FERC last week accepted two previously rejected unexecuted generator interconnection agreements between SPP, Oklahoma Gas & Electric (OG&E) and a pair of wind farms (ER20-2544, ER20–2545).
The two wind facilities, Frontier Windpower II and Chilocco Wind Farm, were part of SPP’s 2016 definitive interconnection system impact study (DISIS). Staff performed five restudies following the initial DISIS as projects dropped out of the GI queue or interconnection points were re-designated.
The fourth restudy identified Wolf Creek-Emporia as a shared network upgrade needed to accommodate the cluster’s interconnection requests. However, the ensuing restudy indicated the upgrade was no longer needed following the Board of Directors’ 2019 approval of the Wolf Creek-Blackberry competitive transmission project.
SPP revised the original GIAs to remove the Emporia upgrade. It said it filed the unexecuted agreements because OG&E disagreed with the proposed cost allocations, which did not allocate any Blackberry project costs to the wind facilities.
FERC rejected the GIA filings in April, saying their cost allocations were unjust and unreasonable because they were based on the Emporia upgrade. In approving the revised GIAs on Sept. 28, it noted they no longer contain the Emporia upgrade and include the Blackberry project as a contingent facility.
The commission reiterated its position that SPP did not violate its Tariff in performing the fifth restudy, pointing out that 13 higher or equal priority queued interconnection customers had dropped out. FERC disagreed with OG&E’s argument that SPP violated the commission’s interconnection-related pricing policy and cost-causation principles by proposing not to assign Blackberry’s costs to the DISIS group.
“SPP’s proposed cost allocation for the Blackberry project is consistent with the [Tariff’s] requirements for cost allocation,” the commission said.
FERC last week also responded to OG&E’s request to rehear the April order on Frontier II, which was automatically rejected when the commission did not respond within 30 days. The commission provided additional discussion but came to the same conclusion (ER19-2747).
OG&E had argued that FERC “failed to support with substantial evidence” its finding that SPP was allowed to undertake the fifth restudy when some of the projects were withdrawn. The commission declined to address the complaints.
The utility also contended that FERC erred by agreeing with an earlier mistaken SPP statement that a planning assessment justified the fifth restudy, arguing that the assessment contained improper assumptions that cause it to ignore the Frontier project’s impact. The commission reminded OG&E that it found the fifth restudy was not flawed, and it said the utility failed to provide evidence supporting its allegations that SPP never provided “specific assumptions” including in the planning assessment.
Frontier II, at 350 MW, is the largest wind project in Duke Energy Renewables’ fleet. It will be paired with the 200-MW Frontier I, which has been operational since 2016.
Three Northwest law firms last week filed a class action suit against PacifiCorp alleging the utility failed to de-energize power lines that contributed to a set of devastating blazes ignited in Oregon during the Labor Day weekend.
The development highlights the pressures Western utilities increasingly confront as wildfire dangers grow in length and scope, impacting areas previously not prone to the kind of fast-moving conflagrations that have plagued California in recent years.
It also illustrates the tightrope utilities must walk when deciding whether to invoke public safety power shutoffs (PSPS), the policy of pre-emptively shutting down lines to prevent sparking fires in high-risk areas.
The lawsuit, filed with the Multnomah County Circuit Court on Thursday, contends that Portland-based Pacific Power and its parent company PacifiCorp ignored warnings of hot, dry winds coupled with “extremely critical fire conditions” on Sept. 7, leaving lines energized in high-risk fire areas even as other Oregon utilities proactively cut power to avoid igniting trees and brush in the state’s extensive and towering forests.
An unusual wind storm with easterly winds swept the state Labor Day evening, toppling a number of those lines, sparking fires that rapidly swept through the Clackamas, Santiam, McKenzie and Umpqua canyons, as well as other parts of Oregon, the complaint contends.
“Defendants’ energized power lines ignited massive, deadly and destructive fires that raced down the canyons, igniting and destroying homes, businesses and schools,” the complaint says. “These fires burned over hundreds of thousands of acres, destroyed thousands of structures, killed people and upended countless lives.”
Ruins of the Lyons, Ore., home of the lead plaintiffs in the class action suit filed against Pacific Power and PacifiCorp | Jeanyne James/Robin Colbert
As evidence of Pacific Power’s culpability, the lawsuit cites a Northwest Incident Management Team (NIMT) report on Sept. 10 stating that downed lines on Sept. 7 sparked at least 13 fires along a nearly 30-mile stretch of the Santiam Canyon from the town of Detroit west to Mehama. The following day, the ferocious, wind-driven Beachie Creek Fire overran Detroit from the east and ultimately grew to more than 190,000 acres after merging with a separate blaze originally dubbed the Santiam Fire.
The lead plaintiffs in the suit, Jeanyne James and Robin Colbert, lived in the Santiam-area town of Lyons. The couple lost their home, four cars, a garage full of collectibles and tools, and nearly all their personal belongings, according to the suit, which seeks to represent other residents who suffered similar losses.
The complaint cites statements from an NIMT commander, who recounted during an early September press conference that a fire team stationed at the Old Gates School in Gates, east of Lyons, witnessed power lines fall near the school around 9:45 p.m. on Labor Day, sparking a fire that burned down the incident command post. Firefighters and other witnesses saw downed lines ignite fires in other parts of Gates, the complaint notes.
Pacific Power “could have de-energized their power lines during the critical and extremely critical fire conditions, at little to no cost to defendants, and thereby fully eliminate the risk of fire caused by power lines,” the complaint says.
Instead, the utility acknowledged that the Santiam area was not in its PSPS area and only de-energized lines at the request of local emergency agencies, the suit said.
PacifiCorp said it does not comment on pending litigation.
‘No Small Matter’
The filing of the class action Thursday coincided with a special meeting of the Oregon Public Utility Commission on utility responses to the Labor Day wind storm and subsequent fires. Testimony illustrated the complications utilities face when deciding whether to call for shutoffs in high-risk areas. It also demonstrated the differences between the responses of the state’s two big investor-owned utilities, Pacific Power and Portland General Electric.
Stefan Bird, Pacific Power | Oregon PUC
Pacific Power CEO Stefan Bird said the utility introduced PSPS in its planning in 2018 “as a last resort in extreme weather conditions in specific high fire-risk areas of our service territory.”
“We understand it’s no small matter to consider turning the power off for an entire community, and that such an action needs to take in consideration the risks that imposes to critical emergency services that rely on power, such as hospitals, 911 communications, water supply and vulnerable customers that rely on power to meet their medical requirements,” Bird told commissioners.
David Lucas, Pacific Power’s vice president of operations, said conditions on the utility’s system “did not meet protocols” for using PSPS in its high fire-risk areas. However, a map on Pacific Power’s website shows the Santiam Canyon is not even located near any of the utility’s PSPS zones.
“Similar to our colleagues at PGE,” Lucas said, “we did de-energize lines at the request of local emergency agencies to allow firefighters to do their job safely and to assist in removing debris to unblock roadways.” He said utility staff took those actions in the Medford area, about 235 miles south of the Santiam Canyon.
“We know public safety power shutoffs are often a focus when the public hears about utility wildfire mitigation; however, this is only one tool in a utility’s toolbox,” Lucas said. “And as we’ve learned through extensive local community engagement, public safety power shutoff events must be properly planned and coordinated so that a loss of power does not have unintended consequences of actually increasing public safety risk.”
Unlike Pacific Power, PGE did pre-emptively de-energize lines on Labor Day in anticipation of the wind storm, shutting power to about 5,000 customers near Mount Hood in what was the first PSPS event to affect Oregon residents. (See High Fire Danger Prompts First Oregon PSPS Event.)
Larry Bekkedahl, Portland General Electric | Oregon PUC
During the PUC call, PGE Vice President Larry Bekkedahl said the utility was under a “heightened level of alert” in the week before the weather event, prompting it to contact customers and community leaders to plan for a potential PSPS, including relocating “medically fragile” residents.
“This was not a decision we took lightly, as we recognized the hardships that the loss of power presents to many customers,” Bekkedahl said. “On [Labor Day] evening, I made the decision to de-energize in the highest-risk section of our service area” near Mount Hood. PGE subsequently de-energized lines in eight other areas, including towns threatened by both the Beachie Creek and Riverside fires, which at one point threatened to merge.
While the lawsuit does not mention PGE’s actions, it does note that the Eugene Water & Electric Board (EWEB), which serves a territory about 70 miles south of the Santiam area, pre-emptively de-energized lines during the storm.
The complaint noted that EWEB spokesman Joe Harwood told The Register–Guard on Sept. 9 that “I know people weren’t happy, but the idea was not to be the cause of a fire.”
The Northeast Energy and Commerce Association’s Fuels Conference on Wednesday tackled the subject of natural gas bans by local governments, questioning whether they are necessary for the “transition to a clean energy future or major government overreach with unintended consequences.”
Judy Chang, undersecretary of energy in the Massachusetts Executive Office of Energy and Environmental Affairs, said that the transition away from natural gas “is not going to be easy,” noting that gas demand has increased amid decarbonization efforts and that it is used for both heat and electricity.
“New England has very cold winters, and approximately 50% of our households heat with natural gas, and that number has been increasing,” Chang said. “In addition, we are at the end of long pipelines.”
Regulatory Assistance Project principal Richard Cowart concurred, saying, “Phasing out natural gas is probably the most challenging climate policy topic” he has encountered in nearly 30 years of working to decarbonize the power sector.
“I just think [natural] gas is going to be harder,” Cowart said. “The automobile fleet is easier than converting buildings away from fossil fuels, but climate science tells us it has to be done.”
Cowart said gas utilities need new business models and a regulatory transformation as well. “I went through electric industry restructuring, and this is starting to feel a lot like that.”
Clockwise from top left: Tamara Small, NAIOP Massachusetts; Paul Hibbard, Analysis Group; Albert Wynn, Greenberg Traurig; Judy Chang, Massachusetts Executive Office of Energy and Environmental Affairs; Richard Cowart, Regulatory Assistance Project | NECA
Cutting away quickly from fossil fuels like natural gas is not possible, according to Cowart. “Cold turkey is not on the menu,” he said. “We can only exit traditional fossil gas and oil as quickly as we can add renewable electricity, perhaps some clean gases, heat pumps and building renovations.”
Tamara Small, CEO of NAIOP Massachusetts, which represents companies involved in commercial real estate, said that her organization recognizes the effects of climate change, and its 1,700 members embrace projects designed to reduce carbon emissions. Small said any transition away from fossil fuel needs to be done in a “phased approach,” especially in new construction.
“Banning the use of natural gas for new construction means that residents will be paying for electric stoves and other electric appliances that drive up individual utility costs and may burden residents who cannot afford large increases,” Small said. “Energy efficiency needs to go hand in hand with electrification, but there is still a cost impact.”
Paul Hibbard, principal at Analysis Group, said he has not seen “careful economic analysis or assessment of what is the pathway” to reaching net-zero carbon emissions by 2050.
“The most difficult part of decarbonization is putting a pin on the board about when we need to be all-electric in buildings. [It] will be important to provide that runway … to get carbon reductions going much sooner,” Hibbard said.
Tepper Talks About Mass. DPU Petition
Nearly two years after a series of explosions and fires in natural gas lines just outside of Boston in September 2018, the Massachusetts Attorney General’s Office filed a petition with the Department of Public Utilities to investigate the future of the industry as the state “transitions away from fossil fuels and toward a clean, renewable energy future by 2050.”
Rebecca Tepper, the chief of the office’s Energy and Telecommunications Division, said during a keynote speech that “numerous audits and reports” showed how vulnerable the “whole state gas system is.”
“If we sit back and do not plan for how to manage this transition, we will repeat the mistakes of the past, and vulnerable communities will be the ones who suffer,” she said.
Shaela Collins of Columbia Gas (left), and Rebecca Tepper, Massachusetts Office of the Attorney General | NECA
The first phase of the investigation, Tepper said, should require gas companies to submit detailed economic analyses and business plans that project the state’s future gas demand, including potential revenues, expenses and investments, and input from stakeholders on necessary regulatory, policy and legislative changes. The second phase should focus on developing and carrying out the changes required in a way that protects the state’s gas consumers.
“It’s critical that we start planning this now, and that we include all stakeholders in our process,” Tepper said. “I feel like we are at a crossroad. It’s not unlike where we were in restructuring, and we need to work together as a stakeholder community to figure this out.
“We’re not alone in Massachusetts thinking about this,” she said. The petition points to similar actions in New York, where an investigation was opened in March to ensure more useful and comprehensive planning for natural gas usage and investments, and California, which started a proceeding this year to examine the safety and reliability of its natural gas infrastructure, while the state focuses on achieving its long-term decarbonization goals.
“This transition is happening; it’s happening faster than even we thought it would, so neither the status quo nor kicking the problem down the road is going to work,” Tepper said. “This is the time. Not five years or 10 years from now.”
Renewable Natural Gas Opportunities
Judith Judson, Ameresco’s vice president of distributed energy systems, said that the Northeast has a chance to be an early leader in renewable natural gas.
Judson said that Ameresco had discussions with utilities in the Northeast on adding RNG from landfills, waste-water treatment plants or large waste-producing farms to their supply portfolios.
Clockwise from top left: Rick Sullivan, Economic Development Council of Western Massachusetts; Judith Judson, Ameresco; Zach Chapin, Dominion Energy; and Edson Ng, G4 Insights | NECA
“In terms of carbon emissions, it’s considered carbon neutral,” Judson said. “There are a growing number of studies that [RNG] is cost-effective relative to other decarbonization options for heating.”
RNG can be delivered through existing infrastructure without any further capital investment, she said, and it is a baseload, dispatchable renewable fuel source to support resilience objectives.
Judson said that an “economy-wide perspective” is needed to meet carbon goals in a “cost-effective way,” and RNG should be a part.
Looming Mystic Closure Reduces Flexibility
Jake Anderson, head of gas and power fundamentals analysis at Macquarie Energy, said during his keynote that the announced retirement of Exelon’s Mystic Units 8 and 9 “reduces flexibility” for New England gas markets.
Jake Anderson of Macquarie Energy (left) and Jonathan Carroll, Énergir | NECA
Asked if there will be renewed interest in gas storage development from independent or pipeline-affiliated companies, given the gap in storage capacity and production volume, Anderson said, “it’s a tough environment for building storage because the costs haven’t necessarily come down all that much.”
Regardless of the economics, Anderson added, if gas demand grows and LNG terminals need storage, “we’re going to see at some point a resurgence of storage building; it’s just a question of when and how quickly.”
FERC on Friday rejected a challenge by security activist Michael Mabee against NERC’s Critical Infrastructure Protection (CIP) reliability standards (EL20-46).
Mabee filed his complaint May 12, focusing primarily on CIP-013-1 (Cybersecurity — Supply chain risk management) and its supposed deficiencies relating to President Trump’s executive order of May 1 declaring a national emergency regarding foreign threats to the bulk electric system. (See Trump Declares BPS Supply Chain Emergency.) The activist characterized the executive order as “a vote of no-confidence in the lackadaisical and inadequate actions of FERC and NERC” to protect the grid.
Mabee’s complaint holds that CIP-013-1 in particular is inadequate to protecting the grid because it only covers high- and medium-impact BES cyber systems but allows individual companies to determine what systems qualify as low-impact. Citing language in the order directing the secretary of energy to identify grid equipment “designed, developed, manufactured or supplied” by foreign adversaries, without reference to their level of impact, Mabee called for FERC to direct NERC to modify CIP-013-1 to apply to all BPS equipment without exception.
The complaint also criticized FERC for failing to ensure that the broader family of CIP standards “fully address leading federal guidance for critical infrastructure cybersecurity” — specifically the National Institute of Standards and Technology’s (NIST) Cybersecurity Framework. He requested that all CIP standards be revamped to bring them more in line with NIST’s recommendations.
FERC Sides with NERC, Trade Associations
NERC voiced its objections to Mabee’s complaint in June, accusing the activist of “[relying] on a logical fallacy” that the executive order must invalidate CIP-013-1 because it “covers more systems” than the standard. (See NERC Pushes Back on New CIP Standard Challenge.) Rather, the organization said, each measure applies to different cases, with the CIP standards — including CIP-013-1 — covering supply chain risks in a broad sense and the emergency declaration addressing “specific risks from specific sources.”
| Shutterstock
The ERO also said it “consistently relies upon” NIST’s framework to guide its standards development efforts and accused Mabee of using criticism of outdated versions of the CIP standards from various sources, including a 2019 Government Accountability Office report, to imply otherwise.
A coalition of trade associations, including the American Public Power Association, Edison Electric Institute and the National Rural Electric Cooperative Association, backed NERC’s call to dismiss the complaint, despite requests by Mabee and the Secure the Grid Coalition to block EEI from commenting because of its alleged work on behalf of the Chinese government.
The trade associations said that Mabee had “[failed] to articulate any connection between the executive order and … CIP-013-1,” and further called his assertion that entities had discretion to decide what constitutes a low-impact cyber system “simply untrue.” In addition, they called Mabee’s complaints regarding the CIP standards and the NIST framework “unfounded,” referring to statements by FERC commissioners that the GAO report Mabee cited as an indictment of the commission was actually “constructive” and had resulted in action to implement its recommendations.
In its response, FERC agreed that the complaint provided “[no] legal basis to conclude that [the] executive order … ‘invalidates’ or otherwise requires modifications to” CIP-013-1. The commission asserted that its recently issued Notice of Inquiry on BES equipment originating overseas showed that it takes the risk of foreign interference in the BPS seriously. (See FERC Opens Supply Chain Cyber Risk Inquiry.) In addition, FERC noted that NERC is currently revising the CIP standards “to expand protections for low-impact BES cyber systems.”
FERC also denied the request to overhaul the CIP standards to close gaps with the NIST framework, citing another recent NOI that revealed reluctance on the part of industry stakeholders to revise the standards. (See Stakeholders Speak out on FERC CIP Concerns.)
FERC Chair Neil Chatterjee said the commission’s technical conference on carbon pricing Wednesday would not be an academic exercise.
FERC Chair Neil Chatterjee | FERC
Although the commission “is not an environmental regulator,” he said, “our complex energy markets cannot be hermetically sealed from state environmental policies. … And it’s evident to anyone who’s watched us over the past several years [that] we’ve grappled with the thorny issues that arise at the intersection of state policies and our markets. We’re at a pivotal point when it comes to these discussions — a point that, I think, will ultimately lead to action in some shape or form.”
FERC heard from 32 industry officials, economists, lawyers, RTO executives and others during the daylong conference, which Chatterjee scheduled in response to a petition by a broad coalition of independent power producers and renewable energy trade groups in April (AD20-14). (See IPPs, Renewable Groups Seek FERC Carbon Pricing Conference.)
Most of the panelists urged the commission to support state and RTO efforts to introduce carbon pricing, although they said a uniform national price regime authorized by Congress would be preferable.
Here are the highlights of what we heard.
‘Crash Warnings’
Sen. Sheldon Whitehouse (D-R.I.) opened the conference with a list of potential bad outcomes if the U.S. and other industrialized nations fail to curb emissions linked to increasingly severe weather.
“These crash warnings focus separately on a coastal property value crash, a separate carbon bubble crash and insurance failure as risk becomes too unpredictable to value. But nothing says all three can’t happen,” said Whitehouse, co-founder of the Senate Climate Action Task Force and the ranking Democrat on the Senate Environment and Public Works Committee. “The warnings are many, clear and well founded. … When you are facing the risk of an economic crash, it’s hard to anticipate when the avalanche will start. It could be soon. It could be devastating.”
Legal Authority
Speakers on the day’s first panel agreed that the commission has the legal authority to approve a carbon price submitted by an RTO or ISO.
David Hill, Columbia University | FERC
David Hill, a member of the NYISO Board of Directors and an adjunct senior research scholar at the Columbia University Center on Global Energy Policy, went further. “I believe the authority and jurisdiction exist under Sections 205 and 206 of the Federal Power Act for an ISO or RTO tariff and market design to integrate state carbon pricing and carbon-control policy. And it potentially could be unjust, unreasonable or unduly discriminatory for it not to do so,” Hill said.
Kate Konschnik, director of the Climate & Energy Program at Duke University’s Nicholas Institute for Environmental Policy Solutions, said carbon pricing could “potentially reduce state policy proliferation.”
She ended her opening remarks by chiding FERC for failing to invite any state regulators or more women to the conference; all but five of the 32 panelists were men. “I hope there will be an opportunity to solicit a broader sampling of views for the record and in future conferences and dockets,” she said.
Ari Peskoe, Harvard University | FERC
Ari Peskoe, director of the Harvard Electricity Law Initiative, said that “the Supreme Court’s most recent decision [FERC v. EPSA] about the scope of the commission’s authority teaches that when the commission does ‘no more than follow the dictates of its regulatory mission to improve the competitiveness, efficiency and reliability of the wholesale market,’ courts will be reluctant to cut off the commission’s jurisdiction in the absence of a clear statutory bar. Integrating a carbon price can fit well within the commission’s mandate as a market regulator.”
Matthew Price, Jenner & Block | FERC
Attorney Matthew Price, of Jenner & Block, said that by accepting such an RTO filing, the commission does not impose any federal policy on unwilling states.
“States have allowed load-serving entities to join an RTO, understanding the RTO will make market design decisions governing the footprint. Many decisions will affect different states differently. Indeed, the status quo affects states that can’t do so in the most efficient manner, an inevitable consequence of being part of an interstate market,” Price said.
Jim Rossi, Vanderbilt University | FERC
Vanderbilt University School of Law professor Jim Rossi said that both courts and FERC have recognized that many state clean energy programs are beyond FERC’s jurisdictional reach, including zero-emission credits and unbundled renewable energy certificates.
“It would exceed the commission’s jurisdiction to use a carbon price in a wholesale tariff to pass judgment on existing state programs favoring clean energy resources, unless a state explicitly chooses for carbon pricing to apply to or supersede specific programs,” Rossi said.
Independent consultant Roy Shanker said that while the commission has authority to approve carbon pricing in RTOs, doing so might be counterproductive absent a nationwide and economy-wide carbon price that eliminates “leakage” concerns.
“Notions presented by parties that try to suggest that such segmented approaches to carbon pricing policy convey a societal benefit by internalizing carbon-related emission costs are simply incorrect,” Shanker said. “The reality is that they may be making things actually worse.”
One Wholesale Market, One Carbon Price
States should strive for agreement on a single carbon price across a wholesale market’s footprint — if not nationwide — experts stressed during the second panel of the day.
Stanford University’s Frank Wolak said a “stable, predictable price of carbon into the distant future” could function like fuel prices in wholesale electricity markets.
“Simply subsidizing green is a much more expensive way to reduce greenhouse gas emissions than taxing brown,” he said.
PJM Monitor Joe Bowring | FERC
PJM Independent Market Monitor Joe Bowring said a single carbon price for the RTO could simply become part of the marginal costs of generators, with states controlling the resulting revenues. If multiple states can’t settle on a single carbon price, he said, revenue redistribution mechanisms can be used.
NYISO CEO Rich Dewey said current compliance costs for environmental obligations, including the Regional Greenhouse Gas Initiative, are simply incorporated into suppliers’ offers and are subject to review from the ISO’s Market Monitoring Unit in a “fairly seamless” manner.
New York is relying on decarbonization to target a 70% renewable energy supply by 2030, a full renewable energy supply by 2040 and carbon neutrality by 2050, Dewey said.
“Achievement of those outlying goals will require significant investment in innovative technologies and commercialization of emerging new innovative choices which otherwise, absent a carbon price, would be very challenging to bring to market,” he said.
R Street Institute’s Devin Hartman argued for a universal carbon price from the federal level.
“Carbon pricing is, at least on paper, the least-cost solution to reducing emissions but also something that’s fully compatible with wholesale electric competition,” he said. “There’s a subset of states that do not want to pursue carbon emission reduction yet but may in the future. And then in the other camp, you have some that have really thrown a variety of policies at this issue. As we move forward in carbon pricing dialogue, the former camp will conform.”
Hartman said the longer states are left to pursue individual and uncoordinated pricing plans, the more “unnecessary risk” is introduced into investment decisions and wholesale markets.
“Whereas, if we start to have more long-term pricing stability on this front, then that lets markets go to work more efficiently,” he said.
ISO-NE CEO Gordon van Welie said there’s “obviously a big political dimension” surrounding how states pursue decarbonization and allocate carbon pricing revenues. He predicted that different approaches and discrepancies across states will create inefficiencies and distort wholesale markets until FERC is forced to act.
Kate Konschnik, Duke University | FERC
“I don’t think the commission can escape making a decision,” van Welie said, predicting that the issue will come to “a head more quickly in PJM, New England and New York,” whose capacity markets employ minimum offer price rules that make it difficult for state-subsidized resources to clear.
Arne Olson, senior partner with Energy and Environmental Economics, said the lack of a nationwide carbon price may be more detrimental to carbon-cutting goals than no carbon pricing at all.
“So the challenge is when [you] apply 50 carbon prices within interstate markets, where there is no ability to control or even measure the carbon content of imports … you could end up in a situation where piecemeal carbon pricing ends up with a worse result than no carbon pricing,” he said. “People want to do things now; they want to take early action to address this problem that is so glaringly obvious. Where we need to get is a societal agreement on what the price of carbon ought to be, so we can get electrification of vehicles and buildings, [and] emission reduction in the industrial sector.”
Panelists also conceded that carbon leakage is unavoidable when one geographic area of a wholesale market uses a carbon price and another doesn’t. “I think of it as trying to push water into one corner of a bathtub,” Olson said.
Leakage Concerns
Solving the leakage issue was a primary topic for Wednesday’s afternoon panel of market design experts.
“It’s not an intractable problem, but you have to manage leakage,” said Rana Mukerji, senior vice president for market structures at NYISO. “There’s not a politically perfect way of managing leakage, but you can minimize the effect of leakage at your borders.”
Anthony Giacomoni, senior market strategist for PJM, noted the distinctions between inter- and intra-market leakage.
Consultant Roy Shanker | FERC
Because PJM covers 13 states and D.C., he said, “you have this added complexity between the intra-ISO and inter-ISO leakage, and both have to be handled differently because of the nature of the economic dispatch. We dispatch across the entire RTO in one integrated dispatch. We do not handle external transactions in the same manner, and so a different mechanism is needed for leakage between ISOs.”
Chairman Chatterjee asked what role carbon pricing could play in investment decisions, including entry and exit of resources.
Matthew White, chief economist for ISO-NE, said carbon pricing would benefit the region’s flexible resources. As more renewables come onto the system, he said, there’s a need for more “balancing resources” that will be able to meet consumer demand when the weather is uncooperative and renewable resources can’t provide energy.
“We do not have the benefits of the sunshine of Southern California,” White said. “We live in a place where it is cold and dark for much of the year. And while I love to ski, it does mean we face a difficult challenge ensuring that the balancing resources can be there as much as we need them.”
Role for Nukes, Gas
In the closing session, Exelon CEO Christopher Crane lamented the increased emissions resulting from the shuttering of money-losing nuclear generators. He said Illinois will see a 70% increase in electric sector emissions if Exelon shuts its Byron and Dresden plants, which are scheduled for retirement in 2021, and the Braidwood and LaSalle plants, which he said are “showing increasing signs of financial distress.”
Crane said Exelon did not fully support the petition seeking a technical conference because it included a sentence saying the petitioners were not asking the commission to institute a rulemaking or direct implementation of carbon pricing.
“Continued talk about the benefit of placing a meaningful price on carbon emissions, uncoupled from concrete and immediate action to do so, while simultaneously acting to undermine state-led emission-reduction efforts, serves only to prolong emissions output from fossil generation, force more nuclear into early retirement and put the nation farther away from meeting our decarbonization goals,” Crane said. “Discussion at the commission and RTO/ISO level must evolve into action that is commensurate with the urgency of the climate crisis. Until then, states seeking to preserve and expand emissions-free electricity have only the second-best tools available. If the commission is serious about the virtue of wholesale markets and the efficiencies they bring, it will insist that those markets be used to help states achieve their carbon goals, rather than undermine them.”
Sen. Sheldon Whitehouse (D-R.I.) | FERC
Calpine CEO Thad Hill and Dena Wiggins, CEO of the Natural Gas Supply Association, expressed support of carbon pricing but lobbied for a continued role for natural gas-fired generation, saying it is essential to supplementing intermittent resources. “Natural gas generation is an enabler of economy-wide decarbonization, not an inhibitor,” Hill said.
Brett Mattison, CEO of American Electric Power’s Kentucky Power, said FERC must be cognizant of the economic hardship facing ratepayers in his company’s service territory. “In evaluating carbon pricing and other mechanisms designed to incentivize the participation of renewable resources in organized markets, it is important to consider the impacts of such mechanisms on our customers,” he said. “AEP recognizes and is committed to transformation to a greener economy; we cannot, however, overlook issues of cost and reliability as we realize this change. We must promote a diverse supply mix that can lower emissions while preserving cost and reliability goals.”
Chris Parker, executive director of the Utah Department of Commerce, said his state would “resist any direct, pre-dispatch carbon price mechanism in RTO/ISO markets because state policies should not have such a direct effect on wholesale markets.”
“FERC has no authority to tax resources in its markets. States have no authority to set a carbon price that directly changes dispatch and prices in wholesale electricity markets,” he continued. “The fact that states’ resource decisions will affect the wholesale markets does not license direct intervention in dispatch and pricing outcomes in wholesale markets. This would leap the boundaries of state authority, exporting state policies to the entire market. Federal market regulation does not license extraterritorial state taxation.
“There’s a lot of fear among states like Utah that we’re going to end up with other states’ policies rammed down our throat,” he added. “We’re going to be wary of participating in those markets.”
Chatterjee Responds
Speaking to reporters via teleconference the next day, Chairman Chatterjee acknowledged “there seems to be a basic, foundational agreement that FERC has the legal authority to evaluate” a state-imposed carbon price in an RTO’s or ISO’s tariff. Whether the tariff revisions pass the just-and-reasonable standard of the FPA would depend on their details, he said.
In his opening remarks Wednesday, Chatterjee warned that “some of the proposals that have been floated — while presumably well intentioned — could actually bring with them more harm than good.” When asked what these proposals were, he alluded to state subsidies.
“I believe in markets and market mechanisms, and the landmark actions we have taken bear that out,” he said, noting Orders 841 and 2222, which directed RTOs to open their markets to energy storage and aggregated distributed energy resources, respectively. “Out-of-market payments are less efficient toward” decarbonization of the electricity sector, he said.
Chatterjee also said it would not be “appropriate for the commission to act proactively” and find an RTO’s Tariff unjust and unreasonable because of its lack of a price on carbon, “absent a congressional mandate.”
The chairman also was asked about the potential impact of the presidential and congressional elections on federal carbon policy. Regardless of the election results, he said, “the commission is going to have to confront these issues, as states are going to continue to take it upon themselves to push for these policies.”
The CAISO Board of Governors on Thursday bid farewell to its retired CEO, greeted a new leader and passed a half dozen measures, including a plan to implement FERC Order 831 that one governor worried could lead to market manipulation.
The five-member board also named its new chair and vice chair.
The meeting occurred as CAISO called for conservation to avoid shortfalls unusually late in the year. Triple-digit temperatures hit Los Angeles and inland areas of California last week, straining supply.
The late-season heat wave was a reminder of the grid emergencies in August and September, when resources ran short during record temperatures and forced CAISO to order rolling blackouts Aug. 14-15. (See CAISO: Blackouts May Continue, Calls Emergency Meetings.)
The summer shortages came up in several of Thursday’s policy discussions and when former CEO Steve Berberich delivered his last report to the board about events that had happened on his watch.
Berberich officially retired from CAISO on Sept. 29 but agreed to stick around to help with the transition. He told the board Thursday he wanted to “make sure [new CEO Elliot Mainzer] doesn’t drown in the firehose that is headed his way.”
The ISO, the California Energy Commission and the California Public Utilities Commission are preparing a report that examines the root causes of the energy shortages, Berberich told the governors. The report will delve into factors such as exports from the state during the shortfalls and failures of some load-serving entities to schedule supply in the day-ahead market.
“We will look into those contributing factors and make sure we are not living on the margin like we were this summer,” Berberich said. “Mr. Mainzer, I know, is going to make resource adequacy a top priority.”
CAISO CEO Elliot Mainzer | BPA
The board honored Berberich with a resolution that praised his accomplishments during his nine years as CEO, including the creation of the now flourishing Western Energy Imbalance Market and the establishment of RC West, the reliability coordinator for most of the Western Interconnection.
The governors told Mainzer they were pleased he had accepted their job offer after seven years as head of the Bonneville Power Administration.
“Elliot, welcome,” Governor Ashutosh Bhagwat said. “We are very excited to work with you. These are exciting times — challenging times, but exciting times. And I know you are going to do an amazing job leading this organization.”
Later in the meeting, Bhagwat’s four colleagues chose him as their new vice chair and picked Angelina Galiteva as CAISO’s first female board chair in its 20-year existence. The positions rotate every two years.
The board approved CAISO’s fourth and last phase of its five-year effort to make it easier for energy storage and distributed energy resources (ESDER) to participate in its market. (See CAISO Finalizes ESDER Phase 4 Proposal.)
The ESDER initiative includes rooftop solar, energy storage, plug-in electric vehicles and demand response. It addresses a state-of-charge biddable parameter for storage resources; streamlines market participation agreements for non-generator resources; applies market power mitigation to storage resources; and sets a maximum daily run time parameter for DR.
The board also approved proposals on flexible ramping products, maximum import capability, reliability-must-run contracts, and changes to ISO rates and fees for next year.
Order 831 Initiative
The longest and most complex of the policy discussions, however, took place over an initiative meant to align the ISO’s practices with the requirements of FERC Order 831.
FERC issued Order 831 in 2016, two years after the polar vortex of 2014 pushed natural gas prices in the Northeast and Midwest to levels where marginal generation costs exceeded the $1,000 offer caps then in place. It required ISOs and RTOs to raise the hard caps on supply bids from $1,000 to $2,000, with offers over $1,000 requiring suppliers to justify their costs.
The board on Thursday approved a stakeholder initiative intended to help facilitate the order in California with import bidding rules and market parameters meant to “align the implementation of the order with some of the different characteristics of the Western grid,” said Greg Cook, the ISO’s director of market and infrastructure policy.
CAISO must implement the changes by March to comply with FERC’s ruling, he said.
The main differences between Eastern and Western markets, Cook said, is that it is rare to see natural gas prices as high as in the East because gas demand peaks at different times in varying parts of the West. Some areas are extremely hot in summer; others are bitterly cold in winter.
And CAISO, unlike other ISOs and RTOs, is heavily dependent on imported electricity, he said.
In response, CAISO maintains a power balance constraint to ensure that supply equals demand. If there is insufficient supply, the ISO relaxes the constraint and sets market prices at a bid cap of $1,000/MWh.
The initiative approved Thursday sets “appropriate levels of shortage pricing when energy costs exceed $1,000/MWh.” When that happens, and there is insufficient supply to meet demand, the “market will base prices on the price of the highest-priced cleared energy bid if the shortfall is no more than a small threshold value,” CAISO Vice President of Market Policy and Performance Mark Rothleder said in his written report to the board. “Market prices will be based on $2,000/MWh if the shortfall is greater than the threshold value.”
A second enhancement establishes rules for allowing import and virtual bids greater than $1,000/MWh, which Order 831 does not do. The proposal would allow CAISO to accept non-resource adequacy import and virtual bids above $1,000/MWh “only when the ISO has cost-verified a bid or the ISO has calculated a maximum import price that exceeds $1,000/MWh,” Rothleder wrote.
“For resource adequacy import bids, management proposes to reduce the price of bids priced above $1,000/MWh to the maximum import bid price index or the highest resource-specific cost-verified bid,” he said.
The ISO would calculate the maximum import price based on prevailing bilateral prices at the Palo Verde and Mid-Columbia trading hubs, whichever is higher.
“We picked those because those are the largest, most liquid trading hubs in the Southwest and Northwest, respectively,” Cook said.
The Palo Verde and Mid-Columbia hubs will be used by CAISO to set import prices during supply shortages. | U.S. EIA
CAISO’s Market Surveillance Committee previously supported the changes as an intermediate step but called for a stakeholder initiative on scarcity pricing to address situations similar to the August and September shortages. (See CAISO MSC Urges Scarcity Pricing for Emergencies.)
Cook said the ISO agrees with that assessment and intends to introduce a scarcity pricing initiative.
Governor Severin Borenstein, a professor at the University of California, Berkeley, took issue with the idea of using the higher-priced trading hub to set prices. Palo Verde can have higher prices and trades at a lower volume than Mid-Columbia, he noted.
“It seems that this is … not a very precise price index if we’re taking the maximum of two very different locations,” he said. He worried that CAISO is setting up a system by which traders could game the market with high bids at Palo Verde, which is less liquid than the Mid-Columbia hub.
CAISO said prices at Palo Verde climbed to $1,500/MWh during the August emergency, and Southern California Edison said it had seen prices of $1,750/MWh.
Eric Hildebrandt, executive director of market monitoring at CAISO, told Borenstein that FERC must approve such high prices after the fact.
“The best we can do is encourage FERC to perform that kind of review,” Hildebrandt said.
CAISO Governor Severin Borenstein | University of California, Berkeley
Cook said it would “be very rare for these bilateral trading prices to exceed $1,000 MWh,” except in situations such as the August heat wave.
In the initiative, CAISO “wanted to ensure we wouldn’t discourage import bids” during times of tight supply, Cook said. If conditions support prices over $1,000/MWh, then the ISO wants the energy to be able flow into its market, he said.
Rothleder said it would be “too risky at this point” to limit imported supply based on prices, given the experiences of August and September. CAISO intends to address the liquidity issue in the future, including seeking guidance from FERC, he said. In the meantime, it will closely watch prices to make sure they “keep with reality,” he said.
The board, including a somewhat reluctant Borenstein, approved the Order 831 initiative unanimously.
“I think we have to do this,” Borenstein said of the measure, but he said he remained concerned about creating an “incentive to manipulate the prices at the trading hubs” and urged the ISO to find a solution.
More than 8,000 wildfires have burned nearly 4 million acres in California this year, but there’s little indication that utility equipment played a role in starting major blazes.
That differs markedly from the last three years, when equipment belonging to Southern California Edison and Pacific Gas and Electric was blamed for starting catastrophic fires including the Camp Fire, the state’s deadliest and most destructive blaze, in November 2018. (PG&E says its large-scale public safety power shutoffs this year have helped avoid catastrophes.)
So far, the only 2020 summer wildfire in which power lines might be implicated is the Bobcat Fire burning in the San Gabriel Mountains northeast of Los Angeles.
The Bobcat Fire burns in the mountains above Monrovia, Calif., near Los Angeles, on Sept. 10.
A Sept. 15 report by SCE to the California Public Utilities Commission said the utility experienced a line fault at approximately the same time and in the same area the Bobcat Fire started. However, the utility said a fire camera had recorded smoke from the blaze shortly before its relay tripped.
“The Bobcat Fire was reported in the vicinity of Cogswell Reservoir/Dam in the Angeles National Forest on Sunday, Sept. 6, 2020, at 12:21 p.m.” SCE told the CPUC. “The Jarvis 12-kV circuit out of Dalton Substation experienced a relay operation at 12:16 p.m. on Sept. 6, 2020. The Mount Wilson East camera captured the initial stages of the fire, with the first observed smoke as early as approximately 12:10 p.m., prior to the relay operation.”
The investigation of the Bobcat Fire is being conducted by the U.S. Forest Service, which on Sept. 15 “requested that SCE remove a specific section of SCE overhead conductor in the vicinity of Cogswell Dam,” the utility reported.
Five of the 20 largest wildfires in California history have occurred this year and all but three since 2000. | Cal Fire
“While USFS has not alleged that SCE facilities were involved in the ignition of the Bobcat Fire, SCE submits this report in an abundance of caution given USFS’ interest in retaining SCE facilities in connection with its investigation,” it told the CPUC.
Lightning storms on Aug. 17-18 ignited massive wildfires, including the 980,000-acre August Complex, the largest fire in state history, USFS and the California Department of Forestry and Fire Protection (Cal Fire) reported.
The August storms also started three more of the five largest fires in state history: the SCU Lightning Complex, LNU Lightning Complex and the North Complex, all in Northern California, the agencies said.
The Creek Fire, in the Sierra Nevada foothills of Central California, rounds out the top five fires, all of which occurred this year, Cal Fire said. Its cause, and the cause of other major blazes, remains under investigation.
California still has at least another month of high fire risk. In Northern California, the late summer and fall fire season usually lasts until seasonal rains start in November. Major fires have broken out in drier Southern California as late as December in recent years.
“As we enter the fall season, which is known to have the largest wildfires, we want to remind everyone that now is the time to be prepared,” Cal Fire warned residents.
[contact-form][contact-field label=”Name” type=”name” required=”true” /][contact-field label=”Email” type=”email” required=”true” /][contact-field label=”Website” type=”url” /][contact-field label=”Message” type=”textarea” /][/contact-form]More than 200 people joined the annual two-day Energy Action Network (EAN) Summit online last week to hear ideas on how to tackle some of the clean energy challenges facing the mostly rural Vermont, including increasing bus ridership and incentivizing more fuel-efficient cars.
EAN comprises more than 200 nonprofits, businesses, public agencies and other organizations advocating for clean energy. Following is some of what we heard at the meeting.
Clockwise from top left: Carolyn Wesley, EAN; Cara Robechek VEEP; Jack Hanson, Sustainable Transportation Vermont; state Sen. Andrew Perchlik; and Linda McGinnis, EAN. | Vermont EAN
‘Cultural War’
State Sen. Andrew Perchlik spoke about his proposed vehicle “feebate” program aimed at people buying new vehicles. It would provide a rebate if the vehicle has a mileage rating above average for its vehicle class and add a fee on the purchase if it is below average. House Bill 529, signed into law last year, called for a study of the proposal, which Perchlik said would be self-funding program and revenue-neutral for the state.
The electric Chevy Bolt, which gets 118 mpg equivalent, would be worth a $1,000 rebate, under the program he said.
“But if you really wanted a Cadillac CT5 that only gets 21 mpg, that price would be adjusted up $500. … In a truck example, if you wanted the Ford F-150 Raptor four-wheel drive that only gets 16 mpg, you would pay $250 more for that vehicle,” Perchlik said.
“We would adjust accordingly… to make sure that it’s meeting its goal of causing people to buy more efficient vehicles,” Perchlik said. “We also don’t want to make the penalty so large … that it creates a lot of pushback, especially as we’re just rolling out the program.”
He said the program has been implemented in Ontario but not in the U.S. “Part of the reason is that you get into a cultural war of truck owners not wanting to support Prius owners, for example.”
Junk the Clunker, Go Electric
Sue Minter, executive director of Capstone Community Action, a social advocacy organization, and EAN Senior Fellow Linda McGinnis promoted a “Replace Your Ride” program modeled on one in California to provide cash incentives to low-income Vermonters to trade in their older high-polluting vehicles for a range of clean transportation and shared-mobility options.
Jennifer Wallace-Brodeur of the Vermont Energy Investment Corp. (VEIC), a nonprofit organization that advocates for energy efficiency and renewable energy, joined Cara Robechek of the Vermont Energy Education Program (VEEP) and Peggy O’Neill-Vivanco of the University of Vermont to speak on combining and electrifying rural school and public transportation.
The Vermont Clean Cities Coalition at UVM is a transportation fuels resource for educators, consumers and providers of advanced transportation technologies.
Clockwise from top left: Carolyn Wesley, EAN; Jennifer Wallace-Brodeur, VEIC; Peggy O’Neill-Vivanco, UVM; and Cara Robechek VEEP. | Vermont EAN
An anonymous participant submitted a question about how the electric buses would handle the rough terrain that a lot of diesel- or natural gas-powered school buses cover in rural areas.
In 2017, Green Mountain Transit, Advance Transit and UVM demonstrated an electric transit bus to test out how it would do in winter conditions and a variety of routes. “We did find that there are different emission savings and fuel cost savings associated with different operating conditions. So, whether it be short routes in town with lots of stops and starts, or hilly routes, there’s definitely some pros and cons to all of that. Operating conditions do make a difference,” O’Neill-Vivanco said. (See Takeaways from the Zero Emission Bus Conference.)
Wallace-Brodeur said that buses can increase their power through regenerative braking when they’re going downhill.
“But they do draw on the battery a little bit more when you’re going up, so it’s a bit of a tradeoff there,” she said. “And we absolutely know that winter conditions will impact the range of battery electric buses. So that has to be factored in when you’re planning routes and the size of batteries and battery configuration.”
Analysts at UVM have found that all of the schools that are participating in the test could meet the needs of their daily school transportation routes, with an electric bus, despite the range decreases in winter, Robechek said.
Another question was how the program would overcome safety issues connected with merging school and public transit systems.
“In most of the world, and many cities in this country, school and public transit does take place on the same buses, including in Burlington, Vt., and it takes place on public buses, not on school buses,” Robechek said.
Nothing Beats a Free Ride
Jack Hanson of Sustainable Transportation Vermont (STVT) proposed that the state allocate $3 million out of the $641 million transportation budget for 2020 to fund fare-free transit, as a way to cut per capita emissions and enhance social justice.
“Vermont has a very serious problem of transportation emissions despite years of improvement, with nearly half of current emissions as a state coming from transportation. By far the largest share of those emissions is from our reliance on single-occupancy vehicles,” Hanson said.
Mass transit offers a drastic reduction in carbon emissions over single-occupancy vehicle gains, but it’s a challenge in a rural state to get people out of their cars and onto buses. Fare-free transit has proven effective in case studies around the world, he said.
The first electric bus in Vermont went into service last winter in Burlington. | Green Mountain Transit
For example, Advance Transit, which serves the Dartmouth area between Vermont and New Hampshire, saw a 76% increase in ridership in the first two years of fare-free transit and a nearly 300% increase since it was implemented in 2014. Green Mountain Transit, which serves the Burlington and Montpelier areas, projects that if fare-free was implemented under normal, non-pandemic conditions, it would see a 37% increase in ridership, Hanson said.
“So, who is currently paying transit fares in Vermont? Well, it’s the bus riders themselves, obviously,” Hanson said. “And this is a group of Vermonters that is disproportionately low-income and people of color. It’s a group that has some of the least impact on climate change … [and] many of these folks have limited mobility options.”
The Sept. 29 debate between President Trump and former Vice President Joe Biden didn’t draw rave reviews, but there was one bright spot, said Dan Shreve, Wood Mackenzie’s head of Global Wind Energy Research.
“Happily, climate change did get about 10 minutes of the debate last night, which is far more than what was seen in the last presidential election,” Shreve said during a presentation at Greentech Media’s annual Power and Renewables Summit last week. “So certainly, environmental concerns are top of mind for folks.”
By one account, the three debates in the 2016 presidential general election spent less than six minutes on climate change and other environmental issues. In 2000, by contrast, Al Gore and George W. Bush spent more than 14 minutes discussing the environment over three debates.
While Trump has dismissed concern over climate change and is promising to continue rolling back environmental regulations, Biden has proposed a $2 trillion plan to eliminate power sector carbon emissions by 2035 and make the U.S. the leader in electric vehicle production. (See Biden Offers $2 Trillion Climate Plan.)
“The stakes are exceptionally high” in this election, said Shreve, citing both the presidential race and the fight for control of the Senate.
The Biden plan would require 1,500 GW of new capacity — more than 1,100 GW of utility-scale solar, 243 GW of onshore wind and 142 GW of offshore wind — plus 410 GW of battery storage, an estimated $2.2 trillion in capital expenditures.
“There are some big changes in here, and that’s why we’re characterizing them as aspirational. The changes are so substantial and require so much collaboration — things that we haven’t had a great deal of here in the United States for some time,” Shreve said.
The $2.2 trillion doesn’t cover transmission and other infrastructure upgrades needed to support the additional renewables. The National Renewable Energy Laboratory’s 2018 interconnection seams study, which proposed three HVDC transmission connections between the Eastern and Western Interconnections, would cost about $250 billion, Shreve said.
The Climate Institute’s proposed North American Supergrid, which envisions 42,000 miles of new HVDC transmission, most of it underground, has a price tag of almost $500 billion, he added.
Winning legislative approval and finding funding isn’t the end of the battle, however.
“We’re running increasingly into wind and solar permitting issues,” Shreve said. “A great deal of NIMBY [not in my back yard] concerns being voiced through social media and a variety of different avenues. … This same thing happens when we start talking about transmission infrastructure” needed to deliver wind power to load centers.
Energy Vault, which stores renewable energy by raising and lowering 35-ton cement bricks, won a $110 million investment from Softbank. | Energy Vault
If emission-free resources supply 90% of the nation’s power needs, the remaining 10% could be filled by natural gas-fired generation, but that would require refining carbon-capture technologies that have yet to reach commercialization, Shreve said.
“There’s an enormous amount of R&D that has to happen and a tremendous amount of risk of those technologies [not] actually reaching some level of commercial success.”
Shreve said venture capital has been pouring into companies attempting to develop long-duration, high-energy-density storage applications that could be paired with wind, citing Gravitricity and Energy Vault, which received a $110 million investment from Softbank.
“They are still very early-stage technologies,” he cautioned.
National Grid CEO Discusses Electrification Challenges
In another session at the virtual conference, Badar Khan, president of National Grid US, said decarbonizing heating will be the biggest obstacle to addressing climate change. The utility serves 20 million people in Massachusetts, New York and Rhode Island.
“Home heating is going to be the hardest sector to decarbonize because the current technologies beyond natural gas are just much more expensive. The good news is that plenty of people are working on solutions,” he said, referring to geothermal heat pumps, biogas from landfills and wastewater treatment plants, and “green” hydrogen made from renewable power.
“Whether it’s the electrifying pathway or the biogas/hydrogen pathway, we’re going to need to see a lot of innovation and policy support and a lot of customer engagement,” Khan said.
‘Bullish’ on the Future
Todd Glass, a partner in energy and infrastructure for the Palo Alto law firm Wilson Sonsini Goodrich & Rosati, said he’s “bullish” on the future.
“Renewables are becoming cheaper and cheaper, and the marginal cost of energy is lower than we ever thought it would be, especially 10 to 15 years ago when we were starting to do these types of things. The second thing is that the technology in the controls and dynamic pricing … these technologies with [artificial intelligence] and other things like that are driving innovation at the grid edge in a way that delivers value to customers.”
Glass said he’d like to “restart the conversation” from the beginning of utility restructuring 20 years ago, saying customers want “the opportunity … to be green.”
While two-thirds of the U.S. load is in restructured states, “one-third of the load has zero choice. That means they get whatever their utility serves up,” he said. “That is so stuck in the past and so contrary to the customers’ interest. For too long … utilities and captured utility commissions have deigned to speak for what customers want. I think we need to focus on what the customers actually want and put their interests first.”
‘Huge Opportunity’
Dan Seif, vice president of market development for 7X Energy, a Texas-based utility-scale solar and storage developer, said load-serving entities in Texas — particularly those not subject to retail choice — should be contracting for storage.
He said ERCOT’s interconnection queue has 200 MW of storage and is likely to hit 1 GW within two years. “The real issue that’s keeping it from … exploding and realizing the size of the queue is contractability of ancillary services, particularly” responsive reserve service (RRS), he said.
Seif said RRS represents two-thirds of the ancillary services that load-serving entities must purchase. “There’s a huge opportunity that’s kind of obvious for load-serving entities,” he said. “They should buy a portion of their load exposure from storage projects or solar and storage projects. All the big guys — Reliant [Energy], EDF [Renewables], the big monopoly utilities … Austin Energy, [Lower Colorado River Authority], Brazos [Electric Power Cooperative] — no reason not to put that into your portfolio and enable some of these storage projects.
“I think a lot of them are thinking about it, but maybe everybody is kind of looking to the left and right and saying, ‘You first.’”
Seif said some financial traders are looking at storage for arbitrage opportunities. But the “natural buyers” are LSEs, “as long as they think they’re going to have a lot of load for a while. And the monopolies have no excuse — the customers have nowhere to go.”
Brattle’s analysis also shows Rhode Island demand outlook similar to New England, with moderate load growth through 2030 and significant growth after because of heating and transportation electrification. | The Brattle Group
Rhode Island will need to add about 440 GWh of renewable energy annually to meet the state’s goal of 100% renewable energy by 2030, The Brattle Group said at the second in a series of three public workshops hosted by the state’s Office of Energy Resources (OER) on Sept. 29.
Equally daunting, the state will need to continue adding an average of 400 GWh a year to maintain the 100% target through 2050 as its load potentially doubles from the electrification of heating and transportation, Brattle said.
The consultants are helping state officials develop a plan by year-end for the clean energy target mandated in a January executive order by Gov. Gina Raimondo. (See RI Seeks to Lead with 100% Renewable Goal.)
Electrification Impact
At the first public meeting in July, the analysts said the state would need to add 360 GWh annually through 2030 to meet the target. The current estimate’s base case projects net load of 7,700 GWh in 2030, including electrification of 5% of light-duty vehicles (LDVs) and 5% of heating, based on an ISO-NE forecast, said Michael Hagerty, Brattle senior associate. The baseline also incorporates National Grid’s forecast for energy efficiency.
Michael Hagerty, Brattle | The Brattle Group
The baseline is bracketed by a low-demand scenario of 7,000 GWh and a high-demand scenario of 8,300 MWh, which assumes 15% LDV electrification and 10% heating electrification.
“In our low-demand scenario, we’re assuming that level of electrification does not occur,” Hagerty said.
The study says the state needs to add 4,400 GWh of renewable energy by 2030 to meet 100%. Last year, Rhode Island’s renewable electricity production of 930 GWh represented 13% of the state’s load. The state has 410 MW of renewables, including 230 MW of solar, including net metered resources, and 180 MW of contracted resources.
Current transmission queues list more than 12 GW of offshore wind, and 2.2 GW of onshore wind from Maine and 4 GW from New York. But the ISO-NE queue currently has no Rhode Island-based onshore wind because of wind quality and land availability, Brattle reported.
The costs of transmission and distribution system upgrades needed to accommodate the new renewables is “a source of significant uncertainty,” Hagerty said. “We’ve been reviewing these projections with renewable developers to make sure that they find them to be reasonable, and we’ve generally heard that they are.”
The limited availability of low-cost interconnection points for 1- to 10-MW scale distributed solar has resulted in increased interconnection costs, which might offset some of the cost declines seen in the industry, Hagerty said. An increase of $200 to $300/kW in system upgrades could increase distributed solar costs by $10 to $24/MWh, he added.
Wholesale Modeling
Brattle principal Dean Murphy outlined how the consultants are modeling the New England wholesale electricity market.
Dean Murphy, Brattle | The Brattle Group
“It’s important to recognize that the fundamental nature of this market is going to change substantially, even by 2030, and perhaps especially thereafter due to the significant addition of renewable energy generators across the system,” Murphy said. At 6% of regional load, “Rhode Island … is a very small component of New England overall, so it will be driven more by changes in other states that are also decarbonizing their electricity resources, albeit less quickly than Rhode Island.”
Because the output of renewables is highly correlated and difficult to store, once a lot of solar has been added to the system, incremental additions will have diminishing value. To capture how that dynamic will work out over time, Brattle uses an in-house model called GridSim.
Jurgen Weiss, Brattle | The Brattle Group
The study projects that gas-fired capacity will be kept around until 2040 but will be used much less than now as other renewable resources come online. In response to a question by an attendee, Brattle principal Jürgen Weiss acknowledged that gas generators will become increasingly dependent on capacity revenues to survive as their energy market revenue drops with lower utilization. He said the model accounts for the shift, ensuring all resources cover their fixed and variable costs.
“[It is] important to note that something similar is already the case since there are resources that don’t generate much electricity but stay in the market to provide reliability,” such as older dual-fuel units, he said. “If they have been built, you don’t necessarily need higher capacity prices since the capital cost is sunk and you just need to cover their going-forward costs,” Weiss said.
“Solar may be an excellent complement to wind, in part because it does generate more in the summer, when there is a summer peak for load in the daytime,” Murphy said. “A blend of these two kinds of resources is likely to be better than either one in isolation.”
Natural gas-fired capacity will be maintained into 2040 but will be used a lot less as other renewable resources come online. | The Brattle Group
Environmental Justice
OER Commissioner Nicholas Ucci told the workshop that his office is including social and environmental justice considerations in its work on clean energy.
“Folks should be comforted by the fact that we are accounting for many if not most of those categories in the 4600 framework, either analytically, qualitatively or by other means,” Ucci said, referring to the Public Utilities Commission’s Docket No. 4600, an investigation into the changing electric distribution system.
“One piece of good news is that, unlike in the past when dirty stuff was located in places that hurt particularly vulnerable populations, here we’re talking about locating renewable energy resources — and their negative impact on surrounding communities is considerably less than coal-fired power plants,” Weiss said.
How those vulnerable populations are protected from potential rate increases is a separate and important topic, Weiss said. “But we’re cleaning up Rhode Island’s electricity system, so the trajectory is to remove harm that might have been inflicted in the past. One can also ask whether the policies that are implemented to achieve the 100% renewable electricity target could be used to help those communities that are disadvantaged.”
For environmental justice, “the first step is to look inward,” Ucci said. “A lot of our state agencies are starting to connect with local grassroots organizations to better understand their perspectives [and] working to educate and train ourselves.”
