, risks and frictions” that can discourage fleet operators from making the switch.

Among the uncertainties are concerns about battery performance and lifespan and the residual value of vehicles and batteries when they are taken out of service.

Then there are the “frictions,” such as a lack of staff familiar with the new technologies or financing methods, and inertia in the procurement and contracting process.

EDF found that traditional public and private mechanisms to help with the purchase of cleaner vehicles are “often mismatched with the highest-priority needs for fleet transitions.”

Total cost of electrification (TCE) toolkit | *EDF*

Fleet owners also complain that existing grant programs are administratively difficult and expensive to navigate. “The end result is a lost opportunity to replace more internal-combustion vehicles with zero-emission ones,” the report said.

The toolkit identifies three types of financing solutions: capital instruments, risk-reduction instruments and cost-smoothing instruments. These include public-backed “soft” loans with low interest rates, longer maturity and reduced collateral requirements; public “buy down” of interest rates; equity investments; and commercial, municipal and green bonds.

Smaller MHDV fleet electrification projects can be bundled together to attract investors looking for larger opportunities. “This approach can transform one-off, non-traded assets into standardized, tradable assets and has been used in other clean economy sectors (e.g., renewable energy, energy efficiency) to catalyze the flow of capital at scale,” EDF said.

Risk-reduction instruments include performance guarantees to protect electric MHDV purchasers from underperformance of vehicles or batteries and residual value guarantees to protect investors or purchasers by guaranteeing a minimum resale value. Political risk guarantees can protect against losses from changes in climate and vehicle or fuel regulations or policies.

EDF also promotes nonfinancial solutions such as technical support and policy actions, such as changes to allow EVs to acquire monetizable emissions credits or to operate as grid assets via bidirectional charging and discharging.

Darrell noted that school buses are idle most of the day and during summers. “A vehicle-to-grid integration program [that allows the buses to sell power to the grid] could be a terrific solution,” he said. “That might work for school buses, but it might not work for fleets that are in use most of the day.”

Next Steps

“Research of this type is critical in ensuring that the ambitious goals that are being set across the country can be met in the most cost-effective way possible,” Larissa Koehler, a senior attorney at EDF who works on transportation electrification, said in an interview.

Capitalizing on the report will require collaboration, EDF said. “Real progress requires more than frameworks and toolkits. To bring these static documents to life, leaders from government, business and finance must break out of sectoral silos and open themselves up to thinking differently.”

New York’s Metropolitan Transportation Authority has committed to convert its 6,000 transit buses to electricity by 2045, with interim goals of switching out 500 buses per year. But their depots are in crowded urban areas, making them difficult to retrofit with charging stations.

“The depot that I visited ended up having the charging stations up on the roof because they were having a hard time fitting them in elsewhere,” Darrell said. “It took a creative thinker from the real estate side and the fleet side [of MTA] to figure out how to do this.

“I see this gap between the opportunity in the fleets to do something amazing for climate and clean air, and capital waiting on the sidelines to jump in. I’m hoping that this report can help close that gap,” Darrell said. “Now that we understand a little more what the landscape looks like, we are interested to partner with fleet owners and policymakers and investors to try to help create the table around which these stakeholders can come together and … show the real world how this can work.”

November 29, 2020

CGNP Fleshes out Diablo Canyon FERC Complaint

The activist group Californians for Green Nuclear Power (CGNP) has updated its request that FERC overturn the planned closing of a California nuclear generating station in response to criticism from NERC and other respondents named in the original complaint (EL21-13).

CGNP’s complaint, filed in October, concerns Pacific Gas and Electric’s Diablo Canyon Power Plant, a facility comprising two nuclear reactors with a nameplate capacity of 2.3 GW that is scheduled to shut down by 2025. Diablo Canyon has operated since 1985; in 2019 it produced nearly 16.2 TWh of electricity, according to the U.S. Energy Information Administration, accounting for about 10% of in-state generation.

Initial Complaint Draws Harsh Response

CGNP describes its membership as scientists “dedicated to promoting the peaceful use of safe, carbon-free nuclear power.” In its filing, the group accused NERC, PG&E, WECC, NERC Blasts Calif. Nuclear Group’s Complaint.)

The respondents fired back in multiple separate responses, raising a number of issues with the complaint. NERC pointed out that CGNP cited no specific violations of its reliability standards, while PG&E asserted that “responsibility for electric generation resource planning … rests with state authorities” and that FERC involving itself in the matter would therefore be improper. CAISO and the California Public Utilities Commission called the legal basis for the complaint “unclear.”

Diablo Canyon FERC Complaint — Diablo Canyon Nuclear Power Plant

In the amended complaint, CGNP aims to address the respondents’ objections by fleshing out its arguments, in particular the reliability standard it claims to be at issue — BAL-002-WECC-2a (Contingency reserve). The new filing also clarifies the specific actions the group is seeking from FERC:

halt the respondents’ alleged violations through its “plenary jurisdiction”;
issue the appropriate orders to ensure the region maintains a reliable supply of natural gas in the event of Diablo Canyon’s retirement;
review CAISO’s loading order, which gives preference to renewable energy and distributed generation over nuclear and other resources for meeting demand, as “unduly preferential and discriminatory”; and
disallow the cost recovery granted PG&E for the infrastructure needed to transmit Diablo Canyon’s power and investigate the effects of the facility’s closure on California electric rates.

Plant Closure a Recipe for Trouble

CGNP’s accusation rests on BAL-002-WECC-2a, a regional reliability standard that took effect in January 2017. The standard mandates the minimum contingency reserves that must be maintained by each balancing authority and reserve sharing group in order to “ensure reliability under normal and abnormal conditions.” The group alleges that “retiring Diablo will result in an unreliable grid” by removing the facility’s generation from the Western Interconnection.

What is being lost, according to the complaint, is not the sheer generating power of Diablo Canyon, which PG&E expects to replace with “a portfolio of [greenhouse gas]-free resources.” Instead, CGNP is concerned with the uniquely stable power supply that the plant provides.

Currently, PG&E can depend on Diablo Canyon to keep generating power, rain or shine — a level of confidence that solar and wind generation can never provide, according to CGNP. It is not alone in this assessment: Multiple industry participants have confirmed that the closure of the nuclear plant will remove significant baseload capacity from the grid, including stakeholders at WECC’s second Resource Adequacy Forum this month. (See Experts Urge West to Address RA Shortfall Immediately.)

One option when renewable resources falter is natural gas, but this too is not without risk. The region’s gas pipelines are not only aging but are also vulnerable to aseismic creep, a phenomenon involving the relative motion of Earth’s tectonic plates without earthquakes.

Over time this slow but inexorable movement can bend and break pipelines. CGNP claims its scientists found that one pipeline crossing the San Andreas Fault was bent by about 32 inches, the result of an estimated 23 years of accumulated creep.

According to the complaint, by shutting down Diablo Canyon, PG&E, CAISO and the CPUC will move from a stable facility with an excellent operational record to a mix of questionably reliable resources. Their disregard of the risk created is grounds for FERC to exercise its own authority to enforce BAL-002-WECC-2a by halting the Diablo Canyon closure and ordering its own investigation into the shutdown’s potential impact on reliability for the power grid and the gas pipeline system, the group says.

Fairness for Ratepayers Questioned

In addition to the alleged reliability standard violation, CGNP also takes issue with the loading order in California’s Energy Action Plan, created in 2003 by the CPUC, the California Power Authority and the California Energy Commission. The order requires that CAISO meet electricity demand with renewable energy resources and distributed generation before turning to non-renewable resources; CGNP calls this order “unduly preferential and discriminatory” and requests an investigation into whether closing Diablo Canyon “will result in market design flaws.”

Finally, the organization accuses PG&E of pulling a bait-and-switch by obtaining permission from FERC to recover some costs of the Diablo Canyon project from ratepayers who will not reap the expected benefits from the project because of its early termination (ER19-2568). CGNP requests that the commission hold a hearing on whether the utility’s rates can still be justified based on the closure of Diablo Canyon.

“Taking 10% of the state’s [baseload] power offline … and then building new lines through wildfire-prone regions, to deliver less reliable power, is neither just nor reasonable,” CGNP says.

November 25, 2020September 26, 2025

Entergy Consultant Under Fire for Covert Role in MISO

Tensions have been building among MISO stakeholders over what some perceive as an undercover Entergy plant in stakeholder meetings.

At the center of the controversy is Veriquest Group President David Harlan, a former Entergy executive and regular attendee of MISO transmission planning meetings.

On Sunday, renewable energy advocacy group Energy and Policy Institute accused Entergy of placing Harlan in MISO stakeholder meetings to espouse the utility’s ideas without the company connection, citing public records it obtained. The group suggested that Entergy may have hired him to influence MISO policy away from renewable development in order to safeguard its coal and gas plants. “Entergy may have been worried about low-cost wind energy in MISO displacing the company’s expensive legacy coal and gas units, impairing its ability to justify construction of new power plants,” EPI said.

| MISO

Entergy: Nothing to Hide

Although Harlan had refused to identify his clients during meetings in 2019 and 2020, Entergy on Tuesday confirmed its association with him, telling RTO Insider there was nothing wrong with how he conducted himself.

Entergy Mississippi “has a longstanding working relationship with Dave Harlan and Veriquest Consulting,” an Entergy spokesperson said. “Mr. Harlan is a retired Entergy employee. [He] has made no secret of his time working with Entergy and his representation of Entergy Mississippi is well known within MISO circles. He advocated on the company’s behalf in the MISO stakeholder process, and, contrary … to insinuations, there’s nothing improper or unusual about those efforts.”

Entergy’s statement confirmed what some MISO members believed, said one stakeholder who asked not to be identified.

Use of a covert consultant does not appear to violate any MISO rules, however.

MISO’s Steering Committee debated throughout the year — but ultimately decided against — proposing a new rule that would require consultants to identify the clients they represent when participating in stakeholder meetings. The RTO’s Stakeholder Governance Guide does not contain a rule against the practice. (See MISO Weighs Rule on Consultant Transparency.)

The Steering Committee has instead advocated for committee chairs to be empowered to manage discussion based on the “norms” of their committees.

Stakeholders took notice after Harlan repeatedly refused to disclose his clients over multiple meetings of the MISO Planning Advisory Committee in 2019 and 2020. When Harlan offered opinions or asked MISO planners for more examination of their planning inputs, he has sometimes insisted that he is simply acting on his own behalf.

Questioning Planners’ Assumptions

Harlan repeatedly questioned MISO transmission planners’ assumptions on renewable generation growth, especially in MISO South. He has argued that renewables will not be able to carry the region’s industrial load as effectively as existing baseload generation.

Before forming Veriquest in 2008, Harlan, an engineer and MBA, worked for Entergy for 17 years. His last job was senior vice president for system planning and operations, following stints as vice president for strategic planning and special projects and vice president of marketing. He did not respond to RTO Insider’s request for comment.

The Steering Committee in May leaned toward drafting general language supporting stakeholder transparency rather than imposing a strict rule that consultants be forthcoming about their clients. The committee has avoided mentioning Harlan by name, as other consultants have participated in the MISO stakeholder process without first disclosing clients publicly.

“I think the Steering Committee is hesitant to put some strict rules in place regarding consultants, but there could be some language that says, ‘Hey, transparency is paramount to the stakeholder process,’” Resource Adequacy Subcommittee Chair Chris Plante of WEC Energy Group said at the Steering Committee’s meeting June 10.

Market Subcommittee Chair Megan Wisersky of Madison Gas and Electric said it was unnecessary to enact a new rule on consultant transparency.

“I see this as a matter of professional courtesy. And it’s just that. I don’t want to see professional courtesy codified in the Stakeholder Governance Guide,” Wisersky said.

Discounting Comments

Plante also said a rule was unnecessary, though he warned that stakeholders unwilling to disclose whom they represent might be dismissed by others.

“I discount their comments. From my perspective, if they’re not willing to announce their client, I take their comment less seriously,” Plante said.

MISO’s Advisory Committee discussed mandatory consultant identification at its closed executive planning session Nov. 2. The committee acknowledged that the issue arises mostly in PAC meetings. PAC Chair Cynthia Crane has promised a follow-up on the issue at the committee’s January meeting.

Entergy’s spokesperson said Harlan has abided by MISO requirements and that “his client’s identity was known to MISO, to our regulators and to many stakeholders, as well.”

“In addition, Mr. Harlan’s advocacy with MISO was part of a larger effort by Entergy Mississippi to work alongside regulators and other stakeholders to advocate for transmission planning and cost allocation approaches that we believe are in our customers’ best interests,” the spokesperson said.

Communications with Mississippi PSC

Emails from Harlan to Mississippi Public Service Commission Special Counsel David Carr, obtained by EPI, confirm that Harlan makes comments on behalf of Entergy and collects information in MISO meetings to pass along in the company’s strategy meetings. They also appear to show that Harlan sometimes voices the positions of the Mississippi PSC as well as Entergy Mississippi.

In one email Sept. 25, 2019, Harlan asks if he is accurately representing the stances of both Entergy Mississippi and the Mississippi PSC. “Please let me know if any of my comments were perceived as contrary to the common or best interest of MISO South customers, [the Mississippi PSC] or [Entergy Mississippi],” he says. “I need to be aware of any concerns so I can limit or reframe my comments in future discussions.”

He also reports that he received “pushback in and outside of meetings seeking to silence or restrict my oral comments, from the renewable lobby and probably a MISO North regulator and some transmission developers.” In the same email he says he “resisted efforts … from MISO and some stakeholder [sic] to identify my clients before making a comment.”

“My comments at MISO meetings always seek to raise issues for thought and to promote better visibility, transparency and objectivity in the MISO discussions and planning processes,” he tells Carr. “I never represent that I speak for [Entergy Mississippi] or [the Mississippi PSC], but rather as a MISO South customer and an adviser to multiple MISO South stakeholders.”

Harlan sent the email after Clean Grid Alliance’s (CGA) Natalie McIntire appeared at the Sept. 23, 2019, PAC meeting to sound the alarm about increasingly pricey network upgrades for the mostly renewable generation in MISO’s interconnection queue. (See More MISO Members Join Call for Tx Planning Change.) He writes that his comments on the presentation “were not made on behalf of a specific client but to address issues of clarity or objectivity about the CGA proposal.”

“Since no other MISO South entity made comments, I felt that CGA[’s] comments needed some timely injection questioning some of their logic.”

Harlan says that CGA is “launching a full-court press to build transmission for wind delivery from MISO North and have load pay for transmission costs for both local and distance delivery.” He speculates that the Midwestern Governors Association and some MISO Midwest state regulators and utilities were also behind the push for new transmission to enable renewable generation.

In early October 2019, Carr wrote that PSC staff would discuss Clean Grid Alliance’s presentation with Entergy Mississippi using information collected by Harlan. In a May 2019 email, Entergy Mississippi Vice President of Regulatory Affairs Jeremy Vanderloo gives Carr a heads-up that Harlan would be raising Entergy Mississippi’s concerns about the cost allocation of some transmission projects in MISO’s 2019 planning cycle at a MISO South subregional planning meeting.

Entergy has used backdoor channels to advance its agenda before. In 2018, Entergy New Orleans contracted with public affairs firm The Hawthorn Group to arrange for paid actors to show up at New Orleans City Council hearings in support of a proposed $210 million natural gas plant. Though the council placed a $5 million fine against the company for the scandal, it ultimately approved the Michoud Plant.

November 25, 2020

Meshed OSW Tx Grid May Work Best, NY Officials Hear

Preliminary analysis suggests that a mesh-and-backbone network design would be the best way to integrate offshore wind into the New York grid despite higher initial costs than a business-as-usual radial approach, likely offering more redundancy and potential savings down the line, state officials heard Monday.

“That redundancy is what we’re attempting to quantify with the project availability analysis, so if there is an outage, if you are operating in a mesh system, for example, that outage may not be as severe than it otherwise would be with a radial connection,” Jake Frye, senior project manager at DNV GL, said in delivering the findings at the second transmission technical conference hosted this fall by the state’s Department of Public Service and the New York State Energy Research and Development Authority. (See OSW Growth to Test New York’s Transmission Grid.)

OSW Transmission — Consultants say the meshed grid design is the most flexible and can adapt to different OSW project locations and sizes, whereas other networked strategies are limited by uncertainty around availability of wind energy areas. | *DNV GL, PowerGEM, WSP*

“There are cost savings there; there’s a savings in megawatt-hours that were not lost,” Frye said, adding that additional cost and availability analysis is nearly complete and will be available in a written report by the end of the year.

Norway-based DNV is collaborating with engineering firms PowerGEM and WSP to complete an OSW integration study for New York, one of three studies informing grid investment plans to be established by the Public Service Commission for distribution and local transmission upgrades, as well as for bulk system transmission investments (Case No. 20-E-0 1 97). (See NYPSC Launches Grid Study, Extends Solar Funding.)

Siemens presented its work on the zero-emission grid for the second study, which found that significant local transmission upgrades will be necessary to incorporate all planned renewables in New York. Siemens Consulting Manager Yan Du said his group identified 63% of the state’s total congestion constraints in New York City (Zone J), 12% in Westchester County (Zone I) and 8% on Long Island (Zone K).

Further study will be required at every level, from the impacts of OSW on the downstate grid, to the exact cost and size of transmission upgrades, Siemens said.

“We are committed and seek the best input in achieving the most sensible, risk-minimizing and cost-effective path to achieving our goals quickly and reliably,” PSC Chair John B. Rhodes said.

Utility Local Transmission Studies

While every utility in the state has plans to upgrade its transmission system, all eyes tend to move southeast, as 6 GW of OSW will interconnect into New York City and 3 GW into Long Island. The state’s Climate Leadership and Community Protection Act (CLCPA) mandates procuring 9 GW of offshore wind energy by 2035.

The state’s investor-owned utilities on Nov. 2 jointly filed a report on transmission and distribution investment, and representatives from each company joined the technical conference to outline their policy recommendations and proposed projects.

The IOUs include Avangrid subsidiaries New York State Electric and Gas and Rochester Gas & Electric; Central Hudson Electric and Gas; Consolidated Edison and Orange and Rockland Utilities; and National Grid subsidiary Niagara Mohawk Power. They collectively proposed to undertake about $7 billion in transmission and distribution upgrades by 2025 and another $10 billion in projects for the following five years to 2030.

Con Ed has identified three immediately actionable projects to give renewable resources access to the load and unbottle load currently served by fossil generation, the utility’s Section Manager Martin Paszek said. The projects will also enable compliance with the state Department of Environmental Conservation’s “Peaker Rule,” new NOx regulations that go into effect May 1, 2023. (See NY DEC Kicks off Peaker Emissions Limits Hearings.)

The projects’ total estimated cost is $860 million for new 345/138-kV phase angle regulator-controlled feeders for the second Rainey-Corona, third Gowanus-Greenwood and Goethals-Fox Hills feeders, and a substation rebuild for the last, allowing an estimated 900 MW of renewables access to load.

Con Ed plans to file a petition with the PSC by the end of the year seeking approval to recover the costs and will provide each individual project’s cost estimate for inclusion in the petition. Further, the company asked that the PSC “consider the significant regional environmental benefits these three immediately actionable projects provide.”

The utility is also asking the commission to approve up to $4 billion for the second phase of six projects to create points of interconnection, including two new “NYC Clean Energy Hubs,” several new feeders and two rebuilt area stations, and that the PSC allocate the costs statewide on a load-ratio-share basis.

The Long Island Power Authority (LIPA) and PSEG Long Island submitted a list of projects through 2025 and another list of Phase Two “conceptual” projects specifically identified to deliver 3,000 MW of OSW into Long Island. They were considered for their ability to increase the transmission transfer capability on LIPA’s system, said Hao Fu, PSEG transmission planning engineer.

“Under peak-load conditions, transmission headroom is available to deliver offshore wind power to load centers, and under light-load conditions, total load demand will be much less than total offshore wind output,” Fu said. “As a result, more power will flow in the east-to-west direction on the transmission system, which will create thermal constraints.”

Written comments on the overall plan are due at DPS by Jan. 18.

November 25, 2020

ISO-NE PAC Briefs: Nov. 19, 2020

ISO-NE is proposing a pilot study for its “Transmission Planning for the Clean Energy Transition” effort that would test grid performance assumptions under scenarios of high renewable penetration and quantify the tradeoffs between transmission investment and less system flexibility.

The pilot study would take a “10,000-foot view” of the entire New England system, rather than a portion of it, according to Dan Schwarting, a transmission planning supervisor for the RTO.

The goal is to identify the overall trend of system behavior and reliability concerns as more renewables are brought online, not to identify exact needs or system upgrades. Base cases will represent a likely dispatch for a given condition rather than stress any specific portion of the system through generator outages.

The RTO said steady-state N-1-1 analysis on the entire system is feasible because of recent study automation efforts. Stability analysis will concentrate on faults on the 345-kV system and 230-kV or 115-kV faults that are incredibly impactful. Limited electromagnetic transient study work may be pursued as well.

ISO-NE PAC — Each blue dot represents a single hour experienced between 2012 and 2018. ISO-NE is proposing to study the “corners,” at the intersection of high/low load and high/low solar output. | *ISO-NE*

Schwarting said the results of the pilot study will be most useful if it begins with fairly conservative conditions, such as high wind generation when low inertia may be a concern and low wind generation where load serving may be an issue. He said it would also investigate potential paths to address reliability concerns through transmission system investment, operational measures and policy changes.

Any reliability problems found would not be immediately addressed in a solutions study or competitive request for proposals. The proposed transmission solutions would be representative only, and costs would be order-of-magnitude estimates.

The results of the pilot study would inform decisions on assumptions to be used in future transmission needs assessments.

Additionally, certain study assumptions are affected by policies both inside and outside ISO-NE’s purview, such as distribution system power factor, distributed energy resource voltage and frequency control capability, and DER fault ride-through capability. Initially, the pilot study will assume a “business-as-usual” approach to these policies. If changes to the policies promise benefits, they will be considered as mitigating measures. However, the RTO wants reasonable assurance that these policies would be implemented and enforced before it could rely on them in future needs assessments.

Schwarting said that many stakeholders provided comments during and after his PAC presentation in September. (See “Proposed Study Conditions to Meet Challenges in Transmission Planning,” ISO-NE Planning Advisory Comm. Briefs: Sept. 24, 2020.)

The feedback related to study conditions centered on two questions: How likely are the proposed study conditions to occur, and can operational measures ensure reliability in those conditions?

The DER and storage policies-related feedback and questions from stakeholders included: Would the implementation of voltage and/or frequency control on DERs mitigate reliability concerns? Also, could better rules around the behavior of storage assets address peak- and minimum-load conditions?

Stakeholders may submit feedback on the pilot study proposal until Dec. 4, and the next steps include the development and review of the base cases. The analysis will begin in late 2020 or early 2021. The RTO will reach out to distribution providers regarding DER data collection in parallel to the pilot study.

Preliminary Production Cost from Economic Study Presented

ISO-NE presented preliminary production cost results to the PAC for the 2020 Economic Study requested by National Grid. The utility asked for a one-year study focused on 2035 to provide stakeholders analyses of the best ways to meet state clean-energy goals cost-effectively, leveraging transmission and storage as needed.

Richard Kornitsky, ISO-NE’s assistant engineer for system planning, said the introduction of bidirectionality across existing ties causes a reduction of spillage during situations of low load and high-variable resource production. Total systemwide spillage is relatively low compared to the New England States Committee on Electricity case of 8,000 MW spilled because of the RTO’s assumption of high load in 2035.

Because emissions associated with imports from Hydro-Québec and New Brunswick are assumed to be zero, the impact of energy banking of non-emitting New England resources is not apparent in many of the systemwide metrics. Natural gas production is replaced by adding new ties with firm low threshold-price import capability from Hydro-Québec.

The study used bidirectional threshold prices reflecting renewable energy credit values, first-to-curtail imports, then trigger exports, with renewables curtailed once export capability is exhausted. The prices ranged from -$100/MWh for behind-the-meter PV to -$30/MWh for onshore wind. The trigger for exports is assumed at -$25/MWh.

Kornitsky asked for any feedback or comments by Dec. 1, including possible sensitivity scenarios. The next steps include identifying sensitivity scenarios and assumptions for the PAC meeting on Dec. 16, presenting assumptions for ancillary services analysis and draft results in the first quarter of 2021. The final report is expected in the second quarter of 2021.