Pacific Gas and Electric announced late Friday it had reached a $13.5 billion settlement with the individual victims of wildfires sparked by its equipment from 2015 to 2018.
The announcement ended a tumultuous week for PG&E that included a growing movement to take the investor-owned utility public and revelations in a state report that said worn and broken hardware on a century-old transmission line had led to California’s worst wildfire disaster.
PG&E’s agreement with the Tort Claimants Committee (TCC) and firms representing individual claimants, to be paid in cash and stock, matches a proposed deal by bondholders for their own Chapter 11 reorganization plan in an effort to take over the utility. PG&E and bondholders have engaged in mediation and negotiations with California Gov. Gavin Newsom to resolve their differences. (See PG&E Bankruptcy Judge Appoints Mediator.)
How PG&E’s announcement will affect the bondholders’ plan remains uncertain, but the utility hailed its settlement as a big step in its bankruptcy. The company is trying to emerge from bankruptcy by June so it can participate in a $21 billion wildfire recovery fund established by the state last summer under Assembly Bill 1054.
“From the beginning of the Chapter 11 process, getting wildfire victims fairly compensated, especially the individuals, has been our primary goal,” PG&E CEO Bill Johnson said in a statement. “With this important milestone now accomplished, we are focused on emerging from Chapter 11 as the utility of the future that our customers and communities expect and deserve.”
Neither the TCC nor other interested parties had issued any reaction to the announcement as of Sunday.
PG&E came under heavy criticism this fall for cutting power to millions of residents as part of its public safety power shutoff events, intended to prevent its equipment from igniting more wind-driven wildfires.
The $13.5 billion settlement with the TCC, composed of the lawyers representing fire victims, will resolve all claims arising from 22 major wildfires in Northern California’s wine country in October 2017 and the 2018 Camp Fire, PG&E said.
In a surprising move, the agreement includes the Tubbs Fire, which killed 22 people and leveled part of Santa Rosa in Sonoma County in October 2017. It’s unclear why that fire was included. State fire investigators determined a private landowner’s illegal distribution lines, not PG&E’s equipment, sparked that fire. PG&E has denied responsibility. A trial to determine liability is scheduled to start in January, but whether it will proceed is unknown.
On the tower suspected of starting the Camp Fire in November 2018, an insulator detached from the hangar plate and hung upside down.| PG&E/CPUC
The settlement also covers the Butte Fire, which decimated communities in the Sierra Nevada foothills southeast of Sacramento in September 2016, killing two people, destroying 475 homes and scorching more than 70,000 acres. Many victims of that fire have yet to receive compensation from PG&E.
The settlement with fire victims is the third and final agreement that PG&E wanted to emerge from Chapter 11 reorganization. The utility previously announced a $1 billion settlement with local governments over fire claims and an $11 billion settlement with insurers and hedge funds who hold subrogation claims against it.
On Wednesday, lawyers argued in court over whether the bankrupt utility should be allowed to move forward with a proposed $11 billion settlement with the subrogation claimants. Lawyers for fire victims have argued that the deal would leave the company without enough resources to fairly compensate fire victims. (See related story, PG&E Judge Weighs Insurers’ Settlement.) PG&E’s agreement with fire victims could potentially moot that concern.
All the settlements must be approved by U.S. Bankruptcy Judge Dennis Montali in San Francisco, who is overseeing the case.
PG&E’s stock price shot up from $7.66/share on Dec. 3 to $10.49 during trading Thursday based on rumors of the settlement with wildfire victims prior to its announcement. Shares closed Friday at $9.65.
The settlement ended an eventful week in the PG&E drama. California’s largest utility, facing billions of dollars in wildfire liabilities, is engaged in one of the largest bankruptcies in U.S. history.
On Dec. 3, the California Public Utilities Commission’s Safety and Enforcement Division released a nearly 700-page report that detailed PG&E’s failings in its inspections and maintenance on its 100-year-old Caribou-Palermo transmission line in the rugged foothills of Butte County. Those failings led to the Camp Fire, the deadliest and most destructive fire in state history, which killed 86 people and destroyed more than 19,000 structures in November 2018 in the town of Paradise, state fire investigators and the CPUC found.
On Thursday, San Jose Mayor Sam Liccardo said his plan to turn PG&E into a public utility was gaining ground — with 115 elected officials now supporting it — as he released an outline of principles meant to guide such a transition. Those principles include keeping the giant utility whole, instead of breaking off pieces into municipal utilities as some have suggested, while transitioning it to public ownership and operation. “Today, we released a … framework for a customer-owned PG&E that is transparent, accountable and equitable to put the company’s days of underinvestment, mismanagement and negligence far behind us,” Liccardo tweeted.
LAS VEGAS — CAISO’s Western Energy Imbalance Market Governing Body and Regional Issues Forum met last week in Sin City’s fake take on an ancient Egyptian pyramid, the Luxor Hotel and Casino. In the casino, gamblers pulled on the handles of slot machines while nursing free drinks. In a nearby meeting room, RIF participants discussed resource adequacy while sipping free coffee.
They also heard from representatives from Modesto Irrigation District, Tacoma Power and Turlock Irrigation District, who explained why they plan to join the West’s real-time interstate electricity market.
Money was a factor, but so too was the evolving Western electricity market, where interstate trading of diverse resources across state lines appears key to the future.
“As more and more folks join the EIM … the thought of not participating in that market is just not feasible … to be blunt,” said James McFall, Modesto’s assistant general manager of electric resources. “You’d get left out in the cold, and we’d have a very illiquid market to access at that point.”
The irrigation district was formed in 1887 to supply water to farmers in California’s Central Valley. It became an electricity purveyor in 1923 and now serves nearly 129,000 retail, commercial and industrial customers across 560 square miles.
The neighboring Turlock Irrigation District, which is two days older than MID, has a similar backstory, said its energy markets manager, Dan Severson. Its hydroelectric dams in the Sierra Nevada foothills are now part of a portfolio that includes natural gas, biomass, solar, wind and geothermal generation.
In his presentation, Severson echoed some of McFall’s remarks. He said that as EIM participation increases, the bilateral hour-ahead markets are becoming less liquid, with fewer trading — which will increase costs going forward. As the EIM looks to expand to a day-ahead market, liquidity could be further reduced, he said.
By joining the EIM, “we [have] access to a larger network of energy providers and increased revenues from sales and increase purchase of megawatt-hours,” Severson said.
Tacoma Power’s electricity comes mainly from hydropower, said Clay Norris, the utility’s power manager. The 125-year-old municipal utility is a subsidiary of a parent company, Tacoma Public Utilities, that also owns and operates a short-line railroad serving the Port of Tacoma.
Norris said Tacoma Power ran its own analyses instead of hiring a consultant when it considered joining the EIM. Its scenarios didn’t all pencil out. The utility has about a 70% chance of recovering the hefty start-up costs of joining the market in the next 10 years, he said.
But the move was about more than finances, he said, echoing that bilateral trading was becoming more difficult in the West, and the broader market of the EIM is now the primary route for buying and selling electricity, with diverse resources and fluid trading.
“This decade has really been about the EIM, I think,” Norris said.
Washington, like several other Western states, now has a 100% clean energy mandate by midcentury and needs to modernize its trading practices to achieve that goal, he said.
The three new entrants join a growing list of EIM participants in a Western market that’s proven popular for its financial benefits and wholly voluntary participation.
The Balancing Area of Northern California signed an implementation agreement with CAISO that will allow members Modesto, Turlock and others to begin trading in the EIM in April 2021.
The BANC agreement represents the second phase of the balancing area’s approach to incorporating its members into the EIM. Sacramento Municipal Utility District entered the market in April. (See SMUD Goes Live in Western EIM.)
Tacoma plans to begin participating in the EIM in 2022. By that time, 77% of the Western Electricity Coordinating Council’s total load will be active in the EIM.
BOSTON — Some 200 industry players braved the first major snowstorm of the season in order to attend the New England Power Generators Association’s inaugural energy summit last week, where state officials and investors debated the right market model to achieve environmental goals across the six-state region.
NEPGA President Dan Dolan said the inaugural conference marked the 20th anniversary of ISO-NE launching its wholesale electricity market in 1999.
Following are highlights of what we heard at the conference.
Wood Urges Markets to Become ‘Proactive’
Former FERC Chair Pat Wood III said that the electricity markets have provided a lot of benefits since the founding of the New England Power Pool in 1971, but that a “troubling amount of state subsidies outside the market … risks losing all the benefit of that market construct.”
“That efficient dispatch and that transparent display of pricing — people meeting each other in the market — brings down costs to the customer,” Wood said. “That’s fundamentally in the spirit of a public industry that’s got a lot of private interest involved but is a very publicly oriented industry.”
The link between what customers and their elected representatives want and what the markets are delivering is fraying because of the growing imbalance between market revenue and that from out-of-market contracts, he said.
“So, we’ve got to get the market design back to being a proactive function and not so much in the reactive mode,” Wood said. “Unbundle the crap out of everything and take exactly what we have in the FERC system and unbundle it.
“When we align the end-use customer price signals back to all these wonderful price signals we’re putting out in the wholesale market, that’s when we win.”
Massachusetts Sen. Michael Barrett, a member of the legislature’s Joint Committee on Telecommunications, Utilities and Energy, said his state can expect a big energy initiative soon.
“It’s fair to say the state subscribes to the idea that we are here to support deep electrification,” Barrett said. “Fundamentally, if you’re a power generator, this is very good news.”
Barrett said Massachusetts is “leading the way” on the Transportation and Climate Initiative (TCI), a collaboration of 12 Northeast and Mid-Atlantic states and D.C. seeking to reduce car and truck emissions, partly because New York has not joined.
“New York is sending staff to the multistate meetings, but Gov. [Andrew] Cuomo has not committed his state the way other governors have done,” Barrett said. “It would be wonderful if New York did join.”
The gasoline market does not show a perfect correlation between pricing and consumer behavior, “so if you double the price, you don’t halve consumption, but there is a positive relation, so we can make progress,” he said.
New Hampshire Sen. Martha Fuller Clark, chair of the Energy and Natural Resources Committee, said her state “has historically been a bit behind the other New England states in energy policy … which is not necessarily a bad thing, since we’ve been able to learn from the others.”
Massachusetts Energy and Environmental Affairs Secretary Kathleen Theoharides said that she is focused on bringing new renewable resources into the market as well as electrifying the transportation and building sectors to take advantage of the new hydro, wind and solar resources as they come online.
“We really feel you need to do those two pieces at the same time. You don’t just clean up your power and then do electrification next,” she said.
Transportation now accounts for 40% of carbon dioxide emissions in the state, region and country, so the TCI is working on a cap-and-trade system similar to the Regional Greenhouse Gas Initiative, which the state has been trying to do “in one form or another for the past 10 years,” Theoharides said.
“Our economies are tied together in the region, and pricing gasoline is more difficult if you’re doing it state by state,” she said. “If you look at the 12-state region, Massachusetts is about 10% of the emissions for that region, so when we’re able to get the whole region into something like this, we can actually multiply our impact on emissions 10 times.”
Theoharides said she worries about “the piecemeal nature of some our climate and energy policies” and that cities, states, regions and the federal government have to “pull together” better than they have to date.
Dan Burgess, director of the Maine governor’s Energy Office, highlighted the new push for renewables under Gov. Janet Mills and said that “a lot of the new energy legislation passed in Maine this year was done in a bipartisan way.”
Investor Perspectives
Jim Burke, executive vice president and COO of Vistra Energy, said that in the past three years, his company has “shut 4,200 MW of coal in Texas; we have just shuttered 1,500 MW of coal in Illinois last month; we have 400 MW that will close in two weeks; and our portfolio shifted from two-thirds coal to two-thirds gas.”
The company also has the 2,425-MW Comanche Peak nuclear plant in Texas, “and we’re building the largest battery so far … just an hour south of Silicon Valley; that’s a 300-MW battery.” It is also pairing energy storage with solar, he said.
“We are technology-agnostic,” Burke said. “We believe that trends that are happening in New England and California will happen elsewhere in the country, but we’d also like to see trends that are happening in Texas spread elsewhere. There are things we can learn from each market.”
Brookfield Renewable Power Managing Partner Mitch Davidson said his company invests in New England for the same reason it invests elsewhere: because it sees an opportunity to either acquire or build an asset and get a healthy return on it.
“Early on in New England, the capacity markets worked very well,” Davidson said. “In Forward Capacity Auction 8, we saw that the market was short, and the price signals were there … and in FCAs 9, 10 and 11, there were 2,000 MW built over those four capacity auctions. Those were the right signals … and that’s the kind of environment we want to put our capital to work in.”
In FCA 12, the company expanded its Bear Swamp pumped hydro facility, of which it is part owner, he said.
“What we have concerns about is the trend in which the market is heading … some uncertainties we’re seeing,” Davidson said.
Matthew O’Connor, managing director of Carlyle Power Partners, said his firm chose New England in 2015 “because it looked like a really good environment to invest: really hard to permit things, really hard to build things, lots of barriers to entry. And back then, we actually thought gas was going to come into the region.”
Carlyle is the second-largest owner of generation in New England after Vistra, with just under 2,500 MW, he said.
“We have a number of plants that are dual-fuel, so we are able to respond to ISO-NE when gas gets really short, as it does in the wintertime here,” O’Connor said.
“We see this as an attractive market, but I share Mitch’s concerns about the future,” he said. “As an example, we put almost $90 million in each of our plants over the last three years. We’re only going to be able to continue to do that if there’s going to be a return on that money, and we’re starting to get concerned that that might be good money after bad.”
Former FERC Chair Cheryl LaFleur asked, “Are you still confident that if we get the price signals right, we can still build the things that we need to serve New England? Or, how much is that in your thinking?”
“I think ‘confident’ is a strong word when answering that question,” O’Connor said. “The question is, do the economics support that [investment]? And we would argue today that they don’t.”
CARMEL, Ind. — A new team considering sequencing parts of MISO’s transmission planning with network upgrades identified in generator interconnection studies held its second meeting Wednesday, with stakeholders outlining the issues they hope to have addressed.
Upcoming discussions of the RTO’s Coordinated Planning Process Task Team (CPPTT) could result in strategies to lower the increasing costs generation developers are facing for network upgrades.
The task team is MISO and stakeholders’ response to complaints from the Environmental and Other Stakeholder Groups sector and others that renewable growth is being hindered by increasingly expensive upgrades. (See Renewables Group Calls for MISO West Tx Construction.)
Several stakeholders have called for the RTO to more closely align its studies that identify network upgrades for the interconnection queue with its annual Transmission Expansion Plan (MTEP) so that transmission that facilitates new renewable output isn’t borne exclusively by generation developers.
The team’s tentative mission is to identify “potential coordination and consistency issues” between MISO’s generator interconnection and MTEP processes.
MISO Manager of Resource Interconnection Arash Ghodsian promised that the team will examine the timing and methodology of the different studies under the interconnection queue and MTEP. “Where can we gain some efficiencies? Where can we gain some consistency?” he told stakeholders. He said the goal is to find the best transmission solutions that can meet a variety of purposes.
Clean Grid Alliance’s Natalie McIntire said the interconnection queue and the MTEP process should share assumptions so that it’s not a race to see which party will foot the bill of a transmission project. “We don’t want to have the timing of the studies determine who pays for the project. Right now, whatever study finishes first determines who pays. That seems to us to be an important principle here. We should have a better process to determine the beneficiaries,” McIntire said.
However, MISO Director of Planning Jeff Webb said it’s impractical to expect the RTO would be able to apply the same set of assumptions to every type of planning study. “It doesn’t make sense. It’s too prescriptive,” Webb said.
McIntire said that interconnection customers are discovering that the costs of network upgrades are “more than the capital costs” of the generation projects themselves.
“I don’t think anyone believes that these several million to $1 billion major upgrades are going to be paid for by interconnection customers,” EDF Renewable Energy Interconnection Manager Anton Ptak said.
He also said MISO “is just at the beginning” of seeing its utilities dramatically alter their fuel mixes and argued that it should identity the beneficiaries beyond the interconnection customer of such expensive upgrades.
“Once upon a time, we were ordered to do cost allocations for generator interconnections instead of the direct assignment approach,” Webb pointed out, noting that MISO has returned to assigning costs directly to interconnection customers and ignoring other beneficiaries. About 14 years ago, the RTO used a 50/50 cost sharing of network upgrades between interconnection customers and load in corresponding transmission pricing zones, with the zonal half collected like baseline reliability projects were, through a blend of 20% postage stamp and 80% sub-regional allocation. To be eligible for the cost sharing, interconnection customers had to become MISO network resources or have proof of a one-year power purchase agreement.
The Union of Concerned Scientists’ Sam Gomberg said MISO should strive to end the “free ridership” of beneficiaries. “Those seem like principles that we should be able to get behind,” Gomberg told attendees.
Great River Energy’s Mike Steckelberg suggested MISO consider creating a transmission project market, where multiple parties can bid in to share project costs.
MISO stakeholders are encouraged to send more issues for the task team to consider through Jan. 2. The CPPTT will hold another a meeting in mid-January.
CARMEL, Ind. — MISO stakeholders last week debated whether the RTO is being too conservative in anticipating industry shifts in its new futures scenarios for transmission planning.
MISO in October released a trio of new 20-year future scenarios to assist transmission planning for the 2021 Transmission Expansion Plan (MTEP 21). (See MISO Sets Course for New Futures.)
Now, the RTO has revised the scenarios’ names to Announced Plans, Accelerated Fleet Change and Advanced Electrification. It has also upped the age at which coal units retire by at least four years in each future and reduced carbon reductions from 50% to 40% in the Accelerated Fleet Change future.
MISO also cut its electrification predictions in both the Advanced Electrification (from 70% to 40% energy growth potential) and Accelerated Fleet Change futures (from 40% to 20%).
Finally, the Announced Plans future now contains an 85% probability instead of total confidence in changes identified in utilities’ integrated resource plans, including coal retirements, new gas-fired generation and emission-reduction targets.
At a special workshop Thursday, MISO Planning Manager Tony Hunziker said the changes were made after the RTO evaluated feedback from stakeholders.
“There was an emphasis on having more conservative assumptions,” he said.
A Question of Coal Retirements
Xcel Energy’s Drew Siebenaler pointed out that his company plans to end all coal use in the MISO footprint by 2030. He also said the RTO should consider that it is often expensive to keep aging coal plants cycling.
“What we’ve learned is it takes a ton of capital to keep these units [operating as reliability]-must-run. I’d like to also see how they’re going to be dispatched,” he told RTO staff.
Veriquest Group’s David Harlan said MISO wasn’t clear on what generation would replace retiring coal units. Hunziker said it would use the Electric Power Research Institute’s Electric Generation Expansion Analysis System (EGEAS) to predict generation expansion.
Clean Grid Alliance’s Natalie McIntire said it didn’t make sense to extend the lifespan of coal plants from 30 years to 35 in the Advanced Electrification future. She said coal use is ending, whether or not members want it to occur.
“I understand that there are a lot of stakeholders that are uncomfortable with an aggressive future. But it’s not MISO’s job to predict the future; it’s to create a reasonable range of plausible futures. We’re not trying to get everyone comfortable with every future. I don’t think it’s reasonable not to have an aggressive future in there, given that all of the [changes predicted] in MISO’s existing futures have been exceeded,” she said.
Comfort not the Goal
Megan Wisersky of Madison Gas and Electric said she agreed that stakeholders shouldn’t be at ease with the scenarios outlined in the futures.
“It’s not our job to make sure that everyone is comfortable. We really need futures that are stretches — that contemplate technological change, political change … that in late 2019, we can’t fathom,” she said.
Wisersky said MISO should craft futures using more intense industry shifts so it doesn’t again use obsolete predictions. The RTO plans to use its existing four futures one last time for the 2020 cycle of its transmission planning.
“It just seems like MISO has scaled back on these in response to a few stakeholders’ comments. These are supposed to be bookends,” McIntire said.
Minnesota Public Utilities Commission staff member Hwikwon Ham suggested MISO assume a 35-year coal plant age retirement in all three futures, then update the ages as utilities announce retirements.
Stakeholders also said MISO should take utilities’ IRP plans at their word, or even assume that utilities will exceed their IRP goals ahead of time. Some suggested that for utilities to publicly announce retirements and not see them through may constitute fraud.
McIntire asked if MISO would include corporate commitments to renewable energy and carbon-cutting in any of its futures.
“We considered that. We didn’t want to double-count them,” Hunziker said.
He said MISO would rely on load-serving entities to include that information in their load forecasting. However, he also said it might consider reaching out to multistate corporations whose renewable goals might be hard to pin down on a single-utility basis.
After MISO revealed its initial futures proposal, the Union of Concerned Scientists’ Sam Gomberg blogged that they were the result of the RTO “lean[ing] into the undeniable transition towards renewable energy resources, emerging technologies like battery storage and the growing momentum behind decarbonizing our economy.”
Gomberg said the new futures are “essential to ensure a modern grid is ultimately ready to support a clean and reliable electricity supply.”
“MISO’s job isn’t easy — making investments now to prepare for an uncertain future. MISO can’t create our clean energy future — that’s up to us as consumers to demand. But MISO, through its function as the regional grid operator, can either complement or hinder our progress. MISO’s proposed revamp of its planning process is a strong step in the right direction to ensure our electricity grid is ready for our clean energy future,” Gomberg said.
Hunziker invited more stakeholder opinions on the three futures. MISO will continue developing the futures scenarios through January, with the definitions completed in either February or March.
BOSTON — ISO-NE on Thursday marked 10 years of its Consumer Liaison Group, whose quarterly meetings serve as a forum for the public to get to know the regional transmission organization, and for the RTO to hear people’s concerns about climate change, their electricity bills and public policy on energy.
As is customary on an anniversary, people took the opportunity to look back, as well as to think about what the future might hold.
The nearly 200 people who attended included state regulators, utility executives, consumer advocates and industry stakeholders — some of whom thought that public policy is outstripping people’s ability to pay, while others said the region is not moving fast enough to meet the challenge of climate change.
Following are highlights of what we heard at the event.
“We are running out of time,” said Mary Beth Gentleman, board member of FirstLight Power and clean energy advocate E4TheFuture. “We have done incredibly creative and smart things in New England, but we’re not doing it fast enough. We face an existential threat, and the kind of consensus and meetings and groupthink that have been the strength of New England now seems at odds to me with the pace that we need to move.”
Gentleman said that the biggest surprise for her in the past decade was that Massachusetts licensed a billion-dollar natural gas-fired power plant, Footprint Power’s 674-MW Salem Harbor Station, which came online in May 2018.
Lisa Linowes, executive director of The WindAction Group, a clean energy advocacy organization, said that most consumers have no idea why electricity prices are so high, or how public policy decisions affect their lives.
“Today I would encourage, if not demand, that the Consumer Liaison Group become much more engaged with consumers, and not people who come to push their own agendas at the state house,” Linowes said.
The RTO deserves a lot of credit for the work it’s done over the past decade, but ratepayers in New England are paying the highest electricity rates in the continental U.S., and third in the country only to Hawaii and Alaska, she said.
“There’s something wrong with the system here,” Linowes said. “Much of the onus, in my opinion, is on the shoulders of the states. Does anyone know how much the Massachusetts [renewable portfolio standard] costs? In 2016, which … is the most recent information we have, it was $645 million; that’s the estimate put out by [the Department of Energy Resources].”
Market Economics
“I don’t think markets are broken; it’s just that the world has changed around the markets,” said Matthew Nelson, chair of the Massachusetts Department of Public Utilities. “Regardless of our personal or political positions, the reality in the market is one of increasing demand for clean resources.
“The question is: Can the market rise to meet that challenge? And if it can, what’s the cost?” Nelson said.
He likened today’s market to a three-legged stool, and said, “We’re trying to balance clean with cost and with reliability. Reliability today is king in the electric market, but the relationship between reliability and clean energy is not binary. The narrative that a clean future can only come at the expense of reliability is false.”
While reliability will decline slightly because of adding variable generation to the resource mix, it’s important to better understand what is “on the margins,” and the connection between decarbonization goals, reliability and costs, he said.
“Our metrics for reliability on the electric side are not easily understood, nor is the cost around different levels of reliability easily understood,” Nelson said.
Clean energy does bring sustainability, “but reliability will decline, so we’re left to decide how to deal with that going forward,” Nelson said. “We’re trying to redesign the market on the fly, while not interrupting service, and that’s a cost.”
If costs go up too much, it would affect businesses in the region, which face global competition, he said.
“I think out-of-market contracts are putting a strain on the system a little bit,” Nelson said. “They’ve got new resources coming in at zero price, but the costs are being passed onto consumers, and that’s interrupting the way the market works.
“We want to be able to balance sustainability with a plan,” he continued. “Where is this energy coming in? How much do we need? These are the decisions we need to think about right now. And are the contracts being purchased to respond to a consumer demand, or a policy demand for clean energy?”
Judy Chang of The Brattle Group spoke on trends in the New England power sector, such as declining load, technological advances, reduced costs of solar and wind, low natural gas prices and increasing environmental restrictions.
“What does it mean to have a market of increasing amounts of zero or negative price energy?” Chang said, suggesting setting up a centralized market for clean energy attributes.
Chang mentioned the power of corporations to affect energy policy, as signified by the growth of the Renewable Energy Buyers Alliance, whose members include many household names. Companies “do want to contribute to decarbonization,” Chang said. “Their customers and employees will be increasingly demanding such action.”
Brian Forshaw of Energy Market Advisors said he brought a consumer-owned utility perspective to the conference, and that his biggest surprise of the past decade “is that the markets have lasted as long as they have” after being created in the aftermath of the 1965 blackout.
Forshaw said the key takeaway from the day came from Nelson, who said that the world has changed around the region’s electricity markets.
Wind, Sun and Storage
Anne George, vice president for external affairs and corporate communications at ISO-NE, presented an update on the RTO’s activities, noting the grid’s transition to renewable resources, a topic to which the grid operator devoted a conference in May. (See ‘Grid Transformation Day’ Highlights ISO-NE Challenges.)
“It’s a much different grid from 10 years ago,” George said. “The amount of wind in our interconnection queue is the greatest we’ve ever had” — 13,720 MW, or 65% of the queue total of 21,138 MW. “And over the next 10 years, we’re going to see a lot more activity with battery storage,” she added.
Solar is growing too, as attested by Robert Dostis, vice president of stakeholder relations at Green Mountain Power, which serves about 78% of Vermont.
“In 2008 when I joined [GMP], I put solar on our roof and it was a novelty,” Dostis said. “It started picking up in 2012, and in 2013, we had 20 MW in the state. Today, just in [GMP] territory, we have 300 MW of installed solar and 130 MW in the queue. We have so much solar that some substations can’t handle any more.”
New England’s grid is transitioning to clean energy resources, which already dominate the ISO-NE interconnection queue. | ISO-NE
CLG Coordinating Committee Chair Rebecca Tepper, chief of the Energy and Telecommunications Division at the Massachusetts attorney general’s office, offered a snapshot of the group’s history.
“I don’t know if people are aware of this, but the Consumer Liaison Group was formed because of a FERC order, No. 719 … which was about enhancing the responsiveness of RTOs and ISOs to customers and other stakeholders,” Tepper said.
Among other requirements, FERC directed each RTO to provide a forum for affected consumers to voice concerns and propose solutions on how to improve the efficient operation of the markets, she said.
Tepper said the CLG will meet next on March 12, 2020, in Vermont.
SALT LAKE CITY — The Western Electricity Coordinating Council will launch an initiative next month to streamline bulk power system planning in the West. The effort seeks to tighten coordination and clarify who does what among the myriad planning groups, utilities and other industry stakeholders across the sprawling region.
WECC will create a new “BPS Roles” task force in January and expects to present an outreach and communication plan to its Board of Directors at the organization’s annual meeting in September 2020.
The effort is one of WECC’s “near-term priorities,” endowing it with a sense of urgency as the region’s BPS faces unprecedented and accelerating change from increased use of renewables and distributed energy resources, expansion of markets such as West’s RC Transition Earns Plaudits.)
Stakeholders attending a WECC Members Advisory Committee meeting Dec. 3 expressed broad support for the effort. Dozens of organizations have a hand in the West’s BPS planning, including formal planning groups (such as the soon-to-be merged Columbia Grid and Northern Tier Transmission Group), load-serving entities, transmission and generation owners, public interest groups and merchant developers. Rounding out the list are “assessment groups” such as NERC, FERC, the Western Interconnection Regional Advisory Board and WECC itself.
Kicking off a technical panel discussion to explain the initiative, WECC System Adequacy Planning Manager Byron Woertz showed a clip from “Miracle,” the 2004 film about the U.S. men’s ice hockey team that defeated a heavily favored Soviet team in the 1980 Winter Olympics.
The scene depicts coach Herb Brooks chiding the overly confident but incohesive team of college athletes following a humiliating loss: “You think you can win on talent alone? Gentlemen, you don’t have enough talent to win on talent alone.”
“In the West, we have talented planners, but we don’t have enough talent to solve our problems on our own,” Woertz told the audience of WECC stakeholders, staff and board members. “We need to coordinate with each other.”
‘The Punchline’
Three panelists joined Woertz to explain the rationale for the initiative, describe how WECC intends to approach it — and to provoke discussion among members.
“We know things are changing. When we look around the system, it’s not the same system that it was 20, 30, 40 years ago,” said Enoch Davies, WECC’s manager of system stability planning. Davies said system planners must gather more data on DERs connected with distribution systems: “That’s one thing that we have to improve coordination on — is how we get that information.”
Chelsea Loomis, regional electric system planning manager at NorthWestern Energy, said the use of the transmission system is also going to change. “And I think we’re experiencing that [change] as well, as entities are entering the Energy Imbalance Market or changing RCs. We’re just seeing a lot of different use on the transmission system itself.”
Woertz noted that — similar to DERs — utility-scale renewable resources are more widely dispersed than the fossil-fueled and hydroelectric resources that have traditionally dominated the grid. “The coordination among not only the organizations and the different planning roles, but [also among] the resources themselves, is going to be a challenge moving forward,” he said.
“As we see everything else changing, we probably need to change with it in our planning methods. I think that’s kind of the punchline of this whole discussion,” Davies said.
“Particularly if we want to maintain the same level of reliability that we’ve grown accustomed to,” Loomis added.
Growth Opportunity
Woertz broke the information-gathering process down to three key points: gathering the right data, from the right people, at the right time.
“There’s a lot of data out there. Make sure you’re getting from the people that really own that data. Make sure it’s timely — that you’re getting current information,” Woertz said.
“Regarding distribution generation, that’s a struggle we’re having today,” Davies said. “Where do we get that data? Is it distribution providers? Maybe that’s the right group; maybe it’s not.”
Loomis also pointed to the increased collaboration needed to create WECC’s “anchor data set,” the compilation of load, resource, unit dispatch and planning base case information to be used by the Western Interconnection’s regional planning groups as part of their transmission plans. That effort, kicked off five years ago, is still a work in progress.
Using the language of personal development, Northwest Power Pool’s Dave Angell, chair of WECC’s Reliability Assessment Committee (RAC), joked that the committee’s creation of the anchor data set has been “an opportunity for growth for a lot of folks.” The group has produced one anchor data set, is starting to produce the second and has set up a task force to review its first effort, he said.
One of Angell’s goals for the RAC is to fix inconsistencies in planning base cases. He noted that power flow base cases designed for planning are also used for reliability studies. “Those engineers that do reliability studies have a particular expectation of what information is in those particular cases, and they’re not at all interested in fictitious transmission lines and resources and all these things that might come about 10 years from now. ‘If it isn’t in the ground today, or if it isn’t under construction today, I don’t want it in my cases.’
“That ends up creating a disparity between looking at the future 10 years out, where a wind plant can be put up in matter of months,” Angell said. “We’re not talking years like older thermal plants used to take, and so things could change much more rapidly out there, and the ability for some of these engineers to embrace this sort of new and different world has been a struggle.”
Davies pointed to further “interesting interactions” with transmission and resource planners. “Transmission planners only want very sure things in their cases,” whereas resource planners want to include more speculative projects. “They need to work together to identify what actually should be showing up in those base cases.”
Loomis recounted a story that illustrated the uncertainty of including speculative projects in base cases, describing a proposed 460-MW wind farm that had triggered the need for a new 230-kV line in NorthWestern’s Montana system.
The project had an interconnection agreement and transmission service, but half of the planning team refused to include it in base cases for local area planning, saying they couldn’t rely on the resource.
“And I kind of pushed back and said, ‘They have an interconnection agreement and transmission service — this is a no-brainer,’” Loomis said. “To acquiesce to me, they put it in one of our sensitivity analyses and, lo and behold, the project did indeed go away. It’s really hard to know.”
Loomis also pointed to the case of the Highwood Generating Station, a 46-MW gas-fired project in Montana that broke ground in 2010 but was decommissioned five years later before it ever commenced commercial operation after its sponsor declared bankruptcy.
“It’s really hard to know exactly what [will get built], so I think trying to establish some common rules or common expectations for those types of generation projects that are driven by outside entities is a good thing,” she said.
“What we’re looking at is all these different perspectives using a common data source and process and methods to process the data and disseminate the information,” Angell said.
Sharing the Success
Woertz said gathering all the data was essential for “timely and relevant” reliability assessments.
“Regional planning groups, utilities [and] the ISO are doing their own analyses,” he said. “All of the organizations within the West are doing their own analyses, and they all give us a little bit different look at what the potential risks might be. Again, there’s a great need for collaboration and coordination so we can learn from each other as we’re doing these analyses.”
“And we don’t want to be duplicating analyses — and we want to do the right ones,” Angell added.
Davies pondered the ephemeral nature of the questions planners are trying to answer with their analyses. He said a decade ago, the industry was assuming a large amount of wind generation would be built to “serve all the huge loads in California.”
“It seems a lot different today, doesn’t it? Trying to evolve all those questions over time also is going to be part of this,” Davies said.
The graphic illustrates the complex interactions among stakeholders involved in Western system planning. WECC’s Woertz said a breakdown showing actual individuals would “look like a snowstorm.” | WECC
Woertz emphasized that another key objective would be putting the reliability results “into the hands of the right people differently and more effectively than we have in the past.”
“It’s not going to be sufficient to send out a mass email just to our committee people,” he said. “There are probably other people we should proactively reach out to, to actually get the message out to folks. WECC deals strictly with information. We don’t build anything; we don’t operate anything. If we have effective information, reliable data and interpretation of that data, that can be shared with other people,” he said.
Promising Signs
Brian Theaker, director of Western regulatory and market affairs for Middle River Power, urged the panelists not to downplay the impact of public policy in its analyses. He also expressed concern that reliability is “taking a backseat” to the imperatives of policymakers who don’t understand the reliability impacts of their decisions.
“What drives everything in California at this point is the race for decarbonization,” Theaker said. “And though there has been some really good work done that tries to look at some of the other perspectives and bring reliability and adequacy into it, there’s still this inexorable drive of public policy towards decarbonization.”
“In California, the policymakers are leapfrogging over the physics of the system,” said Dick Ferreira, of the Transmission Agency of Northern California. “If the lights go out, everybody’s going to point their fingers at each other.”
Loomis agreed with those concerns and noted a similar situation closer to home for her. “Missoula, Mont., announced that they’re going to 100% green by 2030, and everybody besides the city of Missoula is saying, ‘Wow, so you’re looking forward to some brownouts.’”
Maury Galbraith, executive director of the Western Interstate Energy Board, congratulated WECC and the panelists for providing the “most candid conversation” he’s heard about an issue in front of board members in his five years attending WECC meetings. He also reminded them that he brought up the same issue five years earlier with the creation of the anchor data set and the RAC.
“My question to the panelists is: You have a plan for the next nine months [in the BPS Roles effort]. What’s different today? What’s going to energize people to come to the table and try to address these issues, because you still have basically a collaborative approach to getting this data. You’re still trying to work with people and appeal to their best interests and share the data. What’s changed? What’s different now and why are you hopeful that this is going to work?”
Angell replied that RAC participants “are slowly sensing that there is change” and are “slowly changing to catch up.”
“You know the change cycle, right?” Angell said. “The first [reaction] is: ‘You screwed everything up and now you are harming me.’ Well, it takes a little while for some folks to get back out of being stuck in victim mode and to actually step forward and start working towards solving problems.
“We are starting to see some collaboration occur. It’s a start, and I think with this initiative and further emphasis on it, we’ll continue to move forward.”
ST. PAUL, Minn. — Increasing incidents of extreme winter weather, along with threats to physical and cybersecurity, are the most pressing items identified in Midwest Reliability Organization’s draft Regional Risk Assessment, presented at the organization’s Annual Member and Board of Directors Meeting last week.
The report follows NERC’s 2019 ERO Reliability Risk Priorities Report, which analyzed the risks facing electric utilities on a national scale and grouped them into four major categories: grid transformation; extreme natural events, including both weather and geomagnetic disturbances (GMD); security risks; and critical infrastructure interdependencies. (See NERC Board of Trustees Briefs: Nov. 5, 2019.) MRO aimed to determine which areas had a higher or lower potential burden for operators in the region.
Resource Mix Heightens Weather Impact
Given MRO’s footprint, which extends from Oklahoma to as far north as Saskatchewan and Manitoba, it is not surprising that winter weather, along with GMD events, are a higher priority than for regions in warmer regions. However, officials said winter challenges have become more pronounced over the last 10 years, with extreme events such as the 2011 polar vortex straining grid capacity even in the southern areas of the region.
“Winter peak demand is approaching or exceeding summer peak during severe cold spells. For example, on [the] Jan. 17, 2018, [cold-weather] event in the southern portion of the Midwest, all five entities involved exceeded their winter forecast by about 5 to 13%,” said John Seidel, MRO’s principal technical adviser. “It’s pretty interesting what winter … can cause, mainly due to the electric heating that occurs during the severe cold.” The 2018 event led Gen Operators Cool to Winter Preparedness Standard.)
MRO’s changing resource mix can also complicate the cold-weather issues, as conventional synchronous generation is replaced by renewable options such as wind, with output that is harder to predict. Seidel cited the gap between MISO’s predicted and actual wind energy production during the Jan. 30, 2019, cold-weather event as an example of this concern, adding that the problem was exacerbated when the extreme cold led turbines to hit their cutoff temperatures just as the need for their energy was most acute. (See Extreme Weather Tops NERC Winter Outlook.)
Evolving Threats, Lagging Response
Rapid change is also a hallmark of the technology landscape, and the need to determine how to integrate new technology tools while maintaining the reliability of the grid continues to be a source of headaches for security professionals.
Steen Fjalstad, security and mitigation principal at MRO, observed that 2019 saw no reported cyber or physical security incidents in the bulk power system that caused a loss of load, according to NERC’s Electricity Information Sharing and Analysis Center (E-ISAC). Along with this good news, however, there is also no shortage of reminders about the dangers that can arise from deploying new technology without adequate preparation.
“There have been recent breaches, not necessarily in our sector … due to cloud storage, and … identifying if we have the same risks and liabilities is very important,” Fjalstad said. “It’s kind of a gray area still in terms of components: A lot of the controls that might be in the cloud area [are] under contract, and the legalese … of what’s going into these contracts … is really a very valuable opportunity for us to delve further and reduce this risk.”
Risks highlighted in the cyber and physical security section of the report include a lack of adequately trained security staff and internal cultures focused on compliance rather than proactive threat detection. This feeds into other common problems such as incomplete asset inventory, with Fjalstad observing that “if you don’t know what you have to secure, then it is very hard to make sure that you’re mitigating all the risks.” Third-party equipment suppliers must also be considered a potential security backdoor, with vendors held to as high a standard as a utility’s own staff.
Unmanned aerial vehicles pose a unique challenge, as the intersection between physical and cybersecurity that is not well addressed by current law. (See Feds Late to Act on Drone Threat, DHS Official Says.) Utilities that believe drones are monitoring their facilities have no recourse to law enforcement unless their airspace is violated, and even then, tracking down the operator of the vehicle is easier said than done. Fjalstad said operators must find other ways to protect their assets from unwanted surveillance.
Infrastructure Intersections
While environmental and security concerns dominated the presentation, other topics were suggested for future monitoring. One example is the risk that the growth of electric vehicles and charging stations could exacerbate the weather and resource mix issues. Operators also identified copper theft and vandalism as ongoing dangers — not just to their own equipment, but also among the telecommunication companies on which they rely for remote monitoring.
ERCOT will likely welcome back double-digit reserve margins next year and well into the decade, according to the grid operator’s latest capacity, demand and reserves (CDR) report.
While they won’t provide relief from Texas’ blistering summers, the additional reserves will give ERCOT a little more room to work with than it did in surviving 2019’s record demand with a 8.6% margin — up from an initial historic low of 7.4%.
Released Thursday, ERCOT’s newest CDR indicates its planning reserve margin will hit 10.6% in 2020 and 18.2% in 2021. The margin will shrink again after that, reaching a projected 12.9% in 2024. The grid operator has a target planning reserve margin of 13.75%.
ERCOT’s projected resource capacity through 2024 | ERCOT
“Yes, the reserve margin’s improving, and the [later] years seem to be significantly better,” said Dan Woodfin, ERCOT’s senior director of system operations. “While the reserve margin seems higher in 2020, we could still see some operating days with tight conditions. We’re prepared for that, just like we were last year.”
ERCOT shattered its all-time system peak in August, hitting 74.8 GW and breaking the mark set in 2018 by more than 1 GW. While its resources met peak demand, the grid operator ran into tight conditions during the early afternoon when West Texas wind energy dropped off. It was twice forced to call energy emergency alerts to ease the scarcity. (See “ERCOT CEO Briefs Commission on Summer Performance,” Texas PUC Briefs: Aug. 29, 2019.)
Staff are projecting a peak of more than 76.7 GW in 2020, but they also expect an additional 7.6 GW in new capacity for summer 2020, based on preliminary data from generation owners. Most of those resources are renewable or smaller gas-fired peakers.
ERCOT has approved 1,058 MW of installed capacity for commercial operations since the last CDR was released in May. More than 4,650 MW of installed capacity has become eligible for inclusion in the CDR after completing necessary agreements and permits.
Two canceled gas plants with 1,227 MW of capacity were removed from the CDR, and eight solar projects with a 1,056-MW capacity contribution were delayed until 2021, accounting for the reserve margin’s leap to 18.2% that year.
Wind and solar energy will continue to increase their shares of ERCOT’s fuel mix. Solar’s summer capacity is forecast to account for 9.7% of the fuel mix by 2022, while coal will drop to 15.6%. Wind energy is projected to reach 10.2% of the summer mix in 2024.
ERCOT has changed the way it calculates wind and solar capacity for the CDR, switching to a capacity-weighted average instead of a simple average of historical contributions. Staff also split its non-coastal wind region into “Panhandle” and “other” wind regions.
CARMEL, Ind. — MISO says it will look to make improvements to the capacity testing process after sifting through results from its generators and discovering errors.
The RTO received more than 1,800 submittals from approximately 140 generation operators by the Oct. 31 deadline for its generation verification test capacity (GVTC) process. It requires generation owners to test the capability of their units annually to determine maximum capacity to help calculate MISO’s resource adequacy.
At the Resource Adequacy Subcommittee’s meeting Tuesday, MISO Manager of Capacity Market Administration Eric Thoms said the RTO would reach out to about 40 generation owners this month to discuss correcting possible errors in the submittals in time for the 2020/21 Planning Resource Auction.
Some stakeholders asked how MISO had determined errors had been made in the first place.
“It wouldn’t be obvious to me that we’ve even made errors,” MidAmerican Energy’s Greg Schaefer said.
Thoms said MISO performed a quality and validation review at the behest of its Independent Market Monitor. He said the likely errors are centered on temperature corrections for cooling water and air temperature, generator polarity data, and “misinterpretations” of some of the fields on the survey.
RASC liaison Patrick Brown said that over the next year, the RTO will investigate potential GVTC process improvements to “increase the quality of data being submitted and lesson the burden of MISO’s review.”
“We’re not trying to eat the elephant all at once,” Brown said of working in improvements.
Stakeholders Remain Critical of Capacity Deliverability Remedy
MISO remains committed to tightening capacity deliverability requirements using the same method it proposed in October, but some stakeholders are voicing concerns over reduced capacity credits issued to wind resources.
The RTO has said it will use an intermittent resource’s transmission service request value to set its maximum historical output for the average capacity factor, which will likely reduce a resource’s unforced capacity values and stands to reduce capacity credits. It would only apply the solution to its intermittent resources, citing increasing wind curtailments in the footprint. (See “MISO Pushes Back Deliverability Requirements,” MISO RASC Briefs: Oct. 9, 2019.)
MISO’s Darrin Landstrom said the move will “improve the expectation of generators required to deliver capacity to load.”
“Under the current process, an intermittent resource that is not fully deliverable could acquire capacity credit with the same equality as an intermittent resource that is fully deliverable. Revising capacity accreditation calculations to factor in studied levels of deliverability may incentivize intermittent resources to obtain more deliverability if necessary and/or improve the confidence that capacity is being accredited in a method that more closely aligns with deliverability levels,” MISO said.
The Monitor has argued for more than a year that the RTO doesn’t properly account for capacity deliverability because its loss-of-load expectation (LOLE) study assumes that all capacity resources are fully deliverable on an installed capacity (ICAP) basis. However, it also allows resources to demonstrate deliverability only up to the unforced capacity (UCAP) levels, which tend to be about 5 to 10% below full ICAP levels. The Monitor thinks it should assess deliverability for all capacity resources based on full ICAP.
Madison Gas and Electric’s Megan Wisersky said MISO’s proposal may be expensive in that more capacity resources or more transmission capacity will be required to meet peak loads.
“Are we merely trying to jack up the transmission we’re building, increasing costs to our customers?” she asked.
Landstrom said the proposal might leave some of the wind fleet’s effective load carrying capability (ELCC) unassigned. He said the unassigned ELCC might be applied to resources that have secured full deliverability through transmission service. However, MISO may run into problems if it gives a resource more capacity credit than the reliability, including the issue of “how to slice and divide the ELCC pie.” MISO annually calculates a system-level ELCC, which is currently 15.7% of the MISO wind fleet’s registered maximum capacity.
IMM Michael Chiasson also pointed out that there are few benefits to purchasing transmission service for 100% deliverability. He said it’s possible to achieve zonal resource credit requirements “well under” full deliverability.
“We have some homework to do,” Brown said before closing the discussion. He said MISO may need to delay release of its design concept until February and promised another presentation in January. “In my mind, we have a lot of open questions, and I’ll take that, on behalf of MISO staff.”
